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EPA.
PROPERTY,01"
STANDARDS OF PERFORMANCE
FOR NEW STATIONARY SOURCES
U.S. ENVIRONMENTAL PROTECTION AGENCY
OFFICE OF ENFORCEMENT
OFFICE OF GENERAL ENFORCEMENT
WASHINGTON, D.C. 20460
-------
HANDBOOK DISTRIBUTION RECORD
This edition of the Standards of Performance for New Stationary Sources - A Compilation has
been designed to permit selective replacement of outdated material as new standards are proposed
and promulgated or existing standards are revised. A NSPS Handbook distribution record has been
established and will be maintained up to date so that future revisions and additions to the document
may be distributed to Handbook users: (These supplements will be issued at approximately six-
month intervals.) In order to enter the Handbook user's name and address in the distribution
record system, the card shown below must be filled out and mailed to the address indicated on the
reverse side of card. Any future change in name and/or address should be sent to the following:
U.S. Environmental Protection Agency
Library Services Office, MD-35
Research Triangle Park, North Carolina 27711
Attn: NSPS Regulations Information
(cut along dotted line)
DISTRIBUTION RECORD CARD
NSPS Handbook Date
User (Last name) (First) (Middle initial)
Address to send
future revisions (Street)
and additions
(City) (State) (Zip code)
If address is an employer
or affiliate (fill in)
(Employer or Affiliate name)
I have received a copy of the NSPS Handbook (EPA-340/1-77-015). Please send me any revisions
and new additions to the Handbook
-------
U.S. ENVIRONMENTAL PROTECTION AGENCY
Library Services Office, MD-35
Research Triangle Park, North Carolina 27711
Attn: NSPS Regulations Information
-------
EPA 340/1-80-OOIa
STANDARDS OF PERFORMANCE
FOR NEW STATIONARY SOURCES
A COMPILATION AS OF JULY 1,198O
by
PEDCo Environmental, Inc.
Cincinnati, Ohio 45246
Contract No. 68-01-4147
EPA Project Officer: Kirk Foster
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Enforcement
Office of General Enforcement
Division of Stationary Source Enforcement
Washington, D.C. 20460
July 1980
-------
The Stationary Source Enforcement series of reports is issued by the
Office of General Enforcement, Environmental Protection Agency, to
assist the Regional Offices in activities related to enforcement of
implementation plans, new source emission standards, and hazardous
emission standards to be developed under the Clean Air Act. Copies of
Stationary Source Enforcement reports are available - as supplies
permit - from the U.S. Environmental Protection Agency, Office of
Administration, General Services Division, MD-35, Research Triangle
Park, North Carolina 27711, or may be obtained, for a nominal cost,
from the National Technical Information Service, 5285 Port Royal Road,
Springfield, Virginia 22151.
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PREFACE
This document is a compilation of the New Source Performance
Standards promulgated under Section 111 of the Clean Air Act, repre-
sented in full as amended. The information contained herein updates the
original compilation published by the Environmental Protection Agency in
August 1976 and Supplement I issued in March 1977 (EPA 340/1-76-009 and
340/1-76-009a).
The format of this document permits easy and convenient replacement
of material as new standards are proposed and promulgated or existing
standards revised. Section I is an introduction to the standards,
explaining their purpose and interpreting the working concepts which
have developed through their implementation. Section II contains a
"quick-look" summary of each standard, including the dates of proposal,
promulgation, and any subsequent revisions. Section III is the complete
standards with all amendments incorporated into the material. Section
IV contains the full text of all revisions, including the preamble
which explains the rationale behind each revision. Section V is all
proposed amendments to the standards. To facilitate the addition of
future materials, the punched, loose-leaf format was selected. This
approach permits the document to be placed in a three-ring binder or to
be secured by rings, rivets, or other fasteners; future revisions can
then be easily inserted.
iii
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Future Supplements to New Source Performance Standards - A Com-
pilation will be issued on an as needed basis by the Division of Sta-
tionary Source Enforcement. Comments and suggestions regarding this
document should be directed to: Standards Handbooks, Division of Sta-
tionary Source Enforcement (EN-341), U.S. Environmental Protection
Agency, Washington, D.C. 20460.
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TABLE OF CONTENTS
Page
I. INTRODUCTION TO STANDARDS OF PERFORMANCE FOR NEW 1-1
STATIONARY SOURCES
II. SUMMARY OF STANDARDS AND REVISIONS II-l
III. PART 60 - STANDARDS OF PERFORMANCE FOR NEW III-l
STATIONARY SOURCES
SUBPART A - GENERAL PROVISIONS
Section
60.1 Applicability III-4
60.2 Definitions 111-4
60.3 Abbreviations III-4
60.4 Address III-5
60.5 Determination of construction or modification III-7
60.6 Review of plans III-7
60.7 Notification and recordkeeping III-7
60.8 Performance tests III-7
60.9 Availability of information III-8
60.10 State authority III-8
60.11 Compliance with standards and maintenance III-8
requirements
60.12 Circumvention 111-8
60.13 Monitoring requirements III-8
60.14 Modification 111-10
60.15 Reconstruction III-ll
60.16 Priority List III-ll
SUBPART B - ADOPTION AND SUBMITTAL OF STATE PLANS
FOR DESIGNATED FACILITIES
Section
60.20 Applicability 111-13
60.21 Definitions 111-13
60.22 Publication of guideline documents, emission 111-13
guidelines, final compliance times
v
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TABLE OF CONTENTS
Section Page
60.23 Adoption and submittal of state plans; public hearings 111-13
60.24 Emission standards and compliance schedules 111-14
60.25 Emission inventories, source surveillance reports 111-14
60.26 Legal authority 111-15
60.27 Actions by the Administrator 111-15
60.28 Plan revisions by the State 111-15
60.29 Plan revisions by the Administrator 111-15
SUBPART C - EMISSION GUIDELINES AND COMPLIANCE TIMES 111-16
SUBPART D - STANDARDS OF PERFORMANCE FOR FOSSIL-FUEL-FIRED
STEAM GENERATORS FOR WHICH CONSTRUCTION IS
COMMENCED AFTER AUGUST 17, 1971
Section
60.40 Applicability and designation of affected facility 111-17
60.41 Definitions 111-17
60.42 Standard for particulate matter 111-17
60.43 Standard for sulfur dioxide 111-17
60.44 Standard for nitrogen oxides 111-17
60.45 Emission and fuel monitoring 111-18
60.46 Test methods and procedures 111-19
SUBPART Da - STANDARDS OF PERFORMANCE FOR ELECTRIC UTILITY
STEAM GENERATING UNITS FOR WHICH CONSTRUCTION IS
COMMENCED AFTER SEPTEMBER 18, 1978
Section
60.40a
60.41a
60.42a
60.43a
60.44a
Applicability and designation of affected facility
Definitions
Standard for particulate matter
Standard for sulfur dioxide
Standard for nitrogen oxides
111-21
111-21
111-22
111-22
111-23
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TABLE OF CONTENTS
Section
60.45a
60.46a
60.47a
60.48a
60.49a
Commercial demonstration permit
Compliance provisions
Emission monitoring
Compliance determination procedures and methods
Reporting requirements
Page
111-23
111-24
111-24
111-25
111-26
Section
60.50
60.51
60.52
60.53
60.54
SUBPART E - STANDARDS OF PERFORMANCE FOR INCINERATORS
Applicability and designation of affected facility 111-28
Definitions 111-28
Standard for particulate matter 111-28
Monitoring of operations 111-28
Test methods and procedures 111-28
Section
60.60
60.61
60.62
60.63
60.64
SUBPART F - STANDARDS OF PERFORMANCE FOR PORTLAND
CEMENT PLANTS
Applicability and designation of affected facility 111-29
Definitions 111-29
Standard for particulate 111-29
Monitoring of operations 111-29
Test methods and procedures 111-29
Section
60.70
60.71
60.72
60.73
60.74
SUBPART G - STANDARDS OF PERFORMANCE FOR
NITRIC ACID PLANTS
Applicability and designation of affected facility
Definitions
Standard for nitrogen oxides
Emission monitoring
Test methods and procedures
111-30
111-30
111-30
111-30
111-30
vn
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TABLE OF CONTENTS
Page
Section
60.80
60.81
60.82
60.83
60.84
60.85
SUBPART H - STANDARDS OF PERFORMANCE FOR
SULFURIC ACID PLANTS
Applicability and designation of affected facility
Definitions
Standard for sulfur dioxide
Standard for acid mist
Emission monitoring
Test methods and procedures
111-31
111-31
111-31
111-31
111-31
111-31
Section
60.90
60.91
60.92
60.93
SUBPART I - STANDARDS OF PERFORMANCE FOR
ASPHALT CONCRETE PLANTS
Applicability and designation of affected facility
Definitions
Standard for particulate matter
Test methods
111-32
111-32
111-32
111-32
SUBPART J - STANDARDS OF PERFORMANCE FOR
PETROLEUM REFINERIES
Section
60.100 Applicability and designation of affected facility
60.101 Definitions
60.102 Standard for particulate matter
60.103 Standard for carbon monoxide
60.104 Standard for sulfur dioxide
60.105 Emission monitoring
60.106 Test methods and procedures
111-33
111-33
111-33
111-33
111-33
111-33
111-34
VTM
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TABLE OF CONTENTS
Page
Section
60.110
60.111
60.112
60.113
SUBPART K - STANDARDS OF PERFORMANCE FOR STORAGE VESSELS
FOR PETROLEUM LIQUIDS CONSTRUCTED AFTER JUNE 11, 1973
AND PRIOR TO MAY 19, 1978
Applicability and designation of affected facility
Definitions
Standard for volatile organic compounds (VOC)
Monitoring of operations
111-36
111-36
111-36
111-36
Section
60.110a
60.Ilia
60.112a
60.113a
60.114a
60.115a
SUBPART Ka - STANDARDS OF PERFORMANCE FOR STORAGE VESSELS
FOR PETROLEUM LIQUIDS CONSTRUCTED AFTER MAY 18, 1978
Applicability and designation of affected facility 111-37
Definitions 111-37
Standard for volatile organic compounds (VOC) 111-37
Testing and procedures 111-38
Equivalent equipment and procedures 111-38
Monitoring of operations 111-39
Section
60.120
60.121
60.122
60.123
SUBPART L - STANDARDS OF PERFORMANCE FOR
SECONDARY LEAD SMELTERS
Applicability and designation of affected facility
Definitions
Standard for particulate matter
Test methods and procedures
111-40
111-40
111-40
111-40
IX
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TABLE OF CONTENTS
Page
Section
60.130
60.131
60.132
60.133
SUBPART M - STANDARDS OF PERFORMANCE FOR SECONDARY
BRASS AND BRONZE INGOT PRODUCTION PLANTS
Applicability and designation of affected facility
Definitions
Standard for particulate matter
Test methods and procedures
111-41
111-41
111-41
111-41
Section
60.140
60.141
60.142
60.143
60.144
SUBPART N - STANDARDS OF PERFORMANCE FOR
IRON AND STEEL PLANTS
Applicability and designation of affected facility
Definitions
Standard for participate matter
Monitoring of operations
Test methods and procedures
111-42
111-42
111-42
111-42
111-42
Section
60.150
60.151
60.152
60.153
60.154
SUBPART 0 - STANDARDS OF PERFORMANCE FOR
SEWAGE TREATMENT PLANTS
Applicability and designation of affected facility
Definitions
Standard for participate matter
Monitoring of operations
Test methods and procedures
111-43
111-43
111-43
111-43
111-43
Section
60.160
60.161
SUBPART P - STANDARDS OF PERFORMANCE FOR
PRIMARY COPPER SMELTERS
Applicability and designation of affected facility
Definitions
111-44
111-44
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TABLE OF CONTENTS
60.162 Standard for particulate matter
60.163 Standard for sulfur dioxide
60.164 Standard for visible emissions
60.165 Monitoring of operations
60.166 Test methods and procedures
Page
111-44
111-44
111-44
111-44
111-45
SUBPART Q - STANDARDS OF PERFORMANCE FOR
PRIMARY ZINC SMELTERS
Section
60.170 Applicability and designation of affected facility
60.171 Definitions
60.172 Standard for particulate matter
60.173 Standard for sulfur dioxide
60.174 Standard for visible emissions
60.175 Monitoring of operations
60.176 Test methods and procedures
111-46
111-46
111-46
111-46
111-46
111-46
111-46
SUBPART R - STANDARDS OF PERFORMANCE FOR
PRIMARY LEAD SMELTERS
Section
60.180 Applicability and designation of affected facility
60.181 Definitions
60.182 Standard for particulate matter
60.183 Standard for sulfur dioxide
60.184 Standard for visible emissions
60.185 Monitoring of operations
60.186 Test methods and procedures
111-47
111-47
111-47
111-47
111-47
111-47
111-47
XI
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TABLE OF CONTENTS
Page
Section
60.190
60.191
60.192
60.193
60.194
60.195
SUBPART S - STANDARDS OF PERFORMANCE FOR
PRIMARY ALUMINUM REDUCTION PLANTS
Applicability and designation of affected facility
Definitions
Standard for fluorides
Standard for visible emissions
Monitoring of operations
Test methods and procedures
111-48
111-48
111-48
111-48
111-48
111-48
Section
60.200
60.201
60.202
60.203
60.204
SUBPART T - STANDARDS OF PERFORMANCE FOR PHOSPHATE
FERTILIZER INDUSTRY: WET PROCESS PHOSPHORIC ACID PLANTS
Applicability and designation of affected facility 111-50
Definitions 111-50
Standard for fluorides 111-50
Monitoring of operations 111-50
Test methods and procedures II1-50
Section
60.210
60.211
60.212
60.213
60.214
SUBPART U - STANDARDS OF PERFORMANCE FOR PHOSPHATE
FERTILIZER INDUSTRY: SUPERPHOSPHORIC ACID PLANTS
Applicability and designation of affected facility 111-51
Definitions 111-51
Standard for fluorides II1-51
Monitoring of operations 111-51
Test methods and procedures 111-51
xn
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TABLE OF CONTENTS
Page
Section
60.220
60.221
60.222
60.223
60.224
SUBPART V - STANDARDS OF PERFORMANCE FOR PHOSPHATE
FERTILIZER INDUSTRY: DIAMMONIUM PHOSPHATE PLANTS
Applicability and designation of affected facility
Definitions
Standard for fluorides
Monitoring of operations
Test methods and procedures
111-52
111-52
111-52
111-52
111-52
Section
60.230
60.231
60.232
60.233
60.234
SUBPART W - STANDARDS OF PERFORMANCE FOR PHOSPHATE
FERTILIZER INDUSTRY: TRIPLE SUPERPHOSPHATE PLANTS
Applicability and designation of affected facility 111-53
Definitions 111-53
Standard for fluorides 111-53
Monitoring of operations 111-53
Test methods and procedures 111-53
Section
60.240
60.241
60.242
60.243
60.244
SUBPART X - STANDARDS OF PERFORMANCE FOR THE PHOSPHATE
FERTILIZER INDUSTRY: GRANULAR TRIPLE SUPERPHOSPHATE
STORAGE FACILITIES
Applicability and designation of affected facility 111-54
Definitions 111-54
Standard for fluorides 111-54
Monitoring of operations 111-54
Test methods and procedures 111-54
xi i i
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TABLE OF CONTENTS
Page
Section
60.250
60.251
60.252
60.253
60.254
SUBPART Y - STANDARDS OF PERFORMANCE FOR
COAL PREPARATION PLANTS
Applicability and designation of affected facility
Definitions
Standards for particulate matter
Monitoring of operations
Test methods and procedures
111-55
111-55
111-55
111-55
111-55
SUBPART Z - STANDARDS OF PERFORMANCE FOR FERROALLOY
PRODUCTION FACILITIES
Section
60.260 Applicability and designation of affected facility 111-56
60.261 Definitions 111-56
60.262 Standard for participate matter 111-56
60.263 Standard for carbon monoxide 111-56
60.264 Emission monitoring 111-56
60.265 Monitoring of operations 111-56
60.266 Test methods and procedures 111-57
Section
60.270
60.271
60.272
60.273
60.274
60.275
SUBPART AA - STANDARDS OF PERFORMANCE FOR STEEL
PLANTS: ELECTRIC ARC FURNACES
Applicability and designation of affected facility 111-59
Definitions 111-59
Standard for particulate matter 111-59
Emission monitoring 111-59
Monitoring of operations 111-59
Test methods and procedures 111-60
xiv
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TABLE OF CONTENTS
Page
Section
60.280
60.281
60.282
60.283
60.284
60.285
SUBPART BB - STANDARDS OF PERFORMANCE
FOR KRAFT PULP MILLS
Applicability and designation of affected facility
Definitions
Standard for participate matter
Standard for total reduced sulfur (TRS)
Monitoring of emissions and operations
Test methods and procedures
111-61
111-61
111-61
111-61
111-62
111-62
Section
60.300
60.301
60.302
60.303
60.304
SUBPART DD - STANDARDS OF PERFORMANCE
FOR GRAIN ELEVATORS
Applicability and designation of affected facility
Definitions
Standard for particulate matter
Test methods and procedures
Modification
111-64
111-64
111-64
111-64
111-64
Section
60.330
60.331
60.332
60.333
60.334
60.335
SUBPART GG - STANDARDS OF PERFORMANCE
FOR STATIONARY GAS TURBINES
Applicability and designation of affected facility
Definitions
Standard for nitrogen oxides
Standard for sulfur dioxide
Monitoring of operations
Test methods and procedures
111-66
111-66
111-66
111-67
111-67
111-67
xv
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TABLE OF CONTENTS
Page
SUBPART HH - STANDARDS OF PERFORMANCE
FOR LIME MANUFACTURING PLANTS
Section
60.340 Applicability and designation of affected facility 111-69
60.341 Definitions 111-69
60.342 Standard for participate matter 111-69
60.343 Monitoring of emissions and operations 111-69
60.344 Test methods and procedures 111-69
xvi
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TABLE OF CONTENTS
APPENDIX A - REFERENCE METHODS
Method 1
Sample and velocity traverses for stationary
sources
Method 2 - Determination of stack gas velocity and volumetric
flow rate (Type S Pi tot Tube)
Method 3 - Gas analysis for carbon dioxide, excess air, and
dry molecular weight
Method 4 - Determination of moisture in stack gases
Method 5 - Determination of particulate emissions from
stationary sources
Method 6 - Determination of sulfur dioxide emissions from
stationary sources
Method 7 - Determination of nitrogen oxide emissions from
stationary sources
Method 8 - Determination of sulfuric acid mist and sulfur
dioxide emissions from stationary sources
Method 9 - Visual determination of the opacity of emissions
from stationary sources
Method 10 - Determination of carbon monoxide emissions from
stationary sources
Method 11 - Determination of hydrogen sulfide content of fuel
gas streams in petroleum refineries
Method 12 - [Reserved]
Method 13A - Determination of total fluoride emissions from
stationary sources - SPADNS Zirconium Lake Method
Method 13B - Determination of total fluoride emissions from
stationary sources - Specific Ion Electrode
method
Method 14 - Determination of fluoride emissions from potroom
roof monitors of primary aluminum plants
Page
Ill-Appendix A-l
Ill-Appendix A-4
III-Appendix A-l4
Ill-Appendix A-l7
Ill-Appendix A-21
III-Appendix A-28
III-Appendix A-30
Ill-Appendix A-32
Ill-Appendix A-35
III-Appendix A-39
Ill-Appendix A-41
Ill-Appendix A-45
Ill-Appendix A-50
Ill-Appendix A-52
xvn
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Method 15 - Determination of hydrogen sulfide, carbonyl
sulfide, and carbon desulfide emissions from
stationary sources
Method 16 - Semicontinuous determination of sulfur emissions
from stationary sources
Method 17 - Determination of particulate emissions from
stationary sources (in-stack filtration method)
Method 19 - Determination of sulfur dioxide removal
efficiency and particulate, sulfur dioxide and
nitrogen oxides emission rates from electric
utility steam generators
Method 20 - Determination of nitrogen oxides, sulfur dioxide,
and oxygen emissions from stationary gas turbines
APPENDIX B - PERFORMANCE SPECIFICATIONS
APPENDIX C - DETERMINATION OF EMISSION RATE CHANGE
APPENDIX D - REQUIRED EMISSION INVENTORY INFORMATION
IV. FULL TEXT OF REVISIONS (References)
V. PROPOSED AMENDMENTS
Page
Ill-Appendix A-57
Ill-Appendix A-6C
Ill-Appendix A-68
Ill-Appendix A-79
Ill-Appendix A-85
Ill-Appendix B-l
Ill-Appendix C-l
Ill-Appendix D-l
IV-1
V-l
xvm
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I INTRODUCTION
The Clean Air Act of 1970, building on prior Federal, state and
local control agency legislation and experience, authorized a national
program of air pollution prevention and control which included receptor/
effect and specification standards, emission standards for mobile
sources, and - for the first time - nationwide uniform emission standards
for new and modified stationary sources. This is a compilation of the
emission standards authorized in Section 111 of the Act: Standards of
Performance for New Stationary Sources, commonly referred to as new
source performance standards or NSPS.
Taking up less than two pages of the 56-page Clean Air Act, NSPS
have become an important and integral part of Federal air pollution
control activities. The major purpose of NSPS is that of preventing new
air pollution problems. Section 111 of the 1970 Act, therefore, requires
the application of the best adequately demonstrated system of emission
reduction (taking into account the cost), permits control of existing
sources which increase emissions, and can be applied to both new and
existing sources of a pollutant not regulated by Sections 109 and 112.
Standards may apply to specific equipment and processes, or to entire
plants and facilities [Section lll(b)(2)], and may be revised whenever
necessary. Since the standards are based on emissions, the owner or
operator of a source may select any control system desired, but he must
achieve the standard. Installation and operation of a control system
1-1
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is not enough: compliance is based on actual emissions. Finally,
there is no provision for variances or exemptions; the NSPS must be met
during normal operation (start-up, shutdown, and malfunction periods are
provided for in specific regulations).
In developing NSPS or determining whether violations of NSPS have
occurred, Section 114 of the Act permits EPA to require an owner or
operator to keep records, make reports, monitor, sample emissions, and
provide other information. Section 114 also grants EPA rights of entry,
access to records and monitoring systems, and authority to sample
emissions.
NSPS may be used to complement other standards (ambient air quality,
hazardous pollutant, or mobile source), or may constitute the sole
approach to controlling a specific air pollutant or air pollution
source. The National Ambient Air Quality Standards (NAAQS) are attained
through state implementation plans (SIP) and mobile source emission
standards. The SIP are based on emission inventories. NSPS provide the
standard test methods and accurate emission measurements required for a
meticulous emission inventory. The emission measurements made during
NSPS development can be used to support SIP regulations, and usually
prove easier to enforce than a general regulation because they are
tailored to specific sources. By imposing more stringent control on new
sources, NSPS extend the usefulness of SIP's and of control equipment by
reducing the rate at which emissions increase.
1-2
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Protection of air quality is also aided by NSPS. No significant
deterioration (non-degradation) regulations, as a minimum, require that
SIP apply best available control technology to specified categories of
new sources. Usually, NSPS will represent best technology. For sources
not subject to NSPS, selection of best available control technology may
be aided by NSPS studies and by transfer of NSPS-determined technology
between similar industries.
Hazardous pollutant standards which do not require absolute best
control to protect public health can be supplemented by NSPS that (1)
minimize environmental accumulation of the pollutant if long-term effects
are suspected and (2) increase margins of safety gradually, with less
economic impact, by requiring best control of new sources. Even if the
hazardous pollutant standard represents best existing technology, NSPS
can be applied as control technology improves, increasing the margin of
safety without penalizing existing plants.
Finally, NSPS can be used alone to control emissions of designated
pollutants. This is the most feasible approach when emissions of a
pollutant could endanger public health or welfare if not limited, but
the number of existing sources is small. In situations where neither
hazardous nor ambient air standards are justified, NSPS may be used.
Public health could, for example, be endangered yet there could be
insufficient data to set ambient air standards that would with certainty
protect the public. Or a pollutant may affect public welfare, but
1-3
-------
not public health, another situation where NSPS could be used instead of
the more complex SIP approach.
NSPS Working Concepts
The development of working concepts and standard-setting processes
for both NSPS and hazardous pollutant standards reflects interpretations
of the Act that have evolved, and continue to evolve, during its imple-
mentation.
Affected facility. The term "affected facility" does not appear in
the Act, but is used in NSPS regulations to identify the equipment/
system/process to which an NSPS applies. This concept permits full
utilization of the authority in Section lll(b)(2) to "distinguish among
classes, types, and sizes within categories." Affected facilities range
from process equipment (cement plant kilns) to entire plants (asphalt
concrete, nitric acid). Some NSPS exempt facilities below a specified
size (steam generators, storage tanks). Distinctions may also be made
between the materials used (different standards for coal, oil, and gas
fired steam generators) or the material produced (different electric arc
furnace standards for ferroalloys and steel production).
Standards of performance. Senate Report No. 91-1196 explains that
this refers to the degree of control which can be achieved. EPA is to
determine achievable limits and let the owner or operator determine the
most economically acceptable technique to apply. The definition appearing
in the 1970 Act contains two phrases which also require explanation:
(a) Emission limitations. This term refers to the maximum
allowable quantity of concentration of pollutant that
1-4
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may be emitted to the atmosphere. Standard test methods
are absolutely essential to the establishment of emission
limitations, because different methods yield different
results. The test method used to collect data for the
standard must be used to determine compliance unless a
correlation with other test methods is established.
Several attempts have been made to correlate particulate
matter test methods, but statistical analyses of these
data indicate that sampling errors and process and other
variations mask any correlation that may exist. Even if
such correlations do exist, they will very probably differ
for each source category.
An advantage of emission limitations is that any
system of control may be applied; the owner/operator is
responsible only for meeting the standard. This helps
assure proper maintenance and permits innovative control
techniques, but can create problems if well-designed,
properly operated control equipment for some reason exceeds
allowable emission levels. In addition, when a large number
of small sources, such as stationary internal combustion
engines, are involved, the cost of even a single performance
test can be a significant fraction of the cost of the unit.
For standardized units like gas turbines, prototype testing
could be substituted, but a few categories (petroleum product
storage tanks, for example) may best be regulated with equip-
ment standards.
1-5
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(b) Best system of emission reduction. In the selection of
this system, the Act requires that the cost of achieving
such reduction be taken into account and that the system
be adequately demonstrated. The latter stipulation does
not necessarily require that the system be in widespread
use or even that it be in full-scale use at all. Experi-
mental results could suffice, as could reasonable transfer
of technology from one category to another. In practice,
however, the system selected is usually the best available
full-scale operating system. This should be expected,
since a well-controlled existing plant provides actual
cost figures, emission data, and operating and reliability
information that experimental results cannot.
An NSPS applies nationwide over tremendous geographic,
geologic, and climatic variations. Standards must there-
fore provide for differences in raw materials (whether
friability of different coals affects coal cleaning plant
emissions), weather (whether scrubbers can operate during
Alaskan winters), operating parameters (whether seldom
operated emergency power supply gas turbines should be
controlled), and other factors. These variables are
especially important because there is no provision for
granting variances from NSPS, other than total exclusion
or a separate NSPS.
1-6
-------
Stationary sources. A stationary source is any potential or actual
source of air pollution. This has come to include, by implication, the
control system and ducting which handles the exhaust gases from the
source. An affected facility is then a new or modified stationary
source to which a standard applies.
Modification. Basically a modification is any change in an existing
source which increases emissions. EPA has interpreted this as applying
only to emissions to the atmosphere from sources for which NSPS have
been proposed or promulgated, and has excluded some changes from the
definition (such as increases in the hours of operation). Determination
of modification can, however, become complex. The regulation defining
modifications was promulgated on December 16, 1975.
Designated pollutants. When the pollutant for which an NSPS is set
is not listed as either a hazardous (Section 112) or a criteria (Section
108) pollutant, it is defined as a designated pollutant and action under
Section lll(d) of the Act is initiated. In a process similar to that
required for state implementation plans, states are to establish existing
source emission standards for this designated pollutant and submit
control plans to EPA. Standards and control plans are required only for
existing sources to which the NSPS apply if such sources were new sources.
Regulations establishing this procedure have been difficult to
formulate; the role of state agencies in the determination of best
control of existing sources is probably the most controversial issue.
The regulation promulgated on November 17, 1975, specifies that EPA
either issues guidelines (welfare pollutants) or an emission value
1-7
-------
(health pollutants) which states are to utilize in a manner analogous to
the SIP process.
Continuous monitoring. The lack of a variance process, the need to
account for nationwide process variations, and the implications of
emission standards that must be attained: all point to the need for
continuous air pollutant emission monitoring. Present manual source
test methods require such a high investment in both funds and personnel
that they may be used only once every six months or year to determine
compliance. Such tests reveal almost nothing about the effect of process
or raw material variations on emissions.
As a first step in improving emission data gathering and in moving
toward the next step in emission standards, EPA is requiring continuous
monitoring on certain pollutant-affected facility combinations. Regu-
lations promulgated on October 6, 1975, specify performance criteria
that continuous monitoring instruments installed as NSPS requirements
must meet. Specified "continuous" data output ranges from the second-
by-second opacity meter readings to the once every 15 minutes output
from NO instruments.
A
This document contains all New Source Performance Standards,
promulgated under Section 111 of the Clean Air Act, represented in full
as amended. As more sources of pollution are investigated and new
technology developed, the New Source Performance Standards will continue
to be updated to achieve their primary purpose of preventing new air
pollution problems.
Gary D. McCutchen
U.S. Environmental Protection Agency
1-8
-------
SECTION II
SUMMARY OF STANDARDS
AND REVISIONS
-------
II. SUMMARY OF STANDARDS AND REVISIONS
In order to make the information in this document more easily
acessible, a summary has been prepared of all New Source Performance
Standards promulgated since their inception in December 1971. Anyone
who must use the Federal Register frequently to refer to regulations
published by Federal agencies is well aware of the problems of sifting
through the many pages to extract the "meat" of a regulation. Although
regulatory language is necessary to make the intent of a regulation
clear, a more concise reference to go to when looking up a particular
standard would be helpful. With this in mind, the following table was
developed to assist those who work with the NSPS. It includes the
categories of stationary sources and the affected facilities to which
the standards apply; the pollutants which are regulated and the levels
to which they must be controlled; and the requirements for monitoring
emissions and operating parameters. Before developing standards for a
particular source category, EPA must first identify the pollutants
emitted and determine that they contribute significantly to air pollu-
tion which endangers public health or welfare. The standards are then
developed and proposed in the Federal Register. After a period of time
during which the public is encouraged to submit comments on the pro-
posal, appropriate revisions are made to the regulations and they are
II-l
-------
promulgated in the Federal Register. To cite such a promulgation, it is
common to refer to it by volume and page number, i.e. 36 FR 24876, which
means Volume 36, page 24876 of the Federal Register. The table gives
such references for the proposal, promulgation and subsequent revisions
of each standard listed.
Linda S. Chaput
U.S. Environmental
Protection Agency
II-2
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-------
SECTION III
STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
-------
Title 40PROTECTION OF
ENVIRONMENT
Chapter IEnvironmental Protection
Agency
SUBCHAPTEt CAlt PROGRAMS
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY
SOURCES UA
Subparf AGeneral Provision*
Sec
60.1 Applicability.
60.2 Definitions
60.3 Units and abbreviations
60.4 Address.
60.5 Determination of construction or
modification.
60.6 Review of plans.
60.7 Notification and record keeping.
60.8 Performance tests.
60.9 Availability of information.
60.10 State authority
60.11 Compliance with standards and
maintenance requirements.4
60.12 Circumvention.5
60.13 Monitoring requirements.18
60.14 Modification75
60.15 Reconstruction.22
60.16 Priority list.W
Subport BAdoption and SubmiHal of State
Plant for Designated Facilities L'
60.20 Applicability.
60.21 Definitions.
60.22 Publication of guideline documents,
emission guidelines, and final compli-
ance times.
60.23 Adoption and submittal of State
plans; public hearings.
60.24 Emission standards and compliance
schedules.
60.25 Emission inventories, source surveil-
lance, reports.
60.26 Legal authority,
60.27 Actions by the Administrator.
60.28 Plan revisions by the State.
60.29 Plan revisions by the Administrator.
Subport CEmission Guidelines and
Compliance Times 73
60.30 Scope.
60.31 Definitions.
60.32 Designated facilities
60.33 Emission guidelines.
60.34 Compliance times.
Subpart DStandards of Performance for
Fosiil-Fu«l Fired Steam Generators
for Which Construction I* Commenced
After August 17,1*71"
60.40 Applicability and designation of af-
fected facility.
60.41 Definitions.
60.42 Standard for particulate matter
60.43 Standard for sulfur dioxide.
60.44 Standard for nitrogen oxides.
60.45 Emission and fuel monitoring.
60.46 Test methods and procedures
Subpart DaStandards of Performance for
Electric Utility Steam Generating Units for
Which Construction Is Commenced After Sep-
tember 18.197898
60.40a Applicability and designation of af
fected facility.
60.41a Definitions
60.42a Standard for particulate matter
60.43a Standard for sulfur dioxide.
60.44a Standard for nitrogen oxides
60.45a Commercial demonstration permit
60.46a Compliance provisions
60.47a Emission monitoring.
60.48a Compliance determination proce-
dures and methods.
60.49a Reporting requirements.
Subpart EStandards of Performance for
Incinerators
60.50 Applicability and designation of af-
fected facility.
60.51 Definitions.
60.52 Standard for particulate matter
60.53 Monitoring of operations.
60.54 Test methods and procedures
Subpart FStandards of Performance for
Portland Cement Plants
60.60 Applicability and designation of af-
fected facility.
60.61 Definitions.
60.62 Standard for particulate matter
60.63 Monitoring of operations
60.64 Test methods and procedures
Subpart GStandards of Performance for
Nitric Acid Plants
60.70 Applicability and designation of af-
fected facility
60.71 Definitions.
60.72 Standard for nitrogen oxides.
60.73 Emission monitoring.
60.74 Test methods and procedures.
Subpart HStandards of Performance for
Sulfuric Acid Plants
60.80 Applicability and designation of af-
fected facility.
60.81 Definitions
60.82 Standard for sulfur dioxide
60.83 Standard for acid mist
60.84 Emission monitoring
60.85 Test me*hods and procedures
Subpart IStandard* of Performance for
Asphalt Concrete Plants 5
60 90 Applicability and designation of af-
fected facility
60.91 Definitions.
60.92 Standard for particulate matter,
60.93 Test methods and procedures
Subpart JStandards of Performance for
Petroleum Refineries
60.100 Applicability and designation of af-
fected facility
60.101 Definitions.
60.102 Standard for particulate matter.
60.103 Standard for carbon monoxide,
60.104 Standard for sulfur dioxide
60.105 Emission monitoring.
60 106 Test methods and procedures
Subpart KStandards of Performance for
Storage Vessels for Petroleum Liquids
Constructed After June 11, 1973 and Prior to
May 19,19785,11]
60.110 Applicability and designation of af-
fected facility.
60.111 Definitions.
60.112 Standard for volatile organic
compounds (VOC).111
60.113 Monitoring of operations.
Subpart KaStandards of Performance for
Storage vessels for Petroleum Liquids
Constructed After May 18,1978"'
60 llOa Applicability and designation of
affected facility.
60.111a Definitions.
60.112a Standard for volatile organic
compounds (VOC).
60.113a Testing and procedures.
60.114a Equivalent equipment and
procedures.
60.115a Monitoring of operations.
Subport LStandards of Performance for
Secondary Lead Smelters5
60.120 Applicability and designation of af-
fected facility.
60.121 Definitions
60.122 Standard for particulate matter.
60.123 Test methods and procedures.
Subpart MStandards of Performance for Sec-
ondary Brass and Bronze Ingot Production
Plants5
60.130 Applicability and designation of af-
fected facility.
60.131 Definitions.
60.132 Standard for particulate matter.
60.133 Test methods and procedures.
Subpart NStandards of Performance for Iron
and Steel Plants5
60.140 Applicability and designation of af-
fected facility.
60.141 Definitions.
60.142 Standard for particulate matter.
60.143 Monitoring of operations.88
60.144 Test methods and procedures.
Subpart OStandards of Performance for
Sewage Treatment Plants
60.150 Applicability and designation of af-
fected facility.
60.151 Definitions.
60.152 Standard for particulate matter.
60.153 Monitoring of operations
00 i64 i <-M methods and procedures
Subpart PStandards of Performance for
Primary Copper Smelters2'
60.160 Applicability and designation of af
fected facility.
60.161 Definitions.
60 162 Standard for particulate matter
60 163 Standard for sulfur dioxide.
60.164 Standard for visible emissions
60 165 Monitoring of operations
60 166 Test methods, and procedures
III-l
-------
Subpart QStandards of Performance for
Primary Zinc Smelter*
60.170 Applicability and designation of af-
fected facility.
60.171 Definitions
60.172 Standard for paniculate matter.
60.173 Standard for sulfur dioxide.
60.174 Standard for visible emissions.
60.175 Monitoring of operations.
60.176 Test methods and procedures.
Subport RStandards of Performance for
Primary Lead Smelters
26
60.180 Applicability and designation of af-
fected facility
60.181 Definitions.
60.182 Standard for particulate matter.
60.183 Standard for sulfur dioxide.
60.184 Standard for visible emissions.
60.185 Monitoring of operations.
60 186 Test methods and procedures.
Subpart SStandards of Performance for
Primary Aluminum Reduction Plants2^
60.190 Applicability and designation of af-
fected facility.
60.191 Definitions.
60.192 Standard for fluorides.
60.193 Standard for visible emissions.
60.194 Monitoring of operations.
60.195 Test methods and procedures.
Subpart TStandards of Performance for the
Phosphate Fertilizer Industry: Wet Process
Phosphoric Acid Plants14
60.200 Applicability and designation of af-
fected facility.
60.201 Definitions.
60.202 Standard for fluorides.
60.203 Monitoring of operations.
60.204 Test methods and procedures.
Subpart UStandards of Performance for the
Phosphate Fertilizer Industry: Superphot-
phoric Acid Plants
14
60.210 Applicability and designation of af-
fected facility.
60211 Definitions
60.212 Standard for fluorides
60.213 Monitoring of operations.
60.214 Test methods and procedures
Subpart VStandards of Performance for the
Phosphate Fertilizer Industry: Diammonium
Phosphate Plants14
60.220 Applicability and designation of af-
fected facility.
60.221 Definitions.
60 222 Standard for fluorides.
60.223 Monitoring of operations.
60.224 Test methods and procedures.
Subpart WStandards of Performance for the
Phosphate Fertilizer Industry: Triple Super-
phosphate Plants14
60.230 Applicability and designation of af-
fected facility.
60.231 Definitions.
60.232 Standard for fluorides.
60.233 Monitoring of operations.
60.234 Test methods and procedures.
Subpart XStandards of Performance for the
Phosphate Fertilizer Industry: Granular Triple
Superphosphate Storage Facilities14
60.240 Applicability and designation of af-
fected facility.
60.241 Definitions.
60.242 Standard for fluorides.
60.243 Monitoring of operations.
60.244 Test methods and procedures.
Subpart YStandards of Performance for Coal
Preparation Plants26
60.250 Applicability and designation of af-
fected facility.
60.251 Definitions.
60.252 Standards for particulate matter.
60.253 Monitoring of operations.
60.254 Test methods and procedures.
Subpart ZStandards of Performance for
Ferroalloy Production Facilities33
60.260 Applicability and designation of af-
fected facility.
60.261 Definitions.
60.262 Standard for particulate matter.
60.263 Standard for carbon monoxide.
60.264 Emission monitoring.
60.265 Monitoring of operations.
60.266 Test methods and procedures.
Subpart AAStandards of Performance far
Steel Plants: Electric Arc Furnaces16
60.270 Applicability and designation of af-
fected facility.
60.271 Definitions.
60.272 Standard for particulate matter
60 273 Emission monitoring
60.274 Monitoring ol operations
60.275 Test methods and procedures
Subport BBStandards of Performance for
Kraft Pulp Mill*82
60.280 Applicability and designation of af-
fected facility.
60.281 Definitions.
60.282 Standard for particulate matter.
60.283 Standard for total reduced sulfur
(TRS).
60.284 Monitoring of emissions and oper-
ations.
60.285 Test methods and procedures
Subpart CC[Reserved]
Subpart DOStandards of Performance fo
Grain Elevators90
60.300 Applicability and designation of af-
fected facility.
60.301 Definitions.
60.302 Standard for particulate matter.
60.302 Test methods and procedures.
60.304 Modification.
Subpart GOStandards of Performance for
Stationary Gas Turbine*10'
60.330 Applicability and designation of
affected facility.
60.331 Definitions.
00.332 Standard for nitrogen oxides.
60.333 Standard for sulfur dioxide.
60.334 Monitoring of operations.
60.335 Test methods and procedures.
Subpart HHStandards of Performance for
Lime Manufacturing Plants 8i
60.340 Applicability and designation of af-
fected facility.
60.341 Definitions.
60.342 Standard for particulate matter.
60.343 Monitoring of emissions and oper-
ations.
60.344 Test methods and procedures.
III-2
-------
Appendix AReference Methods
Method 1Sample and velocity traverses
for stationary sources.
Method 2Determination of stack gas ve-
locity and volumetric flow rate (Type S
pitot tube).
Method 3Gas analysis for carbon dioxide,
oxygen, excess air, and dry molecular
weight.
Method 4Determination of moisture con-
tent in stack gases.
' Method 5Determination of particulate
emissions from stationary sources.
Method 6Determination of sulfur dioxide
emissions from stationary sources.
Method 7Determination of nitrogen oxide
emissions from stationary sources.
Method 8Determination of sulfuric acid
mist and sulfur dioxide emissions from
stationary sources.
Method 9Visual determination of the
opacity of emissions from stationary
sources.
Method 10Determination of carbon mon-
oxide emissions from stationary sources.
Method 11Determination of hydrogen sul-
fide content of fuel gas streams in petro-
leum refineries.79
Method 12[Reserved]
Method 13ADetermination of total flu-
oride emissions from stationary
sourcesSPADNS Zirconium Lake
Method.
Method 13BDetermination of total flu-
oride emissions from stationary
sourcesSpecific Ion Electrode Method.
Method 14Determination of fluoride emis-
sions from potroom roof monitors of pri-
mary aluminum plants.27
Method 15Determination of hydrogen sul-
fide, carbonyl sulfide, and carbon disul-
fide emissions from stationary sources.86
Method 16Semicontinuous determination
of sulfur emissions from stationary
sources.82
Method 17Determination of particulate
emissions from stationary sources (in-
stack filtration method).82
METHOD 19. DETERMINATION OF SULFUR
DIOXIDE REMOVAL EFFICIENCY AND PARTIC-
ULATE, SULFUR DIOXIDE AND NITROGEN
OXIDES EMISSION RATES PROM ELECTKIC
UTILITY STEAM GENERATORS98
Method 20Determination of Nitrogen
Oxkie», Sulfur Dioxide, and Oxygen
missions from Stationary Gas Turbines101
Appendix BPerformance Specifications'8
Performance Specification 1Perform-
ance specifications and specification test
procedures for transmissometer systems for
continuous measurement of the opacity of
stack emissions.
Performance Specification 2Perform-
ance specifications and specification test
procedures for monitors of SO> and NO,
from stationary sources.
Performance Specification 3Perform-
ance specifications and specification test
procedures for monitors of CO, and O, from
stationary sources.
Appendix CDetermination of Emission
Rate Change22
Appendix DRequired Emission Inventory
Information21
AUTHORITY: Sec. Ill, 301(a) of the Clean
Air Act as amended (42 U.S.C. 7411,
7601(a)>, unless otherwise noted.68,83
III-3
-------
Subport AGeneral Previsions
§60.1 Applicability.8'21
Except as provided in Subparts B
and C, the provisions of this part
apply to the owner or operator of any
stationary source which contains an
affected facility, the construction or
modification of which is commenced
after the date of publication in this
part of any standard (or, if earlier, the
date of publication of any proposed
standard) applicable to that facility.
§ 60.2 Definitions.102
The terms used in this part are
defined in the Act or in this section as
follows:
"Act" means the Clean Air Act (42
U.S.C. 1857 et seq., as amended by Pub.
L. 91-604, 84 Stat. 1676).
"Administrator" means the
Administrator of the Environmental
Protection Agency or his authorized
representative.
"Affected facility" means, with
reference to a stationary source, any
apparatus to which a standard is
applicable.
"Alternative method" means any
method of sampling and analyzing for
an air pollutant which is not a reference
or equivalent method but which has
been demonstrated to the
Administrator's satisfaction to, in
specific cases, produce results adequate
for his determination of compliance.5
"Capital expenditure" means an
expenditure for a physical or
operational change to an existing facility
which exceeds the product of the
applicable "annual asset guideline
repair allowance percentage" specified
in the latest edition of Internal Revenue
Service (IRS) Publication 534 and the
existing facility's basis, as defined by
section 1012 of the Internal Revenue
Code. However, the total expenditure
for a physical or operational change to
an existing facility must not be reduced
by any "excluded additions" as defined
in IRS Publication 534, as would be done
for tax purposes.22'109
"Commenced" means, with respect to
the definition of "new source" in section
lll(a)(2) of.the Act, that an owner or
operator has undertaken a continuous
program of construction or modification
or that an owner or operator has entered
into a contractual obligation to
undertake and complete, within a
reasonable time, a continuous program
of construction or modification.5
' Construction" means fabrication.
erection, or installation of an affected
facility.
"Continuous monitoring system"
means the total equipment, required
under the emission monitoring sections
in applicable subparts, used to sample
and condition (if applicable), to analyze.
and to provide a permanent record of
emissions or process parameters.18
"Equivalent method" means any
method of sampling and analyzing for
an air pollutant which has been
demonstrated to the Administrator's
satisfaction to have a consistent and
quantitatively known relationship to the
reference method, under specified
conditions.5
"Existing facility" means, with
reference to a stationary source, any
apparatus of the type for which a
standard is promulgated in this part, and
the construction or modification of
which was commenced before the date
of proposal of that standard; or any
apparatus which could be altered in
such a way as to be of that type.22
"Isokinetic sampling" means sampling
in which the linear velocity of the gas
entering the sampling nozzle is equal to
that of the undisturbed gas stream at the
sample point.
"Malfunction" means any sudden and
unavoidable failure of air pollution
control equipment or process equipment
or of a process to operate in a normal or
usual manner. Failures that are caused
entirely or in part by poor maintenance.
careless operation, or any other
preventable upset condition or
preventable equipment breakdown shall
not be considered malfunctions.4
"Modification" means any physical
change in, or change in the method of
operation of, an existing facility which
increases the amount of any air
pollutant (to which a standard applies)
emitted into the atmosphere by that
facility or which results in the emission
of any air pollutant (to which a standard
applies) into the atmosphere not
previously emitted.22
"Monitoring device" means the total
equipment, required under the
monitoring of operations sections in
applicable subparts, used to measure
and record (if applicable) process
parameters.18
"Nitrogen oxides" means all oxides of
nitrogen except nitrous oxide, as
measured by test methods set forth in
this part.
"One-hour period" means any 60- 41h
minute period commencing on the hour.
"Opacity" means the degree to which
emissions reduce the transmission of
light and obscure the view of an object
in the background.
"Owner or operator" means any
person who owns, leases, operates,
controls, or supervises an affected
facility or a stationary source of which
an affected facility is a part.
"Particulate matter" means any finely
divided solid or liquid material, other
than uncombined water, as measured by
the reference methods specified under
each applicable subpart, or-an 5 8 w
equivalent or alternative method. ' '
"Proportional sampling" means
sampling at a rate that produces a
constant ration of sampling rate to stack
gas flow rate.
"Reference method" means any
method of sampling and analyzing for
an air pollutant as described in
Appendix A to this part.5'8
"Run" means the net period of time
during which an emission sample is
collected. Unless otherwise specified, a
run may be either intermittent or
continuous within the limits of good
engineering practice.5
"Shutdown" means the cessation of
operation of an affected facility for any
purpose.4
' Six-minute period" means any one of
the 10 equal parts of a one-hour period.18
"Standard" means a standard of
performance proposed or promulgated
under this part.
"Standard conditions" means a
temperature of 293 K (68°F) and a
pressure of 101.3 kilopascals (29.92 in
Hg}.5'84
"Startup" means the setting in
operation of an affected facility for any
purpose.
§ 60.3 Units and abbreviations.5'62
Used in this part are abbreviations
and symbols of units of measure.
These are defined as follows:
(a) System International (SI) units
of measure:
Aampere
ggram
Hzhertz
Jjoule
Kdegree Kelvin
kgkilogram
mmeter
m3cubic meter
mgmilligram10"1 gram
mmmillimeter10" "meter
Mgmegagram106 gram
mo!mole
N - newton
ng nanogram10"1 gram
nui -nanometer10 "meter
Papascal
ssecond
Vvolt
Wwatt
nohm
grnicrogram10 * gram
65
III-4
-------
(b) Other units of measure:
BtuBritish thermal unit
"Cdegree Celsius (centigrade)
calcalorie
cfmcubic feet per minute
cu ftcubic feet
dcfdry cubic feet
dcmdry cubic meter
dscfdry cubic feet at standard conditions
dscmdry cubic meter at standard condi-
tions
eqequivalent
"Pdegree Fahrenheit
ftfeet
galgallon
grgrain
g-eqgram equivalent
hrhour
ininch
k-1,000
]liter
1pmliter per minute
Ibpound
meqmilliequivalent
minminute
mlmilliliter
mol. wt.molecular weight
ppbparts per billion
ppmparts per million
psiapounds per square inch absolute
psigpounds per square inch gage
°Rdegree Rankine
scfcubic feet at standard conditions
scfhcubic feet per hour at standard condi-
tions
scmcubic meter at standard conditions
secsecond
sq ftsquare feet
stdat standard conditions
(c) Chemical nomenclature:
CdScadmium sulfide
COcarbon monoxide
CO,carbon dioxide
HC1hydrochloric acid
Hemercury
HzOwater
HjShydrogen sulfide
H,SO.sulfunc acid
Ninitrogen
NOnitric oxide
NOinitrogen dioxide
NO,nitrogen oxides
Oioxygen
SOasulfur dioxide
SO,sulfur trioxide
SO,sulfur oxides
(d) Miscellaneous:
A.S.T.M.American Society for Testing and
Materials
(Sees. Ill and 301(a) of the Clean Air Act.
sec. 4(a) of Pub. L. 91-604, 84 Slat 1683. sec
2 of Pub. L. 90-148, 81 Slat. 504 (42 U S.C
1857c-6, 1857g(a)))
§60.4 Address.512
(a) All requests, reports, applica-
tions, submittals, and other communi-
cations to the Administrator pursuant
to this part shall be submitted in du-
plicate and addressed to the appropri-
ate Regional Office of the Environ-
mental Protection Agency, to the at-
tention of the Director, Enforcement
Division. The regional offices are as
follows:
Region I (Connecticut, Maine, New Hamp-
shire, Massachusetts, Rhode Island, Ver-
mont), John F. Kennedy Federal Building.
Boston, Massachusetts 02203.
Region II (New York, New Jersey, Puerto
Rico, Virgin Islands), Federal Office Build-
ing, 26 Federal Plaza (Foley Square), New.
York, New York 10007.
Region III (Delaware, District of Colum-
bia, Pennsylvania, Maryland, Virginia, West
Virginia), Curtis Building, Sixth and
Walnut Streets, Philadelphia, Pennsylvania
19106.
Region IV (Alabama, Florida, Georgia.
Mississippi, Kentucky, North Carolina.
South Carolina, Tennessee), Suite 300, 1421
Peachtree Street. Atlanta, Georgia 30309
Region V (Illinois, Indiana. Minnesota.
Michigan, Ohio, Wisconsin). 230 South
Dearborn Street, Chicago, Illinois 60604.59
Region VI (Arkansas. Louisiana, New
Mexico, Oklahoma, Texas), 1600 Patterson
Street. Dallas, Texas 75201
Region VII (Iowa, Kansas, Missouri, Ne-
braska), 1735 Baltimore Street, Kansas City,
Missouri 63108
Region VIII (Colorado, Montana, North
Dakota, South Dakota, Utah, Wyoming),
196 Lincoln Towers, 1860 Lincoln Street.
Denver, Colorado 80203
Region IX (Arizona, California, Hawaii.
Nevada, Guam, American Samoa), 100 Cali-
fornia Street. San Francisco, California
94111
Region X (Washington, Oregon, Idaho,
Alaska), 1200 Sixth Avenue. Seattle, Wash-
ington 98101.
(b) Section lll(c) directs the Admin-
istrator to delegate to each State,
when appropriate, the authority to im-
plement and enforce standards of per-
formance for new stationary sources
located in such State. All information
required to be submitted to EPA under
paragraph (a) of this section, must
also be submitted to the appropriate
State Agency of any State to which
this authority has been delegated
(provided, that each specific delega-
tion may except sources from a certain
Federal or State reporting require-
ment). The appropriate mailing ad-
dress for those States whose delega-
tion request has been approved is as
follows:
(A) (reserved)
(B) State of Alabjma, Au Pollution Con
trol Division, Air Pollution Control Commis-
sion, 645 S. McDonough Street, Mont
pomcry, Alabama 36104 "
(C) [reserved]
(D) Arizona.
Maricopa County Department of Health
Services, Bureau of Air Pollution Control,
1825 East Roosevelt Street, Phoenix, Ariz.
85006.
Pima County Health Department, Air
Quality Control District. 151 West Congress.
Tucson, Ariz. 85701.5'. 89
(P) California.
Bay Area- Air Pollution Control District,
93P Ellis Street, San Francisco, Calif. 94 i a
Del Norte County Air Pollution Control
District, Courthouse, Crescent City, Calif.
95531.
Fresno County Air Pollution Control Dis-
trict, 515 South Cedar Avenue, Fresno,
Calif. 93702
Humboldt County Air Pollution Control
District, 5600 ' South Broadway, Eureka,
Calif. 95501.
Kern County Air Pollution Control Dis-
trict, 1700 Flower Street (P.O. Box 997), Ba-
kersfield, Calif. 93302.
Madera County Air Pollution Control Dis-
trict, 135 West Yosemlte Avenue, Madera,
Calif. 93637.
Mendocino County Air Pollution Control
District, County Courthouse, Uklah, Calif.
94582.
Monterey Bay Unified Air Pollution Con-
trol District, 420 Church Street (P.O. Box
487), Salinas, Calif. 93901.
Northern Sonoma County Air Pollution
Control District, 3313 Chanate Road, Santa
Rosa, Calif. 95404.
Sacramento County Air Pollution Control
District, 3701 Branch Center Road, Sacra-
mento, Calif. 95827.
San Diego County Air Pollution Control
District, 9150 Chesapeake Drive, San Diego,
Calif. 92123.
San Joaquin County Air Pollution Control
District, 1601 East Hazelton Street (P.O.
Box 2009), Stockton, Calif. 95201.
Santa Barbara County Air Pollution Con-
trol District, 4440 Calle Real, Santa Bar-
bara, Calif. 93110.
Shasta County Air Pollution Control Dis-
trict, 1855 Placer Street, Redding, Calif.
96001.
South Coast Air Quality Management Dis-
trict, 9420 Telstar Avenue, El Monte, Caltf.
91731.
Stanislaus County Air Pollution Control
District, 820 Scenic Drive, Modesto, Calif.
95350.
Trinity County Air Pollution Control Dis-
trict, Box AJ, Weaverville, Calif. 96093.
Ventura County Air Pollution Control
District, 625 East Santa Clara Street, Ven-
tura, Calif. 93001. 15,17,36,40,44,48,52,89
(O> State of Colorado, Colorado Air
Pollution Control Division, 4210 Ear.
llth Avenue. Denver. Colorado 80220. 20
(H) State of Connecticut, Department
of Environmental Protection, State Of-
fice Building, Hartford. Connecticut
3I
(I) State of Delaware (for fossil fuel-fired
steam generators; incinerators; nitric acid
plants, asphalt concrete plants; storage
vessels for petroleum liquids; sulfunc acid
plants, and sewage treatment plants only.
Delaware Department of Natural Resources
and Environmental Control, Edward Tatnall
B.nldmg. Dover. Delaware 19901.8I«106
'J)-(K) [reserved]
\li) State of Georgia, Environmental Fro-
rrotlon Division, Department of Natural Re-
"lurces. 270 Washington Street. S.W.. At-
lanta, Georgia 30334. 38
i M ) | Reserved |
(N) State of Idaho, Department of Health
anil Welfare, Statehouse. Boise, Idaho 83701 '3
(O) | Reserved |
IP) State of Indiana, Indiana Air Pollu-
ti< . Control Board, 1330 West Michigan
SI «f , Indianapolis, Indiana 46206 46
III-5
-------
I Q) State of Iowa, Department of Environ-
mental Quality, 3920 Delaware, P.O. Box 3226,
Des Moines, Iowa 50316. 54
(R)- [reserved],
(S) Division of JUr Pollution Control, De
partment for Natural Resources and Envi-
ronmental Prot»otion, U.S. 127, Frankfort
Ky. 40601.80
IT) | Reserved |
(U) State of Maine. Department of Envi-
ronmental Protection, State House. Augusta.
Maine 04330. 24
(V) State of Maryland: Bureau of Air
Quality and Noise Control. Maryland State
Department of Health and Mental Hygiene,
201 West Preston Street, Baltimore, Maryland
21 201 .°5
(W) Massachusetts Department of Envi-
ronmental Quality Engineering, Division of
Air Quality Control, 600 Washington Street.
Boston. Massachusetts 02111.34
(X) Stato of Michigan, Air Pollution
Control Division, Michigan Department of
Natural Resources. Stevens T. Mason Build-
ing. 8th Floor, Lansing, Michigan 48926. 25
(T) Minnesota Pollution Control Agency
Division of Air Quality, 1935 West County
Road B-2, Bosevllle, Minn. 55113. 78
iZ) | Reserved |
(AA) [i
fBB) State of Montana, Department of
Health and Environmental Services, Cogswell
Building. Helena, Mont. 69601. 70
Nebraska Department of Envi-
ronmental Control, P.O. Box 94653, State
House Station, Lincoln, Nebraska 68509 M
(DD) Nevada.
Clark County, County District Health De-
partment, Air Pollution Control Division,
625 Shadow Lane, Las Vegas, Nev. 89106.
Washoe County District Health Depart-
ment, Division of Environmental Protection,
10 Kirman Avenue, Reno, Nev. 89502. 89
(QQ> State or South Dakota, Depnn-
ment of Environmental Protection, -W
FVii Building, Pierre, South Daiots
&750J.M
i RR) (reserved]
UJS. Virgin Islands: V£. Vir-
gin Islands Department of Conservation
and Cultural Affairs, P.O. Box 578, Char-
lotte Amalie, St. Thomas, U.S. Virgin
Islands 00801.4r
(ODD) (reserved)
III-6
-------
§ 60.5 Determination of construction or
modification. 2 2
(a) When requested to do so by an
owner or operator, the Administrator
will make a determination of whether
action taken or intended to be taken by
such owner or operator constitutes con-
struction (including reconstruction) or
modification or the commencement
thereof within the meaning of this part.
(b) The Administrator will respond to
any request for a determination under
paragraph (a) of this section within 30
days of receipt of such request.
g 60.6 Review of plan*.
(a) When requested to do so by an
owner or operator, the Administrator will
review plans for construction or modifi-
cation for the purpose of providing
technical advice to the owner or operator.
(b) (1) A separate request shall be sub-
mitted for each construction or modifi-
cation project. 5
(2) Each request shall identify the lo-
cation of such project, and be accom-
panied by technical information describ-
ing the proposed nature, size, design, and
method of operation of each affected fa-
cility involved hi such project, including
information on any requipment to be
used for measurement or control of emis-
sions. 5
(c) Neither a request for plans review
Dor advice furnished by the Administra-
tor in response to such request snail (1)
relieve an owner or operator of legal
responsibility for compliance with any
provision of this part or of any applicable
State or local requirement, or (2) prevent
the Administrator from implementing or
enforcing any provision of this part or
taking any other action authorized by the
Act.
§ 60.7 Notification and record keeping.
(a) Any owner or operator subject to
the provisions of this part shall furnish
fee Administrator written notification u
fellows:
(DA notification of the date construc-
tion (or reconstruction as defined under
I $0.15) of an affected facility is com-
menced postmarked no later than 30
days after such date. This requirement
shall not apply in the case of mass-pro-
duced facilities which are purchased In
completed form. 22
(2) A notification of the anticipated
date of initial startup of an affected
facility postmarked not more than 60
days nor less than 30 days prior to such
date."
(3) A notification of the actual date
of Initial startup of an affected facility
postmarked within 15 days after such
state. 22
(4) A notification of any physical or
perational change to an existing facil-
ftj^which may increase the emission rate
of any air pollutant to which a stand-
ard applies, unless that change is spe-
$!j|Vo»lly exempted under an applicable
ubpart or in I 60 14 used, and the
date and time of commencement and
completion of each time period of excess
emissions.18
(2) Specific identification of each
period of excess emissions that occurs
during startups, shutdowns, and mal-
functions of the affected facility. The
nature and cause of any malfunction (if
known), the corrective action taken or
preventative measures adopted.18
(3) The date and time identifying each
period during which the continuous
monitoring system was inoperative ex-
cept for zero and spar, checks and the
nature of the system repairs or adjust-
ments. '8
(4) When no excess emissions have
occurred or the continuous monitoring
system (si have not been inoperative, re-
paired, or adjusted, such information
ahall be stated in the report *.18
(d> Any owner or operator subject to
the provisions of this part shall maintain
a file of all measurements, including con-
tinuous monitoring system, monitoring
device, and performance testing meas-
urements; all continuous monitoring sys-
tem performance evaluations, all con-
tinuous monitoring system or monitoring
device calibration checks; adjustments
and maintenance performed on these
systems or devices; and all other infor-
mation required by this part recorded in
a permanent form suitable for inspec -
Uon The file shall be retained for at least
two years following the date of such
measurements, maintenance, reports, and
records 5,18
If notification substantially similar
to that in paragraph (a) of this section
is required by any other State or local
agency, sending the Administrator a
copy of that notification will satisfy the
requirements of paragraph (a) of this
section.22
§ 60.8 Performance tests.
(a) Within 60 days after achieving the
maximum production rate at which the
affected facility will be operated, but not
later than 180 days after Initial startup
of such facility and at such other times
as may be required by the Administrator
under section 114 of the Act, the owner
or operator of such facility shall conduct
performance test(s) and furnish the Ad-
ministrator a written report of the results
of such performance test(s).
(b) Performance tests shall be con-
ducted and data reduced in accordance
with the test methods and procedures
contained in each applicable subpart
unless the Administrator (1) specifies
or approves, in specific cases, the use of
a reference method with minor changes
in methodology, (2) approves the use
of an equivalent method, (3) approves
the use of an alternative method the re-
sults of which he has determined to be
adequate for indicating whether a spe-
cific source is in compliance, or (4)
waives the requirement for performance
tests because the owner or operator of
a source has demonstrated by other
means to the Administrator's satisfac-
tion that the affected facility is in> com-
pliance with the standard. Nothing in
this paragraph shall be construed to
abrogate the Administrator's authority
to require testing under section 114 of
the Act.5
(c) Performance tests shall be con-
ducted under such conditions as the Ad-
ministrator shall specify to the plant
operator based on representative per-
formance of the affected facility. The
owner or operator shall make available
to the Administrator such records as may
be necessary to determine the conditions
of the performance tests. Operations
during periods of startup, shutdown, and
malfunction shall not constitute repre-
sentative conditions for the purpose of a
performance tast nor shall emissions in
excess of the level of the applicable emis-
sion limit during periods of startup,
shutdown, and malfunction be con-
sidered a violation of the applicable
emission limit unless otherwise specified
in the applicable standard.4 74
(d) The owner or operator of an
affected facility shall provide the
Administrator at least 30 days prior
notice of any performance test, except
as specified under other subparts, to
afford the Administrator the opportunity
to have an observer present.5'98
(e) The owner or operator of an
affected facility shall provide, or cause to
III-7
-------
be provided, performance testing facil-
ities as follows:
(1) Sampling ports adequate for test
methods applicable to such facility.
(2) Safe sampling platform(s).
(3) Safe access to sampling plat-
form (s) .
(4) Utilities for sampling and testing
equipment.
(f) Unless otherwise specified in the
applicable subpart, each performance
test shall consist of three separate runs
using the applicable test method. Each
run shall be conducted for the time and
under the conditions specified in the
applicable standard. For the purpose of
determining compliance with an
applicable standard, the arithmetic
means of results of the three runs shall
apply. In the event that a sample is
accidentally lost or conditions occur in
which one of the three runs must be
discontinued because of forced
shutdown, failure of an irreplaceable
portion of the sample train, extreme
meteorological conditions, or other
circumstances, beyond the owner or
operator's control, compliance may,
upon the Administrator's approval, be
determined using the arithmetic mean of
the results of the two other runs.5'98
(Sec. 114. Clean Air Act U amended (42
U.SC 7414)). 68<83
§ 60.9 Availability of information.
The availabality to the public of in-
formation provided to, or otherwise ob-
tained by, the Administrator under this
Part shall be governed by Part 2 of this
chapter. (Information submitted volun-
tarily to the Administrator for the pur-
poses of §§ 60.5 and 60.6 is governed by
§ 2.201 through § 2.213 of this chapter
and not by § 2.301 of this chapter.)
(Sec. 114. Clean Air Act ii amended (42
TLS.C. 7414)). *8'83
§ 60.10 State authority.
The provisions of this part shall not
be construed in any manner to preclude
any State or political subdivision thereof
from:
(a) Adopting and enforcing any emis-
sion standard or limitation applicable to
an affected facility, provided that such
emission standard or limitation is not
less stringent than the standard appli-
cable to such facility.
(b) Requiring the owner or operator
of an affected facility to obtain permits,
licenses, or approvals prior to initiating
construction, modification, or operation
of such facility.
(Src 116 of the Cletm Air Act as amended
(42 U.SC. 7416)). 68,83
§ 60.11 Compliance with standards and
maintenance requirements.
(a) Compliance with standards in this
part, other than opacity standards, shall
be determined only by performance
tests established by § 60.8, unless
otherwise specified in the applicable
standard.111
(b) Compliance with opacity stand-
ards in this part shall be determined by
conducting observations in accordance
with Reference Method 9 in Appendix A
of this part or any alternative method
that is approved by the Administrator.
Opacity readings of portions of plumes
which contain condensed, uncombined
water vapor shall not be used for pur-
poses of determining compliance with
opacity standards. The results of con-
tinuous monitoring by transmissometer
which indicate that the opacity at the
time visual observations were made was
not in excess of the standard are proba-
tive but not conclusive evidence of the
actual opacity of an emission, provided
that the source shall meet the burden of
proving that the instrument used meets
(at the time of the alleged violation)
Performance Specification 1 in Appendix
B of this part, has been properly main-
tained and (at the time of the alleged
violation) calibrated, and that the
resulting data have not been tampered
with in any way. 10-60
(c) The opacity standards set forth in
this part shall apply at all times except
during periods of startup, shutdown, mal-
function, and as otherwise provided In
the applicable standard.
(d) At all times, including periods of
startup, shutdown, and malfunction,
owners and operators shall, to the extent
practicable, maintain and operate any
affected facility Including associated air
pollution control equipment in a manner
consistent with good air pollution control
practice for minimizing emissions. De-
termination of whether acceptable oper-
ating and maintenance procedures are
being used will be based on information
available to the Administrator which may
Include, but is not limited to, monitoring
results, opacity observations, review of
operating and maintenance procedures,
and inspection of the source.
(e) (1) An owner or operator of an af-
fected facility may request the Admin-
istrator to determine opacity of emis-
sions irom the affected facility during
the initial performance tests required by
§ 60 8.10
(2) Upon receipt from such owner or
operator of the written report of the re-
sults of the performance tests required
by § 60.8, the Administrator will make
a finding concerning compliance with
opacity and other applicable standards.
If the Administrator finds that an af-
fected facility is in compliance with all
applicable standards for which perform-
ance tests are conducted in accordance
with § 60.8 of this part but during the
time such performance tests are being
conducted fails to meet any applicable
opacity standard, he shall notify the
owner or operator and advise him that he
may petition the Administrator within
10 days of receipt of notification to make
appropriate adjustment to the opacity
standard for the affected facility.10
(3) The Administrator will grant such
a petition upon a demonstration by the
owner or operator that the affected fa-
cility and associated air pollution con-
trol equipment was operated and main-
tained in a manner to minimize the
opacity of emissions during the perform-
ance tests; that the performance tests
were performed under the conditions es-
tablished by the Administrator; and that
the affected facility and associated air
pollution, control equipment were In-
capabls of being adjusted or operated to
meet the applicable opacity standard.10
<4> The Administrator will establish
an opacity standard for the affected
facility meeting the above requirements
at a level at which the source will be
able, t.s indicated by the performance
and edacity tests, to meet the opacity
standard at all times during which the
source is meeting the mass or concentra-
tion enission standard. The Adminis-
trator will promulgate the new opacity
standard in the FEDERAL REGISTER. 10
(Sec. 114. Clean Air Act is amended (42
U.S.C. V414».68,83
§ 60.11! Circumvention.
No owner or operator subject to the
provisions of this part shall build, erect,
install, or use any article, machine,
equipment or process, the use of which
conceals an emission which would other-
wise constitute a violation of an applica-
ble standard. Such concealment In-
cludes, but Is not limited to, the use of
gaseous diluents to achieve compliance
with an opacity standard or with a
standard which is based on the concen-
tration of a pollutant In the gases dis-
charged to the atmosphere.
i p
§60.].'! Monitoring requirements.
(a) For the purposes of this section,
all continuous monitoring systems re-
quired under applicable subparts shall
be subject to the provisions of this sec-
tion upon promulgation of perfor-
mance specifications for continuous
monitoring system under Appendix B
to this part, unless: 82
(1) The continuous monitoring
system is subject to the provisions of
paragraphs (c)(2) and (c)(3) of this
section, or 82
(2) otherwise specified in an applica-
ble subpart or by the Administrator.82
(b) All continuous monitoring systems
and monitoring devices shall be installed
and operational prior to conducting per-
formance tests under § 60.8. Verification
of operational status shall, as a mini-
mum, consist of the following:
-------
(1) For continuous monitoring sys-
tems referenced in paragraph (c) (1) of
this section, completion of the condi-
tioning /period specified by applicable
requirements in Appendix B.
(2) For continuous "monitoring sys-
tems referenced in paragraph (c) (2) of
this section, completion of seven days of
operation.
(3) For monitoring devices referenced
in applicable subparts, completion of the
manufacturer's written requirements or
recommendations for checking the op-
eration, or calibration of the device.
(c) During any performance tests
required under § 60.8 or within 30 days
thereafter and at such other times as
may be required by the Administrator
under section 114 of the Act, the owner
or operator of any affected facility shall
conduct continuous monitoring system
performance evaluations and furnish the
Administrator within 60 days thereof two
or, upon request, more copies of a written
report of the results of such tests. These
continuous monitoring system perform-
ance evaluations shall be conducted in
accordance with the following specifica-
tions and procedures:
(1) Continuous monitoring systems
listed within this paragraph except as
provided in paragraph (c) (2) of this sec-
tion shall be evaluated in accordance
with the requirements and procedures
contained in the applicable perform-
ance specification of Appendix B as
follows:
(i) Continuous monitoring systems for
measuring opacity of emissions shall
comply with Performance Specification 1.
(ii) Continuous monitoring systems for
measuring nitrogen oxides emissions
shall comply with Performance Specifi-
cation 2.
(iii) Continuous monitoring systems for
measuring sulfur dioxide emissions shall
comply with Performance Specification 2.
(iv) Continuous monitoring systems for
measuring the oxygen content or carbon
dioxide content of effluent gases shall
comply with Performance Specification
3.
(2) An owner or operator who, prior
to September 11, 1974, entered into a
binding contractual obligation to pur-
chase specific continuous monitoring
system components except as referenced
by paragraph (c) (2) (iii) of this section
shall comply with the following require-
ments:
(i) Continuous monitoring systems for
measuring opacity of emissions shall be
capable of measuring emission levels
within ±20 percent with a confidence
level of 95 percent. The Calibration Error
Test and associated calculation proce-
dures set forth in Performance Specifi-
cation 1 of Appendix B shall be used for
demonstrating compliance with this
specification.
(li) Continuous monitoring systems
for measurement of nitrogen oxides or
sulfur dioxide shall be capable of meas-
uring emission levels within ±20 percent
with a confidence level of 95 percent. The
Calibration Error Test, the Field Test
for Accuracy (Relative), and associated
operating and calculation procedures set
forth in Performance Specification 2 of
Appendix B shall be used for demon-
strating compliance with this specifica-
tion.
(iii) Owners or operators of all con-
tinuous monitoring systems installed on
an affected facility prior to October 6,
1975 are not required to conduct
tests under paragraphs (c) (2) (i) and/or
(ii) of this section unless requested by
the Administrator. 23
(3) All continuous monitoring systems
referenced by paragraph (c~> (2) of this
section shall be upgraded or replaced < if
necessary1 with new continuous moni-
toring systems, and the new or improved
systems shall be demonstrated to com-
ply with applicable performance speci-
fications under paragraph (cHl) of this
section on or before September 11, 1979.
(d) Owners or operators of all con-
tinuous monitoring systems installed in
accordance with the provisions of this
part shall check the zero and span drift
at least once daily in accordance with
the method prescribed by the manufac-
turer of such systems unless the manu-
facturer recommends adjustments at
shorter intervals, in which case such
recommendations shall be followed. The
zero and span shall, as a minimum, be
adjusted whenever the 24-hour zero drift
or 24-hour calibration drift limits of the
applicable performance specifications in
Appendix B are exceeded. For continuous
monitoring systems measuring opacity of
emissions, the optical surfaces exposed
to the effluent gases shall be cleaned prior
to performing the zero or span drift ad-
justments except that for systems using
automatic zero adjustments, the optical
surfaces shall be cleaned when the cum-
ulative automatic zero compensation ex-
ceeds four percent opacity. Unless other-
wise approved by the Administrator, the
following procedures, as applicable, shall
be followed:
(1) For extractive continuous moni-
toring systems measuring gases, mini-
mum procedures shall include introduc-
ing applicable zero and span gas mixtures
into the measurement system as near the
probe as is practical. Span and zero gases
certified by their manufacturer to be
traceable to National Bureau of Stand-
ards reference gases shall be used when-
ever these reference gases are available.
The span and zero gas mixtures shall be
the same composition as specified in Ap-
pendix B of this part. Every six months
from date of manufacture, span and zero
gases shall be reanalyzed by conducting
triplicate analyses with Reference Meth-
ods 6 for SO., 7 for NO,, and 3 for Oi
and CO?, respectively. The gases may bfl
analyzed at less frequent intervals If
longer shelf lives are guaranteed by the
manufacturer.
(2) For non-extractive continuous
monitoring systems measuring gases,
minimum procedures shall include up-
scale check (s) using a certified calibra-
tion gas cell or test cell which is func-
tionally equivalent to a known gas con-
centration. The zero check may be per-
formed by computing the zero value from
upscale measurements or by mechani-
cally producing a zero condition.
(3) For continuous monitoring systems
measuring opacity of emissions, mini-
mum procedures shall include a method
for producing a simulated zero opacity
condition and an upscale (span) opacity
condition using a certified neutral den-
sity filter or other related technique to
produce a known obscuration of the light
beam. Such procedures shall provide a
system check of the analyzer internal
optical surfaces and all electronic cir-
cuitry including the lamp and photode-
tector assembly.
i.e) Except for system breakdowns, re-
pairs, calibration checks, and zero and
span adjustments required under para-
graph (d) of this section, all continuous
monitoring systems shall be in contin-
uous operation and shall meet minimum
frequency of operation requirements as
follows:
(1) All continuous monitoring sys-
tems referenced by paragraphs (c)(l)
and tc) (.2) of this section for measuring
opacity of emissions shall complete a
minimum of one cycle of sampling and
analyzing for each successive ten-second
period and one cycle of data recording
for each successive six-minute period.5'
(2) All continuous monitoring systems
referenced by paragraph (c) (1) of this
section for measuring oxides of nitrogen,
sulfur dioxide, carbon dioxide, or oxygen
shall complete a minimum of one cycle
of operation (sampling, analyzing, and
data recording) for each successive 15-
minute period.
(3) All continuous monitoring systems
referenced by paragraph (c) (2) of this
section, except opacity, shall complete a
minimum of one cycle of operation (sam-
pling, analyzing, and data recording)
for each successive one-hour period.
(f) All continuous monitoring systems
or monitoring devices shall be installed
such that representative measurements
of emissions or process parameters from
the affected facility are obtained. Addi-
tional procedures for location of contin-
uous monitoring systems contained in
the applicable Performance Specifica-
tions of Appendix B of this part shall be
used.
(g) When the effluents from a single
affected facility or two or more affected
facilities subject to the same emission
standards are combined before being re-
leased to the atmosphere, the owner or
operator may install applicable contin-
uous monitoring systems on each effluent
or on the combined effluent. When the af-
fected facilities are not subject to the
same emission standards, separate con-
tinuous monitoring systems shall be in-
stalled on each effluent. When the efflu-
ent from one affected facility is released
to the atmosphere through more than
one point, the owner or operator shall
install applicable continuous monitoring
systems on each separate effluent unless
III-9
-------
the installation of fewer systems is ap-
proved by the Administrator.
(h) Owners or operators of all con-
tinuous monitoring systems for measure-
ment of opacity shall reduce all data to
six-minute averages and for systems
other than opacity to one-hour averages
for time periods under § 60.2 (x) and (r)
respectively. Six-minute opacity averages
sha1! be calculated from 24 or more data
points equally spaced over each six-
minute period. For systems other than
opacity, one-hour averages shall be com-
puted from four or more data points
equally spaced over each one-hour pe-
riod. Data recorded during periods of sys-
tem breakdowns, repairs, calibration
checks, and zero and span adjustments
shall not be included in the data averages
computed under this paragraph. An
arithmetic or integrated average of all
data may be used. The data output of all
continuous monitoring systems may be
recorded in reduced or nonreduced form
(e.g. ppm pollutant and percent O2 or
Ib/million Btu of pollutant). All excess
emissions shall be converted into units
of the standard using the applicable con-
version procedures specified in subparts.
After conversion into units of the stand-
ard, the data may be rounded to the same
number of significant digits used in sub-
parts to specify the applicable standard
(e.g., rounded to the nearest one percent
opacity).
(!) After receipt and consideration of
written application, the Administrator
may approve alternatives to any moni-
toring procedures or requirements of this
part including, but not limited to the
following:42
(1) Alternative monitoring require-
ments when installation of a continuous
monitoring system or monitoring device
specified by this part would not provide
accurate measurements due to liquid wa-
ter or other interferences caused by sub-
stances with the effluent gases.
<2) Alternative monitoring require-
ments when the affected facility is infre-
quently operated.
(3) Alternative monitoring require-
ments to accommodate continuous moni-
toring systems that require additional
measurements to correct for stack mois-
ture conditions.
(4) Alternative locations for installing
continuous monitoring systems or moni-
toring devices when the owner or opera-
tor can demonstrate that installation at
alternate locations will enable accurate
and representative measurements.
(5) Alternative methods of converting
pollutant concentration measurements to
units of the standards.
(6) Alternative procedures for per-
forming daily checks of zero and span
drift that do not involve use of span gases
or test cells.
(7) Alternatives to the A.S.T.M. test
methods or sampling procedures specified
by any subpart.
(8) Alternative continuous monitor-
ing systems that do not meet the design
or performance requirements in Perform-
ance Specification 1, Appendix B, but
adequately demonstrate a definite and
consistent relationship between its meas-
urements and the measurements of
opacity by a system complying with the
requirements in Performance Specifica-
tion 1. The Administrator may require
that such demonstration be performed
for each affected facility.
(9) Alternative monitoring require-
ments when the effluent from a single
affected facility or the combined effluent
from two or more affected facilities are
released to the atmosphere through more
than one point.
(Sec. 114. Clem Air Act Is Amended (42
UAC. 7414)). 68, 83
§60.14 Modification.22
(a) Except as provided under
paragraphs (e) and (f) of this section,
any physical or operational change to an
existing facility which results in an
increase in the emission rate to the
atmosphere of any pollutant to which a
standard applies shall be considered a
modification within the meaning of
section 111 of the Act. Upon modification,
an existing facility shall become an af-
fected facility for each pollutant to
which a standard applies and for which
there is an increase in the emission rate
to the atmosphere.'09
(b) Emission rate shall be expressed as
kg/hr of any pollutant discharged into
the atmosphere for which a standard is
applicable. The Administrator shall use
the following to determine emission rate:
(1) Emission factors as specified in
the latest issue of "Compilation of Air
Pollutant Emission Factors," EPA Pub-
lication No. AP-42, or other emission
factors determined by the Administrator
to be superior to AP-42 emission factors,
in cases where utilization of emission
factors demonstrate taat the emission
level resulting from thj physical or op-
erational change will cither clearly in-
crease or clearly not increase.
(2) Material balances, continuous
monitor data, or manual emission tests
in cases where utilization of emission
factors as referenced in paragraph (b)
(1) of this section does not demonstrate
to the Administrator's satisfaction
whether the emission level resulting from
the physical or operational change will
either clearly increase or clearly not in-
crease, or where an owner or operator
demonstrates to the Administrator's
satisfaction that there are reasonable
grounds to dispute the result obtained by
the Administrator utilizing emission fac-
tors as referenced in paragraph (b)(l)
of this section. When the emission rate
is based on results from manual emission
tests or continuous monitoring systems,
the procedures specified in Appendix C
of this part shall be used to determine
whether an increase in emission rate has
occurred. Tests shall be conducted under
such conditions as the Administrator
shall specify to the owner or operator
based on representative performance of
the facility. At least three valid test
runs must be conducted before and at
least three after the physical or opera-
tional change All operating parameters
which may affect emissions must be held
constant to the maximum feasible degree
for all test runs.
(c) The addition of an affected facility
to a stationary source as an expansion
to that source or as a replacement for
an existing facility shall not by itself
bring within the applicability of this
part any other facility within that
source.
(d) [Reserved] 109
(e) The following shall not, by them-
selves, be considered modifications under
this part:
(1) Maintenance, repair, and replace-
ment which the Administrator deter-
mines to be routine for a source category,
subject to the provisions of paragraph
(c) of ibis section and { 60.15.
(2) An increase in production rate of
an existing facility, if that increase can
be accomplished without a capital ex-
penditure on that facility. *°
(3) An increase in the hours of opera-
tion.
(4) Use of an alternative fuel or raw
material if, prior to the date any stand-
ard unoer this part becomes applicable
to that siource type, as provided by § 60.1,
the existing facility was designed to ac-
commodate that alternative use. A
facility tihall be considered to be designed
to accommodate an alternative fuel or
raw material if that use could be accom-
plished under the facility's construction
specifications as amended prior to the
change. Conversion to coal required
for energy considerations, as specified
in section lll(a)(8) of the Act, shall not
be considered a modification.'09
(5) The addition or use of any system
or device whose primary function Is the
reduction of air pollutants, except when
an emission control system Is removed
or is replaced by a system which the Ad-
ministrator determines to be less en-
vironmentally teneflcial.
(6) The relocation or change In
ownership of an existing facility.
(f) S[«cial provisions set forth under
an applicable subpart of this part shall
supersede any conflicting provisions of
this sect on.
(g) Within 180 days of the completion
of any physical or operational change
subject (3 the control measures specified
in paragiaph (a) of this section,
compliar ce with all applicable
standards must be achieved.109
III-10
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§60.15 Reconstruction.22
(a) An existing facility, upon recon-
struction, becomes an affected facility,
Irrespective of any change in emission
rate.
(b) "Reconstruction" means the re-
placement of components of an existing
facility to such an extent that:
(1) The fixed capital cost of the new
components exceeds 50 percent of the
fixed capital cost that would be required
to construct a comparable entirely new
facility, and
(2) It is technologically and econom-
ically feasible to meet the applicable
standards set forth In this part.
(c) "Fixed capital cost" means the
capital needed to provide all the de-
preciable components.
(d) If an owner or operator of an
existing facility proposes to replace com-
ponents, and the fixed capital cost of the
new components exceeds 50 percent of
the fixed capital cost that would be re-
quired to construct a comparable en-
tirely new facility, he shall notify the
Administrator of the proposed replace-
ments. The notice must be postmarked
60 days (or as soon as practicable) be-
fore construction of the replacements is
commenced and must include the fol-
lowing information:
(1) Name and address of the owner
or operator.
(2) The location of the existing facil-
ity.
(3) A brief description of the existing
facility and the components which are to
be replaced.
(4) A description of the existing air
pollution control equipment and the
proposed air pollution control equip-
ment.
(5) An estimate of the fixed capital
cost of the replacements and of con-
structing a comparable entirely new
facility.
(6) The estimated life of the existing
facility after the replacements.
(7) A discussion of any economic or
technical limitations the facility may
have in complying with the applicable
standards of performance after the pro-
Dosed replacements.
(e) The Administrator will deter-
mine, within 30 days of the receipt of the
notice required by paragraph (d) of this
section and any additional information
he may reasonably require, whether the
proposed replacement constitutes re-
construction.
(f) The Administrator's determination
under paragraph (e) shall be based on:
(1) The fixed capital cost of the re-
placements in comparison to the fixed
capital cost that would be required to
construct a comparable entirely new
facility;
(2) The estimated life of the facility
after the replacements compared to the
life of a comparable entirely new facility;
(3) The extent to which the compo-
nents being replaced cause or contribute
to the emissions from the facility; and
(4) Any economic or technical limita-
tions on compliance with applicable
standards of performance which are in-
herent in the proposed replacements.
(g) Individual subparts of this part
may include specific provisions which
refine and delimit the concept of recon-
struction set forth in this section.
00
$60.16 Priority list
Prioritized Major Source Categories
Priority Number *
Source Category
I. Synthetic Organic Chemical Manufacturing
(a) Unit processes
(b) Storage and handling equipment
(c) Fugitive emission sources
(d) Secondary sources
2. Industrial Surface Coating: Cans
3. Petroleum Refineries: Fugitive Sources
4. Industrial Surface Coating: Paper
5. Dry Cleaning
(a) Percbloroethylene
(b) Petroleum solvent
6. Graphic Arts
7. Polymers and Resins: Acrylic Resins
8. Mineral Wool
9. Stationary Internal Combustion Engines
10. Industrial Surface Coating: Fabric
11. Fossil-Fuel-Fired Steam Generators
Industrial Boilers
12. Incineration: Non-Municipal
13. Non-Metallic Mineral Processing
14. Metallic Mineral Processing
15. Secondary Copper
16. PhMpbats Rock Preparation
17. Foundries: Steel and Gray Iron
18. Polymer* and Resins: Polyethylene
19. Charcoal Production
£0. Synthetic Rubber
(a) Tire manufacture
(b) SBR production
21. Vegetable Oil
22. Industrial Surface Coating: Metal Coil
23. Pvtrotaioi Transportation and Marketing
24. By-Prodnct Coke Ovens
29. Synthetic Fibers
26. Plywood Manufacture
27. Industrial Surface Coating: Automobiles
28. Industrial Surface Coating: Large
Appliances
29. Crude Oil and Natural Gas Production
30. Secondary Aluminum
31. Potash
32. Sintering: Clay and Fly Ash
33. Glass
34. Gypsum
35. Sodium Carbonate
38. Secondary Zinc
37. Polymers and Resins: Phenolic
38. Polymers and Resins: UreaMelamine
30. Ammonia
40. Polymers and Resinr Polystyrene
4L Polymers and Resinr ABS-SAN Resins
42. Fiberglass
43. Polymers and Resins: Polypropylene
44. Textile Processing
45. Asphalt Roofing Plants
4ft. Brick and Related Clay Products
47. Ceramic Clay Manufacturing
48. Ammonium Nitrate Fertilizer
49. Castable Refractories
50. Borax and Boric Acid
51. Polymers and Resins. Polyester Resins
52. Ammonium Sulfate
53. Starch
54. Perlite
55. Phosphoric Acid: Thermal Process
56. Uranium Refining
57. Animal Feed Defluorination
SB. Urea (for fertilizer and polymers)
59. Detergent
Other Source Categories.
Lead acid battery manufacture**
Organic solvent cleaning**
Industrial surface coating: metal furniture"
Stationary gas turbines***
(Sec. Ill, 301(a), Clean Air Act as amended
(42 U.S.C. 7411, 7601))
* Low numbers have highest priority: e.g. N
high priority. No. 59 is low priority.
* * Minor tamrae category, but included on hit
since an NSPS i» being developed for mat source
category
*** Not prioritized, unoe an NSPS for thn major
source category has already been proposed.
III-ll
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111-12
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Subpart BAdoption and Submlttal of
State Plans for Designated Facilities21
§ 60.20 Applicability.
The provisions of this subpart apply
to States upon publication of a final
guideline document under §60.22(a).
§ 60.21 Definitions.
Terms used but not defined In this
subpart shall have the meaning given
them in the Act and in subpart A:
(a) "Designated pollutant" means any
air pollutant, emissions of which are
subject to a standard of performance for
new stationary sources but for which air
quality criteria have not been issued.
and which is not included on t- list pub-
lished under section 108(a) or section
112(b)(l)(A) of the Act.
(b) "Designated facility" means any
existing faculty (see }60.2(aa>) which
emits a designated pollutant and which
would be subject to a standard of per-
formance for that pollutant if the exist-
ing facility were an affected facility (see
»60.2(e)).
(c) "Plan" means a plan under sec-
tion lll(d) of the Act which establishes
emission standards for designated pol-
lutants from ^designated facilities and
provides for the Implementation and
enforcement of such emission standards.
(d) "Applicable plan" means the plan,
or most recent revision thereof, which
has been approved under § 60.27(b) or
promulgated under § 60.27(d).
(e) "Emission guideline" means a
guideline set forth in subpart C of this
part, or in a final guideline document
published under §60.22(a), which re-
flects the degree of emission reduction
achievable through the application of the
best system of emission reduction which
(taking into account the cost of such
reduction) the Administrator has de-
termined has been adequately demon-
strated for designated facilities.
(f) "Emission standard" means a
legally enforceable regulation setting
forth an allowable rate of emissions into
the atmosphere, or prescribing equip-
ment specifications for control of air pol-
lution emissions.
If the Administrator determines
that a designated pollutant may cause
or contribute to endangerment of public
welfare, but that adverse effects on pub-
lic health have not been demonstrated,
he will include the determination In the
draft guideline document and in the FED-
ERAL REGISTER notice of its availability.
Except as provided in paragraph (d) (2)
or this section, paragraph (c) of this
section shall be Inapplicable In such
cases.
(2) If the Administrator determines at
any time on the basis of new Information
that a prior determination under para-
graph (d) (1) of this section Is incorrect
or no longer correct, he will publish
notice of the determination In the FED-
ERAL REGISTER, revise the guideline docu-
ment as necessary under paragraph (a)
of this section, and propose and promul-
gate emission guidelines and compliance
times under paragraph (c) of this
section.
§ 60.23 Adoption and sulnnitlal of Stntp
plans; public hearings.
(l) Within nine months after no-
tice of the availability of a final guide-
line document is published under § 60.22
(a>, each State shall adopt and submit
to the Administrator, in accordance with
§ 60.4, a plan for the control of the desig-
nated pollutant to which the guideline
document applies.
(2' Within nine months after notice of
the availability of a final revised guide-
line document is published as provided
in ? 60.22(d)(2), each State shall adopt
and submit to the Administrator any
plan revision necessary to meet the re-
quirements of this subpart.
If no designated facility is located
within a State, the State shall submit
a letter of certification to that effect to
the Administrator within the time spe-
cified in paragraph (a> of this section.
Such certification shall exempt the State
from the requirements of this subpart
for that designated pollutant
(c)(l) Except as provided in para-
graphs (c) (2) and (c) (3) of this section,
the State shall, prior to the adoption of
any plan or revision thereof, conduct
one or more public hearings within the
State on such plan or plan revision.
(2) No hearing shall be required for
any change to an increment of progress
In an approved compliance schedule un-
less the change is likely to cause the
facility to be unable to comply with the
final compliance date in the schedule.
(3) No hearing shall be required on
an emission standard In effect prior to
the effective date of this subpart if it was
adopted after a public hearing and is
at least as stringent as the corresponding
emission guideline specified in the appli-
cable guideline document published
vnder § 60 22(a).
(di Any hearing required by para-
graph (c) of this section shall be held
only after reasonable notice. Notice shall
be given at least 30 days prior to the
date of such hearing and shall include:
(1) Notification to the public by
prominently advertising the date, time,
and place of such hearing in each region
affected;
(2) Availability, at the time of public
announcement, of each proposed plan or
111-13
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revision thereof for public inspection in
at least one location in each region to
which it will apply;
(3) Notification to the Administrator;
(4) Notification to each local air pol-
lution control agency in each region to
which the plan or revision will apply; and
(5) In the case of an interstate re-
gion, notification to any other State in-
cluded in the region.
(e) The State shall prepare and retain,
for a minimum of 2 years, a record of
each hearing for inspection by any inter-
ested party. The record shall contain, as
a minimum, a list of witnesses together
with the text of each presentation.
(f) The State shall submit with the
plan or revision:
(1) Certification that each hearing re-
quired by paragraph (c) of this section
was held in accordance with the notice
required by paragraph (d) of this sec-
tion; and
(2) A list of witnesses and their orga-
nizational affiliations, if any, appearing
at the hearing and a brief written sum-
mary of each presentation or written
submission.
(g) Upon written application by a
State agency (through the appropriate
Regional Office). the Administrator may
approve State procedures designed to in-
sure public participation in the matters
for which hearings are required and pub-
lic notification of the opportunity to par-
ticipate if, in the judgment of the Ad-
ministrator, the procedures, although
different from the requirements of this
subpart, in fact provide for adequate
notice to and participation of the public.
The Administrator may impose such con-
ditions on his approval as he deems
necessary. Procedures approved under
this section shall be deemed to satisfy the
requirements of this subpart regarding
procedures for public hearings.
§ 60.24 Emission standards and compli-
ance schedules.
(a) Each plan shall Include emission
standards and compliance schedules.
(b)(l) Emission standards shall pre-
scribe allowable rates of emissions except
when it is clearly impracticable. Such
cases will be identified in the guideline
documents issued under § 60.22. Where
emission standards prescribing equip-
ment specifications are established, the
plan shall, to the degree possible, set
forth the emission reductions achievable
by implementation of such specifications,
and may permit compliance by the use
of equipment determined by the State
to be equivalent to that prescribed.
(2) Test methods and procedures for
determining compliance with the emis-
sion standards shall be specified in the
plan. Methods other than those specified
in Appendix A to this part may be speci-
fied in the plan if shown to be equivalent
or alternative methods as defined In
§ 60.2 (t) and (u).
(3) Emission standards shall apply to
all designated facilities within the State.
A plan may contain emission standards
adopted by local jurisdictions provided
that the standards are enforceable by
the State.
(c) Except as provided in paragraph
(f) of this section, where the Adminis-
trator has determined that a designated
pollutant may cause or contribute to en-
dangerment of public health, emission
standards shall be no less stringent than
the corresponding emission guideline(s)
specified in Subpart C of this part, and
final compliance shall be required as ex-
peditiously as practicable but no later
than the compliance times specified in
Subpart C of this part.
(d) Where the Administrator has de-
termined that a designated pollutant
may cause or contribute to endangerment
of public welfare but that adverse ef-
fects on public health have not been
demonstrated, States may balance the
emission guidelines, compliance times,
and other information provided in the
applicable guideline document against
other factors of public concern in estab-
lishing emission standards, compliance
schedules, and variances. Appropriate
consideration shall be given to the fac-
tors specified in § 60.22 (b) and to infor-
mation presented at the public hear-
ing (s) conducted under § 60.23(c).
(e) (1) Any compliance schedule ex-
tending more than 12 months from the
date required for submittal of the plan
shall include legally enforceable incre-
ments of progress to achieve compliance
for each designated facility or category
of facilities. Increments of progress shall
include, where practicable, each incre-
ment of progress specified in § 60.21(h)
and shall Include such additional in-
crements of progress as may be necessary
to permit close and effective supervision
of progress toward final compliance.
(2) A plan may provide that compli-
ance schedules for individual sources or
categories of sources will be formulated
after plan submittal. Any such schedule
shall be the subject of a public hearing
held according to § 60.23 and shall be
submitted to the Administrator within 60
days after the date of adoption of the
schedule but in no case later than the
date prescribed for submittal of the first
semiannual report required by § 60.25 (e).
(f) On a case-by-case basis for par-
ticular designated faculties, or classes of
facilities, States may provide for the ap-
plication of less stringent emission
standards or longer compliance schedules
than those otherwise required by para-
graph (c) of this section, provided that
the State demonstrates with respect to
each such facility (or class of facilities):
(1) Unreasonable cost of control re-
sulting from plant age, location, or basic
process design;
(2) Physical impossibility of installing
necessary control equipment; or
(3) Other factors specific to the facility
(or class of facilities) that make applica-
tion of a less stringent standard or final
compliance time significantly more rea-
sonable.
(g) Nothing in this subpart shall be
construed to preclude any State or po-
litical subdivision thereof from adopting
or enforcing (1) emission standards
more stringent than emission guidelines
specified in Subpart C of this part or in
applicable guideline documents or (2)
compliance schedules requiring final
compliance at earlier times than those
specified in Subpart C or In applicable
guideline documents.
(Sec. 116 of the Clean Air Act M amended
(42U.S.C. 7416)). 68,83
§ 60.25 Emission inventories, source
surveillance, reports.
(a) Each plan shall include an Inven-
tory of all designated facilities, Including
emission data for the designated pollut-
ants and information related to emissions
as specified in Appendix D to this part.
Such data shall be summarized In the
plan, and emission rates of designated
pollutants from designated facilities shall
be correlated with applicable emission
standards. As used in this subpart, "cor-
related" means presented In such a man-
ner as to show the relationship between
measured or estimated amounts of emis-
sions and the amounts of such emissions
allowable under applicable emission
standards.
(b) Each plan shall provide for moni-
toring the status of compliance with ap-
plicable emission standards. Each plan
shall, as a minimum, provide for:
(1) Legally enforceable procedures for
requiring owners or operators of desig-
nated facilities to maintain records and
periodically report to the State informa-
tion on the nature and amount of emis-
sions from such facilities, and/or such
other information as may be necessary
to enable the State to determine whether
such facilities are in compliance with ap-
plicable portions of the plan.
(2) Periodic inspection and, when ap-
plicable, testing of designated facilities.
(c) Each plan shall provide that in-
formation obtained by the State under
paragraph (b) of this section shall be
correlated with applicable emission
standards (see |60.25(a» and made
available to the general public.
(d) The provisions referred to in par-
agraphs (b) and (c) of this section shall
be specifically Identified. Copies of such
provisions shall be submitted with the
plan unless:
(1) They have been approved as por-
tions of a preceding plan submitted un-
der this subpart or as portions of an
implementation plan submitted under
section 110 of the Act. and
(2) The State demonstrates:
(i) That the provisions are applicable
to the designated pollutant(s) for which
the plan is submitted, and
(ii) That the requirements of 8 60.26
are met
(e) The State shall submit reports on
progress in plan enforcement to the
Administrator on an annual (calendar
year) basis, commencing with the first
full report period after approval of a
plan or after promulgation of a plan by
the Administrator. Information required
under this paragraph must be included
in the annual report required by § 51.321
of this chapter.'04
(f) Each progress report shall include:
(1) Enforcement actions initiated
against designated facilities during the
reporting period, under any emission
III-14
-------
atandard or compliance schedule of the
plan.
(2) Identification of the achievement
of any increment of progress required by
the applicable plan during the reporting
period.
(3) Identification of designated facili-
ties that have ceased operation during
the reporting period.
(4) Submission of emission inventory
data as described In paragraph (a) of
this section for designated facilities that
were not in operation at the time of plan
development but began operation during
the reporting period.
(5) Submission of additional data as
necessary to update the information sub-
mitted under paragraph (a) of this sec-
tion or In previous progress reports.
(6) Submission of copies of technical
reports on an performance testing on
designated facilities conducted under
paragraph (b) (2) of this section, com-
plete with concurrently recorded process
data.
8 60.26 Legal authority.
(a) Each plan shall show that the
State has legal authority to carry out
the plan, including authority to:
(1) Adopt emission standards and
compliance schedules applicable to des-
ignated facilities.
(2) Enforce applicable laws, regula-
tions, standards, and compliance sched-
ules, and seek injunctive relief.
(3) Obtain information necessary to
determine whether designated facilities
are in compliance with applicable laws,
regulations, standards, and compliance
achedules, Including authority to require
recordkeeplng and to make Inspections
and conduct tests of designated facilities.
(4) Require owners or operators of
designated facilities to Install, maintain,
and use emission monitoring devices and
to make periodic reports to the State on
the nature and amounts of emissions
from such facilities; also authority for
the State to make such data available to
the public as reported and as correlated
with applicable emission standards.
(b) The provisions of law or regula-
tions which the State determines provide
the authorities required by this section
ahall be specifically identified. Copies of
uch laws or regulations shall be sub-
mitted with the plan unless:
(1) They have been approved as por-
tions of a preceding plan submitted
under this subpart or as portions of an
Implementation plan submitted under
ection 110 of the Act, and
(2) The State demonstrates that the
laws or regulations are applicable to the
designated pollutant(s) for which the
plan is submitted.
(c) The plan shall show that the legal
authorities specified In this section are
available to the State at the time of sub-
mission of the plan. Legal authority ade-
quate to meet the requirements of para-
graphs (a) (3) and (4) of this section
may be delegated to the State under sec-
tion 114 of the Act.
(d) A State governmental agency
other than the State air pollution con-
trol agency may be assigned responsibil-
ity for Carrying out a portion of a plan
If the plan demonstrates to the Admin-
istrator's satisfaction that the State gov-
ernmental agency has the legal authority
necessary to carry out that portion of the
plan.
(e) The State may authorize a local
agency to carry out a plan, or portion
thereof, within the local agency's juris-
diction if the plan demonstrates to the
Administrator's satisfaction that the
local agency has the legal authority nec-
essary to implement the plan or portion
thereof, and that the authorization does
not relieve the State of responsibility
under the Act for carrying out the plan
or portion thereof.
§ 60.27 Actions by the Administrator.
(a) The Administrator may, whenever
he determines necessary, extend the pe-
riod for submission of any plan or plan
revision or portion thereof.
(b) After receipt of a plan or plan re-
vision, the Administrator will propose the
plan or revision for approval or dis-
approval. The Administrator will, within
four months after the date required for
submission of a plan or plan revision,
approve or disapprove such plan or revi-
sion or each portion thereof.
(c) The Administrator will, after con-
sideration of any State hearing record,
promptly prepare and publish proposed
regulations setting forth a plan, or por-
tion thereof, for a State if:
(1) The State fails to submit a plan
within the time prescribed;
(2) The State fails to submit a plan
revision required by § 60.23
-------
Subpart CEmission Guidelines and
Compliance Times73
§ 60.30 Scope.
This subpart contains emission guide-
lines and compliance times for the con-
trol of certain designated pollutants from
certain designated facilities in accord-
ance with section lll(d) of the Act and
Subpart B.
§ 60.31 Definitions.
Terms used but not defined in this
subpart have the meaning given them
in the Act and in Subparts A and B of
this part.
§ 60.32 Designated facilities.
(a) Sulfuric acid production units.
The designated facility to which IS 60.33
(a) and 60.34(a) apply is each existing
"sulfuric acid production unit" as de-
fined in § 60.81 (a) of Subpart H.
§ 60.33 Emission guidelines.
(a) Sulfuric acid production units.
The emission guideline for designated
facilities is 0.25 gram sulfuric acid mist
(as measured by Reference Method 8, of
Appendix A) per kilogram of sulfuric
acid produced (0.5 Ib/ton), the produc-
tion being expressed as 100 percent
aso..
§ 60.34 Compliance times.
(a) Sulfuric acid production units.
Planning, awarding of contracts, and
Installation of equipment capable of
attaining the level of the emission guide-
line established under { 60.33(a) can be
accomplished within 17 months after the
effective date of a State emission stand-
ard for sulfuric acid mist.
T.II-16
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Subpart DStandards of Perform-
ance for Fossil-Fuel-Fired Steam
Generators for Which Construction
Is Commenced After August 17.
197198,110
§ 60.40 Applicability and designation of
affected facility.8."9,64,94
(a) The affected facilities to which
the provisions of this subpart apply
are:
(1) Each fossil-fuel-fired steam gen-
erating unit of more than 73
megawatts heat input rate (250 million
Btu per hour).
(2) Each fossil-fuel and wood-resi-
due-fired steam generating unit capa-
ble of firing fossil fuel at a heat input
rate of more than 73 megawatts (250
million Btu per hour).
(b) Any change to an existing fossil-
fuel-fired steam generating unit to ac-
commodate the use of combustible ma-
terials, other than fossil fuels as de-
fined in this subpart, shall not bring
that unit under the applicability of
this subpart.
(c) Except as provided in paragraph
(d) of this section, any facility under
paragraph (a) of this section that com-
menced construction or modification
after August 17, 1971, is subject to the
requirements of this subpart.84
(d) The requirements of
§§60.44(a)(4), (a)(5), (b) and (d), and
60.45(f )(4)(vi) are applicable to lignite-
fired steam generating units that com-
menced construction or modification
after December 22, 1976.84
(e) Any facility covered under Sub-
part Da is not covered under this Sub-
part.98
§ 60.41 Definitions.
As used in this subpart, all terms not
defined herein shall have the meaning
given them in the Act, and in Subpart
A of this part.
(a) "Fossil-fuel fired steam generat-
ing unit" means a furnace or boiler
used in the process of burning fossil
fuel for the purpose of producing
steam by heat transfer.
(b) "Fossil fuel" means natural gas.
petroleum, coal, and any form of solid.
liquid, or gaseous fuel derived from
such materials for the purpose of cre-
ating useful heat.
(c) "Coal refuse" means waste-prod-
ucts of coal mining, cleaning, and coal
preparation operations (e.g. culm, gob,
etc.) containing coal, matrix material,
clay, and other organic and inorganic
material.'1
(d) "Fossil fuel and wood residue-
fired steam generating unit" means a
furnace or boiler used in the process
of burning fossil fuel and wood residue
for the purpose of producing steam by
heat transfer.4'*'
(e) "Wood residue" means bark, saw-
dust, slabs, chips, shavings, mill trim,
and other wood products derived from
wood processing and forest manage-
ment operations.49
(f) "Coal" means all solid fuels clas-
sified as anthracite, bituminous, subbi-
tuminous, or lignite by the American
Society for Testing Material. Designa-
tion D 38S-66.84
§ 60.42 Standard for participate matter.
(a) On and after the date on which
the performance test required to be
conducted by § 60.8 is completed, no
owner or operator subject to the provi-
sions of this subpart shall cause to be
discharged into the atmosphere from
any affected facility any gases which:
(1) Contain particulate matter in
excess of 43 nanograms per joule heat
input (0.10 Ib per million Btu) derived
from fossil fuel or fossil fuel and wood
residue.49
(2) Exhibit greater than 20 percent
opacity except for one six-minute
period per hour of not more than 27
percent opacity.18'76
(b)(l) On and after (the date of
publication of this amendment), no
owner or operator shall cause to be
discharged into the atmosphere from the
Southwestern Public Service Company's
Harrington Station Unit #1, in Amarillo,
Texas, any gases which exhibit greater
than 35% opacity, except that a
maximum of 42% opacity shall be
permitted for not more than 6 minutes in
any hour.107
(2) Interstate Power Company shall
not cause to be discharged into the
atmosphere from its Lansing Station
Unit No. 1 in Lansing, Iowa, any gases
which exhibit greater than 32% opacity,
except that a maximum of 39% opacity
shall be permitted for not more than six
minutes in any hour.112
(Sec. 111.301(a), Clear Air Act as amended
(42 U.S.C. 7411, 7601)).
§ 60.13 Standard for sulfur dioxide.2-8
(a) On and after the date on which
the performance test required to be
conducted by § 60.8 is completed, no
owner or operator subject to the provi-
sions of this subpart shall cause to be
discharged into the atmosphere from
any affected facility any gases which
contain sulfur dioxide in excess of:
(1) 340 nanograms per joule heat
input (0.80 Ib per million Btu) derived
from liquid fossil fuel or liquid fossil
fuel and wood residue.49
(2) 520 nanograms per joule heat
input (1.2 Ib per million Btu) derived
from solid fossil fuel or solid fossil fuel
and wood residue.49
(b) When different fossil fuels are
burned simultaneously in any combi-
nation, the applicable standard (in ng/
J) shall be determined by proration
using the following formula:
PSSOJ = ly (340) + 2~(520)l/y + z
where:
PS.O, is the prorated standard for sulfur
dioxide when burning different fuels si-
multaneously, in nanograms per joule
heat input derived from all fossil fuels
fired or from all fossil fuels and wood
residue fired,
y is the percentage of total heat input de-
rived from liquid fossil fuel, and
2 is the percentage of total heat input de-
rived from solid fossil fuel.49
(c) Compliance shall be based on the
total heat input from all fossil fuels
burned, including gaseous fuels.
§ 60.44 Standard for nitrogen oxides.8
(a) On and after the date on which
the performance test required to be
conducted by § 60.8 is completed, no
owner or operator subject to the provi-
sions of this subpart shall cause to be
discharged into the atmosphere from
any affected facility any gases which
contain nitrogen oxides, expressed as
NO2 in excess of:
(1) 86 nanograms per joule heat
input (0.20 Ib per million Btu) derived
from gaseous fossil fuel or gaseous
fossil fuel and wood residue.49
(2) 130 nanograms per joule heat
input (0.30 Ib per million Btu) derived
from liquid fossil fuel or liquid fossil
fuel and wood residue.49
(3) 300 nanograms per joule heat
input (0.70 Ib per million Btu) derived
from solid fossil fuel or solid fossil fuel
and wood residue (except lignite or a
solid fossil fuel containing 25 percent,
by weight, or more of coal refuse).11'49
(4) 260 nanograms per joule heat
input (0.60 Ib per million Btu) derived
from lignite or lignite and wood resi-
due (except as provided under para-
graph (a)(5) of this section).84
(5) 340 nanograms per joule heat
input (0.80 Ib per million Btu) derived
from lignite which is mined in North
Dakota, South Dakota, or Montana
and which is burned in a cyclone-fired
unit.84
(b) Except as provided under para-
graphs (c) and (d) of this section,
when different fossil fuels are burned
simultaneously in any combination,
the applicable standard (in ng/J) is de-
termined by proration using the fol-
lowing formula:
PSvo,= w< 260) + 1(86) + y( 130) + 2(300)
w+x+y+s
where.
PStm*=is the prorated standard for nitro-
gen oxides when burning different
fuels simultaneously, in nanograms
per joule heat input derived from all
fossil fuels fired or from all fossil fuels
and wood residue fired;
tc=is the percentage of total heat input
111-17
-------
derived from lignite;
x=is the percentage of total heat input
derived from gaseous fossil fuel;
y=is the percentage of total heat input
derived from liquid fossil fuel; and
e=is the percentage of total heat input de-
rived from solid fossil fuel (except lig-
nite). 11,49,84
(c) When a fossil fuel containing at
least 25 percent, by weight, of coal
refuse is burned in combination with
gaseous, liquid, or other solid fossil
fuel or wood residue, the standard for
nitrogen oxides does not apply.34
(d) Cyclone-fired units which burn
fuels containing at least 25 percent of
lignite that is mined in North Dakota,
South Dakota, or Montana remain
subject to paragraph (a)(5) of this sec-
tion regardless of the types of fuel
combusted in combination with that
lignite.94
48)8
§60.45 Emission and fuel monitoring1.'
(a) Each owner or operator shall in-
stall, calibrate, maintain, and operate
continuous monitoring systems for
measuring the opacity of emissions,
sulfur dioxide emissions, nitrogen
oxides emissions, and either oxygen or
carbon dioxide except as provided in
paragraph (b) of this section.57
(b) Certain of the continuous moni-
toring system requirements under
paragraph (a) of this section do not
apply to owners or operators under
the following conditions:57
(1) For a fossil fuel-fired steam gen-
erator that burns only gaseous fossil
fuel, continuous monitoring systems
for measuring the opacity of emissions
and sulfur dioxide emissions are not
required.57
(2) For a fossil fuel-fired steam gen-
erator that does not use a flue gas de-
sulfurization device, a continuous
monitoring system for measuring
sulfur dioxide emissions is not re-
quired if the owner or operator moni-
tors sulfur dioxide emissions by fuel
sampling and analysis under para-
graph (d) of this section.57
(3) Notwithstanding § 60.13(b), in-
stallation of a continuous monitoring
system for nitrogen oxides may be de-
layed until after the initial perform-
ance tests under § 60.8 have been con-
ducted. If the owner or operator dem-
onstrates during the performance test
that emissions of nitrogen oxides are
less than 70 percent of the applicable
standards in § 60.44, a continuous mon-
itoring system for measuring nitrogen
oxides emissions is not required. If the
initial performance test results show
that nitrogen oxide emissions are
greater than 70 percent of the applica-
ble standard, the owner or operator
shall install a continuous monitoring
system for nitrogen oxides within one
year after the date of the initial per-
formance tests under § 60.8 and
comply with all other applicable moni-
toring requirements under this part.57
(4) If an owner or operator does not
install any continuous monitoring sys-
tems for sulfur oxides and nitrogen
oxides, as provided under paragraphs
(bXl) and (b)(3) or paragraphs (b)(2)
and (b)(3) of this section a continuous
monitoring system for measuring
either oxygen or carbon dioxide is not
required.57
(c) For performance evaluations
under 5 60.13(0 and calibration checks
under §60.13(d), the following proce-
dures shall be used:57
(1) Reference Methods 6 or 7, as ap-
plicable, shall be used for conducting
performance evaluations of sulfur
dioxide and nitrogen oxides continu-
ous monitoring systems.57
(2) Sulfur dioxide or nitric oxide, as
applicable, shall be used for preparing
calibration gas mixtures under Per-
formance Specification 2 of Appendix
B to this part.57
(3) For affected facilities burning
fossil fuel(s), the span value for a con-
tinuous monitoring system measuring
the opacity of emissions shall be 80,
90, or 100 percent and for a continuous
monitoring system measuring sulfur
oxides or nitrogen oxides the span
value shall be determined as follows:
[In parts per million]
tion shall each be on a consistent basis
(wet or dry). Alternative procedures
approved by the Administrator shall
be used when measurements are on a
wet basis. When measurements are on
a dry basis, the following conversion
procedure shall be used:
Fossil fuel
Gas
Liquid
Solid
Combinations
Span value for
sulfur dioxide
C)
1,000
1.500
1,000y+ 1.5007
Span value for
nitrogen oxides
600
500
500
500(jr 4/) +1,000*
'Not applicable.
where:
x = the fraction of total heat input derived
from gaseous fossil fuel, and
y = the fraction of total heat input derived
from liquid fossil fuel, and
z=the fraction of total heat input derived
from solid fossil fuel. 57
(4) All span values computed under
paragraph (c)(3) of this section for
burning combinations of fossil fuels
shall be rounded to the nearest 500
ppm.57
(5) For a fossil fuel-fired steam gen-
erator that simultaneously burns fossil
fuel and nonfossil fuel, the span value
of all continuous monitoring systems
shall be subject to the Administrator's
approval.57
(d) [Reserved]5
(e) For any continuous monitoring
system installed under paragraph (a)
of this section, the following conver-
sion procedures shall be used to con-
vert the continuous monitoring data
into units of the applicable standards
(ng/J, Ib/million Btu):49-57
(1) When a continuous monitoring
system for measuring oxygen is select-
ed, the measurement of the pollutant
concentration and oxygen concentra-
~cv f
0 L 2
tor-percent O,_
where:
E, C, F, and %O, are determined under
paragraph (f) of this section.57
(2) When a continuous monitoring
system for measuring carbon dioxide is
selected, the measurement of the pol-
lutant, concentration and carbon diox-
ide concentration shall each be on a
consistent basis (wet or dry) and the
following conversion procedure shall
be used:
r 100
e L percent CO,.
where:
E, C, PC and %CO, are determined under
paragraph (f) of this section.57
(f) The values used in the equations
under paragraphs (e) (1) and (2) of
this section are derived as follows:
(1) £-pollutant emissions, ng/J (lb/
million Btu).
(2) C=pollutant concentration, ng/
dscm (Ib/dscf), determined by multi-
plying the average concentration
(ppm) for each one-hour period by
4.15xl04 M ng/dscm per ppm
(2.59xlO"9 M Ib/dscf per ppm) where
M= pollutant molecular weight, g/g-
mole (Ib/lb-mole). Jf=64.07 for sulfur
dioxide and 46.01 for nitrogen oxides.49
(3) %O,, %CO2=oxygen or carbon
dioxide volume (expressed as percent),
determined with equipment specified
under paragraph (d) of this section.
(4) F, Fc = a factor representing a
ratio of the volume of dry flue gases
generated to the calorific value of the
fuel combusted (F), and a factor repre-
senting a ratio of the volume of
carbon dioxide generated to the calo-
rific value of the fuel combusted (Fc),
respectively. Values of F and Fc are
given as follows:
(i) For anthracite coal as classified
according to A.S.T.M. D 388-66, F=
2.723 xltT 1 dscm/J (10,140 dscf /mil-
lion Btu) and ^ = 0.532x10^ ' scm
CO,//(1.980 scf CO,/million Btu).49
(ii) For subbituminous and bitumi-
nous coal as classified according to
A.S.T.M. D 388-66, F= 2.637 x 10"'
dscm/J (9,820 dscf/million Btu) and
Fc=0.486xlO-7 scm CO,// (1,810 scf
COa/millionBtu).49
(iii) For liquid fossil fuels including
crude, residual, and distillate oils,
f=2.476xlO-' dscm/J (9,220 dscf/mil-
lion Btu) and Fc =0.384xlO'7 scm CO,/
J (1,430 scf CO2/million Btu).49-67
(iv) For gaseous fossil fuels, F= 2.347
x 10"' dscm/J (8 740 dscf/million Btu).
For natural gas, propane, and butane
IIT.-lf
-------
fuels, *V=0.279xlO-' scm CO,/J (1,040
scf CO,/million Btu) for natural gas,
0.322x10-' scm CO,/J (1,200 scf CO,/
million Btu) for propane, and
0.338x10-' scm CO,/J (1,260 scf CO*/
million Btu) for butane.49/67
(v) For bark F=2.589xlO"7 dscm/J
(9,640 dscf/million Btu) and Fc=0.500
xlO-' scm CO,/J (1,860 scf CO,/ mil-
lion Btu). For wood residue other than
bark F= 2.492x10-' dscm/J (9,280
dscf/million Btu) and Fc=0.494xlO'7
scm CO,/J (1,840 scf CO,/ million
Btu).49-67
(vi) For lignite coal as classified ac-
cording to A.S.T.M. D 388-66,
F= 2.659x10-' dscm/J (9900 dscf/mil-
lion Btu) and Fc=0.516xlO-' scm CO,/
J (1920 scf CO,/million Btu).M
(5) The owner or operator may use
the following equation to determine
an F factor (dscm/J or dscf/million
Btu) on a dry basis (if it is desired to
calculate F on a wet basis, consult the
Administrator) or Fc factor (scm CO,/
/, or scf CO,/million Btu) on either
basis in lieu of the F or Ff factors spec-
ified in paragraph (f)(4) of this sec-
tion:49
(f )(5) of this section shall be prorated
in accordance with the applicable for-
mula as follows:
F =
where:
Jt(=the fraction of total heat input de-
rived from each type of fuel (e.g. natu-
ral gas, bituminous coal, wood residue,
etc.)
Ft or (fc)(=the applicable F or F, factor
for each fuel type determined in ac-
cordance with paragraphs (f)(4) and
(fX5) of this section.
n=the number of fuels being burned in
combination.49
(g) For the purpose of reports re-
quired under {60.7(c), periods of
excess emissions that shall be reported
are defined as follows:
(1) Opacity. Excess emissions are de-
fined as any six-minute period during,
which the average opacity of emissions
exceeds 20 percent opacity, except
that one six-minute average per hour
(3) Nitrogen oxides. Excess emissions
for affected facilities using a continu-
ous monitoring system for measuring
nitrogen oxides are defined as any
three-hour period during which the
average emissions (arithmetic average
of three contiguous one-hour periods)
exceed the applicable standards under
S 60.44.
(Sec. 114. Clean Air Act U amended (42
U.SC. 7414».«8.83
1227.3 (pet. H)-r»5.5 (pet. C)-1-35.6 (pot. S)+8.7 (pet. N)~28.7 (pet. O)l
QCV ~~ '
(SI units)
» 10'I3.64(%g)+1.53(%C)+0.57(%S)+O.U(%AO-0.46(%0)]
GCV
(English units)
2.0X10-* (pet. C)
GCV
(SI units)
_ 321X10»(%C)
GCV
(English units)
23,49,67
(i) H, C, 8, N, and O are content by
weight of hydrogen, carbon, sulfur, ni-
trogen, and oxygen (expressed as per-
cent), respectively, as determined on
the same basis as GCV by ultimate
analysis of the fuel fired, using
AJ3.T.M. method D3178-74 or D3176
(olid fuels), or computed from results
using A.S.T.M. methods D1137-53(70),
D1945-64(73), or D1946-67(72) (gas-
eous fuels) as applicable.
(ii) GCV is the gross calorific value
(kJ/kg, Btu/lb) of the fuel combusted,
determined by the A.S.T.M. test meth-
ods D2015-66(72) for solid fuels and D
1826-64(70) for gaseous fuels as appli-
cable.49
(ill) For affected facilities which fire
both fossil fuels and nonfossil fuels,
the F or Fc value shall be subject to
ttu« AdminJattalQr'e fiEproval/9
(6) For affected facilities firing com-
binations of fossD fuels or fossil fuels
and wood residue, the F or Fc factors
determined by paragraphs (fX4) or
of up to 27 percent opacity need not
be reported.76
(i) For sources subject to the opacity
standard of i 60.42(b)(l), excess
emissions are defined as any six-minute
period during which the average opacity
of emissions exceeds 35 percent opacity,
except that one six-minute average per
hour of up to 42 percent opacity need
not be reported.107
(ii) For sources subject to the opacity
standard of § 60.42(b)(2), excess
emissions are defined as any six-minute
period during which the average opacity
of emissions exceeds 32 percent opacity,
except that one six-minute average per
hour of up to 39 percent opacity need
not be reported. 112
(2) Sulfur dioxide. Excess emissions
for affected facilities are defined as:
(i) Any three-hour period during
which the average emissions (arithme-
tic average of three contiguous one-
hour periods) of sulfur dioxide as
measured by a continuous monitoring
system exceed the applicable standard
under $ 60.43.
§ 60.46 Test methods and procedures.8-18
(a) The reference methods in Appen-
dix A of this part, except as provided
in § 60.8(b), shall be used to determine
compliance with the standards as pre-
scribed in §§60.42, 60.43, and 60.44 as
follows:
(1) Method 1 for selection of sam-
pling site and sample traverses.
(2) Method 3 for gas analysis to be
used when applying Reference Meth-
ods 5, 6 and 7.
(3) Method 5 for concentration of
particulate matter and the associated
moisture content.
(4) Method 6 for concentration of
SO2, and
(5) Method 7 for concentration of
NO,.
(b) For Method 5, Method 1 shall be
used to select the sampling site and
the number of traverse sampling
points. The sampling time for each
run shall be at least 60 minutes and
the minimum sampling volume shall
be 0.85 dscm (30 dscf) except that
smaller sampling times or volumes,
when necessitated by process variables
or other factors, may be approved by
the Administrator. The probe and
filter holder heating systems in the
sampling train shall be set to provide a
gas temperature no greater than 433
K (320°F).49
(c) For Methods 6 and 7, the sam-
pling site shall be the same as that se-
lected for Method 5. The sampling
point in the duct shall be at the cen-
troid of the cross section or at a point
no closer to the walls than 1 m (3.28
ft). For Method 6, the sample shall be
extracted at a rate proportional to the
gas velocity at the sampling point.
(d) For Method 6, the minimum
sampling time shall be 20 minutes and
the minimum sampling volume 0.02
dscm (0.71 dscf) for each sample. The
arithmetic mean of two samples shall
constitute one run. Samples shall be
taken at approximately 30-minute in-
tervals.
(e) For Method 7, each run shall
consist of at least four grab samples
taken at approximately 15-minute in-
tervals. The arithmetic mean of the
samples shall constitute the run value.
(f) For each run using the methods
specified by paragraphs (a)(3), (a)(4),
and (a)(5) of this section, the emis-
sions expressed in ng/J (Ib/million
111-19
-------
Btu) shall be determined by the fol-
lowing procedure:
£=C/X20.9/20 9-percent O,)
where:
(1) E = pollutant emission ng/J (lb/
million Btu).
(2) C = pollutant concentration, ng/
dscm (Ib/dscf), determined by method
5, 6, or 7.
(3) Percent Oa = oxygen content by
volume (expressed as percent), dry
basis. Percent oxygen shall be deter-
mined by using the integrated or grab
sampling and analysis procedures of
Method 3 as applicable.
The sample shall be obtained as fol-
lows:
(i) For determination of sulfur diox-
ide and nitrogen oxides emissions, the
oxygen sample shall be obtained si-
multaneously at the same point in the
duct as used to obtain the samples for
Methods 6 and 7 determinations, re-
spectively [§ 60.46(c)L For Method 7,
the oxygen sample shall be obtained
using the grab sampling and analysis
procedures of Method 3.
(ii) For determination of particulate
emissions, the oxygen sample shall be
obtained simultaneously by traversing
the duct at the same sampling location
used for each run of Method 5 under
paragraph (b) of this section. Method
1 shall be used for selection of the
number of traverse points except that
no more than 12 sample points are re-
quired.
(4) F=a factor as determined in
paragraphs (f) (4), (5) or (6) of § 60.45.
(g) When combinations of fossil
fuels or fossil fuel and wood residue
are fired, the heat input, expressed in
watts (Btu/hr), is determined during
each testing period by multiplying the
gross, calorific value of each fuel fired
(in J/kg or Btu/lb) by the rate of each
fuel burned (in kg/sec or Ib/hr). Gross
calorific values are determined in ac-
rordance with A.S.T.M. methods D
2015-66(72) (solid fuels), D 240-64(73)
(liquid fuels), or D 1826-64(7) (gaseous
fuels) as applicable. The method used
to determine calorific value of wood
residue must be approved by the Ad-
ministrator. The owner or operator
shall determine the rate of fuels
burned during each testing period by
suitable methods and shall confirm
the rate by a material balance over the
steam generation system.49
Sec. 114. Clem Air Act
U.SC
U amended <4J
Proposed/effecti ve
36 FR 15704, 8/17/71
Promulgated
36 FR 24876, 12/23/71 (1)
Revised
37 FR 14877
38 FR 28564
39 FR 20790
40 FR 2803,
40 FR 46250
40 FR 59204
41 FR 51397
42 FR 5936,
42 FR 37936,
42 FR 41122,
42 FR 41424,
42 FR 61537,
43 FR 8800,
43 FR 9276,
44 FR 3491,
44 FR 33580,
44 FR 76786,
45 FR 8211,
45 FR 36077,
, 7/26/72 (2)
10/15/73 (4)
6/14/74 (8)
1/16/75 (11)
10/6/75 (18)
12/22/75 (23)
11/22/76 (49)
1/31/77 (57)
7/25/77 (64)
8/15/77 (67)
8/17/77 (68)
12/5/77 (76)
3/3/78 (83)
3/7/78 (84)
1/17/79 (94)
6/11/79 (98)
12/28/79 (107)
2/6/80 (110)
5/29/80 (112)
111-20
-------
Subpart DaStandard* of
Performance for Electric Utility Steam
Generating Units for Which
Construction Is Commenced After
September tt, 1978 98<"°
J60.40a AppflcaMlty and designation of
affected facility.
(a] The affected facility to which this
subpart applies is each electric utility
steam generating unit:
(1) That is capable of combusting
more than 73 megawatts (250 million
Btu/hour) heat input of fossil fuel (either
alone or in combination with any other
fuel); and
(2) For which construction or
modification is commenced after
September 18,1978.
(b) This subpart applies to electric
utility combined cycle gas turbines that
are capable of combusting more than 73
megawatts (250 million Btu/hour) heat
input of fossil fuel in the steam
generator. Only emissions resulting from
combustion of fuels in the steam
generating unit are subject to this
subpart. (The gas turbine emissions are
subject to Subpart CC.)
(c) Any change to an existing fossil-
fuel-flred steam generating unit to
accommodate the use of combustible
materials, other than fossil fuels, shall
not bring that unit under the
applicability of this subpart
(d) Any change to an existing steam
generating unit originally designed to
fire gaseous or liquid fossil fuels, to
accommodate the use of any other fuel
(fossil or nonfossil) shall not bring that
unit under the applicability of this
subpart.
J60.41a Definition*.
As used in this subpart, all terms not
defined herein shall have the meaning
given them in the Act and in subpart A
of this part.
"Steam generating unit" means any
furnace, boiler, or other device used for
combusting fuel for the purpose of
producing steam (including fossil-fuel-
fired steam generators associated with
combined cycle gas turbines; nuclear
steam generators are not included).
"Electric utility steam generating unit"
means any steam electric generating
unit that is constructed for the purpose
of supplying more than one-third of its
potential electric output capacity and
more than 25 MW electrical output to
any utility power distribution system for
sale. Any steam supplied to a steam
distribution system for the purpose of
providing steam to a steam-electric
generator that would produce electrical
energy for sale is also considered in
determining the electrical energy output
capacity of the affected facility.
"Fossil fuel" means natural gas,
petroleum, coal, and any form of solid,
liquid, or gaseous fuel derived from sach
material for the purpose of creating
useful heat.
"Snbbituminous coat" means coal that
is classified as subbituminoas A, B, or C
according to the American Society of
Testing and Materials' (ASTM)
Standard Specification for Classification
of Coals by Rank D388-66.
"Lignite" means coal that w classified
as lignite A or B according to the
American Society of Testing and
Materials' (ASTM} Standard
Specification for Classification of Coals
by Rank D388-86.
"Coal refuse" means waste products
of coal mining, physical coal cleaning,
and coal preparation operations (e.g.
culm, gob, etc.) containing coai, matrix
material, clay, and other organic and
inorganic material.
"Potential combustion concentration"
means the theoretical emissions (ng/J,
Ib/million Btu heat input) that would
result from combustion of a fuel in an
uncleaned state ^without emission
control systems) and*.
(a) For participate matter is:
(1) 3,000 ng/J (7.0 Ib/million Btu) heat
input for solid fuel; and
(2) 75 ng/J (0.17 Ib/millionBtu) heat
input for liquid fuels.
(b) For sulfur dioxide is determined
under § 60.48a(b),
(c) For nitrogen oxides is:
(1) 290 ng/J (0.67 Ib/million Btu) heat
input for gaseous fuels;
(2) 310 ng/J (0.72 Ib/million Btu) heat
input for liquid fuels; and
(3) 990 ng/J (2.30 Ib/million Btu) heat
input for solid fuels.
"Combined cycle gas turbine" means
a stationary turbine combustion system
where heat from the turbine exhaust
gases is recovered by a steam
generating unit
"Interconnected" means that two or
more electric generating units are
electrically tied together by a network of
power transmission lines, and other
power transmission equipment
"Electric utility company" means the
largest interconnected organization,
business, or governmental entity that
generates electric power for sale (eg- a
holding company with operating
subsidiary companies).
"Principal company" means the
electric utility company or companies
which own the affected facility.
"Neighboring company" means any
one of those electric utility companies
with one or more electric power
interconnections to the principal
company and which have
geographically adjoining service areas.
"Net system capacity" means the sum
of the net electric generating capability
(not necessarily equal to rated capacity)
of all electric generating equipment
owned by an electric utility company
(including steam generating units,
internal combustion engines, gas
turbines, nuclear units, hydroelectric
units, and all other electric generating
equipment) plus firm contractual
purchases that are interconnected to the
affected facility that has the
malfunctioning flue gas desulfurization
system. The electric generating
capability of equipment under multiple
ownership is prorated based on
ownership unless the proportional
entitlement to electric output is
otherwise established by contractual
arrangement
"System load" means the entire
electric demand of an electric utility
company's service area interconnected
with the affected facility that has the
malfunctioning flue gas desulfurizau'on
system plus firm contractual sales to
other electric utility companies. Sales to
other electric utility companies (e.g.,
emergency power) not on a firm
contractual basis may also be included
in the system load when no available
system capacity exists in the electric
utility company to which the power is
supplied for sale.
"System emergency reserves" means
an amount of electric generating
capacity equivalent to the rated
capacity of the single largest electric
generating unit in the electric utility
company (including steam generating
units, internal combustion engines, gas
turbines, nuclear units, hydroelectric
units, and all other electric generating
equipment) which is interconnected with
the affected facility that has the
malfunctioning flue gas desulfurization
system. The electric generating
capability of equipment under multiple
ownership is prorated based on
ownership unless the proportional
entitlement to electric output is
otherwise established by contractual
arrangement.
"Available system capacity" means
the capacity determined by subtracting
the system load and the system
emergency reserves from the net system
capacity.
"Spinning reserve" means the sum of
the unutilized net generating capability
of all units of the electric utility
company that are synchronized to the
power distribution system and that are
capable of immediately accepting
111-21
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additional load. The electric generating
capability of equipment under multiple
ownership is prorated based on
ownership unless the proportional
entitlement to electric output is
otherwise established by contractual
arrangement.
"Available purchase power" means
the lesser of the following:
(a) The sum of available system
capacity in all neighboring companies.
(b) The sum of the rated capacities of
the power interconnection devices
between the principal company and all
neighboring companies, minus the sum
of the electric power load on these
Interconnections.
(c) The rated capacity of the power
transmission lines between the power
interconnection devices and the electric
generating units (the unit in the principal
company that has the malfunctioning
flue gas desulfurization system and the
unit(s) in the neighboring company
supplying replacement electrical power)
less the electric power load on these
transmission lines.
"Spare flue gas desulfurization system
module" means a separate system of
sulfur dioxide emission control
equipment capable of treating an,
amount of flue gas equal to the total
amount of flue gas generated by an
affected facility when operated at
maximum capacity divided by the total
number of nonspare flue gas
desulfurization modules in the system.
"Emergency condition" means that
period of time when:
(a) The electric generation output of
an affected facility with a
malfunctioning flue gas desulfurization
system cannot be reduced or electrical
output must be increased because:
(1) All available system capacity in
the principal company interconnected
with the affected facility is being
operated, and
(2) All available purchase power
interconnected with the affected facility
is being obtained, or
(b) The electric generation demand is
being shifted as quickly as possible from
an affected facility with a
malfunctioning flue gas desulfurization
system to one or more electrical
generating units held in reserve by the
principal company or by a neighboring
company, or
(c) An affected facility with a
malfunctioning flue gas desulfurization
system becomes the only available unit
to maintain a part or all of the principal
company's system emergency reserves
and the unit is operated in spinning
reserve at the lowest practical electric
generation load consistent with not
causing significant physical damage to
the unit. If the unit is operated at a
higher load to meet load demand, an
emergency condition would not exist
unless the conditions under (a) of this
definition apply.
"Electric utility combined cycle gas
turbine" means any combined cycle gas
turbine used for electric generation that
is constructed for the purpose of
supplying more than one-third of its
potential electric output capacity and
more than 25 MW electrical output to
any utility power distribution system for
sale. Any steam distribution system that
is constructed for the purpose of
providing steam to a steam electric
generator that would produce electrical
power for sale is also considered in
determining the electrical energy output
capacity of the affected facility.
"Potential electrical output capacity"
is defined as 33 percent of the maximum
design heat input capacity of the steam
generating unit (e.g., a steam generating
unit with a 100-MW (340 million Btu/hr)
fossil-fuel heat input capacity would
have a 33-MW potential electrical
output capacity). For electric utility
combined cycle gas turbines the
potential electrical output capacity is
determined on the basis of the fossil-fuel
firing capacity of the steam generator
exclusive of the heat input and electrical
power contribution by the gas turbine.
"Anthracite" means coal that is
classified as anthracite according to the
American Society of Testing and
Materials' (ASTM) Standard
Specification for Classification of Coals
by Rank D388-66.
"Solid-derived fuel" means any solid,
liquid, or gaseous fuel derived from solid
fuel for the purpose of creating useful
heat and includes, but is not limited to,
solvent refined coal, liquified coal, and
gasified coal.
"24-hour period" means the period of
time between 12:01 a.m. and 12:00
midnight.
"Resource recovery unit" means a
facility that combusts more than 75
percent non-fossil fuel on a quarterly
(calendar) heat input basis.
"Noncontinental area" means the
State of Hawaii, the Virgin Islands,
Guam, American Samoa, the
Commonwealth of Puerto Rico, or the
Northern Mariana Islands.
"Boiler operating day" means a 24-
hour period during which fossil fuel is
combusted in a steam generating unit for
the entire 24 hours.
§ 60.42a Standard for participate matter.
(a) On and after the date on which the
performance test required to be
conducted under § 60.8 is completed, no
owner or operator subject to the
provisions of this subpart shall cause to
be discharged into the atmosphere from
any affected facility any gases which
contain participate matter in excess of:
(1) 13 ng/J (0.03 Ib/million Btu) heat
input derived from the combustion of
solid, liquid, or gaseous fuel;
(2) 1 percent of the potential
combustion concentration (99 percent
reduction) when combusting solid fuel;
and
(3) 30 percent of potential combustion
concentration (70 percent reduction)
when combusting liquid fuej.
(b) On and after the date the
particulate matter performance test
required to be conducted under 5 60.8 is
completed, no owner or operator subject
to the provisions of this subpart shall
cause to be discharged into the
atmosphere from any affected facility
any gases which exhibit greater than 20
percent opacity (6-minute average),
except for one 6-minute period per hour
of not more than 27 percent opacity.
$60.43a Standard for sulfur dioxide.
(a) On and after the date on which the
initial performance test required to be
conducted under $ 60.8 is completed, no
owner or operator subject to the
provisions of this subpart shall cause to
be discharged into the atmosphere from
any affected facility which combusts
solid fuel or solid-derived fuel, except as
provided under paragraphs (c), (d), (f) or
(h) of this section, any gases which
contain sulfur dioxide in excess of:
(1) 520 ng/J (1.20 Ib/million Btu) heat
input and 10 percent of the potential
combustion concentration (90 percent
reduction), or
(2) 30 percent of the potential
combustion concentration (70 percent
reduction), when emissions are less than
260 ng/J (0.60 Ib/million Btu) heat input.
(b) On and after the date on which the
initial performance test required to be
conducted under § 60.8 is completed, no
owner or operator subject to the
provisions of this subpart shall cause to
be discharged into the atmosphere from
any affected facility which combusts
liquid or gaseous fuels (except for liquid
or gaseous fuels derived from solid fuels
and as provided under paragraphs (e) or
(h) of this section), any gases which
contain sulfur dioxide in excess of:
(1) 340 ng/J (0.80 Ib/million Btu) heat
input and 10 percent of the potential
combustion concentration (90 percent
reduction), or
(2) 100 percent of the potential
combustion concentration (zero percent
reduction) when emissions are less than
86 ng/J (0.20 Ib/million Btu) heat input.
(c) On and after the date on which the
initial performance test required to be
111-22
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conducted under § 60.8 is complete, no
owner or operator subject to the
provisions of this subpart shall cause to
be discharged into the atmosphere from
any affected facility which combusts
olid solvent refined coal (SRC-I) any
gases which contain sulfur dioxide in
excess of 520 ng/J (1.20 Ib/million Btu)
heat input and 15 percent of the
potential combustion concentration (85
percent reduction) except as provided
under paragraph (f) of this section;
compliance with the emission limitation
is determined on a 30-day rolling
average basis and compliance with the
percent reduction requirement is
determined on a 24-hour basis.
(d) Sulfur dioxide emissions are
limited to 520 ng/J (1.20 Ib/million Btu)
heat input from any affected facility
which:
(1) Combusts 100 percent anthracite,
(2) Is classified as a resource recovery
facility, or
(3) Is located in a noncontinental area
and combusts solid fuel or solid-derived
fuel.
(e) Sulfur dixoide emissions are
limited to 340 ng/J (0.80 Ib/million Btu}
heat input from any affected facility
which is located in a noncontinental
area and combusts liquid or gaseous
fuels (excluding solid-derived fuels).
(f) The emission reduction
requirements under this section do not
apply to any affected facility that is
operated under an SO* commercial
demonstration permit issued by the
Administrator in accordance with the
provisions of § 60.45a.
(g) Compliance with the emission
limitation and percent reduction
requirements under this section are both
determined on a 30-day rolling average
basis except as provided under
paragraph (c) of this section.
(h) When different fuels are
combusted simultaneously, the
applicable standard is determined by
proration using the following formula:
(1) If emissions of sulfur dioxide to the
atmosphere are greater than 260 ng/J
(0.60 Ib/million Btu) heat input
EM, = (340 x + 520 y]/100 and
P»o, = 10 percent
(2) It emissions of sulfur dioxide to the
atmosphere are equal to or less than 260
ng/J (0.60 Ib/million Btu) heat input:
E.O, = (340 x + 520 yJ/100 and
Pao, = (90 x + 70 yJ/100
where:
EM, is the prorated sulfur dioxide emission
limit (ng/J heat input),
PIO, is the percentage of potential sulfur
dioxide emission allowed (percent
reduction required - 100-PW|),
x is the percentage of total heat input derived
from the combustion of liquid or gaseous
fuels (excluding solid-derived fuels)
y is the percentage of total heat input derived
from the combustion of solid fuel
(including solid-derived fuels)
{ 60.44a Standard for nitrogen oxides.
(a) On and after the date on which the
initial performance test required to be
conducted under § 60.8 is completed, no
owner or operator subject to the
provisions of this subpart shall cause to
be discharged into the atmosphere from
any affected facility, except as provided
under paragraph (b) of this section, any
gases which contain nitrogen oxides in
excess of the following emission limits,
based on a 30-day rolling average.
(1) NO, Emission Limits
Fuel type
Gaseous Fuels-
Coal-derived fuels
All other fuels
Uqukl Fuels
CoaWertved fuels
Shale oil ,
M other fuels
Sold Fuels.
Coal-derived fuels
Any fuel containing more than
25%, by weight, coal refuse ..
Any fuel containing more than
25%. by weight, lignite If the
Ignite is mined in North
Dakota, South Dakota, or
Montana, and is combusted
In a slag tap furnace
Lignite not subject to the 340
ng/J heat input emission limit
Subbituminous coal
Bituminous coal
Anthracite coal
All other fuels
Emission kmrt
ng/J (Ib/mllion Btu)
heat input
210 (0.50)
66 (0.20)
210 (050)
210 (0 50)
130 (0.30)
210 (0.50)
Exempt from NO,
standards and NO,
monitoring
requirements
340 (0.80)
260 (060)
210 (0.50)
260 (0.60)
260 (0.60)
260 (0.60)
(2) NO, reduction requirements
Fuel type
Gaseous fuels.
Uqud fuels.
SokJ fuels _..
Percent reduction
of potential
combustion
concentration
25%
30%
65%
(b) The emission limitations under
paragraph (a) of this section do not
apply to any affected facility which is
combusting coal-derived liquid fuel and
is operating under a commercial
demonstration permit issued by the
Administrator in accordance with the
provisions of § 60.45a.
(c) When two or more fuels are
combusted simultaneously, the
applicable standard is determined by
proration using the following formula:
(86 w+130 x+210 y+260 z]/100
where:
END 's *ne applicable standard for nitrogen
'oxides when multiple fuels are
combusted simultaneously (ng/J heat
input);
w is the percentage of total heat input
derived from the combustion of fuels
subject to the 86 ng/J heat input
standard;
x is the percentage of total heat input derived
from the combustion of fuels subject to
the 130 ng/J heat input standard;
y is the percentage of total heat input derived
from the combustion of fuels subject to
the 210 ng/J heat input standard; and
z is the percentage of total heat input derived
from the combustion of fuels subject to
the 260 ng/J heat input standard.
5 60.45a Commercial demonstration
permit.
(a) An owner or operator of an
affected facility proposing to
demonstrate an emerging technology
may apply to the Administrator for a
commercial demonstration permit. The
Administrator will issue a commercial
demonstration permit in accordance
with paragraph (e) of this section.
Commercial demonstration permits may
be issued only by the Administrator,
and this authority will not be delegated.
(b) An owner or operator of an
affected facility that combusts solid
solvent refined coal (SRC-I) and who is
issued a commercial demonstration
permit by the Administrator is not
subject to the SO* emission reduction
requirements under § 60.43a(c) but must,
as a minimum, reduce SOj emissions to
20 percent of the potential combustion
concentration (80 percent reduction) for
each 24-hour period of steam generator
operation and to less than 520 ng/J (1.20
Ib/million Btu) heat input on a 30-day
rolling average basis.
(c) An owner or operator of a fluidized
bed combustion electric utility steam
generator (atmospheric or pressurized)
who is issued a commercial
demonstration permit by the
Administrator is not subject to the SO*
emission reduction requirements under
§ 60.43a(a) but must, as a minimum,
reduce SO2 emissions to 15 percent of
the potential combustion concentration
(85 percent reduction) on a 30-day
rolling average basis and to less than
520 ng/J (1.20 Ib/million Btu) heat input
on a 30-day rolling average basis.
(d) The owner or operator of an
affected facility that combusts coal-
derived liquid fuel and who is issued a
commercial demonstration permit by the
Administrator is not subject to the
applicable NO, emission limitation and
percent reduction under § 60.44a(a) but
must, as a minimum, reduce emissions
to less than 300 ng/J (0.70 Ib/million Btu)
111-23
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heat input on a 30-day rolling average
basis.
(e) Commercial demonstration permits
may not exceed the following equivalent
MW electrical generation capacity for
any one technology category, and the
Jotal equivalent MW electrical
generation capacity for all commercial
demonstration plants may not exceed
15,000 MW.
Technology
Equivalent
tactncal
Pollutant opacity
(MW electrical
output)
SoW solvent rafted coal
(SRC 0 -
FkKfcedbed combustion
(atniospneric) -
Rmoned bed combustion
(pressunzed) _
Coal fcquKcation
Total afcxnble tor all
technologies
SO, 6.000-10,000
SO, «00-3,000
SO,
NO,
400-1.200
750-10.000
15.000
160.46a Compliance provision*.
(a) Compliance with the participate
matter emission limitation under
§ 60.42a(a)(l) constitutes compliance
with the percent reduction requirements
for particulate matter under
§ 60.42a(a)(2) and (3).
(b) Compliance with the nitrogen
oxides emission limitation under
§ 60.44a{a) constitutes compliance with
the percent reduction requirements
under § 60.44a[a)(2J.
(c) The particulate matter emission
standards under § 60.42a and the
nitrogen oxides emission standards
under § 60.44a apply at all times except
during periods of startup, shutdown, or
malfunction. The sulfur dioxide emission
standards under 5 60.43a apply at all
times except during periods of startup,
shutdown, or when both emergency
conditions exist and the procedures
under paragraph (d) of this section are
implemented.
(d) During emergency conditions in
the principal company, an affected
facility with a malfunctioning flue gas
desulfurization system may be operated
if sulfur dioxide emissions are
minimized by:
(1) Operating all operable flue gas
desulfurization system modules, and
bringing back into operation any
malfunctioned module as soon as
repairs are completed,
(2) Bypassing flue gases around only
those flue gas desulfurization system
modules that have been taken out of
operation because they were incapable
of any sulfur dioxide emission reduction
or which would have suffered significant
physical damage if they had remained in
operation, and
(3) Designing, constructing, and
operating a spare flue gas
desulfurization system module for an
affected facility larger than 365 MW
(1,250 million Btu/hr) heat input
(approximately 125 MW electrical
output capacity). The Administrator
may at his discretion require the owner
or operator within 60 days of
notification to demonstrate spare
module capability. To demonstrate this
capability, die owner or operator must
demonstrate compliance with the
appropriate requirements under
paragraph (a), (b), (d), (e), and (i) under
$ 60.43a for any period of operation
lasting from 24 hours to 30 days when:
(i) Any one flue gas desulfurization
module is not operated,
(ii) The affected facility is operating at
the maximum heat input rate,
(iii) The fuel fired during the 24-hour
to 30-day period is representative of the
type and average sulfur content of fuel
used over a typical 30-day period, and
(iv) The owner or operator has given
the Administrator at least 30 days notice
of the date and period of rime over
which the demonstration will be
performed.
(e) After the initial performance test
required under § 60.8, compliance with
the sulfur dioxide emission limitations
and percentage reduction requirements
under § 60.43a and the nitrogen oxides
emission limitations under § 60.44a is
based on the average emission rate for
30 successive boiler operating days. A
separate performance test is completed
at the end of each boiler operating day
after the initial performance test, and a
new 30 day average emission rate for
both sulfur dioxide and nitrogen oxides
and a new percent reduction for sulfur
dioxide are calculated to show
compliance with the standards.
(f) For the initial performance test
required under $ 60.8, compliance with
the sulfur dioxide emission limitations
and percent reduction requirements
under § 60.43a and the nitrogen oxides
emission limitation under § 60.44a is
based on the average emission rates for
sulfur dioxide, nitrogen oxides, and
percent reduction for sulfur dioxide for
the first 30 successive boiler operating
days. The initial performance test is the
only test in which at least 30 days prior
notice is required unless otherwise
specified by the Administrator. The
initial performance test is to be
scheduled so that the first boiler
operating day of the 30 successive boiler
operating days is completed within 60
days after achieving the maximum
production rate at which the affected
facility will be operated, but not later
than 180 days after initial startup of the
facility.
(g) Compliance is determined by
calculating the arithmetic average of all
hourly emission rates for SOi and NO,
for the 30 successive boiler operating
days, except for data obtained during
startup, shutdown, malfunction (NO,
only), or emergency conditions (SO,
only). Compliance with the percentage
reduction requirement for SOi is
determined based on the average inlet
and average outlet SO, emission rates
for the 30 successive boiler operating
days.
(h) If an owner or operator has not
obtained the minimum quantity of
emission data as required under | 60.47a
of this subpart compliance of the
affected facility with the emission
requirements under §| 60.43a and 50.44a
of this subpart for the day on which the
3O-day period ends may be determined
by the Administrator by following the
applicable procedures in sections 6.0
and 7.0 of Reference Method 19
(Appendix A).
§ 60.47a Emission monitoring.
fa) The owner or operator of an
affected facility shall install, calibrate,
maintain, &nd operate a continuous
monitoring system, and record the
output of the system, for measuring the
opacity of emissions discharged to the
atmosphere, except where gaseous fuel
is the only fuel combusted. If opacity
interference due to water droplets exists
in die stack, (for example, from the use
of an FGD system), the opacity is
monitored upstream of the interference
(at the inlet to the FGD system). If
opacity interference is experienced at
all locations (both at the inlet and outlet
of the sulfur dioxide control system),
alternate parameters indicative of the
particulate matter control system's
performance are monitored (subject to
the approval of the Administrator).
(b) The owner or operator of an
affected facility shall install, calibrate,
maintain, and operate a continuous
monitoring system, and record the
output of the system, for measuring
sulfur dioxide emissions, except where
natural gas is the only fuel combusted,
as follows:
(1) Sulfur dioxide emissions are
monitored at both the inlet and outlet of
the sulfur dioxide control device.
(2) For a facility which qualifies under
the provisions of § 60.43a(d), sulfur
dioxide emissions are only monitored as
discharged to the atmosphere.
(3) An "as fired" fuel monitoring
system (upstream of coal pulverizers)
meeling the requirements of Method 19
(Appendix A) may be used to determine
111-24
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potential sulfur dioxide emissions in
place of a continuous sulfur dioxide
emission monitor at the inlet to the
sulfur dioxide control device as required
under paragraph (b)(l) of this section.
(c) The owner or operator of an
affected facility shall install, calibrate,
maintain, and operate a continuous
monitoring system, and record the
output of the system, for measuring
nitrogen oxides emissions discharged to
the atmosphere.
(d) The owner or operator of an
affected facility shall install, calibrate,
maintain, and operate a continuous
monitoring system, and record the
output of the system, for measuring the
oxygen or carbon dioxide content of the
flue gases at each location where sulfur
dioxide or nitrogen oxides emissions are
monitored.
(e) The continuous monitoring
systems under paragraphs (b), (c), and
(d) of this section are operated and data
recorded during all periods of operation
of the affected facility including periods
of startup, shutdown, malfunction or
emergency conditions, except for
continuous monitoring system
breakdowns, repairs, calibration checks,
and zero and span adjustments.
(f) When emission data are not
obtained because of continuous
monitoring system breakdowns, repairs,
calibration checks and zero and span
adjustments, emission data will be
obtained by using other monitoring
systems as approved by the
Administrator or the reference methods
as described in paragraph (h) of this
section to provide emission data for a
minimum of 18 hours in at least 22 out of
30 successive boiler operating days.
(g) The 1-hour averages required
under paragraph § 60.13(h) are
expressed in ng/J (Ibs/million Btu) heat
input and used to calculate the average
emission rates under § 60.46a. The 1-
hour averages are calculated using the
data points required under § 60.13(b). At
least two data points must be used to
calculate the 1-hour averages.
(h) Reference methods used to
supplement continuous monitoring
system data to meet the minimum data
requirements in paragraph § 60.47a(f)
will be used as specified below or
otherwise approved by the
Administrator.
(1) Reference Methods 3, 6, and 7, as
applicable, are used. The sampling
location(s) are the same as those used
for the continuous monitoring system.
(2) For Method 6, the minimum
sampling time is 20 minutes and the
minimum sampling volume is 0.02 dscm
(0.71 dscf) for each sample. Samples are
taken at approximately 60-minute
intervals. Each sample represents a 1-
hour average.
(3) For Method 7, samples are taken at
approximately 30-minute intervals. The
arithmetic average of these two
consective samples represent a 1-hour
average.
(4) For Method 3, the oxygen or
carbon dioxide sample is to be taken for
each hour when continuous SOa and
NO, data are taken or when Methods 6
and 7 are required. Each sample shall be
taken for a minimum of 30 minutes in
each hour using the integrated bag
method specified in Method 3. Each
sample represents a 1-hour average.
(5) For each 1-hour average, the
emissions expressed in ng/J (Ib/million
Btu) heat input are determined and used
as needed to achieve the minimum data
requirements of paragraph (f) of this
section.
(i) The following procedures are used
to conduct monitoring system
performance evaluations under
§ 60.13{c) and calibration checks under
5 60.13(d).
(1) Reference method 6 or 7, as
applicable, is used for conducting
performance evaluations of sulfur
dioxide and nitrogen oxides continuous
monitoring systems.
(2) Sulfur dioxide or nitrogen oxides,
as applicable, is used for preparing
calibration gas mixtures under
performance specification 2 of appendix
B tp this part.
(3) For affected facilities burning only
fossil fuel, the span value for a
continuous monitoring system for
measuring opacity is between 60 and 80
percent and for a continuous monitoring
system measuring nitrogen oxides is
determined as follows:
Post* fuel
Span value for
nitrogen oxides (ppm)
Oaf
Liquid
Solid
Combination
500
500
1,000
500(x+y) + 1,000z
where:
x is the fraction of total heat input derived
from gaseous fossil fuel,
y is the fraction of total heat input derived
from liquid fossil fuel, and
z is the fraction of total heat input derived
from solid fossil fuel.
(4) All span values computed under
paragraph (b)(3) of this section for
burning combinations of fossil fuels are
rounded to the nearest 500 ppm.
(5) For affected facilities burning fossil
fuel, alone or in combination with non-
fossil fuel, the span value of the sulfur
dioxide continuous monitoring system at
the inlet to the sulfur dioxide control
device is 125 percent of the maximum
estimated hourly potential emissions of
the fuel fired, and the outlet of the sulfur
dioxide control device is 50 percent of
maximum estimated hourly potential
emissions of the fuel fired.
(Sec. 114, Clean Air Act as amended (42
U.S.C. 7414).)
§ 60.48a Compliance determination
procedures and methods.
(a) The following procedures and
reference methods are used to determine
compliance with the standards for
particulate matter under § 60.42a.
(1) Method 3 is used for gas analysis
when applying method 5 or method 17.
(2) Method 5 is used for determining
particulate matter emissions and
associated moisture content. Method 17
may be used for stack gas temperatures
less than 160 C (320 F).
(3) For Methods 5 or 17, Method 1 is
used to select the sampling site and the
number of traverse sampling points. The
sampling time for each run is at least 120
minutes and the minimum sampling
volume is 1.7 dscm (60 dscf) except that
smaller sampling times or volumes,
when necessitated by process variables
or other factors, may be approved by the
Administrator.
(4) For Method 5, the probe and filter
holder heating system in the sampling
train is set to provide a gas temperature
no greater than 160°C (32°F).
(5) For determination of particulate
emissions, the oxygen or carbon-dioxide
sample is obtained simultaneously with
each run of Methods 5 or 17 by
traversing the duct at the same sampling
location. Method 1 is used for selection
of the number of traverse points except
that no more than 12 sample points are
required.
(6) For each run using Methods 5 or 17,
the emission rate expressed in ng/J heat
input is determined using the oxygen or
carbon-dioxide measurements and
particulate matter measurements
obtained under this section, the dry
basis Fc-factor and the dry basis
emission rate calculation procedure
contained in Method 19 (Appendix A).
(7) Prior to the Administrator's
issuance of a particulate matter
reference method that does not
experience sulfuric acid mist
interference problems, particulate
matter emissions may be sampled prior
to a wet flue gas desulfurization system.
(b) The following procedures and
methods are used to determine
compliance with the sulfur dioxide
standards under § 60.43a.
(1) Determine the percent of potential
combustion concentration (percent PCC)
emitted to the atmosphere as follows:
111-25
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(i) Fuel Pretreatment (% Rf):
Determine the percent reduction
achieved by any fuel pretreatment using
the procedures in Method 19 (Appendix
A). Calculate the average percent
reduction for fuel pretreatment on a
quarterly basis using fuel analysis data.
The determination of percent R, to
calculate the percent of potential
combustion concentration emitted to the
atmosphere is optional. For purposes of
determining compliance with any
percent reduction requirements under
§ 60.43a, any reduction in potential SO»
emissions resulting from the following
processes may be credited:
(A) Fuel pretreatment (physical coal
cleaning, hydrodesulfurization of fuel
oil, etc.),
(B) Coal pulverizers, and
(C) Bottom and flyash interactions.
(ii) Sulfur Dioxide Control System (%
Re): Determine the percent sulfur
dioxide reduction achieved by any
sulfur dioxide control system using
emission rates measured before and
after the control system, following the
procedures in Method 19 (Appendix A);
or, a combination of an "as fired" fuel
monitor and emission rates measured
after the control system, following the
procedures in Method 19 (Appendix A).
When the "as fired" fuel monitor is
used, the percent reduction is calculated
using the average emission rate from the
sulfur dioxide control device and the
average SOj input rate from the "as
fired" fuel analysis for 30 successive
boiler operating days.
(iii) Overall percent reduction (% Raj:
Determine the overall percent reduction
using the results obtained in paragraphs
(b)(l) (i) and (ii) of this section following
the procedures in Method 19 (Appendix
A). Results are calculated for each 30-
day period using the quarterly average
percent sulfur reduction determined for
fuel pretreatment from the previous
quarter and the sulfur dioxide reduction
achieved by a sulfur dioxide control
system for each 30-day period in the
current quarter.
(iv) Percent emitted (% PCC):
Calculate the percent of potential
combustion concentration emitted to the
atmosphere using the following
equation: Percent PCC=100-Percent R.
(2) Determine the sulfur dioxide
emission rates following the procedures
in Method 19 (Appendix A).
(c) The procedures and methods
outlined in Method 19 (Appendix A) are
used in conjunction with the 30-day
nitrogen-oxides emission data collected
under § 60.47a to determine compliance
with the applicable nitrogen oxides
standard under § 60.44.
(d) Electric utility combined cycle gas
turbines are performance tested for
particulate matter, sulfur dioxide, and
nitrogen oxides using the procedures of
Method 19 (Appendix A). The sulfur
dioxide and nitrogen oxides emission
rates from the gas turbine used in
Method 19 (Appendix A) calculations
are determined when the gas turbine is
performance tested under subpart GG.
The potential uncontrolled particulate
matter emission rate from a gas turbine
is defined as 17 ng/J (0.04 lb/million Btu)
heat input.
S 60.49a Reporting requirements.
(a) For sulfur dioxide, nitrogen oxides,
and particulate matter emissions, the
performance test data from the initial
performance test and from the
performance evaluation of the
continuous monitors (including the
transmissometer) are submitted to the
Administrator.
(b) For sulfur dioxide and nitrogen
oxides the following information is
reported to the Administrator for each
24-hour period.
(1) Calendar date.
(2) The average sulfur dioxide and
nitrogen oxide emission rates (ng/J or
Ib/million Btu) for each 30 successive
boiler operating days, ending with the
last 30-day period in the quarter;
reasons for non-compliance with the
emission standards; and, description of
corrective actions taken.
(3) Percent reduction of the potential
combustion concentration of sulfur
dioxide for each 30 successive boiler
operating days, ending with the last 30-
day period in the quarter; reasons for
non-compliance with the standard; and,
description of corrective actions taken.
(4) Identification of the boiler
operating days for which pollutant or
dilutent data have not been obtained by
an approved method for at least 18
hours of operation of the facility;
justification for not obtaining sufficient
data; and description of corrective
actions taken.
(5) Identification of the times when
emissions data have been excluded from
the calculation of average emission
rates because of startup, shutdown,
malfunction (NOX only), emergency
conditions (SO« only), or other reasons,
and justification for excluding data for
reasons other than startup, shutdown,
malfunction, or emergency conditions.
(6) Identification of "F" factor used for
calculations, method of determination,
and type of fuel combusted.
(7) Identification of times when hourly
averages have been obtained based on
manual sampling methods.
(8) Identification of the times when
the pollutant concentration exceeded
full span of the continuous monitoring
system.
(9) Description of any modifications to
the continuous monitoring system which
could affect the ability of the continuous
monitoring system to comply with
Performance Specifications 2 or 3.
(c) If the minimum quantity of
emission data as required by § 60.47a is
not obtained for any 30 successive
boiler operating days, the following
information obtained under the
requirements of § 60.46a(h) is reported
to the Administrator for that 30-day
period:
(1) The number of hourly averages
available for outlet emission rates (nj
and inlet emission rates (n,) as
applicable.
(2) The standard deviation of hourly
averages for outlet emission rates (s0)
and inlet emission rates (s,) as
applicable,
(3) The lower confidence limit for the
mean outlet emission rate (E0*) and the
upper confidence limit for the mean inlet
emission rate (E,*) as applicable.
(4) The applicable potential
combustion concentration.
(5) The ratio of the upper confidence
limit for the mean outlet emission rate
(Eo*) and the allowable emission rate
(£«,,) as applicable.
(d) If any standards under § 60.43a are
exceeded during emergency conditions
because of control system malfunction,
the owner or operator of the affected
facility shall submit a signed statement:
(1) Indicating if-emergency conditions
existed and requirements under
§ 60.46a(d) were met during each period,
and
(2) Listing the following information:
(i) Time periods the emergency
condition existed;
(ii) Electrical output and demand on
the owner or operator's electric utility
system and the affected facility;
(iii) .Amount of power purchased from
interconnected neighboring utility
companies during the emergency period;
(iv) Percent reduction in emissions
achieved;
(v) Atmospheric emission rate fng/J)
of the pollutant discharged; and
(vi) Actions taken to correct control
system malfunction.
(e) If fuel pretreatment credit toward
the sulfur dioxide emission standard
under § 60.43a is claimed, the owner or
operator of the affected facility shall
submit a signed statement:
(1) Indicating what percentage
cleaning credit was taken for the
calendar quarter, and whether the credit
was determined in accordance with the
111-26
-------
provisions of 5 60.48a and Method 19
(Appendix A); and
(2) Listing the quantity, heat content,
and date each pretreated fuel shipment
was received during the previous
quarter, the name and location of the
fuel pretreatment facility; and the total
quantity and total heat content of all
fuels received at the affected facility
during the previous quarter.
(f) For any periods for which opacity,
sulfur dioxide or nitrogen oxides
emissions data are not available, the
owner or operator of the affected facility
shall submit a signed statement
indicating if any changes were made in
operation of the emission control system
during the period of data unavailability.
Operations of the control system and
affected facility during periods of data
unavailability are to be compared with
operation of the control system and
affected facility before and following the
period of data unavailability,
(g) The owner or operator of the
affected facility shall submit a signed
statement indicating whether:
(1) The required continuous
monitoring system calibration, span, and
drift checks or other periodic audits
have or have not been performed as
specified.
(2) The data used to ^how compliance
was or was not obtained in accordance
with approved methods and procedures
of this part and is representative of
plant performance.
(3) The minimum data requirements
have or have not been met; or, the
minimum data requirements have not
been met for errors that were
unavoidable.
(4) Compliance with the standards has
or has not been achieved during the
reporting period.
(h) For the purposes of the reports
required under § 60.7, periods of excess
emissions are defined as all 6-minute
periods during which the average
opacity exceeds the applicable opacity
standards under § 60.42a(b). Opacity
levels in excess of the applicable
opacity standard and the date of such
excesses are to be submitted to the
Administrator each calendar quarter.
(i) The owner or operator of an
affected facility shall submit the written
reports required under this section and
subpart A to the Administrator for every
calendar quarter. All quarterly reports
shall be postmarked by the 30th day
following the end of each calendar
quarter.
(Sec. 114, Clean Air Act as amended (42
U.8.C. 7414).)
Proposed/effective
43 FR 42154, 9/19/78
Promulgated
44 FR 33580, 6/11/79 (98)
Revised
45 FR 8211, 2/6/80 (110)
111-27
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Subpart EStandards of Performance
for Incinerators
§ 60.50 Applicability and designation of
affected facility. 8, 64
(a) The provisions of this subpart are
applicable to each Incinerator of more
than 45 metric tons per day charging
rate (50 tons/day), which is the affected
facility.
(b) Any faculty under paragraph (a)
of this section that commences construc-
tion or modification after August 17,
1971, is subject to the requirements of
this subpart.
§ 60.51 Definitions.
As used In this subpart, all terms not
defined herein shall have the meaning
given them in the Act and In Subpart A
of this part.
(a) "Incinerator" means any furnace
used In the process of burning solid waste
for the purpose of reducing the volume
of the waste by removing combustible
matter.8
(b) "Solid waste" means refuse, more
than 50 percent of which is municipal
type waste consisting of a mixture of
paper, wood, yard wastes, food wastes,
plastics, leather, rubber, and other com-
bustibles, and noncombustible materials
such as glass and rock.
(c)"Day" means 24 hours.8
§ 60.52 Standard for paniculate matter.8
(a) On and after the date on which
the performance test required to be con-
ducted by § 60.8 Is completed, no owner
or operator subject to the provisions of
this part shall cause to be discharged
Into the atmosphere from any affected
facility any gases which contain par-
ticulate matter In excess of 0.18 g/dscm
(0.08 gr/dscf) corrected to 12 percent
CO2.
§ 60.53 Monitoring of operations.8
(a) The owner or operator of any In-
cinerator subject to the provisions of this
part shall record the daily charging rates
and hours of operation.
(Sec. 114. Clean Air Act is amended (42
U.S.C. 7414)). 68, 83
§ 60.54 Test methods and procedures.8
(a) The reference methods In Ap-
pendix A to this part, except as provided
for in § 60.8(b), shall be used to deter-
mine compliance with the standard pre-
scribed in § 60.52 as follows:
(1) Method 5 for the concentration of
particulate matter and the associated
moisture content;
(2) Method 1 for sample and velocity
traverses;
(3) Method 2 for velocity and volu-
metric flow rate; and
(4) Method 3 for gas analysis and cal-
culation of excess air, using the Inte-
grated sample technique.
(b) For Method 5, the sampling time
for each run shall be at least 60 minutes
and the minimum sample volume shall
be 0.85 dscm (30.0 dscf) except that
smaller sampling times or sample vol-
umes, when necessitated by process vari-
ables or other factors, may be approved
by the Administrator.
(c) If a wet scrubber is used, the gas
analysis sample shall reflect flue gas con-
ditions after the scrubber, allowing for
carbon dioxide absorption by sampling
the gas on the scrubber inlet and outlet
sides according to either the procedure
under paragraphs (c) (1) through (c) (5)
of this section or the procedure under
paragraphs (c)(l), (c) (2) and (c) (6)
of this section as follows:
(1) The outlet sampling site shall be
the same as for the particulate matter
measurement. The Inlet site shall be
selected according to Method 1, or as
specified by the Administrator.
(2) Randomly select 9 sampling points
within the cross-section at both the inlet
and outlet sampling sites. Use the first
set of three for the first run, the second
set for the second run, and the third set
for the third run.
(3) Simultaneously with each par-
ticulate matter run, extract and analyze
for CO, an integrated gas sample accord-
Ing to Method 3, traversing the three
sample points and sampling at each
point for equal increments of time. Con-
duct the runs at both inlet and outlet
sampling sites.
(4) Measure the volumetric flow rate
at the inlet during each particulate mat-
ter run according to Method 2, using the
full number of traverse points. For the
inlet make two full velocity traverses ap-
proximately one hour apart during each
run and average the results. The outlet
volumetric flow rate may be determined
from the particulate matter run
(Method 5).
(5) Calculate the adjusted CO, per-
centage using the following equation:
(% CO«).dj = (% CO,) 41 (Qdt/Qdo)
where:
(% COi) «4j is the adjusted CO, percentage
which removes the effect of
COa absorption and dilution
air.
(% COa) 1^-1
_ 100+(%BA).J
where:
(% CO,) .4) Is the adjusted outlet CO, per-
centage,
(% CO>) 4i Is the percentage of CO« meas-
ured before the scrubber, dry
basis,
(% EA) t Is the percentage of excess air
at the Inlet, and
(% EA)» Is the percentage of excee* air
at the outlet.
(d) Particulate matter emissions, ex-
pressed in g/dscm. shall be corrected to
12 percent CO, by using the following
formula:
120
%00i
where:
ftj Is the concentration of partlculate
matter corrected to 12 percent
CO.,
e \a the concentration of parttoulate
matter as measured by Method 6,
and
% COi U the percentage of CO, as meas-
ured by Method 3, or when ap-
plicable, the adjusted outlet CO,
percentage as determined by
paragraph (c) of this section.
(Sec. 114, Clean Air Act Is amended (42
U.SC. 7414)). 68, 83
Proposed/effective
36 FR 15704, 8/17/71
Promulgated
36 FR 24876, 12/23/71 (1)
Revised
39 FR 20790, 6/14/74 (8)
42 FR 37936, 7/25/77 (64)
42 FR 41424, 8/17/77 (68)
43 FR 8800, 3/3/78 (83)
111-28
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Subpart FStandards of Performance
for Portland Cement Plant*
g 60.60 Applicability and designation of
affected facility. 64
(a) The provisions of this subpart are
applicable to the following affected fa-
cilities in Portland cement plants: kiln,
clinker cooler, raw mill system, finish
mill system, raw mill dryer, raw material
storage, clinker storage, finished product
storage, conveyor transfer points, bag-
ging and bulk loading and unloading sys-
tems.
(b) Any facility under paragraph (a)
of this section that commences construc-
tion or modification after August 17,
1971, is subject to the requirements of
this subpart
§ 60.61 Definitions.
As used In this subpart, all terms not
denned herein shall have the meaning
given them in the Act and in Subpart A
of this part.
(a) "Portland cement plant" means
any facility manufacturing Portland ce-
ment by either the wet or dry process.8
§ 60.62 Standard for particulate matter.8
(a) On and after the date on which
the performance test required to be con-
ducted by ! 60.8 is completed, no owner
or operator subject to the provisions of
this subpart shall cause to be discharged
Into the atmosphere from any kiln any
gases which:
(1) Contain particulate matter In ex-
cess of 0.15 kg per metric ton of feed
(dry basis) to the kiln (0.30 Ib per ton).
(2) Exhibit greater than 20 percent
opacity.10
(b) On and after the date on which
the performance test required to be con-
ducted by § 60.8 is completed, no owner
or operator subject to the provisions of
this subpart shall cause to be discharged
Into the atmosphere from any clinker
cooler any gases which:
(1) Contain particulate matter In ex-
cess of 0.050 kg per metric ton of feed
(dry basis) to the kiln (0.10 Ib per ton).
(2) Exhibit 10 percent opacity, or
greater.
(c) On and after the date on which
the performance test required to be con-
ducted by { 60.8 Is completed, no owner
or operator subject to the provisions of
this subpart shall cause to be discharged
Into the atmosphere from any affected
facility other than the kiln and clinker
cooler any gases which exhibit 10 percent
opacity, or greater. 1»
§ 60.63 Monitoring of operations.8
(a) The owner or operator of any
Portland cement plant subject to the pro-
visions of this part shall record the dally
production rates and kiln feed rates.
(Sec. 114, Clean Air Act Is amended (42
U.S.C. 7414)). 68, 83
§ 60.64 Test methods and procedures.8
(a) The reference methods in Appen-
dix A to this part, except as provided for
In J60.8(b), shall be used to determine
compliance with the standards pre-
scribed in § 60.62 as follows:
(1) Method 5 for the concentration
of particulate matter and the associated
moisture content;
(2) Method 1 for sample and velocity
traverses;
(3) Method 2 for velocity and volu-
metric flow rate; and
(4) Method 3 for gas analysis.
(b) For Method 5, the minimum sam-
pling time and minimum sample volume
for each run, except when process varia-
bles or other factors justify otherwise to
the satisfaction of the Administrator,
shall be as follows:
(1) 60 minutes and 0.85 dscm (30.0
dscf) for the kiln.
(2) 60 minutes and 1.15 dscm (40.6
dscf) for the clinker cooler.
(c) Total kiln feed rate (except fuels),
expressed In metric tons per hour on a
dry basis, shall be determined during
each testing period by suitable methods;
and shall be confirmed by a material bal-
ance over the production system.
(d) For each run, particulate matter
emissions, expressed in g/metric ton of
kiln feed, shall be determined by divid-
ing the emission rate in g/hr by the kiln
feed rate. The emission rate shall be
determined by the equation, g/hr=Qsx
c, where Q.=volumetrlc flow rate of the
total effluent in dscm/hr as determined
In accordance with paragraph (a) (3) of
this section, and c=particulate concen-
tration In g/dscm as determined in ac-
cordance with paragraph (a) (1) of this
section.
(Sec. 114. Clean Air Act is amended (42
U.S.C. 7414)). 68, 83
Proposed/effecti ve
36 FR 15704, 8/17/71
Promulgated
36 FR 24876, 12/23/71 (1)
Revised
39 FR 20790,
39 FR 39872.
40 FR 46250,
42 FR 37936,
42 FR 41424,
43 FR
6/14/74 (8)
11/12/74 (10)
10/6/75 (18)
7/25/77 (64)
8/17/77 (68)
3/3/78 (83)
111-29
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Subpart CStandards of Performance
for Nitric Acid Plants
§ 60.70 Applicability and designation of
affected facility. 64
(a) The provisions of this subpart are
applicable to each nitric acid production
unit, which is the affected facility.
(b) Any facility under paragraph (a)
of this section that commences construc-
tion or modification after August 17,
1971, is subject to the requirements of
this subpart.
§ 60.71 Definitions.
As used in this subpart, all terms not
defined herein shall have the meaning
given them in the Act and in Subpart A
of this part.
(a) "Nitric acid production unit"
means any facility producing weak nitric
acid by either the pressure or atmos-
pheric pressure process.
(b) "Weak nitric acid" means acid
which is 30 to 70 percent in strength.
method test data averages by the moni-
toring data averages to obtain a ratio ex-
pressed in units of the applicable stand-
ard to units of the monitoring data, i.e.,
kg/metric ton per ppm (Ib/short ton per
ppm>. The conversion factor shall be re-
established during any performance test
under { 60.8 or any continuous .monitor-
ing system performance evaluation under
§60.13(c).
(c) The owner or operator shall record
the daily production rate and hours of
operation.
(d) [Reserved] 8
(e) For the purpose 6f reports required
under 5 60.7(c), periods of excess emis-
sions that shall be reported are defined
as any three-hour period during which
the average nitrogen oxides emissions
(arithmetic average of three contiguous
one-hour periods) as measured by a con-
tinuous monitoring system exceed the
standard under § 60.72(a).4*'8
(Sec. 114, Clean Air Act Is amended (42
U.S.C. 7414)). 48, 83
§60.72 Standard for nitrogen oxide*.3'8
(a) On and after the date on which
the performance test required to be con-
ducted by § 60.8 Is completed, no owner
or operator subject to the provisions of
this subpart shall cause to be discharged
into the atmosphere from any affected
facility any gases which:
(1) Contain nitrogen oxides, ex-
pressed as NOi. In excess of 1.5 kg per
metric ton of acid produced (3.0 Ib per
ton), the production being expressed as
100 percent nitric acid.
(2) Exhibit 10 percent opacity, or
greater. 18
§ 60.73 Emission monitoring. "
(a) A continuous monitoring system
for the measurement of nitrogen oxides
shall be installed, calibrated, maintained,
and operated by the owner or operator.
The pollutant gas used to prepare cali-
bration gas mixtures under paragraph
2.1, Performance Specification 2 and for
calibration checks under I 60.13 (d) to
this part, shall be nitrogen dioxide (NO?) .
The span shall be set at 500 ppm of nitro-
gen dioxide. Reference Method 7 shall
be used for conducting monitoring sys-
tem performance evaluations under 8 60.-
(b) The owner or operator shall estab-
lish a conversion factor for the purpose
of converting monitoring data into units
of the applicable standard (kg/metric
ton, Ib/short ton) . The conversion factor
shall be established by measuring emis-
sions with the continuous ' monitoring
system concurrent with measuring .emis-
sions with the applicable reference methr
od tests. Using only that portion of the
continuous monitoring emission data
that reoresents emission measurements
concurrent with the reference method
test periods, the conversion factor shall
be determined by dividing the reference
§ 60.74 T<*l method* end procedure*. 8
(a) The reference methods In Appen-
dix A to this part, except as provided for
In § 60.8(b), shall be used to determine
compliance with the standard prescribed
In { 60.72 as follows:
(1) Method 7 for the concentration of
NO*;
(2) Method 1 for sample and velocity
traverses;
(3) Method 2 for velocity and volu-
metric flow rate; and
(4) Method 3 for gas analysis.
(b) For Method 7, the sample site shall
be selected according to Method 1 and
the sampling point shall be the centroid
of the stack or duct or at a point no
closer to the walls than 1m (3.28 ft).
Each run shall consist of at least four
grab samples taken at approximately 15-
minutes intervals. The arithmetic mean
of the samples shall constitute the run
value. A velocity traverse shall be per-
formed once per run.
(c) Acid production rate, expressed In
metric tons per hour of 100 percent nitric
acid, shall be determined during each
testing period by suitable methods and
shall be confirmed by a material balance
over the production system.
(d) For each run, nitrogen oxides, ex-
pressed In g/metric ton of 100 percent
nitric acid, shall be determined by divid-
ing the emission rate in g/hr by the acid
production rate. The emission rate shall
be determined by the equation.
g/br-Q.Xc
where Q,volumetric flow* rate of the
effluent in dscm/hr, as determined in ac-
cordance with paragraph (a) (3) of this
section, and cNO, concentration In
g/dscm, as determined in accordance
with paragraph (a) (1) of this section.
-------
Subpart HStandards of Performance
for Sulfuric Acid Plants
§ 60.80 Applicability «nd designation of
a Sfcted facility. 64
(a) The provisions of this subpart are
applicable to each sulfuric acid produc-
tion unit, which is the affected facility.
(b) Any facility under paragraph (a)
of this section that commences construc-
tion or modification after August 17,
1971, is subject to the requirements of
this subpart.
§ 60.81 Definition*.
As used in this subpart, all terms not
defined herein shall have the meaning
given them in the Act and in Subpart A
of this part.
(a) "Sulfuiic acid production unit"
means any facility producing sulfuric
acid by the contact process by burning
elemental sulfur, alkylation acid, hydro-
gen sulflde, organic sulfides and mer-
captans, or acid sludge, but does not in-
clude facilities where conversion to sul-
furic acid is utilized primarily as a means
of preventing emissions to the atmos-
phere of sulfur dioxide or other sulfur
compounds.
(b) "Acid mist" means sulfuric add
mistr at measured by Method 8 of Ap-
pendix A to this part or an equivalent or
alternative method. B
§ 60.82 Standard for tnlf ur dioxide. 8
(a) On and after the date on which the
performance test required to be con-
ducted by 5 60.8 Is completed, no owner
or operator subject to the provisions of
this subpart shall cause to be discharged
into the atmosphere from any affected
facility any gases which contain sulfur
dioxide In excess of 2 kg per metric ton
of acid produced (4 Ib per ton) , the pro-
duction being expressed as 100 percent
{60.83 Standard for acid mi*!.3'8
(a) On and after the date on which the
performance test required to be con-
ducted by i 60.8 is completed, no owner
or operator subject to the provisions of
this subpart shall cause to be discharged
into the atmosphere from any affected
facility any gases which:
(1) Contain add mist, expressed as
H»SO,, in excess of 0.075 kg per metric
ton of acid produced (0.15 Ib per ton),
the production being expressed as 100
percent H>SO<.
(2) Exhibit 10 percent opacity, or
greater, is
§60.84 F mission monitoring. '*
(a) A continuous monitoring system
for the measurement of sulfur dioxide
shall be installed, calibrated, maintained.
and operated by the owner or operator.
The pollutant gas used to prepare cali-
bration gas mixtures under paragraph
2.1, Performance Specification 2 and for
calibration checks under § 60.13(d) to
this part, shall be sulfur dioxide (SO,).
Reference Method 8 shall be used for
conducting monitoring system perform-
ance evaluations under § 60.13CO ex-
cept that onlv the sulfur dioxide portion
of the Method 8 results shall be used. The
scan shall be set at 1000 ppm of sulfur
dioxide.
(b) The owner or operator snail estab-
lish a conversion factor for the purpose
of converting monitoring data into units
of the applicable standard (kg/metric
ton, Ib/short ton). The conversion fac-
tor shall be determined, as a minimum,
three times daily by measuring the con-
centration of sulfur dioxide entering the
converter using suitable methods (e.g.,
the Reich test, National Air Pollution
Control Administration Publication No.
999-AP-13 and calculating the appro-
priate conversion factor for each eight-
hour period as follows:
__, . ri.000-0.015rl
CF=k IF^r J
where:
CF = eon version factor (kg/metric ton per
ppm. Ib/short ton per .ppm).
k ^-constant derived from material bal-
ance. For determining CF In metric
units, k = 0.0653. For determining CF
in English units, k=0.1306.
r = percentage of sulfur dioxide by vol-
ume entering the gas converter. Ap-
propriate correctione must be made
for air Injection plants subject to the
Administrator's approval.
s =percentage of sulfur dioxide by vol-
ume In the emissions to the atmos-
phere determined by the continuous
monitoring system required under
paragraph (a) of this section.
(c) The owner or operator shall re-
cord all conversion factors and values un-
der paragraph Cb) of this section from
which they were computed (i.e.. CF. r,
and s).
(d) [Reservedl 8
(e) For the purpose of reports under
|60.7(c), periods of excess emissions
shall be all three-hour periods (or the
arithmetic average of three consecutive
one-hour periods) during which the in-
tegrated average sulfur dioxide emissions
exceed the applicable standards under
J 615 82. <,18
(Sec. 114. Clean Air Act It amended (42
U.6.C. 7414)).68. 83
| 60.85 Te»l method* and procedure*.8
(a) The reference methods in Appen-
dix A to this part, except as provided for
in i 60.8(b), shall be used to determine
compliance with the standards pre-
scribed in 55 60.82 and 60.83 as follows:
(1) Method « for the concentrations of
SO, and acid mist;
(2). Method 1 for sample and velocity
traverses;
(3) Method 2 for velocity and volu-
metric flow rate; and
(4.) Method 3 for gas analysis.
(b) The moisture content can be con-
sidered to be zero. For Method 8 the sam-
pling time for each run shall be at least
60 minutes and the minimum sample vol-
ume shall be 1,15 dscm (40.6 dscf) except
that smaller sampling times or sample
volumes, when necessitated by process
variables or other factors, may be ap-
proved by the Administrator.
(c) Acid production rate, expressed in
metric tons per hour of 100 percent
BUSOi, shall be determined during each
testing period by suitable methods and
hall be confirmed by a material bal-
ance over the production system.
(d) Acid mist and sulfur dioxide emis-
sions, expressed in g/metric ton of 100
percent HiSOt, shall be determined by
dividing the emission rate in g/hr by the
acid production rate. The emission rate
shall be determined by the equation,
B/hr=Q.xe, where Q.=volumetric flow
rate of the effluent in dscm/hr as deter-
mined in accordance with paragraph
(a) (3) of this section, and c=acid mist
and SO. concentrations in g/dscm as
determined in accordance with para-
graph (a) (1) of this section.
(Sec. 114. Clean Air Act U amended (42
U.S.C. 7414)).6883
Proposed/effective
36 FR 15704, 8/17/71
Promulgated
36 FR 24876, 12/?3/71 (1)
Revised
38 FR 13562,
38 FR 28564.
39 FR 20790.
40 FR 46250,
42 FR 37936.
42 FR 41424.
43 FR 8800,
5/23/73 (3)
10/15/73 (4)
6/14/74 (8)
10/6/75 (18)
7/25/77 (64)
8/17/77 (68)
3/3/78 (83)
111-31
-------
Subpart IStandards of Performance
for Asphalt Concrete Plants5'100
§60.90 Applicability and designation of
affected facility.
(a) The affected facility to which
the provisions of this subpart apply is
each asphalt concrete plant. For the
purpose of this subpart, an asphalt
concrete plant is comprised only of
any combination of the following:
Dryers; systems for screening, han-
dling, storing, and weighing hot aggre-
gate; systems for loading, transferring,
and storing mineral filler; systems for
mixing asphalt concrete; and the load-
ing, transfer, and storage systems asso-
ciated with emission control systems.
(b) Any facility under paragraph (a)
of this section that commences con-
struction or modification after June
11, 1973, is subject to the requirements
of this subpart.
when necessitated by process variables
or other factors, may be approved by
the Administrator.
(Sec. 114, Clean Air Act as amended (42
U.S.C. 7414))68'83
§ 60.91 Definitions.
As used in this subpart, all terms not
defined herein shall have the meaning
given them in the Act and in Subpart
A of this part.
(a) "Asphalt concrete plant" means
any facility, as described in § 60.90,
used to manufacture asphalt concrete
by heating and drying aggregate and
mixing with asphalt cements.
§ 60.92 Standard for paniculate matter.
(a) On and after the date on which
the performance test required to be
conducted by § 60.8 is completed, no
owner or operator subject to the provi-
sions of this subpart shall discharge or
cause the discharge into the atmos-
phere from any affected facility any
gases which:
(1) Contain particulate matter in
excess of 90 mg/dscm (0.04 gr/dscf).
(2) Exhibit 20 percent opacity, or
greater.18
§ 60.93 Test methods and procedures.
(a) The reference methods appended
to this part, except as provided for in
§ 60.8(b), shall be used to determine
compliance with the standards pre-
scribed in § 60.92 as follows:
(1) Method 5 for the concentration
of particulate matter and the associat-
ed moisture content,
(2) Method 1 for sample and velocity
traverses,
(3) Method 2 for velocity and volu-
metric flow rate, and
(4) Method 3 for gas analysis.
(b) For Method 5, the sampling time
for each run shall be at least 60 min-
utes and the sampling rate shall be at
least 0.9 dscm/hr (0.53 dscf/min)
except that shorter sampling times,
Proposed/effective
38 FR 15406, 6/11/73
Promulgated
39 FR 9308, 3/8/74 (5)
Revised
40 FR 46250, 10/6/75 (18)
42 FR 37936, 7/25/77 (64)
42 FR 41424, 8/17/77 (68)
43 FR 8800, 3/3/78 (83)
44 FR 51225, 8/31/79 (100)
111-32
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Subpart JStandards of Performance
for Petroleum Refineries5
S 60.100 Applicability and designation of
affected facility.64'8*
(a) The provisions of this subpart are
applicable to the following affected
facilities in petroleum refineries: fluid
catalytic cracking unit catalyst
regenerators, fuel gas combustion
devices, and all Claus sulfur recovery
plants except Claus plants of 20 long
tons per day (LTD) or less. The Claus
ulfur recovery plant need not be
physically located within the boundaries
of a petroleum refinery to be an affected
facility, provided it processes gases
produced within a petroleum refinery.
(b) Any fluid catalytic cracking unit
catalyst regenerator or fuel gas com-
bustion device under paragraph (a) of
this section which commences con-
struction or modification after June
11, 1973, or any Claus sulfur recovery
plant under paragraph (a) of this sec-
tion which commences construction or
modification after October 4, 1976, is
subject to the requirements of this
part.
§60.101 Definitions.
As used in this subpart, all terms not
defined herein shall have the meaning
given them in the Act and in Subpart
A.
(a) "Petroleum refinery" means any
facility engaged in producing gasoline,
kerosene, distillate fuel oils, residual
fuel oils, lubricants, or other products
through distillation of petroleum or
through redistillation, cracking or re-
forming of unfinished petroleum de-
rivatives.
(b) "Petroleum" means the crude oil
removed from the earth and the oils
derived from tar sands, shale, and coal.
(c) "Process gas" means any gas gen-
erated by a petroleum refinery process
unit, except fuel gas and process upset
gas as defined in this section.
(d) "Fuel gas" means natural gas or
any gas generated by a petroleum re-
finery process unit which is combusted
separately or in any combination. Fuel
does not include gases generated by
catalytic cracking unit catalyst regen-
erators and fluid coking unit coke
burners.96
(e) "Process upset gas" means any
gas generated by a petroleum refinery
process unit as a result of start-up,
shut-down, upset or malfunction.
(f) "Refinery process unit" means
any segment of the petroleum refinery
in which a specific processing oper-
ation is conducted.
(g) "Fuel gas combustion device"
means any equipment, such as process
heaters, boilers and flares used to com-
bust fuel gas, except facilities in which
gases are combusted to produce sulfur
or sulfuric acid.
(h) "Coke burn-off" means the coke
removed from the surface of the fluid
catalytic cracking unit catalyst by
combustion in the catalyst regenera-
tor. The rate of coke burn-off is calcu-
lated by the formula specified in
§ 60.106.
(i) "Claus sulfur recovery plant"
means a process unit which recovers
sulfur from hydrogen sulfide by a
vapor-phase catalytic reaction of
sulfur dioxide and hydrogen sulfide.86
(j) "Oxidation control system"
means an emission control system
which reduces emissions from sulfur
recovery plants by converting these
emissions to sulfur dioxide.86
(k) "Reduction control system"
means an emission control system
which reduces emissions from sulfur
recovery plants by converting these
emissions to hydrogen sulfide.86
(1) "Reduced sulfur compounds"
means hydrogen sulfide (H2S), car-
bonyl sulfide (COS) and carbon disul-
fide (CSa).86
(m) [Reserved]
'CJ
§ 60.102 Standard for paniculate matter.
(a) On and after the date on which
the performance test required to be
conducted by § 60.8 is completed, no
owner or operator subject to the provi-
sions of this subpart shall discharge or
cause the discharge into the atmos-
phere from any fluid catalytic crack-
ing unit catalyst regenerator.-8*
(1) Particulate matter in excess of
1.0 kg/1000 kg (1.0 lb/1000 Ib) of coke
burn-off in the catalyst regenerator.
(2) Gases exhibiting greater than 30
percent opacity, except for one six-
minute average opacity reading in any
one hour period.18,61-66
(b) Where the gases discharged by
the fluid catalytic cracking unit cata-
lyst regenerator pass through an in-
cinerator or waste heat boiler in which
auxiliary or supplemental liquid or
solid fossil fuel is burned, particulate
matter in excess of that permitted by
paragraph (aXl) of this section may
be emitted to the atmosphere, except
that the incremental rate of particu-
late matter emissions shall not exceed
43.0 g/MJ (0.10 Ib/million Btu) of
heat input attributable to such liquid
or solid fossil fuel.86
§60.103 Standard for carbon monoxide.
(a) On and after the date on which
the performance test required to be
conducted by § 60.8 is completed, no
owner or operator subject to the provi-
sions of this subpart shall discharge or
cause the discharge into the atmos-
phere from the fluid catalytic cracking
unit catalyst regenerator any gases
which contain carbon monoxide in
excess of 0.050 percent by volume.
§ 60.104 Standard for sulfur dioxide.86
(a) On and after the date on which
the performance test required to be
conducted by § 60.8 is completed, no
owner or operator subject to the provi-
sions of this subpart shall:
(1) Burn in any fuel gas combustion
device any fuel gas which contains hy-
drogen sulfide in excess of 230 mg/
dscm (0.10 gr/dscf), except that the
gases resulting from the combustion of
fuel gas may be treated to control
sulfur dioxide emissions provided the
owner or operator demonstrates to the
satisfaction of the Administrator that
this is as effective in preventing sulfur
dioxide emissions to the atmosphere
as restricting the H, concentration in
the fuel gas to 230 mg/dscm or less.
The combustion in a flare of process
upset gas, or fuel gas which is released
to the flare as a result of relief valve
leakage, is exempt from this para-
graph.
(2) Discharge or cause the discharge
of any gases into the atmosphere from
any Claus sulfur recovery plant con-
taining in excess of:
(i) 0.025 percent by volume of sulfur
dioxide at zero percent oxygen on a
dry basis if emissions are controlled by
an oxidation control system, or a re-
duction control system followed by in-
cineration, or
(ii) 0.030 percent by volume of re-
duced sulfur compounds and 0.0010
percent by volume of hydrogen sulfide
calculated as sulfur dioxide at zero
percent oxygen on a dry basis if emis-
sions are controlled by a reduction
control system not followed by incin-
eration.
(b) [Reserved]
I Q
§60.105 Emission monitoring.
(a) Continuous monitoring systems
shall be installed, calibrated, main-
tained, and operated by the owner or
operator as follows:
(DA continuous monitoring system
for the measurement of the opacity of
emissions discharged into the atmos-
phere from the fluid catalytic cracking
unit catalyst regenerator. The con-
tinuous monitoring system shall be
spanned at 60, 70, or 80 percent opac-
ity.
(2) An instrument for continuously
monitoring and recording the concen-
tration of carbon monoxide in gases
discharged into the atmosphere from
fluid catalytic cracking unit catalyst
regenerators. The span of this con-
tinuous monitoring system shall be
1,000 ppm.86
(3) A continuous monitoring system
for the measurement of sulfur dioxide
in the gases discharged into the atmos-
phere from the combustion of fuel
gases (except where a continuous mon-
itoring system for the measurement of
hydrogen sulfide is installed under
paragraph (a) (4) of this section). The
pollutant gas used to prepare calibra-
tion gas mixtures under paragraph 2.1,
111-33
-------
Performance Specification 2 and for
calibration checks under § 60.13(d),
shall be sulfur dioxide (SO2). The span
shall be set at 100 ppm. For conduct-
ing monitoring system performance
evaluations under § 60.13(c), Reference
Method 6 shall be used.
(4) An instrument for continuously
monitoring and recording concentra-
tions of hydrogen sulfide in fuel gases
burned in any fuel gas combustion
device, if compliance with
§ 60.104(a)(l) is achieved by removing
H2S from the fuel gas before it is
burned; fuel gas combustion devices
having a common source of fuel gas
may be monitored at one location, if
monitoring at this location accurately
represents the concentration of H2S in
the fuel gas burned. The span of this
continuous monitoring system shall be
300 ppm.86
(5) An instrument for continuously
monitoring and recording concentra-
tions of SO2 in the gases discharged
into the atmosphere from any Claus
sulfur recovery plant if compliance
with § 60.104(a)(2) is achieved through
the use of an oxidation control system
or a reduction control system followed
by incineration. The span of this con-
tinuous monitoring system shall be
sent at 500 ppm. 86
(6) An instrument(s) for continuous-
ly monitoring and recording the con-
centration of HzS and reduced sulfur
compounds in the gases discharged
into the atmosphere from any Claus
sulfur recovery plant if compliance
with § 60.104(a)(2) is achieved through
the use of a reduction control system
not followed by incineration. The
span(s) of this continuous monotoring
system(s) shall be set at 20 ppm for
monitoring and recording the concen-
tration of H2S and 600 ppm for moni-
toring and recording the concentration
of reduced sulfur compounds.86
(b) [Reserved]
(c) The average coke burn-off rate
(thousands of kilogram/hr) and hours
of operation for any fluid catalytic
cracking unit catalyst regenerator sub-
ject to § 60.102 or § 60.103 shall be re-
corded daily.
(d) For any fluid catalytic cracking
unit catalyst regenerator which is sub-
ject to § 60.102 and which utilizes an
incinerator-waste heat boiler to com-
bust the exhaust gases from the cata-
lyst regenerator, the owner or opera-
tor shall record daily the rate of com-
bustion of liquid or solid fossil fuels
(liters/hr or kilograms/hr) and the
hours of operation during which liquid
or solid fossil fuels are combusted in
the incinerator-waste heat boiler.
(e) For the purpose of reports under
§ 60.7(c), periods of excess emissions
that shall be reported are defined as
follows:
(1) Opacity. All one-hour periods
which contain two or more six-minute
periods during which the average
opacity as measured by the continuous
monitoring system exceeds 30 percent*'46 (4) Any six-hour period during
(2) Carbon monoxide. All hourly pe-
riods during which the average carbon
monoxide concentration in the gases
discharged into the atmosphere from
any fluid catalytic cracking unit cata-
lyst regenerator subject to § 60.103 ex-
ceeds 0.050 percent by volume.86
(3) Sulfur dioxide, (i) Any three-
hour period during which the average
concentration of H2S in any fuel gas
combusted in any fuel gas combustion
device subject to § 60.104(a)(l) exceeds
230 mg/dscm (0.10 gr/dscf), if compli-
ance is achieved by removing H2S from
the fuel gas before it is burned; or any
three-hour period during which the
average concentration of SOa in the
gases discharged into the atmosphere
from any fuel gas combustion device
subject to §60.104(a)(l) exceeds the
level specified in § 60.104(a)(l), if com-
pliance is achieved by removing SO,
from the combusted fuel gases.86
(ii) Any twelve-hour period during
which the average concentration of
SO2 in the gases discharged into the
atmosphere from any Claus sulfur re-
covery plant subject to § 60.104(a)(2)
exceeds 250 ppm at zero percent
oxygen on a dry basis if compliance
with § 60.104(b) is achieved through
the use of an oxidation control system
or a reduction control system followed
by incineration; or any twelve-hour
period during which the average con-
centration of H2S, or reduced sulfur
compounds in the gases discharged
into the atmosphere of any Claus
sulfur plant subject to § 60.104(a)(2)(b)
exceeds 10 ppm or 300 ppm, respec-
tively, at zero percent oxygen and on a
dry basis if compliance is achieved
through the use of a reduction control
system not followed by incineration.86
which the average emissions (arithme-
tic average of six contiguous one-hour
periods) of sulfur dioxide as measured
by a continuous monitoring system
exceed the standard under § 60.104.
(Sec. 114. Clean Air
U.S.C. 7414»°8,83
Act as amended (42
§ 60.106 Test methods and procedures.
(a) For the purpose of determining
compliance with § 60.102(a)(l), the fol-
lowing reference methods and calcula-
tion procedures shall be used:
(1) For gases released to the atmos-
phere from the fluid catalytic cracking
unit catalyst regenerator:
(i) Method 5 for the concentration
of particulate matter and moisture
content,
(ii) Method 1 for sample and velocity
traverses, and
(iii) Method 2 for velocity and volu-
metric flow rate.
(2) For Method 5, the sampling time
for each run shall be at least 60 min-
utes and the sampling rate shall be at
least 0.015 dscm/min (0.53 dscf/min),
except that shorter sampling times
may be approved by the Administrator
when process variables or other fac-
tors preclude sampling for at least 60
minutes.
(3) For exhaust gases from the fluid
catalytic cracking unit catalyst regen-
erator prior to the emission control
system: the integrated sample tech-
niques of Method 3 and Method 4 for
gas analysis and moisture content, re-
spectively; Method 1 for velocity tra-
verses; and Method 2 for velocity and
volumetric flow rate.
(4) Coke burn-off rate shall be deter-
mined by the following formula:
R. -0.2982 QRK (%COi+%CO)+2.088 QnA-0.0994 QRI
(Metric Units)
R,-0.0186QR« (%COt+%CO)+0.1303 QRA-0.0062 QBE (^£2+%cOrf%Oj) (English Units)
where:
Rc=coke burn-off rate, kg/hr (English units: Ib/hr).
0.2982=metrtc units material balance factor divided by 100, kg-inin/hr-m'.
0.0186= English units material balance factor divided by 100, Ib-min/hr-ft1.
QRK = fluid catalytic cracking unit catalyst regenerator eihaust gas flow rat« before entering the emission
control system, as determined by method 2, dscm/mln (English units: dscf/mln).
%COi= percent carbon dioiide by volume, dry basis, as determined by Method 3.
Tc CO = percent carbon monoxide by volume, dry basis, as determined by Method 3.
% Oi=percent oxygen by volume, dry basis, as determined by Method 3.
2.0S8=metric units material balance factor divided by 100, kg-min/hr-m'.
0.1303=English units material balance factor divided by 100, ib-inin/hr-ft'.
QRA=alr rate to fluid catalytic cracking unit catalyst regenerator, as determined from fluid "catalytic cracking
unit control room Instrumentation, dscm/mln (English units: dscf/mln).
0.0994=metric units material balance factor divided by 100, kg-min/hr-m'.
0.0082=EngUsh units material balance factor divided by 100, Ib-raln/hr-ft».
(5) Particulate emissions shall be determined by the following equation :
RK=(60X10-«)QRvC. (Metric Units)
or
RE=(8.57X10-»)Q,RvC. (English Units)
where:
RKpartlculate omission rate, kg/hr (English units: Ib/hr).
80X10"*=metrlc units conversion factor, mln-kg/hr-mg.
8.57X10-'=English units conversion factor, mln-lb/lir-pr.
QRv=volumetric flow rate of gases discharged Into the atmosphere from the fluid catalytic cracking unit
catalyst regenerator following the emission control system, as determined by Method 2, dscm/mln
(English units: dscf/mln).
C," particulate emission concentration discharged Into tbe atmosphere, as determined by Method 8.
mg/dscm (English units: gr/dscf)-
111-34
-------
(6) For each run, emissions expressed In kg/1000 kg (English units: lb/1000 Ib)
of coke burn-off In the catalyst regenerator shall be determined by the following
equation:
K.-100oJ^ (Metric or English Units)
K»
where
R.particulate emission rate, kg/1000 kg (English units: IbAOOO Ib) of coke burn-ofl In the fluid catalytic crack-
Ing unit catalyst regenerator.
1000-oonverdon factor, kg to 1000 kg (English units: Ib to 1000 Ib).
RE~ particular emission rate, kg/hr (English units Ib/hr).
R.coke burn-ofl rate, kg/hr (English units: Ib/br).
(7) In those Instances In which auxiliary liquid or solid fossil fuels are burned
In an Incinerator-waste heat boiler, the rate of participate matter emissions per-
mitted under 5 60.102(b) must be determined. Auxiliary fuel heat Input, expressed
In millions of cal/nr (English units: Millions of Btu/hn shall be calculated for
each run by fuel flow rate measurement and analysis of the liquid or solid auxiliary
fossil fuels. For each run, the rate of partlculate emissions permitted under
160.102(b> shall be calculated from the following equation :
R.=
R.-1.0+
(Metric
(Engllsh Units)
where
R.=
1.0-
0.18 =
0.10-
H =
R.-
allowable partlculate emission rate, kg/1000 kg (English units- IbAOOO Ib) of coke burn-ofl In the
fluid catalytic cracking unit catalyst regenerator.
emission standard, 1.0 kg/1000 kg (English units: 1.0 IbAOOO Ib) of coke burn-off In the fluid catalytic
cracking unit catalyst regenerator.
metric units maiimum allowable Incremental rate of partlculate emissions, g/mllllon cal.
English units maximum allowable incremental rate of particular emissions. Ib/mlllion Btu.
heat input from solid or liquid fossil fuel, million cal/hr (English units* million Btu/hr).
coke burn-off rate, kg/hr (English units' Ib/hr).
(b) For the purpose of determining
compliance with {60.103, the integrated
sample technique of Method 10 shall be
used. The sample shall be extracted at a
rate proportional to the gas velocity at a
sampling point near the centrold of the
duct. The sampling time shall not be less
than 90 minutes.
(c) For the purpose of determining
compliance with § 60.104(a)(l),
Method 11 shall be used to determine
the concentration of, H»S and Method
6 shall be used to determine the con-
centration of SOa.86
(1) If Method 11 is used, the gases
sampled shall be introduced into the
sampling train at approximately atmo-
spheric pressure. Where refinery fuel
gas lines are operating at pressures
substantially above atmosphere, this
may be accomplished with a flow con-
trol valve. If the line pressure is high
enough to operate the sampling train
without a vacuum pump, the pump
may be eliminated from the sampling
train. The sample shall be drawn from
a point near the centroid of the fuel
gas line. The minimum sampling time
shall be 10 minutes and the minimum
sampling volume 0.01 dscm (0.35 dscf)
for each sample. The arithmetic aver-
age of two samples of equal sampling
time shall constitute one run. Samples
shall be taken at approximately 1-
hour Intervals. For most fuel gases,
sample times exceeding 20 minutes
may result in depletion of the collect-
Ing solution, although fuel gases con-
taining low concentrations of hydro-
gen sulfide may necessitate sampling
for longer periods of time.86
(2) If Method 6 is used, Method 1
shall be used for velocity traverses and
Method 2 for determining velocity and
volumetric flow rate. The sampling
site for determining SOa concentration
by Method 6 shall be the same as for
determining volumetric flow rate by
Method 2. The sampling point in the
duct for determining SO, concentra-
tion by Method 6 shall be at the cen-
troid of the cross section if the cross
sectional area is less than 5 m! (54 f t')
or at a point no closer to the walls
than 1 m (39 inches) if the cross sec-
tional area is 5 m2 or more and the
centroid is more than one meter from
the wall. The sample shall be extract-
ed at a rate proportional to the gas ve-
locity at the sampling point. The mini-
mum sampling time shall be 10 min-
utes and the minimum sampling
volume 0.01 dscm (0.35 dscf) for each
sample. The arithmetic average of two
samples of equal sampling time shall
constitute one run. Samples shall be
taken at approximately 1-hour inter-
vals.86
(d) For the purpose of determining
compliance with §60.104(a)(2),
Method 6 shall be used to determine
the concentration of SO, and Method
15 shall be used to determine the con-
centration of HaS and reduced sulfur
compounds.86
(1) If Method 6 is used, the proce-
dure outlined in paragraph (c)(2) of
this section shall be followed except
that each run shall span a minimum
of four consecutive hours of continu-
ous sampling. A number of separate
samples may be taken for each run,
provided the total sampling time of
these samples adds up to a minimum
of four consecutive hours. Where more
than one sample is used, the average
SO, concentration for the run shall be
calculated as the time weighted aver-
age of the SO, concentration for each
sample according to the formula:
r VT
"~ '
Where:
CR = SO, concentration for the run.
N= Number of samples.
Cs, =SOj concentration for sample i.
fc, = Continuous sampling time of sample i.
T=Total continuous sampling time of all
TV samples.86
(2) If Method 15 is used, each run
shall consist of 16 samples taken over
a minimum of three hours. The sam-
pling point shall be at the centroid of
the cross section of the duct if the
cross sectional area is less than 5 m*
(54 ft2) or at a point no closer to the
walls than 1 m (39 inches) if the cross
sectional area is 5 m2 or more and the
centroid is more than 1 meter from
the wall. To insure minimum residence
time for the sample inside the sample
lines, the sampling rate shall be at
least 3 liters/minute (0.1 ft'/min). The
SOj equivalent for each run shall be
calculated as the arithmetic average of
the SO2 equivalent of each sample
during the run. Reference Method 4
shall be used to determine the mois-
ture content of the gases. The sam-
pling point for Method 4 shall be adja-
cent to the sampling point for Method
15. The sample shall be extracted at a
rate proportional to the gas velocity at
the sampling point. Each run shall
span a minimum of four consecutive
hours of continuous sampling. A
number of separate samples may be
taken for each run provided the total
sampling time of these samples adds
up to a minimum of four consecutive
hours. Where more than one sample is
used, the average moisture content for
the run shall be calculated as the time
weighted average of the moisture con-
tent of each sample according to the
formula:
B««=Proportion by volume of water vapor
in the gas stream for the run.
N=Number of samples.
B,, = Proportion by volume of water vapor
in the gas stream for the sample £
t,, =-= Continuous sampling time for sample
t.
T- Total continuous sampling time of all
N samples.
(Sec. 114 of the Clean Air Act, as amended
[42U.S.C. 7414]>.86
Proposed/effective
38 FR 15406, 6/11773
41 FR 43866, 10/4/76
Promulgated
39 FR 9308, 3/8/74 (5)
Revised
40 FR 46250,
42 FR 32426,
42 FR 37936,
42 FR 39389,
42 FR 41424,
43 FR 8800,
43 FR 10866,
44 FR 13480,
44 FR 61542,
10/6/75 (18)
6/24/77 (61)
7/25/77 (64)
8/4/77 (66)
8/17/77 (68)
3/3/78 (83)
3/15/78 (86)
3/12/79 (96)
10/25/79 (103)
111-35
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Subpart KStandards of Performance
for Storage Vessels for Petroleum
Liquids Constructed After June 11,
1973 and Prior to May 19,19781'1
160.110 Applicability and designation
of affected facility.64
(a) Except as provided in { 60.110(b>,
the affected facility to which this sub-
part applies is each storage vessel for
petroleum liquids which has a storage
capacity greater than 151,412 liters
(40,000 gallons).
(b) This subpart does not apply to
storage vessels for petroleum or conden-
sate stored, processed, and/or treated at
a drilling and production facility prior
to custody transfer.8
(c) Subject to the requirements of
this subpart is any facility under para-
graph (a) of this section which:
(1) Has a capacity greater than 151,
416 liters (40,000 gallons), but not
exceeding 246,052 liters (65,000 gallons),
and commences construction or
modification after March 8,1974, and
prior to May 19,1978.111
(2) Has a capacity greater than 246,052
liters (65,000 gallons) and commences
construction or modification after June
11,1973, and prior to May 19,1978.nl
§60.111 Definitions.
As used in this subpart, all terms not
defined herein shall have the meaning
given them in the Act and in Subpart A
of this part.
(a) "Storage vessel" means any tank,
reservoir, or container used for the
storage of petroleum liquids, but does
not include:
(1) Pressure vessels which are designed
to operate in excess of 15 pounds per
square inch gauge without emissions to
the atmosphere except under emergency
conditions,
(2) Subsurface caverns or porous, rock
reservoirs, or
(3) Underground tanks if the total
volume of petroleum liquids added to
and taken from a tank annually does
not exceed twice the volume of the tank.
(b) "Petroleum liquids" means
petroleum, condensate, and any finished
or intermediate products manufactured
in a petroleum refinery but does not
mean Nos. 2 through 6 fuel oils as
specified in ASTM-D-396-78, gas
turbine fuel oils Nos. 2-GT through 4-
GT as specified in ASTM-D-2880-78, or
diesel fuel oils Nos. 2-D and 4-D as
specified in ASTM-D-97578.'1'
(c) "Petroleum refinery" means each
facility engaged in producing gasoline,
kerosene, distillate fuel oils, residual
fuel oils, lubricants, or other products
through distillation of petroleum or
through redistillation, cracking,
extracting, or reforming of unfinished
petroleum derivatives.
(d) "Petroleum" means the crude oil
removed frooi the earth and the oils
derived from tar sands, shale, and coal.'
(e) "Hydrocarbon" means any organic
compound consisting predominantly of
carbon and hydrogen.6
(f) "Condensate" means hydrocarbon
liquid separated from natural gas which
condenses due to changes In the tem-
perature and/or pressure and remains
liquid at standard conditions.
(g) "Custody transfer" means the
transfer of produced petroleum and/or
condensate, after processing and/or
treating in the producing operations,
from storage tanks or automatic trans-
fer facilities to pipelines or any other
forms of transportation.8
(h) "Drilling and production fa.
-------
Subpart KaStandards of
Performance for Storage Vessels for
Petroleum Liquids Constructed After
May 18,1978
( 60.11 Oa Applicability and designation of
affected facility.
(a) Except as provided in paragraph
(b) of this section, the affected facility to
which this subpart applies is each
storage vessel for petroleum liquids
which has a storage capacity greater
than 151,416 liters (40,000 gallons) and
for which construction is commenced
after May 18,1978.
(b] Each petroleum liquid storage
vessel with a capacity of less than
1,589,873 liters (420,000 gallons) used for
petroleum or condensate stored,
processed, or treated prior to custody
transfer is not an affected facility and,
therefore, is exempt from the
requirements of this subpart
§ 60.111a Definitions.
In addition to the terms and their
definitions listed in the Act and Subpart
A of this part the following definitions
apply in this subpart:
(a) "Storage vessel" means each tank,
reservoir, or container used for the
storage of petroleum liquids, but does
not include:
(1) Pressure vessels which are
designed to operate in excess of 204.9
kPa (15 psig) without emissions to the
atmosphere except under emergency
conditions.
(2) Subsurface caverns or porous rock
reservoirs, or
(3) Underground tanks if the total
volume of petroleum liquids added to
and taken from a tank annually does not
exceed twice the volume of the tank.
(b) "Petroleum liquids" means
petroleum, condensate, and any finished
or intermediate products manufactured
in a petroleum refinery but does not
mean NOB. 2 through 6 fuel oils as
specified in ASTM-D-396-78, gas
turbine fuel oils Nos. 2-GT through 4~
GT as specified in ASTM-D-2880-78, or
diesel fuel oils Nos. 2-D and 4-D as
specified in ASTM-D-975-78.
(c) "Petroleum refinery" means each
facility engaged in producing gasoline,
kerosene, distillate fuel oils, residual
fuel oils, lubricants, or other products
through distillation of petroleum or
through redistillation, cracking,
extracting, or reforming of unfinished
petroleum derivatives.
(d) "Petroleum" means the crude oil
removed from the earth and the oils
derived from tar sands, shale, and coal.
(e) "Condensate" means hydrocarbon
liquid separated from natural gas which
condenses due to changes in the
temperature or pressure, or both, and
remains liquid at standard conditions.
(f) "True vapor pressure" means the
equilibrium partial pressure exerted by
a petroleum liquid such as determined in
accordance with methods described in
American Petroleum Institute Bulletin
2517, Evaporation Loss from Floating
Roof Tanks, 1962.
(g) "Reid vapor pressure" is the
absolute vapor pressure of volatile
crude oil and volatile non-viscous
petroleum liquids, except liquified
petroleum gases, as determined by
ASTM-D-323-58 (re approved 1968).
(h) "Liquid-mounted seal" means a
foam or liquid-filled primary seal
mounted in contact with the liquid
between the tank wall and the floating
roof continuously around the
circumference of the tank.
(i) "Metallic shoe seal" includes but is
not limited to a metal sheet held
vertically against the tank wall by
springs or weighted levers and is
connected by braces to the floating roof.
A flexible coated fabric (envelope)
spans the annular space between the
metal sheet and the floating roof.
(j) "Vapor-mounted seal" means a
foam-filled primary seal mounted
continuously around the circumference
of the tank so there is an annular vapor
space underneath the seal. The annular
vapor space is bounded by the bottom of
the primary seal, the tank wall, the
liquid surface, and the floating roof.
(k) "Custody transfer" means the
transfer of produced petroleum and/or
condensate, after processing and/or
treating in the producing operations,
from storage tanks or automatic transfer
facilities to pipelines or any other forms
of transportation.
§ 60.112a Standard for volatile organic
compounds (VOC).
(a) The owner or operator of each
storage vessel to which this subpart
applies which contains a petroleum
liquid which, as stored, has a true vapor
pressure equal to or greater than 10.3
kPa (1.5 psia) but not greater than 76.6
kPa (11.1 psia) shall equip the storage
vessel with one of the following:
(1) An external floating roof,
consisting of a pontoon-type or double-
deck-type cover that rests on the surface
of the liquid contents and is equipped
with a closure device between the tank
wall and the roof edge. Except as
provided in paragraph (a)(l)(ii)(D) of
this section, the closure device is to
consist of two seals, one above the
other. The lower seal is referred to as
the primary seal and the upper seal is
referred to as the secondary seal. The
roof is to be floating on the liquid at all
times (i.e., off the roof leg supports)
except during initial fill and when the
tank is completely emptied and
subsequently refilled. The process of
emptying and refilling when the roof is
resting on the leg supports shall be
continuous and shall be accomplished
as rapidly as possible.
(i) The primary seal is to be either a
metallic shoe seal, a liquid-mounted
seal, or a vapor-mounted seal. Each seal
is to meet the following requirements:
(A) The accumulated area of gaps
between the tank wall and the metallic
shoe seal or the liquid-mounted seal
shall not exceed 212 cm2 per meter of
tank diameter (10.0 in * per ft of tank
diameter) and the width of any portion
of any gap shall not exceed 3.81 cm (IVfe
in).
(B) The accumulated area of gaps
between the tank wall and the vapor-
mounted seal shall not exceed 21.2 cm*
per meter of tank diameter (1.0 in1 per ft
of tank diameter) and the width of any
portion of any gap shall not exceed 1.27
cm (V4 in).
(C) One end of the metallic shoe is to
extend into the stored liquid and the
other end is to extend a minimum
vertical distance of 61 cm (24 in) above
the stored liquid surface.
(D) There are to be no holes, tears, or
other openings in the shoe, seal fabric,
or seal envelope.
(ii) The secondary seal is to meet the
following requirements:
(A) The secondary seal is to be
Installed above the primary seal so that
it completely covers the space between
the roof edge and the tank wall except
as provided in paragraph (a)(l)(ii)(B) of
this section.
(B) The accumulated area of gaps
between the tank wall and the
secondary seal shall not exceed 21.2 cm*
per meter of tank diameter (1.0 in1 per ft
of tank diameter) and the width of any
portion of any gap shall not exceed 1.27
cm (Mi in).
(C) There are to be no holes, tears or
other openings in the seal or seal fabric.
(D) The owner or operator is
exempted from the requirements for
secondary seals and the secondary seal
gap criteria when performing gap
measurements or inspections of the
primary seal.
(iii) Each opening in the roof except
for automatic bleeder vents and rim
space vents is to provide a projection
below the liquid surface. Each opening
in the roof except for automatic bleeder
vents, rim space vents and leg sleeves is
to be equipped with a cover, seal or lid
which is to be maintained in a closed
position at all times (i.e., no visible gap)
except when the device is in actual use
or as described in pargraph (a)(l)(iv) of
this section. Automatic bleeder vents
111-37
-------
are to be closed at all times when the
roof is floating, except when the roof is
being floated off or is being landed on
the roof leg supports. Rim vents are to
be set to open when the roof is being
floated off the roof legs supports or at
the manufacturer's recommended
setting.
(iv) Each emergency roof drain is to
be provided with a slotted membrane
fabric cover that covers at least 90
percent of the area of the opening.
(2) A fixed roof with an internal
floating type cover equipped with a
continuous closure device between the
tank wall and the cover edge. The cover
is to be floating at all times, (i.e., off the
leg supports) except during initial fill
and when the tank is completely
emptied and subsequently refilled. The
process of emptying and refilling when
the cover is resting on the leg supports
shall be continuous and shall be
accomplished as rapidly as possible.
Each opening in the cover except for
automatic bleeder vents and the rim
space vents is to provide a projection
below the liquid surface. Each opening
in the cover except for automatic
bleeder vents, rim space vents, stub
drains and leg sleeves is to be equipped
with a cover, seal, or lid which is to be
maintained in a closed position at all
times (i.e., no visible gap) except when
the device is in actual use. Automatic
bleeder vents are to be closed at all
times when the cover is floating except
when the cover is being floated off or is
being landed on the leg supports. Rim
vents are to be set to open only when
the cover is being floated off the leg
supports or at the manufacturer's
recommended setting.
(3) A vapor recovery system which
collects all VOC vapors and gases
discharged from the storage vessel, and
a vapor return or disposal system which
is designed to process such VOC vapors
and gases so as to reduce their emission
to the atmosphere by at least 95 percent
by weight.
(4) A system equivalent to those
described in paragraphs (a)(l), (a)(2), or
(a)(3) of this section as provided in
S 60.114a.
(b) The owner or operator of each
storage vessel to which this subpart
applies which contains a petroleum
liquid which, as stored, has a true vapor
pressure greater than 76.6 kPa (11.1
psia), shall equip the storage vessel with
a vapor recovery system which collects
all VOC vapors and gases discharged
from the storage vessel, and a vapor
return or disposal system which is
designed to process such VOC vapors
and gases so as to reduce their emission
to the atmosphere by at least 95 percent
by weight.
§60.113a Testing and procedures.
(a) Except as provided in § 60.8(b)
compliance with the standard
prescribed in § 60.112a shall be
determined as follows or in accordance
with an equivalent procedure as
provided in § 60.114a.
(1) The owner or operator of each
storage vessel to which this subpart
applies which has an external floating
roof shall meet the following
requirements:
(i) Determine the gap areas and
maximum gap widths between the
primary seal and the tank wall, and the
secondary seal and the tank wall
according to the following frequency
and furnish the Administrator with a
written report of the results within 60
days of performance of gap
measurements:
(A) For primary seals, gap
measurements shall be performed within
60 days of the initial fill with petroleum
liquid and at least once every five years
thereafter. All primary seal inspections
or gap measurements which require the
removal or dislodging of the secondary
seal shall be accomplished as rapidly as
possible and the secondary seal shall be
replaced as soon as possible.
(B) For secondary seals, gap
measurements shall be performed within
60 days of the initial fill with petroleum
liquid and at least once every year
thereafter.
(C) If any storage vessel is out of
service for a period of one year or more,
subsequent refilling with petroleum
liquid shall be considered initial fill for
the purposes of paragraphs (a)(l)(i)(A)
and (a)(l)(i)((B) of this section.
(ii) Determine gap widths in the
primary and secondary seals
individually by the following
procedures:
(A) Measure seal gaps, if any, at one
or more floating roof levels when the
roof is floating off the roof leg supports.
(B) Measure seal gaps around the
entire circumference of the tank in each
place where a Vs" diameter uniform
probe passes freely (without forcing or
binding against seal) between the seal
and the tank wall and measure the
circumferential distance of each such
location.
(C) The total surface area of each gap
described in paragraph (a)(l)(ii)(B) of
this section shall be determined by using
probes of various widths to accurately
measure the actual distance from the
tank wall to the seal and multiplying
each such width by its respective
circumferential distance.
(iii) Add the gap surface area of each
gap location for the primary seal and the
secondary seal individually. Divide the
sum for each seal by the nominal
diameter of the tank and compare each
ratio to the appropriate ratio in the
standard in § 60.1l2a(a)(l)(i) and
(iv) Provide the Administrator 30 days
prior notice of the gap measurement to
afford the Administrator the opportunity
to have an observer present.
(2) The owner or operator of each
storage vessel to which this subpart
applies which has a vapor recovery and
return or disposal system shall provide
the following information to the
Administrator on or before the date on
which construction of the storage vessel
commences:
(i) Emission data, if available, for a
similar vapor recovery and return or
disposal system used on the same type
of storage vessel, which can be used to
determine the efficiency of the system.
A complete description of the emission
measurement method used must be
included.
(ii) The manufacturer's design
specifications and estimated emission
reduction capability of the system.
(iii) The operation and maintenance
plan for the system.
(iv) Any other information which will
be useful to the Administrator in
evaluating the effectiveness of the
system in reducing VOC emissions.
(Sec. 114, Clean Air Act as amended (42
U.S.C. 7414))
$ 60.1 14a Equivalent equipment and
procedures.
(a) Upon written application from an
owner or operator and after notice and
opportunity for public hearing, the
Administrator may approve the use of
equipment or procedures, or both, which
have been demonstrated to his
satisfaction to be equivalent in terms of
reduced VOC emissions to the
atmosphere to the degree prescribed for
compliance with a specific paragraph(s)
of this subpart.
(b) The owner or operator shall
provide the following information in the
application for determination of
equivalency:
(1) Emission data, if available, which
can be used to determine the
effectiveness of the equipment or
procedures in reducing VOC emissions
from the storage vessel. A complete
description of the emission
measurement method used must be
included.
(2) The manufacturer's design .
specifications and estimated emission
reduction capability of the equipment
(3) The operation and maintenance
plan for the equipment.
(4) Any other information which will
be useful to the Administrator in
evaluating the effectiveness of the
111-38
-------
equipment or procedures in reducing
VOC emissions.
(Sec. 114 of the Clean Air Act as amended (42
U.S.C, 7414))
§ 60.115a Monitoring of operations.
(a) Except as provided in paragraph
(d) of this section, the owner or operator
subject to this subpart shall maintain a
record of the petroleum liquid stored,
the period of storage, and the maximum
true vapor pressure of that liquid during
the respective storage period.
(b) Available data on the typical Reid
vapor pressure and the maximum
expected storage temperature of the
stored product may be used to
determine the maximum true vapor
pressure from nomographs contained in
API Bulletin 2517, unless the
Administrator specifically requests that
the liquid be sampled, the actual storage
temperature determined, and the Reid
vapor pressure determined from the
sample(s).
(c) The true vapor pressure of each
type of crude oil with a Reid vapor
pressure less than 13.8 kPa (2.0 psia) or
whose physical properties preclude
determination by the recommended
method is to be determined from
available data and recorded if the
estimated true vapor pressure is greater
than 6.9 kPa (1.0 psia).
(d) The following are exempt from the
requirements of this section:
(1) Each owner or operator of each
storage vessel storing a petroleum liquid
with a Reid vapor pressure of less than
6.9 kPa (1.0 psia) provided the maximum
true vapor pressure does not exceed 6.9
kPa (1.0 psia).
(2) Each owner or operator of each
storage vessel equipped with a vapor
recovery and return or disposal system
in accordance with the requirements of
51 60.112a(a)(3) and 60.112a(b).
(Sec. 114 of the Clean Air Act as amended (42
U.S.C. 7414))
Proposed/effecti ve
43 FR 21616, 5/18/78
Promulgated
45 FR 23374, 4/4/80 (111)
111-39
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Subpart LStandards of Performance
for Secondary Lead Smelters5
§6(1.12(1 Applicability and designation of
affected facilitj.64
(a) The provisions of this subpart
are applicable to the following affect-
ed facilities in secondary lead smelters.
Pot furnaces of more than 250 kg (550
Ib) charging capacity, blast (cupola)
furnaces, and reverberatory furnaces.
(b) Any facility under paragraph (a)
of this section that commences con-
struction or modification after June
11, 1973, is subject to the requirements
of this subpart.
§60.121 Definitions.
As used in this subpart. all terms not
defined herein shall have the meaning
given them in the Act and in Subpart
A of this part.
(a) "Reverberatory furnace" in-
cludes the following types of reverber-
atory furnaces: stationary, rotating.
rocking, and tilting.
(b) "Secondary lead smelter" means
any facility producing lead from a
leadbearing scrap material by smelting
to the metallic form.
(c) "Lead" means elemental lead or
alloys in which the predominant com-
ponent is lead.6
§60.123 Test methods and procedures.
(a) The reference methods appended
to this part, except as provided for in
§ 60.8 (b), shall be used to determine
compliance with the standards pre-
scribed in § 60.122 as follows:
(1) Method 5 for the concentration
of particulate matter and the associat-
ed moisture content,
(2) Method 1 for sample and velocity
traverses.
(3) Method 2 for velocity and volu-
metric flow rate, and
(4) Method 3 for gas analysis.
(b) For method 5, the sampling time
for each run shall be at least 60 min-
utes and the sampling rate shall be at
least 0.9 dscm/hr (0.53 dscf/min)
except that shorter sampling times,
when necesitated by process variables
or other factors, may be approved by
the Administrator. Particulate sam-
pling shall be conducted during repre-
sentative periods of furnace operation,
including charging and tapping.
(Sec. 114, Clean Air Act as amended (42
U.S.C. 7414))68.83
§ 60.122 Standard for particulate matter.
(a) On and after the date on which
the performance test required to be
conducted by § 60.8 is completed, no
owner or operator subject to the provi-
sions of this subpart shall discharge or
cause the discharge into the atmos-
phere from a blast (cupola) or rever-
beratory furnace any gases which:
(1) Contain particulate matter in
excess of 50 mg/dscm (0.022 gr/dscf).
(2) Exhibit 20 percent opacity or
greater.
(b) On and after the date on which
the performance test required to be
conducted by § 60.8 is completed, no
owner or operator subject to the provi-
sions of this subpart shall discharge or
cause the discharge into the atmos-
phere from any pot furnace any gases
which exhibit 10 percent opacity or
greater.
18
Proposed/effective
38 FR 15406, 6/11/73
Promulgated
39 FR 9308, 3/8/74 (5)
Revised
39 FR 13776
40 FR 46250
42 FR 37936
(6)
4/17/74
10/6/75 (18)
7/25/77 (64)
42 FR 41424, 8/17/77 (68)
43 FR 8800, 3/3/78 (83)
111-40
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Subpart MStandards of Perform-
ance for Secondary Brass and
Bronze Ingot Production Plants5
§ 60.130 Applicability and designation of
affected facility.64
(a) The provisions of this subpart
are applicable to the following affect-
ed facilities in secondary brass or
bronze ingot production plants: Rever-
beratory and electric furnaces of 1,000
kg (2,205 Ib) or greater production ca-
pacity and blast (cupola) furnaces of
250 kg/hr (550 Ib/hr) or greater pro-
duction capacity.
(b) Any facility under paragraph (a)
of this section that commences con-
struction or modification after June
11, 1973, is subject to the requirements
of this subpartr.
§ 60.131 Definitions.
As used in this subpart, all terms not
defined herein shall have the meaning
given them in the Act and in Subpart
A of this part.
(a) "Brass or bronze" means any
metal alloy containing copper as its
predominant constituent, and lesser
amounts of zinc, tin, lead, or other
metals.
(b) "Reverberatory furnace" in-
cludes the following types of reverber-
atory furnaces: Stationary, rotating,
rocking, and tilting.
(c) "Electric furnace" means any
furnace which uses electricity to pro-
duce over 50 percent of the heat re-
quired in the production of refined
brass or bronze.
(d) "Blast furnace" means any fur-
nace used to recover metal from slag
§ 60.133 Test methods and procedures.
(a) The reference methods appended
to this part, except as provided for in
§ 60.8(b), shall be used to determine
compliance with the standards pre-
scribed in § 60.132 as follows:
(1) Method 5 for the concentration
of particulate matter and the associat-
ed moisture content.
(2) Method 1 for sample and velocity
traverses,
(3) Method 2 for velocity and volu-
metric flow rate, and
(4) Method 3 for gas analysis.
(b) For Method 5, the sampling time
for each run shall be at least 120 min-
utes and the sampling rate shall be at
least 0.9 dscm/hr (0.53 dscf/min)
except that shorter sampling times,
when necessitated by process variables
or other factors, may be approved by
the Administrator. Particulate matter
sampling shall be conducted during
representative periods of charging and
refining, but not during pouring of the
heat.
(Sec. 114. Clean Air Act as amended (42
U S.C 7414))68'83
§60.132 Standard for particulate matter.
(a) On and after the date on which
the performance test required to be
conducted by § 60.8 is completed, no
owner or operator subject to the provi-
sions of this subpart shall discharge or
cause the discharge into the atmos-
phere from a reverberatory furnace
any gases which:
(1) Contain particulate matter in
excess of 50 mg/dscm (0.022 gr/dscf).
(2) Exhibit 20 percent opacity or
greater.
(b) On and after the date on which
the performance test required to be
conducted by § 60.8 is completed, no
owner or operator subject to the provi-
sions of this subpart shall discharge or
cause the discharge into the atmos-
phere from any blast (cupola) or elec-
tric furnace any gases which exhibit
10 percent opacity or greater.18
Proposed/effective
38 FR 15406, 6/11/73
Promulgated
39 FR 9308, 3/8/74 (5)
Revised
4~OTR~46250, 10/6/75 (18)
42 FR 37936, 7/25/77 (64)
42 FR 41424, 8/17/77 (68)
43 FR 8800, 3/3/78 (S3)
111-41
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Subpart NStandards of Performance for
Iron and Steel Plant* 5
§60.140 Applicability and designation
of affected facility. 6 4
(a) The affected facility to which the
provisions of this subpart apply is each
basic oxygen process furnace.
(b) Any facility under paragraph (a)
of this section that commences construc-
tion or modification after June 11, 1973,
is subject to the requirements of this
subpart.
§ 60.141 Definitions.
As used in this subpart, all terms not
defined herein shall have the meaning
given them in the Act and in subpart A
of this part.
(a) "Basic oxygen process furnace"
(BOPP) means any furnace producing
steel by charging scrap steel, hot metal,
and flux materials into a vessel arid in-
troducing a high volume of an oxygen-
rich gas.
(b) "Steel production cycle" means
the operations required to produce each
batch of steel and includes the following
majo^ functions: Scrap charging, pre-
heating (when used), hot metal charg-
ing, primary oxygen blowing, additional
oxygen blowing (when used), and tap-
ping.
(c) "Startup means the setting into
operation for the first steel production
cycle of a rellned BOPF or a BOPF
which has been out of production for a
minimum continuous time period of
eight hours.88
§ 60.142 Standard for paniculate mat-
ter.
(a) On and after the date on which
the performance test required to be con-
ducted by S 60.8 is completed, no owner
or operator subject to the provisions of
this subpart shall discharge or cause
the discharge into the atmosphere from
any affected facility any gases which:
(1) Contain participate matter in ex-
cess of 50 mg/dscm (0.022 gr/dscf).
(2) Exit from a control device and
exhibit 10 percent opacity or greater,
except that an opacity of greater than
10 percent but less than 20 percent
jnay occur once per steel production
cycle.88
{ 60.143 Monitoring of operations.8"
(a) The owner or operator of an af-
fected facility shall maintain a single
time-measuring instrument which
shall be used in recording daily the
time and duration of each steel pro-
duction cycle, and the time and dura-
tion of any diversion of exhaust gases
from the main stack servicing the
BOPF.
(b) The owner or operator of any af-
fected facility that uses venturi scrub-
ber emission control equipment shall
install, calibrate, maintain, and con-
tinuously operate monitoring devices
as follows:
(DA monitoring device for the con-
tinuous measurement of the pressure
loss through the venturi constriction
of the control equipment. The moni-
toring device is to be certified by the
manufacturer to be accurate within
±250 Pa (±1 inch water).
(2) A monitoring device for the con-
tinous measurement of the water
upply pressure to the control equip-
ment. The monitoring device Is to be
certified by the manufacturer to be ac-
curate within ±5 percent of the design
water supply pressure. The monitoring
device's pressure sensor or pressure
tap must be located close to the water
discharge point. The Administrator
may be consulted for approval of alter-
native locations for the pressure
tensor or tap.
(3) All monitoring devices shall be
synchronized each day with the time-
measuring instrument used under
paragraph (a) of this section. The
chart recorder error directly after syn-
chronization shall not exceed 0.08 cm
(Vtt inch).
(4) All monitoring devices shall use
chart recorders which are operated at
a minimum chart speed of 3.8 cm/to
(1.5 in/hr).
(5) All monitoring devices are to be
recalibreated annually, and at other
times as the Administrator may re-
quire, in accordance with the proce-
duces under J 60.13(bX3).
(c) Any owner or operator subject to
requirements under paragraph (b) of
this section shall report for each cal-
endar quarter all measurements over
any three-hour period that average
more than 10 percent below the aver-
age levels maintained during the most
recent performance test conducted
under § 60.8 hi which the affected fa-
cility demonstrated compliance with
the standard under §60.142(a)(l). The
accuracy of the respective measure-
ments, not to exceed the values speci-
fied in paragraphs (b)U) and (b)(2) of
this section, may be taken into consid-
eration when determining the mea-
surement results that must be report-
ed.
§ 60.144 Test methods and procedures.
(a) The reference methods appended
to this part, except as provided for in
§60.8(b), shall be used to determine
compliance with the standards prescribed
in I 60.142 as follows:
(1) Method 5 for concentration of
particulate matter and associated mois-
ture content,
(2) Method 1 for sample and velocity
traverses,
(3) Method 2 for volumetric flow rate,
and
(4) Method 3 for gas analysis.
(5) Method 9 for visible emissions.
For the purpose of this subpart, opac-
ity observations taken at 15-second in-
tervals immediately before and after a
diversion of exhaust gases from the
tack may be considered to be consecu-
tive for the purpose of computing an
average opacity for a six-minute
period. Observations taken during a di-
version shall not be used in determin-
ing compliance with the opacity stan-
dard,88
(b) For Method 5, the sampling for
each run shall continue for an integral
number of cycles with total duration of
at least 60 minutes. The sampling rate
shall be at least 0.9 dscm/hr (0.53 dscf/
min) except that shorter sampling times,
(c) Sampling of flue gases during
each steel production cycle shall be
discontinued whenever all flue gases
are diverted from the stack and shall
be resumed after each diversion
period.88
(See. 114. Clean Air Act to amended (42
U.S.C. 7414)). OS. 83
Proposed/effectl ye
15406, 6/11/73
opos
FR
Promulgated
39 FR 9308, 3/8/74 (5)
Revised
42 FR 37936, 7/25/77 (64)
42 FR 41424, 8/17/77 (68)
43 FR 8800, 3/3/78 (83)
43 FR 15600, 4/13/78 (88)
111-42
-------
Subpart OStandards of Performance for
Sewage Treatment Plants 5
160.150 Applicability and designation
of affected facility.lS
Ca) The affected facility Is each In-
cinerator that combusts wastes contain-
ing more than 10 percent sewage sludge
(dry basis) produced by municipal sew-
age treatment plants, or each incinerator
that charges more than 1000 kg (2205
Ib) per day municipal sewage sludge (dry
basis).
Xb) Any facility under paragraph (a)
of this section that commences construc-
tion or modification after June 11, 1973,
is subject to the requirements of this
ubpart.
160.151 Definition*.
As used in this subpart. all terms not
defined herein shall have the meaning
given them in the Act and in subpart A
of this part.
| 60.152
ter.
Standard for paniculate mat-
te) On and after the date on which the
performance test required to be con-
ducted by § 60.8 is completed, no owner
or operator of any sewage sludge incin-
erator subject to the provisions of this
subpart shall discharge or cause the dis-
charge into the atmosphere of:
(1) Paxticulate matter at a rate In ex-
cess of 0.65 g/kg dry sludge input (1.30
Ib/ton dry sludge input).
(2) Any gases which exihibit 20 per-
cent opacity or greater. 18
| 60.153 Monitoring of operations/5
(a) The owner or operator of any
sludge incinerator subject to the provi-
sions of this subpart shall:
(1) Install, calibrate, maintain, and
operate a flow measuring device which
can be used to determine either the mass
or volume of sludge charged to the In-
cinerator. The flow measuring device
shall have 'an accuracy of ±5 percent
over its operating range.
(2) Provide access to the sludge
charged so that a well mixed representa-
tive grab sample of the sludge can be ob-
tained.
(3) Install, calibrate, maintain, and
operate a weighing device for determin-
ing the mass of any municipal solid
waste charged to the incinerator when
sewage sludge and municipal solid waste
are incinerated together. The weighing
device shall have an accuracy of ±5 per-
cent over its operating range.
(flee. 114. Clean Air Act to amended (43
U.S.C. 7414)).6883
§ 60.154 Test Method* and Procedures.
(a) The reference methods appended
to this part, except as provided for in
I 60.8(b), shall be used to determine
compliance with the standards pre-
scribed In i 60.152 as follows:
(1) Method 5 for concentration of
particulate matter and associated mois-
ture content,
(2) Method 1 for sample and velocity
traverses,
(3) Method 2 for volumetric flow rate,
and
(4) Method 3 for gas analysis.
(b) For Method 5, the sampling time
for each run shall be at least 60 min-
utes and the sampling rate shall be at
least 0.015 dscm/min (0.53 dscf/mm),
except that shorter sampling times,
when necessitated by process variables
or other factors, may be approved by the
Administrator.
(c) Dry sludge charging rate shall be
determined as follows:
(1) Determine the mass (SH) or vol-
ume (Si) of sludge charged to the in-
cinerator during each run using a flow
measuring device meeting the require-
ments of 560.153(a)(l). If total input
during a run is measured by a flow meas-
uring device, such readings shall be used.
Otherwise, record the flow measuring de-
vice readings at 5-minute intervals dur-
ing a run. Determine the quantity
charged during each interval by averag-
ing the flow rates at the beginning and
end of the interval and then multiplying
the average for each interval by the time
for each interval. Then add the quantity
for each interval to determine the total
quantity charged during the entire run,
(SM) or (Sv).
(2) Collect samples of the sludge
charged to the incinerator in non-porous
collecting Jars at the beginning of each
run and at approximately 1-hour in-
tervals thereafter until the test ends, and
determine for each sample the dry sludge
content (total solids residue) In accord-
ance with "224 O. Method for Solid and
Semisolid Samples," Standard Methods
for the Examination of Water and
Wastewater, Thirteenth Edition, Ameri-
can Public Health Association, Inc., New
York, N.Y., 1971, pp. 539-41, except that:
(1) Evaporating dishes shall be ignited
to at least 103°C rather than the 550°C
specified in step 3(a) (1).
(11) Determination of volatile residue,
step 3(b) may be deleted.
(ill) The quantity of dry sludge per
unit sludge charged shall be determined
in terms of either R,,, (metric units: mg
dry sludge/liter sludge charged or Eng-
lish units: lb/ft') or RI.M (metric units:
mg dry sludge/mg sludge charged or
English units: Ib/lb).
(3) Determine the quantity of dry
sludge per unit sludge charged In terms
of either Rnv or Ri,M.
(i) If the volume of sludge charged is
used:
8D-(60X10->) RpJ[Sv (Metric Units)
SD = (8.021) ~S? (English Units)
where:
So^average dry sludge charging rate during the run, kg/hr (English units: Ib/hr).
RDv=average quantity of dry sludge per unit volume of sludge charged to the incinerator, mg/1 (English
units: lb/ttl).
8v=sludge charged to the incinerator during the run, m> (English units: gal).
T=duration of run, rain (English units: min).
JOX10-I="metric units conversion factor, l-kg-min/m«-mg-hr.
8.021 - English units conversion factor, it'-min/gal-hr. °
(it) If the mass of sludge charged Is used:
8o-(«0) ft0"8" (Metric or English Units)
where:
BD=average dry sludge charging rate during the run, kg/hr (English units: Ib/hr).
RDM=average ratio of quantity of dry sludge to quantity of sludge charged to the incinerator, mg/mg (English
units- Ib/lb).
Sn=sludge charged during the run, kg (English units: Ib).
T=duration of run, min (Metric or English units). 6
60=conversion factor, min/hr (Metric or English units).
(d) Particulate emission rate shall be determined by:
C..-C.Q. (Metric or English Units)
where.
C.w=parttculate matter mass emissions, mg/hr 'English units: Ib/hr). 7
Ciparticulate matter concentration, mg/m' (English units: Ib/dscf).
Q,=volumetric stack gas flow rate, dscm/hr (English units: dscf/hr). Q, and d sball be determined using Methods
2 and 5, respectively.
(e) Compliance with 8 60.152(a) shall be determined as follows:
Cj.-(10-")~ (Metric Units)
SSD
or
Cd.= (2000)~= (English Units)
DD
where:
Cdi"" particulate emission discharge, g/kg dry sludge (English units: Ib/ton dry sludge).
lO-'-Metric conversion factor, g/mg.
1000- English conversion factor, Ib/ton.
(Sec. 114. Clean Air Act U amended (43
U.S.C. 7414)).68'83
Proposed/effective
38 FR 15406, 6/11/73
Promulgated
39 FR 9308, 3/8/74 (5)
111-43
Revised
39 FR 13776, 4/17/74 (6)
39 FR 15396, 5/3/74 (7)
40 FR 46250, 10/6/75 (18)
42 FR 37936, 7/25/77 (64)
42 FR 41424, 8/17/77 (68)
42 FR 58520, 11/10/77 (75)
43 FR 8800, 3/3/78 (83)
-------
Subpart PStandards of Performance for
Primary Copper Smelters 26
§ 60.160 Applicability and designation
of affected facility. 64
(a) The provisions of this subpart are
aplicable to the following affected facili-
ties in primary copper smelters: dryer,
roaster, smelting furnace, and copper
converter.
(b) Any facility under paragraph (a)
of this section that commences construc-
tion or modification after October 16,
1974, is subject to the requirements of
this subpart.
§60.161 Definition*.
As used in this subpart, all terms not
defined herein shall have the meaning
given them in the Act and in subpart
A of this part.
(a) "Primary copper smelter" means
any installation or any intermediate
process engaged in the production of
copper from copper sulfide ore concen-
trates through the use of pyrometallurgl-
cal techniques.
(b) "Dryer" means any facility In
which a copper Bulfide ore concentrate
charge is heated in the presence of air
to eliminate a portion of the moisture
from the charge, provided less than 5
percent of the sulfur contained in the
charge is eliminated in the facility.
(c) "Roaster" means any facility in
which a copper sulfide ore concentrate
charge is heated in the presence of air
to eliminate a significant portion (5 per-
cent or more) of the sulfur contained
in the charge.
(d) "Calcine" means the solid mate-
rials produced by a roaster.
(e) "Smelting" means processing
techniques for the melting of a copper
sulfide ore concentrate or calcine charge
leading to the formation of separate lay-
ers of molten slag, molten copper, and/or
copper matte.
(f) "Smelting furnace" means any
vessel in which the smelting of copper
sulfide ore concentrates or calcines is
performed and hi which the heat neces-
sary for smelting is provided by an elec-
tric current, rapid oxidation of a portion
of the sulfur contained in the concen-
trate as It passes through an oxidizing
atmosphere, or the combustion of a fossil
fuel.
(g) "Copper converter" means any
vessel to which copper matte is charged
and oxidized to copper.
(h) "Sulfurlc acid plant" means any
facility producing sulfuric acid by the
contact process.
(1) "Fossil fuel" means natural gas,
petroleum, coal, and any form of solid,
liquid, or gaseous fuel derived from such
materials for the purpose of creating
useful heat.
(j) "Reverberatory smelting furnace"
means any vessel in which the smelting
of copper sulfide ore concentrates or cal-
cines Is performed and in which the heat
necessary for smelting Is provided pri-
marily by combustion of a fossil fuel.
(k) "Total smelter charge" means the
weight (dry basis) of all copper sulfides
ore concentrates processed at a primary
copper smelter, plus the weight of all
other solid materials Introduced into the
roasters and smelting furnaces at a pri-
mary copper smelter, except calcine, over
a one-month period.
(1) "High level of volatile impurities"
means a total smelter charge containing
more than 0.2 weight percent arsenic, 0.1
weight percent antimony, 4.5 weight per-
cent lead or 5.5 weight percent zinc, on
a dry basis.
§ 60.162 Slundiird for parliciilalr ninl-
tcr.
(a) On and after the date on which
the performance test required to be con-
ducted by § 60.8 is completed, no owner
or operator subject to the provisions of
this subpart shall cause to be discharged
into the atmosphere from any dryer any
gases which contain particulate matter
In excess of 50 mg/dscm (0.022 gr/dscf).
§ 60.163 Standard for sulfur dioxide.
(b) On and after the date on which
the performance test required to be con-
ducted by { 60.8 is completed, no owner
or operator subject to the provisions
of this subpart shall cause to be dis-
charged Into the atmosphere from any
roaster, smelting furnace, or copper con-
verter any gases which contain sulfur
dioxide in excess of 0.065 percent by
volume, except as provided in para-
graphs (b) and (c) of this section.
(b) Reverberatory smelting furnaces
shall be exempted from paragraph (a)
of this section during periods when the
total smelter charge at the primary cop-
per smelter contains a high level of
volatile impurities.
(c) A change in the fuel combusted
in a reverberatory furnace shall not be
considered a modification under this
part.
§ 60.164 Standard for visible cmUsions.
(a) On and after the date on which
the performance test required to be con-
ducted by § 60.8 is completed, no owner
or operator subject to the provisions of
this subpart shall cause to be discharged
into the atmosphere from any dryer any
visible emissions which exhibit greater
than 20 percent opacity.
(b) On and after the date on which
the performance test required to be con-
ducted by § 60.8 is completed, no owner
or operator subject to the provisions of
this subpart shall cause to be discharged
into the atmosphere from any affected
facility that uses a sulfuric acid to com-
ply with the standard set forth in
5 60.163, any visible emissions which ex-
hibit greater than 20 percent opacity.
§ 60.165 Monitoring of operations.
(a) The owner or operator of any pri-
mary copper smelter subject to { 60.163
(b) shall keep a monthly record of the
total .smelter charge and the weight per-
cent (dry basis) of arsenic, antimony,
lead and zinc contained In this charge.
The analytical methods and procedures
employed to determine the weight of the
total . smelter charge and the weight
percent of arsenic, antimony, lead and
zinc shall be approved by the Adminis-
trator and shall be accurate to within
plus or minus ten percent. 30
(b) The owner or operator of any pri-
mary copper smelter subject to the pro-
visions of this subpart shall install and
operate:
(1) A continuous monitoring system
to monitor and record the opacity of
gases discharged into the atmosphere
from any dryer. The span of this system
shall be set at 80 to 100 percent opacity.
(2) A continuous monitoring system
to monitor and record sulfur dioxide
emissions discharged Into the atmos-
phere from any roaster, smelting furnace
or copper converter subject to § 60.163
(a). The span of this system shall be
set at a sulfur dioxide concentration of
0.20 percent by volume.
(i) The continuous monitoring system
performance evaluation required under
{ 60.13 (c) shall be completed prior to the
initial performance test required under
5 60.8. During the performance evalua-
tion, the span of the continuous moni-
toring system may be set at a sulfur
dioxide concentration of 0.15 percent by
volume if necessary to maintain the sys-
tem output between 20 percent and 90
percent of full scale. Upon completion
of the continuous monitoring system
performance evaluation, the span of the
continuous monitoring system shall be
set at a sulfur dioxide concentration of
0.20 percent by volume.
(ii) For the purpose of the continuous
monitoring system performance evalua-
tion required under § 60.13(c) the ref-
erence method referred' to under the
Field Test for Accuracy (Relative) in
Performance Specification 2 of Appendix
B to this part shall be Reference Method
6. For the performance evaluation, each
concentration measurement shall be of
one hour duration. The pollutant gas
used to prepare the calibration gas mix-
tures required under paragraph 2.1, Per-
formance Specification 2 of Appendix 3,
and for calibration checks under § 60.13
(d), shall be sulfur dioxide.
(c) Six-hour average sulfur dioxide
concentrations shall be calculated and
recorded daily for the four consecutive 6-
hour periods of each operating day. Each
six-hour average shall be determined as
the arithmetic mean of the appropriate
six contiguous one-hour average sulfur
dioxide concentrations provided by the
continuous monitoring system installed
under paragraph (b) of this section.
(d) For the purpose of reports required
under |60.7(c>, periods of excess emis-.
sions that shall be reported are defined
as follows:
(1) Opacity. Any six-minute period
during which the average opacity, as
measured by the continuous monitoring
111-44
-------
system installed under paragraph (b) of
this section, exceeds the standard under
5 60.164(a).
(2) Sulfur dioxide. All six-hour periods
during which the average emissions of
sulfur dioxide, as measured by the con-
tinuous monitoring system installed
under § 60.163, exceed the level of the
standard. The Administrator will not
consider emissions in excess of the level
of the standard for less than or equal to
1.5 percent of the six-hour periods dur-
ing the quarter as indicative of a poten-
tial violation of § 60.1 l(d) provided the
affected facility, including air pollution
control equipment, is maintained and
operated in a manner consistent with
good air pollution control practice for
minimizing emissions during these pe-
riods. Emissions in excess of the level of
the standard during periods of startup,
shutdown, and malfunction are not to be
included within the 1.5 percent74
(Sec. 114, Clean Air Act It amended (42
U.B.C. 7414)). 68 83
§ 60.166 Test methods and procedures.
(a) The reference methods in Ap-
pendix A to this part, except as provided
for in § 60.8(b), shall be used to deter-
mine compliance with the standards
prescribed in §§60.162, 60.163 and
60.164 as follows:
(1) Method 5 for the concentration of
particulate matter and the associated
moisture content.
(2) Sulfur dioxide concentrations shall
be determined using the continuous
monitoring system installed in accord-
ance with § 60.165(b). One 6-hour aver-
age period shall constitute one run. The
monitoring system drift during any run
shall not exceed 2 percent of span.
(b) For Method 5, Method 1 shall be
used for selecting the sampling site and
the number of traverse points, Method 2
for determining velocity and volumetric
flow rate and Method 3 for determining
the gas analysis. The sampling time for
each run shall be at least 60 minutes and
the minimum sampling volume shall be
0 85 dscm (30 dscf) except that smaller
times or volumes, when necessitated by
process variables or other factors, may
be approved by the Administrator
(Sec. 114. Clean Air Act
U.S.C. 7414)). 68 83
amended (42
Proposed/effective
39 FR 37040, 10/16/74
Promulgated
41 FR 2331, 1/15/76 (26)
Revised
4TTfT8346, 2/26/76 (30)
42 FR 37936, 7/25/77 (64)
42 FR 41424, 8/17/77 (68)
42 FR 57126, 11/1/77 (74)
43 FR 8800, 3/3/78 (83)
111-45
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Subpart QStandards of Performance for
Primary Zinc Smelters 26
§ 60.170 Applicability and designation
of affected facility.64
(a) The provisions of this subpart are
applicable to the following affected facili-
ties in primary zinc smelters: roaster and
sintering machine.
(b) Any facility under paragraph (a)
of this section that commences construc-
tion or modification after October 16,
1974, Is subject to the requirements of
this subpart.
§ 60.171 Definitions.
As used in this subpart, all terms not
defined herein shall have the meaning
given them in the Act and in subpart A
of this part.
(a) "Primary zinc smelter" means any
installation engaged in the production, or
any intermediate process in the produc-
tion, of zinc or zinc oxide from zinc sul-
fide ore concentrates through the use
of pyrometallurglcal techniques.
(b) "Roaster" means any facility in
which a zinc sulflde ore concentrate
charge is heated in the presence of air
to eliminate a significant portion (more
than 10 percent) of the sulfur contained
in the charge.
(c) "Sintering machine" means any
furnace in which calcines are heated in
the presence of air to agglomerate the
calcines into a hard porous mass called
"sinter."
(d) "Sulfuric acid plant" means any
facility producing sulfuric acid by the
contact process.
§ 60.172 Standard for paniculate mat-
ter.
(a) On and after the date on which
the performance test required to be con-
ducted by ! 60.8 is completed, no owner
or operator subject to the provisions of
this subpart shall cause to be discharged
into the atmosphere from any sintering
machine any gases which contain par-
ticulate matter in excess of 50 mg/dscm
(0.022 gr/dscf).
| 60.173 Standard for sulfur dioxide.
(a) On and after the date on whjch
the performance test required to be con-
ducted by § 60.8 is completed, no owner
or operator subject to the provisions of
tills subpart shall cause to be discharged
into the atmosphere from any roaster
any gases which contain sulfur dioxide in
excess of 0.065 percent by volume.
(b) Any sintering machine which
eliminates more than 10 percent of the
sulfur initially contained in the zinc
sulnde ore concentrates will be consid-
ered as a roaster under paragraph (a)
of this section.
| 60.174 Standard for visible emissions.
(a) On and after the date on which the
performance test required to be con-
ducted by S 60.8 is completed, no owner
or operator subject to the provisions of
this subpart shall cause to be discharged
into the atmosphere from any sintering
machine any visible emissions which ex-
hibit greater than 20 percent opacity.
(b) On and after the date on which
the performance test required to be con-
ducted by {60.8 is completed, no owner
or operator subject to the provisions of
this subpart shall cause to be discharged
Into the atmosphere from any affected
facility that uses a sulfuric acid plant to
comply with the standard set forth In
I 60.173, any visible emissions which ex-
hibit greater than 20 percent opacity.
§ 60.175 Monitoring of operations.
(a) The owner or operator of any pri-
mary zinc smelter subject to the provi-
sions of this subpart shall install and
operate:
(1) A continuous monitoring system to
monitor and record the opacity of gases
discharged into the atmosphere from any
sintering machine. The span of this sys-
tem shall be set at 80 to 100 percent
opacity.
(2) A continuous monitoring system to
monitor and record sulfur dioxide emis-
sions discharged into the atmosphere
from any roaster subject to { 60.173. The
span of this system shall be set at a
sulfur dioxide concentration of 0.20 per-
cent by volume.
(1) The continuous monitoring system
performance evaluation required under
5 60.13(c) shall be completed prior to the
initial performance test required under
{60.8. During the performance evalua-
tion, the span of the continuous monitor-
ing system may be set at a sulfur dioxide
concentration of 0.15 percent by volume
if necessary to maintain the system out-
put between 20 percent and 90 percent
of full scale. Upon completion of the con-
tinuous monitoring system performance
evaluation, the span of the continuous
monitoring system shall be set at a sulfur
dioxide concentration of 0.20 percent by
volume.
(ii) For the purpose of the continuous
monitoring system performance evalua-
tion required under { 60.13(c), the ref-
erence method referred to under the
Field Test for Accuracy (Relative) In
Performance Specification 2 of Appendix
B to this part shall be Reference Method
6. For the performance evaluation, each
concentration measurement shall be of
one hour duration. The pollutant gas
used to prepare the calibration gas mix-
tures required under paragraph 2.1, Per-
formance Specification 2 of Appendix B,
and for calibration checks under i 60.13
(d), shall be sulfur dioxide.
(b) Two-hour average sulfur dioxide
concentrations shall be calculated and
recorded dally for the twelve consecutive
2-hour periods of each operating day.
Each' two-hour average shall be deter-
mined as the arithmetic mean of the ap-
propriate two contiguous one-hour aver-
age sulfur dioxide concentrations pro-
vided by the continuous monitoring sys-
tem installed under paragraph (a) of
this section.
(c) For the purpose of reports required
under § 60.7(c), periods of excess emis-
sions that shall be reported are denned
as follows:
(1) Opacity. Any six-minute period
during which the average opacity, as
measured by the continuous monitoring
system Installed under paragraph (a) of
this section, exceeds the standard under
i 60.174(a).
(2) Sulfur dioxide. Any two-hour pe-
riod, as described in paragraph (b) of
this section, during which the average
emissions of sulfur dioxide, as measured
by the continuous monitoring system in-
stalled under paragraph (a) of this sec-
tion, exceeds the standard under ( 60.173.
(Sec. 114. Clean Air Act is amended (43
U.S.C. 7414)). 68, 83
§ 60.176 Test methods and procedures,
(a) The reference methods in Appen-
dix A to this part, except as provided for
in § 60.8(b), shall be used to determine
compliance with the standards pre-
scribed in §§ 60.172, 60.173 and 60.174 as
follows:
(1) Method 5 for the concentration of
particulate matter and the associated
moisture content.
(2) Sulfur dioxide concentrations shall
be determined using the continuous
monitoring system installed In accord-
ance with $ 60.175(a). One 2-hour aver-
age period shall constitute one run.
(b) For Method 5, Method 1 shall be
used for selecting the sampling site and
the number of traverse points, Method 2
for determining velocity and volumetric
flow rate and Method 3 for determining
the gas analysis. The sampling time for
each run shall be at least 60 minutes and
the minimum sampling volume shall be
0.85 dscm (30 dscf) except that smaller
times or volumes, when necessitated by
process variables or other factors, may be
approved by the Administrator.
(Sec. 114. Clean Air Act is amended (42
U.S.C. 74it».*8 83
Proposed/effective
39 FR 37040, 10/16/74
Promulgated
41 FR 2331, 1/15/76 (26)
Revised
42 FR 37936, 7/25/77 (64)
42 FR 41424, 8/17/77 (68)
43 FR 8800, 3/3/78 (83)
111-46
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Sufapart RStandards of Performance for
Primary Lead Smtftwx 2*
160.180 Applicability Mid designation
of affected facility.**
(a) The provisions of this subpart are
applicable to the following affected
facilities In primary lead smelters: sin-
tering machine, sintering machine dis-
charge end. blast furnace, dross rever-
beratory furnace, electric smelting fur-
nace, and converter.
(b) Any facility under paragraph (a)
of this section that commences con-
struction or modification after October
16, 1974, is subject to the requirements
of this iubpart.
160.lt! Definition..
As used In this subpart, all terms not
defined herein shall have the meaning
given them in the Act and In subpart A
of this part.
(a) "Primary lead smelter" means any
Installation or any intermediate process
engaged In the production of lead from
lead sulfide ore concentrates through
Hie use of pyrometallurgical techniques.
(b) "Sintering machine" means any
furnace in which a lead sulflde ore con-
centrate charge is heated in the presence
of air to eliminate sulfur contained In
the charge and to agglomerate the
charge into a hard porous mass called
"sinter."
-------
Subpart SStandards of Performance
for Primary Aluminum Reduction
Plants27
Authority: Sections 111 and 301(a) of the
Clean Air Act as amended (42 U.S.C. 7411,
7601(a)), and additional authority as noted
below.
§ 60.190 Applicability and designation of
affected facility.64
(a) The affected facilities in'primary
aluminum reduction plants to which this
subpart applies are potroom groups and
anode bake plants.114
(b) Any facility under paragraph (a)
of this section that commences con-
struction or modification after October
23, 1974, is subject to the requirements
of this subpart.
§60.191 Definitions.'14
As used in this subpart. all terms not
defined herein shall have the meaning
given them in the Act and in subpart A
of this part.
"Aluminum equivalent" means an
amount of aluminum which can be
produced from a Mg of anodes produced
by an anode bake plant as determine*}
by § 60.195(g).
"Anode bake plant" means a facility
which produces carbon anodes for use
in a primary aluminum reduction plant
"Potroom" means a building unit
which houses a group of electrolytic
cells in which aluminum is produced
"Potroom group" means an
uncontrolled potroom. a potroom which
is controlled individually, or a group of
potrooms or potroom segments ducted to
a common control system.
"Primary aluminum reduction plant"
means any facility manufacturing
aluminum by electrolytic reduction
"Primary control system" means an
air pollution control system designed to
remove gaseous and particulate
flourides from exhaust gases which are
capture'd at the cell.
"Roof monitor" means that portion of
the roof of a potroom where gases not
captured at the cell exit from the
potroom.
"Total fluorides" means elemental
fluorine and all fluoride compounds as
measured by reference methods
specified in § 60.195 or by equivalent or
alternative methods (see § 60.8(b))
§60.192 Standard* for fluorides.114
(a) On and after the date on which the
initial performance test required to be
conducted by § 60.8 is completed, no
owner or operator subject to the
provisions of this subpart shall cause to
be discharged into the atmosphere from
any affected facility any gases
containing total fluorides, as measured
according to § 60.8 above, in excess of
(1) 1.0 kg/Mg (2.0 Ib/ton) of aluminum
produced for potroom groups at
Soderberg plants: except that emissions
between 1.0 kg/Mg and 1.3 kg/Mg (2.6
Ib/ton) will be considered in compliance
if the owner or operator demonstrates
that exemplary operation and
maintenance procedures were used with
respect to the emission control system
and that proper control equipment was
operating at the affected facility during
the performance tests;
(2) 0.95 kg/Mg (1.9 Ib/ton) of
aluminum produced for potroom groups
at prebake plants; except that emissions
between 0.95 kg/Mg and 1.25 kg/Mg (2.5
Ib/ton) will be considered in compliance
if the owner or operator demonstrates
that exemplary operation and
maintenance procedures were used with
respect to the emission control system
and that proper control equipment was
operating at the affected facility during
the performance test: and
(3) 0.05 kg/Mg (0.1 Ib/ton) of
aluminum equivalent for anode bake
plants.
(b) Within 30 days of any performance
test which reveals emissions which fall
between the 1.0 kg/Mg and 1.3 kg/Mg
levels in paragraph (a)(l) of this section
or between the 0.95 kg/Mg and 1.25 kg/
Mg levels in paragraph (a)[2) of this
section, the owner or operator shall
submit a report indicating whether all
necessary control devices were on-line
and operating properly during the
performance test, describing the
operating and maintenance procedures
followed, and setting forth any
explanation for the excess emissions, to
the Director of the Enforcement Division
of the appropriate EPA Regional Office
§ 60.193 Standard for visible emissions.!w
(a) On and after the date on which the
performance test required to be
conducted by § 60.8 is completed, no
owner or operator subject to the
provisions of this subpart shall cause to
be discharged into the atmosphere:
(1) From any potroom group any gases
which exhibit 10 percent opacity or
greater, or
(2) From any anode bake plant any
gases which exhibit 20 percent opacity
or greater.
§ 60.194 Monitoring of operations.114
(a) The owner or operator of any
affected facility subject to the provisions
of this subpart shall install, calibrate.
maintain, and operate monitoring
devices which can be used to determine
daily the weight of aluminum and anode
produced. The weighing devices shall
have an accuracy of ± 5 percent over
their operating range.
(b) The owner or operator of any
affected facility shall maintain a record
of daily production rates of aluminum
and anodes, raw material feed rates,
and cell or potline voltages.
(Section 114 of the Clean Air Ad as amended
(42 U.S.C. 7414))
§60.195 Test methods and procedures.114
{a) Following the initial performance
test as required under § 60,8(a). an
owner or operator shall conduct a
performance test at least once each
month during the life of the affected
facility, except when malfunctions
present representative sampling, as
provided under § 60.8(c). The owner or
operator shall give the Administrator at
least 15 days ad\ance notice of each
test The Administrator may require
additional testing under section 114 of
the Clean Air Act
(b) An owner or operator may petition
the Administrator to establish an
alternative testing requirement that
requires testing less frequently than
once each month for a primary control
system or an anode bake plant. If the
owner or operator show that emissions
from the primary control system or the
anode bake plant have low variability
during day-to-day operations, the
Administrator may establish such an
alternative testing requirement. The
alternative testing requirement shall
include a testing schedule and. in the
case of a primary control system, the
method to be used to determine priman,
control system emissions for the purpose
of performance tests. The Administrator
shall publish the alternative testing
requirement in the Federal Register.
(cj Except as provided in § 60.8(b).
reference methods specified in
Appendix A of this part shall be used 10
determine compliance with the
standards prescribed in | 60.192 as
follows:
(11 For sampling emissions from
stacKs:
(i) Method 1 for sample and velocity
traverses.
(11) Method 2 for velocity and
volumetric flow rate.
(in] Method 3 for gas analysis, and
(i\) Method 13A or 13B for the
concentration of total fluorides and the
associated moisture content.
(2) For sampling emissions from roof
monitors not employing stacks or
pollutant collection systems:
(i) Method 1 for sample and velocity
traverses.
(ii) Method 2 and Method 14 for
111-48
-------
velocity and volumetric flow rate.
(lii) Method 3 for gas analysis, and
(iv) Method 14 for the concentration of
total fluorides and associated moisture
content.
(3) For sampling emissions from roof
monitors not employing stacks but
equipped with pollutant collection
systems, the procedures under § 60.8(b)
shall be followed.
(d) For Method 13A or 13B, the
sampling time for each run shall be at
least 8 hours for any potroom sample
and at least 4 hours for any anode bake
plant sample, and the minimum sample
volume shall be 6.8 dscm (240 dscf) for
any potroom sample and 3.4 dscm (120
dscf) for any anode bake plant sample
except that shorter sampling times or
smaller volumes, when necessitated by
process variables or other factors, may
be approved by the Administrator.
(e) The air pollution control system for
each affected facility shall be
constructed so that volumetric flow
rates and total fluoride emissions can be
accurately determined using applicable
methods specified under paragraph (c)
of this section.
(f) The rate of aluminum production is
determined by dividing 720 hours into
the weight of aluminum tapped from the
affected facility during a period of 30
days prior to and including the final run
of a performance test.
(g) For anode bake plants, the
aluminum equivalent for anodes
produced shall be determined as
follows:
(1) Determine the average weight (Mg)
of anode produced in anode bake plant
during a representative oven cycle using
a monitoring device which meets the
requirements of § 60.194(a).
(2) Determine the average rate of
anode production by dividing the total
weight of anodes produced during the
representative oven cycle by the length
of the cycle in hours.
(3) Calculate the aluminum equivalent
for anodes produced by multiplying the
average rate of anode production by
two. (Note: An owner or operator may
establish a different multiplication
factor by submitting production records
of the Mg of aluminum produced and the
concurrent Mg of anode consumed by
potrooms.)
(h) For each run, potroom group
emissions expressed in kg/Mg of
aluminum produced shall be determined
using the following equation:
(CsOs),10"N-(CsOs),1D-'
Ep«
M
Where:
Epg = potroom group emissions of total
fluorides in kg/Mg of aluminum
produced.
Cs = concentration of total fluorides in mg/
dscm as determined by'Method 13A or
13B, or by Method 14. as applicable.
Qs = volumetric flow rate of the effluent
gas stream in dscm/hr as determined by
Method 2 and/or Method 14, as
applicable
10 ~'= conversion factor from mg to kg
M = rate of aluminum production in Mg/hr
as determined by § 60.195(f).
(CsQs), = product of Cs and Qs for
measurements of primary control system
effluent gas streams.
(CsQs)j = product of Cs and Qs for
measurements of secondary control
system or roof monitor effluent gas
streams.
Where an alternative testing requirement has
been established for the primary control
system, the calculated value (CsQs) i from
the most recent performance test will be
used.
(i) For each run, as applicable, anode
bake plant emissions expressed in kg/
Mg of aluminum equivalent shall be
determined using the following equation:
CsOs 10 '
Ebp=
Where:
Ebp = anode bake plant emissions of total
fluorides in kg/Mg of aluminum
equivalent.
Cs = concentration of total fluorides in
mg/dscm as determined by Method 13A
or 13B.
Qs = volumetric flow rate of the effluent
gas stream in dscm/hr as determined by
Method 2.
10 ~* = conversion factor from mg to kg.
Me = aluminum equivalent for anodes
produced by anode bake plants in Mg/hr
as determined by § 60.195(g).
(Section 114 of the Clean Air Act as amended
(42 U.S.C. 7414))
Proposed/effective
39 FR 37730, 10/23/74
Promulgated
41 FR 3825, 1/26/76 (27)
Revised
4T7n7936, 7/25/77 (64)
42 FR 41424, 8/17/77 (68)
43 FR 8800, 3/3/78 (83)
45 FR 44202, 6/30/80 (114)
111-49
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Subpart TStandards of Performance for
the Phosphate Fertilizer Industry: Wet-
Process Phosphoric Acid Plants "»
§ 60.200 Applicability and designation
of affected facility.64
(a) The affected facility to which the
provisions of this subpart apply Is each
wet-process phosphoric acid plant. For
the purpose of this subpart, the affected
facility includes any combination of:
reactors, filters, evaporators, and hot-
wells.
(b) Any facility under paragraph (a)
of this section that commences con-
struction or modification after October
22, 1974, is subject to the requirements
of this subpart.
§ 60.201 Definitions.
As used in this subpart, all terms not
defined herein shall have the meaning
given them In the Act and in Subpart A
of this part.
.=Equlvalent PjOt feed In metric
ton/hr as determined by f 60.-
204(d).
(Sec. 114. Clean Air Act to amended (43
U.S.C. 7414)). 68,83
Proposed/effecti ve
"39 FR 37602, 10/22/74
Promulgated
40 FR 33152, 8/6/75 (14)
Revised
42 FR 37936, 7/25/77 (64)
42 FR 41424, 8/17/77 (68)
43 FR 8800, 3/3/78 (83)
111-50
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Subpart UStandards of Performance for
the Phosphate Fertilizer Industry: Super-
phosphoric Acid Plants 14
160.210 Applicabililr and designation
of affected facility.64
(a) The affected facility to which the
provisions of this subpart apply is each
uperphosphoric acid plant. For the
purpose of this subpart, the affected
facility Includes any combination of:
evaporators, hot wells, acid sumps, and
cooling tanks.
(b) Any facility under paragraph (a)
of this section that commences con-
struction or modification after October
22, 1974, is subject to the requirements
of this suboart
§ 60.211 Definitions.
As used in this subpart, all terms not
defined herein shall have the meaning
given them In the Act and In subpart A
of this part.
(a) "Superphosphoric acid plant"
means any facility which concentrates
wet-process phosphoric acid to 66 per-
cent or greater P2OB content by weight
for eventual consumption as a f ertilizer.
(b) "Total fluorides" means elemen-
tal fluorine and all fluoride compounds
as measured by reference methods spe-
cified in I 60.214, or equivalent or alter-'
native methods.
(c) "Equivalent P2O, feed" means the
quantity of phosphorus, expressed as
phosphorous pentoxide, fed to the
process.
j 60.212 Standard for fluorides.
<&/ On and after the date on which
the performance test required to be con-
ducted by ! 60.8 is completed, no owner
or operator subject to the nrovisions of
this subpart shall cause to be discharged
Into the atmosphere from any affected
facility any gases which contain total
fluorides in excess of 5.0 g/metric ton of
equivalent P.O. feed. (0.010 Ib/ton).
| 60.213 Monitoring of operation*.
(a) The owner or operator of any
uperphosphoric acid plant subject to
the provisions of this subpart shall in-
stall, calibrate, maintain, and operate
* flow monitoring device which can be
used to determine the mass flow of
phosphorus -bearing feed material to the
process. The flow monitoring device shall
have an accuracy of ± 5 percent over its
operating range.
(b) The owner or operator of any
uperphosphoric acid plant shall main-
tain a daily record of equivalent PaO5
feed by first determining the total mass
late in metric ton/hr of phosphorus-
bearing feed using a flow monitoring de-
vice meeting the requirements of para-
graph (a) of this section and then by
proceeding according to 5 60.214(d) (2).
(c) The owner or operator of any
Uperphosphoric acid plant subject to the
provisions of this part shall install, cali-
brate, maintain, and operate a monitor-
tng device which continuously measures
»nd permanently records the total pres
we drop across the process scrubbing
system. The monitoring device shall have
Mn accuracy of ± 5 percent over its
perating range.
(Sec. 114. Clean Air Act 1* amended (42
U.S.C. 7414)).68'83
i 60.214 Test methods and procedures.
(a^ Reference methods In Appendix
A of this part, except as provided In
I 60.8(b), shall be used to determine
compliance with the standard prescribed
In I 60.212 as follows:
(1) Method 13A or 13B for the concen-
tration of total fluorides and the asso-
ciated moisture content.
(2) Method 1 for sample and velocity
traverses,
(3) Method 2 for velocity and volu-
metric flow rate, and
(4) Method 3 for gas analysis.
(b) For Method ISA or 138, the sam-
pling time for each run shall be at least
60 minutes and the minimum sample
volume shall be at least 0.85 dscm (30
dscf) except that shorter sampling times
or smaller volumes, when necessitated by
process variables or other factors, may
be approved by the Administrator.
(c) The air pollution control system
for the affected facility shall be con-
structed so that volumetric flow rates and
total fluoride emissions can be accurately
determined by applicable test methods
and procedures.
(d) Equivalent P*OS feed shall be deter-
mined as follows:
(1) Determine the total mass rate in
metric ton/hr of phosphorus-bearing
feed during each run using a flow moni-
toring device meeting the requirements
of J 60.213(a).
(2) Calculate the equivalent P,Oi feed
by multiplying the percentage P«O3 con-
tent, as measured by the spectrophoto-
metric molybdovanadophosphate method
(AOAC Method 9), times the total mass
rate of phosphorus-bearing feed. AOAC
Method 9 is published in the Official
Methods of Analysis of the Association of
Official Analytical Chemists, llth edition,
1970, pp. 11-12. Other methods may be
approved by the Administrator.
(e) For each run, emissions expressed
to g/metric ton of equivalent P2OS feed,
ball be determined using the following
equation:
E=(C.Q.\ 10-
Where:
£ = Emissions of total fluorides In g/
metric ton of equivalent P2Or
feed.
Ct Concentration of total fluorides In
mg/dscm as determined by
Method 13A or 13B.
C. = Volumetric flow rate of the effluent
gas stream In dscm 'hr as deter-
mined by Method 2.
10-'=Conversion factor for mg to g.
Uiy>0=Equivalent PfO5 feed In metric
ton/hr «s determined by { 60.-
314(d).
(Sec. 114, Clean Air Act Is amended (42
V£.C. 7414)). 68, 83
Proposed/effective
39 FR 37602, 10/22/74
Promulgated
40 FR 33152, 8/6/75 (14)
Revised
42 FR 37936, 7/25/77 (64)
42 FR 41424, 8/17/77 (68)
43 FR 8800, 3/3/78 (83)
111-51
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Subpart VStandards of Performance for
the Phosphate Fertilizer Industry: Diam-
rnonium Phosphate Plants H
§ 60.220 Applicability and designation
of affected facility.'^
(a) The affected facility to which the
provisions of this subpart apply is each
granular diammonium phosphate plant.
For the purpose of this subpart, the af-
fected facility includes any combination
of: reactors, granulators, dryers, coolers,
screens, and mills.
(b> Any facility under paragraph (a)
of this section that commences construc-
tion or modification after October 22,
1971, is subject to the requirements of
this subpart.
§ 60.221 Definitions.
As used in this subpart, all terms not
defined herein shall have the meaning
given them in the Act and in subpart A
of this part.
(a) "Granular diammonium phos-
phate plant" means any plant manu-
facturing granular diammonium phos-
phate by reacting phosphoric acid with
ammonia.
(b) "Total fluorides" means elemental
fluorine and all fluoride compounds as
measured by reference methods speci-
fied in § 60.224, or equivalent or alter-
native methods.
(c) "Equivalent P.O5 feed" means the
quantity of phosphorus, expressed as
phosphorous pentoxide, fed to the proc-
ess.
g 60.222 Standard for fluorides.
(a) On and after the date on which
the performance test required to be con-
ducted by § 60.8 is completed, no owner
or operator subject to the provisions of
this subpart shall cause to be discharged
into the atmosphere from any affected
facility any gases which contain total
fluorides in excess of 30 g/metric ton of
equivalent PiO; feed (0.060 Ib/ton).
§ 60.223 Monitoring of operations.
(a) The owner or operator of any
granular diammonium phosphate plant
subject to the provisions of this subpart
shall install, calibrate, maintain, and
operate a flow monitoring device which
can be used to determine the mass flow
of phosphorus-bearing feed material to
the process. The flow monitoring device
shall have an accuracy of ±5 percent
over its operating range.
(b) The owner or operator of any
granular diammonium phosphate plant
shall maintain a daily record of equiv-
alent P..O; feed by first determining the
total mass rate in metric ton/hr of phos-
phorus-bearing feed using a flow moni-
toring device meeting the requirements
of paragraph (a) of this section and then
by proceeding according to § 60.224 (d)
(2).
(c) The owner or operator of any
granular diammonium phosphate plant
subject to the provisions of this part shall
Install, calibrate, maintain, and operate
a monitoring device which continuously
measures and permanently records the
total pressure drop across the scrubbing
system. The monitoring device shall have
an accuracy of ±5 percent over its op-
erating range.
(Sec. 114. Clean Air Act U amended (42
U.S.C. 7414)).68.83
§ 60.224 Test methods and procedures.
(a) Reference methods in Appendix A
of this part, except as provided for in
I 60.8 (b) , shall be used to determine com-
pliance with the standard prescribed in
I 60.222 as follows :
(1) Method ISA or 13B for the con-
centration of total fluorides and the as-
sociated moisture content,
(2) Method 1 for sample and velocity
traverses,
(3) Method 2 for velocity and volu-
metric flow rate, and
(4) Method 3 for gas analysis.
(b) For Method 13A or 13B, the
sampling time for each run shall be at
least 60 minutes and the minimum
sample volume shall be at least 0.85 dscm
(30 dscf) except that shorter sampling
times or '-smaller volumes when, neces-
sitated by process variables or other
factors, may be approved by the Ad-
ministrator.
(c) The air pollution control system
for the affected facility shall be con-
structed so that volumetric flow rates
and total fluoride emissions can be ac-
curately determined by applicable test
methods and procedures.
(d) Equivalent P30, feed shall be de-
termined as follows:
(1) Determine the total mass rate in
metric ton/hr of phosphorus-bearing
feed during each run using a flow moni-
toring device meeting the requirements
of §60.223 (a).
(2) Calculate the equivalent P:0, feed
by multiplying the percentage P30« con-
tent, as measured by the spectrophoto-
metric molybdovanadophosphate method
(AOAC Method 9), times the total mass
rate of phosphorus -bearing feed. AOAC
Method 9 Is published In the Official
Methods of Analysis of the Association
of Official Analytical Chemists, llth edi-
tion, 1970, pp. 11-12. Other methods may
be approved by the Administrator.
(e) For each run, emissions expressed
In g/metric ton of equivalent P.0i feed
shall be determined using the following
equation:
MVjO,;: Equivalent P.O. feed In metric
ton/hr M determined by 160.-
224(d).
(Sec. 114. Clean Air Act to amended (43
UAC. 7414)). 68'S3
where:
£ = Emissions of total fluorides In g/
metric ton of equivalent P,Of.
C, = Concentration of total fluorides In
mg/dscm as determined by
Method ISA or 13B.
-------
Subpart WStandards of Performance for
the Phosphate Fertilizer Industry: Triple
Superphosphate Plants 14
§ 60.230 Applicability and designation
of affected facility.64
The aflected facility to which the
provisions of this subpart apply is each
triple superphosphate plant. For the pur-
pose of this subpart, the affected facility
includes any combination of: mixers,
curing belts (dens), reactors, granula-
tors, dryers, cookers, screens, mills, and
facilities which store run-of-pile triple
superphosphate.
(b) Any facility under paragraph (a)
of this section that commences construc-
tion or modification after October 22,
1974, is subject to the requirements of
this subpart.
In metric ton/hr of phosphorus-bearing
feed using a flow monitoring device meet-
ing the requirements of paragraph (a)
of this section and then by proceeding
according to I 80.234(d) (2).
(c) The owner or operator of any triple
superphosphate plant subject to the pro-
visions of this part shall install, calibrate,
maintain, and operate a monitoring de-
vice which continuously measures and
permanently records the total pressure
drop across the process scrubbing system.
The monitoring device shall have an ac-
curacy of ±5 percent over Its operating
range.
(Sec. 114, Clean Air Act is amended (42
U.S.C. 7414».*8, 83
$ 60.231 Definition*.
As used In this subpart, all terms not
defined herein shall have the meaning
given them in the Act and In subpart A
of this part.
(a) "Triple superphosphate plant"
means any facility manufacturing triple
superphosphate by reacting phosphate
rock with phosphoric acid. A rule-of-pile
triple superphosphate plant includes
curing and storing.
(b) "Run-of-pile triple superphos-
phate" means any triple superphosphate
that has not been processed In a grauu-
lator and is composed of particles at
least 25 percent by weight of which
(when not caked) will pass through a 16
mesh screen.
(c) "Total fluorides" means ele-
mental fluorine and all fluoride com-
pounds as measured by reference
methods specified In § 60.234, or equiva-
lent or alternative methods.
(d) "Equivalent P.OB feed" means the
quantity of phosphorus, expressed aa
phosphorus pentoxlde, fed to the process.
| 60.232 Standard for fluorides.
(a) On and after the date on which the
performance test required to be con-
ducted by 5 60.8 is completed, no owner
or operator subject to the provisions of
this subpart shall cause to be discharged
into the atmosphere from any affected
facility any gases which contain total
fluorides in. excess of 100 g/metric ton of
equivalent P,O, feed (0.20 Ib/ton).
| 60.233 Monitoring of operations.
(a) The owner or operator of any triple
superphosphate plant subject to the pro-
visions of this subpart shall Install, cali-
brate, maintain, and operate a flow moni-
toring device which can be used to deter-
mine the mass flow of phosphorus-bear-
ing feed material to the process. The flow
monitoring device shall have an accuracy
of ±5 percent over its operating range.
(b) The owner or operator of any
triple superphosphate plant shall main-
tain a daily record of equivalent PjO. feed
by first determining the total mass rate
C, = Concentration of total fluorides In
mg/dscm as determined by
Method 13A or 13B.
<},=Volumetric flow rate of the effluent
gas stream in dscm/hr as deter-
mined by Method 2.
10-"=Conversion factor for mg to g.
M>.o.=Equivalent P2O, feed In metric
ton/hr * determined by i 60.-
234(d).
(Sec. 114. Clean Air Act is amended (42
U.S.C. 7414».68'83
§ 60.234 Test methods and procedures.
(a) Reference methods in Appendix A
of this part, except as provided for in
{ 60.8(b), shall be used to determine com-
pliance with the standard prescribed in
160.232 as follows:
(1) Method ISA or 13B for the concen-
tration of total fluorides and the asso-
ciated moisture content,
(2) Method 1 for sample and velocity
traverses,
(3) Method 2 for velocity and volu-
metric flow rate, and
(4) Method 3 for gas analysis.
(b) For Method 13A or 13B, the sam-
pling time for each run shall be at least
60 minutes and the minimum sample
volume shall be at least 0.85 dscm (30
dscf) except that shorter sampling times
or smaller volumes, when necessitated by
process variables or other factors, may
be approved by the Administrator.
(c) The ah- pollution control system
for the affected facility shall be con-
structed so that volumetric flow rates
and total fluoride emissions can be ac-
curately determined by applicable test
methods and procedures.
(d) Equivalent P,O. feed shall be deter-
mined as follows:
(1) Determine the total mass rate in
metric ton/hr of phosphorus-bearing
feed during each run using a flow moni-
toring device meeting the requirements
of S60.233(a).
(2) Calculate the equivalent PSOS feed
by multiplying the percentage P.O. con-
tent, as measured by the spectrophoto-
metric molybdovanadophosphale method
(AOAC Method 9), times the total mass
rate of phosphorus-bearing feed. AOAC
Method 9 is published In the Official
Methods of Analysis of the Association of
Official Analytical Chemists, IIth edition,
1970, pp. 11-12. Other methods may be
approved by the Administrator.
(e) For each run, emissions expressed
in g/metric ton of equivalent P.Oi feed
shall be determined using the following
equation:
(C.Q.)
where:
= Emissions of total fluorides In g/
metric ton of equivalent P,OI
feed.
Proposed/effective
39 FR 37602, 10/24/74
Promulgated
40 FR 33152, 8/6/75 (14)
Revised
42 FR 37936, 7/25/77 (64)
42 FR 41424, 8/17/77 (68)
43 FR 8800, 3/3/78 (83)
111-53
-------
Subpart XStandards of Performance for
the Phosphate Fertilizer Industry: Gran-
ular Triple Superphosphate Storage Fa-
cilities M
§ 60.240 Applicability and designation
of affected facility.64
(a) The affected facility to which the
provisions of this subpart apply is each
granular triple superphosphate storage
facility. For the purpose of this subpart,
the affected facility includes any combi-
nation of: storage or curing piles, con-
veyors, elevators, screens, and mills.
(b) Any facility under paragraph (a)
of this section that commences construc-
tion or modification after October 22,
1974, is subject to the requirements of
this subpart.
§ 60.241 Definitions.
As used in this subpart, all terms not
defined herein shall have the meaning
given, them in the Act and In subpart A
of this part
(a) "Granular triple superphosphate
storage faculty" means any facility cur-
ing or storing granular triple superphos-
phate.
(b) "Total fluorides" means elemental
fluorine and all fluoride compounds as
measured by reference methods specified
In § 60.244, or equivalent or alternative
methods.
(c) "Equivalent P=O5 stored" means
the quantity of phosphorus, expressed as
phosphorus pentoxide, being cured or
stored in the affected facility.
(d) "Fresh granular triple superphos-
phate" means granular triple superphos-
phate produced no more than 10 days
prior to the date of the performance lest.
§ 60.242 Sundard for fluorides.
(a) On and after the date on which the
performance test required to be con-
ducted by i 60.8 is completed, no owner
or operator subject to the provisions of
this subpart shall cause to be discharged
into the atmosphere from any affected
faculty any gases which contain total
fluorides in excess of 0.25 g/hr/metric
ton of equivalent PiO, stored (5.0 x 10*4
Ib/hr/ton of equivalent P.Oi stored).
§ 60.243 Monitoring of operations.
(a) The owner or operator of any
granular triple superphosphate storage
facility subject to the provisions of this
subpart shall maintain an accurate ac-
count of triple superphosphate in storage
to permit the determination of the
amount of equivalent P,O, stored.
(b) The owner or operator of any
granular triple superphosphate storage
facility shall maintain a daily record of
total equivalent PSO« stored by multiply-
ing the percentage P,OS content, as
determined by i 60.244(f)(2), times the
total mass of granular triple superphos-
phate stored.
(c) The owner or operator of any
granular triple superphosphate storage
facility subject to the provisions of this
part shall install, calibrate, maintain,
and operate a monitoring device which
continuously measures and permanently
records the total pressure drop across the
process scrubbing sytem. The monitoring
device shall have an accuracy of ±5 per-
cent over Its operating range.
(Sec. 114, Clean Air Act is Amended (42
U.S.C. 7414)). 6& 83
§ 60.244 Test methods and procedures.
(a) Reference methods in Appendix A
of this part, except as provided for In
I 60.8(b), shall be used to determine
compliance with the standard prescribed
In § 60.242 as follows:
(1) Method 13A or 13B for the con-
centration of total fluorides and the as-
sociated moisture content,
(2) Method 1 for sample and velocity
traverses,
<3) Method 2 for velocity and volu-
metric Sow rate, and
(4) Method 3 for gas analysis.
f the build-
ing capacity.
(2) Fresh granular triple superphos-
phateat least 20 percent of the amount
of triple superphosphate In the buUding.
(e) If the provisions set forth in para-
graph (d) (2) of this section exceed pro-
duction capabilities for fresh granular
triple superphosphate, the owner or oper-
ator shall have at least five days maxi-
mum production of fresh granular triple
superphosphate In the building during
a performance test.
(f) Equivalent P^Oi stored shall be
determined as follows:
(,1) Determine the total mass stored
during each run using an accountability
system meeting the requirements of
§60.243 (a).
(2) Calculate the equivalent P,O5
stored by multiplying the percentage
P«O« content, as measured by the spec-
trophotometric molybdovanadophos-
phate method
-------
Subpart YStandards of Performance for
Coal Preparation Plants "
§ 60.250 Applicability and designation
of affected facility.64
(a) The provisions of this subpart are
applicable to any of the following af-
fected facilities in coal preparation
plants which process more than 200 tons
per day: thermal dryers, pneumatic coal-
cleaning equipment (air tables), coal
processing and conveying equipment (in-
cluding breakers and crushers), coal
storage systems, and coal transfer and
loading systems.
(to) Any facility under paragraph (a)
of this section that commences construc-
tion or modification after October 24,
1974, is subject to the requirements of
this subpart 71
160.251 Definition*.
As used in this subpart, all terms not
denned herein have the meaning given
them in the Act and in subpart A of this
part.
(a) "Coal preparation plant" means
any facility (excluding underground
mining operations) which prepares coal
by one or more of the following proc-
esses: breaking, crushing, screening, wet
or dry cleaning, and thermal drying.
(to) "Bituminous coal" means solid fos-
Bl) fuel classified as bituminous coal by
A.8.TJM. Designation D-388-«6.
(c) "Coal" means all solid fossil fuels
classified as anthracite, bituminous, sub-
bituminous, or lignite by AJ3.T.M. Des-
ignation D-388-66.
(d) "Cyclonic flow" means a spiralmg
movement of exhaust gases within a duct
or stack.
(e) "Thermal dryer" means any fa-
cility In which the moisture content of
bituminous coal Is reduced by contact
with a heated gas stream which Is ex-
hausted to the atmosphere.
(1) "Pneumatic coal-cleaning equip-
ment" means any facility which classifies
^bituminous coal by size or separates bi-
tuminous coal from refuse by application
bf air stream(s).
! (g) "Coal processing and conveying
Equipment" means any machinery used
to reduce the size of coal or to separate
boal from refuse, and the equipment used
lo convey coal to or remove coal and
Refuse from the machinery. This In-
cludes, but is not limited to, breakers,
crushers, screens, and conveyor belts.
(h) "Coal storage system" means any
facility used to store coal except for open
.Storage piles.
: (1) "Transfer and loading system"
means any facility used to transfer and
load coal for shipment.
Standard* for paniculate mat-
«harged Into the atmosphere from any
thermal dryer gases which:
(1) Contain particulate matter in ex-
ess of 0.070 g/dscm (0.031 gr/dscf).
(2) Exhibit 20 percent opacity or
greater.
(b) On and after the date on which the
performance test required to be con-
ducted by | 60.8 is completed, an owner
or operator subject to the provisions of
this subpart shall not cause to be dis-
charged into the atmosphere from any
'pneumatic coal cleaning equipment,
gases which:
(1) Contain particulate matter in ex-
cess of 0.040 g/dscm (0.018 gr/dscf).
(2) Exhibit 10 percent opacity or
greater.
(c) On and after the date on which
the performance test required to be con-
ducted by {60.8 Is completed, an owner
or operator subject to the provisions of
this subpart shall not cause to be dis-
charged into the atmosphere from any
coal processing and conveying equip-
ment, coal storage system, or coal trans-
fer and loading system processing coal,
gases which exhibit 20 percent opacity
or greater.
( 60.253 Monitoring of operations.
(a) The owner or operator of any ther-
mal dryer shall install, calibrate, main-
tain, and continuously operate monitor-
Ing devices as follows:
(DA monitoring device for the meas-
urement of the temperature of the gas
stream at the exit of the thermal dryer
on a continuous basis. The monitoring
device Is to be certified by the manu-
facturer to be accurate within ± 3 Fahr-
enheit
(2) For affected facilities that use ven-
turi scrubber emission control equip-
ment:
XI) A monitoring Device for the con-
tinuous measurement of the pressure loss
.through the renturl constriction of the
control equipment. The monitoring de-
Vice is to be certified by the manufac-
turer to be accurate within ±1 tach
water gage.
(ii) A monitoring device for the con-
tinuous measurement of the water sup-
ply pressure to the control equipment.
The monitoring device is to be certified
by the manufacturer to be accurate with-
in ±5 percent of design water supply
pressure. The pressure sensor or tap must
be located close to the water discharge
point. The Administrator may be con-
sulted for approval of alternative loca-
tions.
(b) All monitoring devices under para-
graph (a) of this section are to be recali-
brated annually in accordance with pro-
cedures under { 60.18(b) (3) of this part.
| 60.252
ler.
(a) On and after the date on which
the performance test required to be con-
ducted by f 60.8 is completed, an owner
*r operator subject to the provisions of
Ibis nibpart shall not cause to be dls-
pliance with the standards prescribed In
{60.252 as follows:
(1) Method 5 for the concentration of
particulate matter and associated mois-
ture content,
(2) Method 1 for sample and velocity
traverses,
(3) Method 2 for velocity and volu-
metric flow rate, and
(4) Method 3 for gas analysis.
(b) For Method 5, the sampling time
for each run is at least 60 minutes and
the minimum sample volume is 0.85 dscm
(30 dscf) except that shorter sampling
times or smaller volumes, when necessi-
tated by process variables or other fac-
tors, may be approved by the Adminis-
trator. Sampling is not to be started until
30 minutes after start-up and is to be
terminated before shutdown procedures
commence. The owner or operator of the
affected facility shall eliminate cyclonic
flow during performance tests in a man-
ner acceptable to the Administrator.
(c) The owner or operator shall con-
struct the facility so that particulate
emissions from thermal dryers or pneu-
matic coal cleaning equipment can be
accurately determined by applicable test
methods and procedures under para-
graph (a) of this section.
(Sec. 114. Clean Air Act U amended (42
U.S.C. 7414)).68-83
(Sec. 114. Clean Air Act U amended (42
V£.C. 7414)). 68,83
160.254 Te»t methods and procedure*.
(a) The reference methods In Ap-
pendix A of this part, except as provided
in { 60.8(b), are used to determine com-
Proposed/effactive
39 FR 37922, 10/24/74
Promulgated
gal
223
41 FR 2231, 1/15/76 (26)
Revised
42 FR 37936, 7/25/77 (64)
42 FR 41424, 8/17/77 (68)
42 FR 44812, 9/7/77 (71)
43 FR 8800, 3/3/78 (83)
111-55
-------
Subpart ZStandards of Performance for
Ferroalloy Production Facilitie*33'3*
§ 60.260 Applicability and designation
of affected facility.64
(a) The provisions of this subpart are
applicable to the following affected fa-
cilities: electric submerged arc furnaces
which produce silicon metal, ferroslllcon.
calcium silicon, Silicomanganese zircon-
ium, ferrochrome silicon, silvery
Iron, high-carbon ferrochrome, charge
chrome, standard ferromanganese, slll-
comanganese, ferromanganese silicon, or
calcium carbide; and dust-handling
equipment.35
(b) Any facility under paragraph (a)
of this section that commences construc-
tion or modification after October 21.
1974, Is subject to the requirements of
this subpart.
§ 60.261 Definitions.
As used in this subpart, all terms not
denned herein shall have the meaning
given them in the Act and in subpart A
of this part.
(a) "Electric submerged arc furnace"
means any furnace wherein electrical
energy is converted to heat energy by
transmission of current between elec-
trodes partially submerged in the furnace
charge.
(b) "Furnace charge" me?ns any ma-
terial introduced into the electric. sub-
merged arc furnace and may consist of,
but is not Mmitcd to, orss, slag, carbo-
naceous mateiial, and limestone.
(c) "Product change" means any
change in the composition of the furnace
charge that would cause the electric sub-
merged arc furnace to become subject
to a different mass standard applicable
under this subpart.
(d) "Slag" means the more or less
completely fused and vitrified matter
separated during the reduction of a
metal from ifs ore.
(e) "Tapping" means the removal of
slag or product from the electric sub-
merged arc furnace under normal op-
erating conditions such as removal of
metal under normal pressure and move-
ment by gravity down the spout Into the
ladle.
(f) "Tapping period" means the time
duration from initiation of the process
of opening the tap hole until plugging of
the tap hole is complete.
(g) "Furnace cycle" means the time
period from completion of a furnace
product tap to the completion of the next
consecu' ive product tap.
(h) "Tapping station" means that
general area where molten product or
slag is removed from the electric sub-
merged arc furnace.
(i) "Blowing tap" means any tap In
which an evolution of gas forces or pro-
jects jets of flame or metal sparks be-
yond the ladle, runner, or collection hood.
(J) "Furnace power input" means the
resistive electrical power consumption of
an electric submerged arc furnace as
measured in kilowatts.
(k) "Dust-handling equipment" means
any equipment used to handle particu-
Ir.te matter collected by th: air pollution
Control device (and located at or near
uch device) serving any electric sub-
merged, arc furnace subject to this sub-
part.
(1) "Control device" means the air
pollution control equipment used to re-
aove participate matter venerated by an
electric submerged arc furnace from an
effluent gas stream.
(m) "Capture 'system" means the
equipment (Including hoods, ducts, fans,
dampers, etc.) used to capture or trans-
port particulate matter generated by an
affected electric submerged arc furnace
to the control device.
(n) "Standard ferromanganese" means
that alloy as denned by A.S.T.M. desig-
nation A99-66.
(o) "Silicomanganese" means that
alloy as denned by A.S.T.M. designation
A483-66.
(p) "Calcium carbide" means materinl
containing 70 to 85 percent calcium car-
bide by weight.
(q) "High-carbon ferrochrome" means
that alloy as defined by A.S.T.M. desig-
nation A101-66 grades HC1 through HC6.
(r) "Charge chrome" means that alloy
containing 52 to 70 percent by weight
chrcmium, 5 to 8 percent by weight car-
bon, and 3 to 6 percent by weight silicon.
(s) "Silvery iron" means any ferro-
silicon, as defined by A.S.T.M. designa-
tion 100-69, which contains less than
30 percent silicon.
(t) "Ferrochrome silicon" means that
alloy as denned by A.S.T.M. designation
A482-66.
(u) "Eilicomanganese ?irconium"
means that alloy containing 60 to 65 per-
cent by weight silicon, 1.5 to 2.5 percent
by weight calcium, 5 to 7 percent by
weight zirconium, 0.75 to 1.25 percent by
weight aluminum, 5 to 7 percent by
weight manganese, and 2 to 3 percent by
weight barium.
(v) "Calcium silicon" means that
alloy as defined by A.S.T.M. designation
A405-G4.
(w) "Ferrosilicon" means that alloy as
denned by A.S.T.M. designation A100-69
grades A, B, C, D, and E which contains
5D or more percent by weight silicon.
(x) "Silicon metal" means any siUcon
alloy containing more than 96 percent
silicon by weight.
(y) "Ferromanganese silicon" means
that alloy containing 63 to 66 percent by
weight manganese, 28 to 32 percent by
weight silicon, and a maximum of 0.08
percent by weight carbon.
g 60.262 Standard for parliculatc mat-
ter.
(a) On and after the date on which the
performance test required to be con-
ducted by § 60.8 is completed, no owner
or operator subject to the provisions of
this subpart shall cause to be discharged
into the atmosphere from any electric
submerged arc furnace any gases which:
(1) Exit frorr. a control device and con-
tain particulate matter in excess of 0.45
kg/MW-hr (0.99 Ib/MW-hr) while sili-
con metal, ferrosilicon, calcium silicon,
or Silicomanganese zirconium is being
produced.
(2) Exit from a control device and con-
tain particulate matter In excess of 0.23
kg/MW-hr (0.51 Ib/MW-hr) while high-
carbon ferrochrome, charge chrome,
standard ferromanganese, Silicomanga-
nese, calcium carbide, ferrochrome sili-
con, ferromanganese silicon, or silvery
iron is being produced.
(3) Exit from a control device and ex-
hibit 15 percent opacity or greater.
(4) Exit from an electric submerged
arc furnace and escape the capture sys-
tem and are visible without the aid of
Instruments. The requirements under
(this subparagraph apply only during pe-
riods when flow rates are being estab-
lished under § 60.265(d).
(5) Escape the capture system at the
tapping station and are visible without
the aid of instruments for more than 40
percent of each tapping period. There are
no limitations on visible emissions under
this subnaragraph when a blowing tap
occurs. The requirements under this sub-
paragraph apply only during periods
when flow rates are being established
under $ 60.265(d).
(b) On and after the date" on which
the performance test required to be con-
ducted by § 60.8 Is completed, no owner
or operator subject to the provisions of
this subpart shall cause to be discharged
into the atmosphere from any dust-han-
dling equipment any gases which exhibit
10 percent opacity or greater.
§ 60.263 Standard for carbon monoxide.
(a) On and after the date on which
the performance test required to be con-
ducted by § 60.8 Is completed, no owner
or operator subiect to the provisions of
this subpart shall cause to be discharged
into toe atmosphere from any electric
submerged arc furnace any gases which
contain, on a dry basis, 20 or greater
volume percent of carbon monoxide.
Combustion of such gases under condi-
tions acceptable to the Administrator
constitutes comnliance with this section.
Acceptable conditions include, but are
not limited to, flaring of gases or use of
gases as fuel for other processes.
§ 60.261 Envssion monitoring.
fa> The owner or operator subject to
the provisions of this subpart shall In-
stall, calibrate, maintain and operate a
continuous monitoring system for meas-
urement of the opacity of emissions dis-
charged into the atmosphere from the
control devlce(s).
(b) For the purpose of .reports re-
quired under § 60.7(c), the owner or op-
erator shall report as excess emissions
all six-minute periods in which the av-
erage onacity is 15 percent or greater.
(c) The owner or operator subiect to
the provisions of this subnart shall sub-
mit a written report of any product
change to the Administrator. Reports of
product changes must be postmarked
not later than 30 days after implemen-
tation of the product change.
(Sec. 114. Clean Air Act U amended (42
U.S.C. -i4V4)).'8 83
§ 60.265 Monitoring of operation*.
-------
tain dally records of the following In-
formation:
(1) Product being produced.
C2) Description of constituents of fur-
nace charge, including the quantity, by
weight.
(3) Time and duration of each tap-
ping period and the Identification of ma-
terial tapped (slag or product.)
<4) All furnace power Input data ob-
tained under paragraph (b) of this sec-
tion.
<3> AD flow rate data obtained under
paragraph (c) of this section or all fan
motor power consumption and pressure
drop data obtained under paragraph (e)
of this section.
(b) The owner or operator subject to
the provisions of this subpart shall In-
stall, calibrate, maintain, and operate a
device to measure and continuously re-
cord the furnace power input. The fur-
nace power input may be measured at the
output or input side of the transformer.
The device must have an accuracy of ±5
percent over its operating range.
(o) The owner or operator subject to
the provisions of this subpart shall in-
stall, calibrate, and maintain a monitor-
ing device that continuously measures
and records the volumetric flow rate
through each separately ducted hood of
the capture system, except as provided
under paragraph (e) of this section. The
owner or operator of an electric sub»
merged arc furnace thst is equipped with
a water cooled cover which is designed
to contain and prevent escape of the
generated gas and paniculate matter
shall monitor only the volumetric flow
rate through the canture system for con-
trol of emissions from the tapping sta-,
tion. The owner or operator may install
th? monitoring device(s) in any appro-
priate location in the exhaust duct such
that reproducible flow rate monitoring
will result. The flow rate monitoring de-
vice must have an accuracy of ±10 per-
cent over its normal operating range and
must be calibrated qccsrding to the
manufacturer's instructions. The Ad-
ministrator may reauire the owner or
operator to demonstrate the accuracy of
{.he monitoring device relative to Meth-
ods 1 and 2 of Appendix A tc this port.
(d) When performance tests are con-
ducted under the provisions of § 60.8 of
this part to demonstrate compliance
with the standards under §§60.262 (a)
<4> and <5), the volumetric flow rate
through each separately ducted hood of
the capture system must be determined
using the monitoring device required
under paragraph (c) of this section. The
valumttric flow rates must be determined
for furnace power input levels at 50 and
100 percent of the nominal rated capacity
of the electric submerged arc furnace.
At all times the electric submerged arc
furnace is operated, the owner or oper-
ator shall maintain the volumetric flow
rate at or above the appropriate levels
for that furnace power input level de-
termined during the most recent per-
formance test. If emissions due to tap-
ping are captured and ducted separately
from emissions of the electric submerged
arc furnace, during each, tapping period
the owner or operator shall maintain
the exhaust flow rates through the cap-
ture system over the tapping station at
or above the levels established during
the most recent performance test. Oper-
ation at lower flow rates may be consid-
ered by the Administrator to be unac-
ceptable operation and maintenance of
the affected facility. The owner or oper-
ator may request that these flow rates be
reestablished by conducting new per-
formance tests under I 00.8 of this part.
(e) The owner or operator may as an
alternative to paragraph (c) of this sec-
tion determine the volumetric flow rate
through each fan of the capture system
from the fan power consumption, pres-
sure drop across the fan and the fan per-
formance curve. Only data specific to the
operation of the affected electric sub-
merged arc furnace are acceptable for
demonstration ot compliance with the
requirements of this paragraph. The
owner or operator shall maintain on file
a permanent record of the fan per-
formance curve 'prepared for a specific
temnerature) and shall:
(1) Install, calibrate, maintain, and
operate a device to continuously measure
and record the power consumption of the
fan motor fme^si'red in kilowatts), and
(2) Install, calibrate, maintain, and
operate a device to continuously meas-
ure pnd re-ord the pressure dron across
the fan. The fan rower consumption and
pressure dron measurements must be
synchronised to allo-" real time compar-
i^ons cf the data. The monitoring de-
vices must h«ve an accuracy of +5 per-
cent over the'r normal operating ranges.
(f) The vol'imetric flow rate through
each ffn of the capture svstem must be
determined from the fan power con-
sumntlon, fan pressure drop, and fan
performance curve pneciPed under para-
erarh (e) of thij section, during anv per-
formance te"!t required under § 60.8 of
this pTt to demonstrate compliance with
the standards under §§ 60 262(a) (4) and
(5). The o^ner or operator shall deter-
mine the volumetric flow rate at a re^re-
sentative temnerature for furnace power
input leve's of 50 and 100 percent of the
nominal rated capacity of the electric
submersed arc furnace At all times the
e'ectric submerged arc furnace is op-
erated, the owner or operator shall main-
tain the fan power consumption nnd fan
pressure dron at leve's such that the vol-
umetric flow rate is at or above the levels
established during the most recent per-
formance te^t for that furnace pov.-er in-
put level. If emissions due to tapping are
captured and ducted senarately from
emissions of the electric submerged arc
furnace, during each tapping period the
owner or operator shall maintain the fan
power consumption and fan pressure
drop at levels such that the volumetric
flow rate is at or above the levels estab-
lished during the most recent perform-
ance test. Operation at lower flow rates
mav be considered bv the Administrator
to be unacceptable operation and main-
tenance of the affected facility. The own-
er or operator may request tint these
flow rates be reestablished by conducting
new performance tests under 5 60.8 of
this part. The Administrator may require
the owner or operator to verify the fan
performance curve by monitoring neces-
sary fan operating parameters and de-
termining the gas volume moved relative
to Methods 1 and 2 of Appendix A to this
part.
(g) AH monitoring devices required
under paragraphs (c) and (e) of this
section are to be checked for calibration
annually fn accordance with the proce-
dures under |60.13cb>.
(Sec. 114, Clean Air Act is amended (42
U.S.C. 7414)).*8, 83
§ 60.266 Test methods and procedure*.
(a) Reference methods m Appendix A
of this part, except as provided ta f 80.8
(b), shall be used to determine compli-
ance with the standards prescribed in
| 60.262 and f 60.263 as follows:
(1) Method 5 for the concentration of
particulate matter and the associated
moisture content except that the heating
systems specified in paragraphs 2.1.2 and
2.1.4 of Method 5 are not to be used when
the carbon monoxide content of the gas
stream exceeds 10 percent by volume,
dry basis.
(2) Method 1 for sample and velocity
traverses.
(3) Method 2 for velocity and volumet-
ric flow rate.
(4) Method 3 for gas analysis, includ-
ing carbon monoxide.
(b) For Method 5, the sampling time
for each run is to include an integral
number of furnace cycles. The sampling
time for each run must be at leist 60
minutes and the minimum sample vol-
ume must be 1.8 dscm (64 dscf) when
sampling emissions from open electric
submerged arc furnaces with wet scrub-
ber control devices, sealed electric sub-
merged arc furnaces, or semi-enclosed
electric submerged arc furnaces. When
sampling emissions from other types of
installations, the sampling time for each
run must be at leist 200 minutes and the
minimum sample volume must be 5.7
dscm (200 dscf). Shorter sampling times
or smaller sampling volumes, when ne-
cessitated by process variables or other
factors, may be approved by the Admin-
istrator.
(c) During the performance test, the
owner or operator shall record the maxi-
mum open hood area (In hoods with
segmented or otherwise moveable sides)
under which the process is expected to
be operated and remain in compliance
with all standards. Any future operation
of the hooding system with open areas in
excess of the maximum is not permitted.
(d) The owner or operator shall con-
struct the control device so that volu-
metric flow rates and particulate matter
emissions can be accurately determine*
by applicable test methods and proce-
dures.
(e) During any performance test re-
quired under § 60.8 of this part, the
owner or operator shall not allow gaseous
diluents to be added to the effluent gas
stream after the fabric in an open pres-
surized fabric flltei collector unless the
111-57
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total gas volume flow from the collector
Is accurately determined and considered
in the determination of emissions.
(f) When compliance with 5 60.263 Is
to be attained by combusting the gas
stream In a flare, the location of the
sampling site for particulate matter Is
to be upstream of the flare.
(g) For each run, particulate matter
emissions, expressed In Itg/hv Ub/hr),
must be determined for each exhaust
stream at which emissions are quantified
using the following equation:
where:
£=Emissions of particulate nutter In
kg/hr (Ib/hr).
Ct=Con:entratlon of paniculate matter In
kg/dscm (Ib/dscf) as determined by
Method 6.
Q, = Volumetric fl<4w rate of the effluent gaa
stream In ds:m/hr (dsef/hr) as de-
termined by Method 2.
(h) For Method 5. particulate matter
emissions from the affected facility, ex-
pressed in kg/MW-hr (Ib/MW-hr) must
be determined for each run using the
following equation:
N
where:
£ = Emissions of particulate from the af-
fected facility,' In kg/MW-hr (lb/
MW-hr).
W=Total number of exhaust streams at
which emissions are quantified.
£i>=Emlgslon of particulate matter from
each exhaust stream In kg/hr (lb/
hr), as determined In paragraph (g)
of this section.
p=Average furnace power Input during
the sampling period. In megawatts
as determined according to f 80.263
(b).
(Sec. 114. Clean Air Act U amended (43
U.S.C. 7414)). *8,83
Proposed/effective
39 FR 37922, 10/24/74
Promulgated
41 FR 18498, 5/4/76 (33)
Revised
41 FR 20659, 5/20/76 (35)
42 FR 37936, 7/25/77 (64)
42 FR 41424, 8/17/77 (68)
43 FR 8800, 3/3/78 (83)
111-58
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Bubpart AAStandards of Performance
for Steel Plants: Electric Arc Furnaces "
I 60.270 Applicability and designation
of affected facility.64
(a) The provisions of this sUbpart are
applicable to the following affected fa-
cilities in steel plants: electric arc fur-
naces and dust-handling equipment.
(b) Any facility under paragraph (a)
of this section that commences construc-
tion or modification after October 21,
1974, is subject to the requirements of
this subpart. ^
f 60.271 Definition*.
As used In this subpart, all terms not
denned herein shall have the meaning
given them in the Act and In subpart A
of this part
(a) "Electric arc furnace" OEAP)
means any furnace tliat produces molten
teel and beats the charge materials
with electric arcs from carbon electrodes.
Furnaces from which the molten steel is
cast Into the shape of finished products,
such as in a foundry, are not affected fa-
cilities Included within the scope of this
definition. Furnaces which, as the pri-
mary source of Iron, continuously feed
prereduced ore pellets are not affected
facilities within the scope of this
definition.
cb) "Dust-handling equipment" means
any equipment used to handle particu-
late matter collected by the control de-
vice and located at or near the control
device for an EAF subject to this sub-
part
(c) "Control device" means the air
pollution control equipment used to re-
move participate matter generated by
an EAF(s) from the effluent gas stream.
(d) "Capture system" means the
equipment (Including ducts, hoods, fans,
dampers, etc.) used to capture or trans-
port particulate matter generated by an
EAF to the air pollution control device.
relative to Methods 1 and 2 of Appendix
A of this part.
(c) When the owner or operator of
an EAF Is required to demonstrate com-
pliance with the standard under 5 60.272
(a) (3) and at any other time the Ad-
ministrator may require (under section
114 of the Act, as amended), the volu-
metric Sow rate through each separately
ducted hood shall be determined during
all periods in which the hood Is operated
for the purpose of capturing emissions
from the EAF using the monitoring de-
vice under paragraph (b) of this section.
The owner or operator may petition the
Administrator for reestablishment of
these flow rates whenever the owner or
operator can demonstrate to the Admin-
istrator's satisfaction that the EAF oper-
ating conditions upon which the flow
rates were previously established are no
longer applicable. The flow rates deter-
mined during the most recent demon-
stration' of compliance shall be main-
tained (or may be exceeded) at the ap-
propriate level for each applicable period.
Operation at lower flow rates may be
considered by the Administrator to be
unacceptable operation and maintenance
of the affected facility.
(d) The owner or operator may peti-
tion the Administrator to approve any
alternative method that will provide a
continuous record of operation of each
emission capture system.
(e) Where emissions during any phase
of the heat time are controlled by use
of a direct shell evacuation system, the
111-59
-------
owner or operator shall Install, calibrate,
and maintain a monitoring device that
continuously records the pressure in the
free space inside the EAF. The pressure
shall be recorded as 15-minute inte-
grated averages. The monitoring device
may be installed in any appropriate lo-
cation in the EAF such that reproduc-
ible results will be obtained. The pres-
sure monitoring device shall have an ac-
curacy of ±5 mm of water gauge over
its normal operating range and shall be
calibrated according to the manufac-
turer's instructions.
(f) When the owner or operator of an
EAF is required to demonstrate compli-
ance with the standard under I 60.272
(a) (3) and at any other time the Ad-
ministrator may require (under section
114 of the Act, as amended), the pressure
in t'le free space inside the furnace shall
be determined during the meltdown and
reftning period(s) using the monitoring
device under paragraph (e) of this sec-
tion. The owner or operator may peti-
tion the Administrator for reestablish-
ment of the 15-minute integrated aver-
age pressure whenever the owner or
operator can demonstrate to the Admin-
istrator's satisfaction that the EAF op-
erating conditions upon which the pres-
sures were previously established are no
longer applicable. The pressure deter-
mined during the. most recent demon-
stration of compliance shall be main-
tained at all times the EAP is operating
in a meltdown and refining period. Op-
eration at higher pressures may be con-
sidered by the Administrator to be un-
acceptable operation and maintenance
of the affected facility.
(g) Where the capture system is de-
signed and operated such that all emis-
sions are captured and ducted to a con-
trol device, the owner or operator shall
not be subject to the requirements of this
section.
(Sec. 114. Clean Air Act Is amended (42
U.SC. 7414)). 68 83
§ 60.275 Test methods and procedures.
(a) Reference methods in Appendix A
of this part, except as provided under
§60.8(b), shall be used to determine
compliance with the standards pre-
scribed under § 60.272 as follows:
(1) Method 5 for concentration of par-
ticulate matter and associated moisture
content;
(2) Method 1 for sample and velocity
traverses;
(3) Method 2 for velocity and volu-
metric flow rate; and
(4) Method 3 for gas analysis.
(b) For Method 5, the sampling time
for each run shall be at least four hours.
When a single EAF is sampled, the sam-
pling time for each run shall also in-
clude an integral number of heats.
Shorter sampling times, when necessi-
tated by process variables or other fac-
tors, may be approved by the Admin-
istrator. The minimum sample volume
shall be 4.5 dscm (160 dscf).
(c) For the purpose of this subpart,
the owner or operator shall conduct the
demonstration of compliance with 60.-
272(a)(3) and furnish the Adminis-
trator a written report of the results of
the test.
(d) During any performance test re-
qu'Jed under § 60.8 of this part, no gase-
ous diluents may be added to the
effluent gas stream after 'the fabric in
any pressurized fabric filter collector,
unless the amount .of dilution la sepa-
rately determined and considered in the
determination of emissions.
(e) When more than one control de-
vice serves the EAF(s) being tested, the
concentration of particulate matter shall
be determined using the following
equation:
See.).
n=i
where-
C.=coneentration of particular matt.r
in mg/dscm (gr/dscf) as determined
, by method 5.
Ar=wtal number of control devices
tested.
C. = volumetric flow rate of the effluent
gas stream in dscrn/hr (dscf/hr) as
determined by method 2.
(C.Q.). or (Q,ln = vilue of the applicable parameter for
each control device tested.
. (f) Any control device subject to the
provisions of this subpart shall be de-
signed and constructed to allow meas-
urement of emissions using applicable
test methods and procedures.
(g) Where emissions from any EAF(s)
are combined with emissions from facili-
ties not subject to the provisions of this
subpart but controlled by a common cap-
ture system and control device, the owner
or operator may use any of the follow-
ing procedures during a performance
test:
(1) Base compliance on control of the
combined emissions.
(2) Utilize a method acceptable to
the Administrator which compensates
for the emissions from the facilities not
subject to the provisions of this subpart.
(3) Any combination of the criteria
of paragraphs (g)(l) and (g)(2) of this
section.
(h) Where emissions from any EAF(s)
are combined with emissions from facili-
ties not subject to the provisions of
this subpart, the owner or operator may
use any of the following procedures for
demonstrating compliance with § 60.272
(a) (3) :
(1) Base compliance on control of the
combined emissions.
(2) Shut down operation of facilities
not subject to the provisions of this
subpart.
(3) Any combination of the criteria
of paragraphs (h) (1) and (h) (2) of this
section.
(Sec 114. Clean Air Act i& amended (42
U.SC 7414)). 6B 83
Proposed/effective
39 FR 37466, 10/21/74
Promulgated
40 FR 43850, 9/23/75 (16)
Revised
42 FR 37936, 7/25/77 (64)
42 FR 41424, 8/17/77 (68)
42 FR 44812, 9/7/77 (71)
43 FR 8800, 3/3/78 (83)
111-60
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Subporl UStandards «f Performance far
Kraft Pulp MUh82
M.280 Applicability and designation of af-
fected facility.
(a) The provisions of this subpart
are applicable to the following affect-
ed facilities in kraft pulp mills: digest-
er system, brown stock washer system,
multiple-effect evaporator system,
black liquor oxidation system, recov-
ery furnace, smelt dissolving tank,
lime kiln, and condensate stripper
system. In pulp mills where kraft
pulping is combined with neutral sul-
fite semichemical pulping, the provi-
sions of this subpart are applicable
when any portion of the material
charged to an affected facility is pro-
duced by the kraft pulping operation.
(b) Any facility under paragraph (a)
of this section that commences con-
struction or modification after Sep-
tember 24, 1976, is subject to the re-
quirements of this subpart.
f C0.281 Definitions.
As used in this subpart, all terms not
defined herein shall have the same
meaning given them in the Act and in
Subpart A.
(a) "Kraft pulp mill" means any sta-
tionary source which produces pulp
from wood by cooking (digesting)
wood chips in a water solution of
sodium hydroxide and sodium sulfide
(White liquor) at high temperature
and pressure. Regeneration "of the
cooking chemicals through a recovery
process is also considered part of the
kraft pulp mill.
(b) "Neutral sulfite semichemical
pulping operation" means any oper-
ation in which pulp is produced from
wood by cooking (digesting) wood
chips in a solution of sodium sulfite
and sodium bicarbonate, followed by
mechanical defibrating (grinding).
(c) "Total reduced sulfur (TRS)"
means the sum of the sulfur com-
pounds hydrogen sulfide, methyl mer-
captan, dimethyl sulfide, and dimethyl
disulfide, that are released during the
kraft pulping operation and measured
by Reference Method 16.
(d) "Digester system" means each
continuous digester or each batch di-
gester used for the cooking of wood in
white liquor, and associated flash
tank(s), below tank(s), chip steamer(s),
and condenser(s).
(e) "Brown stock washer system"
means brown stock washers and associ-
ated knotters, vacuum pumps, and fil-
trate tanks used to wash the pulp fol-
lowing the digester system.
(f) "Multiple-effect evaporator
system" means the multiple-effect
evaporators and associated
condenser(s) and hotwell(s) used to
concentrate the spent cooking liquid
that is separated from the pulp (black
liquor).
(g) "Black liquor oxidation system"
means the vessels used to oxidize, with
air or oxygen, the black liquor, and as-
sociated storage tank(s).
(h) "Recovery furnace" means either
a straight kraft recovery furnace or a
cross recovery furnace, and includes
the direct-contact evaporator for a
direct-contact furnace.
(i) "Straight kraft recovery furnace"
means a furnace used to recover
chemicals consisting primarily of
sodium and sulfur compounds by
burning black liquor which on a quar-
terly basis contains 7 weight percent
or less of the total pulp solids from
the neutral sulfite semichemical pro-
cess or has green liquor sulfidity of 28
percent or less.
(j) "Cross recovery furnace" means a
furnace used to recover chemicals con-
sisting primarily of sodium and sulfur
compounds by burning black liquor
which on a quarterly basis contains
more than 7 weight percent of the
total pulp solids from the neutral sul-
fite semichemical process and has a
green liquor sulfidity of more than 28
percent.
(k) "Black liquor solids" means the
dry" weight of the solids which enter
the recovery furnace in the black
liquor.
(1) "Green liquor sulfidity" means
the sulfidity of the liquor which leaves
the smelt dissolving tank.
(m) "Smelt dissolving tank" means a
vessel used for dissolving the smelt
collected from the recovery furnace.
(n) "Lime kiln" means a unit used to
calcine lime mud, which consists pri-
marily of calcium carbonate, into
quicklime, which is calcium oxide.
(o) "Condensate stripper system"
means a column, and associated con-
densers, used to strip, with air or
steam, TRS compounds from conden-
sate streams from various processes
within a kraft pulp mill.
J 60.282 Standard for particulate matter.
(a) On and after the date on which
the performance test required to be
conducted by §60.8 is completed, no
owner or operator subject to the provi-
sions of this subpart shall cause to be
discharged into the atmosphere:
(1) From any recovery furnace any
gases which:
(i) Contain particulate matter in
excess of 0.10 g/dscm (0.044 gr/dscf)
corrected to 8 percent oxygen.
(U) Exhibit 35 percent opacity or
greater.
(2) From any smelt dissolving tank
any gases which contain particulate
matter in excess of 0.1 g/kg black
liquor solids (dry weight)[0.2 Ib/ton
black liquor solids (dry weight)].
(3) From any lime kiln any gases
which contain particulate matter in
excess of:
(i) 0.15 g/dscm (0.067 gr/dscf) cor-
rected to 10 percent oxygen, when gas-
eous fossil fuel is burned.
(ii) 0.30 g/dscm (0.13 gr/dscf) cor-
rected to 10 percent oxygen, when
liquid fossil fuel Is burned.
§60.283 Standard for total reduced sulfur
(TRS).
(a) On and after the date on which
the performance test required to be
conducted by §60.8 is completed, no
owner or operator subject to the provi-
sions of this subpart shall cause to be
discharged into the atmosphere:
(1) From any digester system, brown
stock washer system, multiple-effect
evaporator system, black liquor oxida-
tion system, or condensate stripper
system any gases which contain TRS
in excess of 5 ppm by volume on a dry
basis, corrected to 10 percent oxygen,
unless the following conditions are
met:
(i) The gases are combusted in a lime
kiln subject to the provisions of para-
graph (a)(5) of this section; or
(ii) The gases are combusted in a re-
covery furnace subject to the provi-
sions of paragraphs (a)(2) or (a)(3) of
this section; or
(iii) The gases are combusted with
other waste gases in an incinerator or
other device, or combusted in a lime
kiln or recovery furnace not subject to
the provisions of this subpart, and are
subjected to a minimum temperature
of 1200° F. for at least 0.5 second; or
(iv) It has been demonstrated to the
Administrator's satisfaction by the
owner or operator that incinerating
the exhaust gases from a new, modi-
fied, or reconstructed black liquor oxi-
dation system or brown stock washer
system in an existing facility is tech-
nologically or economically not feasi-
ble. Any exempt system will become
subject to the provisions of this sub-
part if the facility Is changed so that
the gases can be incinerated.
(v) The gases from the digester
system, brown stock washer system,
condensate stripper system, or black
liquor oxidation system are controlled
by a means other than combustion. In
this case, these systems shall not dis-
charge any gases to the atmosphere
which contain TRS in excess of 5 ppm
by volume on a dry basis, corrected to
the actual oxygen content of the un-
treated gas stream.9'
(2") From any straight kfaft recovery
furnace any gases which contain TRS
in excess of 5 ppm by volume on a dry
basis, corrected to 8 percent oxygen.
(3) From any cross recovery furnace
any gases which contain TRS in excess
of 25 ppm by volume on a dry basis,
corrected to 8 percent oxygen.
(4) From any smelt dissolving tank
any gases which contain TKS in excess
of 0.0084 g/kg black liqu-.r solids (dry
weight) [0.0168 Ib/ton liquor solids
(dry weight)].
(5) From any lime kiln any gases
which contain TRS in excess of 8 ppm
by volume on a dry basis, corrected to
10 percent oxygen.
111-61
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f 6Q.2&4 Monitoring of emissions and op-
erations.
(a) Any owner or operator subject to
the provisions of this subpart shall in-
stall, calibrate, maintain, and operate
the following continuous monitoring
systems:
(DA continuous monitoring system
to monitor and record the opacity of
the gases discharged into the atmos-
phere from any recovery furnace. The
span of this system shall be set at 70
percent opacity.
(2) Continuous monitoring systems
to monitor and record the concentra-
tion of TRS emissions on a dry basis
and the percent of oxygen by volume
on a dry basis in the gases discharged
into the atmosphere from any lime
kiln, recovery furnace, digester
system, brown stock washer system,
multiple-effect evaporator system,
black liquor oxidation system, or con-
densate stripper system, except where
the provisions of |60.283(a)(l) (iii) or
(iv) apply. These systems shall be lo-
cated downstream of the control
device(s) and the span(s) of these con-
tinuous monitoring system(s) shall be
set:
(i) At a TRS concentration of 30
ppm for the TRS continuous monitor-
ing system, except that for any cross
recovery furnace the span shall be set
at 50 ppm.
(ii) At 20 percent oxygen for the
continuous oxygen monitoring system.
(b) Any owner or operator subject to
the provisions of this subpart shall in-
stall, calibrate, maintain, and operate
the following continuous monitoring
devices:
(DA monitoring device which mea-
sures the combustion temperature at
the point of incineration of effluent
gases which are emitted from any di-
gester system, brown stock washer
system, multiple-effect evaporator
system, black liquor oxidation system,
or condensate stripper system where
the provisions of §60.283(a)(l)(iii)
apply. The monitoring device is to be
certified by the manufacturer to be ac-
curate within ±1 percent of the tem-
perature being measured.
(2) For any lime kiln or smelt dis-
solving tank using a scrubber emission
control device:
(i) A monitoring device for the con-
tinuous measurement of the pressure
loss of the gas stream through the
control equipment. The monitoring
device is to be certified by the manu-
facturer to be accurate to within a
gage pressure of ±500 pascals (ca. ±2
inches water gage pressure).
(ii) A monitoring device for the con-
tinuous measurement of the scrubbing
liquid supply pressure to the control
equipment. The monitoring device is
to be certified by the manufacturer to
be accurate within ±15 percent of
design scrubbing liquid supply pres-
sure. The pressure sensor or tap is to
be located close to the scrubber liquid
discharge point. The Administrator
may be consulted for approval of alter-
native locations.
(c) Any owner or operator subject to
the provisions of this subpart shall,
except where the provisions of
§60.283(a)UXiv) or § 60.283(aX4)
apply.
(1) Calculate and record on a daily
basis 12-hour average TRS concentra-
tions for the two consecutive periods
of each operating day. Each 12-hour
average shall be determined as the
arithmetic mean of the appropriate 12
contiguous 1-hour average total re-
duced sulfur concentrations provided
by each continuous monitoring system
installed under paragraph (a)(2) of
this section.
(2) Calculate and record on a daily
basis 12-hour average oxygen concen-
trations for the two consecutive peri-
ods of each operating day for the re-
covery furnace and lime kiln. These
12-hour averages shall correspond to
the 12-hour average TRS concentra-
tions under paragraph (c)(D of this
section and shall be determined as an
arithmetic mean of the appropriate 12
contiguous 1-hour average oxygen con-
centrations provided by each continu-
ous monitoring system installed under
paragraph (a)(2) of this section.
(3) Correct all 12-hour average TRS
concentrations to 10 volume percent
oxygen, except that all 12-hour aver-
age TRS concentration from a recov-
ery furnace shall be corrected to '8
volume percent using the following
equation:
where:
C^,=the concentration corrected for
oxygen.
CL»,=the concentration unconnected for
oxygen.
X=the volumetric oxygen concentration in
percentage to be corrected to (8 percent
for recovery furnaces and 10 percent for
lime kilns, incinerators, or other de-
vices).
y=the measured 12-hour average volumet-
ric oxygen concentration.
(d) For the purpose of reports re-
quired under § 60.7(c), any owner or
operator subject to the provisions of
this subpart shall report periods of
excess emissions as follows:
(1) For emissions from any recovery
furnace periods of excess emissions
are:
(i) All 12-hour averages of TRS con-
centrations above 5 ppm by volume for
straight kraft recovery furnaces and
above 25 ppm by volume for cross re-
covery furnaces.
(ii) All 6-minute average opacities
that exceed 35 percent.
(2) For emissions from any lime kiln,
periods of excess emissions are all 12-
hour average TRS concentration
above 8 ppm by volume.
(3) For emissions from any digester
system, brown stock washer system,
multiple-effect evaporator system,
black liquor oxidation system, or con-
densate stripper system periods of
excess emissions are:
(i) All 12-hour average TRS concen-
trations above 5 ppm by volume unless
the provisions of $60.283(a)(l) (i), (11).
or (iv) apply; or
(ii) All periods in excess of 5 minutes
and their duration during which the
combustion temperature at the point
of incineration is less than 1200° F.
where the provisions of
§ 60.283(a)(l)(ii) apply.
(e) The Administrator will not con-
sider periods of excess emissions re-
ported under paragraph (d) of this sec-
tion to be indicative of a violation of
§ eo.HCd) provided that:
(1) The percent of the total number
of possible contiguous periods of
excess emissions in a quarter (exclud-
ing periods of startup, "shutdown, or
malfunction and periods when the fa-
cility is not operating) during which
excess emissions occur does not
exceed:
(i) One percent for TRS emissions
from recovery furnaces.
(ii) Sis percent for average opacities
from recovery furnaces.
(2) The Administrator determines
that the affected facility, including air
pollution control equipment, is main-
tained and operated in a manner
which Ls consistent with good air pol-
lution control practice for minimizing
emissions during periods of excess
emissions.
§ 60.285 Test methods and procedures.
(a) Reference methods in Appendix
A of this part, except as provided
under § 60.8(b), shall be used to deter-
mine compliance with J60.282(a) as
follows:
(1) Method 5 for the concentration
of parti culate matter and the associat-
ed moisture content,
(2) Method 1 for sample and velocity
traverses,
(3) When determining compliance
with § 60.282(a)(2), Method 2 for veloc-
ity and volumetric flow rate,
(4) Method 3 for gas analysis, and
(5) Method 9 for visible emissions.
(b) For Method 5, the sampling time
for each run shall be at least 60 min-
utes and the sampling rate shall be at
least 0.35 dscm/hr (0.53 dscf/mln)
except that shorter sampling times.
when necessitated by process variables
or other factors, may be approved by
the Administrator. Water shall be
used as ihe cleanup solvent instead of
acetone in the sample recovery proce-
dure outlined in Method 5.
(c) Method 17 (in-stack filtration)
may be used as an alternate method
for Method 5 for determining compli-
ance with §60.282(a)(D(i): Provided,
That a constant value of 0.009 g/dscm
(0.004 gr/dscf) is added to the results
of Method 17 and the stack tempera-
111-62
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ture is no greater than 205* C (ca. 400°
F). Water shall be used as the cleanup
solvent instead of acetone in the
sample recovery procedure outlined in
Method 17.
(d) For the purpose of determining
compliance with §60.283(a) (1), (2),
(3), (4), and (5), the following refer-
ence methods shall be used:
(1) Method 16 for the concentration
of TRS.
(2) Method 3 for gas analysis, and
(3) When determining compliance
with §60.283(aX4), use the results of
Method 2, Method 16, and the black
liquor solids feed rate in the following
equation to determine the TRS emis-
sion rate.
.X «
n + CMU'D
Where:
X « mass of TRS emitted per unity of black
liquor solids (g/kg> (Ib/ton)
Cn -= average concentration of hydrogen
sulfide (HjS) during the test period,
PPM.
CM, = average concentration of methyl
mercaptan (MeSH) during the test
period, PPM.
CMS average concentration of dimethyl
sulfide (DMS) during the test period,
PPM.
CDMM -= average concentration of dimethyl
disulfide (DMDS) during the test period.
PPM.
/ _ 0.001417 g/m' PPM for metric units
« 0.08844 lb/ft« PPM for English units
'MB = 0.00200 g/m' PPM for metric units
0.1248 Ib/ft1 PPM for English units
fmm = 0.002583 g/m« PPM for metric units
= 0.1612 lb/ff PPM for English units
/M» - 0.003917 g/m« PPM for metric units
- 0.2445 lb/ff PPM for English units
QM dry volumetric stack gas flow rate cor-
rected to standard conditions, dscm/hr
(dscf/hr>
BLS = black liquor solids feed rate, kg/hr
(Ib/hr)
(4) When determining whether a
furnace Is straight kraft recovery fur-
nace or a cross recovery furnace,
TAPPI Method T.624 shall be used to
determine sodium sulfide, sodium hy-
droxide and sodium carbonate. These
'determinations shall be made three
times daily from the green liquor and
the daily average values shall be con-
verted to sodium oxide (Na,O) and
substituted into the following equa-
tion to determine the green liquor sul-
fidity:
QLS - 100 CN.I'/CN.I' + CH^H + CH.KO,
Where:
QLS = percent green liquor sulf idity
Cite* = average concentration of No* ex-
pressed as NatO (mg/1)
C».OH = average concentration of NaOH
expressed as A'OiO (mg/1)
CB..CO. = average concentration of Na,CO,
expressed as Na,O
-------
Subpart DDStandards of
Performance for Grain Elevators 90
§ 60.300 Applicability and designation of
affected facility.
(a) The provisions of this subpart
apply to each affected facility at any
grain terminal elevator or any grain
storage elevator, except as provided
under §60.304(b). The affected facili-
ties are each truck unloading station,
truck loading station, barge and ship
unloading station, barge and ship load-
ing station, railcar loading station,
railcar unloading station, grain dryer,
and all grain handling operations.
(b) Any facility under paragraph (a)
of this section which commences con-
struction, modification, or reconstruc-
tion after (date of reinstatement of
proposal) is subject to the require-
ments of this part.
$ 60.301 Definitions.
As used in this subpart, all terms not
defined herein shall have the meaning
given them in the act and in subpart A
of this part.
(a) "Grain" means corn, wheat, sor-
ghum, rice, rye, oats, barley, and soy-
beans.
(b) "Grain elevator" means any
plant or installation at which grain is
unloaded, handled, cleaned, dried,
stored, or loaded.
(c) "Grain terminal elevator" means
any grain elevator which has a perma-
nent storage capacity of more than
88,100 m3 (ca. 2.5 million U.S. bushels).
except those located at animal food
manufacturers, pet food manufactur-
ers, cereal manufacturers, breweries,
and livestock feedlots.
-------
(4) The installation of permanent
storage capacity with no increase in
hourly grain handling capacity.
Proposed/effective
43 FR 34349, 8/3/78
Promulgated
43 FR 34340, 8/3/78 (90)
111-65
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Subpart GGStandards of
Performance for Stationary Gas
Turbines101
5 60.330 Applicability and designation of
affected facility.
The provisions of this subpart are
applicable to the following affected
facilities: all stationary gas turbines
with a heat input at peak load equal to
or greater than 10.7 gigajoules per hour,
based on the lower heating value of the
fuel fired.
{60.331 Definitions.
As used in this subpart, all terms not
defined herein shall have the meaning
given them in the Act and in subpart A
of this part.
(a) "Stationary gas turbine" means
any simple cycle gas turbine,
regenerative cycle gas turbine or any
gas turbine portion of a combined cycle
steam/electric generating system that is
not self propelled. It may, however, be
mounted on a vehicle for portability.
(b) "Simple cycle gas turbine" means
any stationary gas turbine which does
not recover heat from the gas turbine
exhaust gases to preheat the inlet
combustion air to the gas turbine, or
which does not recover heat from the
gas turbine exhaust gases to heat water
or generate steam.
(c) "Regenerative cycle gas turbine"
means any stationary gas turbine which
recovers heat from the gas turbine
exhaust gases to preheat the inlet
combustion air to the gas turbine.
(d) "Combined cycle gas turbine"
means any stationary gas turbine which
recovers heat from the gas turbine
exhaust gases to heat water or generate
steam.
(e) "Emergency gas turbine" means
any stationary gas turbine which
operates as a mechanical or electrical
power source only when the primary
power source for a facility has been
rendered inoperable by an emergency
situation,
(f) "Ice fog" means an atmospheric
suspension of highly reflective ice
crystals.
(g) "ISO standard day conditions"
means 288 degrees Kelvin, 60 percent
relative humidity and 101.3 kilopascals
pressure.
(h) "Efficiency" means the gas turbine
manufacturer's rated heat rate at peak
load in terms of heat input per unit of
power output based on the lower
heating value of the fuel.
(i) "Peak load" means 100 percent of
the manufacturer's design capacity of
the gas turbine at ISO standard day
conditions.
(j) "Base load" means the load level at
which a gas turbine is normally
operated.
(k) "Fire-fighting turbine" means any
stationary gas turbine that is used solely
to pump water for extinguishing fires.
(1) 'Turbines employed in oil/gas
production or oil/gas transportation"
means any stationary gas turbine used
to provide power to extract crude oil/
natural gas from the earth or to move
crude oil/natural gas, or products
refined from these substances through
pipelines.
(m) A "Metropolitan Statistical Area"
or "MSA" as defined fay the Department
of Commerce.
(n) "Offshore platform gas turbines"
means any stationary gas turbine
located on a platform in an ocean.
(o) "Garrison facility" means any
permanent military installation.
[p] "Gas turbine model" means a
group of gas turbines having the same
nominal air flow, combuster inlet
pressure, combuster inlet temperature,
firing temperature, turbine inlet
temperature and turbine inlet pressure.
§60.332 Standard for nitrogen oxides.
(a) On and after the date on which the
performance test required by f 60.8 is
completed, every owner or operator
subject to the provisions of this subpart,
as specified in paragraphs (b), (c), and
(d) of this section, shall comply with one
of the following, except as provided in
paragraphs (e), (f), (g), (h), and (i) of this
section.
(1) No owner or operator subject to
the provisions of this subpart shall
cause to be discharged into the
atmosphere from any stationary gas
turbine, any gases which contain
nitrogen oxides in excess of:
STD = 0.0075
where:
32
STD=allowable NO, emissions (percent by
volume at 15 percent oxygen and on a
dry basis).
Y = manufacturer's rated heat rate at
manufacturer's rated load (kilojoules per
watt hour) or, actual measured heat rate
based on lower beating value of fuel as
measured at actual peak load for the
facility. The value of Y shall not exceed
14.4 kilojoules per watt hour.
F=NO, emission allowance for fuel-bound
nitrogen as defined in part (3) of this
paragraph.
(2) No owner or operator subject to the
provisions of this subpart shall cause to be
discharged into the atmosphere from any
stationary gas turbine, any gases which
con'aih nitrogen oxides in excess of:
STD = 0.0150 (1^) + F
where:
STD = allowable NO, emissions (percent by
volume at 15 percent oxygen and on a
dry basis).
Y = manufacturer's rated heat rate at
manufacturer's rated peak load
(kilojoules per watt hour), or actual
measured heat rate based on lower
heating value of fuel as measured at
actual peak load for the facility. The
value of Y shall not exceed 14.4
kilojoules per watt hour.
F=NO» emission allowance for fuel-bound
nitrogen as defined in pert (3) ef this
paragraph.
(3) F shall be defined according to the
nitrogen content of the fuel as follows:
Fuel-Bound
(percent by weight)
« c 0.015
0.015 < «t < 0 7
0.1 « N 0.25
N > O.Z5
rcent by volume)
0
0.004 + 0.0067(N-0.))
0.005
where:
N = the nitrogen content of the fuel (percent
by weight).
or
Manufacturers may develop custom
fuel-bound nftrojjen allowances for each
gas turbine model they manufacture.
These fuel-bound nitrogen allowances
shall be substantiated with data and
must be approved for use by the
Administrator before the initial
performance test required by { 60.8.
Notices of approval of custom fuel-
bound nitrogen allowances will be
published in the Federal Register.
(b) Stationary gas turbines with a heat
input at peak load greater than 107.2
gigajoules per hour (100 million Btu/
hour) based OB the lower heating value
of the fuel fired except as provided in
§ 60.332(d) shall comply with the
provisions of § 60.332(a)(l).
(c) Stationary gas turbines with a heat
input at peak load equal to or greater
than 10.7 gigajoules per hour (10 million
Btu/hour) but less than or equal to 107.2
gigajoules per hour (100 million Btu/
hour) based on the lower heating value
of the fuel fired, shall comply with the
provisions of § 60.332(a)(2).
(d) Stationary gas turbines employed
in oil/gas production or oil/gas
transportation and not located in
Metropolitan Statistical Areas; and
offshore platform turbines shall comply
with the provisions of § 60.332(a){2).
(e) Stationary gas turbines with a heat
input at peak load equal to or greater
than 10.7 gigajoules per hour (10 million
Btu/hour) but less than or equal to 107.2
gigajoules per hour (100 million Btu/
hour) baaed on the lower heating value
of the fuel fired and that have
111-66
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commenced construction prior to
October 3,1962 are exempt from
paragraph (a) of this section.
(f) Stationary gas turbines using water
or steam injection for control of NO,
emissions are exempt from paragraph
(a] when ice fog is deemed a traffic
hazard by the owner or operator of the
gas turbine.
(g) Emergency gas turbines, military
gas turbines for use in other than a
garrison facility, military gas turbines
installed for use as military training
facilities, and fire fighting gas turbines
are exempt from paragraph (a) of this
section.
(h) Stationary gas turbines engaged by
manufacturers in research and
development of equipment for both gas
turbine emission control techniques and
gas turbine efficiency improvements are
exempt from paragraph (a) on a case-by-
case basis as determined by the
Administrator.
(i) Exemptions from the requirements
of paragraph (a) of this section will be
granted on a case-by-case basis as
determined by the Administrator in
specific geographical areas where
mandatory water restrictions are
required by governmental agencies
because of drought conditions. These
exemptions will be allowed only while1
the mandatory water restrictions are in
effect.
160.333 Standard for sulfur dioxide.
On and after the date on which the
performance test required to be
conducted by § 60.8* is completed, every
owner or operator subject to the
provision of this subpart shall comply
with one or the other of the following
conditions:
(a) No owner or operator subject to
the provisions of this subpart shall
cause to be discharged into the
atmosphere from any stationary gas
turbine any gases which contain sulfur
dioxide in excess of 0.015 percent by
volume at 15 percent oxygen and on a
dry basis.
(b) No owner or operator subject to
the provisions of this subpart shall burn
in any stationary gas turbine any fuel
which contains sulfur in excess of O.B
percent by weight.
160.334 Monitoring of operations.
(a) The owner or operator of any
stationary gas turbine subject to the
provisions of this subpart and using
water injection to control NO, emissions
shall install and operate a continuous
monitoring system to monitor and record
the fuel consumption and the ratio of
water to fuel being fired in the turbine.
This system shall be accurate to within
±5.0 percent and shall be approved by
the Administrator.
(b) The owner or operator of any
stationary gas turbine subject to the
provisions of this subpart shall monitor
sulfur content and nitrogen content of
the fuel being fired in the turbine. The
frequency of determination of these
values shall be as follows:
(1) If the turbine is supplied its fuel
from a bulk storage tank, the values
shall be determined on each occasion
that fuel is transferred to the storage
tank from any other source.
(2) If the turbine is supplied its fuel
without intermediate bulk storage the
values shall be determined and recorded
daily. Owners, operators or fuel vendors
may develop custom schedules for
determination of the values based on the
design and operation of the affected
facility and the characteristics of the
fuel supply. These custom schedules
shall be substantiated with data and
must be approved by the Administrator
before they can be used to comply with
paragraph (b] of this section.
(c) For the purpose of reports required
under § 60.7(c), periods of excess
emissions that shall be reported are
defined as follows:
(1) Nitrogen oxides. Any one-hour
period during which the average water-
to-fuel ratio, as measured by the
continuous monitoring system, falls
below the water-to-fuel ratio determined
to demonstrate compliance with § 60.332
by the performance test required in
{ 60.8 or any period during which the
fuel-bound nitrogen of the fuel is greater
than the maximum nitrogen content
allowed by the fuel-bound nitrogen
allowance used during the performance
test required in S 60.8. Each report shall
include the average water-to-fuel ratio,
obs
where:
NO,"emissions of NO, at 15 percent oxygen
and ISO standard ambient conditions.
NO,ou=measured NO, emissions at 15
percent oxygen, ppmv.
Pr^=reference combuster inlet absolute
pressure at 101.3 kilopascals ambient
pressure.
Plb>=measured combustor inlet absolute
pressure at test ambient pressure.
Hob. = specific humidity of ambient air at test.
e=transcendental constant (2.718}.
TAMBtemperature of ambient air at test.
The adjusted NO, emission level shall
be used to determine compliance with
{ 60.332.
(ii) Manufacturers may develop
custom ambient condition correction
factors for each gas turbine model they
manufacture in terms of combustor inlet
pressure, ambient air pressure, ambient
average fuel consumption, ambient
conditions, gas turbine load, and
nitrogen content of the fuel during the
period of excess emissions, and the
graphs or figures developed under
S 60.335(a).
(2) Sulfur dioxide. Any daily period
during which the sulfur content of the.
fuel being fired in the gas turbine
exceeds 0.8 percent.
(3) Ice fog. Each period during which
an exemption provided in § 60.332[g) is
in effect shall be reported in writing to
the Administrator quarterly. For each
period the ambient conditions existing
during the period, the date and time the
air pollution control system was
deactivated, and the date and time the
air pollution control system was
reactivated shall be reported. All
quarterly reports shall be postmarked by
the 30th day following the end'of each
calendar quarter.
(Sec. 114 of the Clean Air Act as amended [42
U.S.C. 18570-9]).
160.335 Test methods and procedures.
(a) The reference methods in
Appendix A to this part, except as
provided in § 60.8(b), shall be used to
determine compliance with the
standards prescribed in § 60.332 as
follows:
(1) Reference Method 20 for the
concentration of nitrogen oxides and
oxygen. For affected facilities under this
subpart, the span value shall be 300
parts per million of nitrogen oxides.
(i) The nitrogen oxides emission level
measured by Reference Method 20 shall
be adjusted to ISO standard day
conditions by the following ambient
condition correction factor:
'AMB »i.53
- °-00633>
air humidity and ambient air
temperature to adjust the nitrogen
oxides emission level measured by the
performance test as provided for in
§ 60.8 to ISO standard day conditions.
These ambient condition correction
factors shall be substantiated with data
and must be approved for use by the
Administrator before the initial
performance test required by 5 60.8.
Notices of approval of custom ambient
condition correction factors will be
published in the Federal Register.
(iii) The water-to-fuel ratio necessary
to comply with { 60.332 will be
determined during the initial
performance test by measuring NO,
emission using Reference Method 20 and
111-67
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the water-to-fuel ratio necessary to
comply with § 60.332 at 30, 50, 75, and
100 percent of peak load or at four
points in the normal operating range of
the gas turbine, including the minimum
point in the range and peak load. All
loads shall be corrected to ISO
conditions using the appropriate
equations supplied by the manufacturer.
(2) The analytical methods and
procedures employed to determine the
nitrogen content of the fuel being fired
shall be approved by the Administrator
and shall be accurate to within ±5
percent.
(b) The method for determining
compliance with § 60.333, except as
provided in | 60.8(b), shall be as
follows:
(1) Reference Method 20 for the
concentration of sulfur dioxide and
oxygen or
(2) ASTM D2880-71 for the sulfur
content of liquid fuels and ASTM
D1072-70 for the sulfur content of
gaseous fuels. These methods shall also
be used to comply with § 60.334(b).
(c) Analysis for the purpose of
determining the sulfur content and the
nitrogen content of the fuel as required
by § 60.334(b), this subpart, may~be
performed by the owner/operator, a
service contractor retained by the
owner/operator, the fuel vendor, or any
other qualified agency provided that the
analytical methods employed by these
agencies comply with the applicable
paragraphs of this section.
(Sec. 114 of the Clean Air Act as amended {42
U.S.C. 1857c-91J).
Proposed/effective
42 FR 53782, 10/3/77
Promulgated
44 FR 52792, 9/10/79 (101)
111-68
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Svbpart HHStandard* of Perfor-
mance for Urn* Manufacturing
riant* 85
{60.340 Applicability and designation of
affected facility.
(a) The provisions of this subpart
are applicable to the following affect-
ed facilities used in the manufacture
of lime: rotary lime kilns and lime hy-
drators.
(b) The provisions of this subpart
are not applicable to facilities used in
the manufacture of lime at kraft pulp
mills.
(c) Any facility under paragraph (a)
of this section that commences con-
struction or modification after May 3,
1977, is subject to the requirements of
this part.
§ 60.341 Definitions.
As used in this subpart, all terms not
defined herein shall have the same
meaning given them in the Act and in
subpart A of this part.
(a) "Lime manufacturing plant" in-
cludes any plant which produces a
lime product from limestone by calci-
nation. Hydration of the lime product
is also considered to be part of the
source.
(b) "Lime product" means the prod-
uct of the calcination process includ-
ing, but not limited to, calcitic lime,
dolomitic lime, and dead-burned dolo-
mite.
(c) "Rotary lime kiln" means a unit
with an inclined rotating drum which
is used to produce a lime product from
limestone by calcination.
(d) "Lime hydrator" means a unit
used to produce hydrated lime prod-
uct.
{ 60.342 Standard for participate matter.
(a) On and after the date on which
the performance test required to be
conducted by §60.8 is completed, no
owner or operator subject to the provi-
sions of this subpart shall cause to be
discharged Into the atmosphere:
(1) Prom any rotary lime kiln any
gases which:
(i) Contain particulate matter in
excess of 0.15 kilogram per megagram
of limestone feed (0.30 Ib/ton).
(ii) Exhibit 10 percent opacity or
greater.
(2) Prom any lime hydrator any
gases which contain particulate matter
in excess of 0.075 kilogram per mega-
gram of lime feed (0.15 Ib/ton).
§ 60.343 Monitoring of emissions and op-
erations.
(a) The owner or operator subject to
the provisions of this subpart shall in-
stall, calibrate, maintain, and operate
a continuous monitoring system,
except as provided in paragraph (b) of
this section, to monitor and record the
opacity of a representative portion of
the gases discharged into the atmos-
phere from any rotary lime kiln. The
span of this system shall be set at 40
percent opacity.
(b) The owner or operator of any
rotary lime kiln using a wet scrubbing
emission control device subject to the
provisions of this subpart shall not be
required to monitor the opacity of the
gases discharged as required in para-
graph (a) of this section, but shall in-
stall, calibrate, maintain, and operate
the following continuous monitoring
devices:
(DA monitoring device for the con-
tinuous measurement of the pressure
loss of the gas stream through the
scrubber. The monitoring device must
be accurate within ±250 pascals (one
inch of water).
(2) A monitoring device for the con-
tinuous measurement of the scrubbing
liquid supply pressure to the control
device. The monitoring device must be
accurate within ±5 percent of design
scrubbing liquid supply pressure.
(c) The owner or operator of any
lime hydrator using a wet scrubbing
emission control device subject to the
provisions of this subpart shall install,
calibrate, maintain, and operate the
following continuous monitoring de-
vices:
(DA monitoring device for the con-
tinuous measuring of the scrubbing
liquid flow rate. The monitoring
device must be accurate within ±5 per-
cent of design scrubbing liquid flow
rate.
(2) A monitoring device for the con-
tinuous measurement of the electric
current, in amperes, used by the scrub-
ber. The monitoring device must be ac-
curate within ±10 percent over its
normal operating range.
(d) For the purpose of conducting a
performance test under §60.8, the
owner or operator of any lime manu-
facturing plant subject to the provi-
sions of this subpart shall install, cali-
brate, maintain, and operate a device
for measuring the mass rate of lime-
stone feed to any affected rotary lime
kiln and the mass rate of lime feed to
any affected lime hydrator. The mea-
suring device used must be accurate to
within ±5 percent of the mass rate
over its operating range.
(e) For the purpose of reports re-
quired under §60.7(c), periods of
excess emissions that shall be reported
are defined as all six-minute periods
during which the average opacity of
the plume from any lime kiln subject
to paragraph (a) of this subpart is 10
percent or greater.
(Sec. 114 of the Clean Air Act, as amended
(42U.S.C. 7414).)
{ 60.344 Test methods and procedures.
(a) Reference methods in Appendix
A of this part, except as provided
under §60.8(b), shall be used to deter-
mine compliance with J60.322(a) as
follows:
(1) Method 5 for the measurement
of particulate matter,
(2) Method 1 for sample and velocity
traverses,
(3) Method 2 for velocity and volu-
metric flow rate,
(4) Method 3 for gas analysis,
(5) Method 4 for stack gas moisture,
and
(6) Method 9 for visible emissions.
(b) For Method 5, the sampling time
for each run shall be at least 60 min-
utes and the sampling rate shall be at
least 0.85 std m'/h, dry basis (0.53
dscf/min), except that shorter sam-
pling times, when necessitated by pro-
cess variables or other factors, may be
approved by the Administrator.
(c) Because of the high moisture
content (40 to 85 percent by volume)
of the exhaust gases from hydrators,
the Method 5 sample train may be
modified to include a calibrated orifice
immediately following the sample
nozzle when testing lime hydrators. In
this configuration, the sampling rate
necessary for maintaining isokinetic
conditions can be directly related to
exhaust gas velocity without a correc-
tion for moisture content. Extra care
should be exercised when cleaning the
sample train with the orifice in this
position following the test runs.
(Sec. 114 of the Clean Air Act, as amended
(42U.S.C. 7414).)
Proposed/effective
42 FR 22506, 5/3/77
Promulgated
43 FR 9452, 3/7/78 (85)
111-69
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Appendix AReference Methods
8
The reference methods in this appendix at nfcrrcd to
in I 6n.8 (Performance Tests) and 1(50.11 (Cortiplttnc*
With SUnOvdg and Maintenance Requirement*) of 40
CFR Part W, Subpart A (General Provisions). Speclfle
uses ol those reference methods axe described in tb«
standards o( performance contained in the subparts,
beginning with Subnart D. .
Vvltlu'n each standard ot performance, a section titled
"Tost Methods ami Procedures" Is provided to (1)
identify the test methods applicable to the facility
subject to the respective standard and (2) identify any
special instructions or conditions to be followed when
applying a nvthod to the respective facility. Bucb in-
structions (for example, establish sampling rates, vol-
umes, or temperatures) are to be used either In addition
lo, or as a substitute for procedures In a reference method.
Himilarly, tor sources subject to emission monitoring
requirements, specific Instraetloni pertaining to any us*
of a reference method ore provided f» (he stibpart «r to
Appendix B.
Inclusion of methods In thii appendix is not Intended
M to endorsement or denial of their applicability to
sources that arc not subject to standards of performance.
Th« methods an potentially applicable to other source*;
however, applicability should be confirmed by earefal
and appropriate evaluation of the conditions prevalent
at such sources.
The approach followed in the formulation of the ref-
erence methods Involves specifications for equipment.
procedures, and performance. In concept, a performance
specification approach would be preferable in all methods
because Him allows tlie greatest flexibility to the user.
In pract ice, hoi\ ever, this approach is impi act ical in most
eases bcramB performance, specifications cannot be
established. Most of the methods describe^ herein,
therefore, involve specific equipment siwciflcations and
procedures, and only a few methods iti this appendix rely
on peiformance critciia.
Minor changes in MIC reference methods should not
necessarily nffcct the validity of the results and it Is
recounted that aliernativn and equivalent methods
exikt Section fiO R prnvidis authority for the Administra-
tor to specify or approve (1) equivalent methods, (2)
alternative methods, and (3) minor elianpes in the
methodology of the reference methods. It should be
clearly understood that unless otherwise identified all
such methods and changes must have pimr approval of
the Administrator. An ow nfr emploj ing sueh methods or
deviations from the reference methods n ithout oblainlnn
prior approval docs so at the risk of subsequent disarm
proval and reteslmg with approved methods.
Within the reference methods, certain sprclflc equip-
ment or procedures are recognized as being acceptable
er potentially acceptable and are siieeillcalTy Identilied
In the methods. The items Identified as acceptable op-
lions may be used without approval but mnst be identi-
fied in the test report. Tfio potentially gpprovablc on-
tkmi are cited as "subject to the approval of the
Administrator" or as "or equivalent." Such potentially
approvable techniques or alternatives may be used at the
discretion of the owner without prior approval. However,
detailed descriptions for applying these potentially
approvable techniques or alternatives are not provided
In the reference methods. Also, the potentially approv-
able options are not necessarily acceptable in all applica-
tion*. Therefore, an owner elecllng to use such po-
tentially approvable techniques or alternative!! is re-
sponsible for: (1) assuring that the techniques or
alternatives are in laot applicable and are properly
executed; (2) Including a written description of the
alternative method in the test report (the written
method must be clear and must be capable of hninx per-
formed without additional Instruction, and the degree
ol detail should be similar to the detail contained In the
reference methods); and (3) providing any rationale er
supporting data necessary to show the validity of lAe
alternative In the particular application. Failure to
meet these requirement! can result In the Adminis-
trator's disapproval of the alternative.
69
MITITOD 1 SAMPLE AND VEI.OCITY TnivmxKs
STATIONABT Sormr.s 69
50
0.5
DUCT DIAMETERS UPSTREAM FROM FLOW DISTURBANCE (DISTANCE A)
1.0 1.5 2.0
2.5
40
O
Q,
UJ
UJ
> 30
or
ec
UJ
20
* 10
\
T
A
i
I
}
i
PiUBB
i
I
^
'DISTURBANCE
MEASUREMENT
£- SITE
DISTURBANCE
N. ]
* FROM POINT OF ANY TYPE OF
DISTURBANCE (BEND, EXPANSION. CONTRACTION, ETC.)
6789
*
10
DUCT DIAMETERS DOWNSTREAM FROM FLOW DISTURBANCE (DISTANCE B)
Figure 1-1. Minimum number of traverse points for particulate traverses.
Ill-Appendix A-l
-------
1. rtiHfiofcai
1.1 Principle. To aid in the reprcvntat^c measure-
ment of pollutant emissions and/or total volumetric Bow
rate from a stationary source, a measurement site where
the effluent stream Is flowing in a known direction is
selected, and the cross-section o( the 'tack is divided Into
a number of ennui areas. A traverse point i« (lien located
within each of these equal areas.
1.2 Applicability. This method is applicable to flow-
inf fit streams m ducts, stacks, and flues. The method
cannot be nsed when: (1) flow is cyclonic or swirling (see
Section 2.4), <2> a stack is smaller than about 0.30 meter
(12 in.) in diameter, or 0.071 m' (113 in.7) in cross-sec-
tional area, or (3) the measurement fit? is less than two
stark or duct diameters downstream or less (linn a half
diameter upstream from a Sow disturbance.
The requirements of this method must be considered
before construction of a new facility from which emissions
will bt measured; failure to do so ma} require subsequent
alterations to the stack or deviation from the standard
procedure, rases Involving variants arc subject to ap-
proval by the' Administrator. U.S. Environmental
Protection Agency.
2.1 Selection of Measurement Silc. Sampling or
velocity measurement is performed at a site located »t
least eight stack or duct diameters downstream and two
diameters npslream from any flow disturbance such w
a bmd, expansion, or contraction in the stack, or from a
visible flame. If necessary, an alternative location may
be selected, at a position at least two stack or duct di-
ameters downstream and a half diameter upstream from
any flow disturbance. For a rectangular cross section,
an equivalent diameter (/>.) shall be calculated from the
following equation, to determine the upstream and
downstream distances:
n 2LIF
"'~L+W
where t=length and VK=width.
2.8 Determining the Number of Traverse Points.
2.2.1 Paniculate Traverses. When the eight- and
two-diameter criterion can be met, the minimum number
of traverse points shall be: (1) twelve, for circular or
rectangular stacks with diameters (or equivalent di-
ameters) greater than 0.61 meter (24 in.); (2) eight, for
circular stacks with diameters between 0.30 and 0.61
meter (12-24 m.); (3) rune, for rectangular stacks with
equivalent diameters between 0.30 and 0.61 meter (12-24
in.).
When the eight- and two-diameter criterion cannot be
met, the minimum number of traverse points is deter-
mined from Figure 1-1. Before referring to the figure,
however, determine the distances from the chosen meas-
urement site to the nearest upstream and downstream
disturbances, and divide each distance by the stack
diameter or equivalent diameter, to determine the
distance m terms of the number of duct diameters. Then,
determine from Figure 1-1 the minimum number of
traverse points that corresponds: (1) to the number of
duct diameters upstream; and (2) to the number of
diameters downstream. Select the higher of the two
minimum numbers of traverse points, or a greater value,
so that for circular stacks the number is a multiple of 4,
and for rectangular stacks, the number is one of those
shown in Table 1-1.
TAME l-t. Crott-icctional Ivjoul fur rectangular stac*»
Ma-
trix
lay-
mi
3x3
--. 4x3
4x4
5x4
5x5
6x5
6x«
7x6
7x7
X'tmber of
trwtrtt points:
12..
It..
20-..
25..
30..
36..
43..
M..
2.2.2 Velocity (Non-Partlculate) Traverses. When
velocity or volumetric flow rate is to be determined (but
not particulat* matter), the same procedure as that for
partfculat* traverses (Section 2.2.1) is followed, except
that Figure 1-2 may be used Instead of Figure 1-1.
2.8 Cross-Sectional Layout and Location of Traverse
Points.
2.3.1 Circular Stacks. Locate the traverse points on
two perpendicular diametersaccordmg to Table 1-2 and
the example shown in Figure 1-3. Any equation (for
examples, see Citations 2 and 3 in the Bibliography) that
gives the same values,as those in Table 1-2 may be used
In lieu of Table 1-2. »'
For paniculate traverses, one of the diameters must be
In a plane containing the greatest expected concentration
variation, e.g , after bends, one diameter shall be in the
plane of the bend. This requirement becomes less critical
as the distance from the disturbance increases; therefore,
ther diameter locations may be used, subject to approval
of the Administrator.
In addition, for stacks having diameters greater than
0.01 m (24 in.) no traverse points shall be located within
2.8 centimeters (1.00 in.) of the stack walls, and for stack
diameters equal to or less than 0.61 m (24 in.), no traverse
points shall be located within 1.3cm (O.SOin.) of the stack
walls. To meet these criteria, observe the procedures
given below.
2.3.1.1 Stacks With Diameters Greater Than 0.61 m
(24 In.). When any of the traverse points as located in
Section 2.3.1 fall within 2.5cm (1.00in.) of the stack walls,
relocate tliem away from the stack walls to: (1) a distance
of 2.5 cm (1.00 in.); or (2) a distance equal to the nozzle
Inside diameter, whichever is larger. These relocated
traverse points (on each end of a diameter) shall be the
"adjusted" traverse points.
Whenever two successive traverse points are combined
to form a single adjusted traverse point, treat the ad-
Justed point as two separate traverse points, both In the
samphni; (or velocity measurement) procedure, and in
recording the data.
0.5
DUCT DIAMETERS UPSTREAM FROM FLOW DISTURBANCE (DISTANCE A)
1.0 1.8 2.0
2.5
50
CO
40
O
K
20
10
I
I
I
^TMSTURBANCE
MEASUREMENT
(- >- SITE
I
I
3456789
DUCT DIAMETERS DOWNSTREAM FROM FLOW DISTURBANCE (DISTANCE R)
10
Figure 1-2. Minimum number of traverse points for velocity (nonparticulate) traverses.
ill-Appendix A-2
-------
TRAVERSE
POINT
1
2
3
4
S
S
DISTANCE
% of diameter
it*
29 .5
70.S
85.3
95.6
Figure 1-3. Example showing circular stack cross section divided into
12 equal areat, with location of traverse points indicated.
Table 1-2. LOCATION OF TRAVERSE POINTS IN CIRCULAR STACKS
(Percent of stack diameter from inside wall to traverse point)
Traverse
point
number
on a .
diameter
1
2
3
4|
5'
6
7
8
9
10
11
12|
13~
14
15
16
17
18
19
20;
21
22
23
24
Number of traverse points on a diameter
2
14.6
85.4
4
6.7
25.0
75.0
93.3
6
4.4
14.6
29.6
70.4
85.4
95.6
8
3.2
10.5
19.4
32.3
67.7
80.6
89.5
96.8
10
2.6
8.2
14.6
22.6
34.2
65.8
77.4
85.4
91.8
97.4
12
2.1
6.7
11.8
17.7
25.0
35.6
64.4
75.0
82.3
88.2
93.3
97.9
14
1.8
5.7
9.9
14.6
20.1
26.9
36.6.
63.4
73.1
79.9
85.4
90.1
94.3
98.2
16
1.6
4.9
8.5
12.5
16.9
22.0
28.3
37.5
62.5
71.7
78.0
83.1
87.5
9K5
95'. 1
98.4
18
1.4
4.4
7.5
10.9
14.6
18.8
23.6
29.6
38.2
61.8
70.4
76.4
81.2
85.4
89.1
92.5
95.6
98.6
20
1.3
3.9
6.7
.9.7
12.9
16.5
20.4
25.0
30.6
38.8
61 .2
69.4
75.0
79.6
83.5
87.1
90.3
93.3
96.1
98.7
22
1.1
3.5
6.0
8.7
11.6
14.6
18.0
21.8
26.2
31.5
39.3
60.7
68.5
73.8
78.2
82.0
85.4
88.4
91.3
94.0
96.5
98.9
24
1.1
3.2
5.5
7.9
10.5
13.2
16.1
19.4
23.0
27.2
32.3
39.8
60.2
67.7
72'.8
77.0
80.6
83.9
86.8
89.5
92.1
94.5
96.8
98.9
"minimum number of points" matrix were
expanded to 36 points, the final matrix
could be 9x4 or 12x3, and would not neces-
sarily have to be 6x6. After constructing the
final matrix, divide the stack cross-section
into as many equal rectangular, elemental
areas as traverse points, and locate a tra-
verse .point at the centroid of each equal
area.87
The situation of traverse points being too close to the
stack mils is not expected to arise with rectangular
stacks. If this problem should ever arise, the Adminis-
trator must be contacted for resolution of tbe matter.
2.4 Verification of Absence of Cyclonic Plow. In moat
stationary sources, the direction of stack gas flow la
essentially parallel- to the stack walla. However,
eyctonk flow may exist (1) after such device* as cyclone*
and Inertia! demlsten following Tentnri scrubbers, or
(!) ID (tacka bavb« tanfenOal inlets or other duct eon-
jtoratiou which tend to Induct swirling; in these
Instance*, the presence or absence of cyclonic flow at
the sampling location must be determined. The follerwing
techniques are acceptable for this determination.
0
0
o
1
1
0 , 0
r !
0 j 0
1
o 1 o
1
0
o
0
Figure 1-4. Example showing rectangular stack crosi
section divided into 12 equal areas, with a traverse
point at centroid of each area.
Level and zero the manometer. Connect a Type 8
pitot tube to the manometer. Position the Type 8 pitot
tube at each traverse point. In succession, so that the
planes of the lace openings of the pitot tube are perpendic-
ular to the stack cross-sectional ptene: when the Type 8
pitot tube is in this po&ition, it Is at "0° reference.' Note
tbe differential pressure (Ap) reading at each traverse
point. If a null (zero) pitot reading is obtained at fr
reference at a given traverse point, an acceptable flow
condition Mists at that point. If the pitot readingls not
lero at 0° reference, rotate the pitot tube (up to ±9(r yaw
angle), until armllreading is obtained. Carefully determine
and record the value of the rotation angle (a) to the
nearest degree. After the null technique has been applied
at each traverse point, calculate th* average of the abso-
lute values of a; assign a values of 0° to those points for
which no rotation was required, and include these in the
overall average. If the averageValue ot or is greater than
10°, the overall flow condition in the stack is unacceptable
and alternative methodology, subject to the approval of
the Administrator, must be used to perform accurate
sample and velocity traverses. 87
3. Bibliogmpki
1 Determining Dust Concentration in a Gas Stream.
A3ME. Performance Test Code No. 27. New York.
1057
2 Devorkln, Howard, et al. Air Pollution Source
Testing Manual. Air Pollution Control District. Los
Angeles, CA. November 1963
3 Methods for Determination of Velocity, Volume,
Dust and Mist Content of Oases. Western Precipitation
Division of Joy Manufacturing Co. Los Angeles, CA.
Bulletin WP-50.1968. ' .
4 Standard Method for Sampling Stacks for Particulate
Matter. In: 1971 Book of ASTM Standards, Part 23.
ASTM Designation D-2928-71. Philadelphia, Pa. 1971.
5. Hanson, H. A., et al. Particulate Sampling Strategies
for Large Power Plants Including Nonuniform Flow.
USEPA, OBD, ESRL, Research Triangle Park, N.C.
EPA-600/2-7fr-170. June 1976.
8. Entropy Environmentalists, Inc. Determination of
the Optimum Number of Sampling Points: An Analysis
of Method 1 Criteria. Environmental Protection Agency.
Research Triangle Park, N.C. EPA Contract No. 68-01-
3172, Task 7.
2312 Stacks With Diameters Equal to or Less Than
061 m (24 in.). Follow the procedure in Section 2.3.1.1,
noting only that any "adjusted" points should bo
relocated away from the stack walls to: (1) a distance of
13 cm (0.50 in.); or (2) a distance equal to the noule
Inside diameter, whichever is larger.
2.3.2 Rectangular Stacks. Determine the number
of traverse points as eiplalned in Sections 2.1 and 2.2 at
this method. From Table 1-1, determine the grid con-
figuration Divide the stack cross-section Into as many
equal rectangular elemental areu u traverse points.
and then locate a traverse point at the centroid of each
equal area according to the trample in Figure 1-4.
If the tester desires to use more than the
minimum number of traverse points,
expand the "minimum number of traverse
points" matrix (see Table 1-1) by adding the
extra traverse points along one or the other
or both legs of the matrix; the final matnx
need not be balanced. For example, if a 4x3
III-Appendix A-3
-------
METHOD 2DETERMINATION or STACK GAS VELOCITY
AND VOLUMETRIC FLOW KATE (TYPE S PITOT TUBE) °y
1. Principle and Applicability
1.1 Principle. The average gas velocity in a stack is
letermined from the gas density and from measurement
)f the average velocity head with a Type S (Stausscheibe
or reverse type) pitot tube.
1.2 Applicability. This method Is applicable for
measurement of the average velocity of a gas stream and
for quantifying gas flow.
This procedure is not applicable at measurement sites
which fail to meet the criteria of Method 1, Section 2.1.
Also, the method cftnnot be used for direct measurement
In cyclonic or swirling gas streams. Section 2.4 of Method
1 shows how to determine cyclonic or swirling now con-
ditions. When unacceptable conditions exist, alternative
procedures, subject to the approval of the Administrator,
U.S. Environmental Protection Agency, must be em-
ployed to make accurate flow rate determinations:
examples of such alternative procedures are: (1) to install
straightening vanes; (2) to calculate the total volumetric
flow rate stoichionietrically, or (3) to move to another
measurement site at which the flow is acceptable.
2. Apparatus
Specifications for the apparatus are given below. Any
other apparatus that has been demonstrated (subject to
approval of the Administrator) to be capable of meeting
toe specifications will be considered acceptable.
2.1 Type 8 PJtot Tube. The Type 8 pitot tabe
(Figure 2-1) shall be made of metal tubing (e.g., stain-
less steel). It is recommended that the external tubing
diameter (dimension D,, Figure 2-2b) be between 0.71
and 0.% centimeters (X« and H inch). There shall b«
an equal distance from the base of each leg of the pitot
tabe to its face-opening plane (dimensions Pj and Pi,
Figure 2-2b); it is recommended that this distance be
between 1.06 and 1.80 times the eiternal tubing diameter.
The face openings of the pitot tube shall, preferably, be
aligned as shown in Figure 2-2; however, slight misalign-
ments of the openings are permissible (see Figure 2-3).
The Type 8 pitot tube shall have a known coefficient,
determined as outlined in Section 4. An identification
number shall be assigned to the pitot tube; this number
(hall be permanently marked or engraved on the body
f the tube.
1.90 -2.54 cm'
(0.75-1.0 in.)
tVEH
, 7
^^^
f.62 cm (3 in.)*
TEMPERATURE SENSOR
MANOMETER
SUGGESTED (INTERFERENCE FREE)
PITOT TUBE THERMOCOUPLE SPACING
Figure 2-1. Type S pitot tube manometer assembly.
III-Appendix A-4
-------
TRANSVERSE
TUBE AXIS
FACE
OPENING
PLANES
(a)
A SIDE PLANE
LONGITUDINAL
TUBE AXIS *
' Ot
A
\ * 8
r
B SIDE PLANE
(b)
PA
NOTE:
1.05Dt
-------
TRANSVERSE
TUBE AXIS "
j W I
LONGITUDINAL
TUBE AXIS
(l)
Figure 2-3. Types of face-opening misalignment that can result from field use or Im-
proper construction of Type S pitot tubes. These will not affect the baseline value
of Cfp{s) so long as ai and a2 < 10°, 01 and 02 < 5°. z < 0.32 cm (1/8 In.) and w <'
0.08 cm (1/32 in.) (citation 11 in Section 6).
Ill-Appendix A-6
-------
A standard pitot tube may be used instead of a Type 8,
provided that it meets the specifications of Sections 2.7
und 4 2; note, however, that the static and impact
pressure holes of standard pitot tubes are susceptible to
plunging in particulate-laden gas streams Therefore,
whenever a standard pitot tube- is tisnd to perform »
traverse, adequate proof must tie furnished that the
openings of the pitot tube have not pluirced up during the
Ii iverse period, This can be done by taking a velocity
liead lip) reiuiiMK at the final traverse point, cleaning out
the impact and static holes of the standard pitot tube by
"iui'k-piiremg" with pressurized air, and then taking
another A/> reading. If the Ap readings made before and
after the :ur puree are the sime (±5 pereent). the traverse
!« luwptahle. Otherwise, reject tlie run N'nte that if Ap
at the final tiaverse point is unsuitably low, another
point may be selected. If "hack-purging" at regular
intervals is part of the procedure, then comparative Ap
readings shall be taken, as above, for the last two backQ7
purges at which suitably high Ap readings are observed.*>'
'22 Differential Pressure Gauge An inclined manom-
eter or equivalent device is used. Most sampling trains
are equipped w.th a 10-in. (water column) inclined-
vertical manometer, having 0.01-in. HjO divisions on the
f> to 1-in inclined scale, and 0,1-ln. HaO divisions on the
1- to 10-in. vertical scale. This type of manometer (or
other gauge of equivalent sensitivity) is satisfactory for
the measurement of Ap values as low as 1 3 mm (0 06 in )
HjO. Uowever, a differentia! pressure gauge of greater
sensitivity shall be used (subject to the approval of the
Administrator), if any of the following is found to bo
true: (1) the arithmetic average of all Ap readings at the
traverse points in the stack is less than 1 3 mm (0.06 In.)
IXiO; (2) for traverses of 12 or more points, more than 10
percent of the individual Ap readings are below 1.3 mm
(0.05 in.) H>O; (3) for traverses of fewer than 12 points,
more than one Ap reading is below 1.3 mm (006 in.) H:O.
Citation 18 in Section 8 describes commercially available
instrumentation for the measurement of low-range gas
velocities."'
As an alternative to criteria (1) through (3) above, the
following calculation may be performed to determine the
necessity of using a more sensitive differential pressure
gauge.
where:
Ap,= Individual velocity head reading at a traverse
point, mm HjO (in. H.O).
n = Total number of traverse points.
A'=0.13 mm HiO when metric units are used and
0.005 in HiO when English units are used.
If T is greater than 1.05, the velocity head data are
unacceptable and a more sensitive differential pressure
gauge must be used.
NOTE.If differential pressure gauges other than
inclined manometers are used (e.g., magnehelic gauges),
their calibration must be checked after each test*series.
To check the calibration of a differential pressure gauge,
compare Ap readings of the gauge with those of a gauge-
oil manometer at a minimum of three points, approxi-
mately representing the range of Ap values in the stack.
If, at each point, the values of Ap as read by the differen-
tial pressure gauge and gauge-oil manometer agree to
within S percent, the differential pressure gauge shall t»
considered to be in proper calibration. Otherwise, the
test series shall either be voided, or procedures to adjtut
the measured Ap values and final results shall be used,
subject to the approval of the Administrator.
2.3 Temperature Gauge. A thermocouple, liquid-
filled bulb thermometer, bimetallic thermometer, mer-
cury-in-glass thermometer, or other gauge capable of
measuring temperature to within 1.5 percent of the mini-
mum absolute stack temperature shall be used. The
temperature gauge shall be attached to the pilot tube
such that the sensor tip does not touch any metal; th»
gauge shall be in an interference-free arrangement with
respect to the pitot tube face openings (see Figure 2-1
and also Figure 2-7 in Section 4). Alternate positions m»j
be used if the pitot tube-temperature gauge system ft
calibrated according to the procedure of Section 4. Pro-
vided that a difference of not more than 1 percent in the
average velocity measurement is introduced, the tem-
perature gauge need not be attached to the pilot tub*;
this alternative Is subject to the approval of the
Administrator.
2.4 Pressure Probe and Gauge. A piezometer tube and
mercury- or water-filled U-tube manometer capable of
measuring stack pressure to within 2.5 mm (0,1 in.) Jig
is used. The static tap of a standard type pitot tube or
one leg of a T>pe S pitot tube with the face opening
planes positioned parallel to the gas flow may also be
used as the pressure probe. 87
2.5 Barometer. A mercury, aneroid, or other barom-
eter capable of measuring atmospheric pressure to
within 2.5 mm I[g (0.1 In. llg) may be used. In many
cases, the barometric reading may be obtained from a
nearby national weather service station, in which case
the station value (which is the absolute barometric
pressure) shall be requested and an adjustment for
elevation differences between the weather station and
the sampling point shall be applied at a rate of minus
2.5 mm (0.1 In.) llg per 30-meter (100 foot) elevation
increase, or vice-versa tor elevation decrease.
2.6 Gas Density Determination Equipment. Method
3 equipment, if needed (see Section 3.6), to determine
the stack gas dry molecular weight, and Reference
Method 4 or Method 5 equipment for moisture content
determination; other methods may be used subject to
approval of the Administrator.
2.7 Calibration Pilot Tube. When calibration of the
Type 8 pitot tube is necessary (see Section 4), a standard
pitot tube is used as a reference. The standard pitot
tube shall, preferably, have a known coefficient, obtained
either (1) directly from the National Bureau of Stand-
ards, Route 270, Quince Orchard Road, Ualthersburg,
Maryland, or (2) by calibration against another standard
pitot tube with an NBS-traceable coefficient. Alter-
natively, a standard pitot tube designed according to
the criteria given in 2.7.1 through 2.7.5 below and Illus-
trated In Figure 2-4 (see also Citations 7, 8, and 17 In
Section 6) may be used. Pitot tubes designed according
to these specifications will have baseline coefficients of
about 0.99±0.01. '
2.7.1 Hemispherical (shown in Figure2-4), ellipsoidal,
or conical tip.
2.7.2 A minimum of six diameters straight run (based
upon D, the external diameter of the tube) between the
tip and the static pressure holes.
2.7.3 A minimum of eight diameters straight run
between the static pressure holes and the centerline at
the external tube, following the 90 degree bend.
2.74 Static pressure holes of equal size (approximately
O.I D), equally spaced in a piezometer ring configuration.
2.7.5 Ninety degree betid, with curved or mitered
junction.
2.8 Differential Pressure Gauge for Type 8 Pitot
Tube Calibration. An inclined manometer or equivalent
Is used. If the single-velocity calibration technique Is
employed (see Section 4.1.2.3), the calibration differen-
tial pressure gauge shall be readable to the nearest 0.13
mm HzO (0.005 In. HiO). For multiveloclty calibrations,
the gauge shall be readable to the nearest 0.13 mm HiO
(0.005 In H.O) for Ap values between 1.3 and 25 mm HiO
(0.05 and 1.0 In. HjO), and to the nearert 1.3 mm HjO
(0,06 in. H>O) for Ap values above 25 mm HiO (1.0 la.
HtO). A special, more sensitive gauge will be required
to read Ap values below 1.3 mm HiO [0.06 in. HiO]
(see Citation 18 In Section 6).
icn
CURVED OR
MITERED JUNCTION
STATIC
HOLES
HEMISPHERICAL
TIP
Figure 24. Standard pitot tube design specifications.
3. Pnutout
3.1 Set up the apparatus as shown in Figuje 2-1.
Capillary tubing or surge tanks installed between the
manometer and pilot tube may be used to dampen Ap
fluctuations. It is recommended, but not required, that
a pretest leak-check be conducted, as follows: (1) blow
through the pitot impact opening until at least 7.6 om
(3 in.) HiO velocity pressure registers on the manometer;
then, close off the impact opening. The pressure shall
remain stable for at least 15 seconds; (2) do the same for
the static pressure side, except using suction to obtain
the minimum of 7.8 em (3 in.) HiO. Other leak-cheek
procedures, subject to the approval of the Administrator,
may be uaed.
3.2 Level and zero (he manometer. Because the ma-
nometer level and zero may drift due to vibrations and
temperature changes, make periodic checks during the
traverse. Record all necessary data as shown in the
example data sheet (Figure 2-5).°'
3.3 Measure the velocity head and temperature at the
traverse points specified by Method 1. Ensure that the
proper differential pressure gauge is being used for the
range of Ap values encountered (see Section 2.2). If it is
necessary to change to a more sensitive gauge, do so, and
remeasure the Ap and temperature readings at each tra-
verse point. Conduct a post-test leak-check (mandatory),
as described in Section 3.1 above, to validate the traverse
run.
3.4 Measure the static pressure in the stack. One
reading is usually adequate.
3.5 Determine the atmospheric pressure.
Ill-Appendix A-7
-------
PLANT.
DATE.
.RUN NO.
STACK DIAMETER OR DIMENSIONS, m(in.)
BAROMETRIC PRESSURE, mm Hg (in. Hg)
CROSS SECTIONAL AREA, m2(ft2)
OPERATORS -
PITOTTUBEI.D. NO.
AVG. COEFFICIENT,Cp = .
LAST DATE CALIBRATED.
SCHEMATIC OF STACK
CROSS SECTION
Traverse
Pt.No.
V«I.Hd..Ap
mm (in.) H20
Stack Temperature
ts.0C(°F)
Average
Tj,0K{°fl)
P9
mm Hg (in.Hg)
.
>T*T
Figure 2-5. Velocity traverse data.
Ill-Appendix A-8
-------
3.6 Determine the stack gas dry molecular weight.
For combustion processes or processes that emit eeatn-
lially COi, Oi, CO, und.Ni, use Method 3. For procesMt
1'inittlng essentially air, an analysis need not be con-
ducted; use a dry molecular -weight ot 29.0. For other
processes, other methods, subject to the approval of the
Administrator, must be used.
:i 7 Obtain the moisture content from Reference
Method 4 (or equivalent) or from Method 5.
3 8 Determine the cross-sectional area of the stack
or duct at the sampling location. Whenever possible,
pnysically measure the stack dimensions rather than
iiMiig blueprints.
4 Calihialion
4.1 Type S Pilot Tube. Before its initial use, care-
fully examine the Type 8 pilot tube in top, side, and
end views to verify that the face openings of the tube
are aligned within the specifications illustrated in Figure
2-2 or 2-3. The pilot tube shall not be used if it fails to
meet these alignment specifications.
After verifying the face opening alignment, measure
and record the following dimensions of the pitof tube:
(a) the external tubing diameter (dimension D,, Figure
2-2b); and (b) the base-to-opening plane distance*
(dimensions PA and PB, Figure 2-2b). If D< Is between
0.48 and 0.98 cm (Mi and H In.) and If PA and Pa an
equal and between 1.09 and l.SOD,, there are two possible
options: (1) the pilot tube may be calibrated according
to the procedure outlined In Sections 4.1,2 through
4.1.5 below, or (2) a baseline (Isolated tube) coefficient
value of 0.84 may bo assigned to the pitot tube. Note,
however, that if the pilot tube is part of an assembly,
calibration may still be required, despite knowledge-.
of the baseline coefficient value (see Section 4.11).K
If D,, PA., and PB are outside the specified limits, the
pitot tube must be calibrated as outlined in 4.1 2 through
4.1.5 below.
4.1.1 Type 8 Pitot Tube Assemblies. During sample
aud velocity traverses, Ihe isolated Type 8 pitot tube li
not always used: in many Instances, the pitot tube Is
used In combination with other source-sampling compon-
ents (thermocouple, sampling probe, nozzle) as part of
an "assembly." The presence 01 other sampling compo»
nents can sometimes aflect the baseline value of the Type
8 pitot tube coefficient (Citation 9 In Section «); therefore
an assigned (or otherwise known) baseline coefficient
value may or may not be valid for a given assembly. The
baseline and assembly coefficient values will be Identical
only when the relative placement of the components la
the assembly Is such that aerodynamic Interference
effects are eliminated. Figures 2-6 through 2-8 Illustrate
Interference-free component arrangements for Type 8
pitot tubes having external tubing diameters between
0.41 and 0.96 cm (Me and H In.). Type 8 pitot tube assem-
blies that fall to meet any or all of the specifications of
Figures 2-6 through 2-8 shall be calibrated according to
Ftne procedure outlined In Sections 4.1.2 through 4.1.8
below, and prior to calibration, the values of the inter-
component spacings (pitot-nozzle, pilot-thermocouple,
pitot-probe sheath) shall be measured and recorded.
NOTE.Do not use any Type 8 pitot tube assembly
which is constructed such that the Impact pressure open-
Ing plane of the pilot tube Is below the entry plane of the
noule (see Figure 2-6b).
4.1.2 Calibration Setup. If the Type 8 pitot tube Is to
be calibrated, one leg of the tube shall be permanently
marked A, and the other, B. Calibration shall be done In
a flow system having the following .essential design
features: 87
I
TYPES PITOT TUBE
T x £ 1.90 em (3/4 in.) FOR On -1.3 cm (1/2 in.)
SAMPLING NOZZLE
A. BOTTOM VIEW; SHOWING MINIMUM PITOT-NOZZLE SEPARATION.
SAMPLING
PROBE
\
SAMPLING
NOZZLE
I
~
TYPES
PITOT TUBE
STATIC PRESSURE
OPENING PLANE
IMPACT PRESSURE
OPENING PLANE
NOZZLE ENTRY
PLANE
B. SIDE VIEW; TO PREVENT PITOT TUBE
FROM INTERFERING WITH GAS FLOW
STREAMLINES APPROACHING THE
NOZZLE. THE IMPACT PRESSURE
OPENING PLANE OF THE PITOT TUBE
SHALL BE EVEN WITH OR ABOVE THE
NOZZLE ENTRY PLANE.
Figure 2-6. Proper pitot tube sampling nozzle configuration to prevent
aerodynamic interference; buttonhook type nozzle; centers of nozzle
and pitot opening aligned; Dt between 0.48 and 0.95 cm (3/16 and
3/8 in.).
Ill-Appendix A-9
-------
THERMOCOUPLE
^ d
(3in.) H
^
__ . jw ,
Z> 1.90 cm (3/4 in.)
^ Ot TYPE SPITOT TUBE C. lO
THERMOCOUPLE
1
Z>S.Olcm
(2 in.) '
1
1
SAMPLE PROBE
I
TYPESMTOTTUBE
SAMPLE PROBE
Figure 2-7. Proper thermocouple placement to prevent interference;
Dt between 0.48 and 0.95 cm (3/16 and 3/8 in.).
TYPE SPITOT TUBE
Figure 2-8. Minimum pitot-sample probe separation needed to prevent interference;
between TJ.48 and 0.95 cm (3/16 and 3/8 in.).
4.1 J.1 Ttt» flowing CM stream ranst be confined to
duct of definite cross-sectional area, either circular or
rectangular. For circular cross-sections, the minimum
duct diameter shall be 30JS cm (12 In.); -for rectangular
vow-sections, the width (shorter side) shall be at lent
V.4cm (10 in.).
4.1.2.* The cross-sectional area of the calibration -duet
nut be constant over a distance of 10 or more duet
diameters. For a rectangular cross-section, use an equlva-
lent diameter, calculated from the following equation,
to determine toe number of duct diameters:
D.-
2LW
Equation 2-1
where:
D.« Equivalent diameter
I,-Length
If-Wtdth
To ensure the presence of stable, fully developed flow
patterns at the calibration site, or "t«st section," the
site must be located at least eight diameters downstream
and two diameters upstream from the nearest disturb-
ances.
NOTE.The eight- and two-diameter criteria are not
absolute; other test section locations may be used ((ob-
ject to approval of the Administrator), provided that the
flow at the test site la stable and demonstrably parallel
to the duct axis.
4.1.1J The flow system shall have the capacity to
tsmnU a taft-ttetton velocity around «lt m/min (1,000
ft/mm). This velocity must be constant with time to
guarantee steady flow during calibration. Note that
Type S pitot tube coefficients obtained by single-velocity
calibration at 915 m/min (3,000 ft/min) will generally be
valid to within ±3 percent for the measurement of
velocities above 305 m/min (1,000 ft/min) and to within
±5 to 6 percent for the measurement of velocities be-
tween 180 and 305 m/min (800 and 1,000 ft/min). If a
more precise correlation between C, and velocity is
desired, the now system shall have the capacity to
generate at least four distinct, time-invariant test-section
velocities covering the velocity range from 180 to 1.525
m/min (600 to 5,000 ft/min), and calibration data shall
be taken at regular velocity intervals over this range
(toe Citation!) 9 and 11 in Section 6 tor details).
4.1.2.1 Two entry ports, one each for the standard
and Type 8 pttot tubes, shall be cut in the test section;
the standard pitot entry port shall be located slightly
downstream of the Type 8 port. BO that the standard
and Type 8 impact openings will lie in the same croas-
Ktional plane during calibration. To facilitate align-
ment of the pilot tubes during calibration, it is advisable
that the test section be constructed of pleiiglas or some
other transparent material.
4.1.3 Calibration Procedure. Note that this procedure
It a general one and must not be used without first
referring to the special considerations presented in Sec-
tion 4.1.5. Note also that this procedure applies Only to
single-velocity calibration. To obtain calibration data
for the A and B sides of the Type 8 pitot tube, proceed
u follows:
4.1.3.1 Hake sure that the manometer Is properly
filled and that the oil is free from contamination and is of
the proper density. Inspect and leak-check all pitot lines;
repair or replace if necessary.
4.1.3.2 Level and lero the manometer. Turn on the
fan and allow the flow to stabilize. Seal the Type S entry
pert.
4.1.8.3 'Ensure that the manometer is level and zeroed.
Position the standard pitot tube at the calibration point
(determined as outlined ip Sction 4.1.5.1), and align the
tube so that its tip Is pointed directly into the flow. Par-
ticular care should be taken in aligning the tube to avoid
yaw and pitch angles. Make sure that the entry port
surround i ig the tube is properly sealed.
4.1.3.4 Bead Ap.td and record its value in a data table
similar to the one shown in Figure 2-9. Remove the
standard pitot tube from the duct and disconnect it from
the manometer. Seal the standard entry port.
4.1.3.5 Connect the Type S pilot tube to the manom-
eter. Open the Type S entry port. Check the manom-
eter level and lero. Insert and align the Type S pitot tube
so that its A side impact opening is at the same point as
was the standard pitot tube and is pointed directly into
tlM Upw. Make sure that the entry port surrounding the
tube is properly sealed.
4.1.3.6 Read Ap, and enter its value in the data table.
Bemovc the Type S pitot tube from the duct and dis-
connect it from the manometer.
4.1.3.7 Repeat steps 4.1.3.3 through 4.1.3.6 above until
three pairs of Ap readings have been obtained.
4.1.3.8 Repeat steps 4.1.3.3 through 4.1.3.7 above for
the B side of the Type S pilot tube.
4.1.3.9 Perform calculations, as described In Section
4.1.4 below.
1.1.4 Calculations.
4.1.4.1 For each of the sli pairs of Ap readings (i.e.,
three from side A and three from side B) obtained in
Section 1.1.3 above, calculate the value of the Type S
pitot tube coefhcieiit as follows:
Ill-Appendix A-10
-------
PITOT TUBE IDENTIFICATION NUMBER:
CALIBRATED BYr,
.DATE:.
RUN NO.
1
2
3
"A" SIDE CALIBRATION
Apttd
em HjO
(in.H20)
AP($)
cmHaO
(in. HaO)
C~p (SIDE A)
CpW
DEVIATION
Cp
DEVIATION
Cp(s)-Cp(B)
AVERAGE DEVIATION o(AORB)
S|CpW.Cp(AORB)|
I » * I
MUSTBE from C, (sideA), and the deviation of
each B-side value of C,(.) from C, (side B). Use the tot
lowing equation:
Deviation = CV,>-C*p(A or B)
Equation 2-3
4.1.44 Calculate °, the average deviation from the
mean, for both the A and B sides of the pitot tube. Use
the following equation:
according to the criteria of Sections 2.7.1 to
2.7.5 of this method.
A»iu=Velocity head measured by the standard pitot
tube, cm HiO (In. HiO)
Ap,=Velocity bead measured bj the Type 8 pltot
tube, cm HiO (in. BiO)
4.1.4J Calculate C, (tide A), the mean A-slde coei-
. . ... . . _ . . .. flclent, and S, (side B), the mean B-dde coefficient;
Standard pltot tube coefficient; use 0.99 if the calculate the difference between these two averate
coefficient la unknown and the tube li designed '
Equation 2-2
a-r
C,(.)-TypeB pltot tube coefficient °'
3
(side A or B)
!CB(.,-CPUorB)|
Equation 2-4
4.1.4.5 Use the Type 8 pilot tube only it the values of
(side A) and * (side B) are less than or equal to 0.01
and If the absolute value of the difference between Ct
(A) and C, (B) Is 0.01 or less.
4.1.S Special considerations.
4.1.5.1 Selection of calibration point.
4.1.5.1.1 When an isolated Type S pltot tube is cali-
brated, select a calibration point at or near the center of
the duct, and follow the procedures outlined in Sections
4.1.3 and 4.1.4 above. The Type 3 pitot coefficient! so
obtained, I.e., (7, (side A) and C, (side B), will be valid,
so long as either: (1) the isolated pitot tube is used; or
(2) the pitot tube is used with other components (nozzle,
thermocouple, sample probe) In an arrangement that Is
free from aerodynamic interference effects (see Figures
2-6 through 2-8).
4.1.5.1.2 For Type 8 pltot tube-thermocouple com-
binations (without sample probe), select a calibration
point at or near the center of the duct, and follow the
procedures outlined In Sections 4.1.3 and 4.1.4 above;
The coefficients so obtained wilt be valid so long as the
pitot tube-thermocouple combination is used by itself
or with other components in an interference-free arrange*
ment (Figures 2-6 and 2-8).
4.1.5.1.3 For assemblies with sample probes, the
calibration point should be located at or near the center
of the duct; however, Insertion of a probe sheath into »
small duct may cause significant cross-sectional area
blockage and yield incorrect coefficient values (Citation 9
In Section 6). Therefore, to minimize the blockage effect,
the calibration point may be a few inches off-center if
necessary. The actual blockage effect will be negligible
when the theoretical blockage, as determined by a
projected-area model of the probe sheath, is 2 percent or
less of the duct cross-sectional area for assemblies without
eiternal sheaths (Figure 2-10a), and 3 percent or less for
assemblies with external sheaths (Figure 2-10b).
4.1.5.2 For those probe assemblies In which pitot
tube-nozzle interference is a factor (i.e., those in which
the pitot-nozzle separation distance fails to meet the
specification illustrated in Figure 2-6a), the value of
C,(,i depends upon the amount of free-space between
the tube and nozzle, and therefore is a function of nozzle
size. In these Instances, separate calibrations shall be
performed with each of the commonly used nozzle sizes
In place. Note that the single-velocity calibration tech-
nique is acceptable for this purpose, even though the
larger nozzle'sizes (> 0.635 cm or K in.) are not ordinarily
used tat isokinetlc sampling at velocities around 915
m/min (3,000 ft/min), which is the calibration velocity;
not* also that it is not necessary to draw an ispkinetje
sample during calibration (see Citation 19 in Section 6).°'
4.1.5.3 For a probe assembly constructed such that
HJ pltot tube is always used in the same orientation, only
one side of the pitot tube need be calibrated (the side
which will face the flow). The pitot tube must still meet
the alignment specifications of Figure 2-2 or 2-3, however,
and must have an average deviation (r) valup of 0.01 or
less (see Section 4.1.4.4).
III-Appendix A-11
-------
ESTIMATED P IxW ~l
SHEATH = x 100
BLOCKAGE LPUCTAREAj
Figure 2-10. Projected-area models lor typical pitot tube assemblies.
4.1.« Field UM and Recallbration.
4.1.6.1 Field Use.
4.1.6.1.1 When* Type S pilot tube (Isolated tube or
assembly) Is used In the flew, the appropriate coefficient
value (whether assigned or obtained by calibration) shall
be used to perform velocity calculations. For calibrated
Type 8 pilot tubes, the A. side coefficient shall be used
when the A side of the tube faces the flow, and the B side
coefficient shall be used when the B side faces the flow;
alternatively the arithmetic average of the A and B side
coefficient values may be used, irrespective of which side
laces the flow.
4.1.6.1.2 When a probe assembly Is used to sample a
small duct (12 to 36 in. in diameter), the probe sheath
sometimes blocks a significant part of the duct cross-
section, causing a reduction in the effective value of
7,(t>. Consult Citation 9 in Section 6 for details. Con-
ventional pilot-sampling probe assemblies are not
recommended for use in ducts having inside diameters
smaller than 12 inches (Citation 16 in Section 6).
4.1.6.2 Recalibration.
4.1.6.2.1 Isolated Pitot Tubes. After each field use, the
pitot tube shall be carefully reexamined in top. side, and
end views. If the pitot face openings are still aligned
within the specifications illustrated in Figure 2-2 or 2-3,
It can be assumed that the baseline coefficient of the pilot
tube has not changed. If, however, the tube has been
damaged to the extent that it no longer meets the specifi-
cations of Figure 2-2 or 2-3, the damage shall either be
repaired to restore proper alignment of the face openings
or the tube shall be discarded.
4,1.6.2.2 Pitot Tube Assemblies. After each field use,
check the face opening alignment of the pitot tube, as
in Section 4.1.6.2.1; also, remeasure the intercomponent
pacings of the assembly. If the Intercomponent spacings
have not changed and the face opening alignment is
acceptable, it can be assumed that the coefficient of the
assembly has not changed. If the face opening alignment
Is no longer within the specifications of Figures 2-2 or
S-S, either repair the damage or replace the pitot tube
(calibrating the new assembly, if necessary). If the Inter-
component spacings have changed, restore the original
(pacings or recalibrate the assembly.
4.2 Standard pitot tube (If applicable). If a standard
pitot tube is used for the velocity traverse, the tube shall
be constructed according to the criteria of Section 2.7 and
shall be assigned a baseline coefficient value of 0.99. If
to* standard pitot tab* Is used as part of an assembly.
the tube aball be In an Interference-free arrangement
(subject to the approval of the Administrator).
4J Temperature Gauges. After each field use, cali-
brate dial thermometers, liquid-filled bulb thermom-
eters, thermocouple-potentiometer systems, and other
gauges at a temperature within 10 percent of the average
absolute stack temperature. For temperatures up to
405° C (761° F), USB an ASTM mercury-in-glass reference
thermometer, or equivalent, as a reference; alternatively,
either a reference thermocouple and potentiometer
(calibrated by NBS) or thermometric fixed points, e.g.,
Ice bath and boiling water (corrected for barometric
pressure) may be used. For temperatures above 405° C
(761° F), use an NBS-calibrated reference thermocouple-
potentiometer system or an alternate reference, subject
to the approval of the Administrator.
If, during calibration, the absolute temperatures meas-
ured with the gauge being calibrated and the reference
gauge agree within 1.5 percent, the temperature data
taken in the field shall be considered valid. Otherwise,
the pollutant emission test shall either be considered
Invalid or adjustments (if appropriate) of the test results
shall be made, subject to the approval of the Administra-
tor.
4.4 Barometer. Calibrate the barometer used against
a mercury barometer.
Ill-Appendix A-12
-------
1. Calculation!
Carry out calculations, retaining at least one extra
decimal figure beyond that of the acquired data. Round
off figures after final calculation.
6.1 Nomenclature
X= Cross-sectional area of stack, m* (ft').
B., Water vapor In the gas stream (from Method 5 or
Reference Method 4), proportion by volume.
C,=Pitot tube coefficient, dimensionless.
Jf,= Pitot tube constant,
*,+Pi Equation 2-«
P.id = Standard absolute pressure, 760 mm Hg (29.02
In. Hg).
Q,d = Dry volumetric stack gas flow rate corrected to
standard conditions, dscm/hr (dscf/hr).
«.=Stack temperature, °C (°F).
T,=Absolute stack temperature, °K (°R).
273+(, for metric Equation 2-7
-460-M, tor English
Equation 2-8
r.u= Standard absolute temperarwrre, 293 °K (528° R)
p.Average stack gas velocity, m/sec (ft/sec).
Ap Velocity head of stack gas, mm H>0 (in. H»O).
3,600-Conversion factor, sec/hr.
18.0= Molecular weight of water, g/g-mole (Ib-lb-
mole).
5.2 Average staok gas velocity.
Equation 2-9
5.3 Average stack gas dry volumetric flow rate,
Equation 2-10
8. BttMotnplii
1. Mark, L. 8. Mechanical Engineers' Handbook. New
York. McQraw-HIU Book Co., IM. 1051.
2. Perry jr. H. Chemical Engineers' Handbook. N«w
York. McGraw-Hill Book Co.. Inc. 1980.
3 Shim-linni, R. T., W. F. Touil, ami W. S. Smith.
Sigmliomee, of Errors in Slack Sampling Measurements.
U.S. Environmental Protection Agency, Research
Ti Jangle Park, N.C. (Presented at the Annual Meeting of
the Air 1'ollution Control Association, St. Louis, Mo.,
June 14-19. l'J70.)
4. Standard Method for SampliiiK StiicR* for Particulale
M.iltiT. In: 1071 Book of ASTM Stamhmls Part 23.
I'liil.icli'lplim, Pa. 1U71. ASTM Designation O-LICJS-?!.
,"i \ iMiiuinl, J. K. Elnmentary Flunl Mocli.uHcs. New
Yiiik Idlin Wiley anil Sons, Inc. 1047.
0. Hunt MotoisThoir Theory and Application.
Ameiu'un riot'ioty of Mechanical EiiKim't'is, Now York,
N Y I'i'i'l
7. A>ll U.VE ITnndlmnk of Fiin. Vull.iro, R. K. (tuitlflines for T>|n- S I'ilot Tul»
<'allliration. U.S. Environmental Hiotri'lioii Agency.
Hi'seaich TrianglePaik, N.C. (Hrosented at 1st Annual
Meeting, Souiec Evaluation Society, Dayton, Ollio,
September 18, 1075.) 87
10. Voliaro, R. F. A Type S 1'itot Tutxi Calibration
Study. U.S. Enviroinnental Protection Agency, Emis-
sion Measurement Biauch, Research Tiiangle Park,
N.C. July 1974.
11. Voliaro, R. F. The Effects of Impact Opening
Misalignment on the Value of the Typo S Pitot Tube
Coefficient. US. Environmental Piotection Agency,,
Emission Measurement Branch, Research Triangle
1'ark, N.C. October 1976.
12. Voliaro, R. F. Establishment of a Baseline, Coeffi-
cient Value for Properly Constructed Type S Pitot
Tubes. U.S. Environmental Protection Agency, Emis-
Mon Measurement Branch, Researcli Tiiangle Park,
N.O. November 1976.
13. Voliaro, R. F. An Evaluation of Single-Velocity
Calibration Technique as a Means of Determining Type
S Pilot Tube Coefficients. U.S. Environmental Protec-
tion Agency, Emission Measmemeivt Blanch, Research
Triangle Park, N.C. August 1975.87
14 Vollaro, R. F. The Us« of Type S Pilot Tubes for
the Measurement of Low Velocilies. U.S. Environmental
Protection Agency, Emission Measurement Branch,
Research Triangle Park, N.C. November 1976.
15. Smith, Marvin L. Velocity Calibiatioo of EPA
Type Source Sampling Probe. United Technologies
Corporation, Pratt and Whitney Aircraft Division,
Kast Hartford, Conn. 1975.
16. Vollaro, R. F. Recommended Procedure for Sample
Traverses in Ducts Smaller than 12 Inches in Diameter.
U.S. Environmental Protection Agency, Emission
Measurement Branch, Research Triangle Park, N.C.
November 1976.
17. Ower, E. and R, C. Pankhurst. The Measurement
of Air Flow, 4th Ed,, London, Pergamon Press. 1966.
18. Vollaro, R. F A Survey of Conimeicially Available
Instrumentation for the Measuiement of Low-Range
(las Velocities. U.S. Environmental Protection Agency,
Emission Measurement Branch, Research Triangle
Park, N.C. November 1976. (Unpublished Paper)87
19. Onyp, A. W., C. C. St. Pierre, D. S. Smith, D.
Mozzon, and J. Stciner. An Expeumental Investigation
of the Effect of Pitot Tube-Sampling Probe Configura-
tions on the Magnitude of the S Type Pitot Tube Co-
efficient for Commeicially Available Source Sampling
Probes. Prepared by the University ol Windsor for th«
Ministry of llie Environment, Toronto, Canada. F»b-
ruary 1975.
Ill-Appendix A-13
-------
METHOD 3 OAS ANALYSIS FOR CARBON DIOXIDI,
OXYOKN, E XCE88 AlB, AND DBV MOI.KCUI.AR WKIOHT
1. Principle and Applicability
1.1 Principle. A gas sample is extracted from a stack,
by one of Die following methods: (1) single-point, grab
sampling* (2) single-point, integrated sampling; or (3)
multi-point, inli-giated sampling. The gas sample Is
analyzed for percent carbon dioxide (COj), percent oxy-
gen (O;), and, if nwisary, percent carbon monoxide
(CO). If a dry molecular weight determination is to be
made, either an Orsat or a Fynte ' analyzer may be used
for the analysis; for excess air or emission rate coriection
factor determination, an Orsat analyzer must be used.
1.2 Applicability. This method is applicable for de-
termining COj and O: concentrations, excess air, and
dry molecular weight of a sample from a gas stream of a
fossil-fuel combustion process. The method may also be
applicable to other processes wheicit has been determined
that compounds other than OOj, Oj, CO, and nitrogen
(Nj) are not present' in concentrations sufficient to
allect the results.
Other methods, as well as modifications to the proce-
dure described herein, are also applicable for some or all
of the above determinations. Examples of specific meth-
ods and modifications include: (1) a multi-point samp-
ling method using an Orsat analyzer to analyze indi-
vidual grab samples obtained at each point; (2) a method
using CO; or Oi and stoichiometric calculations to deter-
mine dry molecular weight and excess air; (3) assigning a
value of 30.0 for dry molecular weight, in lieu of actual
measurements, for processes burning natural gas, coal, or
oil. These methods and modifications may be used, but
are subject to the approval of the Administrator. U S
Kn\ immnenlal Protection AK«'nry87
'2. Apparatus
As an alternative to Uie sampling ap,> Qess than 4.0 percent) or high Oi (greater than
150 percent) concentrations, the measuring burette of
the Orsat must have at least O.I percent subdivisions.
3. DTI Molecular Wfight Determination
Any of the three sampling and analytical procedures
described below may be used for determining the dry
molecular weight.
8.1 Single-Point, Grab Sampling and Analytical
Procedure.
3 1.1 The sampling point in the duct shall either be
at tbe centroid of the cross section or at a point no closer
to the walls than 1.00m (3.3ft), unless otherwise specified
by the Administrator.
812 Set up the equipment as shown In Figure 3-1,
making sure all connections ahead of the analyier are
tight and leak-free If an Orsat analyzer la used, It is
recommended that the analyzer be leaked-«hecked by
following the procedure In Section i; however, tbe leak-
check is optional.
3.1.3 Place the probe in the stack, with the tip of the
probei positioned at the sampling point; purge the sampl-
ing line. Draw & sample into tbe analyzer and imme-
diately analyze It for percent COiand percent Oi. Deter-
mine tbe percentage of the gas that Is N« and CO by
subtracting the sum of the percent COj and percent O>
from 100 percent. Calculate the dry molecular weight as
Indicated in Section 6.3.
8.1.1 Repeat the sampling, analysis, and calculation
procedures, until the dry molecular weights of any three
(rab samples differ from their mean by no more than
0.8 g/g-mole (0.3 Ib/lb-mole). Average these three molec-
ular weights, and report the results to the nearest
0.1 g/g-mole (lb/lb-mole).
3.2 Single-Point, Integrated Sampling and Analytical
Procedure.
3.2.1 The sampling point in the duct shall be located
as specified in Section 3.1.1.
3.2.2 Leak-check (Optional) the flexible bag as In
Section 2.2.6. Set up the equipment as shown in Figure
3-2. Just prior te sampling, leak-check (optional) the
train by placing a vacuum gauge at the condenser inlet,
pulling a vacuum ol at least 250 mm Hg (10 in. Hg),
plugging the outlet at the quick disconnect, and then
lurmng off the pump. The vacuum should remain stable
for at kast 0.5 minute. Evacuate the flexible bag. Connect
the probe and place it in the stack, with the tip of the
probe positioned at the sampling point; purge the sampl-
ing line. Next, connect the bag and make sure that all
connections are tight and leak free.
3.2 3 (Sample at a constant rate. The sampling run
should be simultaneous, -with, and for the same total
length of time as, the pollutant emission rate determina-
tion Collection of at least 30 liters 0 00 ft") of sample gas
is recommended; however, smaller volumes may be
collected, if desired
3 2 4 Obtain one integrated flue gas sample during
»«('h pollutant emission rate determination Within 8
hours after tbe sample is taken, analyze it for percent
COi and percent Oi using either an Orsat analyzer or a
Fyrite-type combustion gas analyier. If an Orsat ana-
lyzer is used, it is recommended that the Orsat leak-
<-heck described In Section & be performed before this
determination; however, tbe check hi optional. Deter-
mine tbe percentage of the (to that Is NI and CObysub-
tracting tbe nun of the oercent CO, and percent Oi
from 100 percent. Calculate the irj molecular weight »
Indicated in Section 6.3. °'
i Mention of trade names or specific products does not
constitute endorsement by the Environmental Protec-
tion Agency.
PROBE
FLEXIBLE TUBING
\
FILTER (GLASS WOOL)
TO ANALYZER
SQUEEZE BULB
Figure 3-1. Grab sampling train.
III-Appendix A-14
-------
RATE METER
AIR-COOLED
CONDENSER
PROBE
\
FILTER
(GLASS WOOL)
RIGID CONTAINER
Figure 3-2. Integrated gas-sampling train.
TIME
TRAVERSE
FT.
AVERAGE
Q
1pm
% DEV.a
, Q Q avg
(MUSTBE<10%)
Figure 33- Sampling rate data.
Ill-Appendix A-15
-------
U.5 Repeat the analysis and calculation procedure)
nntll the Individual dry molecular weights for any three
analyses differ from their mean by no more than O.S
g/g-mole (0.3 Ib/lb-mole). Average these three molecular
weight, and report the results to the nearest 0.1 g/g-mole
(O.llb/lb-mole).
8.3 Multi-Point, Integrated Sampling and Analytical
Procedure.
8.3.1 Unless otherwise specified by the Adminis-
trator, a minimum of eight traverse points shall be used
for circular stack* having diameters less then 0.61 m
(24 in.), a minimum of nine shall be used for rectangular
(tacks having equivalent diameters less than 0.61 m
(24 In.), and a minimum of twelve traverse points shall
be used for all other cases. The traverse points shall be
located according to Method 1. The use of fewer points
is subject to approval of the Administrator.
3.3.2 Follow the procedures outlined In Sections 3.2.2
through 3.2.6, eicept for the following: traverse all sam-
pling points and sample at each point for an equal length
of time. Record sampling data as shown in Figure 3-3.
I. EmiMlon Rate Correction Factor or Eiteii Ait Dettr-
ruination
NOTE.A Fyrite-type combustion gas analyzer is not
acceptable for eicess air or emission rate correction lactor
determination, unless approved by the Administrator.
If both percent CO, and percent Oi are measured, the
analytical results of any of the three procedures given
below may also be used for calculating the dry molecular
weight.
Each of the three procedures below shall be used only
when specified in an applicable subpart of the standards.
The use of these procedures for other purposes must hav e
specific prior approval of the Administrator.
4.1 Single-Point, Grab Sampling and Analytical
Procedure.
4.1.1 The sampling point in the duct shall either be
at the centroid of the cross-section or at a point no closer
to the walls than 1.00m (3.3 It), unless otherwise specified
by the Administrator.
4.1.2 Bet up the equipment as shown In Figure 3-1,
making sure all connections ahead of the analyzer are
tight and leak-free. Leak-check the Orsat analyzer ac-
cording to the procedure described in Section 5. This
leak-check is mandatory.
4.1.3 Place th« probe in the stack, with the tip of tb*
probe positioned at the sampling point; purge the aam-
pllng line. Draw » sample into the analy ler. For emission
rate correction factor determination, Immediately ana-
lyze the sample, as outlined in Sections 4.1.4 and 4.1.5,
for percent COi or percent Oi. If excess air is desired,
proceed as follows: (1) immediately analyze the sample,
as In Sections 4.1.4 and 4.1.6, for percent COi. Oi, and
CO; (2) determine the percentage of the gas that Is Ni
by subtracting the sum of the percent CO], percent O»,
and percent CO from 100 percent; and (3) calculate
percent excess air as outlined In Section 6.2.
4.1.4 To ensure complete absorption of the COt, Oi,
or if applicable, CO, make repeated passes through each
absorbing solution until two consecutive readings are
the same. Several passes (three or four) should be made
between readings. (If constant readings cannot be
obtained after three consecutive readings, replace the
absorbing solution.)
4.1.8 After the analysis Is completed, leak-check
(mandatory) the Orsat analyzer once again, as described
In Section 6. For the results of the analysis to be valid.
the Orsat analyzer must pass this leak test before and
after the analysis. NOTE.Since this single-point, grab
sampling and analytical procedure Is normally conducted
in conjunction with a single-point, grab sampling and
analytical procedure for a pollutant, only ono analysis
is ordinarily conducted. Therefore, great care must bo
taken to obtain a valid sample and analysis. Although
In most cases only COi or Oi Is required, it It recom-
mended that both CO, and O, be measured, and that
Citation 6 in the Bibliography be used to validate the
analytical data.
4.2 Blngle-Point, Integrated Sampling and Analylienl
Procedure.
4.2.1 The sampling point in the duel shall be located
as specified in Section 4.1.1.
4.2.2 Leak-check (mandatory) the flexible bag as in
Section 2.2.6. Set up the equipment as shown in Figure
3-2. Just prior to sampling, leak-check (mandatory) the
train by placing a vacuum gauge at the condenser inlci,
pulling a vacuum of at least 290 mm 111 (10 m. Hit),
plugging the outlet at the quick disconnect, and then
turning off the pump. The vacuum shall remain stable
for at least 0.5 minute. Evacuate th* flexible bag. Con-
nect the probe and place It In the stack, with the tip of the
probe positioned at the sampling point; purge the sam-
pling fine. Next, connect the bag and make sure that
all connections are tight and leak free.
4.2.3 Sample at a constant rate, or as specified by the
Administrator. The sampling run must be simultaneous
with, and for the same total length of time ae, the pollut-
ant emission rate determination. Collect at least 30
liters (1.00 fi>) of sample gas. Smaller volumes may be
collected, subject' ^ ..*-.,-,.*
4.2.4 Obtain c
each pollutant em -
rale correction factor determination, analyze the sample
within 4 hours after it is taken for peicent COi or percent
Oi (as outlined in Sections 4.2.5 through 4.2.7). Th*
Orsat analyzer must be leak-checked (see Section 5)
before the analysts. If excess air is desired, proceed ae
follows: (1) within 4 hours after the sample is taken,
analyze it (as in Sections 4.2.5 through 4.2.7) for percent
Cpj. Oj, and CO; (2) determine the percentage of the
gas that is NI by subtracting the sum of the pen-out COi.
peicent Oj, and peicent CO from 100 percent, (3) cal-
culate percent excess air, as outlined in Section 6 '-'.
4.2.5 To ensure complete absorption of the ('Oj, O»,
or II applicable, CO, make repeated pasws through rtk'h
absorbing solution until two consecutive readings are the
same. Several passes (three or four) should be made be-
tween readings. (If constant readings cannot be obtaliu-d
after three consecutive reading?, replace the aUsuibmg
solution.)
4.2.« Repeat the analysis until the follow ing criteria
are met'
4.2.8.1 For percent COi, repeat the analytical pro-
cedure until the results of any three analyses dlfler by no
more than (a) 0.3 percent by volume when COi Is greater
than 4.0 percent or (b) 0.2 percent by volume when COi
Is less than or equal to 4.0 percent. Average the three ac-
ceptable values of percent COi and report the result* to
the nearest 0.1 percent.
4.2.0.2 For percent Oi, repeat tht analytical procedure
until the results of any three analyses differ by no more
than (a) 0.3 percent by volume when O, Is leas than 1S.O
percent or (b) OJ percent by volume when Oj is greater
than oreo.ua) toU.O percent. Average the three accept -
able values of percent Oi and report the results to
the nearest 0.1 percerjt. 87
4.2.6.3 For percent CO, repeat the analytical proce-
dure until the results of any three analyses differ by no
more than 0.3 percent. Average the three acceptable
values of percent CO and report the result) to the nearest
0.1 percent.
4.2.7 After the analysis Is completed, leak-check
(mandatory) the Orsat analyzer once again, as described
in Sect ion 5. For the results of the analysis to be valid, the
Orsat analyzer must pass this leak test before and after
the analysis. Note: Although in most Instances only COi
or O« is required, it is recommended that both COi and
Ot be measured, and that Citation 5 in the Bibliography
be used to validate the analytical data.
4.3 Multi-Point, Integrated Sampling and Analytical
Procedure.
4.3.1 Both the minimum number of sampling points
and the sampling point location shall be as specified In
Section 3.3.1 of this method. The use of fewer points than
specified Is Jnbject to the approval of the Administrator.
4.8.2 Follow the procedures outlined in Sections 4.2.2
through 4.2.7, except for the following: Traverse all
Sampling points and sample at each point for an equal
length of time. Record sampling data as shown In Figure
83.
6. Ltak-Chfclt Procedure for Or lot Analytert
Moving an Orsat analyzer frequently causes It to leak.
Therefore, an Orsat analyzer should be thoroughly leak-
checked on site before the flue gas sample is introduced
into it. The procedure for leak-checking an Orsat analyzer
is:
6.1.1 Bring the liquid level in each pipette up to the
reference mark on the capillary tubing and then close the
pipette stopcock.
S.I.2 Raise the leveling bulb sufficiently to bring the
confining liquid meniscus onto the graduated portion of
the burette and then close the manifold stopcock.
5.1.3 Record the meniscus position.
1.1.4 Observe the meniscus In the burette and the
liquid level in the pipette for movement over the next 4
minutes.
6.1.5 For the Orsat analyzer to pass the leak-check,
two conditions must be met.
5.1.5.1 The liquid level In each pipette must not fall
below the bottom of the capillary tubing during this
4-minutc Interval.
5.1.5.2 The meniscus In the burette must not change
by more than 0.2ml during this 4-mlnuteinterval.
6.1.6 If the analyzer falls the leak-check procedure, all
robber connections and stopcocks should be checked
nntll the cause of the leak Is Identified. Leaking stopcock!
must be disassembled, cleaned, and regreased. Leaking
rubber connections must be replaced. After the analyzer
Is reassembled, the leak-check procedure must b*
repeated.
8.1 Nomenclature.
Md- Dry molecular weight, g/g-mole Ob/lb-mole).
%E A-Percent excess air.
%COi»Peroent COi by volume (dry basis).
%Oj«-Percent O«by volume (dry basis).
%CO~Percent CO by volume (dry basis).
%N!»Percent N» by volume (dry basis).
0.284=- Ratio of Oi to NI In air, v/v.
0.280=>Molecular weight of NI or CO, divided by 100.
0.320»Molecular weight of Oi divided by 100.
0.440«Molecular weight of COi divided by 100.
6.2 Percent Eicess Air. Calculate the percent excess
air (If applicable), by substituting the appropriate
values of percent O», CO, and Nj (obtained from Section
4.1.3 or 4.2.4) into Equation 8-1.
%0,-0.5%CO -)
0.264 %N2-(%02-0.57cCO) J1W
Equation 8-1 87
NOTE.The equation above assumes that ambient
air Is used as the source of Oi and that the fuel does not
contain appreciable amounts of NI (as do coke oven or
blast furnace gases). For those cases when appreciable
amounts of Ni are present (coal, oil, and natural gas
do not contain appreciable amounts of NI) or when
oxygen enrichment is used, alternate methods, subject
to approval of the Administrator, are required.
6.8 Dry Molecular Weight. Use Equation 8-2 to
calculate the dry molecular weight of the stack gas
»fj-0440(%CO:)+0.320(%Oi)+0.280(%N,+%CO>
Equation 3-2
NOTE.The above equation does not consider argon
In air (about 0.9 percent, molecular weight ol 37.7).
A negative error of about 0.4 percent Is Introduced.
The tester may opt to Include argon In the analysis using
procedural subject to approval of the Administrator.
7. Bibliography
1. Altshuller, A. P. Storage of Gases and Vapors in
Plastic Bags. International Journal of Air and Water
Pollution. S:75-81.1963.
2. Conner, William D. and J. B. Nader. Air Sampling
with Plastic. Bags. Journal nf the American Industrial
Ilvciene Association. W:291-2B7. 1*64. 87
K Burrell Manual for Oas Analysts, Seventh edition.
BurreU Corporation, 2223 Fifth Avenue, Pittsburgh,
Pa. 15219.1951.
4. Mitchell, W. J. and M. R. Midgett. Field Reliability
of the Orsat Analyzer. Journal of Air Pollution Control
Association *J:491-<95. May 1976.
5. Shigehara, R. T., R. M. Neulicht, and W. 8. Smith.
Validating Orsat Analysis Data from Fossil Fuel-Fired
Units. Stack Sampling News. 4X2)21-28. August, 1976.
Ill-Appendix A-16
-------
METHOD 4DETEBMISATIOH or MOISTURE CONTENT
IN STACK OASES
1. Principle and /tppHcaoflttii
1.1 Principle. A gas sample is extracted at a constant
rate from the source; moisture is removed from the sam-
ple stream and determined either volumetrlcally or
gravimetrically.
1.2 Applicability. This method is applicable for
determining the moisture content of stack gas.
Two procedures are given. The first is a reference
method, for accurate determinations of moisture content
(such as aie needed to calculate emission data). The
second is an approximation method, which provides
estimates of percent moisture to aid in sotting isokinetic
sampling rales piior to a pollutant emission measure-
ment run. The approximation method described herein
is only a suggested approach; alternative means for
approximating the moisture content, e.g., drying tubes,
wet bulb-dry bulb techniques, condensation techniques,
stoichlometric calculations, previous experience, etc.,
aie also acceptable.
The reference method is often conducted simultane-
ously with a pollutant emission measurement run; when
it is, calculation of percent isokinetic, pollutant emission
rate etc., for the run shall be based upon the results of
the reference method or its equivalent; these calculations
shall not be based upon the results of the approximation
method, unless the approximation method is shown, to
the satisfaction of the Administrator, U.S. Environmen-
tal Protection Agency, to be capable of yielding results
within 1 percent HjO of the reference method.
NOTE.The reference method may yield questionable
results when applied to saturated gas streams or to
streams that contain water droplets Therefore, when
these conditions exist or are suspected, a second deter-
mination of the moisture content shall be made simul-
taneously with the reference method, as follows: AMIUIU
that the gas stream is saturated. Attach 1lUmperature
tensor (capable of measuring to *1* C (2» F)| to th«
reference method probe. Measure the stack gas tempera-
ture st each traverse point (see Section 2.2.1) during the
reference method traverse; calculate the average Itack
tas temperature. Next, determine the moisture percent*
age either by: (1) using a psychrometric chart rod
miking appropriate corrections if stack pressure ii
Xflerent from that of the chart, or (2) using saturation
vapor pressure tables In cases where the psychrometric
chart or the saturation vapor pressure tables are not
applicable (based on evaluation of the process), alternate
methods, subject to the approval of the Administrator,
shall b« used.
I. Referena Method
The procedure described in Method 5 for determining
moisture content is acceptable as a reference method.
2.1 Apparatus. A schematic of the sampling train
used in this reference method is shown in Figure 4-1.
All components shall be maintained and calibrated
according to the procedure outlined in Method 5.
2.1.1 Probe. The probe is constructed of stainles*
Iteel or glan tubing, sufficiently heated to prevent
water condensation, and is equipped with a filter, either
In-etack (e g., a plug of glass wool inserted into the end
Of the probe) or heated out-stack (e.g., as described In
Method 6), to remove paniculate matter.
When stack conditions permit, other metals or plastic
tubing may be used for the probe, subject to the approval
of the Administrator.
2.1.2 Condenser. The condenser consists of tour
Imoingers connected in series with ground glass, leak-
fret flttings or any similarly leak-free 'non-wntainlnatlng
fittings. The first, third, and fourth impingers shall b»
of the Oreenburg-Smith design, modified By "plactnf
the tip with a 1.3 centimeter H inch) ID glass tub*
ertendlng to about 1.3 cm M In.) 1froinlhV)otwJ!;.
the flask. The second impinger shall be of the Oreenburf-
Smith design with the standard tip. Modifications (e,g.,
using flexible connections between the impingers, uitng
materials oilier than glass, or using flexible vacuum Unyt
to connect the filter holder to the condenser) may D«
used subject to the approval of the Administrator.
The first two impinfjers shall contain known volume*
el water, the third shall be empty, and the fourth shall
contain a known weight of 6- to 18-mesh indicating typ«
silica gel, or equivalent desiccant. If the silica gel ha§
been previously used, dry at 175° C (350° F) for 2 houn.
New silica gel may be used as received. A thermometer,
eapable of measuring temperature to within 1" C (rr),
shall be placed at the outlet of the fourth impinger, lor
monitoring purposes.
Alternatively, any system may be used (subject to
the approval of the Administrator) that cools the sample
cas stream and allows measurement of both the water
That has been condensed and the moisture leaving the
condenser, each to within 1 ml or 1 g. Acceptable meant
are to measure the condensed water, either gravl-
metrically or volumetrically, and to measure the moto-
tore leaving tot condenser by: (1) monitoring the
temperature and prexara at the eilt of th« condenser
and using Dalton's law of partial pressures, or (2) passing
the sample gai stream through a tared sutca gjMor
equivalent desiccant) trap, with eilt gaset kepU»«low
5r> C (68° F>. and determining the weight gain. <"
FILTER
(EITHER IN STACK
OR OUT OF STACK)
STACK
WALL
CONDENSER-ICE BATH SYSTEM INCLUDING
SILICA GEL TUBE
AIR-TIGHT
PUMP
Figure 4-1. Moisture sampling train-reference method.
III-Appendix A-17
-------
It means other than silica gel are used to determine tb«
amount of moisture leaving the condenser, it is recom-
mended that silica gel (or equivalent) still be used be-
tween the condenser system and pump, to prevent
moisture condensation In the pump and metering
devices and to avoid the need to make corrections for
moisture in the metered volume.
2.1.3 Cooling System. An ice bath container and
crushed ice (or equivalent) are used to aid in condensing
moisture.
2.1.4 Metering System. This system Includes a vac-
uum gauge, leak-free pump, thermometers capable of
measuring temperature to within 3° C (8.4° F), dry gas
meter capable of measuring volume to within 2 percent,
and related equipment as shown in Figure i-1. Other
metering systems, capable of maintaining a constant
sampling rate and determining sample gas volume, may
be used, subject to the approval of the Administrator.
2.1.5 Barometer. Mercury, aneroid, or other barom-
eter capable ol measuring atmospheric pressure to within
2.4 mm Hg (0.1 in. Hg) may be used. In many cases, the
barometric reading may be obtained from a nearby
national weather service station, in which case the sta-
tion value {.which is the absolute barometric pressure)
shall be requested and an adjustment for elevation
differences between the wather station and the sam-
pling point shall be applied at a rate of minus 2 fi uim Hg
(0.1 in. Hg) per 30 m (100 ft) elevation increase or vice
versa for elevation decrease.
2.1.8 Graduated Cylinder and/or Balance. These
Items are used to measure condensed water and mobture
caught In the silica gel to within 1 ml or 0.6 g. Graduated
cylinders shall have subdivisions no greater than 1 ml.
Most laboratory balances are capable of weighing to the
nearest 0.4 g or less. These balances are suitable for
use here.
2.2 Procedure. The following procedure is written tor
a condenser system (.such as the impmger system de-
scribed in Section 2 1.2) incorporating volumetric analy-
sis to measure the condensed moisture, and silica gel and
gravimetric analysis to measure the moisture leaving the
condenser.
2.2.1 Unless otherwise specified by the Administrator,
a minimum of eight traverse points shall be used for
circular stacks having diameters less than 0.61 m (24 in.),
a minimum of nine points shall be used for rectangular
stacks having equivalent diameters less than 0.61 m
(24 in.), and a minimum of twelve traverse points shall
be used in all other cases. The traverse points shall be
located according to Method 1. The use of fewer points
is subject to the approval of the Administrator. Select a
suitable probe and probe length such that all traverse
points can be sampled. Consider sampling from opposite
sides of the stack (four total sampling ports) for large
stacks, to permit use of shelter probe lengths. Mark the
probe with heat resistant tape or by some other method
to denote the proper distance into the stack or duct (or
each sampling point. Place known volumes of water in
the first two unpingeis. Weigh and record the weight of
the silica gel to the nearest 0.5 g, and transfer the silica
gel to the fourth impinger; alternatively, the silica gel
may first be transferred to the impmger. and the \v\-ight
of the silica gel plus impinger recorded.87
2.2.2 Select a total sampling time «tieh that a mini-
mum total gas volume of 0.60 som (21 set) wnl be col-
lected, at a rate no greater than 0.021 m'/nun. (0.75 cfm).
When both moisture content and pollutant emission rate
are to be determined, the moisture determination shall
b« simultaneous with, and for the same total length of
time as, the pollutant emission rate run, unless otherwise
specified in an applicable suhpart ol the standards.
2.2.3 Set up the sampling train as shown in Figura
4-1. Turn on the probe heater and (if applicable) the
filter heating system to temperatures of about 120° C
(248° F), to prevent water condensation ahead of UM
condenser; allow time for the temperatures to stabilise.
Place crushed ice in the ice bath container. It is recom-
mended, but not required, that a leak check be done, M
follows Disconnect the probe from the first impmger or
(if applicable) from the filter bolder. Plug the Inlet to ths
fust impinger (or filter holder) and pull a 380 mm (15 in.)
Hg vacuum, a lower vacuum may be used, provided that
it is not exceeded during the test. A leakage rate In
excess of 4 percent of the average sampling rate or 0.00057
m'/min (0.02 elm), whichever is less, is unacceptable.
Following the le&k check, reconnect the probe to the
sampling tram. °7
224 During tbe sampling run, maintain a sampling
rate within 10 percent of constant rate, or as specified by
the Almim'strator. For each run, record the data re-
quired on the example data sheet shown in Figure 4^2.
Be sure to record the dry gas meter reading at the begin-
ning and end of each sampling time increment and when-
ever sampling Is baited. Take other appropriate readings
at each sample point, at least once during each time
Increment.
2.2.6 To begin sampling, position tbe probe tip at the
first traverse point. Immediately start the pump and
djust the flow to the desired rate. Traverse the cross
section, sampling at each traverse point for »n equal
length of time. Add more ice and, if necessary, salt to
maintain a temperature of less than 20° C (68° F) at the
silica gel outlet
2.2.6 After collecting the sample, disconnect the probe
from the filter holder (or from tbe first impinger) and con-
duct a leak check (mandatory) as described in Section
S.2.3. Record the leak rate. If the leakage rate exceeds the
allowable rate, tbe tester shall either reject the. test re-
mits or shall correct the sample volume as in Section 6 3
of Method 5. Next, measure the volume of the moisture
condensed to the nearest ml. Determine the increase in
weight of the silica gel (or silica gel plus impinger) to the
nearest 0.5 g. Record this information (see example data
sheet, Figure 4-3) and calculate the moisture percentage,
as described in 2.3 below.
nun
LOCATION-
OPERATOR.
DATE
RUN NO
AMBIENT TEMPERATURE-
BAROMETRIC PRESSURE-
PROBE LENGTH ntlO
SCHEMATIC OF STACK CROSS SECTION
TRAVERSE POINT
NUMBER
TOTAL
SAMPLING
TIME
(d).mM.
AVERAGE
STACK
TEMPERATURE
C("F)
PRESSURE
DIFFERENTIAL
ACROSS
ORIFICE METER
(AM),
mnCnJ HjO
METER
READING
CAS SAMPLE
VOLUME
m' (ftJ)
AV.
»1(M>
6 AS SAMPLE TEMPERATURE
AT DflY GAS METER
INLET
frmi,,).«Cf»FI
A*.
A*.
OUTLET
(TiUMrtl.'Cf'F)
A*
TEMPERATURE
OF GAS
LEAVING
CONDENSER OR
LAST IMPINGER.
C <«F)
Figure 4-2. Field moisture determination-reference method.87
III-Appendix A-18
-------
HEATED PROBE
SILICA GEL TUBE
FILTER
(GLASS WOOL)
RATE METER,
VALVE
MIDGET IMPINGERS
PUMP
Figure 4-4. Moisture-sampling train - approximation method.
LOCATION.
TEST
COMMENTS
DATE
OPERATOR
BAROMETRIC PRESSURE
CLOCK TIME
GAS VOLUME THROUGH
METER, (Vm).
m3 (ft3)
RATE METER SETTING
m^/min. (ft^/min.)
METER TEMPERATURE,
°C (°F)
1
Figure 4-5. Field moisture determination - approximation method.
III-Appendix A-19
-------
2.3 Calculations Carry out the following calculations,
retaining at least one extra decimal figure beyond that of
the acquired data. Round ofl figures after final calcula-
tion.
FINAL
INITIAL
DIFFERENCE
IMPINGED
VOLUME.
ml
SILICA GEL
WEIGHT.
9
Fi'jure 4 3. Analytical data reference method
2.3.1 Nomenclature.
7?,,, = l'roportioii of watei vapor, by \ulume, m
the pas stream.
M» = Molecular weight of water, 18.0 g/g-mole
(18.01b/lb-mole).
/>B, = Absolute pressure (for this method, same
as barometric pressure) at the dry gas meter,
mm llg (in. Hg).
P.,j=Standard absolute pressure, 7(jO mm Hg
(29.92in. Hg).
tf = Ideal gas constant, 0.06236 (mm Hg) (m')/
(g-mole) (°K) for metric units and 21.85 (in.
llg) = Final volume of condenser water, ml.
V,=Initial volume, if any, of condenser water,
ml.
W/=Final weight of siHca gel or silica gel plus
impinger, g.
IP,=Initial weight of siliea gel or silica gel plus
impinger, g.
V=0ry gas meter calibration factor.
p»=Density_,of water, 0.9982 g/ml i0.0022W
r Ib/ml). 87
232 Volume of water vapor condensed.
V u
Kqnation 4 1
where:
#1=0.001333 m'/ml for metric units
=0.04707 fti/ml for English units
23.3 Volume of water vapor collected in silica gel.
where:
It.i=0.00133« m'/g for metric units
0,04711 ft'/g for English unils
2.3.4 Sample gas volume.
.
= Kt(Wt-W.)
Equation 4-2
_(/',.) (jr.,,,)
" >
where.
A')=038W°K/iiim HK f»r metric viiuls
= 17.64 °R,'in. llg for Bullish units
Fi|ii.itlon 4 3
NOTE If the post-test leak iato lSirlic.ii _' _' h) ex-
ceeds the allowable rate, cmrcct the value of I', ni
Kqlialloll 4-3, as dcscd in Settion f> 3 of MHlmdA.
2 .t :3 Moisture C'onlent
I/ I I r
j, _ __ '_irrfml) r1 :iilti:)
Vuc <»t.l) + Vir,, (st.i) + Vm (.1,1)
Ktniatiun 4-4
N'ori: fn saturated or multure droplet-laden gas
streams, two ealctilations of the moisture content of the
stack gas shall be made, one using a value based upon
the saturated conditions (see Section 1.2), and another
based upon the results of the impinger analysis. The
lower of these, two values of Ku, shall be consideied cor-
rect
23i> Verification of constant sampling late. For each
time increment, determine the &Vm. Calculate the
average If the value for any time inclement dilTers from
the aveiage by more than in percent, rejei t the results
and repeat the run.
3 .4pprojrn«a(io)i Method
The approximation method desciibed below is pie.-
sented only as a suggested method (see Section 1 2).
3 1 Apparatus.
3.1 1 Probe. Stainless steel or glass tubing, sufficiently
heated to prevent water condensation and equipped
with a lUter (either in-stack or heated out-stack) to re-
move paniculate matter A plug of glass wool, inserted
into the end of the probe, is a satisfactory filter.
3.1 2 Impingers. Two midget impingers, each with
30 ml capacity, or equivalent
313 lee Bath. Container and ice, to aid in condens-
ing moisture in impingers
3.1.4 Drying Tube. Tube packed with new or re-
generated 6- to 16-mesh indicating-type silica gel (or
equivalent desiccant), to dry the sample gas and to pro-
tect the meter and pump.
3.1.5 Valve. Needle valve, to legulate the sample gas
flow late.
3.1.6 Pump. Leak-free, diaphragm type, or equiva-
lent, to pull the gas sample through the train.
3.1.7 Volume meter. Dry gas meter, sufficiently ac-
curate to measure the sample volume within 2%, and
calibrated over the range of flow rates and conditions
actually encountered during sampling.
3.1.8 Rate Meter. Hotameter, to .measure the flow
range from 0 to 3 1 pm (0 toO.llefm). 87
3.1.9 Graduated Cylinder. 25 ml.
3.1.10 Barometer. Mercury, aneroid, or other barom-
eter, as described in Section 2.1.5 above.
3.1.11 Vacuum Gauge. At least 760 mm llg (.10 in.
llg) gauge, to be used tor the sampling leak check.
3.2 Procedure.
3.2.1 Place exactly 5 ml distilled water in each im-
pinger. Leak check the sampling train as follows:
Temporarily insert a vacuum gauge at or
near the probe inlet; then, plug the prcbc
inlet and pull a vacuum of at least 250 mm
Hg (10 in. Hg). Note, the time rate of
change of the dry gas meter dial; alternati-
vely. a rotameter (0-40 ce/min) may be tem-
porarily attached to the dry gas meter
outlet to determine the leakage rate. A leak
rate not In excess of 2 percent of the aver-
age sampling rate is acceptable.
NOTE. Carefully release the probe inlet
before tumlni? off the pump.87
3.2.2 Connect the probe. Insert it into the stack, and
sample at a constant rat* of 2 1pm (0.071 etm). Continue
sampling until the dry gas meter registers about 30
liters (1.1 ft<) or until visible liquid droplets are carried
over from the first impinger to the second. Record
temperature, pressure, and dry gas meter readings ai
required by Figure 4-J.
.1.2.3 After collecting the sample, combine the con-
leutsof the two impingers and measure the volume to the
nearest 0.5 ml.
.1.3 Calculations. The calculation method presented Is
designed to estimate the moisture in the stack gas;
therefore, other data, which are only necessary for ac-
curate moisture determinations, are not collected. The
following equations adequately estimate the moisture
content, for the purpose of determining iMjkiiiolic sam-
pling rate settings.
3.3.1 Nomenclature.
B>.=Approiimate proportion, by volume, of
water vapor in the gas stream leaving the
second impinger, 0.025.
B».= Water vapor in the gas btream, proportion by
volume.
.W»= Molecular weight of water, 18.0 g/g-mole
(18.01b/lb-mole)
F.=Absolute pressure (for this method, same as
barometric pressure) at the dry gas meter.
P,,i~ Standard absolute pressure, 760 mm Hg
(29.92 in. Hg).
R = Ideal gas constant, 0.08236 (mm Hg) (m»)/
(g-mole) (°K) for metric units and 21 85
(m. Hg) (ft«)/lb-mole) (°B) for English
T.=Absoiute temperature at meter, °K (°R)
T,, 4= Standard absolute temperature, 293" K
(.528 R)
JV=Flnal volume of impinger contents, ml.
v ,= Initial volume of Impinger contents, ml.
K.-Dry gas volume measured by dry gas meter,
dcm (dcf).
V«(.r<)=Dry gas volume measured by dry gas meter,
corrected to standard conditions, dsran
V.,(,,/)=Volume of water vapor condensed corrected
to standard conditions, scm (scf)
P'v- Density of water, 0.9982 g/ml (0.002201 Ib/ml).
Y = Dry gas meter calibration factor. 8?
3.3.2 Volume ol water vapor collected.
v _
"~
=K1(V,-Vi)
Equation 4-5
where:
X|«=0.001333 m'/ml for metric units
-=0.04707 ft'/ml for English units.
3.3.3 Gas volume.
Equation 4-d
187
where:
JCj=0.3868 "K/mm Hg tor metric units
=17.64 "B/in. Hg tor English units
3..1.4 Approximate moisture content.
* *(<&
+(0.025)
Equation 4-7
4. Calibiatim
4.1 For the reference method, calibrate equipment aa
specified in the following sections of Method 5. .Section 6.3
(metering system); Section fi.5 (temperature gauges);
and Section 5.7 (barometer). The recommended leak
check of the metering system (Section 5.« of Method 5)
also applies to the reference method. For the approiima-
tlon method, use the procedures outlined in Section 5.1.1
of Method 6 to calibrate the metering system, and the
procedure of Method 5, Section 5.7 to calibrate the
barometer.
5. Bibliography
1. Air Pollution Engineering Manual (Second Edition).
Danielson, J. A. (ed.). U.S. Environmental Protection
Agency, Office of Air Quality Planning and Standards.
Research Triangle Park, N.C. Publication No. AP-40.
1973.
2. Devorkin, Howard, et al. Air Pollution Source Test-
ing Manual. Air Pollution Control District, Los Angeles,
Calif. November, 1963.
3. Methods for Determination of Velocity, Volume,
Dust and Mist Content of Oases. Western Precipitation
Division of Joy Manufacturing Co., Los Angeles, Calif.
Bulletin WP-50.1988.
87
Ill-Appendix A-20
-------
METHOD 5 DETERMINATION or PARTICVIA n EuISSIONS
FROM STATIONARY SOURCES
1. Principle and Applicability
1.1 Principle. Particular matter is withdrawn iso-
kineticaUy from the source and collected on a glass
fiber filter maintained at a temperature in the range of
120±U« C (248±2S° F) or such other temperature M
specified by an applicable subpart of the standards or
approved by the Administrator, U.S. Environmental
Protection Agency, for a particular application. The
paniculate mass, which includes any material that
condenses at or above the nitration temperature, i*
determined gravimetrieally after removal of uncombined
water.
1.2 Applicability. This method is applicable for the
determination of particulate emissions from stationary
sources.
2. Apporaiut
2.1 Sampling Train. A schematic of the sampling
train used jn this method is shown in Figure 5-1. Com-
plete construction details are given in APTD-0581
(Citation 2 in Section 7); commercial models of this
train are also available. For changes from APTD-0581
and for allowable modifications of the train shown in
Figure 5-1, see the following subsections.
The operating and maintenance procedures for the
sampling train are described In APTD-0676 (Citation 3
in Section 7). Since correct usage is important in obtain-
ing valid results, all users should read APTD-0676 and
adopt the operating and maintenance procedures out-
lined in It, unless otherwise specified herein. The sam-
pling train consists of the following components:
i.1.1 Probe Noulo. Stainless steel (316) or glass with
harp, tapered leading edge. Tbe angle of taper shall
be <30° and the taper shall be on the outside to preserve
constant internal diameter. The probe noizle shall be
of the button-hook or elbow design, unless otherwise
specified by the Administrator. If made of stainless
steel, the noiile shall be constructed from seamless tub-
ing; other materials of construction majcbe used, subject
to the approval of the Administrator. °'
A range of no»l« SIM* suitable (or Isokinetic sampling
hould be available, e.g., 0.32 to 1.27 cm Ot to >4 in.)
or larger if higher volume sampling trains are used-
inside diameter (ID) notzles In increments of 0.16 em
(H« in.). Each nozzle shall be calibrated according to
the procedures outlined in Section 5.
2.1.2 Probe Liner. Borosihcate or quart! glass tubing
With a heating system capable of maintaining a gas tem-
perature at the exit end during sampling of 120±U° C
(248±25° F), or such other temperature as specified by
an applicable subpart of the standards or approved by
tile Administrator for a particular application. (The
tetter may opt to operate the equipment at a temperature
lower than that specified.) Since the actual temperature
at the ou tlet of the probe is not usually monitored during
sampling, probes constructed according to APTD-0581
and utilizing the calibration curves of APTD-0576 (or
OTlibraled according to the procedure outlined in
APTD-0576) wilJ be considered acceptable.
Either borosilicu* or quarti glass probe liners mar be
Md for stack temperatures up to about 480° C ,800° F)
quarti liners shall be used lor temperatures between 480
tod 900° C (900 and 1,650° F) Both types of liners may
be used at higher temperatures than specified for short
periods of time, subject to the approval ol the Adminis-
trator. Tlie softening temperature for borosilicale is
«20° C (1,508° F), and tor quartz it is 1,50(° C (2,732° F)
Whenever practical, every effort should be made to use
borosilicate or quart* glass probe liners. Alternatively,
metal liners (eg., 216 stainless steel, Incoloy 825 »or other
corrosion resistant metals) made of seamless tubing may
be used, subjec. to the approval o( the Administrator.
2.1.3 Pilot Tube. Type 8, as described in Section 2 1
( Method 2, or other device approved by the Adminis-
trator The pilot tube shall be attached to the probe (as
bown in Figure 5-4) to allow constant monitoring of th«
tack gas velocity Tb* Impact (high prmure) opening
plane of the pilot tube shall be even with or above the
noizle entry plane (see Method 2, Figure 2-61>) during
sampling. The Type S pilot tube assembly shall have a
known coefficient, determined as outlined in Section 4 of
Method 2.
»Mention oi trade names or specific products does not
constitute endorsement by the Environmental Protec-
tion Agency.
2.1.4 Differentia; Pressure (Huge. Inclined manom-
eter or equivalent devcj (two), as uscnbed in Section
2.2 of Method 2. One manometer s'lall be used .or velocity
head (Ap) readings, and the other, for orifice differential
pnasun readings.
2.1.5 Filter Holder. Borosilicate glass, with a glass
frit filter support and a silicone rubber gasket. Other
materials of construction (e.g., stainless steel, Teflon,
Viton) may be used, subject to approval of the Ad-
ministrator. The bolder design shall provide a positive
seal against leakage Irom the outside or around the filter.
The holder ?haU be attached immediately at the outlet
of the probe (or cyclone, it used).
2.1.6 Filter Heating System. Any heating system
capable of maintaining a temperature around the filter
holder during sampling o. 120±H° C (248±2.V> F), or
such other temperature as specified by an applicable
subpart oi the standards or approved by the Adminis-
trator for a particular application. Alternatively, the
tester may opt to operate the equipment at a temperature
lower than that specified. A temperature gauge capable
of measuring temperature to within 3° C (5.4° F) shall
be installed so that the temperature around the filter
holder can be regulated and monitored during sampling.
Heating systems other than the one shown in APTD-
0581 may be used.
2.1.7 Condenser. The following system shall be used
to determine the stack gas moisture content: Four
impingers connected in series with leak-free ground
glass fittings or any similar leak-free non-contaminating
fittings. The first, third, and fourth impingers shall be
ol the Qreenburg-Smith design, modified by replacing
the Up with 1.3 cm (H in.) W glass tube extending to
bout 1.3 cm (H in.) from the bottom o( the flask. The
aecond impinger shall be of the Qrcenburg-Smlth design
with the standard tip. Modifications (e.g , using flexible
eoonections between the impingers, using materials
other than glass, or using flexible vacuum lines to connect
the filter holder to the condenser) may be used, subject
to the approval of the Administrator. The first and
second Impingers shall contain known quantities of
water (Section 4.1.3), the third shall be empty, and. the
fourth shall contain a known weight of silica gel, or
equivalent deslccant. A thermometer, capable of measur-
TEMPERATURE SENSOR
PITOTTUBE /
PROBE /f
- PROBE
TEMPERATURE
SENSOR
IMPINGER TRAIN OPTIONAL,MAY BE REPLACED
BY AN EQUIVALENT CONDENSER
HEATED AREA THERMOMETER
THERMOMETER
REVERSE-TYPE
PITOTTUBE
IMPINGERS ICE BATH
BY-PASS VALVE
PITOT MANOMETER
ORIFICE
CHECK
VALVE
VACUUM
LINE
VACUUM
GAUGE
THERMOMETERS
DRY GAS METER
AIRTIGHT
PUMP
Figure 5 1. Particulate-sampling train.
Ill-Appendix A-21
-------
Ing temperature to within 1° C (2° F) shall be placed
at the outlet of the fourth Implnger (or monitoring
purposes.
Alternatively, any system that cools the sample gas
stream and allows measurement of the water condensed
and moisture leaving the condenser, each to within
1 ml or 1 g may be used, subject to the approval of the
Administrator. Acceptable means are to measure the
condensed water either gravimetrically or volumetrically
and to measure the moisture leaving the condenser by:
(1) monitoring the temperature and pressure at the
exit of the condenser and using Dalton's law of partial
pressures; or (2) passing the sample gas stream through
a tared silica gel (or equivalent desiccant) trap with
exit gases kept below 20° C (68° F) and determining
the weight gain.
If means other than silica gel are used to determine
the amount of moisture leaving the condenser, it is
recommended that silica gel (or equivalent) still be
nsed between the condenser system and pump to prevent
moisture condensation in the pump and metering devices
and to avoid the need to make corrections for moisture in
the metered volume.
NOTE. If a determination of the particulate matter
collected In the impmgers is desired in addition to mois-
ture content, the impinger system described above shall
b« used, without modification. Individual States or
control agencies requiring this information shall be
contacted as to the sample recovery and analysis ol the
impinger contents.
2.1.8 Metering System. Vacuum gauge, leak-free
pump, thermometers capable of measuring temperature
to within 3° C (5.4° F), dry gas meter capable ol measuring
volume to within 2 percent, and related equipment, as
shown in Figure 5-1. Other metering systems capable of
maintaining sampling rates within 10 percent of iso-
kinetic and of determining sample volumes to within 2
percent may be used, subject to the approval of the
Administrator. When the metering system is used m
conjunction with a pitot tube, the system shall enable
checks ol isokinetic rates.
Sampling tramsutiuzingmetering systems designed for
higher flow rates than that described in APTD-OS81 or
APTD-057C may b« used provided that the specifica-
tions 01 this method are met.
2.1.9 Barometer. Mercury, aneroid, or other barometer
capable of measuring atmospheric pressure to within
2.6 mm Hg (0.1 in. llg). In many cases, the barometric
reading may be obtained from a nearby national weather
service station. In which case the station value (which it
the absolute barometric pressure) shall be requested and
an adjustment for elevation difierences between the
weather station and sampling point shall be applied at a
rate of minus 2.5 mm Hg (0.1 in. Hg) per 30 m (100 ft)
elevation increase or vice versa for elevation decrease.
2 1 10 Gas Density Determination Equipment.
Temperature sensor and pressure gauge, ss described
in Sections 2.3 and 2.4 of Method 2, and gas analywr,
if necessary, as described in Method 3. The temperature
sensor shall, preferably, be permanently attached to
the pitot tube or sampling probe in a fixed configuration,
such that the tip of the sensor extends beyond the leading
edge of the probe sheath and docs not touch any metal.
Alternatively, the sensor may be attached Just prior
to use in the field Note , however, that if the temperature
sensor is attached in the field, the sensor must be placed
in an interference-free arrangement with respect to the
Type S pitot tube openings (see Method 2, Figure 2-7).
Asa second alternative, if a difference of not more than
1 percent m the average velocity measurement is to be
introduced, the temperature gauge need not be attached
to tb_e probe or pitot tube. (This alternative is subject
to the approval of the Administrator )
22 Sample Recovery. The following items are
.i Probe-Liner and Probe-Nozzle Brushes. Nylon
bristle brushes with stainless steel wire handles The
probe brush shall have extensions (at least as long as
the probe) of stainless steel, Nylon, Teflon, or similarly
inen material The brushes shall be properly siied and
shaped to brush out the probe liner and nozzle.
2.2.2 Wash Bottles Two. Glass wash bottles are
recommended; polyethylene wash bottles may be used
at the option of the tester. It is recommended that acetone
not be stored in polyethylene bottles for longer than a
month.
2.2.3 Glass Sample Storage Containers. Chemically
resistant, borosilicate glass bottles, for acetone washes,
500 ml or 1000 ml Screw cap liners shall either be rubber-
backed Teflon or shall be constructed so as to be leak-free
and resistant to chemical attack by acetone. (Narrow
mouth glass bottles hav« been found to be less prone to
leakage ) Alternatively, polyethylene bottles may be
used.
2.2 4 Petri Dishes For filter samples, glass or poly-
ethylene, unless otherwise specified by the Admin-
istrator. 87
2.2.5 Graduated Cylinder and/or Balance To meas-
ure condensed water to within 1 ml or 1 g. Graduated
cylinders shall have subdivisions no greater than 2 ml.
Most laboratory balances are capable of weighing to the
nearest 0.5 g or less. Any of these balances is suitable for
use here and in Section 2 3.4.
2.2.6 Plastic Storage Containers. Air-tight containers
to store silica gel.
2.2.7 Funnel and Rubber Policeman. To aid in
transfer of sihca gel to container, not necessary if silica
gel is weighed in the field.
2.2.8 Funnel. Glass or polyethlene, to aid in sample
weoverr.
2.3 Analysis. For analysis, the following equipment Is
needed
2.3.1 Glass Weighing Dishes.
2 3.2 Desiccator.
2.3.3 Analytical Balance. To measure to within 01
mg.
2.3.4 Balance. To measure to within 0.5 g.
2.3.5 Beakers. 250ml.
2.3.6 Hygrometer. To measure the relative humidity
of the laboratory environment.
2.3.7 Temperature Gauge. To measure the tempera-
ture of the laboratory environment.
3. Reatenii
8.1 Sampling. The reagents used in sampling are as
follows:
3.1.1 Filters. Glass fiber filters, without organic
binder, exhibiting at least 99.95 percent efficiency (<0.05
percent penetration) on 0.3-micron dioctyl phthalate
smoke particles. The filter efficiency test shafi be con-
ducted in accordance with ASTM standard method D
2986-71. Test data from the supplier's quality control
program are sufficient for this purpose.
3.1.2. Silica Gel. Indicating type. 8 to 16 mesh. If
previously used, dry at 175° C (350° F) for 2 hours. New
silica gel may be used as received. Alternatively, other
types of desiccants (equivalent or better) may be used,
subject to the approval of the Administrator.
3.1.3 Water. When analysis of the material caught in
the impingers is required, distilled water shall be used.
Run blanks prior to field use to eliminate a high blank
on test samples.
3.1.4 Crushed Ice.
8.1.5 Stopcock Grease. Acetone-insoluble, heat-stable
silicone grease. This is not necessary if screw-on con-
nectors with Teflon sleeves, or similar, are used. Alterna-
tively, other types of stopeock grease may be used, sub-
ject to the approval of the Administrator.
3.2 Sample Recovery. Acetonereagent grade, <0.001
percent residue, in glass bottlesis required. Acetone
from metal containers generally has a high residue blank
and should not be nsed. Sometimes, suppliers transfer
acetoae to glass bottles from metal containers; thus,
acetone blanks shall be ran prior to field use and only
acetone with low blank values (<0.001 percent) shall be
used. In no ease shall a blank value of greater than 0.001
percent of the weight of acetone used be subtracted from
the (ample weight.
8.3 Analysis. Two reagents are required for the analy-
sis:
3.S.1 Acetone. Same as 3.2.
8.8.2 Desiccant. Anhydrous calcium sulfate, indicat-
ing type. Alternatively, other types of desiccants may be
used, subject to the approval of the Administrator.
4. Procedure
4.1 Sampling. The complexity of this method is such
that, in order to obtain reliable results' testers should be
trained and experienced with the test procedures.
4.1.1 I'retest Preparation. All the components snail
be maintained and calibrated according to the procedure
described in APTD-0576, unless otherwise specified
herein.
Weigh several 200 to 300g portions of silicagel in air-tight
containers to the nearest 0.5 g. Record the total weight of
the silica gel plus container, on each container. As an
alternative, the silica gel need not be preweighed, but
may be weighed diioclly in its impinger or sampling
holder just prior to tram assembly.
Check filters visually against light for irregularities and
flaws or p inholc leaks. Label filters of the proper diamel er
on the baok side near the edge using numbering machine
ink. As an alternative, label the shipping containers
(glass or plastic petri dishes) and keep the niters in these
containers at all tu " ' " - -'-- --'
weighing.
containers at all times except during sampling and
Desiccate the filters at 20±5.6° C (68±10° F) and
ambient pressure for at least 24 hours and weigh at in-
tervals of at least 6 hours to a constant weight, i.e.,
<0.5 mg change from previous weighing; record results
to the nearest 0.1 rng. During each weighing the filler
must not be exposed to the laboratory atmosphere for a
period greater than 2 minutes and a relative humidity
above 50 percent. Alternatively (unless otherwise speci-
fied by the Administrator), the filters may be oven
dried at 105° C (220° F) for 2 to 3 hours, desiccated for 2
hours, and weighed. Procedures other than those de-
scribed, -which account for relative humidity effects, may
be used, subject to the approval of the Administrator.
4.1.2 Preliminary- Determinations. Select the sam-
pling site and the minimum number of sampling points
according to Method 1 or as specified by the Administra-
tor. Detcinune the stack pressure, temperature, and the
range of velocity heads using Method 2, It Is recommended
that a leak-check of the pitot lines (see Method 2, Sec-
tion 3.1) be performed. Determine the moisture content
using Approximation Method 4 or its alternatives lor
the purpose of making isokinetic sampling rate settings.
Determine the stack gas dry molecular weight, as des-
cribed in Method 2, Section 3.6; if integrated Method 3
samplinp: :s used for molecular weight determination, the
integrated bag sample shall be taken simultaneously
with, and for the same total length of tune as, the par-
tioulatc sample run,
Select a nozzle size based on the range of velocity heads,
such that it is not necessary to change the nozzle size in
order to maintain isokinetic sampling rates. During the
run, do not change the nozzle size. Ensure that the
proper differential pressure gauge is chosen for the range
of velocit > heads encountered (see Section 2.2 of Method
2).
Select a suitable probe liner and probe length such that
all traverse points can be sampled. For large stacks,
consider sampling from opposite sides, of the stack to
reduce tlie length of probes.
Select a total sampling time greater than or equal to
the minimum total sampling time specified in the test
procedures for the specific industry such that (1) the
sampling time per point is not less than 2 min (or some
greater time interval as specified by the Administrator).
and (2) the sample volume taken (corrected to standard
conditions) will exceed the required minimum total gas
sample volume. The latter Is based on an approximate
average sampling rale.
It is recommended that the number ol minutes sam-
pled at each point be an integer or an integer plus one-
half minute, in order to avoid timekeeping errors. TJie
sampling time at each Writ shall bf the same ^
In some circumstances, e.g., batch cycles, it may be
necessary to sample for shorter times at the traverse
points and to obtain smaller gas sample volumes. In
these cases, the Administrator's approval must first
be obtained.
41.3 Preparation of Collection Train. During prep-
aration and assembly of the sampling train, keep all
openings where contamination can occur covered until
Just prior to assembly or until sampling is about to begin.
Place 100 ml of water in each of the first two impingers,
leave the third impinger empty, and transfer approxi-
mately 200 to 300 g of preweigbed silica gel from its
container to the fourth impinger. More silica gel may be
used, but care should be taken to ensure that it is not
entrained and carried out from the impinger during
sampling. Place the container in a clean place for later
use in the sample recovery. Alternatively, the weight of
the silica gel plus impinger may be determined to the
nearest 0 ,5 g and recorded.
Ill-Appendix A-2 2
-------
Using a tweeier or clean disposable surgical (love*,
pl«c« a labeled (Identified) and weighed filter In the
Biter holder. Be sure vhat the niter Is properly centered
and the gasket properly placed so as to prevent the
ample gas stream from circumventing the niter. Check
the filter for tears after assembly is completed.
When glass liners are used, install the selected noule
using a Viton A O-ring wh«n stack temperatures in
IMS than 200° C (500" F) and an asbestos (trine gasket
when temperatures are higher. See APTD-06,6 lor
details Other connecting systems using either 31G stain
less steel or Teflon ferrules may be used. When metal
liners are used, Install the noule as above or by a leak-
free direct mechanical connection. Mark the probe with
heat resistant tape or by some other method to denote
the proper distance into the stack or duct for each sam-
pling point.
8et up the train as in Figure 5-1, using (if necessary)
a very light" coat of silicone grease on all ground glass
Joints, greasing only the outer portion (see APTD-ft57(i)
to avoid possibility of contamination by the silicone
grease. Subject to the approval of the Administrator, a
glass cyclone may be used between the probe and filter
holder when the total paiticulate cati-h is expected to
exceed 100 mg or when water droplet? are picsrnt in the
stack gas.
Place crushed ice around the iinpmgers
414 Leak-Check Procedures.
4.1.4.1 Pretest Leak-Check. A pretest Icak-i'lic, k is
recommended, but not required. If the tester opts to
conduct the pretest leak-check, the following pioceduie
shall be used.
After the sampling train has been assembled, turn on
and set the filter and probe heating systems at the desired
operating tempei attires. Allow time for the temperatures
to stabilize. If a Viton A O-ring or other leak-free connec-
tion is used in assembling the probe nozzle to the probe
liner, leak-check the train at the sampling site by plug-
ging the nozzle and pulling a 380 mm Hg (15 in. Hg)
vacuum.
NOTE.A lower vacuum may be used, provided that
it is not exceeded during the test.
If an asbestos string is used, do not connect the probe
to the train during the leak-check. Instead, leak-check
the train by first plugging the inlet to the filter holder
(cyclone, if applicable) and pulling a 380 mm Hg (16 in.
Hg) vacuum (see Note immediately above). Then con-
nect the probe to the train and leak-check at about 2o
mm Hg (1 in. Hg) vacuum; alternatively, the probe may
be leak-checked with the rest of the sampling train, in
one step, at 380 mm Hg (15 in. Hg) vacuum. Leakage
rates in excess of 4 percent of the average sampling rate
or 0.00057 m'/min (0.02 cfm), whichever is less, are
unacceptable.
The following leak-check instructions for the sampling
twin described in APTD-ttj7
-------
Take other readings required by Figure 5-2 at least one*
at each sample point during each time increment and
additional readings when significant changes (20 percent
variation In velocity head readings) necessitate addi-
tional adjustments in flow rate. Level and ten the
manometer. Because the manometer level and i«ro may
drift due to vibrations and temperature changes, make
periodic checks during the traverse.
Clean the portholes prior to the tot ran to mlnlmlM
the chance of sampling deposited material. To begin
sampling, remove the noiue cap, verify that the filter
nd prom heating systems are up to temperature, and
that the pilot tube and probe are properly positioned.
Position the nozzle at the first traverse point with the tip
pointing directly into the gas stream, unmediately start
the pump and adjust the flow to laoklnetlc conditions.
Nomographs are available, which aid In the rapid adjust-
ment of the isoklnetlc sampling rate without excessive
computations. These nomographs are designed lor use
when the Type 8 pilot tube coefficient is 8.85±0.02, and
the (tack gas equivalent density (dry molecular weight)
to equal to 29±4. APTD-0676 details the procedure for
using the nomographs. If C, and Mi are outside the
above stated ranges do not use the nomographs unless
appropriate steps (see Citation 7 in Section 7) are taken
to compensate for the deviations.
When the stack is under significant negative pressure
(height of impinger stem), take care to close the coarse
adjust valve before inserting the probe into the stack to
prevent water from backing into the filter holder. If
necessary, the pump may be turned on with the coarse
adjust valve closed.
When the probe is in position, block oft the openings
round the probe and porthole to prevent unrepre-
sentative dilution of the gas stream.
Traverse the stack cross-section, as required by Method
1 or as specified by the Administrator, Deing careful not
to bump the probe nozzle into the stack walls when
sampling near the walls or when removing or inserting
the probe through the portholes; this minimizes the
chance of extracting deposited material.
. During the test run, make periodic adjustments to
keep the temperature around the filter bolder at the
proper level, add more ice and, if necessary, salt to
maintain a temperature of less than 20° C (68° F) at the
condenser/silica gel outlet. Also, periodically check
tne level and zero of the manometer.
If the pressure drop across the filter becomes too high,
making isoklnetlc sampling difficult to maintain, the
filter may be replaced in the midst of a sample run. It
is recommended that another complete filter assembly
be used rather than attempting to change the filter itself.
Before a new filter assembly is installed, conduct a leak-
chexk (see Section 4142). The total particulate weight
shall include the summation of all filter assembly catches.
A single train shall be used lor the entire sample mn,
except in cases where simultaneous sampling IB required
In two or more separate ducts or at two or more different
locations within the same duct, or, In cases where equip-
ment failure necessitates a change of trains. In all other
situations, the use of two or more trains will be subject to
the approval of the Administrator.
Note that when two or more trains an used, separate
analyses of the front-half and (If applicable) Impinger
catches from each train shall be performed, unless Identi-
cal nottle sites were used on all trains, In which case, the
front-half catches from the Individual trains may be
combined (as may the impinger catches) and one analysis
o( front-half catch and one analysis of Impinger catch
may be performed. Consult with the Administrator for
details concerning the calculation of results when two or
more trains are used.
At the end of the sample run, turn off the coarse adjust
valve, remove the probe and noule from the stack, turn
off the pump, record the final dry gas meter reading, and
conduct a post-test leak-check, as outlined In Section
4.1 4 3. Also, leak-check the pitot lines as described In
Method 2, Section 3.1; the lines must pass this leak-check.
In order to validate the velocity head data.
4.1.6 Calculation of Percent Isoklnetlc. Calculate
percent Isokinetic (see Calculations, Section 6) to deter-
mine whether the run was valid or another test run
should be made. II there was difficulty in maintaining
Isokinetic rates due to source conditions, consult with
the Administrator for possible variance on the Isoklnetlc
rates.
4.2 Sample Recovery. Proper cleanup procedure
begins as soon as the probe is removed from the stack at
the end of the sampling period. Allow the probe to cool.
When the probe can be safely handled, wipe off all
external particulate matter near the tip of the probe
noiMe ana place a cap over It to prevent losing or gaining
particulate matter. Do not cap off the probe tip tightly
while the sampling train Is cooling down as this would
create a vacuum In the filter holder, thus drawing water
from the Impingers Into the filter holder.
Before moving the sample train to the cleanup site,
remove the probe from the sample train, wipe off the
silicon* grease, and cap the open outlet of the probe. Be
careful not to lose any condensate that might be present.
Wipe ofl the sillcone grease from the filter Inlet where the
probe was fastened and cap It. Remove the umbilical
cord from the last impinger and cap the impinger. If a
flexible line Is used between the first impinger or con-
denser and the filter holder, disconnect the line at the
filter holder and let any condensed water or liquid
drain Into the impingers or condenser. After wiping off
the sillcone grease, cap off the filter bolder outlet and
Impinger Inlet. Either ground-glass stoppers, plastic
caps, or serum caps may be used to close these openings.
Transfer the probe and filter-lmpinger assembly to the
cleanup area. This area should be clean and protected
from the wind so that the chances of contaminating or
losing the sample will be minimized.
Save a portion of the acetone used for cleanup as a
blank. Take 200 ml of this acetone directly from the wash
bottle being used and place It In a glass sample container
labeled "acetone blank."
Inspect the train prior to and during disassembly and
note any abnormal conditions. Treat the samples as
follows:
Container No. I. Carefully remove the filter from the
filter bolder and place it in Its Identified petri dish con-
tainer. Use a pair of tweezers and/or clean dispos&blo
surgical gloves to handle the filter. If It is necessary to
fold the filter, do so such that the particulate cake is
Inside the fold. Carefully transfer to the petrl dish any
particulate matter and/or filter fibers which adhere to
the filter holder gasket, by using a dry Nylon bristle
brush and/or a sharp-edged blade. Seal the container. °'
Container No, t. Taking care to see that dust on the
outside of the probe or other exterior surface* doe* lot
get Into the sample, quantitatively recover particulate
matter or any condensate from the probe no»le, probe
fitting, probe liner, and front half of the filter boMer by
wathluc them oompouenU with acetone and placing the
wash la a glass container. Distilled water may be wed
instead of acetone when approved by the Administrator
and aball be used m-beu specified by
-------
6. Calibration
Maintain a laboratory log of all calibrations.
S.I Probe Notzle. Probe nozzles shall be calibrated
before their Initial use in the fteld. Using a micrometer,
measure tbe inside diameter of tbe noule to the nearest
0.025 mm (0.001 in.). Make three separate measurements
mlng different diameters each time, and obtain the aver-
age of the measurements. The difference between the high
and low numbers shall not exceed 0.1 mm (0.004 in.).
When nozzles become nicked, dented, or corroded, thej
(hall be reshaped, sharpened, and recalibrated before
use. Each nozzle shall be permanent!; and uniquely
identified.
5.2 Pilot Tube. The Type S pltot tube assembly shall
be calibrated according to the procedure outlined In
Section 4 of Method 2.
8.3 Metering System. Before its initial use in the field,
the metering system shall be calibrated according to the
procedure outlined in APTD-0576. Instead of physically
adjusting the dry gas meter dial readings to correspond
to the wet test meter readings, calibration factors may be
used to mathematically correct the gas meter dial readings
to the proper values. Before calibrating the metering sys-
tem, it is suggested that a leak-check be conducted.
For metering systems having diaphragm pumps, the
normal leak-check procedure will not detect leakages
within the pump. For these cases the following leak-
check procedure is suggested: make a 10-minute calibra-
tion run at 0.00057 m '/mln (a 02 cfm); at the end of the
run, take the difference of the measured wet test meter
and dry gas meter volumes; divide the difference by 10,
to get the leak rate. The leak rate should not exceed
0.00057 m >/min (0.02 cfm).
After each field use, the calibration of the metering
system shall be checked by performing three calibration
runs at a single, intermediate orifice setting (based on
the previous field test), with the vacuum set at the
maximum value reached during the test series. To
adjust the vacuum, insert a valve between the wet test
meter and the inlet of the metering system. Calculate
the average value of the calibration factor. If the calibra-
tion has changed by more than 5 percent, recalibrate
the meter over the full range of orifice settings, as out-
lined in APTD-0576.
Alternative procedures, e.g., using the orifice meter
coefficients, may be used, subject to the approval of the
Administrator.
NOTE.If the dry gas meter coefficient values obtained
before and after a test series differ by more than 6 percent,
the test series shall either be voided, or calculations for
the test series shall be performed using whichever meter
coefficient value (!«, before or after) gives the lower
value of total sample volume.
8.4 Probe Heater Calibration. The probe heating
system shall be calibrated before Its Initial use In the
field according to the procedure outlined in APTD-0576.
Probes constructed according to APTD-0581 need not
be calibrated if the calibration curves in APTD-0578
are used.
8.5 Temperature Oauges. Use the procedure in
Section 4.3 of Method 2 to calibrate in-stack temperature
gauges. Dial thermometers, such as are used for the dry
gas meter and condenser outlet, shall be calibrated
against mercury-ln-glass thermometers.
5.6 Leak Check of Metering System Shown in Figure
8-1. That portion of the sampling train from the pump-
to the orifice meter should be leak checked prior to initial
use and after e ach shipment. Leakage after the pump will
result in less volume being recorded than Is actually
sampled. The following procedure Is suggested (see
Figure 5-4): Close the main valve on the meter box.
Insert a one-hole rubber stopper with rubber tubing
attached into the orifice exhgust pipe. Disconnect and
vent the low side of the orifice manometer. Close off the
low side orifice tap. Pressurize the system to 13 to 18 cm
(8 to 7 in.) water column by blowing Into the rubber
tubing. Pinch off the tubing and observe the manometer
for one minute. A loss of pressure on the manometer
Indicates a leak in the meter box; leaks, if present, must
be corrected.
8.7 Barometer. Calibrate against a mercury barom-
eter.
6. Calculation!
Carry out calculations, retaining at least one extra
decimal figure beyond that of the acquired data. Round
off figures after the final calculation. Other forms of the
equations may be used as long as they give equivalent
results.
Plant.
Date.
Run No..
Filter No..
Amount liquid lost during transport
Acetone blank volume, ml
Acetone wash volume, ml
Acetone blank concentration, mg/mg (equation 5-4).
Acetone wash blank, mg (equation 5-5)
CONTAINER
NUMBER
1
2
TOTAL
WEIGHT OF PARTICIPATE COLLECTED.
mg
FINAL WEIGHT
^xr^
TARE WEIGHT
^xd
Less acetone blank
Weight of parti culate matter
WEIGHT GAIN
FINAL
INITIAL
LIQUID COLLECTED
TOTAL VOLUME COLLECTED
VOLUME OF LIQUID
WATER COLLECTED
IMPINGER
VOLUME,
ml.
SILICA GEL
WEIGHT,
0
9*1 ml
* CONVERT WEIGHT OF WATER TO VOLUME BY DIVIDING TOTAL WEIGHT
INCREASE BY DENSITY OF WATER (1g/ml).
INCREASED : VOLUME WATRtrn,
1 g/ml
Figure 5-3. Analytical data.
Ill-Appendix A-25
-------
RUBBER
TUBING
mm OR,F1CE
VACUUM
GAUGE
LOW INTO TUBING
UNTIL MANOMETER
READS 5 TO 7 INCHES
WATER COLUMN
ORIFICE
MANOMETER
AIR-TIGHT
PUMP
Figure 5-4. Leak check of meter box.
A*
JBw
C.
1*
L,
m.
if.
«
Jt«
?-
Jt
r.
T.
Nomenclature
Crow-sectional area of noitle, m1 (ft1).
Water vapor In the gat stream, proportion
by volume. H7
Acetone blank residue concentration, mg/g.
Concentration of paniculate matter In stack
gaj, dry basis, corrected to standard condi-
tions, g/dscm (g/dscf).
Percent of iaokinetlc sampling.
-Maximum acceptable leakage rate for either a
pretest leak check or for a leak check follow-
ing a component change; equal to 0.00067
mi/min (0.02 cfm) or 4jpereent of the average
sampling rate, whichever is less.
Individual leakage rate observed during the
leak check conducted prior to the l'k"
component change (f-1, 2, 3 .... n),
m>/mln (eta).
-Leakage rate observed daring the post-test
leak check, m'/min (eta).
Total amount of paniculate matter collected,
mg.
Molecular weight of water, 18.0 g/g-mol*
(IS.Olb/lbt-mole).
-Matt of residue of acetone after evaporation,
mg.
-Barometric pressure at the sampling site,
mm Hg (In. Hg).
AbtoluU stack nt pressure, mm Hg (in. Hg).
-Standard absolute pressure, 7«0 mm Hg
0»M In. Hg).
-Idol tat constant, 0.0623* mm Hg-m'/°K-g-
mole (21.86 In. Hg-ftTB-lb-mole).
, -AbtoluU average dry gas meter temperature
(Me Figure 6-2), °K(°R).
Absolute average stack gas temperature (set
Figure 6-2), °K (°R).
14 -Standard absolute temperature, 293° E
(528° H).
Volume of acetone blank, ml.
Volume of acetone used In wash, ml.
Fi.-Total volume of liquid collected in impingen
and silica gel (see Figure 6-3), ml.
V.-Volume of gas sample w iDeasuiofi by dry gat
meter, dem (dcf).
>(>u>"Volume of gat sample measured by the rtry
pi meter, corrected to standard condition,
V.(,u)=Volume ol water vapor In the ifas sample.
corrected to standard conditions, scm (sol)
V = Stack gas velocity, calculated by Method 2,
Equation 29, using data obtained from
Method 5, m/sec (ftSec). 87
W.=Welght of residue In acetone wash, mg.
K=Dry gas meter calibration factor.
AW= Average pressure differential across the oriflce
meter (see Figure 6-2), mm H>O (in. HiO).
P.=Dcnsity of acetone, mg/ml (see label on
bottle).
^.-Density of water, 0.9962 g/ml (0.002201
.
-Total sampling time, min.
»j = 8ampUiig time interval, from the beginning
of a run until the nrst component- change,
min. .
«,= Sampling time interval, between two suc-
cessive component changes, beginning with
the interval between the &rst and second
changes, min.
0P = Sampling time interval, from the final (n")
component change until the end of the
sampling run, min.
13 6= Specific gravity of mercury
60=Sec/min.
100= Con version to percent.
6.2 Average dry gas meter temperature and average
orifice pressure drop. See data sheet (Figure 5-2).
.3 Dry Oas Volume. Correct the sample volume
measured by the dry gas meter to standard conditions
(SOP C, 760 mm Hg or 68° F, 29.92 in. Hg) by using
Equation 5-1.
[p j-MI
_!_JM
P.- I
T.
Equation 6-1
K «='fl !*"* 'Kfnon Hg tor metric units 87
' -17 M "E/ui. Hg tor English onto
NOTS Equation 6-1 can b« osed as written unlesi
the leakage rute observed during any of the mandatary
leak checks (1 «., the poet-test leak check or leak checks
conducted prior to component changes) exceeds £,. U
A» or £, exceeds £>, Equation 6-1 must be modified at
fellows;
(a) Caw I. No component changes made during
ampling run In this case, replace l'« m Equation 5-1
with the .jipression;
(b) Cikie II On* or more component changes made
during Uie sampling run In this case, replace l'» in
Xquation 5-1 by the expression:
>-=2
nd nubstjtiil-e only for those leakage rates (L, or L,)
which exceed L,.
.4 Volume of wi>t«r vapor.
V T / *»
»..id) > It \ ff~
Equation 5- 2
Kj=0 001333 m'/ml for metric units
=0 04707 ft'/ml tor English units.
6.5 Moisture Content.
Equation 5-3
Ill-Appendix A-26
-------
Von-In Mtonted «r w»Uf dropleWaden pa
stream*, two ttfflttH"* oJ the moisture content of the
Mack tat shall be made, one tram the impingw analysis
aquation S-31. and » second from the assumption ol
Iktarated conditions. The tower of the two value* ol
JB« shall be considered oorrart. The procedure tar deter-
alnlng the moisture content baaed upon assumption ol
atturated conditions is given in the Note ol Section 1.2
f Method 4. For the purposes ol this method, theaverage
flack gas temperature from Figure 6-2 may be used to
make this determination, provided that the accuracy ol
the in-stack temperature sensor is ± 1° C (2° F).
6 6 Acetone Blank Concentration.
ca=^
6 7 Acetone Wash Blank.
Equation 5-4
Equation 6-5
6.8 Total Particulate Weight. Determine the total
paniculate catch from the sum of the weight! obtained
Km containers 1 and 2 less the acetone blank (se« Figure
t-i). Noil.Refer to Section 4.1.5 to assist in calculation
«f results Involving two or more- filter assemblies or two
or more sampling bains.
6.9 Particulate Concentration.
6.10
From
ft
g/ft'
g/ft'
e.= (0.001 g/mg)(m*l
Conversion Factors:
To
ir.'ft"
Ib/ft'
fj'm1
Equation b-f
Multiply by
0.02832
15.43
2.206X10-'
36.31
(.11 bokinetic Variation.
t.11.1 Calculation Fromjiav Data.
100 T.[KtV,. + (Vm V/r.) (P*, + AH/13.6)]
60«»4P.A.
Equation 5-7
87
Where
JC«^0.0034M mm Hg-m'/ml °K (or metric units
-0.002669m Hg-rX'/ml-'R lor English unit*.
C.I1.2 Calculation From Intermediate Value.s.
Equation 5-8
where:
Kt-4 320 for metric units
-0.09450 lor English units.
8.12 Acceptablelesults, 1190 percent < I <110 per-
cent, the results are acceptable. If the results are low in
comparison to the standard and 7 is beyond the accept-
able range, or, If / is less than 90 percent, the Adminis-
trator may opt to accept the results. Use Citation 4 to
make Judgments Otherwise, reject the results and repeat
the test.
1 Addendum to Specifications for Incinerator Testing
at Federal Facilities PH9, NCAPC. Dec. 8,196T.
». Martin Robert M. Construction Details of Iso-
kinetic Source-Sampling Equipment. Environmental
Protection Agency. Research Triangle Park, N.C.
APTD-0581. April, 1971.
3 Rom Jerome J. Maintenance, Calibration, ana
Operation of Isokinetic Source Sampling Equipment.
Environmental Protection Agency. Research Triangle
Park, N.C. APTD-0576. March, 1972. ,,__..
4. Smith, W. 8., R. T. Shigehara, ajid W. F. Todd.
A Method of Interpreting Stack Sampling Data. Paper
Presented at the 83d Annual Meeting of the Air Pollu-
tion Control Association, Bt. Louis, Mo. June 14-19,
{ 'Smith, W. 8., *t al. Stack Gas Sampling Improved
and Simplified With New Equipment. APCA Paper
No. «7-119.1987.
«. Specifications lor Incinerator Testing at Federal
Facilities. PHS, NCAPC. 1967.
7, Shigehara, R. T. Adjustments in the EPA Nomo-
graph for Different Pitot Tube Coefficients and Dry
Molecular Weights. Stack Campling News »:4-!l
October. 197<.
8. Vollaro, R. F. A Survey of Commercially Available
Instrumentation For the Measurement of Low-Range
Gas Velocities. U.S. Environmental Protection Agency,
Emission Measurement Branch. Research Triangle
Park, N.C. November, 1976 (unpublished paper).
9. Annual Book of A8TM Standards. Part26. Gaseous
Fuels; Coal and Coke; Atmospheric Analysis. American
Society for Testing and Materials. Philadelphia, Fa.
1974. pp. 617-622.
Ill-Appendix A-27
-------
METHOD 6 DETEHMIKATION OF Svi.rvn DIOXIDE
EMISSIONS FROM STATIO.SARY SOURIES
I. Pritelph and Applictbililii
1.1 Principle. A ns sample is extracted from the
sampling point in the stack. Tbe sulfuric acid mist
(including sulfur trioxide) and tbe sulfur dioxide are
separated. Tbe sulfur dioxide fraction is measured by
the barium-thorin titration method.
1.2 Applicability. This method is applicable for tbe
determination of sulfur dioxide emissions from stationary
sources. The minimum detectable limit of the method
has been determined to be 3.4 milligrams (mg) of BOi/m>
(2.12X10-' lb/tt«). Although no upper limit has been
established, tests have shown that concentrations as
high as 80,000 mg/mi of 80j can be collected efficiently
in two midget impingers, each containing 15 millihurs
of 3 percent hydrogen peroxide, at a rate of 1.0 1pm for
20 minutes. Based on theoretical calculations, the upper
concentration limit in a 20-hter sample is about 93.300
xng/mj.
Possible interferents are free ammonia, water-soluble
cations, and fluorides. The cations and fluorides are
removed by glass wool Alters and an isopropanol bubbler,
and hence do not aflect the SOj analysis. When samples
are being taken from a gas stream with high concentra-
tions of very fine metallic fumes (such as in Inlets to
control devices), a high-efficiency glass fiber filter must
be used in place of the glass wool plug (i.e., the one in
the probe) to remove the cation inlerferents.
Free ammonia interferes by reacting with SOi to form
Particular sulfile and by reacting with the indicator.
If free ammonia is present (this can be determined by
knowledge of the process and noticing white particular
matter in the probe and isopropanol bubbler), alterna-
tive methods, subject to the approval of the Administra-
tor, U.S. Environmental Protection Agency, art
required.
2. Apparottu
3.1 Sampling. The sampling train Isihown in Figure
0-1, and component puts an discussed below. Tbe
t«M«r bu tbe option of substituting sampling equip-
ment described in Method 8 in place of tbe midget irn-
pinger equipment of Method 6. However, the Method 8
Bain must be modified to Include a heated filter between
tbe probe and Isopropanol Impinger, and the operation
of the sampling train and sample analysis must be at
tbe flow rates and solution volumes defined ID Method 8.
The tester also bag tbe option of determining SO,
simultaneously with paniculate matter and moisture
determinations by (1) replacing the water in a Method 5
Impinger system with 3 percent peroxide solution, or
0) by replacing tbe Method 5 water impinger system
with a Method 8 tsopropanol-fllter-pexoiide system, Tbe
analysis for 8Qi must be consistent with tbe procedure
In Method 8.87
11.1 Probe. Borosilicate glass, or stainless steel (other
materials of construction may be used, subject to tbe
approval of tbe Administrator), approximately 6-mm
Inside diameter, with a heating system to prevent water
condensation and a filter (either ln-ctack or heated out-
stack) to remove paniculate matter, including sulluric
add mist. A plug of glass wool Is a satisfactory filter.
2.1.2 Bubbler and Impingers. One midget bubbler,
with medium-coarse glass frit and borosilicate or quartz
glass wool packed in top Owe Figure 6-1) to prevent
snlfuric add mist carryover, and three 30-ml midget
Impingers. The bubbler and midget impingers must be
connected In series with leak-tree glass connectors. Sili-
con* grease may be used , if necessary, to prevent leakage.
At tbe option of the tester, a midget Impinger may be
need in place of tbe midget bubbler.
Otter collection absorbers and flow rates may be used,
but are subject to tbe approval of the Administrator.
Also, collection efficiency must be shown to be at least
90 percent for each test run and must be documented In
the report. If the efficiency Is found to be acceptable after
aeries of three tests, further documentation is not
required. To conduct the efficiency test, an extra ab-
sorber must be added and analyted separately. This
extra absorber must not contain more than 1 percent of
tb* total BOi.
J.1J Glass Wool. Borosilicate or quarts.
».1.4 Stopcock Grease. Acetone-Insoluble, beat-
liable slllcone grease may be used. If necessary.
11.8 Temperature Gauge. Dial thermometer, or
equivalent, to measure temperature of gas leaving 1m-
plnger train to within 1* C (2*F.)
11.6 Drying Tube. Tube packed with 8- to 16-meah
radicating type silica gel, or equivalent, to dry the ga>
ple and to protect the meter and pump. If the illlca
has been used previously, dry at 176* C (350- F) for
urs. New silica gel may be used as received. Alterna-
2.1.10 Volume Meter. Dry gas meter, sufficiently
accurate to measure the sample volume within 2 percent,
calibrated at tbe selected flow rate and conditions
actually encountered during sampling, and equipped
with a temperature gauge (dial thermometer, or equiv-
alent) capable of measuring temperature to within
2.1.11 Barometer. Mercury, aneroid, or other barom-
eter capable of measuring atmospheric pressure to within
2.6mm Hg (0.1 In. Hg). In many cases, the barometric
reading may be obtained from a nearby national weather
service station, In which cam tbe station value (which
Is the absolute barometric pressure) shall be requested
and an adjustment for elevation differences between
the weather station and sampling point shall be applied
atarateof minus2.5mm Hg (0.1 in. Hg) per 30m (100ft).,,
elevation Increase or vice versa for elevation decrease.87
2.1.12 Vacuum Gauge and rotameter. At least 760
mm Hg (30 ln.Hf) gauge, and 0-40 cc/mln rotameter
to be used for leak cberk of the sampling train. 87
12.1 Wash bottles. Polyethylene or giass, 500 ml,
two.
12.2 Storage Bottles. Polyethylene, 100 ml, to store
Impinger samples (one per sample).
" "-1 (one ""
am
gel
2 hours. New silica gel may be us
tively, other types of desiccants (equivalent or better)
may be used, subject to approval of the Administrator. 87
2.1.7 Valve. Needle value, to regulate sample gas flow
nte.°7
2.1.8 Pomp. Leak-free diaphragm pomp, or equiv-
alent, to pull gas through tbe train. Install a small lurge
tank between tbe pump and rate meter to eliminate
the pulsation effect of tbe diaphragm pump on the rota -
2.1.9 Bate Meter. Rotameter, or equivalent, capable
of measuring Bow rate to within 2 percent of the selected
flow rate of about 1000 ce/roin.
2.1.3 Burettes. 5- and SO-ml sites.
114 Erlenmeyer Flasks. 260 mi-site (one for each
sample, blank, and standard).
2.3.6 Dropping Bottle. 125-ml site, to add indicator.
13.8 Graduated Cylinder. 100-ml site.
11.7 Spectropbotometer. To measure absorbance at
362 nanometers.
1. Reagenli
Unless otherwise indicated, all reagents must conform
to tbe specifications established by the Committee on
Analytical Reagents of the American Chemical Society.
Where such specifications are not available, use the best
available grade.
1.1 Sampling.
3.1.1 Water. Deionlted. distilled to conform to A8TM
specification D1183-74, Type 3. At the option of tbe
analyst, tbe KMnO. test for oxidltable organic matter
may be omitted when high concentrations of organic
matter are not expected to be present.
1.1.2 Isopropanol, 80 percent. Mil 80 mi of isopropanol
with 20 ml of deionited. distilled water. Check each lot of
Isopropanol for peroxide impurities as follows: shake 10
ml of Isopropanol with 10 ml of freshly prepared 10
percent potassium iodide solution. Prepare a blank by
similarly treating 10 ml of distilled water. After 1 minute,
read tbe absorbance at 382 nanometers on a spectro-
pbotometer. If absorbance exceeds 0.1, reject alcohol for
use.
Peroxides may be removed from Isopropanol by redis-
tilling or by passage through a column of activated
alumina; however, reagent grade isopropanol with
suitably low peroxide levels may be obtained from com-
mercial sources. Rejection of contaminated lots may,
therefore, be a more efficient procedure.
1.1.1 Hydrogen Peroxide, 1 Percent. Dilute 30 percent
hydrogen peroxide 1:9 (v/v) with delonited, distilled
water (10 ml Is needed per sample). Prepare fresh dally.
1.1.4 Potassium Iodide Solution, 10 Percent. Dissolve
10.0 grams KI In deionited, distilled water and dilute to
100 ml. Prepare when needed.
1.2 Sample Recovery.
1.2.1 Water. Deionited, distilled, as in 3.1.1.
1.2.2 Isopropanol, 80 Percent. Mix 80 ml of Isopropanol
with 20 ml of delonited, distilled water.
3.3 Analysis.
3.3.1 Water. Deionited, distilled, as in 3.1.1.
3.3.2 Isopropanol, 100 percent.
3.3.3 Thorin Indicator. l-(o-arsonophenylaio)-2-
naphthol-3,6-disul(onic acid, dlsodium salt, or equiva-
lent. Dissolve 0.20 g in 100 ml of deionited, distilled
water.
3.1.4 Barium Percblorate Solution, 0.0100 N. Dis-
solve 1.95 g of barium perchlorate trihydrate (Ba(ClO,),
SBiOl In 200 ml distilled water and dilute to 1 liter with
Isopropanol. Alternatively, 1.22 g of [BaCli-2H,O] may
be used Instead of the perchlorate. Standardly as In
Section 5.6187
3.3.5 Sulfurtc Acid Standard, 0.0100 N. Purchase or
standardise to "0.0002 N against 0.0100 N NaOH which
has previously been standardized against potassium
acid phthalate (primary standard grade).
4. Procedure,
4.1 Sampling.
4.1.1 Preparation of collection train. Measure 15 ml of
80 percent isopropanol Into the midget bubbler and 15
ml of 3 percent hydrogen peroxide into each of the flrtt
two midget impingers. Leave the final midget Impinger
dry. Assemble the train as shown in Figure 6-1. Adjust
probe heater to a temperature sufficient to prevent water
condensation. Place crushed ice and water around the
Impingers.
4 1.2 Leak-check procedure. A leak check prior to the
sampling run is optional: however, a leak check after the
sampling run is mandatory. The leak-check procedure Is
as follows:
Temporarily attach a suitable (e.g., <>-40
ec/min) rotameter to the outlet of the dry
gas meter and place a vacuum gauge at or
near tbe probe inlet. Plug the probe Inlet,
pull a vacuum of at least 250 mm Hg (10 in.
Hg). and note the flow rate as indicated by
the rotameter. A leakage rate not in excess
of 2 percent of the average sampling rate is
acceptable.
None Carefully release the probe Inlet
plug before turning off the pump.
It la suggested (not mandatory) that the
pump be leak-checked separately, either
prior to or after the sampling run. If done
prior to the sampling run, the pump leak-
check shall precede the leak check of the
sampling train described immediately above;
if done after the sampling run, the pump
leak-check shall follow the train leak-check.
To leak check the pump, proceed as follows:
Disconnect the drying tube from the probe-
impinger assembly. Place a vacuum gauge at
the inlet to either tbe drying tube or the
pump, pull a vacuum of 250 mm (10 in.) Hg.
plug or pinch off the outlet of the flow
meter and then turn off the pump. The
vacuum should remain stable for at least 30
seconds. 87
Other leak check procedures may be used, subject to
the approval of the Administrator, U.S Environmental
, .
Protection Agency. The procedure used In Method 5 Is
ot suitable for diaphragm pumps.
4 1.3 Sample collection. Record the initial dry gas
.
meter reading and barometric pressure. To begin sam-
pling, position the tip of the probe at the sampling point,
connect the probe to the bubbler, and start the pump.
Adjust the sample flow to a constant rate of ap-
proximately 1.0 liter/min as Indicated by the rotameter.
Maintain this constant rate (*10 percent) during the
entire sampling run. Take readings (dry gas meter,
temperatures at dry gas meter and at Impinger outlet
and rate meter) at least every 5 minutes. Add more Ice
during the run to keep the temperature of tbe gases
leaving the last Impinger at 20° C (68* F) or less. At the
conclusion of each run, turn off the pump, remove probe
from the stack, and record the final readings. Conduct a
leak check as in Section 4.1.2. (This leak check is manda-
tory ) If a leak Is found, void the test run , or uw proem -
ure> acceptable to the Administrator to adjiut the umpM
volume for the leakage Drain the <-« both, and purge
the remaining part of the train by dre ring clean ambient
air through the system for 15 minutes at the sampling
rate. 87
Clean ambient air can be provided by passing air
through a charcoal filter or through an extra midget
Impinger with 15 ml of 3 percent HiOi. The tester may
opt to simply use ambient air, without purification.
4.2 Sample Recovery. Disconnect the Impingers after
purging. Discard tbe contents of the midget bubbler. Pour
the contents of the midget Impingers into a leak-free
polyethylene bottle for shipment. Rinse the three midget
impingers and the connecting tubes with deloniied,
distilled water, and add the washings to the same storage
container. Mark the fluid level. Seal and identify the
sample container.
4.1 Sample Analysis. Note level of liquid in container,
and confirm whether any sample was lost during ship-
ment; note this on analytical data sheet. If a noticeable
amount of leakage has occurred, either void tbe sample
or use methods, subject to the approval of the Adminis-
trator, to correct the final results.
Transfer the contents of the storage container to a
100-ml volumetric flask and dilute to exactly 100 ml
with deionited, distilled water. Pipette a 20-ml aliquot of
this solution into a 250-ml Erlenmeyer flask, add 80 ml
of 100 percent Isopropanol and two to four drops of thortn
indicator, and titrate to a pink endpolnt using 0.0100 N
barium perchlorate. Repeat and average the titration
volumes. Run a blank with each series of samples. Repli-
cate titrations must agree within 1 percent or 0.2 ml,
whichever Is larger.
(Now. Protect the 0.0100 N barium perchlorate
solution from evaporation at all times.)
5. Calibration
5.1 Metering System.
5.1.1 Initial Calibration. Before Its initial use in tbe
field, first leak check the metering system (drying tube,
needle valve, pomp, rotameter, and dry gas meter) as
III-Appendix A-2 8
-------
follows: place a vacuum gauge at tbe Inlet to the drytof
tube and pull a vacuum of MO mm (10 tn.) HI; plug at
pinch off the outlet of the flow meter, and then turn of
the pump. The vacuum (hall remain stable tor at lent
30 seconds. Carefully release the vacuum gauge before
releasing the flow meter end. 87
Neit, calibrate the metering system (at the sampling
flow rate specified by the method) a> follows: connect
an appropriately sized wet test meter (e.g., 1 liter par
revolution) to the inlet of the drying tube. Make three
Independent calibration runs, using at least five revolu-
tions of the dry gas meter per run. Calculate the calibra-
tion factor, Y (wet test meter calibration volume divided
by the dry gas meter volume, both volumes adjusted to
the same reference temperature and pressure), for each
run, and average the results. If any Y value deviate* by
more than 2 percent from the average, the metering
system is unacceptable for use. Otherwise, use the aver-
age as the calibration factor for subsequent test ran*.
5.1.2 Post-Test Calibration Check. After each field
test series, conduct a calibration check as in Section 1.1.1
above, eicept for the following variations: (a) the teak
check Is not to be conducted, (b) three, or more revolu-
tions of the dry gas meter may be used, and (c) only two
Independent runs need be made. If the calibration factor
does not deviate by more than 5 percent from the Initial
calibration factor (determined In Section 5.1.1), then the
dry gas meter volumes obtained during tbe test serin
are acceptable. If the calibration factor deviates by more
than 5 percent, recalibrate tbe metering system as in
Section 5.1.1, and for the calculations, use the calibration
factor (initial or recalibratlon) that yields the lower gas
volume for each test nut.
5.2 Thermometers. Calibrate against mercury-ln-
glass thermometers.
5.3 Rotameter. The rotameter need not be calibrated
but should be cleaned and maintained according to the
manufacturer's instruction.
5.4 Barometer. Calibrate against a mercury barom-
eter.
i.i Barium Perchlorate Solution. Standardise the
barium perchlorate solution against 25 ml of standard
Jill/uric acid to which 100 ml of 100 percent tsopropanot
has been added.
Carry out calculations, retaining at least one extra
decimal figure beyond that of the acquired data. Round
off figures after final calculation.
6.1 Nomenclature.
. B°K/mmHg for metric unite.
-17.94 «R/ln. Hg for English unit*.
6.3 Sulfur dioxide concentration.
(?«, -Concentration of sulfur dioxide, dry ___
' corrected to standard conditions, mg/dscm
. (Ib/dscf).
-V- Normality of barium perchlorate titrant,
mllllequivalents/ml.
Pb.r Barometric pressure at the exit orifice of the
dry gas meter, mm Hg (in. Hg).
Pud -Standard absolute pressure, 700 mm Hg
(29.92 In. Hg).
T«- Average dry gas meter absolute temperature,
°K (°R).
r.ia- Standard absolute temperature, 293° K
(528° R).
V.- Volume of sample aliquot titrated, ml.
V«»Dry gas volume as measured by the dry gaa
meter, dcm (dcf).
V.(.u)-Dry gae volume measured by the dry gat
meter, corrected to standard conditions,
dscm (dscf).
Vtoi.aTotal volume of solution In which the sulfur
dioxide sample Is contained, 100 ml.
V'i-Volume of barium perchlorate titrant used
for the sample, ml (average of replicate
titratlons).
Vii-Volume of barium perchlorate titrant used
for the blank, ml.
y»Dry gas meter calibration factor.
32. 03- Equivalent weight of sulfur dioxide.
6.2 Dry sample gas volume, corrected to standard
conditions.
P b«r
when:
Equation 8-1
Equation 6-2
where:
Jf i32.03 mg/meq. for metric units.
-7.061X10-« Ib/meq. for English unite.
7. BfMJorrapJhy
1. Atmospheric Emissions from Sulfuric Acid Manu-
facturing Processes. U.S. DHEW, PH8, Division of Air
Pollution. Public Health Service Publication No.
999-AP-13. Cincinnati, Ohio. 1965.
2. Corbett, P. F. The Determination of 8O> and SOi
In Flue Gases. Journal of the Institute of Fuel. J+V 237-
243,1961.
3. Matty, R. E. and E. K. Dlehl. Measuring Flue-Gas
SOi and SOi. Power. 101: 94-97. November 1957.
4. Patton, W. F. and J. A. Brink, Jr. New Equipment
and Techniques for Sampling Chemical Process Gases.
J. Air Pollution Control Association. IS: 162.1963.
5. Rom, J. J. Maintenance, Calibration, and Operation
of Isokinetic Source-Sampling Equipment. Office of
Air Programs, Environmental Protection Agency.
Research Triangle Park, N.C. APTD-0576. March 1972.
6. Hamil, H. F. and D. E. Camann. Collaborative
Study of Method for the Determination of Sulfur Dioxide
Emissions from Stationary Sources (Fossil-Fuel Fired
Steam Generators). Environmental Protection Agency,
Research Triangle Park, N.C. EPA-650/4-74-024.
December 1973.
7. Annual Book of A8TM Standards. Part 31; Water,
Atmospheric Analysis. American Society for Testing
and Materials. Philadelphia, Fa. 1974. pp. 40-42.
8. Knoll, J. E. and M. R. Midgett. The Application of
EPA Method 6 to High Sulfur Dioxide Concentrations.
Environmental Protection Agency. Research Triangle
Park, N.C. EPA-600/4-76-03B. July 1976.
PROBE (END PACKED
WITH QUARTZ OR
PYREX WOOL)
STACK WALL
THERMOMETER
MIDGET IMPINGERS
ICE BATH
THERMOMETER
SILICA GEL
DRYING TUBE
PUMP
Figure 6-1. S02 sampling train.
SURGE TANK
Ill-Appendix A-2 9
-------
METHOD 7DETERMINATION or NITROOIN
EMISSIONS FBOM STATIONAET SOURCES
1. Principle and ApfUcabSHti
1.1 Principle. A grab sample is collected in an evacu-
ated flask containing a dilute suUuric acid-hydrogen
peroxide absorbing solution, and the nitrogen oxides,
except nitrous oxide, are measured colorimeterically
using the phenoldlsul/onlc acid (PD8) procedure.
1.2 Applicability. This method is applicable to the
measurement of nitrogen oxides emitted from stationary
sources. The range of the method has been determined
to be 2 to 400 milligrams NO, (as NO,) per dry standard
cubic meter, without having to dilute the sample.
2. Apparatui
2.1 Sampling (see Figure 7-1). Other grab sampling
systems or equipment, capable of measuring sample
volume to within ±2.0 percent and collecting a sufficient
sample volume to allow analytical reproducibllity to
within ±5 percent, will be considered acceptable alter-
natives, subject to approval of the Administrator, U.S.
Environmental Protection Agency. The following
equipment is used in sampling:
2.1.1 Probe. Borosilicate glass tubing, sufficiently
heated to prevent water condensation and equipped
with an in-slack or oat-stack filter to remove partlculate
matter (a plug of glass wool is satisfactory for this
purpose). Stainless steel or Teflon' tubing may also be
used for the probe. Heating is not necessary if the probe
remains dry during the purging period.
> Mention of trade names or specific products does not
constitute endorsement by the Environmental Pro-
tection Agency.
2.1.2 Collection Flask. Two-liter borosillcate, round
bottom flask, with short neck and 24/40 standard taper
opening, protected against Implosion or breakage.
2.1.3 Flask Valve. T-bore stopcock connected to a
24/40 standard taper Joint.
2.1.4 Temperature Gauge. Dial-type thermometer, or
other temperature gauge, capable of measuring 1° C
(2° F) intervals from -5 to 5
-------
3. Reagent!
Unless otherwise indicated, It Is Intended that mil
reagents conform to the specifications established by the
Committee on Analytical Reagents of the American
Chemical Society, where such specifications are avail-
able; otherwise, use the best available grade.
1.1 Sampling. To prepare the absorbing solution,
cautiously add 2.8 ml concentrated HiSO( to 1 liter of
delonited, distilled water. Mix well and add 6 ml of 3
percent hydrogen peroxide, freshly prepared from 80
percent hydrogen peroxide solution. The absorbing
solution should be used within 1 week of its preparation.
Do not expose to extreme heat or direct sunlight
Sample Recovery. Two reagents are required for
la rvui/Mrar-it.
H.2.1 Sodium Hydroxide (IN). Dissolve 40 g NaOH
In deionited, distilled water and dilute to 1 liter.
8.2.2 Water. Deionited, distilled to conform to ASTM
specification D1103-74, Type 8. At the option of the
analyst, the KMNO( test for oxidliable organic matter
may be omitted when high concentrations of organic
matter are not expected to De present.
3.3 Analysis. For the analysis, the following reagents
are required:
8.3.1 Fuming Sulfuric Acid. 15 to 18 percent by weight
free sulfur trioxide. HANDLE WITH CAUTION.
3.3.2 Phenol. White solid.
3.3.8 Sulfuric Acid. Concentrated, 95 percent mini-
mum assay. HANDLE WITH CAUTION.
8.3.4 Potassium Nitrate. Dried at 105 to 110° C (220
to 230° F) for a minimum of 2 hours Just prior to prepara-
tion of standard solution.
3.3.5 Standard KNOi Solution. Dissolve exactly
2.188 g of dried potassium nitrate (KNOs) in deionited,
distilled water and dilute to 1 liter with deionited,
distilled water in a 1.000-ml volumetric flask.
3.3.6 Working Standard ENOi Solution. Dilute 10
ml of the standard solution to 100 ml with deiontted
distilled water. One milliliter of the working standard
solution is equivalent to 100 ng nitrogen dioxide (NOi).
8.3.7 Water. Deionited, distilled as in Section 3.2.2.
8.3.8 Phenoldisulfonic Acid Solution. Dissolve 25 g
of pure white phenol in 150 ml concentrated sulfuric
cid on a steam bath. Cool, add 75 ml fuming sulfuric
cid, and heat at 100° C (212° F) for 2 hours. Store in
dark, stoppered bottle.
4. Procedure*
4.1 Sampling.
4.1.1 Pipette 25 ml of absorbing solution into a sample
flask, retaining a sufficient quantity for use in preparing
the calibration standards. Insert the flask valve stopper
Into the flask with the valve in the "purge" position.
Assemble the sampling train as shown in Figure 7-1
and place the probe at the sampling point. Make sure
that all fittings are tight and leak-free, and that all
ground glass Joints have been properly greased with a
high-vacuum, high-ternperature chlorofluorocarbon-
based stopcock grease. Turn the flask valve and the
pump valve to their "evacuate" positions Evacuate
the flask to 75 mm Hg (3 in. Hg) absolute pressure, or
leas. Evacuation to a pressure approaching the vapor
pressure of water at the existing temperature is desirable
Turn the pump valve to its r'vent" position and turn
off the pump. Check for leakage by observing the ma-
nometer for any pressure fluctuation (Any variation
greater than 10 mm Hg (0.4 In. Hg) over a period of
1 minute Is not acceptable, and the flask is not to be
used until the leakage problem Is corrected. Pressure
In the flask is not to exceed 75 mm Hg (3 in. Hg) absolute
at the time sampling is commenced.) Record the volume
of the flask and valve (Vi), the flask temperature (T.),
and the barometric pressure. Turn the flask valve
counterclockwise to its "purge" position and do the
same with the pump valve. Purge the probe and the
vacuum tube using the squeeze bulb. If condensation
occurs in the probe and the flask valve area, heat the
probe and purge until the condensation disappears
Next, turn the pump valve to its "vent" position. Turn
the flask valve clockwise to its "evacuate" position and
record the difference in the mercury levels in the manom-
eter. The absolute internal pressure in the flask (Ft)
Is equal to the barometric pressure less the manometer
reading Immediately turn the flask valve to the "sam-
ple" position and permit the gas to enter the flask until
pressures in the flask and sample line (i.e., duct, stack)
are equal. This will usually require about 15 seconds;
a longer period indicates a "plug" in the probe, which
must be corrected before sampling is continued After
collecting the sample, turn the flafk valve to its "purge"
position and disconnect the flask from the sampling
train. Shake the flask for at least 5 minutes.
4.1.2 If the gas being sampled contains insufficient
oxygen for the conversion of NO to NO: (e.g., an ap-
plicable subpart of the standard may require taking a
sample of a calibration gas mixture of NO in Ni), then
oxygen shall be introduced into the flask to permit this
conversion. Oxygen may be introduced into the flask
by one of three methods; (1) Before evacuating the
sampling flask, flush with pure cylinder oxygen, then
evacuate flask to 75 mm Hg (3 in. Hg) absolute pressure
or less; or (2) inject oxygen into the flask after sampling;
or (3) terminate sampling with a minimum of 50 mm
Hg (2 in. Hg) vacuum remaining in the flask, record
this final pressure, and then vent the flask to the at-
mosphere until the flask pressure is almost equal to
atmospheric pressure.
4.2 Sample Recovery Let the flask set for a minimum
of It hours and then shake the contents for 2 minutes
Connect the flask to a mercury filled U-tube manometer
Open the valve from the flask to the manometer and
record the flask temperature (TV), the barometric
pressure, and the difference between the mercury levels
in the manometer. The absolute internal pressure In
the flask (Pi) is the barometric pressure less the man-
ometer reading. Transfer the contents of the flask to a
leak-free polyethylene bottle Hinse the flask twice
with 5-ml portions of deionized, distilled water and add
the rinse water to the bottle. Adjust the pH to between
0 and 12 by adding sodium hydroxide (1 N), dropwise
(about 25 to 85 drops) Check the pH by dipping a
stirring rod into the solution and then touching the rod
to the pH test paper Remove as little material as possible
during this step Mark the height of the liquid level so
that the container can be checked for leakage after
transport Label the container to clearly Identify its
contents. Seal the container for shipping. 87
4.3 Analysis. Note the level of the liquid in container
and confirm whether or not any sample was lost during
shipment; note this on the analytical data sheet. If a
noticeable amount of leakage has occurred, either void
the sample or use methods, subject to the approval of
the Administrator, to correct the final results. Immedi-
ately prior to analysis, transfer the contents of the
shipping container to a 50-ml volumetric flask, and
rinse the container twice with 5-ml portions of deionited.
distilled water. Add the rinse water to the flask and
dilute to the mark with deionited, distilled water; TTIJT
thoroughly. Pipette a 25-ml aliquot into the procelaln
evaporating dish. Return any unused portion of the
sample to the polyethylene storage bottle. Evaporate
the 25-ml aliquot to dryness on a steam bath and allow
to cool. Add 2 ml phenoldisulfonic acid solution to the
dried residue and triturate thoroughly with a polyethyl-
ene policeman. Make sure the solution contacts all the
residue. Add 1 ml deionited, distilled water and four
drops of concentrated sulfuric acid. Heat the solution
on a steam bath for 3 minutes with occasional stirring.
Allow the solution to cool, add 20 ml deionited, distilled
water, mix well by stirring, and add concentrated am-
monium hydroxide, dropwise, with constant stirring,
until the pH is 10 (as determined by pH paper). If the
sample contains solids, these must be removed by
nitration (centrifugation is an acceptable alternative,
subject to the approval of the Administrator), as follows:
filter through Whatman No. 41 filter paper into a 100-ml
volumetric flask; rinse the evaporating dish with three
5-ml portions of deionited, distilled water; filter these
three rinses. Wash the filter with at least three 15-ml
portions of deionited, distilled water. Add the filter
washings to the contents of the volumetric flask and
dilute to the mark with deionited, distilled water. If
tolids are absent, the solution can be transferred directly
to the 100-ml volumetric flask and diluted to the mark
with deiomied, distilled water. Mix the contents of the
flask thoroughly, and measure the absorbance at the
optimum wavelength used for the standards (Section
6.2.1), using the blank solution as a tero reference. Dilute
the sample and the blank with equal volumes of deion-
iied, distilled water if the absorbance exceeds A,, the..,
bsorbance of the 400 ^g N Oj standard (see Section 5.2.2) ?'
8. CaUbralUm
4.1 Flask Volume The volume o( the collection flask-
flaak valve combination must be known prior to aam-
pling. Assemble the flask and flask valve and fill with
water, to the stopcock Measure the volume of water to
±10 ml. Record this volume on the flask.
4.2 Spectrophotometer Calibration.
4.2.1 Optimum Wavelength Determination.
Calibrate the wavelength scale of the spec-
trophotometer every 6 months. The calibra-
tion may be accomplished by using an
energy source with an Intense line emission
such as a mercury lamp, or by using a series
of glass filters spanning the measuring
range of the Spectrophotometer. Calibration
materials are available commercially and
from the National Bureau of Standards.
Specific details on the use of such materials
should be supplied by the vendor; general
Information about calibration techniques
can be obtained from general reference
books on analytical chemistry. The wave-
length scale of. the Spectrophotometer must
read correctly within ± 5 nm at all calibra-
tion points; otherwise, the Spectrophoto-
meter shall be repaired and recalibrated.
Once the wavelength scale of the Spectro-
photometer is in proper calibration, use 410
nm as the optimum wavelength for the mea-
surement of the absorbance of the stan-
dards and samples. °7
Alternatively, a scanning procedure may
be employed to determine the proper mea-
suring wavelength. If the instrument is a
double-beam Spectrophotometer, scan the
spectrum between 400 and 415 nm using a
200 fig NO, standard solution in the sample
cell and a blank solution in the reference
cell. If a peak does not occur, the Spectro-
photometer is probably malfunctioning and
should be repaired. When a peak is obtained
within the 400 to 416 nm range, the wave-
length at which this peak occurs shall be
the optimum wavelength for the measure-
ment of absorbance of both the standards
and the samples. For a sipgle-beam Spectro-
photometer, follow the scanning procedure
described above, except that the blank and
standard solutions shall be scanned sepa-
rately. The optimum wavelength shall be
the wavelength at which the maximum dif-
ference In absorbance between the standard
and the blank occurs.S7
8.2.2 Determination of Spectrophotometer
Calibration Factor 1C- Add 0.0 ml, 2 ml, 4
ml, 6 ml, and 8 ml of the KNO, working
standard solution (1 ml=100 >ig NO.) to a
series of five 50-ml volumetric flasks. To
each flask, add 25 ml of absorbing solution,
10 ml deionized, distilled water, and sodium
hydroxide (1 N) dropwise until the pH U be-
tween 9 and 12 (about 25 to 35 drop* each).
Dilute to the mark with deionized, distilled
water. Mix thoroughly and pipette a 25-ml
aliquot of each solution into a separate por-
celain evaporating dish.87
Beginning with the evaporation step, follow the analy-
sis procedure of Section 4.3. until the solution has been
transferred to the 100 ml volumetric flask and diluted to
the mark Measure the absorbance of each solution, at the
optimum wavelength, as determined in Section 6.2.1.
This calibration procedure must be repeated on each day
that samples are analyted. Calculate the Spectrophotom-
eter calibration factor as follows.
K,= 100^
Equation 7-1
where:
K<- Calibration factor
X|=Absorbance of the 100-»ig NOi standard
X>-> Absorbance of the 200-pg NOi standard
At= Absorbance of the SOO-jig NOi standard
Xt-Absorbance of the 400-wg NOi standard
6.3 Barometer. Calibrate against a mercury barom-
eter.
5.4 Temperature Gauge. Calibrate dial thermometers
agaliiSt mercury-in-glass thermometers.
6.5 Vacuum Gauge. Calibrate mechanical gauges, If
used, against a mercury manometer such as that speci-
fied in 2.1.0.
S.t Analytical Balance. Calibrate against standard
weights.
A. Calculation*
Carry out the calculations, retaining at least one extra
decimal figure beyond that of the acquired data. Round
off figures after final calculations.
6.1 Nomenclature.
A"= Absorbance of sample.
C-Concentratiort of NO, as NO», dry basis, cor-
rected to standard conditions, mg/dscm
flb/dscf)
^Dilution factor (ie., 25/5, 26/10, etc., required
only if sample dilution was needed to reduce
the absorbance. into the range of calibration).
Jf.Spectrophotometer calibration factor R7
m -Mass of NO, as NOiin gas sample, nf. °'
P/-Final absolute pressure of flask, mm Hg (in. Hg)
P, = Jnitial absolute pressure of flask, mm Hg (in.
Hg)
P,id= Standard absolute pressure, 760mm Hg (29 92 in.
He).
T/=Final absolute temperature of flask ,°K (°R).
r(«=Initial absolute temperature of flask. °K (°R).
r,t
-------
6.3 Total if NOi per sample.
Equation 7-3
NOTE. If other than a 25-ml aliquot Is used (or analy-
sis, the factor 2 must be replaced by a corresponding
factor.
«.4 Sample concentration, dry basis, corrected to
standard conditions.
C=Kj
Equation 7-4
where:
K 10>
for metric units
6.243X 10-'
-
Mg/ml
for English units
S. Jacob, M. B. The Chemical Analysis of Air Pollut-
ants. New York. Intersclence Publishers, Inc. 1960.
Vol. 10, p. 351-396.
4. Beatty, R. I/., L. B. Berger, and H. H. Schrenk.
Determination of Oxides of Nitrogen by the Phenoldieul-
fonlc Acid Method. Bureau of Mines, U.S. Dent, of
Interior. R. I. 3687. February 1943.
6. Hamil, H. F. and D. E. Camann. Collaborative
Study of Method for the Determination of Nitrogen
Oxide Emissions from Stationary Sources (Fossil Fuel-
Fired Steam Generators). Southwest Research Institute
report for Environmental Protection Agency. Research
Triangle Park, N.C. October 5,1973.
6. Hamil, H. F. and R. E. Thomas. Collaborative
Study of Method for the Determination of Nitrogen
Oxide Emissions from Stationary Sources (Nitric Acid
Plants). Southwest Research Institute report for En-
vironmental Protection Agency. Research Triangle
Park, N.C. May 8,1974.8
7. BibHofrapky
1. Standard Methods of Chemical Analysis. 6th ed.
New York, D. Van Nostrand Co., Inc. 1962. Vol. 1,
p 329-330. 87
2. Standard Method of Test for Glides of Nitrogen in
Oaseous Combustion Products (Phenoldisulfonic Acid
Procedure). In: 1968 Book of A8TM Standards, Fart 26.
Philadelphia, Pa. 1968. A8TM Designation D-1608-60,
p. 725-729.
Ill-Appendix A-31a
-------
Ill-Appendix A-31b
-------
METHOD 8DETERMINATION or Sniruuc ACID Miai
AND Suirua DIOXIDE EMISSIONS FROM STATIONABT
SOURCES
1. Principle and Applicability
1.1 Principle. A gas sample Is extracted Isoklnetlolly
from the stack. The sulfuric acid mist (including sulfur
trloxide) and the sulfur dloiide are separated, and both
fractions are measured separately by the barium-thorin
Utration method.
1.2 Applicability. This method is applicable for tlw
determination of sulfuric acid mist (including sulfur
trioiide, and in the absence of other paniculate matter)
and sulfur dioxide emissions from stationary sources.
Collaborative tests have shown that the minimum
detectable limits of the method are O.OS milligrams/cubic
meter (0.03X1Q-' pounds/cubic foot) for sulfur trioiide
and 1.2 mg/m1 (0 74 10-' Ib/lt1) for sulfur dioxide. No
upper Limits have been established. Uased on theoretical
calculations for 200 miUiliters of 3 percent hydrogen
peroxide solution, the upper concentration limit for
sulfur dioxide in a l.U m> (35.3 ft1) gas sample is about
12.500 mg/m> (7.7X10-' Ib/ft'). The upper limit can be
extended by increasing the quantity of peroxide solution
In the impingers.
Possible interfering agents of this method are fluorides,
free ammonia, and dimethyl aniline. If any of these
Interfering agents are present (this can be determined by
knowledge of the process), alternative methods, subject
to the approval of the Administrator, U S EPA an
required. 87
Filterable partlculate matter may be de-
termined along with SO, and SO, (subject to
the approval of the Administrator) by in-
serting a heated glass fiber filter between
the probe and isopropanol impmger (see
Section 2 1 of Method 6). If this option is
chosen, participate analysis is gravimetric
only: H.SO, acid mist is not determined sep-
arately. 87
1. Apparotut
2 1 Sampling. A schematic of the sampling train
used in this method Is shown In Figure 8-1; it is similar
to the Method 5 train except that the niter portion Is
different and the filter holder does not have to t>e heated.
Commercial models of this train are available For those
who desire to build their own, however, complete con-
struction details are described in Al'TD-O."*!. Change*
from the, Al'TU-(V>81 document and allowable modi-
fications to Figure 8-1 are discussed in the following
subsections.
The operating and maintenance procedures for the
sampling train are descilbed In A VT D-0576. Since correct
usage is important in obtaining valid results, all users
should read the, Al'TD-OjTrj document and adopt the
operating and maintenance procedures outlined In It,
unless otherwise specified hen-m. Further details and
.
on operation and maintenance arc given in
and should bo read and followed whenever
guuk'Hn
Method
they are applicable.
2.1 1 Prol,o Nozzle. Same as Method 5, Section 2.1.1.
2 1 2 Probe Uner. Uorculllcatn or i|uarti glass, with a
heating system to prevent visible condensation during
sampling. Do not use metal probe liners.
> , 3 1'itot Tube. Same as Method 5, Section 2.1.3.
2.1.4 Differential Pressure Gauge. Same as Method 8,
Section 2.1.4.
2.1.5 Filter Holder. Boroslllcale glass, with a glass
frit filter support and a gillcone rubber gasket Other
gasket materials, e.g., Teflon or Viton, may be used sub-
ject to the approval of the Administrator. The holder
design shall provide a positive seal against leakage from
the outside or around the filter. The filter holder shall
be placed between the first and second Impingeni. Note:
Do act heat the filter holder.
2.1.6 ImpingersFour, as shown In Figure »-l. Th«
flrst and third shall be of the Oreenburg-Smith design
with standard tips. The second and fourth shall be of
the Oreenburg-Smlth design, modified by replacing the
Insert with an approximately 13 millimeter (0.5 In.) ID
flail!' tube, having an unconstricUd tip located 13 mm
(O.S In.) from the bottom of the flask. Similar collection
systems, which have been approved by the Adminis-
trator, may be used.
2.1.7 Metering System. Same as Method 6, Section
2.1.8
2.1.8 Barometer. Same as Method 8. Section 2.1.9.
2.1.9 Oas Density Determination Equipment. Same
u Method 5, Section 2.1.10.
2.1.10 Temperature Oauge. Thermometer, or equiva-
lent, to measure the temperature of the gas leaving the
1m pin«er train to within 1° C (2° F).
2.2 Sample Recovery.
TEMPERATURE SENSOR
PROBE
PROBE
\^- PITOTTUBE
TEMPERATURE SENSOR
THERMOMETER
FILTER HOLDER
CHECK
VALVE
REVERSE TYPE
PITOT TUBE
VACUUM
LINE
VACUUM
GAUGE
MAIN VALVE
DRV TEST METER
Figure 8-1. Sulfuric acid mist sampling train.
Ill-Appendix A-32
-------
U.1 With Bottka. rosyitkyina or iltn, 100 ml.
(MTO).
1A» Graduated Cylinders. MO ml, 1 liter. )-2-napb-
tfcol-J. t-dlsulfonlc acid, dlsodlum salt, or equivalent.
Dissolve 0.301 In 100 ml of delonlted. distilled water.
1.1.4 Barium Perchlorate (0.0100 Normal). Dissolve
J$*<*bariumperchtorete trlhydrate(Ba(C10<)f3HiO)
In 200 ml delonlted. distilled water, and dilute to 1 Uter
with laopronanol; 1.22 g of barium chloride dlhydrate
(BaClt-2HiO) may be used Instead of the barium per-
ebtoratp. Btandardlte wHh solfurlc acid as In Section 5.2.
This solution must be protected against evaporation at
3.3.5 Sulfuric Acid Standard (0.0100 N). Purchase or
stand&rdlie to ±0.0002 N against 0.0100 N NaOH that
has previously been standardlted against primary
standard potassium Mid phthalate.
4. Procedure
4.1 Sampling.
4.1.1 Pretest Preparation. Follow the procedure out-
lined in Method 9, Section 4.1.1; filters should be In-
spected, but need not be desiccated, weighed, or identi-
fied. If the effluent gas can be considered dry, I.e., mois-
ture free, the silica gel need not be weighed.
4.1.2 Preliminary Determinations. Follow the pro-
cedure outlined in Method S, Section 4.1.2.
4.1.3 Preparation of Collection Train. Follow the pro-
cedure outlined in Method 5, Section 4.1.3 (except for
the second paragraph and other obviously inapplicable
parts) and use Figure 8-1 instead of Figure 5-1. Replace
the second paragraph with: Place 100 ml of 80 percent
Isopropanol in the flrst impinger, 100 ml of 3 percent
hydrogen peroxide in both the second and third 1m-
plngers; retain a portion of each reagent for use as a
blank solution. Place about 200 g of silica gel In the fourth
imptmer.
KANT.
LOCATION
OPERATOR
DATE
RUN NO
SAMPLE BOX NO..
METER BOX NO. _
METER A H«
C FACTOR
PTTOT TUBE COEFFICIENT, Co.
STATIC PRESSURE, mm HI (in. H|>.
AMBIENT TEMPERATURE
BAROMETRIC PRESSURE
ASSUMED MOISTURE. %
PROBE LENGTH,m (ft)
SCHEMATIC OF STACK CROSS SECTION
NOZZLE IDENTIFICATION NO
AVERAGE CALIBRATED NOZZLE DIAMETER, cm (in.).
PROBE HEATER SETTING
LEAK RATE, m3/min,(efm)
PROBE LINER MATERIAL
FILTER NO.
TRAVERSE POINT
NUMBEF.
TOTAL
SAMPLING
TIME
(9),mia.
AVERAGE
VACUUM
mm H|
(in. Ha)
STACK
TEMPERATURE
°C &)
VELOCITY
HEAD
(APS),
mmHjO
(i«,H20)
PRESSURE
DIFFERENTIAL
ACROSS
ORIFICE
METER.
mmH20
(in. H20)
GAS SAMPLE
VOLUME.
m3 (ft3)
GAS SAMPL E TEMPER ATU RE
AT DRY GAS METER
INLET.
°C ("Fl
Avg
OUTLET,
«C<«F)
Avg
Avg
TEMPERATURE
OF GAS
LEAVING
CONDENSER OR
LAST IMPINGER,
C <«F)
Figure 8-2. Field data.
Ill-Appendix A-33
-------
Nora.If moisture content is to be determined by
Imptnger analysis, weigh each of the Brat three impingen
(plus absorbing solution) to the nearest 0.5 g and record
these weights. The weight of the silica gel (or silica gel
plus container) must also be determined to the nearest
0.5 g and recorded.
4.1.4 Pretest Leak-Check Procedure. Follow the
basic procedure outlined in Method 5, Section 4.1.4.1,
noting that the probe heater shall be adjusted to the
minimum temperature required to prevent condensa-
tion, and also that verbage such as, plugging the
inlet to the filter holder ," shall be replaced by,
" * plugging the inlet to the flat Impinger V1
The pretest leak-check Is optional. °'
4.1.5 Train Operation. Follow the basic procedures
outlined in Method 5, Section 4.1.5, In conjunction with
the following special instructions. Data shall be recorded
on a sheet similar to the one In Figure 8-2. The sampling
rate shall not exceed 0.030 m'/mln (1.0 cfm) during tb*
run. Periodically during the test, observe the connecting
line between the probe and first implnger for signs of
condensation. If it does occur, adjust the probe heater
setting upward to the minimum temperature required
to prevent condensation. If component changes become
necessary during a run, a leak-check shall be done im-
mediately before each change, according to the procedure
outlined in Section 4.1.4.2 of Method 5 (with appropriate
modifications, as mentioned In Section 4.1.4 of this
method); record all leak rates. If the leakage rated)
exceed the specified rate, the tester shall either void the
run or shall plan to correct the sample volume as out-
lined in Section (.3 of Method a. Immediately after com-
ponent changes, leak-checks are optional. If these
leak-checks are done, the procedure outlined In Section
4.1.4.1 of Method 5 (with appropriate modifications)
shall be used.
After turning off the pump and recording the final
readings at the conclusion of each run, remove the probe
from the stack. Conduct a post-test (mandatory) leak-
check as In Section 4.1.4.3 of Method 5 (with appropriate
modification) and record the leak rate. If the post-test
leakage rate exceeds the specified acceptable rate, the
tester shall either correct the sample volume, as outlined
in Section 6.3 of Method S, or shall void the run.
Drain the ice bath and, with the probe disconnected,
purge the remaining part of the train, by drawing clean
ambient air through the system for 15 minutes at the
average flow rate used for sampling.
NOTE.Clean ambient air can be provided by passing
air through a charcoal filter. At the option of the tester,
ambient air (without cleaning) may be used.
4.1.6 Calculation of Percent Isokinetic. Follow the
procedure outlined in Method S, Section 4.1 .A.
4.2 Sample Recovery.
4.2.1 Container No. 1. If a moisture content analysis
Is to be done, weigh the first impinger plus contents to
the nearest 0.5 g and record this weight.
Transfer the contents of the first impinger to a 250-ml
graduated cylinder. Rinse the probe, first impinger, all
connecting glassware before the filter, and the front half
of the filter holder with 80 percent isopropanol. Add the
rinse solution to the cylinder. Dilute to 250 ml with 80
percent isopropanol. Add the filter to the solution, mix,
and transfer to the storage container. Protect the solution
against evaporation. Mark the level of 1'quid on the
container and identify the sample container. °7
4.2.2 Container No. 2. If a moisture content analysis
Is to be done, weigh the second and third impingen
(plus contents) to the nearest 0.5 g and record these
weights. Also, weigh the spent silica gel (or silica gel
plus impinger) to the nearest 0.5 g.
Transfer the solutions from the second and third
implngers to a 1000-ml graduated cylinder. Rinse all
connecting glassware (including back half of filter bolder)
between the filter and silicagellmplnger with delimited,
distilled water, and add this rinse water to the cylinder.
Dilute to a volume of 1000 ml with deloniied, distilled
water. Transfer the solution to a storage container. Mark
the level of liquid on the container. Seal and identify the
sample container.
4.3 Analysis.
Note the level of liquid in containers 1 and 2, and con-
firm whether or not any sample was lost during ship-
ment; note this on the analytical data sheet. It a notice-
able amount of leakage has occurred, either void the
sample or use methods, subject to the approval of the
Administrator, to correct the final results. '
4.3.1 Container No. 1. Shake the container holding
the Isopropanol solution and the filter. If the niter
breaks up, allow the fragments to settle for a few minutes
before removing a sample. Pipette a 100-ml aliquot of
this solution into a 250-ml Erlenmeyer flask, add 2 to 4
drops of thortn indicator, and titrate to a pink endpolnt
using 0.0100 N barium perchlorato. Repeat the titration
with a second aliquot of sample and average the titration
values. Replicate tltrations molt agree within I percent
or 0.2 ml, whichever Is greater.
4~3 J Container No. 2. Thoroughly mix the solution
In the container holding the contents of the second and
third Implngers. Pipette a 10-ml aliquot of sample into a
Mo-mi Erlenmeyer flask. Add 40m) of Isopropanol. 2 to
4 drops of thortn Indicator. and titrate to a pink endpolnt
using 0.0100 N barium perchlorate. Repeat the titration
with a second aliquot of sample and average the titration
values. Replicate tltrations mustagree within 1 percent
or 0.3 ml, whichever Is greater. 87
4.3.3 Blanks. Prepare blanks by adding 2 to 4 drop)
of thorin indicator to 100 ml of 80 percent isopropanol.
Titrate the blanks In the same manner as the samples.
5. CWftfofton
5.1 Calibrate equipment using the procedures speci-
fied in the following sections of Method 5: Section 5.3
(metering system); Section 5.5 (temperature gauges);
Section 5.7 (barometer). Note that the recommended
leak-check of the metering system, described in Section
5.6 of Method 5, also applies to this method.
5.2 Standardise the barium perchlorate solution with
25 ml of standard sulfuric acid, to which 100 ml of 100
percent Isopropanol has been added.
8. Caleuiathni
Note.Carry out calculations retaining at least one
extra decimal figure beyond that of the acquu-ed data-
Round off figures after final calculation.
8.1 Nomenclature.
X.Cross-sectional area of noule, m> (ft*).
£»Water vapor in the gas stream, proportion
by volume.
C,,.\,y -SulJuricacid (Including SOi) concentration,
g/dscm (lb/dscf). i"
C,,v? -Sulfur dioxide concentration, g/dscm (lb/
dscf).o7
7Percent of Isokinetic sampling.
N- Normality of barium perchlorate titrant, g
D equivalents/liter.
"burBarometric pressure »t the sampling site,
mm Hg (in. Hg). B/
JP.Absolute stack gas pressure, mm Hg (in.
P»wStandard absolute pressure, 780 mm Hg
(29.92 in. Hg)/B7
T.-Average absolute dry gas meter temperature
(see Figure 8-2), ° K < R).
T.Average absolute stack gas temperature (see
T, Figure 8-2), ° K C H).
1 >td Standard absolute temperature, 293° K
(528° R). 87
V.-Volume of sample aliquot titrated, 100 ml
tor HiSOi and 10 ml for SO:.
Vi,-Total volume of liquid collected In impingers
and silica gel, ml.
VaVolume of gas sample as measured by dry
,r gas meter, dcm (dcf).
v mi.tni-volume of gas sample measured by the dry
gas meter corrected to standard conditions,
dsem (dscf). 87
».-Average stack gas velocity, calculated by
Method 2. Equation 2-9. using data obtained
,, from Method 8, m/sec (ft/sec).
v
-------
TABU »-l-SMOKE METER DESIGN AND
PERFOBMANCE SPECIFICATIONS
Parameter:
», tight
b. Spectral response
ol photocell.
o. Angle of view
d. Angle of projec-
tion.
e. Calibration error.
t. Zero and span
drift.
g. Response time _
Specification
Incandescent lamp
operated at nominal
rated voltage.
Photopic (daylight
spectral response of
the human eye
reference 4.3).
15* maximum total
angle.
15* maximum total
angle.
±3 % opacity, maxi-
mum.
±1% opacity, 30
minutes.
S6 seconds.
3.3.2 smoke meter evaluation. The smoke
meter design and performance are to be
evaluated &s follows:
3.3.2.1 Light source. Verify from manu-
facturer's data and from voltage measure-
ments made at the lamp, as installed, that
the lamp is operated wit&ln ±S percent of
the nominal rated voltage.
8.3.2.2 Spectral response of photocell.
Verify from manufacturer's data that the
photocell has a photoplc response; l.e, the
spectral sensitivity of the cell shall closely
approximate the. standard spectral-luminos-
ity curve far photoplc vision which Is refer-
enced in (b) of Table 9-1.
3.3.2.3 Angle of view. Check construction
geoinocry to ensure that the total angle 01
view of the smoke plume, RS seen by the
photocell, does not exceed 15*. The total
angle of view may be calculated from: 0=2
tan-1 d/2L, where 0=total angle of view;
d=the sum of the photocell diameter+the
diameter of the limiting aperture; and
L = the distance from the photocell to the
limiting aperture-. The limiting aperture is
the point la the path between the photocell
and the smoke plume where the angle of
view Is most restricted. In smoke generator
smoke meters this is normally *n orifice
plate.
3.3.2.4 Angle of projection. Check con-
struction geometry to ensure that the total
angle of projection of the lamp on the
smoke plume does not exceed IB*. The total
angle of projection may be calculated from:
6=2 tan-1 d/2Ii, where «= total angle of pro-
jection; d= the sum of the length of the
lamp filament 4- the diameter of the limiting
aperture; and L= the distance from the lamp
to the limiting aperture.
3.3.2.5 Calibration error. Using neutral-
density filters of known opacity, check the
error between the actual response and the
theoretical linear response of the smoke
meter. This check Is accomplished by first
calibrating the smoke meter according to
3.3.1 and then inserting a series of three
neutral-density filters of nominal opacity of
20, 60, and 75 percent In the smoke meter
pathlength. Filters callbarted within ±2 per-
cent shall be used. Care should be taken
when Inserting the .filters to prevent stray
light from affecting the meter. Make a total
of five nonconsecutive readings for each
filter. The maximum error on any one read-
Ing shall be 3 percent opacity.
3.3.2.6 Zero and span drift. Determine
the zero and span drift by calibrating and
operating the smoke generator In a normal
manner over a 1-hour period. The drift is
measured by checking the zero and span at
the end of this period.
3.3.2.7 Response time. Determine the re-
sponse time by producng the series of five
simulated 0 percent and 100 percent opacity
values and observing the time required to
reach stable response. Opacity values of 0
percent and 100 percent may be simulated
by alternately switching the power to the
light source off and on while the smoke
generator is not operating.
4. References.
4.1 Air Pollution Control District Rules
ami Regulations, Los Angelea County Air
Pollution Control District, Regulation IV,
Prohibitions, Rule 50.
4.2 Waisburd, Melvin L, Field Operations
and Enforcement Manual for Air, TUB. Envi-
ronmental Protection Agency, Research Tri-
angle Park, N.C., AFTD-1100. August 1972.
pp. 4.1-4.38.
4.3 Condon, E. TT., and Odishaw, H., Hand-
book of Physics, McGraw-Hill Co., N.Y., N.Y,
1958, Table 3.1, p. 6-52.
Ill-Appendix A-36
-------
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Ill-Appendix 7V-38
-------
METHOD 10DETERMINATION OF CARBON MON-
OXIDE EMISSIONS FROM STATIONARY SOURCES 5
1. Principle and Applicability.
1.1 Principle. An Integrated or continuous
gas sample is extracted from a sampling point
and analyzed for carbon monoxide (CO) con-
tent using a Luft-type nondispersive infra-
red analyzer (NDIR) or equivalent.
1.2 Applicability. This method Is appli-
cable for the determination of carbon mon-
oxide emissions from stationary sources only
when specified by the test procedures for
determining compliance with new source
performance standards. The test procedure
will indicate whether a continuous or an
Integrated cample Is to be used.
2. Range and sensitivity.
2.1 Range. 0 to 1,000 ppm.
22 Sensitivity. Minimum detectable con-
centration is 20 ppm for a 0 to 1,000 ppm
span.
3. Interferences. Any substance having a
strong absorption of infrared energy will
interfere to some extent. For example, dis-
crimination ratios for water (H..O) and car-
bon dioxide (CO.) are 3.5 percent HEO per
7 ppm CO and 10 percent CO2 per 10 ppm
CO, respectively, for devices measuring In the
1,500 to 3,000 ppm range. For devices meas-
uring In the 0 to 100 ppm range, Interference
ratios can be as high aa 3.5 percent H.O per
25 ppm CO and 10 percent CO, per 50 ppm
CO. The use of silica gel and ascarite traps
will alleviate the major interference prob-
lems. The measured gas volume must be
corrected If these traps are used.
4. Precision and accuracy.
4.1 Precision. The precision of most NDIR
analyzers is approximately ±2 percent of
span.
4.2 Accuracy. The accuracy of most NDIR
analyzers is approximately ±5 percent of
span alter calibration.
5. Apparatus.
b l Continuous sample (Figure 10-1).
5.1.1 Probe. Stainless steel or sheathed
Pyrexl glass, equipped with a filter to remove
particulate matter.
5.1.2 Air-cooled condenser or equivalent.
To remove any excess moisture.
5.2 Integrated sample (Figure 10-2).
5.2.1 Probe. Stainless steel or sheathed
Pyrex glass, equipped with a filter to remove
particulate matter.
5.2.2 Air-cooled condenser or equivalent.
To remove any excess moisture.
5.2.3 Valve. Needle valve, or equivalent, to
to adjust flow rate.
5.2.4 Pump. Leak-free diaphragm type, or
equivalent, to transport gas.
5.3.5 Rate meter. Kotameter, or equivalent,
to measure a flow range from 0 to 1.0 liter
per min. (0.035 cfm).
5.2.6 Flexible bay. Tedlar, or equivalent,
with a capacity of 60 to 90 liters (2 to 3 ft»).
leak-test the bag in the laboratory before
using by evacuating bag with- a pump fol-
lowed by a dry gas meter. When evacuation
la complete, there should be no flow through
the meter.
6.2.7 Pitot tube. Type S, or equivalent, at-
tached to the probe so that the sampling
rate can be regulated proportional to the
stack gas velocity when velocity is varying
with the time or a sample traverse is con-
ducted. .
5.3 Analysis (Figure 10-3).
TABU 10-1.Field data
Location.
Test
Date
Operator .
Comments:
Clock time
Sotameter setting, liters per minute
(cubic feet per minute)
AW-COOUD CONDENSE*
now
M.IU [GLASS VCOU
53.1 Carbon monoxide analyzer. Nondisper-
sive infrared spectrometer, or equivalent.
This instrument should be demonstrated,
preferably by the manufacturer, to meet or
exceed ' manufacturer's specifications and
those described in this method.
5.3 2 Drying tube. To contain spproxi.-
mately 200 g of silica gel.
5.33 Calibration gas. Refer to paragraph
6.1.
5.3.4 Filter. As recommended by NDIB
manufacturer.
5.3.5 CO2 removal tube. To contain approxi-
mately 500 g of ascarite.
5.3.6 Ice water bath. For ascarite and silica
gel tubes.
5.3.7 Valve. Needle valve, or equivalent, to
adjust flow rate
6.3.8 Rate meter. Botameter or equivalent
to measure gas flow rate of 0 to 1.0 liter per
min. (0.035 cfm) through NDIR.
5.3.9 Recorder (optional). To provide per-
manent record of NDIB readings.
6. Reagents.
1 Mention of trade names or specific prod-
ucts does not constitute endorsement by the
Environmental Protection Agency.
Fl?ur«104. Analytical HblpMnt.
6.1 Calibration gases. Known concentration
of CO in nitrogen (N5) for instrument span,
prepurified grade of N3 for zero, and two addi-
tional concentrations corresponding approxi-
mately to 60 percent and 30 percent span. The
.span concentration shall not exceed 1.5 times
the applicable source performance standard.
The calibration gases shall be certified by
the manufacturer to be within ±2 percent
of the specified concentration.
6.2 Silica gel. Indicating type, 6 to 16 mesh,
dried at 175° C (347» F) for 2 hours.
6.3 Ascarite. CorumeiclpHy available.
7. Procedure.
7.1 Sampling,
FfextM. imnuci iu*i*f»* van.
7.1.1 Continuous sampling. Set up the
equipment as shown in Figure 10-1 making
sure all connections are leak free. Place tho
probe in the stack at a sampling point and
purge the sampling line. Connect the ana-
lyzer and begin drawing sample into ths
analyzer. Allow 5 minutes for the system
to stabilize, then record the analyzer read'
ing as required by the test procedure. (See
fl 12 and 8). COi content of the gas may be
determined by using the Method 3 inte-
grated sample procedure (36 FB 24886), or
by weighing the ascarite CO, removal tube
and computing CO, concentration from the
gas volume sampled and th
-------
9. CalculationConcentration of carbon monoxide. Calculate the concentration of carbon
monoxide In the stack using equation 10-1.
where:
equation 10-1
) in stack, ppm by volume (dry basis),
JKD[B = concentration of CO measured by NDIR analyzer, ppm by volume (dry
basis). &
Fco,= volume fraction of CO3 in sample. I.e., percent COj from Orsat analysto
divided by 100.
10. Bibliography.
10.1 McElroy, Prank, The Intertech NDIR-CO
Analyzer, Presented at llth Methods
Conference on Ah- Pollution, University
of California, Berkeley, Calif., April 1,
1970.
10.2 Jacobs, M. B., et al., Continuous Deter-
mination of Carbon Monoxide and Hy-
drocarbons In Air by a Modified Infra-
red Analyzer, -J. Air Pollution Control
Association, 9(2) :110-114, August 1959.
10.3 MSA LIRA Infrared Gas and Liquid
Analyzer Instruction Book, Mine Safety
Appliances Co, Technical Products Di-
vision, Pittsburgh, Pa.
10.4 Models 215A, 315A, and 416A Infrared
Analyzers, Beckman Instruments, Inc.,
Beckman Instructions 1635-B, Puller-
ton, Calif., October 1967.
10.5 Continuous CO Monitoring System,
Model A5611, Intertech Corp., Princeton,
N.J.
10.6 UNOR Infrared Oas Analyzers, Bendlx
Corp., Ronceverte, West Virginia.
ADDENDA
A. Performance Specifications for NDIR Carbon Monoxide Analyzers.
Range (minimum) 0-1000ppm.
Output (minimum) 0-10mV.
Minimum detectable sensitivity 20 ppm.
Rise time, 90 percent (maximum) . 30 seconds.
Fall time, 90 percent (maximum) 30 seconds.
Zero drift (maximum) , 10% in 8 hours.
Span drift (maximum) 10% in 8 hours.
Precision (minimum) - rfc 2% of full scale.
Noise (maximum) ± 1 % of full scale.
Linearity (maximum deviation) 2% ol full scale.
Interference rejection ratio CO21000 to 1, H«O500 to 1.
B. Definitions o/ Per/orm
-------
METHOD 11DETERMINATION OF HYDROGEN
SULFIDE CONTENT OP FUEL GAS STREAMS III
PETROLEUM REFINERIES 79
1. Principle and applicability. 1.1 Princi-
ple. Hydrogen sulfide (H,S) is collected from
a source in a series of midget impingers and
absorbed in pH 3.0 cadmium sulfate (CdSO.)
solution to form cadmium sulfide (CdS).
The latter compound is then measured iodo-
metrically. An impinger containing hydro-
gen peroxide is included to remove SO, as
an interfering species. This method is a revi-
sion of the H>S method originally published
in the FEDERAL REGISTER, Volume 39, No. 47,
dated Friday, March 8, 1974.
1.2 Applicability. This method is applica-
ble for the determination of the hydrogen
sulfide content of fuel gas streams at petro-
leum refineries.
2. Range and sensitivity. The lower limit
of detection is approximately 8 mg/m1 (6
ppm). The maximum of the range is 740
mg/m! (520 ppm).
3. Interferences. Any compound that re-
duces iodine or oxidizes iodide ion will inter-
fere in this procedure, provide it is collected
in the cadmium sulfate impingers. Sulfur
dioxide in concentrations of up to 2,600 mg/
m' is eliminated by the hydrogen peroxide
solution. Thiols precipitate with hydrogen
sulfide. In the absence of H2S, only co-traces
of thiols are collected. When methane- and
ethane-thiols at a total level of 300 mg/ms
are present in addition to H,S, the results
vary from 2 percent low at an H,S concen-
tration of 400 mg/m' to 14 percent high at
an H,S concentration of 100 mg/m". Carbon
oxysulfide at a concentration of 20 percent
does not interfere. Certain carbonyl-con-
taining compounds react with iodine and
produce recurring end points. However, ac-
etaldehyde and acetone at concentrations of
1 and 3 percent, respectively, do not inter-
fere.
Entrained hydrogen peroxide produces a
negative interference equivalent to 100 per-
cent of that of an equimolar quantity of hy-
drogen sulfide. Avoid the ejection of hydro-
gen peroxide into the cadmium sulfate im-
pingers.
4. Precision and accuracy. Collaborative
testing has shown the within-laboratory co-
efficient of variation to be 2.2 percent and
the overall coefficient of variation to be 5
percent. The method bias was shown to be
4.8 percent when only H,S was present. In
the presence of the interferences cited in
section 3, the bias was positive at low H>S
concentrations and negative at higher con-
centrations. At 230 mg HjS/m1, the level of
the compliance standard, the bias was +2.7
percent. Thiols had no effect on the preci-
sion.
5. Apparatus.
5.1 Sampling apparatus.
5.1.1 Sampling line. Six to 7 mm (Vi in.)
Teflon1 tubing to connect the sampling
train to the sampling valve.
5.1.2 Impingers. Five midget impingers,
each with 30 ml capacity. The internal di-
ameter of the impinger tip must be 1 mm
±0.05 mm. The impinger tip must be posi-
tioned 4 to 6 mm from the bottom of the im-
pinger.
5.1.3 Glass or Teflon connecting tubing
for the impingers.
5.1.4 Ice bath container. To maintain ab-
sorbing solution at a low temperature.
5.1.5 Drying tube. Tube packed with 6- to
16-mesh indicating-type silica gel, or equiv-
alent, to dry the gas sample and protect the
meter and pump. If the silica gel has been
used previously, dry at 175° C'(350° F) for 2
hours. New silica gel may be used as re-
ceived. Alternatively, other types of desic-
cants (equivalent or better) may be used,
subject to approval of the Administrator.
NOTE.Do not use more than 30 g of silica
gel. Silica gel absorbs gases such as propane
from the fuel gas stream, and use of exces-
sive amounts of silica gel could result in
errors in the determination of sample
volume.
8.1.6 Sampling valve. Needle valve or
equivalent to adjust gas flow rate. Stainless
steel or other corrosion-resistant material.
5.1.7 Volume meter. Dry gas meter, suffi-
ciently accurate to measure the sample
volume within 2 percent, calibrated at the
selected flow rate (-1.0 liter/min) and con-
ditions actually encountered during sam-
pling. The meter shall be equipped with a
temperature gauge (dial thermometer or
equivalent) capable of measuring tempera-
ture to within 3' C (5.1' F). The gas meter
should have a petcock, or equivalent, on the
outlet connector which can be closed during
the leak check. Gas volume for one revolu-
tion of the meter must not be more than 10
liters.
5.1.8 Flow meter. Rotameter or equiv-
alent, to measure flow rates In the range
from 0.5 to 2 liters/min (1 to 4 cfh).
5.1.9 Graduated cylinder, 25 ml size.
5.1.10 Barometer. Mercury, aneroid, or
other barometer capable of measuring at-
mospheric pressure to within 2.5 mm Hg
(0.1 in. Hg). In many cases, the barometric
reading may be obtained from a nearby Na-
tional Weather Service station, in which
case, the station value (which is the abso-
lute barometric pressure) shall be requested
and an adjustment for elevation differences
between the weather station and the sam-
pling point shall be applied at a rate of
minus 2.5 mm Hg (0.1 in. Hg) per 30 m (100
ft) elevation increase or vice-versa for eleva-
tion decrease.
5.1.11 U-tube manometer. 0-30 cm water
column. For leak ctieck procedure.
5.1.12 Rubber squeeze bulb. To pressur-
ize train for leak check.
5.1.13 Tee, pinchclamp, and connecting
tubing. For leak check.
5.1.14 Pump. Diaphragm pump, or equiv-
alent. Insert a small surge tank between the
pump and rate meter to eliminate the pulsa-
tion effect of the diaphragm pump on the
rotameter. The pump is used for the air
purge at the end of the sample run; the
pump is not ordinarily used during sam-
pling, because fuel gas streams are usually
sufficiently pressurized to force sample gas
through the train at the required flow rate.
The pump need not be leak-free unless it is
used for sampling.
5.1.15 Needle valve or critical orifice. To
set air purge flow to 1 liter/min.
5.1.16 Tube packed with active carbon.
To filter air during purge.
6.1.17 Volumetric flask. One 1,000 ml.
5.1.18 Volumetric pipette. One 15 ml.
5.1.19 Pressure-reduction regulator De-
pending on the sampling stream pressure, a
pressure-reduction regulator may be needed
to reduce the pressure of the gas stream en-
tering the Teflon sample line to a safe level.
5.1.20 Cold trap If condensed water or
amine is present in the sample stream, a
corrosion-resistant cold trap shall be used
Immediately after the sample tap. The trap
shall not be operated below 0' C (32° F) to
avoid condensation of Ci or C< hydrocar-
bons.
5.2 Sample recovery.
5.2.1 Sample container. Iodine flask,
glass-stoppered: 500 ml size.
5.2.2 Pipette. 50 ml volumetric type.
5.2.3 Graduated cylinders. One each 25
and 250 ml.
Mention of trade names of specific prod-
ucts does not constitute endorsement by the
Environmental Protection Agency.
5.2.4 Flasks. 125 ml. Erlenmeyer.
5.2.5 Wash bottle.
5.2.6 Volumetric flasks. Three 1,000 ml.
5.3 Analysis.
5.3.1 Flask. 500 ml glass-stoppered iodine
flask.
5.3.2 Burette. 50 ml.
5.3.3 Flask. 125 ml, Erlenmeyer.
5.3.4 Pipettes, volumetric. One 25 ml; two
each 50 and 100 ml.
6.3.5 Volumetric flasks. One 1,000 ml;
two 500 ml.
6.3.6 Graduated cylinders. One each 10
and 100 ml.
6. Reagents. Unless otherwise indicated, it
is intended that all reagents conform to the
specifications established by the Committee
on Analytical Reagents of the American
Chemical Society, where such specifications
are available. Otherwise, use best available
grade.
6.1 Sampling.
6.1.1 Cadmium sulfate absorbing solu-
tion. Dissolve 41 g of 3CdSO.-8H,O and 15
ml of 0.1 M sulfuric acid in a 1-liter volumet-
ric flask that contains approximately 3/< liter
of deionized distilled water. Dilute to
volume with deionized water. Mix thorough-
ly. pH should be 3±0.1. Add 10 drops of
Dow-Corning Antifoam B. Shake well before
use. If Antifoam B is not used, the alternate
acidified iodine extraction procedure (sec-
tion 7.2.2) must be used.
6.1.2 Hydrogen peroxide, 3 percent.
Dilute 30 percent hydrogen peroxide to 3
percent as needed. Prepare fresh daily.
6.1.3 Water. Deionized, distilled to con-
form to ASTM specifications D1193-72.
Type 3. At thr- option of the analyst, the
KMnCX test lor ;>xidizable organic matter
may be omitted when high concentrations
of organic matte- are not expected to be
present.
6.2 Sample recoi ery.
6.2.1 Hydrochloric acid solution (HC1),
3M. Add 240 ml of concentrated HC1 (specif-
ic gravity 1.19) to 500 ml of deionized, dis-
tilled water in a 1-liter volumetric flask.
Dilute to 1 liter with deionized water. Mix
thoroughly.
6.2.2 Iodine solution 0.1 N. Dissolve 24 g
of potassium iodide (KI) in 30 ml of deion-
ized, distilled water. Add 12.7 g of resub-
limed iodine (I,) to the potassium iodide so-
lution. Shake the mixture until the iodine is
completely dissolved. If possible, let the so-
lution stand overnight in the dark. Slowly
dilute the solution to 1 liter with deionized,
distilled water, with swirling. Filter the so-
lution if it is cloudy. Store' solution in a
brown-glass reagent bottle.
6.2.3 Standard iodine solution, 0.01 N. Pi-
pette 100.0 ml of the 0.1 N iodine solution
Into a 1-liter volumetric flask and dilute to
volume with deionized, distilled water. Stan-
dardize daily as in section 8.1.1. This solu-
tion must be protected from light. Reagent
bottles and flasks must be kept tightly stop-
pered.
6.3 Analysis.
6.3.1 Sodium thiosulfate solution, stan-
dard 0.1 N. Dissolve 24.8 g of sodium thio-
sulfate pentahydrate (Na£,O,-5H,O) or 15.8
g of anhydrous sodium thiosulfate (NaAOi)
In 1 liter of deionized, distilled water and
add 0.01 g of anhydrous sodium carbonate
(Na,CO.) and 0.4 ml of chloroform (CHC1.)
to stabilize. Mix thoroughly by shaking or
by aerating with nitrogen for approximately
15 minutes and store in a glass-stoppered,
reagent bottle. Standardize as in section
8.1.2.
6.3.2 Sodium thiosulfate solution, stan-
dard 0.01 N. Pipette 50 0 ml of the standard
0.1 N thiosulfate solution into a volumetric
flask and dilute to 500 ml with distilled
water.
III-Appendix A-41
-------
NOTE.A 0.01 N phenylarsine oxide solu-
tion may be prepared instead of 0.01 N thio-
sulfate (see section 6.3.3).
6.3.3 Phenylarsine oxide solution, stan-
dard 0.01 N. Dissolve 1.80 g of phenylarsine
oxide (C.HsAsD) in 150 ml of 0.3 N sodium
hydroxide. After settling, decant 140 ml of
this solution into 800 ml of distilled water.
Bring the solution to pH 6-7 with 6N hydro-
chloric acid and dilute to 1 liter. Standard-
ize as in section 8.1.3.
6.3.4 Starch indicator solution. Suspend
10 g of soluble starch in 100 ml of deionized,
distilled water and add 15 g of potassium
hydroxide (KOH) pellets. Stir until dis-
solved, dilute with 900 ml of deionized dis-
tilled water and let stand for 1 hour. Neu-
tralize the alkali with concentrated hydro-
chloric acid, using an indicator paper similar
to Alkacid test ribbon, then add 2 ml of gla-
cial acetic acid as a preservative.
NOTE.Test starch indicator solution for
decomposition by titrating, with 0.01 N
iodine solution, 4 ml of starch solution in
200 ml of distilled water that contains 1 g
potassium iodide. If more than 4 drops of
the 0.01 N iodine solution are required to
obtain the blue color, a fresh solution must
be prepared.
7. Procedure.
7.1 Sampling.
7.1.1 Assemble the sampling train as
shown in figure 11-1, connecting the five
midget impingers in series. Place 15 ml of 3
percent hydrogen peroxide solution in the
first impinger. Leave the second impinger
empty. Place 15 ml of the cadmium sulfate
absorbing solution in the third, fourth, and
fifth impingers. Place the impinger assem-
bly in an ice bath container and place
crushed Ice around the impingers. Add more
ice during the run, if needed.
7.1.2 Connect the rubber bulb and mano-
meter to first impinger, as shown in figure
11-1. Close the petcock on the dry gas meter
outlet. Pressurize the train to 25-cm water
pressure with the bulb and close off tubing
connected to rubber bulb. The train must
hold a 25-cm water pressure with not more
than a 1-cm drop in pressure in a 1-minute
Interval. Stopcock grease is acceptable for
sealing ground glass joints.
NOTE.This leak check procedure is op-
tional at the beginning of the sample run,
but is mandatory at the conclusion. Note
also that if the pump is used for sampling, it
Is recommended (but not required) that the
pump be leak-checked separately, using a
method consistent with the leak-check pro-
cedure for diaphragm pumps outlined in
section 4.1.2 of reference method 6. 40 CFR
Part 60, Appendix A.
7.1.3 Purge the connecting line between
the sampling valve and first impinger, by
disconnecting the line from the first im-
pinger, opening the sampling valve, and al-
lowing process gas to flow through the line
for a minute or two. Then, close the sam-
pling valve and reconnect the line to the im-
pinger train. Open the petcock on the dry
gas meter outlet. Record the initial dry gas
meter reading.
7.1.4 Open the sampling valve and then
adjust the valve to obtain a rate of approxi-
mately 1 liter/min. Maintain a constant
(±10 percent) now rate during the test.
Record the meter temperature.
7.1.5 Sample for at least 10 mln. At the
end of the sampling time, close the sam-
pling valve and record the final volume and
temperature readings. Conduct a leak check
as described in Section 7.1.2 above.
7.1.6 Disconnect the impinger train from
the sampling line. Connect the charcoal
tube and the pump, as shown in figure 11-1.
Purge the train (at a rate of 1 liter/min)
with clean ambient air fpr 15 minutes to
ensure that all H.S is removed from the hy-
drogen peroxide. For sample recovery, cap
the open ends and remove the impinger
train to a clean area that is away from
sources of heat. The area should be well
lighted, but not exposed to direct sunlight.
7.2 Sample recovery.
7.2.1 Discard the contents of the hydro-
gen peroxide impinger. Carefully rinse the
contents of the third, fourth, and fifth im-
pingers into a 500 ml iodine flask.
PINCH "UBBER
CLAMP BULB
SAMPl l«r (V* '" TEFLON SAMPLING,"' MIDGET
VALVE ' IINE ,'' IMPINGERS
SILICA GEL TUBE
/ /
DRYGASMtTER RATE METER
VALVE
PUMP
(FOR AIR PURGE)
Figure 11-1. H2S sampling train.
III-Appendix A-42
-------
NOTE.The implngers normally have only
a thin film of cadmium sulfide remaining
'after a water rinse. If Antifoam B was not
used or if significant quantities of yellow
cadmium sulfide remain in the impingers,
the alternate recovery procedure described
below must be used.
7.2.2 Pipette exactly 50 ml of 0.01 N
iodine solution into a 125 ml Erlenmeyer
flask. Add 10 ml of 3 M HC1 to the solution.
Quantitatively rinse the acidified - iodine
Into the iodine flask. Stopper the flask im-
mediately and shake briefly.
7.2.2 (Alternate). Extract the remaining
cadmium sulfide from the third, fourth, and
fifth impingers using the acidified iodine so-
lution. Immediately after pouring the acidi-
fied iodine into an impinger, stopper it and
shake for a few moments, then transfer the
liquid to the iodine flask. Do not transfer
any rinse portion from one impinger to an-
other; transfer it directly to the iodine flask.
Once the acidified iodine solution has been
poured into any glassware containing cadmi-
um sulfide, the container must be tightly
stoppered at all times except when adding
more solution, and this must be done as
quickly and carefully as possible. After
adding any acidified iodine solution to the
iodine flask, allow a few minutes for absorp-
tion of the H.S before adding any further
rinses. Repeat the iodine extraction until all
cadmium sulfide is removed from the im-
pingers. Extract that part of the connecting
glassware that contains visible cadmium sul-
fide.
Quantitatively rinse all of the iodine from
the impingers, connectors, and the beaker
Into the iodine flask using deionized, dis-
tilled water. Stopper the flask and shake
briefly.
7.2.3 Allow the iodine flask to stand
about 30 minutes in the dark for absorption
of the HiS into the iodine, then complete
the titration analysis as in section 7.3.
NOTE.Caution! Iodine evaporates from
acidified iodine solutions. Samples to which
acidified iodine have been added may not be
stored, but must be analyzed in the time
schedule stated in section 7.2.3.
7.2.4 Prepare a blank by adding 45 ml of
cadmium sulfate absorbing solution to an
iodine flask. Pipette exactly 50 ml of 0.01 N
iodine solution into a 125-ml Erlenmeyer
flask. Add 10 ml of 3 M HC1. Follow the
same Impinger extracting and quantitative
rinsing procedure carried out in sample
analysis. Stopper the flask, shake briefly,
let stand 30 minutes in the dark, and titrate
with the samples.
NOTE.The blank must be handled by ex-
actly the same procedure as that used for
the samples.
7.3 Analysis.
NOTE.Titration analyses should be con-
ducted at the sample-cleanup area in order
to prevent loss of iodine from the sample.
Titration should never be made in direct
sunlight.
7.3.1 Using 0.01 N sodium thiosulfate so-
lution (or 0.01 N phenylarsine oxide, if ap-
plicable), rapidly titrate each sample in an
iodine flask using gentle mixing, until solu-
tion is light yellow. Add 4 ml of starch indi-
cator solution and continue titrating slowly
until the blue color just disappears. Record
Vn, the volume of sodium thiosulfate solu-
tion used, or VAT, the volume of phenylar-
sine oxide solution used (ml).
7.3.2 "Titrate the blanks in the same
manner as the samples. Run blanks each
day until replicate values agree within 0.05
ml. Average the replicate titration values
which agree within 0.05 ml.
8. Calibration and standards.
8.1 Standardizations.
8.1.1 Standardize the 0.01 N iodine solu-
tion daily as follows: Pipette 25 ml of the
iodine solution into a 125 ml Erlenmeyer
flask. Add 2 ml of 3 M HC1. Titrate rapidly
with standard 0.01 N thiosulfate solution or
with 0.01 N phenylarsine oxide until the so-
lution is light yellow, using gentle mixing.
Add four drops of starch indicator solution
and continue titrating slowly until the blue
color just disappears. Record VT. the volume
of thiosulfate solution used, or Vu, the
volume of phenylarsine oxide solution used
(ml). Repeat until replicate values agree
within 0.05 ml. Average the replicate titra-
tion values which agree within 0.05 ml and
calculate the exact normality of the iodine
solution using equation 9.3. Repeat the
standardization daily.
8.1.2 Standardize the 0.1 N thiosulfate
solution as follows: Oven-dry potassium di-
chromate (K,Cr,O,) at 180 to 200' C (360 to
390' F). Weigh to the nearest milligram, 2 g
of potassium dichromate. Transfer the di-
chromate to a 500 ml volumetric flask, dis-
solve in deionized, distilled water and dilute
to exactly 500 ml. In a 500 ml iodine flask,
dissolve approximately 3 g of potassium
iodide (KI) in 45 ml of deionized, distilled
water, then add 10 ml of 3 M hydrochloric
acid solution. Pipette 50 ml of the dichro-
mate solution into this mixture. Gently
swirl the solution once and allow It to stand
in the dark for 5 minutes. Dilute the solu-
tion with 100 to 200 ml of deionized distilled
water, washing down the sides of the flask
with part of the water. Titrate with 0.1 N
thiosulfate until the solution is light yellow.
Add 4 ml of starch indicator and continue ti-
trating slowly to a green end point. Record
V§, the volume of thiosulfate solution used
(ml). Repeat until replicate analyses agree
within 0.05 ml. Calculate the normality
using equation 9.1. Repeat the standardiza-
tion each week, or after each test series,
whichever time is shorter.
8.1.3 Standardize the 0.01 N Phenylar-
sine oxide (if applicable) as follows: oven
dry potassium dichromate
-------
(6 eq. I,/mole K,Cr,O,) (1,000 ml/liter)/
(249.2 g K,Cr,O,/mole) (100 aliquot
factor)
9.3 Normality of Standard Iodine Solu-
tion.
N, = NTVT/V,
where:
N, = Normality of standard Iodine solution,
g-eq/liter.
Vi=Volume of standard iodine solution
used, ml.
NT = Normallty of standard (-0.01 N) thio-
sulfate solution; assumed to be 0.1 N,, g-
eq/liter.
VT=Volume of thiosulfate solution used, ml.
NOTE.If phenylarsine oxide is used
Intead of thiosulfate, replace NT and VT in
Equation 9.3 with NA and V«, respectively
(see sections 8.1.1 and 8.1.3).
8.4 Dry Gas Volume. Correct the sample
volume measured by the dry gas meter to
standard conditions (20* C) and 160 mm Hg.
V»u,d» = V»Y [dWTJ (Ptar/P«)l
where:
Vmi.,di = Volume at standard conditions of gas
sample through the dry gas meter, stan-
dard liters.
Vm = Volume of gas sample through the dry
gas meter tmeter conditions), liters.
Tlu, = Absolute temperature at standard con-
ditions, 293' K.
Tm = Average dry gas meter temperature, "K.
Ptar = Barometric pressure at the sampling
site, mm Hg
Pu^Absolute pressure at standard condi-
tions, "760 mm Hg.
Y = Dry gas meter calibration factor.
9.5 Concentration of H,S. Calculate the
concentration of HjS in the gas stream at
standard conditions using the following
equation:
CH« = K[(V,TN,-VTTNT) sample-
(V.TN.-VrrN,) blank]/V.w
where (metric units):
CHJS = Concentration of H,S at standard con-
ditions, mg/dscm.
K = Conversion factor = 17.04x10'
(34.07 g/mole H,S> (1,000 liters/m') (1.000
mg/g)/ = ( 1.000 ml/liter) (2H.S eq/mole)
V,T = Volume of standard iodine solu-
tion =50.0 ml.
N, = Normality of standard iodine solution,
g-eq/liter.
VTI = Volume of standard (-0.01 N) sodium
thiosulfate solution, ml.
NT = Normality of standard sodium thiosul-
fate solution, g-eq/liter.
V.nuw.sDry gas volume at standard condi-
tions, liters.
NOTE -*If phenylarsine oxide is used In-
stead of thiosulfate, replace NT and Vn In
Equation 9.5 with N» and VAT. respectively
(see Sections 7.3.1 and 8.1.3).
10. Stability. The absorbing solution is
stable for at least 1 month. Sample recovery
and analysis should begin within 1 hour of
sampling to minimize oxidation of the acidi-
fied cadmium sulfide. Once iodine has been
added to the sample, the remainder of the
analysis procedure must be completed ac-
cording to sections 7.2.2 through 7.3.2.
11. Bibliography.
11.1 Determination of Hydrogen Sulfide,
Ammoniacal Cadmium Chloride Method.
API Method 772-54. In: Manual on Disposal
of Refinery Wastes. Vol. V: Sampling and
Analysis of Waste Oases and Paniculate
Matter, American Petroleum Institute,
Washington, D.C.. 1954.
11.2 Tentative Method of Determination
of Hydrogen Sulfide and Mercaptan Sulfur
In Natural Oas, Natural Gas Processors As-
sociation, Tulsa, Okla., NGPA Publication
No. 2265-65. 1965.
11,3 Knoll, J. E., and M. R. Midgett. De-
termination of Hydrogen Sulfide in Refin-
ery Fuel Gases, Environmental Monitoring
Series, Office of Research and Develop-
ment, USEPA, Research Triangle Park, N.C.
27711, EPA 600/4-77-007.
11.4 Scheill, G. W.. and M. C. Sharp.
Standardization of Method 11 at a Petro-
leum Refinery. Midwest Research Institute
Draft Report for USEPA, Office of Re-
search and Development, Research Triangle
Park, N.C. 27711, EPA Contract No. 68-02-
1098, August 1976, EPA 600/4-77-088*
(Volume 1) and EPA 600/4-77-088b (Volume
2).
(Sees, 111, 114, 301(a), Clean Atr Act a*
amended (42 U.S.C. 7411. 7414. 7601U
III-Appendix A-44
-------
Method ISA. Determination of Total Fluoride
Emissions From Stationary Sources; SPADNS
Zirconium Lake Method 14»113
1. Applicability and Principle
1.1 Applicability. This method applies to
the determination of fluoride (F) emissions
from sources as specified in the regulations. It
does not measure fluorocarbons, such as
freons.
1 2 Principle. Gaseous and participate F
are withdrawn isokinetically from the source
and collected in water and on a filter. The
total F is then determined by the SPADNS
Zirconium Lake colorimetric method.
2. Range and Sensitivity
The range of this method is 0 to 1.4 fig F/
ml. Sensitivity has not been determined.
3. Interferences
Large quantities of chloride will interfere
with the analysis, but this interference can be
prevented by adding silver sulfate into the
distillation flask (see Section 7.3.4). If
chloride ion is present, it may be easier to use
the Specific Ion Electrode Method (Method
13B). Grease on sample-exposed surfaces
may cause low F results due to adsorption.
4, Precision, Accuracy, and Stability
4.1 Precision. The following estimates
are based on a collaborative test done at a
primary aluminum smelter. In the test, six
laboratories each sampled the stack
simultaneously using two sampling trains for
a total of 12 samples per sampling run.
Fluoride concentrations encountered during
the test ranged from 0.1 to 1.4 mg F/m3. The
within-laboratory and between-laboratory
standard deviations, which include sampling
and analysis errors, were 0.044 mg F/m3 with
60 degrees of freedom and 0.064 mg F/m3
with five degrees of freedom, respectively.
4.2 Accuracy. The collaborative test did
not find any bias in the analytical method.
4.3 Stability. After the sample and
colorimetric reagent are mixed, the color
formed is stable for approximately 2 hours. A
3°C temperature difference between the
sample and standard solutions produces an
error of approximately 0.005 mg F/liter. To
avoid this error, the absorbances of the
sample and standard solutions must be
measured at the same temperature.
5. Apparatus
5.1 Sampling Train. A schematic of the
sampling train is shown in Figure 13A-1; it is
similar to the Method 5 train except the filter
position is interchangeable. The sampling
train consists of the following components'
5.1.1 Probe Nozzle, Pilot Tube,
Differential Pressure Gauge, Filter Heating
System, Metering System. Barometer, and
Gas Density Determination Equipment.
Same as Method 5, Sections 2.1.1, 2.1.3, 2.1 4,
2.1.6, 2 1.8, 2.1.9, and 2.1.10. When moisture
condensation is a problem, the filter heating
system is used.
5.1.2 Probe Liner. Borosihcate glass or
316 stainless steel. When the filter is located
immediately after the probe, the tester may
use a probe heating system to prevent filter
plugging resulting from moisture
condensation, but the tester shall not allow
the temperature in the probe to exceed
120±14°C (248±25T).
5.1.3 Filter Holder. With positive seal
against leakage from the outside or around
the filter. If the filter is located between the
probe and first impinger, use borosihcate
glass or stainless steel with a 20-mesh
stainless steel screen filter support and a
silicone rubber gasket, do not use a glass frit
or a sintered metal filter support If the filter
is located between the third and fourth
impingers, the tester may use borosihcate
glass with a glass frit filter support and a
silicone rubber gasket. The tester may also
use other materials of construction with
approval from the Administrator.
5.1.4 Impingers. Four impingers
connected as shown in Figure 13A-1 with
ground-glass (or equivalent), vacuum-tight
fittings. For the first, third, and fourth
impingers, use the Greenburg-Smith design,
modified by replacing the tip with a 1.3-cm-
inside-diameter (Vfe in.) glass tube extending
to 1.3 cm (V4 in.) from the bottom of the flask.
For the second impinger, use a Greenburg-
Smith impinger with the standard tip. The
tester may use modifications (e.g., flexible
connections between the impingers or
materials other than glass), subject to the
approval of the Administrator. Place a
thermometer, capable of measuring
temperature to within 1°C (2°F), at the outlet
of the fourth impinger for monitoring
purposes.
5.2 Sample Recovery. The following
items are needed:
5.2.1 Probe-Liner and Probe-Nozzle
Brushes, Wash Bottles, Graduated Cylinder
and/or Balance, Plastic Storage Containers.
Rubber Policeman, Funnel. Same as Method
5, Sections 2.2.1 to 2.2.2 and 2.2.5 to 2.2.8,
respectively.
5.2.2 Sample Storage Container. Wide-
mouth, high-density-polyethylene bottles for
impinger water samples, 1-liter.
5.3 Analysis. The following equipment is
needed:
5.3.1 Distillation Apparatus. Glass
distillation apparatus assembled as shown in
Figure 13A-2.
5.3.2 Bunsen Burner.
5.3.3 Electric Muffle Furnace. Capable of
heating to 600°C.
5.3.4 Crucibles. Nickel, 75- to 100-ml.
5.3.5 Beakers. 500-ml and 1500-ml.
5.3.6 Volumetric Flasks. 50-ml.
5.3.7 Erlenmeyer Flaskg.or Plastic Bottles.
500-ml.
5.3.8 Constant Temperature Bath.
Capable of maintaining a constant
temperature of ±1.0°C at room temperature
conditions.
5.3.9 Balance. 300-g capacity to measure
to ±0.5 g.
5.3.10 Spectrophotometer. Instrument
that measures absorbance at 570 run and
provides at least a 1-cm light path.
5.3.11 Spectrophotometer Cells. 1-cm
pathlength.
fi Reagents
6.1 Sampling. Use ACS reagent-grade
chemicals or equivalent, unless otherwise
specified. The reagents used in sampling are
as follows:
6.1.1 Filters.
6.1.1.1 If the filter is located between the
third and fourth impingers, use a Whatman'
No. 1 filter, or equivalent, sized to fit the filter
holder.
III-Appendix A-45
-------
TEMPERATURE ( (
SENSOR STACK WALL j OPTIONAL FILTER
/ K-^*" (HOLDER LOCATION
THERMOMETERS. ICE BATH
ORIFICE
THERMOMETER
CHECK VALVE
VACUUM LINE
VACUUM GAUGE
MAIN VALVE
AIR TIGHT PUMP
DRY TEST METER
Figure 13A 1. Fluoride sampling train.
CONNECTING TUBE ^
12 mm ID , \
124/40
THERMOMETER
CONDENSER
SOO-ml
ERLENMEYER
FLASK
Figure 13A-2. Fluoride distillation apparatu
Ill-Appendix A-46
-------
6.1.1.2 If the filter is located between the
probe and first impinger, use any suitable
medium (e.g., paper organic membrane) that
conforms to the following specifications: (1)
The filter can withstand prolonged exposure
to temperatures up to 135°C (275°F). (2) The
filter has at least 95 percent collection
efficiency (<5 percent penetration) for 0.3 /im
dioctyl phthalate smoke particles. Conduct
the filter efficiency test before the test series,
using ASTM Standard Method D 2986-71, or
use test data from the supplier's quality
control program. (3) The filter has a low F
blank value (<0.015 mg F/cm'of filter area).
Before the test series, determine the average
F blank value of at least three filters (from
the lot to be used for sampling) using the
applicable procedures described in Sections
7.3 and 7.4 of this method. In general, glass
fiber filters have high and/or variable F
blank values, and will not be acceptable for
use.
6.1.2 Water. Deionized distilled, to
conform to ASTM Specification D 1193-74,
Type 3. If high concentrations of organic
matter are not expected to be present, the
analyst may delete the potassium
permanganate test for oxidizable organic
matter.
6.1.3 Silica Gel, Crushed Ice. and
Stopcock Grease. Same as Method 5,
Section 3.1.2, 3.1.4, and 3.1.5, respectively.
6.2 Sample Recovery. Water, from same
container as described in Section 6.1.2, is
needed for sample recovery.
6.3 Sample Preparation and Analysis.
The reagents needed for sample preparation
and analysis are as follows:
6.3.1 Calcium Oxide (CaO). Certified
grade containing 0.005 percent F or less.
6.3.2 Phenolphthalein Indicator.
Dissolve 0.1 g of phenolphthalein in a mixture
of 50 ml of 90 percent ethanol and 50 ml of
deionized distilled water.
6.3.3 Silver Sulfate (Ag^O,).
6.3 4 Sodium Hydroxide (NaOH).
Pellets.
635 Sulfuric Acid (H,SO<), Concentrated.
6.3 6 Sulfuric Acid. 25 percent (V/V).
Mix 1 part of concentrated H.SO. with 3
parts of deionized distilled water.
6.3.7 Filters Whatman No. 541, or
equivalent
6.3.8 Hydrochloric Acid (HC1),
Concentrated.
6.3.9 Water. From same container as
described in Section 6.1.2.
6 3 10 Fluoride Standard Solution, 0.01 mg
F/ml. Dry in an oven at 110°C for at least 2
hours. Dissolve 0 2210 g of NaF in 1 liter of
deionized distilled water. Dilute 100 ml of this
solution to 1 liter with deionized distilled
water.
6.3.11 SPADNS Solution (4, 5 dihydroxy-3-
(p-sulfophenylazo)-2,7-naphthalene-disullonic
acid Irisodium salt]. Dissolve 0.960 ± 0.010
g of SPADNS reagent in 500 ml deionized
distilled water. If stored in a well-sealed
botlle protected from the sunlight, this
solution is stable for at least 1 month.
6.3.12 Spectrophotometer Zero Reference
Solution Prepare daily. Add 10 ml of
SPADNS solution (6.3.11) to 100 ml deionized
distilled water, and acidify with a solution
prepared by diluting 7 ml of concentrated HC1
to 10 ml with deionized distilled water.
6.3.13 SPADNS Mixed Reagent. Dissolve
0.135 ± 0.005 g of zirconyl chloride
octahydrate {ZrOCU. 8H.O) in 25 ml of
deionized distilled water. Add 350 ml of
concentrated HC1, and dilute to 500 ml with
deionized distilled water. Mix equal volumes
of this solution and SPADNS solution to form
a single reagent. This reagent is stable for at
least 2 months.
7. Procedure
7.1 Sampling. Because of the complexity
of this method, testers should be trained and
experienced with the text procedures to
assure reliable results.
7.1.1 Pretest Preparation. Follow the
general procedure given in Method 5, Section
4.1.1, except the filter need not be weighed.
7.1.2 Preliminary Determinations.
Follow the general procedure given in
Method 5, Section 4.1.2., except the nozzle
size selected must maintain isokinetic
sampling rates below 28 liters/min (1.0 cfin).
7.1.3 Preparation of Collection Train.
Follow the general procedure given in
Method 5, Section 4.1.3, except for the
following variations:
Place 100 ml of deionized distilled water in
each of the first two impmgers, and leave the
third impinger empty. Transfer approximately
200 to 300 g of preweighed silica gel from its
container to the fourth impinger.
Assemble the train as shown in Figure
13A-1 with the filter between the third and
fourth impingers. Alternatively, if a 20-mesh
stainless steel screen is used for the filter
support, the tester may place the filter
between the probe and first impinger. The
tester may also use a filter heating system to
prevent moisture condensation, but shall not
allow the temperature around the filter holder
to exceed 120 ± 14"C (248 ± 25°F). Record
the filter location on the data sheet.
7.1.4 Leak-Check Procedures. Follow the
leak-check procedures given in Method 5,
Sections 4.1.4.1 (Pretest Leak-Check), 4.1.4.2
(Leak-Checks During the Sample Run), and
4.1.4.3 (Post-Test Leak-Check).
7.1.5 Fluoride Train Operation. Follow
the general procedure given in Method 5,
Section 4.1.5, keeping the filter and probe
temperatures (if applicable) at 120 ± 14°C
(248 ± 25°F) and isokinetic sampling rates
below 28 hters/min (1.0 cfm). For each run.
record the data required on a data sheet such
as the one shown in-Method 5, Figure 5-2.
7.2 Sample Recovery. Begin proper
cleanup procedure as soon as the probe is
removed from the stack at the end of the
sampling period.
Allow the probe to cool When it can be
safely handled, wipe off all external
particulate matter near the Up of the probe
nozzle and place a cap over it to keep from
losing part of the sample. Do not cap off the
probe tip tightly while the sampling tram is
cooling down, because a vacuum would form
in the filter holder, thus drawing impinger
water backward.
Before moving the sample train to the
cleanup site, remove the probe from the
sample train, wipe off the silicone grease, and
cap the open outlet of the probe. Be careful
not to lose any condensate. if present
Remove the filter assembly, wipe off the
silicone grease from the filter holder inlet.
and cap this inlet. Remove the umbilical cord
from the last impinger, and cap the impinger.
After wiping off the silicone grease, cap off
the filter holder outlet and any open impinger
inlets and outlets. The tes.er may use ground-
glass stoppers, plastic caps, or serum caps to
close these openings.
Transfer the probe and filter-impinger
assembly to an area that is clean and
protected from the wind so that the chances
of contaminating or losing the sample is
minimized.
Inspect the train before and during
disassembly, and note any abnormal
conditions. Treat the samples as follows:
7.2.1 Container No. 1 (Probe, Filter, and
Impinger Catches). Using a graduated
cylinder, measure to the nearest ml, and
record the volume of the water in the first
three impingers; include any condensate in
the probe in this determination. Transfer the
impinger water from the graduated cylinder
into this polyethylene container, Add the
filter to this container. (The filter may be
handled separately using procedures subject
to the Administrator's approval.) Taking care
that dust on the outside of the probe or other
exterior surfaces does not get into the
sample, clean all sample-exposed surfaces
(including the probe nozzle, probe fitting.
probe liner, first three impingers, impinger
connectors, and filter holder) with deionized
distilled water. Use less than 500 ml for the
entire wash. Add the washings to the sampler
container. Perform the deionized distilled
water rinses as follows:
Carefully remove the probe nozzle and
rinse the inside surface with deionized
distilled water from a wash bottle. Brush with
a Nylon bristle brush, and rinse until the
rinse shows no visible particles, after which
make a final rinse of the inside surface. Brush
and rinse the inside parts of the Swagelok
fitting with deionized distilled water in a
similar way.
Rinse the probe liner with deionized
distilled water. While squirting the water into
the upper end of the probe, tilt and rotate the
probe so that all inside surfaces will be
wetted with water. Let the water drain from
the lower end into the sample container. The
tester may use a funnel (glass or
polyethylene) to aid in transferring the liquid
washes to the container. Follow the rinse
with a probe brush. Hold the probe in an
inclined position, and squirt deionized
distilled water into the upper end as the
probe brush is being pushed with a twisting
action through the probe. Hold the sample
container underneath the lower end of the
probe, and catch any water and particulate
matter that is brushed from the probe. Run
the brush through the probe three times or
more. With stainless steel or other metal
probes, run the brush through in the above
prescribed manner at least six times since
metal probes have small crevices in which
particulate matter can be entrapped. Rinse
the brush with deionized distilled water, and
quantitatively collect these washings in the
sample container. After the brushing, make a
final rinse of the probe as described above.
It is recommended that two people clean
the probe to minimize sample losses.
Between sampling runs, keep brushes clean
and protected from contamination.
Ill-Appendix A-47
-------
Rinse the inside surface of each of the first
three impingers (and connecting glassware)
three separate times. Use a small portion of
deionized distilled water for each rinse, and
brush each sample-exposed surface with a
Nylon bristle brush, to ensure recovery of
fine participate matter. Make a final rinse of
each surface and of the brush.
After ensuring that all joints have been
wiped clean of the silicone grease, brush and
rinse with deionized distilled water the inside
of the filter holder [front-half only, if filter is
positioned between the third and fourth
impingers). Brush and rinse each surface
three times or more if needed. Make a final
rinse of the brush and filter holder.
After all water washings and particulate
matter have been collected in the sample
container, tighten the lid so that water will
not leak out when it is shipped to the
laboratory. Mark the height of the fluid level
to determine whether leakage occurs during
transport. Label the container clearly to
identify its contents.
7.2.2 Container No. 2 (Sample Blank).
Prepare a blank by placing an unused filter in
a polyethylene container and adding a
volume of water equal to the total volume in
Container No. 1. Process the blank in the
same manner as for Container No. 1.
7.2.3 Container No. 3 (Silica Gel). Note
the color of the indicating silica gel to
determine whether it has been completely
spent and make a notation of its condition.
Transfer the silica gel from the fourth
impinger to its original container and seal.
The tester may use a funnel to pour the silica
gel and a rubber policeman to remove the
silica gel from the impinger. It is not
necessary to remove the small amount of dust
particles that may adhere to the impinger
wall and are difficult to remove. Since the
gain in weight is to be used for moisture
calculations, do not use any water or other
liquids to transfer the silica gel. If a balance
is available in the field, the tester may follow
the analytical procedure for Container No. 3
in Section 7.4.2.
7.3 Sample Preparation and Distillation.
(Note the liquid levels in Containers No. 1
and No. 2 and confirm on the analysis sheet
whether or not leakage occurred during
transport. If noticeable leakage had occurred,
either void the sample or use methods,
subject to the approval of the Administrator,
to correct the final results.) Treat the contents
of each sample container as described below:
7.3.1 Container No. 1 (Probe, Filter, and
Impinger Catches). Filter this container's
contents, including the sampling filter,
through Whatman No. 541 filter paper, or
equivalent, into a 1500-ml beaker.
7.3.1.1 If the filtrate volume exceeds 900
ml, make the filtrate basic (red to
phenolphthalein) with NaOH, and evaporate
to less than 900 ml.
7.3.1.2 Place the filtered material
(including sampling filter) in a nickel crucible,
add a few ml of deionized distilled water,
and macerate the filters with a glass rod.
Add 100 mg CaO to the crucible, and mix
the contents thoroughly to form a slurry. Add
two drops of phenolphthalein indicator. Place
the crucible in a hood under infrared lamps
or on a hot plate at low heat. Evaporate the
water completely. During the evaporation of
the water, keep the slurry basic (red to
phenolphthalein) to avoid loss of F. If the
indicator turns colorless (acidic) during the
evaporation, add CaO until the color turns
red again.
After evaporation of the water, place the
crucible on a hot plate under a hood and
slowly increase the temperature until the
Whatman No. 541 and sampling filters char. It
may take several hours to completely char
the filters.
Place the crucible in a cold muffle furnace.
Gradually (to prevent smoking) increase the
temperature to 600°C, and maintain until the
contents are reduced to an ash. Remove the
crucible from the furnace and allow to cool.
Add approximately 4 g of crushed NaOH to
the crucible and mix. Return the crucible to
the muffle furnace, and fuse the sample for 10
minutes at 600'C.
Remove the sample from the furnace, and
cool to ambient temperature. Using several
rinsings of warm deionized distilled water,
transfer the contents of the crucible to the
beaker containing the filtrate. To assure
complete sample removal, rinse finally with
two 20-ml portions of 25 percent HSSO4, and
carefully add to the beaker. Mix well, and
transfer to a 1-liter volumetric flask. Dilute to
volume with deionized distilled water, and
mix thoroughly. Allow any undissolved solids
to settle.
7.3.2 Container No. 2 (Sample Blank).
Treat in the same manner as described in
Section 7.3.1 above.
7.3.3 Adjustment of Acid/Water Ratio in
Distillation Flask. (Use a protective shield
when carrying out this procedure.) Place 400
ml of deionized distilled water in the
distillation flask, and add 200 ml of
concentrated H2SO4. (Caution: Observe
standard precautions when mixing HaSO«
with water. Slowly add the acid to the flask
with constant swirling.) Add some soft glass
beads and several small pieces of broken
glass tubing, and assemble the apparatus as
shown in Figure 13A-2. Heat the flask until it
reaches a temperature of 175° C to adjust the
acid/water ratio for subsequent distillations.
Discard the distillate.
73.4 Distillation. Cool the contents of
the distillation flask to below 80'C. Pipet an
aliquot of sample containing less than 10.0 mg
F directly into the distillation flask, and add
deionized distilled water to make a total
volume of 220 ml added to the distillation
flask. (To estimate the appropriate aliquot
size, select an aliquot of the solution and
treat as described in Section 7.4.1. This will
be an approximation of the F content because
of possible interfering ions.) Note: If the
sample contains chloride, add 5 mg of Ag2SO<
to the flask for every mg of chloride.
Place a 250-ml volumetric flask at the
condenser exit. Heat the flask as rapidly as
possible with a Bun sen burner, and collect all
the distillate up to 175°C. During heatup, play
the burner flame up and down the side of the
flask to prevent bumping. Conduct the
distillation as rapidly as possible (15 minutes
or less). Slow distillations have been found to
produce low F recoveries. Caution: Be careful
not to exceed 175°C to avoid causing H,SO«
to distill over.
If F distillation in the mg range is to be
followed by a distillation in the fractional mg
range, add 220 ml of deionized distilled water
and distill it over as in the acid adjustment
step to remove residual F from the distillation
system.
The tester may use the acid in the
distillation flask until there is carry-over of
interferences or poor F recovery. Check for
these every tenth distillation using a
deionis i>d distilled water blank and a
standard solution. Change the acid whenever
the F recovery is less than 90 percent or the
blank value exceeds 0.1 Jig/ml.
7.4 Analysis.
7.4.1 Containers No. 1 and No. 2. After
distilling suitable aliquots from Containers
No. 1 and No. 2 according to Section 7.3.4,
dilute the distillate in the volumetric flasks to
exactly 250 ml with deionized distilled water,
and mi* thoroughly. Pipet a suitable aliquot
of each sample distillate (containing 10 to 40
fig F/ml| into a beaker, and dilute to 50 ml
with deionized distilled water. Use the same
aliquot size for the blank. Add 10 ml of
SPADNS mixed reagent (6.3.13), and mix
thoroughly.
After mixing, place the sample in^a
constant-temperature bath containing the
standard solutions (see Section 8.2) for 30
minutes before reading the absorbance on the
spectrophotometer.
Set the spectrophotometer to zero
absorbance at 570 nm with the reference
solution (6.3.12), and check the
spectrophotometer calibration with the
standard solution. Determine the absorbance
of the samples, and determine the
concentration from the calibration curve. If
the concentration does not fall within the
range of the calibration curve, repeat the
procedure using a different size aliquot.
7.4.2 Container No. 3 (Silica Gel). Weigh
the spent silica gel (or silica gel plus
impinger) to the nearest 0.5 g using a balance.
The tester may conduct this step in the field.
8. Calibration
Maintain a laboratory log of all
calibrations.
8.1 Sampling Train. Calibrate the
sampling train components according to the
indicated sections in Method 5: Probe Nozzle
(Section 5.1); Pilot Tube (Section 5.2);
Metering System (Section 5.3); Probe heater
(Section 5.4); Temperature Gauges (Section
5.5); Leak Check of Metering System (Section
5.6); and Barometer (Section 5.7).
8.2 Slpectrophotometer. Prepare the
blank standard by adding 10 ml of SPADNS
mixed reagent to 50 ml of deionized distilled
water. Accurately prepare a series of
standards from the 0.01 mg F/ml standard
fluoride solution (6.3.10) by diluting 0, 2, 4, 6,
8,10,12, and 14 ml to 100 ml with deionized
distilled water. Pipet 50 ml from each solution
and transfer each to a separate 100-ml
beaker. Then add 10 ml of SPADNS mixed
reagent to each. These standards will contain
0,10, 20, 30, 40 50, 60, and 70 fig F (0 to 1.4 fig/
ml), respectively.
After mixing, place the reference standards
and reference solution in a constant
temperature bath for 30 minutes before
reading the absorbance with the
spectrophotometer. Adjust all samples to this
same temperature before analyzing.
Ill-Appendix A-48
-------
VVilh the spectrophotometer at 570 nm, use
the reference solution (6.3.12) to set the
absorbance to zero.
Determine the absorbance of the
standards Prepare a calibration curve by
plotting fig F/50 ml versus absorbance on
linear graph paper. Prepare the standard
curve initially and thereafter whenever the
SPADNS mixed reagent is newly made. Also,
run a calibration standard with each set of
samples and if it differs from the calibration
curve by ±2 percent, prepare a new standard
curve.
9. Calculations
Carry out calculations, retaining at least
one extra decimal figure beyond that of the
acquired data. Round off figures after final
calculation. Other forms of the equations may
be used, provided that they yield equivalent
results.
9.1 Nomenclature.
A,, =f Aliquot of distillate taken for color
development, ml.
At = Aliquot of total sample added to still,
ml.
B»s = Water vapor in the gas stream,
proportion by volume.
Cs = Concentration of F in stack gas, mg/m3,
dry basis, corrected to standard
conditions of 760 mm Hg (29.92 in. Hg)
and 293°K (528'R).
F, = Total F in sample, mg.
jig F = Concentration from the calibration
curve, jig.
Tm = Absolute average dry gas meter
temperature (see Figure 5-2 of Method 5),
KJR).
Ts = Absolute average stack gas temperature
(see Figure 5-2 of Method 5), °K (°R).
Vd = Volume of distillate collected, ml.
Vm(ttd) = Volume of gas sample as measured
by dry gas meter, corrected to standard
conditions, dscm (dscf).
V, = Total volume of F sample, after final
dilution, ml.
VwW = Volume of water vapor in the gas
sample, corrected to standard conditions,
scm (scf).
9.2 Average Dry Gas Meter Temperature
and Average Orifice Pressure Drop. See data
sheet (Figure 5-2 of Method 5).
9.3 Dry Gas Volume. Calculate V^^i and
adjust for leakage, if necessary, using the
equation in section 6.3 of Method 5.
9.4 Volume of Water Vapor and Moisture
Content. Calculate the volume of water vapor
V«(,td) and moisture content B»s from the data
obtained in this method (Figure 13A-1); use
Equations 5-2 and 5-3 of Method 5.
9.5 Concentration.
9.5.1 Total Fluoride in Sample. Calculate
the amount of F in the sample using the
following equation:
Where:
K = 35.31 ft'/m3 if Vm(«d) is expressed In
English units.
= 1.00 mVm^if Vm(,Kii is expressed in
metric units.
9.6 Isokinetic Variation and Acceptable
Results. Use Method 5, Sections 6.11 and
6.12.
10. Bibliography
1. Bellack, Ervin, Simplified Fluoride
Distillation Method. Journal of the American
Water Works Association. 50.P5306.1958.
2. Mitchell. W. J., J. C. Suggs, and F. J.
Bergman. Collaborative Study of EPA method
13A and Method 13B. Publication No. EPA-
600/4-77-050. Environmental Protection
Agency. Research Triangle Park, North
Carolina. December 1977.
3. Mitchell, W. J. and M. R. Midgett.
Adequacy of Sampling Trains and Analytical
Procedures Used for Fluoride. Aim. Environ.
J0.-865-872.1976.
10
V. V .
F)
Eq. 13A-1
9.5.2 Fluoride Concentration in Stack Gas. Determine the F concentration in the stack
gas using the following equation:
'm(std)
Eq. 13A-2
Ill-Appendix A-49
-------
Method 13B. Determination of Total Fluoride
Emissions From Stationary Sources: Specific
Ion Electrode Methodl4'"3
1. Applicability and Principle
1.1 Applicability. This method applies to
the determination of fluoride (F) emissions
from stationary sources as specified in the
regulations. It does not measure
fluorocarbons, such as freons.
1.2 Principle. Gaseous and particulate F
are withdrawn isokinetically from the source
and collected in water and on a filter. The
total F is then determined by the specific ion
electrode method.
2. Range and Sensitivity
The range of this method is 0.02 to 2.000 jtg
F/ml; however, measurements of less than 0.1
jig F/ml require extra care. Sensitivity has
not been determined.
3. Interferences
Crease on sample-exposed surfaces may
cause low F results because of adsorption.
4. Precision and Accuracy
4.1 Precision. The following estimates
are based on a collaborative test done at a
primary aluminum smelter. In the test, six
laboratories each sampled the stack
simultaneously using two sampling trains for
a total of 12 samples per sampling run.
Fluoride concentrations encountered during
the test ranged from 0.1 to 1.4 mg F/m9. The
within-laboratory and between-laboratory
standard deviations, which include sampling
and analysis errors, are 0.037 mg F/m9 with
60 degrees of freedom and 0.056 mg F/m9
with five degrees of freedom, respectively.
4.2 Accuracy. The collaborative test did
not find any bias in the analytical method.
5. Apparatus
5.1 Sampling Train and Sample Recovery.
Same as Method 13A, Sections 5.1 and 5.2,
respectively.
5.2 Analysis. The following items are
needed:
5.2.1 Distillation Apparatus, Bunsen
Burner, Electric Muffle Furnace, Crucibles,
Beakers, Volumetric Flasks. Erlenmeyer
Flasks or Plastic Bottles, Constant
Temperature Bath, and Balance. Same as
Method ISA, Sections 5.3.1 to 5.3.9,
respectively, except include also 100-ml
polyethylene beakers.
5.2.2 Fluoride Ion Activity Sensing
Electrode.
5.2.3 Reference Electrode. Single
junction, sleeve type.
5.2.4 Electrometer. A pH meter with
millivolt-scale capable of ±0.1-mv resolution,
or a specific ion meter made specifically for
specific ion use.
5.2.5 Magnetic Stirrer and TFE *
Fluorocarbon-Coated Stirring Bars.
'Mention of any trade name or specific product
does not constitute endorsement by the
Environmental Protection Agency.
6. Reagents
6.1 Sampling and Sample Recovery.
Same as Method 13A. Sections 6.1 and 6,2.
respectively.
6.2 Analysis. Use ACS reagent grade
chemicals (or equivalent), unless otherwise
specified. The reagents needed for analysis
are as follows:
6.2.1 Calcium Oxide (CaO). Certified
grade containing 0.005 percent F or less.
6.2.2 Phenolphthalein Indicator.
Dissolve 0.1 g of phenolphthalein in a mixture
of 50 ml of 90 percent ethanol and 50 ml
deionized distilled water.
6.2.3 Sodium Hydroxide (NaOH).
Pellets.
6.2.4 Sulfuric Acid (HZSO<). Concentrated.
6.2.5 Filters. Whatman No. 541. or
equivalent.
6.2.6 Water. From same container as
6.1.2 of Method 13A.
6.2.7 Sodium Hydroxide, 5 M. Dissolve
20 g of NaOH in 100 ml of deionized distilled
water
6.2.8 Sulfuric Acid. 25 percent (V/V).
Mix 1 part of concentrated HZSO, with 3
parts of deionized distilled water.
6.2.9 Total Ionic Strength Adjustment
Buffer (TISAB). Place approximately 500 ml
of deionized distilled water in a 1-liter
beaker. Add 57 ml of glacial acetic acid, 58 g
of sodium chloride, and 4 g of cyclohexylene
dinitrilo tetraacetic acid. Stir to dissolve.
Place the beaker in a water bath to cool it
Slowly add 5 M NaOH to the solution,
measuring the pH continuously with a
calibrated pH/reference electrode pair, until
the pH is 5.3. Cool to room temperature. Pour
into a 1-liter volumetric flask, and dilute to
volume with deionized distilled water.
Commercially prepared TISAB may be
substituted for the above.
6.2.10 Fluoride Standard Solution, 0.1 M.
Oven dry some sodium fluoride (NaF) for a
minimum of 2 hours at 110'C, and store in a
desiccator. Then add 4.2 g of NaF to a 1-liter
volumetric flask, and add enough deionized
distilled water to dissolve. Dilute to volume
with deionized distilled water.
7. Procedure
7.1 Sampling, Sample Recovery, and
Sample Preparation end Distillation. Same
as Method 13A, Sections 7.1, 7.2, and 7.3,
respectively, except the notes concerning
chloride and sulfate interferences are not
applicable.
7.2 Analysis.
7.2.1 Containers No. 1 and No. 2. Distill
suitable aliquots from Containers No. 1 and
No. 2. Dilute the distillate in the volumetric
flasks to exactly 250 ml with deionized
distilled water and mix thoroughly. Pipet a
25-ml aliquot from each of the distillate and
separate beakers. Add an equal volume of
TISAB, and mix. The sample should be at the
same temperature as the calibration
standards when measurements are made. If
ambient laboratory temperature fluctuates
more than ±2°C from the temperature at
which the calibration standards were
measured, condition samples and standards
in a constant-temperature bath before
measurement. Stir the sample with a
magnetic stirrer during measurement to
minimize electrode response time. If the
stirrer generates enough heat to change
solution temperature, place a piece of
temperature insulating material such as cork,
between the stirrer and the beaker. Hold
dilute samples (below 10" * M fluoride ion
content) in polyethylene beakers during
measurement.
Insert the fluoride and reference electrodes
into the solution. When a steady millivolt
reading is obtained, record it. This may take
several minutes. Determine concentration
from theTalibration curve. Between electrode
measurements, rinse the electrode with
distilled water.
7.2.2 Container No. 3 (Silica Gel). Same
as Method 13A, Section 7.4.2.
ft Calibration
Maintain a laboratory log of all
calibrations.
8.1 Sampling Train. Same as Method
13A.
8.2 Fluoride Electrode. Prepare fluoride
standardizing solutions by serial dilution of
the 0.1 M fluoride standard solution. Pipet 10
ml of 0.1 M fluoride standard solution into a
100-ml volumetric flask, and make up to the
mark with deionized distilled water for a 10"*
M standard solution. Use 10ml of 10"* M
solution to make a 10"'M solution in the
same manner. Repeat the dilution procedure
and make 10"4and 10"'solutions.
Pipet 150 ml of each standard into a
separate beaker. Add 50 ml of TISAB to each
beaker. Place the electrode in the most dilute
standard solution. When a steady millivolt
reading is obtained, plot the value on the
linear axis of semilog graph paper versus
concentration on the log axis. Plot the
nominal value for concentration of the
standard on the log axis, e.g., when 50 ml of
10"2M standard is diluted with 50 ml of
TISAB, the concentration is still designated
"10"2M."
Between measurements soak the fluoride
sensing electrode in deionized distilled water
for 30 seconds, and then remove and blot dry.
Analyze the standards going from dilute to
concentrated standards. A straight-line
calibration curve will be obtained, with
nominal concentrations of 10"4,10"', 10"*,
and 10"' fluoride molarity on the log axis
plotted versus electrode potential (in mv) on
the linear scale. Some electrodes may be
slightly nonlinear between 10~6 and 10"4M. If
this occurs, use additional standards between
these two concentrations.
Calibrate the fluoride electrode daily, and
check it hourly. Prepare fresh fluoride
standardizing solutions daily (10'*M or less).
Store fluoride standardizing solutions in
polyethylene or polypropylene containers.
(Note: Certain specific ion meters have been
designed specifically for fluoride electrode
use and give a direct readout of fluoride ion
concentration. These meters may be used in
lien of calibration curves for fluoride
measurements over narrow concentration
ranges. Calibrate the meter according to the
manufacturer's instructions.)
Ill-Appendix A-50
-------
9. Calculations
Carry out calculations, retaining at least
one extra decimal figure beyond that of the
acquired data. Round off figures after final
calculation.
9.1 Nomenclature. Same as Method 13A,
Section 9.1. In addition:
M=F concentration from calibration curve,
molarity.
9.2 Average Dry Gas Meter Temperature
and Average Orifice Pressure Drop, Dry Gas
Volume, Volume of Water Vapor and
Moisture Content, Fluroide Concentration in
Stack Gas, and Isokinetic Variation and
Acceptable Results. Same as Method 13A,
Section 9.2 to 9.4, 9.5.2, and 9.6, respectively.
9.3 Fluoride in Sample. Calculate the
amount of F in the sample using the
following:
Ft
Where:
K=19 rag/ml.
Equation 13B-1
10. References
1. Same as Method 13A, Citations 1 and 2
of Section 10.
2. MacLeod, Kathryn E. and Howard L.
Crist. Comparison of the SPADNS
Zirconium Lake and Specific Ion Electrode
Methods of Fluoride Determination in Stack
Emission Samples. Analytical Chemistry.
45:1272-1273.1973.
Ill-Appendix A-51
-------
METHOD 14DETERMINATION OF
FLUORIDE EMISSIONS FROM POTROOM
ROOF MONITORS FOR PRIMARY
ALUMINUM PLANTS27!114
1. Applicability and Principle.
1.1 Applicability. This method is
applicable for the determination of fluoride
emissions from stationary sources only when
specified by the test procedures for
determining compliance with new source
performance standards.
1.2 Principle. Gaseous and particulate
fluoride roof monitor emissions are drawn
into a permanent sampling manifold through
several large nozzles. The sample is
transported from the sampling manifold to
ground level through a duct. The gas in the
duct is sampled using Method 13A or 13B
Determination of Total Fluoride Emissions
from Stationary Sources. Effluent velocity
and volumetric flow rate are determined with
anemometers located in the roof monitor.
2. Apparatus.
2.1 Velocity measurement apparatus.
2.1.1 Anemometers. Propeller
anemometers, or equivalent. Each
anemometer shall meet the following
specifications: (1) Its propeller shall be madi'
of polystyrene, or similar material of uniform
density. To insure uniformity of performance
among propellers, it is desirable that all
propellers be made from the same mold. (2|
The propeller shall be properly balanced, to
optimize performance; (3) When the
anemometer is mounted horizontally, its
threshold velocity shall not exceed 15 m/min
(50 fpm); (4) The measurement range of the
anemometer shall extend to at least 600 m/
min (2,000 fpm); (5) The anemometer shall be
able to withstand prolonged exposure to
dusty and corrosive environments; one way
of achieving this is to continuously purge the
bearings of the anemometer with filtered air
during operation; (6) All anemometer
components shall be properly shielded or
encased, such that the performance of the
anemometer is uninfluenced by potroom
magnetic field effects; (7) A known
relationship shall exist between the electrical
output signal from the anemometer generator
and the propeller shaft rpm, at a minimum of
three evenly spaced rpm settings between 60
and 1800 rpm; for the 3 settings, use 60±15,
900±100, and 1800+100 rpm. Anemometers
having other types of output signals (e.g.,
optical) may be used, subject to the approval
of the Administrator. If other types of
anemometers are used, there must be a
known relationship (as described above)
between output signal and shaft rpm; also.
each anemometer must be equipped with a
suitable readout system (See Section 2.1.3).
2.1.2 Installation of anemometers.
2.1.2.1 If the affected facility consists of a
single, isolated potroom (or potroom
segment), install at least one anemometer for
every 85 m of roof monitor length. If the
length of the roof monitor divided by 85 m is
not a whole number, round the fraction to the
nearest whole number to determine the
number of anemometers needed. For
monitors that are less than 130 m in length.
use at least two anemometers. Divide the
monitor cross-section into as many equal
areas «s anemometers and locate an
anemometer at the centroid of each equ;il
area. See exception in Section 2.1.2.3.
2.1.2.2 If the affected facility consists of
two or more potrooms (or potroom segments)
ducted to a common control device, install
anemometers in each potroom (or segment)
that contains a sampling manifold. Install at
least one anemometer for every 85 m of roof
monitor length of the potroom (or segment). If
the potroom (or segment) length divided by 85
is not a whole number, round the fraction to
the nearest whole number to determine the
number of anemometers needed. If the
potroom (or segment) length is less than 130
m. use at least two anemometers. Divide the
potroom (or segment) monitor cross-section
into as many equal areas as anemometers
and locate'an anemometer at the centroid of
each equal area. See exception in Section
2.1.2.3.
2.1.2.3 At least one anemometer shall be
installed in the immediate vicinity (i.e.,
within 10 m) of the center of the manifold
(See Section 2.2.1). For its placement in
relation to the width of the monitor, there are
two alternatives. The first is'to make a
velocity traverse of the width of the roof
monitdr where an anemometer is to be placed
and install the anemometer at a point of
average velocity along this traverse. The
traverse may be made with any suitable low
velocity measuring device, and shall be made
during normal process operating conditions.
The second alternative, at the option of the
tester, is to install the anemometer halfway
across the width of the roof monitor. In this
latter case, the velocity traverse need not be
conducted.
2.1.3 Recorders. Recorders, equipped with
suitable auxiliary equipment (e.g.
transducers) for converting the output signal
from each anemometer to a continuous
recording of air flow velocity, or to an
integrated measure of volumetric flowrate. A
suitable recorder is one that allows the
output signal from the propeller anemometer
to be read to within 1 percent when the
velocity is between 100 and 120 m/min (350
and 400 fpm). For the purpose of recording
velocity, "continuous" shall mean one
readout per 15-minute or shorter time
interval. A constant amount of time shall
elapse between readings. Volumetric flow
rate may be determined by an electrical
count of anemometer revolutions. The
recorders or counters shall permit
identification of the velocities or flowrate
measured by each individual anemometer.
2.1.4 Pilot tube. Standard-type pilot tube
as described in Section 2.7 of Method 2, and
having a coefficient of 0.99±0.01.
2.1.5 Pilot tube (optional). Isolated. Type
S pilot, as described in Section 2.1 of Method
2. The pilot tube shall have a known
coefficient, determined as outlined in Section
4.1 of Method 2.
2.1.6 Differential pressure gauge. Inclined
manometer or equivalent, as described in
Section 2.1.2 of Method 2.
2.2 Roof monitpr air sampling system
2.2.1 Sampling ductwork. A minimum of
one manifold system shall be installed for
each potroom group (as defined in Subpart S.
Section 60.191). The manifold system and
connecting duct shall be permanently
installed to draw an air sample from the roof
monitor to ground level. A typical installation
of a duct for drawing a sample from a roof
monitor to ground level is shown in Figure
14-1. A plan of a manifold system that is
located in a roof monitor is shown in Figure
14.2. These drawings represent a lypical
installation for a generalized roof monitor
The dimensions on these figures may be
altered slightly to make the manifold system
fit into a particular roof monitor, but the
general configuration shall be followed.
There shall be eight nozzles, each having a
diameter of 0.40 to 0.50 m. Unless otherwise
specified by the Administrator, the length of
the manifold system from the first nozzle to
the eighth shall be 35 m or eight percent of
the length of the potroom (or potroom
segment) roof monitor, whichever is greater
The duct leading from the roof monitor
manifold shall be round with a diameter of
0.30 to 0.40 m. As shown in Figure 14-2. each
of the sample legs of the manifold shall have
a device, such as a blast gale or vdlve to
enable adjustment of the flow into each
sample nozzle.
The manifold shall be located in the
immediate vicinity of one of the propeller
anemometers (see Section 2.1.2.3) and as
close as possible to the midsection of the
polroom (or potroom segment). Avoid
locating the manifold near the end of a
polroom or in a section where the aluminum
reduction pot arrangement is not typical of
the rest of the potroom (or potroom segment).
Center the sample nozzles in the throal of the
roof monitor (see Figure 14-1). Construct all
sample-exposed surfaces within the nozzles.
manifold and sample duct of 316 stainless
steel. Aluminum may be used if a new
ductwork system is conditioned with
fluoride-laden roof monitor air for a period of
six weeks prior lo initial testing. Other
materials of construction may be used if it is
demonstrated through comparative testing
that there is no loss of flourides in the
syslem. All connections in the ductwork shall
be leak free
Locate two sample ports in a vertical
spclion of the duct between the roof monitor
and exhaust fa,n. The sample ports shall be at
least 10 duel diameters downstream and
three diameters upstream from any flow
disturbance such as a bend or contraction.
The Iwo sample ports shall be situated 90°
apart. One of the sample ports shall be
situated so that the duct can be traversed in
the plane of the nearest upstream duct bend.
2.2 2 Exhaust fan. An industrial fan or
blower shall be attached to the sample duct
al ground level (see Figure 14-1). This
exhaust fan shall have a capacity such that a
large enough volume of air can be pulled
through the ductwork to maintain an
isokinctic sampling rate in all the sample
nozzles for all flow rates normally
encountered in the roof monitor.
The exhaust fan volumetric flow rate shall
b« adjustable so that the roof monitor air can
be drawn isokmetically into the sample
nozzles This control of flow may be achieved
b> a damper on the inlet to the exhauster or
by any other workable method.
2.3 Temperature measurement apparatus.
2.3.1 Thei'Biocoupl*. Install a
thermocouple in the roof monitor near th«
Ill-Appendix A-52
-------
O)
C
O
E
**-
o
o
-------
0.025 DIA
CALIBRATION
HOLE
DIMENSIONS IN METERS
NOT TO SCALE
Figure 14 2. Sampling manifold and nozzles.
Ill-Appendix A-54
-------
i
5'+'
-HO
< UJ t-
H- «s m
2!3<
0 0 (f
> =
u
u
^
S.4
0
tc
o
K
uj O
o =>
0. CO
0
0
c
fr^
(D
u.
CD
C.
O.
OC
ro
o
CO
0)
o>
sample duct. The thermocouple shall conform
to the specifications outlined in Section 2.3 of
Method 2.
2.3.2 Signal transducer. Transducer, to
change the thermocouple voltage output )
temperature readout.
2.3.3 Thermocouple wire. To resell from
roof monitor to signal transducer and
recorder.
2.3.4 Recorder. Suitable recorder to
monitor the output from the thermocouple
signal transducer
2.4 Fluoride sampling train. Use the train
described in Method 13A or 13B.
3. Re-agents.
3.1 Sampling and analysis. Use reagents
described in Method 13A or 13B.
4 Calibration.
4.1 Initial performance checks. Conduct
these checks within 60 days prior to the first
performance test.
41.1 Propeller anemometers.
Anemometers which meet the specifications
outlined in Section 2.1.1 need not be
calibrated, provided that a reference
performance curve relating anemometer
signal output to air velocitj (covering the
velocity range of interest) is available from
the manufacturer. For the purpose of this
method, a "reference" performance curve is
defined as one that has been derived from
primary standard calibration data, with the
anemometer mounted vertically. "Primary
standard" data are obtainable by: (1) Direct
calibration of one or more of the
anemometers by the National Bureau of
Standards (NBS); (2) NBS-traceable
calibration; or (3) Calibration by direct
measurement of fundamental parameters
such as length and time (e.g., by moving the
anemometers through still air at measured
rates of speed, and recording the output
signals). If a reference performance curve is
not available from the manufacturer, such a
curve shall be generated, using one of the
three methods described as above. Conduct a
performance-check as outlined in Section
4.1.1.1 through 4.1.1.3, below. Alternatively,
the tester may use any other suitable method.
subject to the approval of the Administrator.
that takes into account the signal output.
propeller condition and threshold velocity of
the anemometer.
4.1.1.1 Check the signal output of the
anemometer by using an accurate rpm
generator (see Figure 14-3) or synchronous
motors to spin the propeller shaft at each of
the three rpm settings described in Section
2.1.1 above (specification No. 7), and
measuring the output signal at each setting. If,
at each setting, the output signal is within ±
5 percent of the manufacturer's value, the
anemometer can be used. If the anemometer
performance is unsatisfactory, the
anemometer shall either be replaced or
repaired.
4.1.1.2 Check the propeller condition, by
visually inspecting the propeller, making note
of any significant damage or warpage;
damaged or deformed propellers shall be
replaced.
Ill-Appendix A-55
-------
SIDE
(A)
FRONT
SIDE
(B)
FRONT
Figure 14-4. Check of anemometer starting torque. A "y" gram weight placed "x" centimeters
from center of propeller shaft produces a torque of "xy" g-cm. The minimum torque which pro-
duces a 90° (approximately) rotation of the propeller is the "starting torque."
4.1.1.3 Check the anemometer threshold
velocity as follows: With the anemometer
mounted at thown in Figure 14-4(A). fasten a
known weight (a straight-pin will suffice) to
tb« anemometer propeller at a fixed distance
from the center of the propeller shaft. This
will generate a known torque: for example, a
0.11 weight, placed 10 cm from the center of
trie fhaft, will generate a torque of 1.0 g-cja. K
the known torqu* causes the propeller to
rotate downward, approximately 90' [see
Figure 14-4(B)], then the known torque is
greater than or equal to the starting torque; if
the propeller fails to rotate approximately
90°, the known torque is less than the starling
torque. By trying different combinations of
weight and distance, the starting torque of a
particular anemometer can be satisfactorily
estimated. Once an estimate of the starting
torque has been obtained, the threshold
velocity of the anemometer (for horizontal
mounting) can be estimated from a graph
such as Figure 14-5 (obtained from the
manufacturer). If the horizontal threshold
velacity is acceptable (<15 m/min (50 fpm),
when this technique is used], the anemometer
can be used. If the threshold velocity of an
anemometer is found to be unacceptably
high, the anemometer shall either be replaced
or repaired.
Ill-Appendix A-56
-------
o
K
O
oc
<
T~T
FPM 20
(m/min) (6)
40
(12)
60
(18)
80
(24)
100
(30)
120
(36)
140
(42)
THESHOLO VELOCITY FOR HORIZONTAL MOUNTING
Figure 145. Typical curve of starting torque vs horizontal threshold velocity for propeller
anemometers. Based on data obtained by R.M. Young Company, May, 1977.
Ill-Appendix A-56a
-------
4.1.2 Thermocouple. Check the calibration
of the thermocouple-potentiometer system.
using the procedures outlined in Section 4.3
of Method 2. at temperatures of 0,100, and
150'C. If the calibration is off by more than
5'C at any of the temperatures, repair or
replace the system: otherwise, the system can
be used.
4.1.3 Recorders and/or counters. Check
the calibration of each recorder and/or
counter (see Section 2.1.3) at a minimum of
three points, approximately spanning the
expected range of velocities. Use the
calibration procedures recommended by the
manufacturer, or other suitable procedures
(subject to the approval of the
Administrator). If a recorder or counter Is
found to be out of calibration, by an average
amount greater than 5 percent for the three
calibration points, replace or repair the
system: otherwise, the system can be used.
4.1.4 Manifold Intake Nozzles. In order to
balance the flow rates in the eight individual
nozzles, proceed as follows: Adjust the
exhaust fan to draw a volumetric flow rate
(refer to Equation 14-1) such that the
entrance velocity into each manifold nozzle
approximates the average effluent velocity in
the roof monitor. Measure the velocity of the
air entering each nozzle by inserting a
standard pitot tube into a 2.S cm or less
diameter hole (see Figure 14-2) located in the
manifold between each blast gate (or valve)
and nozzle. Note that a standard pitot tube is
used, rather than a type S, to eliminate
possible velocity measurement errors due to
cross-section blockage in the small (0.13 m
diameter) manifold leg ducts. The pitot tube
tip shall be positioned at the center of each
manifold leg duct. Take care to insure that
there is no leakage around the pitot tube,
which could affect the indicated velocity in
the manifold leg. If the velocity of air being
drawn into each nozzle is not the same, open
or dose each blast gate (or valve) until the
velocity in each nozzle is the same. Fasten
each blast gate (or valve) so that it will
remain in this position and close the pitot
port holes. This calibration shall be
performed when the manifold system is
installed. Alternatively, the manifou) may be
preassembled and the flow rates balanced on
the ground, before being installed.
4.2 Periodical performance checks.
Twelve months after their initial installation,
check the calibration of the propeller
anemometers, thermocouple-potentiometer
system, and the recorders and/or counters as
in Section 4.1. If the above systems pass the
performance checks, (i.e., if no repair or
replacement of any component is necessary),
continue with the performance checks on a
12-month interval basis. However, if any of
the above systems fail the performance
checks, repair or replace the system(s) that
failed and conduct the periodical
performance checks on a 3-mohth interval
basis, until sufficient information (consult
with the Administrator) is obtained to
establish a modified performance check
schedule and calculation procedure.
Note.If any of the above systems fafl the
initial performance checks, the data for the
past year need not be recalculated.
5. Procedure.
5.1 Roof Monitor Velocity Determination.
5.1.1 Velocity estimate(s) for setting
isokinetic flow. To assist in setting isokinetic
flow in the manifold sample nozzles, the
anticipated average velocity in the section of
the roof monitor containing the sampling
manifold shall be estimated prior to each test
run. The tester may use any convenient
means to make this estimate (e.g.. the
velocity indicated by the anemometer in the
section of the roof monitor containing the
sampling manifold may be continuously
monitored during the 24-hour period prior to
the test run).
If there is question as to whether a single
estimate of average velocity is adequate for
an entire test run (e.g., if velocities are
anticipated to be significantly different
during different potroom operations), the
tester may opt to divide the test run into two
or more "sub-runs," and to use a different
estimated average velocity for each sub-run
(see Section 5.3.2.2.)
5.1.2 Velocity determination during a test
run. During the actual test run, record the
velocity or volumetric flowrate readings of
each propeller anemometer in the roof
monitor. Readings shall be taken for each
anemometer every 15 minutes or at shorter
equal time intervals (or continuously).
S.2 Temperature recording. Record the
temperature of the roof monitor every 2 hours
during the test run.
5.3 Sampling.
5.3.1 Preliminary air flow in duct. During
24 hours preceding the jest, turn on the
exhaust fan and draw roof monitor air
through the manifold duct to condition the
ductwork. Adjust the fan to draw a
volumetric flow through the duct such that
the velocity of gas entering the manifold
nozzles approximates the average velocity of
the air exiting the roof monitor in the vicinity
of the sampling manifold.
5.3.2 Manifold isokinetic sample rate
adjustment(s).
5.3.2.1 Initial adjustment. Prior to the test
run (or first sub-run, if applicable: see Section
5.1.1 and 5.3.2.2), adjust the fan to provide the
necessary volumetric flowrate in the
sampling duct, so that air enters the manifold
sample nozzles at a velocity equal to the
appropriate estimated average velocity
determined under Section 5.1.1. Equation 14-1
gives the correct stream velocity needed in
the duct at the sampling location, in order for
sample gas to be drawn isokinetically into
the manifold nozzles. Next, verify that the
correct stream velocity has been achieved, by
performing a pitot tube traverse of the sample
duct (using either a standard or type S pitot
tube); use the procedure outlined in Method 2.
6(0.)'
(Equation 14-1)
-------
6.1.4.1 If v, is less than or equal to 120
percent of vd, the results are acceptable (note
that in cases where the above calculations
have been performed for each sub-run, the
results are acceptable if the average
percentage for all sub-runs is less than or
equal to 120 percent).
6.1.4.2 If v. is more than 120 percent of vd,
multiply the reported emission rate by the
following factor.
(100v,/va) 120
200
6.2 Average velocity of roof monitor
gases. Calculate the average roof monitor
velocity using all the velocity or volumetric
flow readings from Section 5.1.2.
6.3 Roof monitor temperature. Calculate
the mean value of the temperatures recorded
in Section 5.2.
6.4 Concentration of fluorides in roof
monitor air (in mg F/m3).
6.4.1 If a single sampling train was used
throughout the run. calculate the average
fluoride concentration for the roof monitor
using Equation 13A-2 of Method 13A.
6.4.2 If two or more sampling trains were
used (i.e., one per sub-run), calculate the
average fluoride concentration for the run, as
follows:
1-1
(Equation 14-2)
Where:
C,=Average fluoride concentration in roof
monitor air, mg F/dscm.
F, = Total fluoride mass collected during a
particular sub-run, mg F (from Equation
13A-1 of Method 13A or Equation 13B-1
of Method 13B).
Vm(8id)=Total volume of sample gas
passing through the dry gas meter during
a particular sub-run, dscm (see Equation
5-1 of Method 5).
n = Total number of sub-runs.
6.5 Average volumetric flow from the roof
monitor of the potroom(s) (or potroom
segment(s)) containing the anemometers is
given in Equation 14-3.
vm(A) (Md) P,,,(293 K)
Q., - ~-- - (Equation 14-3)
(!, + 273 ) (760 mm Hg)
Where:
Qm = Average volumetric flow from roof
monitor at standard conditions on a dry
basis, m3/mm.
A = Roof monitor open area. m-.
vml = Average velocity of air in the roof
monitor, m/mm. from Section 6.2.
Pm = Pressure in the roof monitor; equal to
barometric pressure for this application,
mm Hg.
Tm = Roof monitor temperature, °C. from
Section 6.3.
M,i = Mole fraction of dry gas. which is
given by:
M.-11 B.J
Note.B». is the proportion by volume of
water vapor in the gas stream, from Equation
5-3, Method 5.
7. Bibliography.
1. Shigehara. R. T., A guideline for
Evaluating Compliance Test Results
(Isokinetic Sampling Rate Criterion). U.S.
Environmental Protection Agency. Emission
Measurement Branch. Research Triangle
Park. North Carolina. August 1977.
Ill-Appendix A-56c
-------
Ill-Appendix A-56d
-------
METHOD IS. DETERMINATION OF HYDROGEN
SULFIDE. CARBONYL SULFIDE, AND CARBON
DISULFIDE EMISSIONS PROM STATIONARY
SOURCES 86
INTRODUCTION
The method described below uses the
principle of gas chromatographic separation
and flame photometric detection (FPD).
Since there are many systems or sets of op-
erating conditions that represent usable
methods of determining sulfur emissions, all
systems which employ this principle, but
differ only in details of equipment and oper-
ation, may be used as alternative methods,
provided that the criteria set below are met.
1. Principle and applicability
1.1 Principle. A gas sample is extracted
from the emission source and diluted with
clean dry air. An aliquot of the diluted
sample is then analyzed for hydrogen sul-
fide (H,S>. carbonyl sulfide (COS), and
carbon disulfide (CS,) by gas chromatogra-
phic (GO separation and flame photomet-
ric detection (PPD).
1.2 Applicability. This method is applica-
ble for determination of the above sulfur
compounds from tail gas control units of
sulfur recovery plants.
2. Range ana sensitivity
2.1 Range. Coupled with a gas chromto-
graphic system utilizing a 1-milliliter sample
size, the maximum limit of the FPD for
each sulfur compound is approximately 10
ppm. It may be necessary to dilute gas sam-
ples from sulfur recovery plants hundred-
fold (99:1) resulting in an upper limit of
about 1000 ppm for each compound.
2.2 The minimum detectable concentra-
tion of the FPD is also dependent on sample
size and would be about 0.5 ppm for a 1 ml
sample.
3. Interferences
3.1 Moisture Condensation. Moisture con-
densation in the sample delivery system, the
analytical column, or the FPD burner block
can cause losses or interferences. This po-
tential is eliminated by heating the sample
line, and by conditioning the sample with
dry dilution air to lower its dew point below
the operating temperature of the OC/FPD
analytical system prior to analysis.
3.2 Carboft Monoxide and Carbon Dioxide.
CO and CO, have substantial desensitizing
effects on the flame photometric detector
even after 9:1 dilution. (Acceptable systems
must demonstrate that they have eliminat-
ed this interference by some procedure such
as eluding CO and CO, before any of the
sulfur compounds to be measured.) Compli-
ance with this requirement can be demon-
strated by submitting chromatograms of
calibration gases with and without CO, in
the diluent gas. The CO, level should be ap-
proximately 10 percent for the case with
CO, present. The two chromatographs
should show agreement within the precision
limits of, section 4.1.
3 3 Elemental Sulfur. The condensation of
sulfur vapor in the sampling line can lead to
eventual coating and even blockage of the
sample line. This problem can be eliminated
along with the moisture problem by heating
the sample line.
4. Precision
4.1 Calibration Precision. A series of three
consecutive injections of the same calibra-
tion gas, at any dilution, shall produce re-
sults which do not vary by more than ±13
percent from the mean of the three injec-
tions.
4.2 Calibration Drift. The calibration drift
determined from the mean of three injec-
tions made at the beginning and end of any
8-hour period shall not exceed ±5 percent.
5. Apparatus
5.1.1 Probe. The probe must be made of
inert material such as stainless steel or
glass. It should be designed to incorporate a
filter and to allow calibration gas to enter
the probe at or near the sample entry point.
Any portion of the probe not exposed to the
stack gas must be heated to prevent mois-
ture condensation.
5.1.2 The sample line must be made of
Teflon,' no greater than 1.3 cm (Vz In) inside
diameter. All parts from the probe to the di-
lution system must be thermostatically
heated to 120° C.
5.1.3 Sample Pump. The sample pump
shall be a leakless Teflon coated diaphragm
type or equivalent. If the pump is upstream
of the dilution system, the pump head must
be heated to 120* C.
5.2 Dilution System. The dilution system
must be constructed such that all sample
contacts are made of inert material (e.g.
stainless steel or Teflon). It must be heated
to 120° C and be capable of approximately a
8:1 dilution of the sample.
5.3 Gas Chromatograph. The gas chroma-
tograph must have at least the following
components:
5.3.1 Oven. Capable of maintaining the
separation column at the proper operating
temperature ±1' C.
5.3.2 Temperature Gauge. To monitor
column oven, detector, and exhaust tem-
perature ±rc.
5.3.3 Flow System. Gas metering system to
measure sample, fuel, combustion gas, and
carrier gas flows.
5.3.4 Flame Photometric Detector.
5.3.4.1 Electrometer. Capable of full scale
amplification of linear ranges of 10""to 10"
amperes full scale.
5.3.4.2 Power Supply. Capable of deliver-
ing up to 750 volts.
5.3.4.3 Recorder. Compatible with the
output voltage range of the electrometer.
5.4 Gas Chromatograph Columns. The
column system must be demonstrated to be
capable of resolving three major reduced
sulfur compounds: H,S. COS. and CS,.
To demonstrate that adequate resolution
has been achieved the tester must submit a
Chromatograph of a calibration gas contain-
ing all three reduced sulfur compounds In
the concentration range of the applicable
standard. Adequate resolution will be de-
fined as base line separation of adjacent
peaks when the amplifier attenuation is set
so that the smaller peak is at least 50 per-
cent of full scale. Base line separation is de-
fined as a return to zero ±5 percent in the
interval between peaks. Systems not meet-
Ing this criteria may be considered alternate
methods subject to the approval of the Ad-
ministrator.
5.5.1 Calibration System. The calibration
system must contain the following compo-
nents.
5.5.2 Flow System. To measure air flow
over permeation tubes at ±2 percent. Each
flowmeter shall be calibrated after a com-
plete test series with a wet test meter. If the
flow measuring device differs from the wet
test meter by 5 percent, the completed test
shall be discarded. Alternatively, the tester
may elect to use the flow data that would
yield the lowest flow measurement. Calibra-
tion with a wet test meter before a test is
optional.
'Mention of trade names or specific prod-
ucts does not constitute an endorsement by
the Environmental Protection Agency.
5.5.3 Constant Temperature Bath. Device
capable of maintaining the permeation
tubes at the calibration temperature within
±1.1° C.
5.5.4 Temperature Gauge. Thermometer
or equivalent to monitor bath temperature
within ±1' C.
6. Reagents
6.1 Fuel. Hydrogen (Hi) prepurified grade
or better.
6.2 Combustion Gas. Oxygen (O,) or air,
research purity or better.
6.3 Carrier Gas. Prepurified grade or
better.
6.4 Diluent. Air containing less than 0.6
ppm total sulfur compounds and less than
10 ppm each of moisture and total hydro-
carbons.
6.5 Calibration Gases. Permeation tubes,
one each of H>S, COS, and CS,, gravimetri-
cally calibrated and certified at some conve-
nient operating temperature. These tubes
consist of hermetically sealed FEP Teflon
tubing in which a liquified gaseous sub-
stance is enclosed. The enclosed gas perme-
ates through the tubing wall at a constant
rate. When the temperature is constant,
calibration gases covering a wide range of
known concentrations can be generated by
varying and accurately measuring the flow
rate of diluent gas passing over the tubes.
These calibration gases are used to calibrate
the GC/FPD system and the dilution
system.
7. Pretest Procedures
The following procedures are optional but
would be helpful in preventing any problem
which might occur later and Invalidate the
entire test.
7.1 After the complete measurement
system has been set up at the site and
deemed to be operational, the following pro-
cedures should be completed before sam-
pling is initiated.
7.1.1 Leak Test. Appropriate leak test pro-
cedures should be employed to verify the in-
tegrity of all components, sample lines, and
connections. The following leak test proce-
dure is suggested: For components upstream
of the sample pump, attach the probe end
of the sample line to a manometer or
vacuum gauge, start the pump and pull
greater than 50 mm (2 in.) Hg vacuum, close
off the pump outlet, and then stop the
pump and ascertain that there is no leak for
1 minute. For components after the pump,
apply a slight positive pressure and check
for leaks by applying a liquid (detergent in
water, for example) at each joint. Bubbling
indicates the presence of a leak.
7.1.2 System Performance. Since the com-
plete system is calibrated following each
test, the precise calibration of each compo-
nent is not critical. However, these compo-
nents should be verified to be operating
properly. This verification can be performed
by observing the response of flowmeters or
of the GC output to changes in flow rates or
calibration gas concentrations and ascer-
taining the response to be within predicted
limits. If any component or the complete
system fails to respond in a normal and pre-
dictable manner, the source of the discrep-
ancy should be identifed and corrected
before proceeding.
8. Calibration
Prior to any sampling run, calibrate the
system using the following procedures. (If
more than one run is performed during any
24-hour period, a calibration need not be
performed prior to the second and any sub-
sequent runs. The calibration must, howev-
er, be verified as prescribed in section 10,
after the last run made within the 24-hour
Ill-Appendix A-57
-------
period.)
8.1 General Considerations. This section
outlines steps to be followed tor use of the
OC/FPD and the dilution system. The pro-
cedure does not include detailed instruc-
tions because the operation of these systems
is complex, and it requires an understanding
of the individual system being used. Each
system should include a written operating
manual describing in detail the operating
procedures associated with each component
in the measurement system. In addition, the
operator shuld be familiar with the operat-
ing principles of the components; particular-
ly the OC/PPD. The citations in the Bib-
liography at the end of this method are rec-
ommended for review for this purpose.
8.2 Calibration Procedure. Insert the per-
meation tubes into the tube chamber. Check
the bath temperature to assure agreement
with the calibration temperature of the
tubes within ±O.TC. Allow 24 hours for the
tubes to equilibrate. Alternatively equilibra-
tion may be verified by injecting samples of
calibration gas at 1-hour intervals. The per-
meation tubes can be assumed to have
reached equilibrium when consecutive
hourly samples agree within the precision
limits of section 4.1.
Vary the amount of air flowing over the
tubes to produce the desired concentrations
for calibrating the analytical and dilution
systems. The air flow across the tubes must
at all times exceed the flow requirement of
the analytical systems. The concentration in
parts per million generated by a bube con-
taining a specific pel-meant can be calculat-
ed as follows:
Equation 15-1
where:
C= Concentration of permeant produced
in ppm.
P,= Permeation rate of the tube in us/
min.
M=Molecular weight of the permeant: g/
g-mole.
L=Plow rate, 1/min, of air over permeant
@ 20°C, 760 mm Hg.
K = Gas constant at 20*C and 760 mm
Hg = 24.04 1/g mole.
8.3 Calibration of analysis system. Gener-
ate a series of three or more known concen-
trations spanning the linear range of the
PPD (approximately 0.05 to 1.0 ppm) for
each of the four major sulfur compounds.
Bypassing the dilution system, inject these
standards in to the GC/FPD analyzers and
monitor the responses. Three injects for
each concentration must yield the precision
described in section 4.1. Failure to attain
this precision is an indication of a problem
in the calibration or analytical system. Any
such problem must be identified and cor-
rected before proceeding.
8.4 Calibration Curves. Plot the GC/FPD
response in current (amperes) versus their
causative concentrations in ppm on log-log
coordinate graph paper for each sulfur com-
pound. Alternatively, a least squares equa-
tion may be generated from the calibration
data.
8.5 Calibration of Dilution System. Gener-
ate a know concentration of hydrogen sul-
fied using the permeation tube system.
Adjust the flow rate of diluent air for the
first dilution stage so that the desired level
of dilution is approximated. Inject the dilut-
ed calibration gas into the GC/FPD system
and monitor its response. Three Injections
for each dilution must yield the precision
described in section 4.1. Failure to attain
this precision in this step is an indication of
a problem in the dilution system. Any such
problem must be identified and corrected
before proceeding. Using the calibration
data for H.S (developed under 8.3) deter-
mine the diluted calibration gas concentra-
tion in ppm. Then calculate the dilution
factor as the ratio of the calibration gas
concentration before dilution to the diluted
calibration gas concentration determined
under this paragraph. Repeat this proce-
dure for each stage of dilution required. Al-
ternatively, the OC/FPD system may be
calibrated by generating a series of three or
more concentrations of each sulfur com-
pound and diluting these samples before in-
jecting them into the GC/FPD system. This
data will then serve as the calibration data
for the unknown samples and a separate de-
termination of the dilution factor will not
be necessary. However, the precision re-
quirements of section 4.1 are still applicable.
9. Sampling and Analysis Procedure
9.1 Sampling. Insert the sampling probe
into the test port making certain that no di-
lution air enters the stack through the port.
Begin sampling and dilute the sample ap-
proximately 9:1 using the dilution system.
Note that the precise dilution factor is that
which is determined in paragraph 8.5. Con-
dition the entire system with sample for a
minimum of 15 minutes prior to commenc-
ing analysis.
9.2 Analysis. Aliquots of diluted sample
are injected into the GC/FPD analyzer for
analysis.
8.2.1 Sample Run. A sample run is com-
posed of 16 individual analyses (injects) per-
formed over a period of not less than 3
hours or more than 6 hours.
9.2.2 Observation for Clogging of Probe. If
reductions in sample concentrations are ob-
served during a sample run that cannot be
explained by process conditions, the sam-
pling must be Interrupted to determine if
the sample probe is clogged with particulate
matter. If the probe is found to be clogged.
the test must be stopped and the results up
to that point discarded. Testing may resume
after cleaning the probe or replacing It with
a clean one. After each run, the sample
probe must be inspected and, if necessary.
dismantled and cleaned.
10. Post-Test Procedures
10.1 Sample Line Loss. A known concen-
tration of hydrogen sulfide at the level of
the applicable standard, ±20 percent, must
be introduced into the sampling system at
the opening of the probe in sufficient quan-
tities to ensure that there is an excess of
sample which must be vented to the atmo-
sphere. The sample must be transported
through the entire sampling system to the
measurement system in the normal manner.
The resulting measured concentration
should be compared to the known value to
determine the sampling system loss. A sam-
pling system loss of more than 20 percent Is
unacceptable. Sampling losses of 0-20 per-
cent must be corrected by dividing the re-
sulting sample concentration by the frac-
tion of recovery. The known gas sample may
be generated using permeation tubes. Alter-
natively, cylinders of hydrogen sulfide
mixed in air may be used provided they are
traceable to permeation tubes. The optional
pretest procedures provide a good guideline
for determining if there are leaks in the
sampling system.
10.2 Recallbration. After each run, or
after a series of runs made within a 24-hour
period, perform a partial recallbratlon using
the procedures in section 8. Only H»S (or
other permeant) need be used to recalibrate
the GC/FPD analysis system (8.3) and the
dilution system (8.5).
10.3 Determination of Calibration Drift.
Compare the calibration curves obtained
prior to the runs, to the calibration curves
obtained under paragraph 10.1. The calibra-
tion drift should not exceed the limits set
forth in paragraph 4.2. If the drift exceeds
this limit, the intervening run or runs
should be considered not valid. The tester,
however, may instead have the option of
choosing the calibration data set which
would give the highest sample values.
11. Calculations
11.1 Determine the concentrations of each
reduced sulfur compound detected directly
from the calibration curves. Alternatively,
the concentrations may be calculated using
the equation for the least squares line.
11.2 Calculation of SO, Equivalent. SO,
equivalent will be determined for each anal-
ysis made by summing the concentrations of
each reduced sulfur compound resolved
during the given analysis.
SO, equivalent = I(H,S. COS, 2 CS,)d
Equation 15-2
where:
SO, equivalent=The sum of the concen-
tration of each of the measured com-
pounds (COS, H.S, CS,) expressed as
sulfur dioxide in ppm.
H.S=Hydrogen sulfide, ppm.
COS = Carbonyl sulfide, ppm.
CS,=Carbon disulfide, ppm.
d=Dilution factor, dimensionless.
11.3 Average SO, equivalent will be deter-
mined as follows:
Aver
N
I S02 equtv.j
age SO, equivalent * 1 = 1
N (1 - Bwo)
Equation 15-3
where:
Average SO, equivalent,«Average SO,
equivalent in ppm, dry basis.
Average SO, equivalent,=SO, in ppm as
determined by Equation 15-2.
N = Number of analyses performed.
Bwo = Fraction of volume of water vapor
in the gas stream as determined by
Method 4Determination of Moisture
in Stack Gases (36 FR 24887).
12. Example System
Described below is a system utilized by
EPA in gathering NSPS data. This system
does not now reflect all the latest develop-
ments in equipment and column technology,
but it does represent one system that has
been demonstrated to work.
12.1 Apparatus.
12.1.1 Sample System.
12.1.1.1 Probe. Stainless steel tubing, 6.35
mm (V, hi.) outside diameter, packed with
glass wool.
12.1.1.2 Sample Line. VK inch Inside diam-
eter Teflon tubing heated to 120*C. This
temperature is controlled by a thermostatic
heater.
12.1.1.3 Sample Pump. Leakless Teflon
coated diaphragm type or equivalent. The
pump head is heated to 120* C by enclosing
it in the sample dilution box (12.2.4 below).
12.1.2 Dilution System. A schematic dia-
gram of the dynamic dilution system Is
given in Figure 15-2. The dilution system is
constructed such that all sample contacts
are made of inert materials. The dilution
Ill-Appendix A-58
-------
system which is heated to 120* C must be ca-
pable of a minimum of 9:1 dilution of
sample. Equipment used in the dilution
system is listed below:
12.1.2.1 Dilution Pump. Model A-150 Koh-
myhr Teflon positive displacement type.
nonadjustable ISO cc/mln. ±2.0 percent, or
equivalent, per dilution stage. A 9:1 dilution
of sample is accomplished by combining ISO
cc of sample with 1350 cc of clean dry air as
shown in Figure 15-2.
12.1.2.2 Valves. Three-way Teflon solenoid
or manual type.
12.1.2.3 Tubing. Teflon tubing and fittings
are used throughout from the sample probe
to the OC/FPD to present an inert surface
for sample gas.
12.1.2.4 Box. Insulated box, heated and
maintained at 120* C, of sufficient dimen-
sions to house dilution apparatus.
12.1.2.6 Flowmeters. Rotameters or equiv-
alent to measure flow from 0 to 1500 ml/
mln. ±1 percent per dilution stage.
12.1.3.0 Gas Chromatograph.
12.1.3.1 Column-1.83 m (6 ft.) length of
Teflon tubing, 2.16 mm (0.085 in.) Inside di-
ameter, packed with deactivated silica gel,
or equivalent.
12.1.3.2 Sample Valve. Teflon six port gas
sampling valve, equipped with a 1 ml sample
loop, actuated by compressed air (Figure 15-
1).
12.1.3.3 Oven. For containing sample
valve, stripper column and separation
column. The oven should be capable of
maintaining an elevated temperature rang-
ing from ambient to 100* C, constant within
±1*C.
12.1.3.4 Temperature Monitor. Thermo-
couple pyrometer to measure column oven.
detector, and exhaust temperature ±1' C.
12.1.3.5 Flow System. Gas metering
system to measure sample flow, hydrogen
flow, oxygen flow and nitrogen carrier gas
flow.
12.1.3.6 Detector. Flame photometric de-
tector.
12.1.3.7 Electrometer. Capable of full scale
amplification of linear ranges of 10"* to 10 '
amperes full scale.
12.1.3.8 Power Supply. Capable of deliver-
ing up to 750 volts.
12.1.3.9 Recorder. Compatible with the
output voltage range of the electrometer.
12.1.4 Calibration. Permeation tube
system (Figure 15-3).
12.1.4.1 Tube Chamber. Glass chamber of
sufficient dimensions to house permeation
tubes.
12.1.4.2 Mass Flowmeters. Two mass flow-
meters in the range 0-3 1/min. and 0-10 I/
min. to measure air flow over permeation
tubes at ±2 percent. These flowmeters shall
be cross-calibrated at the beginning of each
test. Using a convenient flow rate in the
measuring range of both flowmeters, set
and monitor the flow rate of gas over the
permeation tubes. Injection of calibration
gas generated at this flow rate as measured
by one flowmeter followed by injection of
calibration gas at the same flow rate as mea-
sured by the other flowmeter should agree
within the specified precision limits. If they
do not, then there is a problem with the
mass flow measurement. Each mass flow-
meter shall be calibrated prior to the first
test with a wet test meter and thereafter at
least once each year.
12.1.4.3 Constant Temperature Bath. Ca-
pable of maintaining permeation tubes at
certification temperature of 30' C within
±0.1'C.
12.2 Reagents.
12.2.1 Fuel. Hydrogen (H,> prepurifled
trade or better.
12.2.2 Combustion Gas. Oxygen (O.) re-
search purity or better.
12.2.3 Carrier Gas. Nitrogen (N,) prepuri-
f led grade or better.
12,2.4 Diluent. Air containing less than 0.5
ppm total sulfur compounds and less than
10 ppm each of moisture and total hydro-
carbons, and filtered using MSA filters
46727 and 79030, or equivalent. Removal of
sulfur compounds can be verified by inject-
ing dilution air only, described in section
8.3.
12.2.S Compressed Air. 60 psig for GC
valve actuation.
12.2.6 Calibration Gases. Permeation
tubes gravimetrically calibrated and certi-
fied at 30.0' C.
12.3 Operating Parameters. The operating
parameters for the OC/FPD system are as
follows: nitrogen carrier gas flow rate of 100
cc/mln, exhaust temperature of 110* C, de-
tector temperature 105* C, oven tempera-
ture of 40* C, hydrogen flow rate of 80 cc/
minute, oxygen flow rate of 20 cc/mlnute.
and sample flow rate of 80 cc/mlnute.
12.4 Analysis. The sample valve is actu-
ated for 1 minute in which time an aliquot
of diluted sample is Injected onto the sepa-
ration column. The valve is then deactivated
for the remainder of analysis cycle in which
time the sample loop is refilled and the sep-
aration column continues to be foreflushed.
The elution time for each compound will be
determined during calibration.
13. Bibliography
13.1 O'Keeffe. A. E. and G. C. Ortman,
"Primary Standards for Trace Gas Analy-
sis." Anal. Chem. 38.760 (1966).
13.2 Stevens, R. K., A. E. O'Keeffe, and
G. C. Ortman. "Absolute Calibration of a
Flame Photometric Detector to Volatlie
Sulfur Compounds at Sub-Part-Per-Million
Levels." Environmental Science and Tech-
nology 3:7 (July, 1969).
13.3 Mulick, J. D., R. K. Stevens, and R.
Baumgardner. "An Analytical System De-
signed to Measure Multiple Malodorous
Compounds Related to Kraft Mill Activi-
ties." Presented at the 12tft Conference on
Methods in Air Pollution and Industrial Hy-
giene Studies, University of Southern Cali-
fornia, Los Angeles, Calif. April 6-8, 1971.
13.4 Devonald, R. H., R. S. Serenius, and
A. D. Mclntyre. "Evaluation of the Flame
Photometric Detector for Analysis of Sulfur
Compounds." Pulp and Paper Magazine of
Canada. 73,3 (March, 1972).
13.5 Grimley, K. W., W. S. Smith, and
R. M. Martin. "The Use of a Dynamic Dilu-
tion System in the Conditioning of Strfck
Gases for Automated Analysis by a Mobile
Sampling Van " Presented at the 63rd
Annual APCA Meeting in St. LOUJS, Mo.
June 14-19, 1970.
13.6 General Reference. Standard Meth-
ods of Chemical Analysis Volume III A and
B Instrumental Methods. Sixth Edition.
Van Nostrand Reinhold Co.
Ill-Appendix A-59
-------
METHOD 16. SEMICONTINTJOUS DETERMINATION
OF SULFUR (MISSIONS PROM STATIONARY
SOURCES 82
Introduction
The method described below uses the
principle of gas chromatographic separation
and hame photometric detection. Since
there are many systems or sets of operating
conditions that represent usable methods of
determining sulfur emissions, all systems
which employ this principle, but differ only
in details of equipment and operation, may
be used as alternative methods, provided
that the criteria set below are met.
1. Principle and Applicability.
1.1 Principle. A gas sample is extracted
from the emission source and diluted with
clean dry air. An aliquot of the diluted
sample is then analyzed for hydrogen sul-
fide (H.S), methyl mercaptan (MeSH), di-
methyl sulfide (DMS) and dimethyl disul-
fide (DMDS) by gas chromatographic (GO
separation and flame photometric detection
(FPD). These four compounds are known
collectively as total reduced sulfur (TRS).
1.2 Applicability. This method is applica-
ble for determination of TRS compounds
from recovery furnaces, lime kilns, and
smelt dissolving tanks at kraft pulp mills.
2. Range and Sensitivity.
2.1 Range. Coupled with a gas chromato-
graphic system utilizing a ten milliliter
sample size, the maximum limit of the PPD
for each sulfur compound is approximately
1 ppm. This limit is expanded by dilution of
the sample gas before analysis. Kraft mill
gas samples are normally diluted tenfold
(9:1), resulting in an upper limit of about 10
ppm for each compound.
For sources with emission levels between
10 and 100 ppm, the measuring range can be
best extended by reducing the sample size
to 1 milliliter.
2.2 Using the sample size, the minimum
detectable concentration is approximately
50 ppb.
3. Interferences.
3.1 Moisture Condensation. Moisture
condensation in the sample delivery system,
the analytical column, or the PPD burner
block can cause losses or interferences. This
potential is eliminated by heating the
sample line, and by conditioning the sample
with dry dilution air to lower its dew point
below the operating temperature of the
OC/FPD analytical system prior to analysis.
3.2 Carbon Monoxide and Carbon Diox-
ide. CO and CO, have substantial desensitiz-
ing effect on the flame photometric detec-
tor even after 9:1 dilution. Acceptable sys-
tems must demonstrate that they have
eliminated this interference by some proce-
dure such as eluting these compounds
before any of the compounds to be mea-
sured. Compliance with this requirement
can be demonstrated by submitting chroma-
tograms of calibration gases with and with-
out COi in the diluent gas. The CO, level
should be approximately 10 percent for the
case with CO, present. The two chromato-
graphs should show agreement within the
precision limits of Section 4.1.
3.3 Particulate Matter. Particulate
matter in gas samples can cause interfer-
ence by eventual clogging of the analytical
system. This interference must be eliminat-
ed by use of a probe filter.
3.4 Sulfur Dioxide. SO, is not a specific
interferent but may be present in such large
amounts that it cannot be effectively sepa-
rated from other compounds of interest.
The procedure must be designed to elimi-
nate this problem either by the choice of
separation columns or by removal of SO,
from the sample. In the example
system, SO2 is removed by a citrate
buffer solution prior to GC injection.
This scrubber will be used when SOZ
levels are high enough to prevent
baseline separation from the reduced
sulfur compounds. 93
Compliance with this section can be dem-
onstrated by submitting chromatographs of
calibration gases with SO, present in the
same quantities expected from the emission
source to be tested. Acceptable systems
shall show baseline separation with the am-
plifier attenuation set so that the reduced
sulfur compound of concern Is at least 50
percent of full scale. Base line separation Is
defined as a return to zero ± percent In the
interval between peaks.
4. Precision and Accuracy.
4.1 OC/PPD and Dilution System Cali-
bration Precision. A series of three consecu-
tive injections of the same calibration gas,
at any dilution, shall produce results which
do not vary by more than ± 5 percent from
the mean of the three injections.9 3
4.2 GC/FPD and Dilution System Cali-
bration Drift. The calibration drift deter-
mined from the mean of three injections
made at the beginning and end of any 8-
hour period shall not exceed ± percent.
4.3 System Calibration Accuracy.
Losses through the sample transport
system must be measured and a cor-
rection factor developed to adjust the
calibration accuracy to 100 percent.93
5. Apparatus (See Figure 16-1).
5.1. Sampling. 93
5.1.1 Probe. The probe must be made of
Inert material such as stainless steel or
glass. It should be designed to Incorporate a
filter and to allow calibration gas to enter
the probe at or near the sample entry point.
Any portion of the probe not exposed to the
stack gas must be heated to prevent mois-
ture condensation.
5.1,2 Sample Line. The sample line must
be made of Teflon,1 no greater than 1.3 cm
(V4) Inside diameter. All parts from the
probe to the dilution system must be ther-
mostatically heated to 120' C.
5.1.3 Sample Pump. The sample pump
shall be a leakless Tenon-coated diaphragm
type or equivalent. If the pump is upstream
of the dilution system, the pump head must
be heated to 120° C.
5.2 Dilution System. The dilution system
must be constructed such that all sample
contacts are made of inert materials (e.g.,
stainless steel or Tenon). It must be heated
to 120* C. and be capable of approximately a
9:1 dilution of the sample.
5.3 SO, Scrubber. The
SOj scrubber is a midget impinger
packed with glass wool to eliminate
entrained mist and charged with po-
tassium citrate-citric acid buffer.93
5.4 Gas Chromatograph. The gas chro-
matograph must have at least the following
components: '3
5.4.1 Oven. Capable of maintaining the
separation column at the proper operating
temperature ±1' C.93
5.4.2 Temperature Gauge. To monitor
column oven, detector, and exhaust tem-
perature ±1" C.93
5.4.3 Flow System. Gas metering system
to measure sample, fuel, combustion gas,
and carrier gas flows. 93
1 Mention of trade names or specific-prod-
ucts does not constitute endorsement by the
Environmental Protection Agency.
5.4.4 Flame Photometric Detector. 93
5.4.4.1 Electrometer. Capable of full scale
amplification of linear ranges of 10-» to 10~«
wnperes full scale. 93
6.4.4.2 Power Supply. Capable of deliver-
ing up to 750 volts. 93
5.4.4.3 Recorder. Compatible with the
output voltage range of the electrometer. 9 3
5.5 Gas Chromatograph Columns. The
column system must be demonstrated to be
capble of resolving the four major reduced
sulfur compounds: H.S, MeSH, DMS, and
DMDS. It must also demonstrate freedom
from known Interferences.93
To demonstrate that adequate resolution
has been achieved, the tester must submit a
Chromatograph of a calibration gas contain-
ing all four of the TRS compounds In the
concentration range of the applicable stan-
dard. Adequate resolution will be defined as
base line separation of adjacent peaks when
the amplifier attenuation is set so that the
smaller peak Is at least 50 percent of full
scale. Base line separation Is defined In Sec-
tion 3.4. Systems not meeting this criteria
may be considered alternate methods sub-
ject to the approval of the Administrator. 93
5.5.1 Calibration System. The calibration
system must contain the following compo-
nents. 93
5.5.2 Tube Chamber. Chamber of glass or
Teflon of sufficient dimensions to house
permeation tubes. 93
,5.5.3 Flow System. To measure air flow
over permeation tubes at ±2 percent. Each
flowmeter shall be calibrated after a com-
plete test series with a wet test meter. If the
flow measuring device differs from the wet
test meter by 5 percent, the completed test
shall be discarded. Alternatively, the tester
may elect to use the flow data that would
yield the lower flow measurement. Calibra-
tion with a wet test meter before a test is
optional. 93
5.5.4 Constant Temperature Bath. Device
capable of maintaining the permeation
tubes at the calibration temperature within
±0.1° C.93
5.5.5 Temperature Gauge. Thermometer
or equivalent to monitor bath temperature
within ±1'C. 93
6. Reagents.
6.1 Fuel. Hydrogen (H.) prepurlfled
grade or better.
6.2 Combustion Gas. Oxygen (O>) or air,
research purity or better.
6.3 Carrier Gas. Prepurlfied grade or
better.
6.4 Diluent. Air containing less than 50
ppb total sulfur compounds and less than 10
ppm each of moisture and total hydrocar-
bons. This gas must be heated prior to
mixing with the sample to avoid water con-
densation at the point of contact.
6.5 Calibration Gases. Permeation tubes,
one each of H»S, MeSH, DMS, and DMDS,
agravimetrically calibrated and certified at
some convenient operating temperature.
These tubes consist of hermetically sealed
FEP Teflon tubing in which a liquified gas-
eous substance is enclosed. The enclosed gas
permeates through the tubing wall at a con-
stant rate. When the temperature is con-
stant, calibration gases Governing a wide
range of known concentrations can be gen-
erated by varying and accurately measuring
the flow rate of diluent gas passing over the
tubes. These calibration gases are used to
calibrate the GC/FPD system and the dilu-
tion system.
6.6 Citrate Buffer. Dis-
solve 300 grams ol potassium citrate
and 41 grams of anhydrous citric acid
in 1 liter of deionized water. 284 grams
of sodium citrate may be substituted
for the potassium citrate. 93
III-Appendix A-60
-------
7. Pretett Procedure*. The following proce-
dures are optional but would be helpful in
preventing any problem which might occur
later and Invalidate the entire test.
7.1 After the complete measurement
system has been set up at the site and
deemed to be operational, the following pro-
cedures should be completed before sam-
pling is initiated.
7.1.1 Leak Test. Appropriate leak test
procedures should be employed to verify the
integrity of all components, sample lines,
and connections. The following leak test
procedure is suggested: For components up-
stream of the sample pump, attach the
probe end of the sample line to a ma- no-
meter or vacuum gauge, start the pump and
pull greater than SO mm (2 in.) Hg vacuum,
close off the pump outlet, and then stop the
pump and ascertain that there is no leak for
1 minute. For components after the pump,
apply a slight positive pressure and check
for leaks by applying a liquid (detergent in
water, for example) at each joint Bubbling
indicates the presence of a leak.
7.1.2 System Performance. Since the
complete system is calibrated following each
test, the precise calibration of each compo-
nent Is not critical. However, these compo-
nents should be verified to be operating
properly. This verification can be performed
by observing the response of flowmeters or
of the OC output to changes in flow rates or
calibration gas concentrations and ascer-
taining the response to be within predicted
limits. In any component, or if the complete
system fails to respond in a normal and pre-
dictable manner, the source of the discrep-
ancy should be identified and corrected
before proceeding.
8. Calibration. Prior to any sampling run,
calibrate the system using the following
procedures. (If more than one run is per-
formed during-any 24-hour period, a calibra-
tion need not be performed prior to the
second and any subsequent runs. The cali-
bration must, however, be verified as pre-
scribed in Section 10, after the last run
made within the 24-hour period.)
8.1 General Considerations. This section
outlines steps to be followed for use of the
OC/PPD and the dilution system. The pro-
cedure does not include detailed instruc-
tions because the operation of these systems
is complex, and it requires a understanding
of the individual system being used. Each
system should include a written operating
manual describing in detail the operating
procedures associated with each component
in the measurement system. In addition, the
operator should be familiar with the operat-
ing principles of the components; particular-
ly the OC/PPD. The citations In the Bib-
liography at the end of this method are rec-
ommended for review for this purpose.
8.2 Calibration Procedure. Insert the per-
meation tubes into the tube chamber.
Check the bath temperature to assure
agreement with the calibration temperature
of the tubes within ±0.1* C. Allow 24 hours
for the tubes to equilibrate. Alternatively
equilibration may be verified by Injecting
samples of calibration gas at 1-hour inter-
vals. The permeation tubes can be assumed
to have reached equilibrium when consecu-
tive hourly samples agree within the preci-
sion limits of Section 4.1.
Vary the amount of air flowing over the
tubes to produce the desired concentrations
for calibrating the analytical and dilution
systems. The air flow across the tubes must
at all times exceed the flow requirement of
the analytical systems. The concentration in
parts per million generated by a tube con-
taining a specific permeant can be calculat-
ed as follows: p
Hi
Equation 16-1
where:
C= Concentration of permeant produced in
ppm.
Pr-Permeation rate of the tube In jig/min.
M- Molecular weight of the permeant (g/g-
mole).
L-Flow rate, 1/min, of air over permeant @
30' C, 760 mm Hg.
K=Gas constant at 20* C and 760 mm
Hg=24.04 1/gmole.
8.3 Calibration of analysis system. Gen-
erate a series of three or more known con-
centrations spanning the linear range of the
FPD (approximately 0.05 to 1.0 ppm) for
each of the four major sulfur compounds.
Bypassing the dilution system, but using
the SO, scrubber, inject these
standards into the GC/FPD analyzers and
monitor the responses. Three injects for
each concentration must yield the precision
described in Section 4.1. Failure to attain
this precision Is an indication of a problem
in the calibration or analytical system. Any
such problem must be identified and cor-
rected before proceeding.93
8.4 Calibration Curves. Plot the GC/FPD
response in current (amperes) versus their
causative concentrations in ppm on log-log
coordinate graph paper for each sulfur com-
pound. Alternatively, a least squares equa-
tion may be generated from the calibration
data.
8.5 Calibration of Dilution System. Gen-
erate a known concentration of hydrogen
sulfide using the permeation tube system.
Adjust the flow rate of diluent air for the
first dilution stage so that the desired level
of dilution is approximated. Inject the dilut-
ed calibration gas into the GC/FPD system
and monitor its response. Three injections
for each dilution must yield the precision
described in Section 4.1. Failure to attain
this precision in this step is an Indication of
a problem in the dilution system. Any such
problem must be identified and corrected
before proceeding. Using the calibration
data for H>S (developed under 8.3) deter-
mine the diluted calibration gas concentra-
tion in ppm. Then calculate the dilution
factor as the ratio of the calibration gas
concentration before dilution to the diluted
calibration gas concentration determined
under this paragraph. Repeat this proce-
dure for each stage of dilution required. Al-
ternatively, the GC/FPD system may be
calibrated by generating a series of three or
more concentrations of each sulfur com-
pound and diluting these samples before in-
jecting them into the GC/FPD system. This
data will then serve as the calibration data
for the unknown samples and a separate de-
termination of the dilution factor will not
be necessary. However, the precision re-
quirements of Section 4.1 are still applica-
ble.
9. Sampling and Analysis Procedure.
9.1 Sampling. Insert the sampling probe
into the test port making certain that no di-
lution air enters the stack through the port.
Begin sampling and dilute the sample ap-
proximtely 0:1 using the dilution system.
Note that the precise dilution factor is that
which is determined in paragraph 8.5. Con-
dition the entire system with sample for a
minimum of 15 minutes prior to commenc-
ing analysis.
9.2 Analysis. Aliquots of dilut-
ed sample pass through the SO, scrub-
ber, and then are injected into the
GC/FPD analyzer for analysis. 93
9.2.1 Sample Run. A sample run is com
posed of 16 individual analyses (injects) per
formed over a period of not less than 3
hours or more than 6 hours.
9.2.2 Observation for Clogging of Probe
If reductions in sample concentrations are
observed during a sample run that cannot
be explained by process conditions, the sam-
pling must be interrupted to determine if
the sample probe is clogged with particulate
matter. If the probe is found to be clogged,
the test must be stopped and the results up
to that point discarded. Testing may resume
after cleaning the probe or replacing it with
a clean one. After each run, the sample
probe must be inspected and, if necessary,
dismantled and cleaned.
10. Post-Test Procedures.
10.1 Sample line loss. A known concen-
tration of hydrogen sulfide at the level of
tl.o applicable standard, ± 20 percent, rr> > l
be introduced into the sampling system in
sufficient quantities to insure that there is
an excess of sample which must be vented
to the atmosphere. The sample must be in-
troduced immediately after the probe and
filter and transported through the remain-
der of the sampling system to the measure-
ment system in the normal manner. The re-
sulting measured concentration should be
compared to the known value to determine
the sampling system loss.9'
For sampling losses greater than 20 per-
cent in a sample run, the sample run is not
to be used when determining the arithmetic
mean of the performance test. For sampling
losses of 0-20 percent, the sample concen-
tration must be corrected by dividing the
sample concentration by the fraction of re-
covery. The fraction of recovery is equal to
one minus the ratio of the measured con-
centration to the known concentration of
hydrogen sulfide in the sample line loss pro-
redure. The known gas sample may be gen-
erated using permeation tubes. Alternative-
ly, cylinders of hydrogen sulfide mixed in
air may be used provided they are traceable
to permeation tubes. The optional pretest
procedures provide a good guideline for de-
termining if there are leaks in the sampling
system.'1
10.2 Recalibration. After each run, or
after a series of runs made within a 24-hour
period, perform a partial recalibration using
the procedures in Section 8. Only H,S (or
other permeant) need be used to recalibrate
the GC/FPD analysis system (8.3) and the
dilution system (8.5).
10.3 Determination of Calibration Drift.
Compare the calibration curves obtained
prior to the runs, to the calibration curies
obtained under paragraph 10.1. The calibra-
tion drift should not exceed the limits set
forth insubsection4.2. If the drift exceeds
this limit, the intervening run or runs
should be considered not valid. The tester,
however, may instead have the option of
choosing the calibration data set which
would give the highest sample values. 93
11. Calculations.
11.1 Determine the concentrations of
each reduced sulfur compound detected di-
rectly from the calibration curves. Alterna-
tively, the concentrations may be calculated
using the equation for the least square line.
11.2 Calculation of TRS. Total reduced
sulfur will be determined for each anaylsis
made by summing the concentrations of
each reduced sulfur compound resolved
' -ing a given analysis.
TRS = Z (H.S, MeSH, DMS, 2DMDS)d
Equation 16 2
Ill-Appendix A-61
-------
where:
TBS-Total reduced sulfur In ppm, wet
basis.
EUi-Hydrogen sulfide. ppm.
MeSH=Methyl mercaptan, ppm.
DMS=Dimethyl sulfide, ppm.
DMDS-Dimethyl dlsulfide, ppm.
d-Dilution factor, dlmensionless.
11.3 Avenge TR8. The Average TRS will
be determined at follow*:
N
I TRS
Average TRS-
Average TRS -Average total reduced suflur
In ppm, dry basis.
TRS, -Total reduced sulfur In ppm as deter-
mined by Equation 16-2.
N Number of samples.
B^-Fraction of volume of water vapor in
the gas stream as determined by Refer
ence method 4 Determination of 93
Moisture in Stack Oases (36 FR 24887).
11.4 Average concentration of individual
reduced sulfur compounds.
Equation 16-3
where:
ft-Concentration of any reduced sulfur
compound from the ith sample injec-
tion, ppm.
C-Average concentration of any one of the
reduced sulfur compounds for the entire
run, ppm.
N-Number of Injections in any run period.
13. Example System. Described below is a
system utilized by EPA in gathering NSPS
data. This system does not now reflect all
the latest developments in equipment and
column technology, but it does represent
one system that has been demonstrated to
work.
12.1 Apparatus.
12.1.1 Sampling System.
12.1.1.1 Probe. Figure 16-1 illustrates the
probe used in lime kilns and other sources
where significant amounts of paniculate
matter are present, the probe is designed
with the deflector shield placed between the
sample and the gas inlet holes and the glass
wool plugs to reduce clogging of the filter
and possible adsorption of sample gas. The
exposed portion of the probe between the
sampling port and the sample line is heated
with heating tape.
12.1.1.2 Sample Line *i« inch inside diam-
eter Teflon tubing, heated to 120' C. This
temperature is controlled by a thennostatlc
heater.
12.1.1.3 Sample Pump. Leakless Teflor
coated diaphragm type or equivalent. Th<>
pump head Is heated to 120' C by enclosing
it in the sample dilution box (12.1.2.4 below).
12.1.2 Dilution System. A schematic dia-
gram of the dynamic dilution system is
given in Figure 16-2. The dilution system is
constructed such that all sample contacts
are made of Inert materials. The dilution
ystem which Is heated to 120' C must be ca-
pable of a minimum of 9:1 dilution of
ample. Equipment used in the dilution
ystem is listed below:93
12.1.2.1 Dilution Pump. Model A-150
Kohmyhr Teflon positive displacement
type, nonadjustable 150 cc/min. ±2.0 per-
cent, or equivalent, per dilution stage. A 9:1
dilution of sample is accomplished by com-
bining 150 cc of sample with 1.350 cc of
clean dry air as shown in Figure 16-2.
12.1.2.2 Valves. Three-way Teflon sole-
noid or manual type.
12.1.2.3 Tubing. Teflon tubing and fit-
tings are used throughout from the sample
probe to the OC/FPD to present an inert
surface for sample gas,
12.1.2.4 Box. Insulated "box, heated and
maintained at 120' C. of sufficient dimen-
sions to house dilution apparatus.
12.1.2.5 Flowmeters. Rotameters or
equivalent to measure flow from 0 to 1500
ml 'min ± 1 percent per dilution stage.
12.1.3 S02 Scrub-
ber. Midget impinger with 15 ml of po-
tassium citrate buffer to absorb SO, in
the sample. 93
12.1.4 Gas Chroinatograph Columns
Two types of columns are used for separa-
tion of low and high molecular weight
sulfur compounds:93
12.1.4.1 Low Molecular Weight Sulfur
Compounds Column GC/FPD-I.93
12.1.4.l.lSepara.tiori Column. 11 m by 2.16
mm (36 ft by 0.085 in) Inside diameter
Teflon tubing packed with 30/60 mesh
Teflon coated with 5 percent polyphenyl
ether and 0.05 percent orthophosphoric
acid, or equivalent (see Figure 16-3).
12.1.4.1.2 Stripper or Precolumn. 0.6 m
by 2.16 mm (2 ft by 0.085 in) Inside diameter
Teflon tubing.93
12.1.4.1.3 Sample Valve. Teflon 10-port
gas sampling valve, equipped with a 10 ml
sample loop, actuated by compressed air
(Figure 16-3).93
12.1.4.1.4 Oven. For containing sample
valve, stripper column and separation
column. The oven should be capable of
maintaining an elevated temperature rang-
ing from ambient to 100* C, constant within
±r C. 93
12.1.4.1.5 Temperature Monitor. Thermo-
couple pyrometer to measure column oven,
detector, and exhaust temperature ±1' C.93
12.1.4.1.6 Flow System. Gas metering
system to measure sample flow, hydrogen
flow, and oxygen flow (and nitrogen carrier
gas flow).93
12.1.4-1.7 Detector. Flame photometric
detector.93
12.1.4.1.8 Electrometer. Capable of full
scale amplification of linear ranges of 10"'
to 10~' amperes full scale.93
12.1.4.1.9 Power Supply. Capable of deli-
vering up to 750 volts.93
12.1.4.1.10 Recorder. Compatible with
the output voltage range of the electrom-
eter.93
12.1.4.2 High Molecular Weight Com-
pounds Column (GC/FPD-II).93
12.1.4.2.1. Separation Column. 3.05 m by
2.16 mm (10 ft by 0.0885 in) Inside diameter
Teflon tubing packed with 30/60 mesh
Teflon coated with 10 percent Triton X-305.
or equivalent.93
12.1.4.2.2 Sample Valve. Teflon 6-port gas
sampling valve equipped with a 10 ml
sample loop, actuated by compressed air
(Figure 16-3 ).93
12.1.4.2.3 Other Components. All compo-
nents same as in 12.1.4.1.5 to 12.1.4-1.10.
12.1.5 Calibration. Permeation tub*-
system (figure 16-4).93
12.1.5.1 Tube Chamber. Glass chamber
of sufficient dimensions to house perme-
ation tubes.93
12.1.5.2 Mass Flowmeters. Two mass
flowmeters in the range 0-3 1/mln. and 0-10
1/min. to measure air flow over permeation
tubes at ±2 percent. These flowmeters shall
be cross-calibrated at the beginning of each
test. Using a convenient flow rate in the
measuring range of both flowmeters, set
and monitor the flow rate of gas over the
permeation tubes. Injection of calibration
gas generated at this flow rate as measured
by one flowmeter followed by Injection of
calibration gas at the same flow rate as mea-
sured by the other flowmeter should agree
within the specified precision limits. If they
do not. then there is a problem with the
mass flow measurement. Each mass flow-
meter shall be calibrated prior to the first
test with a wet test meter and thereafter, at
least once each year.
12.1.5.3 Constant Temperature Bath. Ca-
pable of maintaining permeation tubes at
certification temperature of 30* C. within
±0.1' C.
12.2 Reagents
12.2.1 Fuel. Hydrogen (Hi) prepurified
grade or better.
12.2.2. Combustion Gas. Oxygen (O,) re-
search purity or better.
12.2.3 Carrier Gas. Nitrogen (N,) prepuri-
fied grade or better.
12.2.4 Diluent. Air containing less than
60 ppb total sulfur compounds and less than
10 pprn each of moisture and total hydro-
carbons, and filtered using MSA filters
46727 and 79030, or equivalent. Removal of
sulfur compounds can be verified by inject-
ing dilution air only, described in Section
8.3.
12.2.5 Compressed Air. 60 psig for GC
valve actuation.
12.2.6 Calibrated Gases. Permeation
tubes gravlmetrically calibrated and certi-
fied at 30.0' C.
12.2.7 Citrate
Buffer. Dissolve 300 grams of potas-
sium citrate and 41 grams of anhy-
drous citric acid in 1 liter of deionized
water. 284 grams of sodium citrate
may be substituted for the potassium
citrate.93
12.3 Operating Parameters.
12.3.1 Low-Molecular Weight Sulfur
Compounds. The operating parameters for
the GC/FPD system used for low molecular
weight compounds are as follows: nitrogen
carrier gas flow rate of 50 cc/min, exhaust
temperature of 110' C. detector temperature
of 105° C, oven temperature of 40' C, hydro-
gen flow rate of 80 cc/min. oxygen flow rate
of 20 cc/min, and sample flow rate between
30 and 80 cc/min.
12.3.2 High-Molecular "Weight Sulfur
Compounds. The operating parameters for
the GC/FPD system lor high molecular
weight compounds are the same as in 12.3.1
except: oven temperature of 70° C, and m-
trogen carrier gas flow of 100 cc/min.
12.4 Analysis Procedure.
12.4.1 Analysis. Aliquots of diluted
sampje are injected simultaneously Into
both GC/FPD analyzers for analysis. GC/
FPD-I is used to measure the low-molecular
weight reduced sulfur compounds. The low
molecular weight compounds include hydro-
gen sulfide, methyl mercaptan, and di-
methyl sulfide. GC/FPD-II is used to re-
solve the high-molecular weight compound.
The high-molecular weight compound is di-
methyl disulfide.
12.4.1.1 Analysis of Low-Molecular
Weight Sulfur Compounds. The sample
valve is actuated for 3 minutes in which
time an aliquot of diluted sample is injected
into the stripper column and analytical
column. The valve is then deactivated for
approximately 12 minutes in which time,
the analytical column continues to be fore-
III-Appendix A-62
-------
flushed, the stripper column is backflushed,
and the sample loop is refilled. Monitor the
responses. The eiutlon time for each com-
pound will be determined during calibra-
tion.
12.4.1.2 Analysis of High-Molecular
Weight Sulfur Compounds. The procedure
is essentially the same as above except that
no stripper column is needed.
13. Bibliography.
13.1 O'Keeffe, A. E. and G. C. Ortman.
"Primary Standards for Trace Oas Analy-
sis." Analytical Chemical Journal, 38,760
(1966).
13.2 Stevens. R. K.. A. E. O'Keeffe, and
O. C. Ortman. "Absolute Calibration of a
Flame Photometric Detector to Volatile
Sulfur Compounds, at Sub-Part-Per-Million
Levels." Environmental Science and Tech-
nology. 3:7 (July, 1969).
13.3 Mulick, J. D., R. K. Stevens, and R.
Baumgardner. "An Analytical System De-
signed to Measure Multiple Malodorous
Compounds Related to Kraft Mill Activi-
ties." Presented at the 12th Conference on
13.6 General Reference. Standard Meth-
ods of Chemical Analysis Volume III A and
B Instrumental Methods. Sixth Eiiitiim.
Van Nostrand Reinhold Cu 93
\
r
\
\
Methods in Air Pollution and Industrial Hy-
giene Studies, University of Southern Cali
fornla, Los Angeles, CA. April 6-8, 1971.
13.4 Devonald, R. H., R. S. Serenius, and
A. D. Mclntyre. "Evaluation of the Flame
Photometric Detector for Analysis of Sulfur
Compounds." Pulp and Paper Magazine of
Canada, 73,3 (March, 1972).
13.5 Orimley. K. W., W. S. Smith, and R.
M. Martin. "The Use of a Dynamic Dilution.
System in the Conditioning of Stack Gases
for Automated Analysis by a Mobile Sam-
pling Van." Presented at the 63rd Annual
APCA Meeting in St. Louis, Mo. June 14-19,
1970.
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TO INSTRUMENTS
AND
DILUTION SYSTEM
CONSTANT
TEMPERATURE
BATH
THERMOMETER
FLOWMETER
*-
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o
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CHAMBER
DILUENT
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NITROGEN
PERMEATION
TUBE
Figure 16-4. Apparatus for field calibration.
Ill-Appendix A-66
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-------
METHOD 17. DETERMINATION OF PARTICtTLATE
EMISSIONS FROM STATIONARY SOURCES (IN-
STACK FILTRATION METHOD) 82
Introduction
Particulate matter is not an absolute
quantity; rather, It is a function of tempera-
ture and pressure. Therefore, to prevent
variability in paniculate matter emission
regulations and/or associated test methods,
the temperature and pressure at which par-
ticulate matter is to be measured must be
carefully defined. Of the two variables (i.e..
temperature and pressure), temperature has
the greater effect upon the amount of pv-
ticulate matter in an effluent gas stream; in
most stationary source categories, the effect
of pressure appears to be negligible.
In method 5, 250° F is established as a
nominal reference temperature. Thus,
where Method 5 is specified in an applicable
subpart of the standards, particulate matter
is defined with respect to temperature. In
order to maintain a collection temperature
of 250' F, Method 5 employs a heated glass
sample probe and a heated filter holder.
This equipment is somewhat cumbersome
and requires care in its operation. There-
fore, where particulate matter concentra-
tions (over the normal range of temperature
associated with a specified source category)
are known to be independent of tempera-
ture, it is desirable to eliminate the glass
probe and heating systems, and sample at
tack temperature.
This method describes an in-stack sam-
pling system and sampling procedures for
use in such cases. It is intended to be used
only when specified by an applicable sub-
part of the standards, and only within the
applicable temperature limits (if specified),
or when otherwise approved by the Admin-
istrator.
1. Principle and Applicability.
1.1 Principle. Particulate matter is with-
drawn isokinetically from the source and
collected on a glass fiber filter maintained
at stack temperature. The particulate mass
Is determined gravimetrically after removal
of uncombined water.
1.2 Applicability. This method applies to
the determination of particulate emissions
from stationary sources for determining
compliance with new source performance
standards, only when specifically provided
for in an applicable subpart of the stan-
dards. This method is not applicable to
stacks that contain liquid droplets or are
saturated with water vapor. In addition, this
method shall not be used as written If the
projected cross-sectional area of the probe
extension-filter holder assembly covers
more than 5 percent of the stack cross-sec-
tional area (see Section 4.1.2).
2. Apparatus.
2.1 Sampling Train. A schematic of tne
sampling train used in this method is shown
In Figure 17-1. Construction details for
many, but not all, of the train components
are given In APTD-0581 (Citation 2 in Sec-
tion 7); for changes from the APTD-0581
document and for allowable modifications
to Figure 17-1, consult with the Administra-
tor.
Ill-Appendix A-68
-------
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The operating and maintenance proce-
dures for many of the sampling train com-
ponents are described in APTD-0576 (Cita-
tion 3 In Section 7). Since correct usage Is
Important In obtaining valid results, all
users should read the APTD-0576 document
and adopt the operating and maintenance
procedures outlined in it, unless otherwise
specified herein. The sampling train con-
sists of the following components:
2.1.1 Probe Nozzle. Stainless steel (316)
or class, with sharp, tapered leading edge.
The angle of taper shall be 030* and the
taper shall be on the outside to preserve a
constant internal diameter. The probe
nozzle shall be of the button-hook or elbow
design, unless otherwise specified by the Ad-
ministrator. If made of stainless steel, the
nozzle shall be constructed from seamless
tubing. Other materials of construction may
be used subject to the approval of the Ad-
ministrator.
A range of sizes suitable for isokinelic
sampling should be available, e.g., 0.32 to
1.27 cm (V4 to V4 in)«r larger If higher
volume sampling trains are usedinside di-
ameter (ID) nozzles In increments of 0.16 cm
-------
values (00.001 percent) shall be used. In no
case shall a blank value of greater than
0.001 percent of the weight of acetone used
be subtracted from the sample weight.
3.3 Analysis.
3.3.1 Acetone. Same as 3.2.
3.3.2 Deslccant. Anhydrous calcium sul-
fate, indicating type. Alternatively, other
types of desiccants may be used, subject to
the approval of the Administrator.
4. Procedure.
4.1 Sampling. The complexity of this
method is such that, in order to obtain reli-
able results, testers should be trained and
experienced with the test procedures.
4.1.1 Pretest Preparation. All compo-
nents shall be maintained and calibrated ac-
cording to the procedure described in
APTD-0576, unless otherwise specified
herein.
Weigh several 200 to 300 g portions of
silica gel in air-tight containers to the near-
est 0.5 g. Record the total weight of the
silica gel plus container, on each container.
As an alternative, the silica gel need not be
preweighed, but may be weighed directly in
Its Impinger or sampling holder just prior to
train assembly.
Check filters visually against light for ir-
regularities and flaws or plnhole leaks.
Label filters of the proper size on the back
side near the edge using numbering ma-
chine ink. As an alternative, label the ship-
ping containers (glass or plastic petrl dishes)
and keep the filters in these containers at
all times except during sampling and weigh-
ing.
Desiccate the filters at 20±5.6' C (68±10'
F) and ambient pressure for at least 24
hours and weigh at intervals of at least 6
hours to a constant weight, i.e., 00.5 mg
change from previous weighing; record re-
sults to the nearest 0.1 mg. During each
weighing the filter must not be exposed to
the laboratory atmosphere for a period
greater than 2 minutes and a relative hu-
midity above 50 percent. Alternatively
(unless otherwise specified by the Adminis-
trator), the filters may be oven dried at 105*
C (220' F) for 2 to 3 hours, desiccated for 2
hours, and weighed. Procedures other than
those described, which account for relative
humidity effects, may be used, subject to
the approval of the Administrator.
4.1.2 Preliminary Determinations. Select
the sampling site and the minimum number
of sampling points according to Method 1 or
as specified by the Administrator. Make a
projected-area model of the probe exten-
sion-filter holder assembly, with the pilot
tube face openings positioned along the cen-
terline of the stack, as shown in Figure 17-2.
Calculate the estimated cross-section block-
age, as shown in Figure 17-2. If the blockage
exceeds 5 percent of the duct cross sectional
area, the tester has the following options:
(Da suitable out-of-stack filtration method
may be used instead of in-stack filtration; or
(2) a special in-stack arrangement, in which
the sampling and velocity measurement
sites are separate, may be used; for details
concerning this approach, consult with the
Administrator (see also Citation 10 in Sec-
tion 7). Determine the stack pressure, tem-
perature, and the range of velocity heads
using Method 2; it is recommended that a
leak-check of the pitot lines (see Method 2,
Section 3.1) be performed. Determine the
moisture * content using Approximation
Method 4 or its alternatives for the purpose
of making isokinetic sampling rate settings.
Determine the stack gas dry molecular
weight, as described in Method 2, Section
1.6; If integrated Method 3 sampling is used
tor molecular weight determination, the in-
tegrated bag sample shall be taken simulta-
neously with, and for the same total length
Of time' as, the particular sample run.
STACK
WALL
IN STACK FILTER
PROBE EXTENSION
ASSEMBLY
ESTIMATED
BLOCKAGE
fsHADED AREA]
= [_ DUCT AREA J
X 100
Figure 17-2. Projected-area model of cross-section blockage
(approximate average for a sample traverse) caused by an
in-stack filter holder-probe extension assembly.
Ill-Appendix A-71
-------
Select a nozzle size based on the range of
velocity heads, such that it is not necessary
to change the nozzle size in order to main-
tain isokinetic sampling rates. During the
run, do not change the nozzle size. Ensure
that the proper differential pressure gauge
is chosen for the range of velocity heads en-
countered (see Section 2.2 of Method 2).
Select a probe extension length such that
all traverse points can be sampled. For large
stacks, consider sampling from opposite
sides of the stack to reduce the length of
probes.
Select a total sampling time greater than
or equal to the minimum total sampling
time specified in the test procedures for the
specific industry such that (1) the sampling
time per point is not less than 2 minutes (or
some greater time interval if specified by
the Administrator), and (2) the sample
volume taken (corrected to standard condi-
tions) will exceed the required minimum
total gas sample volume. The latter is based
on an approximate average sampling rate.
It is recommended that the number of
minutes sampled at each point be an integer
or an integer plus one-half minute, in order
to avoid timekeeping errors.
In some circumstances, e.g., batch cycles,
it may be necessary to sample for shorter
times at the traverse points and to obtain
smaller gas sample volumes. In these cases,
the Administrator's approval must first be
obtained.
4.1.3 Preparation of Collection Train.
During preparation and assembly of the
sampling train, keep all openings where con-
tamination can occur covered until just
prior to assembly or until sampling is about
to begin.
If impingers are used to condense stack
gas moisture, prepare them as follows: place
100 ml of water in each of the first two im-
pingers, leave the third impinger empty,
and transfer approximately 200 to 300 g of
preweighed silica gel from its container to
the fourth impinger, More silica gel may be
used, but care should be taken to ensure
that it is not entrained and carried out from
the impinger during sampling. Place the
container in a clean place for later use in
the sample recovery. Alternatively, the
weight of the silica gel plus impinger may
be determined to the nearest 0.5 g and re-
cordt d.
If some means other than impingers is
used to condense moisture, prepare the con-
denser (and, if appropnate, silica gel for
condenser outlet) for use.
Using a tweezer or clean disposable surgi-
cal gloves, place a labeled (identified) and
weighed filter in the filter holder. Be sure
that the filter is properly centered and the
gasket properly placed so as not to allow the
sample gas stream to circumvent the filter.
Check filter for tears after assembly is com-
pleted. Mark the probe extension with heat
resistant tape or by some other method to
denote the proper distance into the stack or
duct for each sampling point.
Assemble the train as in Figure 17-1, using
a very light coat of silicone grease on all
ground glass Joints and greasing only the
outer portion (see APTD-0576) to avoid pos-
sibility of contamination by the silicone
grease. Place crushed ice around the im-
pingers.
4.1.4 Leak Check Procedures.
4.1.4.1 Pretest Leak-Check. A pretest
leak-check is recommended, but not re-
quired. If the tester opts to conduct the pre-
test leak-check, the following procedure
shall be used.
After the sampling train has been assem-
bled, plug the inlot to the probe nozzle with
a material that will be able to withstand the
stack temperature. Insert the filter holder
into the stack and wait approximately 5
minutes (or longer, if necessary) to allow
the system to come to equilibrium with the
temperature of the stack gas stream. Turn
on the pump and draw a vacuum of at least
380 mm Hg (15 in. Hg); note that a lower
vacuum may be used, provided that it is not
exceeded during the test. Determine the
leakage rate. A leakage rate in excess of 4
percent of the average sampling rate or
0.00057 m'/min. (0.02 cfm), whichever is
less, is unacceptable.
The following leak-check instructions for
the sampling train described in APTD-0576
and APTD-0581 may be helpful. Start the
pump with by-pass valve fully open and
coarse adjust valve completely closed. Par-
tially open the coarse adjust valve and
slowly .close the by-pass valve until the de-
sired vacuum is reached. Do not reverse di-
rection of by-pass valve. If the desired
vacuum is exceeded, either leak-check at
this higher vacuum or end the leak-check as
shown below and start over.
When the leak-check is completed, first
slowly remove the plug from the inlet to the
probe nozzle and immediately turn off the
vacuum pump. This prevents water from
being forced backward and keeps silica gel
from being entrained backward.
4.1.4.2 Leak-Checks During Sample Run.
If, during the sampling run, a component
(e.g., filter assembly or impinger) change be-
comes necessary, a leak-check shall be con-
ducted immediately before the change is
made. The leak-check shall be done accord-
Ing to the procedure outlined in Section
4.1.4.] above, except that it shall be done at
a vacuum equal to or greater than the maxi-
mum value recorded up to that point in the
test. If the leakage rate is found to be no
greater than 0.00057 m'/min (0.02 cfm) or 4
percent of the average sampling rate
(whichever is less), the results are accept-
able, and no correction will need to be ap-
plied to the total volume of dry gas metered;
if, however, a higher leakage rate is ob-
tained, the tester shall either record the
leakage rate and plan to-correct the sample
volume as shown in Section 6.3 of this
method, or shall void the sampling run.
Immediately after component changes,
leak-checks are optional; if such leak-checks
are done, the procedure outlined in Section
4.1.4.1 above shall be used.
4.1.4.3 Post-Test Leak-Check. A leak-
check is mandatory at the conclusion of
each sampling run. The leak-check shall be
done in accordance with the procedures out-
lined in Section 4.1.4.1, except that it shaH
be conducted at a vacuum equal to or great-
er than the maximum value reached during
the sampling run. If the leakage rate is
found to be no greater than 0.00057 m'/min
(0.02 cfm) or 4 percent of the average sam-
pling rate (whichever is less), the results are
acceptable, and no correction need be ap-
plied to the total volume of dry gas metered.
If, however, a higher leakage rate is ob-
tained, the tester shall either record the
leakage rate and correct the sample volume
as shown in Section 6.3 of this method, or
shall void the sampling run.
4.1.5 Particulate Tram Operation.
During the sampling run, maintain a sam-
pling rate such that sampling is within 10
percent of true isokinetic, unless otherwise
specified by the Administrator.
For each run, record the data required on
the example data sheet shown in Figure 17-
3. Be sure to record the initial dry gas meter
reading. Record the dry gas meter readings
at the beginning and end of each sampling
time increment, when changes in flow rates
are ma.de, before and after each leak check,
and when sampling is halted. Take other
readings required by Figure 17-3 at least
once at each sample point during each time
increment and additional readings when sig-
nificant changes (20 percent variation in ve-
locity head readings) necessitate additional
adjustments in flow rate. Level and zero the
manometer. Because the manometer le\el
and zero may drift due to vibrations and
temperature changes, make periodic checks
during the traverse.
Ill-Appendix A-72
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Clean the portholes prior to the test run
to minimize the chance of sampling the de-
posited material. To begin sampling, remove
the nozzle cap and verify that the pilot tube
and probe extension are properly posi-
tioned. Position the nozzle at the first tra-
verse point with the tip pointing directly
into the gas stream. Immediately start the
pump and adjust the flow to isokinetic con-
ditions. Nomographs are available, which
aid in the rapid adjustment to the isokinetic
sampling rate without excessive computa-
tions. These nomographs are designed for
use when the Type S pitot tube coefficient
is 0.85±0.02, and the stack gas equivalent
density (dry molecular weight) is equal to
29 ±4. APTD-0576 details the procedure for
using the nomographs. II Cp and Mj are out-
side the above stated ranges, do not use the
nomographs unless appropriate steps (see
Citation 7 in Section 7) are taken to com-
pensate for the deviations.
When the stack is under significant nega-
tive pressure (height of Impinger stem),
take care to close the coarse adjust valve
before inserting the probe extension assem-
bly into the stack to prevent water from
being forced backward. If necessary, the
pump may be turned on with the coarse
adjust valve closed.
When the probe is in position, block off
the openings around the probe and porthole
to prevent unrepresentative dilution of the
gas stream.
Traverse the stack cross section, as re-
quired by Method 1 or as specified by the
Administrator, being careful not to bump
the probe nozzle into the stack walls when
sampling near the walls or when removing
or inserting the probe extension through
the portholes, to minimize chance of ex-
tracting deposited material.
During the test run, take appropriate
steps (e.g., adding crushed ice to the im-
pinger ice bath) to maintain a temperature
of less than 20° C (68° F) at the condenser
outlet; this will prevent excessive moisture
losses. Also, periodically check the level and
zero of the manometer.
If the pressure drop across the filter be-
comes too high, making isokinetic sampling
difficult to maintain, the filter may be re-
placed in the midst of a sample run. It is
recommended that another complete filter
holder assembly be used rather than at-
tempting to change the filter itself. Before a
new filter holder is installed, conduct a leak
check, as outlined in Section 4.1.4.2. The
total particulate weight shall include the
summation of all filter assembly catches.
A single train shall be used for the entire
sample run, except in cases where simulta-
neous sampling is required in two or more
separate ducts or at two or more different
locations within the same duct, or, in cases
where equipment failure necessitates a
change of trains. In all other situations, the
use of two or more trains will be subject to
the approval of the Administrator. Note
that when two or more trains are used, a
separate analysis of the collected particu-
late from each train shall be performed,
unless identical nozzle sizes were used on all
trains, in which case the particulate catches
from the individual trains may be combined
and a single analysis performed.
At the end of the sample run, turn off the
pump, remove the probe extension assembly
from the stack, and record the final dry gas
meter reading Perform a leak-check, as out-
lined in Section 4.1.4.3. Also, leak-check the
pilot lines as described in Section 3.1 of
Method 2; the lines must pass Ihis leak-
check, in order to validate the velocity head
data.
4.1.6 Calculation of Percent Isokinetic.
Calculate percent isokinetic (see Seclion
6.11) to determine whether another test run
should be made. If there is difficulty in
maintaining isokinetic rates due to source
conditions, consult wilh Ihe Administrator
for possible variance on the isokinetic rates.
4.2 Sample Recovery. Proper cleanup
procedure begins as soon as the probe ex-
tension assembly is removed from the stack
at the end of the sampling period. Allow the
assembly to cool.
When the assembly can be safely handled,
wipe off all external particulate matter near
the tip of the probe nozzle and place a cap
over It to prevent losing or gaining particu-
late matter. Do not cap off the probe tip
tightly while the sampling train is cooling
down as this would create a vacuum in the
filter holder, forcing condenser water back-
ward.
Before moving th« sample train to the
cleanup site, disconnect the filter holder-
probe nozzle assembly from the probe ex-
tension; cap the open inlet of the probe ex-
tension. Be careful not to lose any conden-
sate, if present. Remove the umbilical cord
from the condenser outlet and cap the
outlet. If a flexible line is used between the
first impinger (or condenser) and the probe
extension, disconnect the line at the probe
extension and let any condensed water or
liquid drain into the tmpingers or condens-
er. Disconnect the probe extension from the
condenser; cap Ihe probe exlension outlet.
After wiping off the silicone grease, cap off
the condenser inlet. Ground glass stoppers,
plastic caps, or serum caps (whichever are
appropriate) may be used to close these
openings.
Transfer both the filter holder-probe
nozzle assembly and the condenser to the
cleanup area. This area should be clean and
protected from the wind so that the chances
of contaminating or losing the sample will
be minimized.
Save a portion of the acetone used for
cleanup as a blank. Take 200 ml of this ac-
etone directly from the wash bottle being
used and place it In a glass sample container
labeled "acetone blank."
Inspect the train prior to and during dis-
assembly and note any abnormal conditions.
Treat the samples as follows:
Container No. 1. Carefully remove the
filter from the filter holder and place it in
its identified petri dish container. Use a pair
of tweezers and/or clean disposable surgical
gloves to handle the filter. If it is necessary
to fold the filter, do so such that the partic-
ulate cake is inside the fold. Carefully trans-
fer to the petri dish any particulate matter
and/or filter fibers which adhere to the
filter holder gasket, by using a dry Nylon
bristle brush and/or a sharp-edged blade.
Seal the container.
Container No. 2. Taking care to see that
dust on the outside of the probe nozzle or
olher exterior surfaces does not get into the
sample, quantitatively recover particulate
matter or any condensate from Ihe probe
nozzle, filling, and fronl half of Ihe filter
holder by washing these components with
acetone and placing the wash in a glass con-
tainer. Distilled waler may be used instead
of acetone when approved by the Adminis-
trator and shall be used when specified by
the Administrator; in these cases, save a
water blank and follow Administrator's di-
rections on analysis. Perform the acetone
rinses as follows:
Carefully remove the probe nozzle and
clean the inside surface by rinsing with ac-
etone from a wash bottle and brushing with
a Nylon bristle brush. Brush until acetone
rinse shows no visible particles, after which
make a final rinse of Ihe inside surface with
acetone.
Brush and rinse wilh acelone Ihe inside
parts of the fitting in a similar way until no
visible particles remain. A funnel (glass or
polyethylene) may be used to aid in trans-
ferring liquid washes to Ihe container. Rinse
the brush with acetone and quantitatively
collect these washings in the sample con-
tainer. Belween sampling runs, keep
brushes clean and protected from contami-
nation.
After ensuring that all joints are wiped
clean of silicone grease (if applicable), clean
the inside of the front half of the filter
holder by rubbing the surfaces with a Nylon
bristle brush and rinsing with acetone.
Rinse each surface three times or more if
needed to remove visible particulate. Make
final rinse of the brush and filter holder.
After all acetone washings and particulate
matter are collected in the sample contain-
er, lighlen Ihe lid on Ihe sample container
so thai acelone will nol leak oul when it is
shipped to the laboratory. Mark the height
of the fluid level to determine whether or
nol leakage occurred during transport
Label the conlainer lo clearly identify ils
contents.
Container No. 3. if silica eel is used in the
condenser syslem for mosilure conlent de-
termination, note the color of the gel to de-
termine if it has been completely spent;
make a notation of its condition. Transfer
the silica gel back lo ils original container
and seal. A funnel may make it easier to
pour the silica gel without spilling, and a
rubber policeman may be used as an aid in
removing the silica gel. It is not necessary to
remove Ihe small amounl of dusl particles
that may adhere to the walls and are diffi-
cult to remove. Since the gain in weight is to
be used for moisture calculations, do not use
any walei or olher liquids lo Iransfer the
silica gel. If a balance is available in the
field, follow the procedure for Container
No. 3 under "Analysis."
Condenser "Water. Treat the condenser or
impinger waler as follows: make a notation
of any color or film in the liquid calch. Mea-
sure the liquid volume to within ±1 ml b>
using a graduated cylinder or, if a balance is
available, determine the liquid weight to
within ±0.5 g. Record the tolal volume or
weight of liquid present. This information is
required to calculate the moisture content
of Ihe effluenl gas. Discard Ihe liquid after
measuring and recording the volume or
weight.
4.3 Analysis. Record the data required on
the example sheet shown in Figure 17-4.
Handle each sample container as follows'
Container No. 1. Leave the contents in the
shipping conlainer or Iransfer the filter and
any loose particulate from the sample con-
tainer to a tared glass weighing dish. Desic-
cate for 24 hours in a desiccator containing
anhydrous calcium sulfate. Weigh lo a con-
slanl weighl and reporl Ihe resulls to the
nearest 0.1 mg. For purposes of this Section,
4.3, the lerra "conslanl weighl" means a dif-
ference of no more than 0.5 mg or 1 percenl
of lolal weighl less tare weight, whichever is
grealer, between two consecutive weighings,
with no less than 6 hours of desiccation
time between weighings.
Alternalively, the sample may be oven
dried al the average stack lemperalure or
Ill-Appendix A-74
-------
105° C (220' F), whichever is less, for 2 to 3
hours, cooled in the desiccator, and weighed
to a constant weight, unless otherwise speci
fied by the Administrator. The tester may
also opt to oven dry the sample at the aver-
age stack temperature or 105° C (220' F),
whichever is less, for 2 to 3 hours, weigh the
sample, and use this weight as a final
weight.
Plant.
Date.
Run No.
Filter No.
Amount liquid lost during transport
Acetone blank volume, ml
Acetone wash volume, ml
Acetone black concentration, mg/mg (equation 174)
Acetone wash blank, mg (equation 17-5)
CONTAINER
NUMBER
1
2
TOTAL
WEIGHT OF PARTICULATE COLLECTED.
mg
FINAL WEIGHT
:x:
TARE WEIGHT
^x^
Less acetone blank
Weight of particulate matter
WEIGHT GAIN
FINAL
INITIAL
LIQUID COLLECTED
TOTAL VOLUME COLLECTED
VOLUME OF LIQUID
WATER COLLECTED
IMPINGER
VOLUME,
ml
SILICA GEL
WEIGHT.
9
9' ml
* CONVERT WEIGHT OF WATER TO VOLUME BY DIVIDING TOTAL WEIGHT
INCREASE BY DENSITY OF WATER (1g/ml).
INCREASE, g
1 g/ml
Figure 17-4. Analytical data.
= VOLUME WATER, ml
Ill-Appendix A-75
-------
Container No. 2. Note the level of liquid in
the container and confirm on the analysis
sheet whether or not leakage occurred
during transport. If a noticeable amount of
leakage has occurred, either void the sample
or use methods, subject to the approval of
the Administrator, to correct the final re-
sults. Measure the liquid in this container
either volumetrically to ±1 ml or gravime-
trically to ±0.5 g. Transfer the contents to a
tared 250-ml beaker and evaporate to dry-
ness at ambient temperature and pressure.
Desiccate for 24 hours and weigh to a con-
stant weight. Report the results to the near-
est 0.1 mg.
Container No. 3. This step may be con-
ducted in the field. Weigh the spent silica
gel (or silica gel plus impinger) to the near-
est 0.5 g using a balance.
"Acetone Blank" Container. Measure ac-
etone in this container either volumetrically
or gravimetrically. Transfer the acetone to a
tared 250-ml beaker and evaporate to dry-
ness at ambient temperature and pressure.
Desiccate for 24 hours and weigh to a con-
stant weight. Report the results to the near-
est 0.1 mg.
NOTE.At the option of the tester, the
contents of Container No. 2 as well as the
acetone blank container may be evaporated
at temperatures higher than ambient. If
evaporation is done at an elevated tempera-
ture, the temperature must be below the
boiling point of the solvent; also, to prevent
"bumping," the evaporation process must be
closely supervised, and the contents of the
beaker must be swirled occasionally to
maintain an even temperature. Use extreme
care, as acetone is highly flammable and
has a low flash point.
6. Calibration. Maintain a laboratory log
of all calibrations.
5.1 Probe Nozzle. Probe nozzles shall be
calibrated before their initial use in the
field. Using a micrometer, measure the
Inside diameter of the nozzle to the nearest
0.025 mm (0.001 In.). Make three separate
measurements using different diameters
each time, and obtain the average of the
measurements. The difference between the
high and low numbers shall not exceed 0.1
mm »(0.004 in.). When nozzles become
nicked, dented, or corroded, they shall be
reshaped, sharpened, and recalibrated
before use. Each nozzle shall be permanent-
ly and uniquely identified.
5.2 Pilot Tube. If the pilot tube is placed
in an interference-free arrangement with re-
spect to the other probe assembly compo-
nents, its baseline (isolated tube) coefficient
shall be determined as outlined in Section 4
of Method 2. If the probe assembly is not in-
terference-free, the pilot tube assembly co-
efficient shall be determined by calibration,
using methods subject to the approval of
the Administrator.
5.3 Metering System. Before its initial
use in the field, the metering system shall
be calibrated according to the procedure
outlined in APTD-0576. Instead of physical-
ly adjusting the dry gas meter dial readings
to correspond to the wet test meter read-
ings, calibration factors may be used to
mathematically correct the gas meter dial
readings to the proper values.
Before calibrating the metering system, it
is suggested that a leak-check be conducted.
For metering systems having diaphragm
pumps, the normal leak-check procedure
will not detecl leakages within the pump.
For these cases the following leak-check
procedure is suggested: make a 10-minute
calibration run at 0.00057 m'/mtn (0.02
cfm); at the end of the run, take the differ-
ence of the measured wet test meter and
dry gas meter volumes; divide the difference
by 10, to get the leak rate. The leak rate
should not exceed 0.00057 m'/min (0.02
cfm).
After each field use, the calibration of the
metering system shall be checked by per-
forming three calibration runs at a single,
intermediate orifice setting (based on the
previous field test), with the vacuum set at
the maximum value reached during the test
series. To adjust the vacuum, insert a valve
between the wet test meter and the inlet of
the metering system. Calculate the average
value of the calibration factor. If the cali-
bration has changed by more than 5 per-
cent, recalibrate the meter over the full
range of orifice settings, as outlined in
APTD-0576.
AlternaUve procedures, e.g., using the ori-
fice meter coefficients, may be used, subject
to the approval of the Administrator.
NOTE.If the dry gas meter coefficient
values obtained before and after a test
series differ by more than 5 percent, the
test series shall either be voided, or calcula-
tions for the test series shall be performed
using whichever meter coefficient value
(i.e., before or after) gives the lower value of
total sample volume.
5.4 Temperature Gauges. Use the proce-
dure in Section 4.3 of Method 2 to calibrate
In-stack temperature gauges. Dial thermom-
eters, such as are used for the dry gas meter
and condenser outlet, shall be calibrated
against mercury-in-glass thermometers.
5.5 Leak Check of Metering System
Shown in Figure 17-1. That portion of the
sampling train from the pump to the orifice
meter should be leak checked prior to-initial
use and after each shipment. Leakage after
the pump will result in less volume being re-
corded than is actually sampled. The follow
ing procedure Is suggested (see Figure 17-5).
Close the main valve on the meter box.
Insert a one-hole rubber stopper with
rubber tubing attached into the orifice ex-
haust pipe. Disconnect and vent the low side
of the orifice manometer. Close off the low
side orifice tap. Pressurize the system to 13
to 18 cm (5 to 7 in.) water column by blow-
ing into the rubber tubing. Pinch off the
tubing and observe the manometer for one
minute. A loss of pressure on the mano-
meter indicates a leak in the meter box;
leaks, if present, must be corrected.
Ill-Appendix A-76
-------
X
o
-O
o>
£
I
o
^
.
V.=Volume of acetone blank, ml.
V.w=Volume of acetone used in wash, ml.
V,< = Total volume of liquid collected in im-
pingers and silica gel (see Figure 17-4),
ml.
V«,=Volume of gas sample as measured by
dry gas meter, dcm (dcf).
Vmu«t=Volume of gas sample measured by
the dry gas meter, corrected to standard
conditions, dscm (dscf).
V»
-------
0,=Sampling time interval, from the final
(n") component change, until the end of
the sampling run, min.
13.6=Specific gravity of mercury.
80-Sec/mm.
100 = Conversion to percent.
6.2 Average dry gas meter temperature
and average orifice pressure drop. See data
»he«t (Figure 17-3).
6.3 Dry Gas Volume. Correct the sample
volume measured by the dry gas meter to
standard conditions (20° C, 760 mm Hg or
68- F, 29.92 in. Hg) by using Equation 17-1.
6.6 Acetone Blank Concentration.
Vm{std) = V
W
rstd
Pfcar + (AH/13.6)
Equation 17-1
where:
K,-=0.3858' K/mm Hg for metric units;
17.64' R/ln. Hg for English units.
NOTE. Equation 17-1 can be used as writ-
ten unless the leakage rate observed during
any of the mandatory leak checks (I.e., the
post-test leak check or leak checks conduct-
ed prior to component changes) exceeds L..
If Lp or L, exceeds L,, Equation 17-1 must be
modified as follows:
(a) Case I. No component changes made
during sampling run. In this case, replace
V. In Equation 17-1 with the expression:
(b) Case II. One or more component
changes made during the sampling run. In
this case, replace Vm in Equation 17-1 by the
expression:
i*L - (Li - LJ ei - z (>-, - LJ e,
in I a i . p i d i
V
Va pa
Equation 17-4
6.7 Acetone Wash Blank.
W. = C.V.wp.
Equation 17-5
6.8 Total Particulate Weight. Determine
the total particulate catch from the sum of
the weights obtained from containers 1 and
2 less the acetone blank (see Figure 17-4).
NOTE. Refer to Section 4.1.5 to assist in
calculation of results involving two or more
filter assemblies or two or more sampling
trains.
6.9 Particulate Concentration.
c.=(0.001 g/mg) (
6.10 Conversion Factors:
Equation 17-6
Prom
To
Multiply by
scf...
/ft'.
/ft'.
/ft'.
tn"
gT/ft'
Ib/ft-
g/m>.
0.02832
15.43
2.505v 10''
35.31
6.11 Isokinetic Variation.
6.11.1 Calculation from Raw Data.
100
-------
Method 19. Determination of Sulfur
Dioxide Removal Efficiency and
Particulate, Sulfur Dioxide and Nitrogen
Oxides Emission Rates From Electric
Utility Steam Generators 9B
1. Principle and Applicability
1.1 Principle.
1.1.1 PueJ samples from before and
after fuel pretreatment systems are
collected and analyzed for sulfur and
heat content, and the percent sulfur
dioxide (ng/Joule, Ib/million Btu)
reduction is calculated on a dry basis.
[Optional Procedure.)
1.1.2 Sulfur dioxide and oxygen or
carbon dioxide concentration data
obtained from sampling emissions
upstream and downstream of sulfur
dioxide control devices are used to
calculate sulfur dioxide removal
efficiencies. (Minimum Requirement.) As
an alternative to sulfur dioxide
monitoring upstream of sulfur dioxide
control devices, fuel samples may be
collected in an as-fired condition and
analyzed for sulfur and heat content.
(Optional Procedure.)
1.1.3 An overall sulfur dioxide
emission reduction efficiency is
calculated from the efficiency of fuel
pretreatment systems and the efficiency
of sulfur dioxide control devices.
1.1.4 Particulate, sulfur dioxide,
nitrogen oxides, and oxygen or carbon
dioxide concentration data obtained
from sampling emissions downstream
from sulfur dioxide control devices are
used along with F factors to calculate
particulate, sulfur dioxide, and nitrogen
oxides emission rates. F factors are
values relating combustion gas volume
to the heat content of fuels.
1.2 Applicability. This method is
applicable for determining sulfur
removal efficiencies of fuel pretreatment
and sulfur dioxide control devices and
the overall reduction of potential sulfur
dioxide emissions from electric utility
steam generators. This method is also
applicable for the determination of
particulate, sulfur dioxide, and nitrogen
oxides emission rates.
2. Determination of Sulfur Dioxide
Removal Efficiency of Fuel
Pretreatment Systems
2.1 Solid Fossil Fuel.
2.1.1 Sample Increment Collection.
Use ASTM D 2234«, Type I, conditions
A, B, or C, and systematic spacing.
Determine the number and weight of
increments required per gross sample
representing each coal lot according to
Table 2 or Paragraph 7.1.5.2 of ASTM D
2234 '. Collect one gross sample for each
raw coal lot and one gross sample for
each product coal lot.
2.1.2 ASTM Lot Size. For the purpose
of Section 2.1.1, the product coal lot size
is defined as the weight of product coal
produced from one type of raw coal. The
raw coal lot size is the weight of raw
coal used to produce one product coal
lot. Typically, the lot size is the weight
of coal processsed in a 1-day [24 hours]
period. If more than one type of coal is
treated and produced in 1 day, then
gross samples must be collected and
analyzed for each type of coal. A coal
lot size equaling the 90-day quarterly
fuel quantity for a specific power plant
may be nsed if representative sampling
can be conducted for the raw coal and
product coal.
Note.Alternate definitions of fuel lot
sizes may be specified subject to prior
approval of the Administrator.
2.1.3 Gross Sample Analysis.
Determine the percent sulfur content
(%S) and gross calorific value (GCV) of
the solid fuel on a dry basis for each
gross sample. Use ASTM 2013 ' for
sample preparation, ASTM D 3177 1 for
sulfur analysis, and ASTM D 3173 ' for
moisture analysis. Use ASTM D 3176 '
for gross calorific value determination.
2.2 Liquid Fossil Fuel.
2.2.1 Sample Collection. Use ASTM
D 270 ' following the practices outlined
for continuous sampling for each gross
sample representing each fuel lot.
2-2*2 Lot Size. For the purposes of
Section 2.2.1, the weight of product fuel
from one pretreatment facility and
intended as one shipment (ship load,
barge load, etc.) is defined as one
product fuel lot. The weight of each
crude liquid fuel type used to produce
one product fuel lot is defined as one
inlet fuel lot.
Note. Alternate definitions of fuel lot
sizes may be specified subject to prior
approval of the Administrator.
Note. For the purposes of this method,
raw or inlet fuel (coal or oil) is defined as the
fuel delivered to the desulfurization
pretreatment facility or to the steam
generating plant. Forpretreated oil the input
oil to the oil desulfurization process (e.g.
hydrotreatment emitted) is sampled.
2.2.3 Sample Analysis. Determine
the percent sulfur content (%S) and
gross calorific value (GCV). Use ASTMD
240 ' for the sample analysis. This value
can be assumed to be on a dry basis.
2.3 Calculation of Sulfur Dioxide
Removal Efficiency Due to Fuel
Pretreatment. Calculate the percent
sulfur dioxide reduction due to fuel
pretreatment using the following
equation:
100
%Si/GCV1
Where:
%Ri=Sulfur dioxide removal efficiency due
pretreatment; percent.
%S0=Sulfur content of the product fuel lot on
a dry basis; weight percent.
%S,=Sulfur content of the inlet fuel lot on a
dry basis; weight percent.
GCV0=Gross calorific value for the outlet
fuel lot on a dry basis; kj/kg (Btu/lb).
GCV,=Gross calorific value for the inlet fuel
lot on a dry basis; kj/kg (Btu/lb).
Note.If more than one fuel type is used to
produce the product fuel, use the following
equation to calculate the sulfur contents per
unit of heat content of the total fuel lot, %S/
GCV:
SS/GCV
k-1
VBk/GCVk)
Where:
Yk=The fraction of total mass input derived
from each type, k, of fuel.
%Si=Sulfur content of each fuel type, k,'on a
dry basis; weight percent
GCVk=Gross calorific value for each fuel
type, k, on a dry basis; kj/kg (Btu/lb).
n=The number of different types of fuels.
'Use the moit recent revision or designation of
the ASTM procedure ipeclfied.
1 U>e the most recent revision or designation of
the ASTM procedure specified.
III-Appendix A-79
-------
3. Determination of Sulfur Removal
Efficiency of the Sulfur Dioxide Control
Device
3.1 Sampling. Determine Sd
emission rates at the inlet and outlet of
the sulfur dioxide control system
according to methods specified in the
applicable subpart of the regulations
and the procedures specified in Section
5. The inlet sulfur dioxide emission rate
may be determined through fuel analysis
(Optional, see Section 3.3.)
3.2. Calculation. Calculate the
percent removal efficiency using the
following equation:
9(m)
100
(1.0 -
Where:
%R, = Sulfur dioxide removal efficiency of
the sulfur dioxide control system using
inlet and outlet monitoring data; percent.
Ego =Sulfur dioxide emission rate from the
outlet of the sulfur dioxide control
system; ng/J (Ib/million Btu).
EIO ,=Sulfur dioxide emission rate to the
outlet of the sulfur dioxide control
system; ng/J (Ib/million Btu).
3.3 As-fired Fuel Analysis (Optional
Procedure). If the owner or operator of
an electric utility steam generator
chooses to determine the sulfur dioxide
imput rate at the inlet to the sulfur
dioxide control device through an as-
fired fuel analysis in lieu of data from a
sulfur dioxide control system inlet gas
monitor, fuel samples must be collected
in accordance with applicable
paragraph in Section 2. The sampling
can be conducted upstream of any fuel
processing, e.g., plant coal pulverization.
For the purposes of this section, a fuel
lot size is defined as the weight of fuel
consumed in 1 day (24 hours) and is
directly related to the exhaust gas
monitoring data at the outlet of the
sulfur dioxide control system.
3.3.1 Fuel Analysis. Fuel samples
must be analyzed for sulfur content and
gross calorific value. The ASTM
procedures for determining sulfur
content are defined in the applicable
paragraphs of Section 2.
3.3.2 Calculation of Sulfur Dioxide
Input Rate. The sulfur dioxide imput rate
determined from fuel analysis is
calculated by;
2.0(tSf) ,
T x 107 for S. I. units.
6(iv
2.0(tSf)
"Hscv
x 10 for English units.
Where:
I " Sulfur dioxide Input rate from as-f1red fuel analysis,
ng/J (Ib/million Btu).
tSf « Sulfur content of as-fired fuel, on a dry basis; weight
percent.
GCV « Gross calorific value for as-fired fuel, on a dry basis;
kJ/kg (Btu/lb).
3.3.3 Calculation of Sulfur Dioxide 3.3.2 and the sulfur dioxide emission
Emission Reduction Using As-fired Fuel rate, ESO», determined in the applicable
Analysis. The sulfur dioxide emission paragraph of Section 5.3. The equation
reduction efficiency is calculated using f°r sulfur dioxide emission reduction
the sulfur imput rate from paragraph ' efficiency is:
Eso,
Rg(f) ' 10° ' -1'0 - 17
Where:
XR /.> Sulfur dioxide removal efficiency of the sulfur
dioxide control system using as-fired fuel analysis
data; percent.
ESQ Sulfur dioxide emission rate from sulfur dioxide control
system; ng/J (Ib/million Btu).
I$ Sulfur dioxide Input rate from as-fired fuel analysis;
ng/J (Ib/wmion Btu).
Ill-Appendix A-80
-------
4. Calculation of Overall Reduction in
Potential Sulfur Dioxide Emission
4.1 The overall percent sulfur
dioxide reduction calculation uses the
sulfur dioxide concentration at the inlet
to the sulfur dioxide control device as
the base value. Any sulfur reduction
realized through fuel cleaning is
introduced into the equation as an
average percent reduction, %Rf.
4.2 Calculate the overall percent
sulfur reduction as:
100C1.0-
Where:
XR Overall sulfur dioxide reduction; percent.
SR* « Sulfur dioxide removal efficiency of fuel pretreatment
from Section 2; percent. Refer to applicable subpart
for definition of applicable averaging period.
XR « Sulfur dioxide removal efficiency of sulfur dioxide control
device either 0. or CO. - based calculation or calculated
fro* fuel analysts and emission data, from Section 3;
percent. Refer to applicable subpart for definition of
applicable averaging period.
5. Calculation of Paniculate, Sulfur
Dioxide, and Nitrogen Oxides Emission
Rates
and oxygen concentrations have been
determined in Section 5.1. wet or dry F
factors are used. (Fw) factors and
associated emission calculation
procedures are not applicable and may
not be used after wet scrubbers; (FJ or
(Fd) factors and associated emission
calculation procedures are used after
wet scrubbers.) When pollutant and
carbon dioxide concentrations have
been determined in Section 5.1, Fc
factors are used.
5.2.1 A verage F Factors. Table 1
shows average Fa. F», and Fc factors
(scm/J, scf/million Bru) determined for
commonly used fuels. For fuels not
listed in Table 1, the F factors are
calculated according to the procedures
outlined in Section 5.2.2 of this section.
5.2.2 Calculating an F Factor. If the
fuel burned is not listed in Table 1 or if
the owner or operator chooses to
determine an F factor rather than use
the tabulated data, F factors are
calculated using the equations below.
.The sampling and analysis procedures
followed in obtaining data for these
calculations are subject to the approval
of the Administrator and the
Administrator should be consulted prior
to data collection.
5.1 Sampling. Use the outlet SO. or
Oi or COi concentrations data obtained
in Section 3.1. Determine the participate,
NO,, and O» or CO, concentrations
according to methods specified in an
applicable subpart of the regulations.
5.2 Determination of an F Factor.
Select an average F factor (Section 5.2.1)
or calculate an applicable F factor
(Section 5.2.2.). If combined fuels are
fired, the selected or calculated F factors
are prorated using the procedures in
Section 5.2,3. F factors are ratios of the
gas volume released during combustion
of a fuel divided by the heat content of
the fuel A dry F factor (F«) is the ratio of
the volume of dry flue gases generated
to the calorific value of the fuel
combusted; a wet F factor (Fw) is the
ratio of the volume of wet flue gases
generated to the calorific value of the
fuel combusted; and the carbon F factor
(FJ is the ratio of the volume of carbon
dioxide generated to the calorific value
of the fuel combusted. When pollutant
For SI Units:
* 9S.7(tC) * 3S.»(«S) + 8.6(tN) - 28.5(M)
GCV
347.4(W)495.7(XC)-t-35.4(K}+8.6(lN)-28.5(SO)+13.0(SH20)«
For English Units:
l
-------
Where:
Fa, Fw, and Fc have the units of scm/J, or scf/
million Bru; *H, %C, %S, %N, %O, and
%H«O are the concentrations by weight
(expressed in percent) of hydrogen,
carbon, sulfur, nitrogen, oxygen, and
water from an ultimate analysis of the
fuel; and GCV is the gross calorific value
of the fuel in kj/kg or Btu/lb and
consistent with the ultimate analysis.
Follow ASTM D 2015* for solid fuels, D
240* for liquid fuels, and D 1826* for
gaseous fuels as applicable in
determining GCV.
5.2.3 Combined Fuel Firing FFactor.
For affected facilities firing
combinations of fossil fuels or fossil
fuels and wood residue, the ft, Fw, or Fc
factors determined by Sections 5.2.1 or
5.2.2 of this section shall be prorated in
accordance with applicable formula as
follows:
_*, xk Fdk
n
I x
k-1
k Fwk
or
or
Fc " r xk Fck
c M K en
-Where:
x^Tbe fraction of total heat input derived
from each type of fuel, K.
n=The number of fuels being burned in
combination.
5.3 Calculation of Emission Rate.
Select from the following paragraphs the
applicable calculation procedure and
calculate the participate, SO,, and NO,
emission rate. The values in the
equations are defined as:
E=Pollutant emission rate, ng/J (Ib/million
Btu).
C=Pollutant concentration, ng/scm (Ib/gcf).
Note.It is necessary in some cases to
convert measured concentration units to
other units for these calculations.
Use the following table for such
conversions:
Conversion Factors for Concentration
From To Mufcpty by-
g/scm
mg/scm
to/ set
PpmlSO.) _..
Ppm(NOJ
ppm/(SOi) ......
ppm/(NOJ
.._ ng/scm ______
ng/refli _
,._._.. nQ/scfn .,._.___.___
,__..... ng/scfn. ...__...
to/scf
to/scf
_ 10»
_. 10*
_. 1.602X10"
£660x10'
1.912x10*
_ -1.660X10-'
._. 1.194X10-'
5.3.1 Oxygen-Based F Factor
Procedure.
5.3.1.1 Dry Basis. When both percent
oxygen (%O^ and the pollutant
concentration (CJ are measured in the
flue gas on a dry basis, the following
equation is applicable:
CdFd
20.9
20.9
2079 -SO
2d
5.3.1.2 Wet Basis. When both the
percent oxygen (%0tw) and the pollutant
concentration (C-,) are measured in the
flue gas on a wet basis, the following
equations are applicable: (Note: Fw
factors are not applicable after wet
scrubbers.)
. . , , - r 20.9 i
1Z075TT - BM) - IO-,
Where:
8,,=Proportion by volume of water vapor in
the ambient air.
In lieu of actual measurement, B*.
may be estimated as follows:
Note.The following estimating factors are
selected to assure that any negative error
introduced in the term:
(^
20.9
-)
will not be larger than -1.5 percent
However, positive errors, or over-
estimation of emissions, of as much as 5
percent may be introduced depending
upon the geographic location of the
facility and the associated range of
ambient mositure.
(i) Bw.0.027. This factor may be used
as a constant value at any location.
(ii) Bw.=Highest monthly average of
B,. which occurred within a calendar
year at the nearest Weather Service
Station.
(iii) Bw.=Highest daily average of B--,
which occurred within a calendar month
at the nearest Weather Service Station,
calculated from the data for the past 3
years. This factor shall be calculated for
each month and may be used as an
estimating factor for the respective
calendar month.
(b)
t
20.9
20.9 (1 -
-1
Where:
I).,=Proportion by volume of water vapor in
the stack gas.
5.3.1.3 Dry/Wet Basis. When the
pollutant concentration (C.) is measured
on a wet basis and the oxygen
concentration (%OM) or measured on a
dry basis, the following equation is
applicable:
E - [
CwFd
20.9
"20.9 - XO
-3
2d
When the pollutant concentration (CJ
is measured on a dry basis and the
oxygen concentration (%O»d) is
measured on a wet basis, the following
equation is applicable: -
20.9 -
5.3.2 Carbon Dioxide-Based F Factor
Procedui-e.
5.3.2.1 Dry Basis. When both the
percent carbon dioxide (%COM) and the
pollutant concentration (Cd) are
measured in the flue gas on a dry basis,
the following equation is applicable:
5.3.2.2 Wet Basis. When both the
percent carbon dioxide (SCO*,) and the
pollutant concentration (C-,) are
measured on a wet basis, the following
equation is applicable:
5.3.2.3 Dry/Wet Basis. When the
pollutant concentration (C-,) is measured
on a wet basis and the percent carbon
dioxide (%COaJ is measured on a dry
basis, the following equation is
applicable:
C. F_
100
When the pollutant concentration (CJ
is measured on a dry basis and the
precent carbon dioxide (%CO»-,) is
measured on a wet basis, the following
equation is applicable:
E C 0 - B) F
5.4 Calculation of Emission Rate
front Combined Cycle-Gas Turbine
Systems. For gas turbine-steam
generator combined cycle systems, the
emissions from supplemental fuel fired
to the steam generator or the percentage
reduction in potential (SO>) emissions
cannot be determined directly. Using
measurements from the gas turbine
exhaust (performance test, subpart GG)
and the combined exhaust gases from
the steam generator, calculate the
emission rates for these two points
following the appropriate paragraphs in
Section 5.3.
Note. F. Factors shall not be used to
determine emission rates from gas turbines
because of the injection of steam nor to
calculate emission rates after wet scrubbers;
Ft or F0 factor and associated calculation
procedures are used to combine effluent
emissions according to the procedure in
Paragraph 5.2.3.
The emission rate from the steam generator
la calculated as:
Ill-Appendix A-82
-------
-
Where:
EM=Pollutant emission rate from steam
generator effluent, ng/J (Ib/milhon Btu).
E^Pollutant emission rate in combined
cycle effluent; ng/J (Ib/million Btu).
E^ = Pollutant emission rate from gas turbine
effluent; ng/J (Ib/million Btu).
XM=Fraction of total heat input from
supplemental fuel fired to the steam
generator.
Xg,=Fraction of total heat input from gas
turbine exhaust gases.
Note. The total heat input to the steam
generator is the sum of the heat input from
supplemental fuel fired to the steam
generator and the heat input to the steam
generator from the exhaust gases from the
gas turbine.
5.5 Effect of Wet Scrubber Exhaust,
Direct-Fired Reheat Fuel Burning. Some
wet scrubber systems require that the
temperature of the exhaust gas be raised
above the moisture dew-point prior to
the gas entering the stack. One method
used to accomplish this is directfiring of
an auxiliary burner into the exhaust gas.
The heat required for such burners is
from 1 to 2 percent of total heat input of
the steam generating plant. The effect of
this fuel burning on the exhaust gas
components will be less than ±1.0
percent and will have a similar effect on
emission rate calculations. Because of
this small effect, a determination of
effluent gas constituents from direct-
fired reheat burners for correction of
stack gas concentrations is not
necessary.
Where:
§.«= Standard deviation of the average outlet
hourly average emission rates for the
reporting period; ng/J (Ib/million Btu).
8,= Standard deviation of the average inlet
hourly average emission rates for the
reporting period; ng/J (Ib/million Btu).
6.3 Confidence Limits. Calculate the
lower confidence limit for the mean
outlet emission rates for SO, and NO,
and, if applicable, the upper confidence
limit for the mean inlet emission rate for
SOi using the following equations:
Table tt-t.F Factors tor Various fuels'
E,*=E,+U.«8,
Where:
£*-« The lower confidence limit for the mean
outlet emission rates; ng/J (Ib/million
Btu).
E,* =The upper confidence limit for the mean
inlet emission rate; ng/J (Ib/million Btu).
t»«= Values shown below for the indicated
number of available data points (n):
F.
Fuel type
Coal
Anthracite
Lignite
OK' _
Gas:
Natural
Propane _
Butane _
Wood
Wood Bark
dscm dscf
J 10* Btu
271X10" (10100)
263x10" (9780)
2.65x10" (9860)
2.47x10- (9190)
243x10" (8710)
234x10' (8710)
2.34x10" (8710)
248x10" (9240)
2.58x10" (9600) __
w*cm mcf
J 10* Btu
2.83x10" (10540)
2.66x10" (10640)
321x10" (11950)
2.77x10- (10320)
285x10* (10810)
2.74x10" (10200)
2.79x10" (10390)
cm tcf
J 10* Btu
0530x10" (1970)
0484x10" (1800)
0513x10" (1910)
0.383X10" (1420)
0.287x10" (1040)
0321x10" (1190)
0337x10" (1250)
0492x10~ (1830)
0497x10" (1850)
As classified accordmg to ASTM 0 386-66.
* Crude, residual, or distillate
Determined at standard conditions 20* C (68' F) and 760 mm Hg (29.92 in. Kg).
n
t
3
4
5
6
7
S
e
10
11
12-16
17-21
22-28
27-31
32-51
52-01
92-151
152 or more
Values tor w.
6.31
£42
2.35
2.13
2.02
1.B4
1.89
1.86
1.83
1.81
1.77
1.73
1.71
1.70
1.68
1.67
1.66
1.65
6. Calculation of Confidence Limits for
Inlet and Outlet Monitoring Data
6.1 Mean Emission Rates. Calculate
the mean emission rates using hourly
averages in ng/J (Ib/million Btu) for SO»
and NO, outlet data and, if applicable,
SO, inlet data using the following
equations:
6.2 Standard Deviation of Hourly
Emission Rates. Calculate the standard
deviation of the available outlet hourly
average emission rates for SO. and NO,
and, if applicable, the available inlet
hourly average emission rates for SO,
using the following equations:
Cn^ Cf^^\
(/*.- - j \T^J
f?t{f<-*s\
(/-^-J
Where:
Eo=Mean outlet emission rate; ng/J (lb/
million Btu).
Ei=Mean inlet emission rate; ng/J (Ib/million
Btu).
x,=Hourly average outlet emission rate; ng/J
(Ib/million Btu).
X|=Hourly average in let emission rate; ng/j
(Ib/million Btu).
n^Number of outlet hourly averages
available for the reporting period.
n,=Number of inlet hourly averages
available for reporting period.
PCC
PCC
Where:
The values of this table are corrected for
n-1 degrees of freedom. Use n equal to
the number of hourly average data
points.
7. Calculation to Demonstrate
Compliance When Available
Monitoring Data Are Less Than the
Required Minimum
7.1 Determine Potential Combustion
Concentration (PCC) for SO,.
7.1.1 When the removal efficiency
due to fuel pretreatment (% Rf) is
included in the overall reduction in
potential sulfur dioxide emissions (% RJ
and the "as-fired" fuel analysis is not
used, the potential combustion
concentration (PCC) is determined as
follows:
10; ng/J
^ 104; Ib/m1l11on Btu.
Potential emissions removed by the pretreatment
process, using the fuel parameters defined 1n
section 2.3; ng/J (Ib/m1ll1on Btu).
Ill-Appendix A-83
-------
7.1.2 When the "as-fired" fuel
analysis is used and the removal
efficiency due to fuel pretreatment (% R{)
is not included in the overall reduction
in potential sulfur dioxide emissions (%
R0), the potential combustion
concentration (PCC) is determined as
follows:
PCC = I,
PCC
PCC
7.1.4 When inlet monitoring data are
used and the removal efficiency due to
fuel pretreatment (% R() is not included
in the overall reduction in potential
sulfur dioxide emissions (% R0), the
potential combustion concentration
(PCC) is determined as follows:
PCC = E,*
Where:
EI* = The upper confidence limit of the mean
inlet emission rate, as determined in
section 6.3.
7.2 Determine Allowable Emission
Rates (£,,,).
7.2.1 NO*. Use the allowable
emission rates for NO, as directly
defined by the applicable standard in
terms of ng/J (Ib/million Btu).
7.2.2 SO?. Use the potential
combustion concentration (PCC) for SOZ
as determined in section 7.1, to
determine the applicable emission
standard. If the applicable standard is
an allowable emission rate in ng/J (lb/
million Btu}, the allowable emission rate
Where:
!, = The sulfur dioxide input rate as defined
in section 3.3
7.1.3 When the "as-fired" fuel
analysis is used and the removal
efficiency due to fuel pretreatment (% R()
is included in the overal, reduction (%
R0), the potential combustion
concentration (PCC) is determined as
follows:
ng/J
Ib/m1l1ion Btu.
is used as E,t
-------
Method 20Determination of Nitrogen
Oxides, Sulfur Dioxide, and Oxygen
Emissions from Stationary Gas Turbines
1. Applicability and Principle
1.1 Applicability. This method is
applicable for the determination of nitrogen
oxides (NO,), sulfur dioxide (SO2), and
oxygen (Oa) emissions from stationary gas
turbines. For the NO, and Oa determinations.
this method includes: (1) measurement
system design criteria, (2) analyzer
performance specifications and performance
test procedures; and (3) procedures for
emission testing.
1.2 Principle. A gas sample is
continuously extracted from the exhaust
stream of a stationary gas turbine; a portion
of the sample stream is conveyed to
instrumental analyzers for determination of
NO, and Oi content. During each NO, and
OO2 determination, a separate measurement
of SO9 emissions is made, using Method 6, or
it equivalent. The Oj determination is used to
adjust the NO, and SOa concentrations to a
reference condition.
2. Definitions
2.1 Measurement System. The total
equipment required for the determination of a
gas concentration or a gas emission rate. The
system consists of the following major
subsystems:
2.1.1 Sample Interface. That portion of a
system that is used for one or more of the
following: sample acquisition, sample
transportation, sample conditioning, or
protection of the analyzers from the effects of
the stack effluent.
2.1.2 NO, Analyzer. That portion of the
system that senses NO, and generates an
output proportional to the gas concentration.
2.1.3 O2 Analyzer. That portion of the
system that senses Oj and generates an
output proportional to the gas concentration.
2.2 Span Value. The upper limit of a gas
concentration measurement range that is
specified for affected source categories in the
applicable part of the regulations.
2.3 Calibration G««. A known
concentration of a gas in an appropriate
diluent gas.
2A Calibration Error. The difference
between the gas concentration indicated by
tbe measurement system and the known
concentration of the calibration gas.
2.5 Zero Drift The difference in the
measurement system output readings before
and after a stated period of operation during
which no unscheduled maintenance, repair,
or adjustment took place and the input
concentration at the time of the
measurements was zero.
2.8 Calibration Drift. The difference in the
measurement system output readings before
and after a stated period of operation during
which no unscheduled maintenance, repair,
or adjustment took place and the input at the
time of 95"C)
stainless steel or Teflon *.bing to transport
the sample gas to the sample conditioners
and analyzers.
4.1.3 Calibration Valve Assembly. A
three-way valve assembly to direct the zero
and calibration gases to the sample
conditioners and to the analyzers. The
calibration valve assembly shall be capable
of blocking the sample gas flow and of
introducing calibration gases to the
measurement system when in the calibration
mode.
4.1.4 NO2 to NO Converter. That portion
of the system that converts the nitrogen
dioxide (NOa) in the sample gas to nitrogen
oxide (NO). Some analyzers are designed to
measure NO, as NO, on a wet basis and can
be used without an NO» to NO converter or a
moisture removal trap provided the sample
line to the analyzer is heated (>95°C) to the
inlet of the analyzer. In addition, an NOa to
NO converter is not necessary if the NO>
portion of the exhaust gas is less than 5
percent of the total NO, concentration. As »
guideline, an NO» to NO converter is not
necessary if the gas turbine is operated at 90
percent or more of peak load capacity. A
converter is necessary under lower load
conditions.
4.1.5 Moisture Removal Trap. A
refrigerator-type condenser designed to
continuously remove condense te from the
sample gas. The moisture removal trap is not
necessary for analyzers that can measure
NO, concentrations on a wet basis; for these
analyzers, (a) heat the sample line up to the
inlet of the analyzers, (b) determine the
moisture content using methods subject to tht
approval of the Administrator, and (c) correc-
the NO, and Ot concentrations to a dry basis
4.1.6 Participate Filter. An in-slack or an
out-of-stack glass fiber filter, of the type
specified in EPA Reference Method 5:
however, an out-of-stack filter is
recommended when the stack gas
temperature exceeds 250 to 300°C.
4.1.7 Sample Pump. A nonreactive leak-
free sample pump to pull the sample gas
through the system at a flow rate sufficient it
minimize transport delay. The pump shall be
made from stainless steel or coated with
Teflon or equivalent.
4.1.8 Sample Gas Manifold. A sample gas
manifold to divert portions of the sample gas
stream to the analyzers. The manifold may be
constructed of glass, Teflon, type 316
stainless steel, or equivalent.
4.1.8 Oxygen and Analyzer. An analyzer
to determine the percent O, concentration of
the sample gas stream.
4.1.10 Nitrogen Oxides Analyzer. An
analyzer to determine the ppm NO,
concentration in the sample gas stream.
4.1.11 Data Output. A strip-chart recorder,.
analog computer, or digital recorder for
recording measurement data.
4.2 Sulfur Dioxide Analysis. EPA
Reference Method 6 apparatus and reagents.
4.3 NO, Caliberation Gases. The
calibration gases for the NO, analyzer may
be NO in N,, NO, in air or N,, or NO and NO,
Ill-Appendix A-85
-------
in Nj. For NO. measurement analyzers thai
require oxidation of NO to NO,, the
< alibration gases must be in the form of NO
in Nz. Use four calibration gas mixtures as
specified below:
4.3.1 High-level Gas. A gas concentration
that is equivalent to 80 to 90 percent of the
spun value.
4.3.2 Mid-level Gas. A gas concentration
that is equivalent to 45 to 55 percent of the
span value.
4.3.3 Low-level Gas. A gas concentration
that is equivalent to 20 to 30 percent of the
span value.
4.3.4 Zero Gas. A gas concentration of
less than 0.25 percent of the span value.
Ambient air may be used for the NO, zero
g.is.
4.4 Oi Calibration Gases. Use ambient air
-------
calibration valve until all readings are stable
then, switch to monitor the stack effluent
until a stable reading can be obtained.
Record the upscale response time. Next,
introduce high-level calibration gas into the
system. Once the system has stabilized at the
high-level concentration, switch to monitor
the stack effluent and wait until a stable
lalue is reached. Record the downscale
response time Repeat the procedure three
times A stable value is equivalent to a
change of less than 1 percent of span value
for 30 seconds or less than 5 percent of the
measured average concentration for 2
minutes Record the response time data on a
form similar to Figure 20-5, the readings of
the upscale or downscale reponse time, and
report the greater time as the "response time"
for the analyzer. Conduct a response time
test prior to the initial field use of the
measurement system, and repeat if changes
are made in the measurement system.
Date of test.
Analyzer type.
Span gas concentration.
Analyzer span setting_
Upscale
1.
2
3.
. S/N.
.ppm
ppm
.seconds
.seconds
.seconds
Average upscale response.
1
Downscale 2
3
.seconds
. seconds
.seconds
. seconds
Average downscale response.
.seconds
System response time = slower average time =.
.seconds.
Figure 20 5. Response time
5 ti NOj NO Conversion Efficiency
Introduce to the system, at the calibration
valve assembly, the NOS/NO gas mixture
(Section 4.5). Record the response of the NOX
analyzer. If the instrument response indicates
less than 90 percent NO, to NO conversion.
make corrections to the measurement system
and repeat the check. Alternatively, the NO,
to NO converter check described in Title 40
Part 86- Certification and Test Procedures for
Heavy-Duty Engines for 1979 and Later
Mode! Years may be used. Other alternate
procedures may be used with approval of the
Administrator.
6 Emission Measurement Test Procedure
6.1 Preliminaries.
6.1.1 Selection of a Sampling Site. Select a
sampling site as close as practical to the
exhaust of the turbine. Turbine geometry,
stack configuration, internal baffling, and
point of introduction of dilution air will vary
for different turbine designs. Thus, each of
these factors must be given special
consideration in order to obtain a
representative sample. Whenever possible,
the sampling site shall be located upstream of
the point of introduction of dilution air into
the duct. Sample ports may be located before
or after the upturn elbow, in order to
accommodate the configuration of the turning
vanes and baffles and to permit a complete,
unobstructed traverse of the stack. The
sample ports shall not be located within 5
feet or 2 diameters (whichever is less) of the
gas discharge to atmosphere. For
supplementary-fired, combined-cycle plants.
the sampling site shall be located between
the gas turbine and the boiler. The diameter
of the sample ports shall be sufficient to
allow entry of the sample probe.
6.1.2 A preliminary Oi traverse is made
for the purpose of selecting low O, values.
Conduct this test at the turbine condition that
is the lowest percentage of peak load
operation included in the program. Follow the
procedure below or alternative procedures
subject to the approval of the Administrator
may be used:
6.1.2.1 Minimum Number of Points. Select
a minimum number of points as follows: (!)
eight, for stacks having cross-sectional areas
less than 1.5 m'fie.l ft1); (2) one sample point
for each 0.2 m' (2.2 ft' of areas, for stacks of
1.5 mMo 10.0 m'tie.l-lOT.e ftl in cross-
sectional area: and (3) one sample point for
each 0.4 m2(4.4 ft2) of area, for stacks greater
than 10.0 m 2 (107.6 ft *) in cross-sectional
area. Note that for circular ducts, the number
of sample points must be a multiple of 4. and
for rectangular ducts, the number of points
must be one of those listed in Table 20-2:
therefore, round off the number of points
(upward), when appropriate
6.1.2.2 Cross-sectional Layout and
Location of Traverse Points. After the number
of traverse points for the preliminary O2
sampling has been determined, use Method 1
to located the traverse points.
8.1.2.3 Preliminary O2 Measurement.
While the gas turbine is operating at the
lowest percent of peak load, conduct a
preliminary O1 measurement as follows:
Position the probe at the first traverse point
and begin sampling. The minimum sampling
time at each point shall be 1 minute plus the
average system response time. Determine the
average steady-state concentration of O'at
each point and record the data on Figure 20-
6.
6.1.2.4 Selection of Emission Test
Sampling Points. Select the eight sampling
points at which the lowest O2 concentration
were obtained. Use these same points for all
the test runs at the different turbine load
conditions More than eight points may be
used, if desired.
Table 20-iCross-secbonal Layout tor
Rectangular Stacks
No of traverse pomfe.
9
12._
16
20
25
30
38
42
49 . ..
Hmtm
3x3
4x3
4x4
5x4
5x5
6x5
8x6
7x6
7«7
Ill-Appendix A-87
-------
5.3 Calibration Check. Conduct the
calibration checks for both the NO, and the
Oi analyzers as follows:
5.3,1 After the measurement system has
been prepared for use (Section 5.2), introduce
zero gases and the mid-level calibration
gases; set the analyzer output responses to
the appropriate levels. Then introduce each
of the remainder of the calibration gases
described in Sections 4.3 or 4.4, one at a time.
to the measurement system. Record the
responses on a form similar to Figure 20-3.
5.3.2 If the linear curve determined from
the zero and mid-level calibration gas
responses does not predict the actual
response of the low-level (not applicable for
the Cs analyzer) and high-level gases within
±2 percent of the span value, the calibration
shall be considered invalid. Take corrective
measures on the measurement system before
proceeding with the test.
5.4 Interference Response. Introduce the
gaseous components listed in Table 20-1 into
the measurement system separately, or as gas
mixtures. Determine the total interference
output response of the system to these
components in concentration units; record the
values on a form similar to Figure 20-4. If the
sum of the interference responses of the test
gases for either the NO, or Oa analyzers is
greater than 2 percent of the applicable span
value, take corrective measure on the
measurement system.
Table 20-1.Interference Tost Gas Concentration
CO 500±50 ppm
SO,._ _ 200±20 ppm.
CO, _., 10-t 1 percent
O,._ _ 20 9± 1
percent
Trtt 9%
type
Ct*tc«<\lta*inn
Finite 20 4 Interlereirce retpon*
Turbine type:.
Date:
Identification number.
Test number
Analyzer type:.
Identification number.
Cylinder Initial analyzer Final analyzer Difference:
value, response, responses, initial-final,
ppm or % ppm or % ppm or % ppm or %
Zero gas
Low level gas
Mid - level gas
High - level gas
Percent drift =
Figure 20-3.
Absolute difference
X 100.
Span value
Zero and calibration data.
Conduct an interference response test of
each analyzer prior to its initial use in the
field. Thereafter, recheck the measurement
system if changes are made in the
instrumentation that could alter the
interference response, e.g., changes in the
type of gas detector.
In lieu of conducting the interference
response test, instrument vendor data, which
demonstrate that for the test gases of Table
20-1 the interference performance
specification is not exceeded, are acceptable.
53 Residence and Response Time.
5.5.1 Calculate the residence time of the
sample interface portion of the measurement
system using volume and pump flow rate
information. Alternatively, if the response
time determined as defined in Section 5.5.2 is
less than 30 seconds, the calculations are not
necessary.
6.5.2 To determine response time, first
introduce zero gas into the system at the
Ill-Appendix A-88
-------
Location:
Plant.
Date.
City. State.
Turbine identification:
Manufacturer
Model, serial number.
Sample point
Oxygen concentration, ppm
Figure 20-6. Preliminary oxygen traverse.
6.Z NO, and O, Measurement. This test is
to be conducted at each of the specified load
conditions. Three test runs at each load
condition constitute a complete test.
6.2.1 At the beginning of each NO, test
run and. as applicable, during the run, record
turbine data as indicated in Figure 20-7. Also.
record the location and number of the
traverse points on a diagram.
6.2.2 Position the probe at the hrst point
determined in the preceding section and
begin sampling. The minimum sampling time
at each point shall be at least 1 minute plus
the average system response time. Determine
the average steady-state concentration of O,
and NO, at each point and record the data on
Figure 20-8.
Ill-Appendix A-89
-------
TURBINE OPERATION RECORD
Test operator Date
Turbine identification:
Type
Serial No
Location:
Plant
City
Ultimate fuel
Analysis C
H
Ambient temperature.
Ambient humidity
Test time start
Ash
H2O
Trace Metals
Na
Test time finish.
Fuel flow ratea_
Va
etcc
Water or steam.
Flow rate3
Ambient Pressure.
Operating load.
aDescribe measurement method, i.e., continuous flow meter,
start finish volumes, etc.
bi.e.( =«dditional elements added for smoke suppression.
Figure 20-7. Stationary gas turbine data.
Turbine identification:
Manufacturer
Test operator name.
©2 instrument type.
Serial No.
type.
Location:
Sample
r>. point
Plant K
Pity StatP
Amhipnt tpmppraturp
Amhipnt prp«nrp
HatP
Test timp -start
Time,
min.
ojl
3
ppm
Test time -finish.
a Aver age steady-state value from recorder or
instrument readout.
Figure 20-8. Stationary gas turbine sample point record.
Ill-Appendix A-90
-------
6.2.3 After sampling the last point,
conclude the test run by recording the final
turbine operating parameters and by
determining the zero and calibration drift, as
follows:
Immediately following the test run at each
load condition, or if adjustments are
necessary for the measurement system during
the tests, reintroduce the zero and mid-level
calibration gases as described in Sections 4.3,
and 4.4, one at a time, to the measurement
system at the calibration valve assembly.
(Make no adjustments to the measurement
system until after the drift checks are made).
Record the analyzers' responses on a form
similar to Figure 2O-3. if the drift values
exceed the specified limits, the test run
preceding the check is considered invalid and
will be repeated following corrections to the
measurement system. Alternatively, the test
results may be accepted provided the
measurement system is recalibrated and the
calibration data that result in the highest
corrected emission rate are used.
6.3 SOi Measurement. This test is
conducted only at the 100 percent peak load
condition. Determine SO, using Method 6, or
equivalent, during the test. Select a minimum
of six total points from those required for the
NO, measurements; use two points for each
sample run. The sample time at each point
shall be at least 10 minutes. Average the O>
readings taken during the NO, test runs at
sample points corresponding to the SO>
traverse points (see Section 6.Z.2) and use
this average O, concentration to correct the
integrated SO, concentration obtained by
Method 6 to 15 percent O, (see Equation 20-
1).
If the applicable regulation allows fuel
sampling and analysis for fuel sulfur content
to demonstrate compliance with sulfur
emission unit, emission sampling with
Reference Method 6 is not required, provided
the fuel sulfur content meets the limits of the
regulation.
7. Emission Calculations
7.1 Correction to 15 Percent Oxygen.
Using Equation 20-1, calculate the NO, and
SO, concentrations (adjusted to 15 percent
Oi). The correction to 15 percent O, is
sensitive to the accuracy of the O,
measurement. At the level of analyzer drift
specified in the method (±2 percent of full
scale), the change in the O, concentration
correction can exceed 10 percent when the O«
content of the exhaust is above 16 percent O,.
Therefore O, analyzer stability and careful
calibration are necessary.
5.!.
"
(Equation 2C-1)
Where:
CM=Pollutant concentration adjusted to
15 percent Oa (ppm)
Cm^ = Pollutant concentration measured,
dry basis (ppm)
5.9=20.9 percent Oj-15 percent Oa, the
defined O, correction basis
Percent Oa=Percent O, measured, dry
basis (%)
7.2 Calculate the average adjusted NO,
concentration by summing the point values
and dividing by the number of sample points.
ft Citations
8.1 Curtis, F. A Method for Analyzing NO,
Cylinder Gases-Specific Ion Electrode
Procedure, Monograph available from
Emission Measurement Laboratory, ESED,
Research Triangle Park, N.C. 27711, October
1978.
III-Appendix A-91
-------
18
APPENDIX BPERFORMANCE SPECIFICATIONS
Performance Specification 1Performance
specifications and specification test proce-
dures for transmissometer systems for con-
tinuous measurement of the opacity of
stack emissions 23
1. Principle and Applicability.
1.1 Principle. The opacity of particulate
matter In stack emissions is measured by a
continuously operating emission measure-
ment system. These systems are based upon
the principle of transmissometry which is a
direct measurement of the attenuation cf
visible radiation (opacity) by particulate
matter In a stack effluent. Light having spe-
cfic spectral characteristics is projected from
a lamp across the stack of a pollutant source
to a light sensor. The light Is attenuated due
to absorption and scatter by the particulate
matter in the effluent The percentage of
visible light attenuated Is defined as the
opacity of the emission. Transparent stack
emissions that do not attenuate light will
have a transmittance of 100 or an opacity of
0. Opaque stack emissions that attenuate all
of the visible light will have a transmittance
of 0 or an opacity of 100 percent. The trans-
missometer is evaluated by use of neutral
density filters to determine the precision of
the continuous monitoring system. Tests of
the system are performed to determine zero
drift, calibration drift, and response time
characteristics of the system.
1.2 Applicability. This performance spe-
cification is applicable to the continuous
monitoring systems specified in the subparts
for measuring opacity cf emissions. Specifi-
cations for continuous measurement of vis-
ible emissions are slx'en in terms of design,
performance, and Installation parameters.
These specifications contain test procedures,
installation requirements, and data compu-
tation procedures for evaluating the accept-
ability of the continuous monitoring systems
subject to approval by the Administrator.
2. Apparatus.
2.1 Calibrated Filters. Optical filters with
neutral spectral characteristics and known
optical densities to risible light or screens
known to produce specified optical densities
Calibrated filters with accuracies certified by
the manufacturer to within -±3 percent
opacity shall be used Filters required are
low, mid, and high-range filters with nom-
inal optical densities as follows when the
transmissometer is spanned at opacity levels
specified by applicable subparts:
Calibrated filler optical densities
with equivalent opacity in
Span value parenthesis
50 .
CO. ...
70
80
"0
100
Low-
range
0.1 (20)
1 CO)
. 1 (20)
1 (20)
.1 (20)
.1 (20)
Mid-
ranpc
0 2 (37)
2 '37)
3 (50)
3 (50)
4 (60)
4 (60)
HlCh-
ranpe
0 3 <59)
.3 I.W)
4
-------
monitor pathlength. The graph necessary to
convert the data recorder output to the
monitor pathlength-basis shall be established
as follows:
log (1-0,) =(!,/!.) log (1-0-0
where:
Oj = the opacity of the effluent based upon
^i-
0, = the opacity of the effluent based upon
l, = the emission outlet pathlength.
I2 = the monitor pathlength.
5. Optical Design Specifications.
The optical design specifications set forth
in Section 6.1 shall be met in order for a
measurement system to comply with the
requirements of this method
6. Determination of Conformance with De-
sign Specifications.
6 1 The continuous monitoring system for
measurement of opacity shall be demon-
strated to conform to the design specifica-
tions set forth as follows:
6.1.1 Peak Spectral Response. The peak
spectral response of the continuous moni-
toring systems shall occur between 500 nm
and 600 nm. Response at any wavelength be-
low 400 nm or above 700 nm shall be less
than 10 percent of the peak response of the
continuous monitoring system.
6.1.2 Mean Spectral Response. The mean
spectral response of the continuous monitor-
ing system shall occur between 500 nm and
600 nm.
6.1.3 Angle of View. The total angle of view
shall be no greater than 5 degrees.
6.1.4 Angle of Projection The total angle
of projection shall be no greater than 5 de-
gress
6.2 Conformance with the requirements
of se'ction 6.1 may be demonstrated by the
owner or operator or the affected facility by
testing each analyzer or by obtaining a cer-
tificate of conformance from the Instrument
manufacturer. The certificate must certify
that at least one analyzer from each month's
production was tested and satisfactorily met
all applicable requirements. The certificate
must state that the first analyzer randomly
Eampled met all requirements of paragraph
6 of this specification. If any of the require-
ments were not met, the certificate must
show that the entire month's analyzer pro-
duction was resampled according to the mili-
tary standard 105D sampling procedure
(MIL-STD-105D) Inspection level II; was re-
tested for each of the applicable require-
ments under paragraph 6 of this specifica-
tion; and was determined to be acceptable
under MTL-STD-105D procedures The certifi-
cate of conformance must show the results
of each test performed for the analyzers
sampled during the month the analyzer be-
ing Installed was produced. 57
6.3 The general test procedures to be foj-
lowed to demonstrate conformance with Sec-
tion 6 requirements are given as follows
(These procedures will not be applicable to
all designs and will require modification in
some cases. Where analyzer and optical de-
sign is certified by the manufacturer to con-
form with the angle of view or angle of pro-
jection specifications, the respective pro-
cedures may be omitted.)
6.3.1 Spectral Response. Obtain spectral
data for detector, lamp, and filter components
used in the measurement system from their
respective manufacturers
6.3.2 Angle of View. Set the received up
as specified by the manufacturer. Draw an
arc with radius of 3 meters. Measure the re-
ceiver response to a small (less than 3
centimeters) non-directional light source at
5-centimeter intervals on the arc for 26 centi-
meters on either side of the detector center-
line. Repeat the test in the vertical direction.
6.3.3 Angle of Projection. Set the projector
up as specified by the manufacturer. Draw
an arc with radius of 3 meters. Using a small
photoelectric light detector (less than 3
centimeters), measure the light intensity at
5-centimeter intervals on the arc for 26
centimeters on either side of the light source
centerline of projection. Repeat the test in
the vertical direction.
7 Continuous Monitoring System Per-
formance .Specifications
The continuous monitoring system shall
meet the performance specifications in Table
1-1 to be considered acceptable under <-»r,
TABLE 1-1. Performance
Parameter
Specifications
a. . Calibration error. - - <3 pet opacity '
h Zoro drift (24 h) <2 pot opacity '
(.Calibration drift (24 h) <2 pet opacity >
d Response time 10 s (maximum)
p. Opoiational test period 168 h.
i Expressed as sum of absolute mean value and the
95 pet confidence interval of a series of tesls
8. Performance Specification Test Proce-
dures. The following test procedures shall be
used to determine conformance with the re-
quirements of paragraph 7:
8.1 Calibration Error and Response Time
Test. These tests are to be performed prior to
installation of the system on the stack and
may be performed at the affected facility or
at other locations provided that proper notifi-
cation is given. Set up and calibrate the
measurement system as specified by the
manufacturer's written instructions for the
monitor pathlength to be used in the in-
stallation. Span the analyzer as specified In
applicable subparts.
8.1.1 Calibration Error Test. Insert a series
of calibration filters in the transmissometer
path at the midpoint A minimum of three
calibration filters (low, mid, and high-
range) selected in accordance with the table
ii"der paragraph 2.1 and calibrated within
3 percent must be used. Make a total of five
ni"consecutive readings for each filter
Record the measurement system output
readings In percent opacity. (See Figure 1-1.)
8.1.2 "System Response Test. Insert the
high-range filter la the trausmissometer
path five times and record the time required
for the system to respond to 95 percent of
final zero and high-range filter values. (See
Figure 1-2.)
8.2 Field-Test for Zero Drift and Calibra-
tion Drift. Install the continuous monitoring
system on the affected facility and perform
the following alignments:
8.2.1 Preliminary Alignments. As soon as
possible after installation and once a year
thereafter wben the facility is not in opera-
tion, perform the following optical and zero
alignments:
82.1.1 OpUcal Alignment. Align the light
beam from trie trausmissometer upon the op-
tical surfaces located across the effluent (i.e.,
the rctroflector or pbotodetector as applica-
ble) in accordance with the manufacturer's
instructions.
8.2.1.2 Zero Alignment. After the transmis-
someter has been optically aligned and the
transmissometer mounting Is mechanically
stable (I.e.. no movement of the mounting
due to thermal contraction of the stack,
duct, etc.) and a clean stack condition has
been determined by a steady zero opacity
condition, perform the zero alignment. This
alignment is performed by balancing the con-
tinuous monitor system response so that any
simulated zero check coincides with an ac-
tual zero check performed across the moni-
tor pathlength of the clean stack.
8.2.1.3 Sptvn. Span the continuous monitor-
ing system at the opacity specified in sub-
parts and offset the zero setting at least 10
percent ol span so that negative drift can be
quantified.
8.2.2. Final Allgnra«nts. After the prelimi-
nary alignments have been completed and the
affected facility lias been started up and.
reaches normal operating temperature, re-
check Uie optical alignment in accordance
with 8.2.1 1 of this specification. If the align-
ment has shifted, realign the optics, record
any detectable shift in the opacity measured
by the system that can be attributed to the
optical realignment, and notify the Admin-
istrator. This condition may not be objec-
tionable If the affected facility operates with-
in a fairly constant and adequately narrow
range of operating temperatures that doe:;
not produce significant shifts in optical
alignment during normal operation of the
facility. Onder circumstances where the facil-
ity operations produce fluctuations In the
effluent gas temperature that result in sig-
nificant misalignments, the Administrator
may require improved mounting structures or
another location for Installation of the trans-
missometer.
8.2.3 Conditioning Period. After complet-
ing the post-startup alignments, operate the
system for an Initial 168-hour conditioning
period in a normal operational manner.
8.2.4 Operational Test Period. After com-
pleting the conditioning period, operate the
system for an additional 168-hour period re-
taining the zero offset. The system shall mon-
itor the source effluent at all times except
when being zeroed or calibrated. At 24-hour
Intervals the zero and span shall be checked
according to the manufacturer's instructions.
Minimum procedures used shall provide a
system check of the analyzer internal mirrors
and all electronic circuitry including the
lamp acd photodetector assembly and shall
include a procedure for producing a simu-
lated zero opacity condition and a simulated
upscale (span) opacity condition as viewed
by the receiver. The manufacturer's written
instructions may be used providing that they
equal or exceed these minimum procedures.
Zero and span the transmissometer, clean all
optical surfaces exposed to the effluent, rea-
lign optics, and make any necessary adjust-
ments to the calibration of the system dally.
These zero and calibration adjustments and
optical realignments are allowed only at 24-
hour intervals or at such shorter Intervals as
the manufacturer's written instructions spec-
ify. Automatic corrections made by the
measurement system without operator Inter-
vention are allowable at any time. The mag-
nitude of any zero or span drift adjustments
shall be recorded. During this 168-hour op-
erational test period, record the following at
24-hour intervals: (a) the zero reading and
span readings after the system is calibrated
(these readings should be set at the same
value at the beginning of each 24-hour pe-
riod);, (b) the zero reading after each 24
hours of operation, but before cleaning and
adjustment; and (c) t*e scan reading after
cleaning and zero adjustment, but before
span adlustment. (See Figure 1-3.)
9. Calculation, Data Analysis, and Report-
ing.
9.1 Procedure for Determination of Mean
Values and Confidence Intervals.
9.1.1 Trie mean value of the data set is cal-
culated according to equation 1-1.
1 "
5=nS*;
1=1 Equation 1-1
where x.:~ absolute value of the individual
measurements.
2=sum ot the individual values.
x=rmean value, and
n=nurnber of data points.
23
9.1.2 The 95 percent confidence interval
(two-sided) is calculated according to equa-
tion 1-2:
Equation 1-2
where
2x, = sum of all data points,
1975 = 1.1 a/2, and
C.I.«s=95 percent confidence interval
estimate of the average mean
value.
The values in this table are already cor-
rected for n-1 degrees of freedom. Use n equal
to the number of samples as data points.
Ill-Appendix B-2
-------
Values for 1.975
n
2
3
4
5
H
g
9 . .
'.975
12.706
4 303
3 38°
2 776
2 S71
2 447
2 365
2.306
n
10.
11
13
14
15.
16
'.975
2 262
2 07g
9 9Q1
' 179
2 160
2 145
2 131
9 2 Data Analysis and Reporting.
9.2.1 Spectral Response. Combine the
spectral data obtained In accordance with
paragraph 6.3.1 to develop the effective spec-
tral response curve of the transmissometer.
Report the wavelength at which the peak
response occurs, the wavelength at which the
mean response occurs, and the maximum
response at any wavelength below 400 nm
and above 700 nm expressed as a percentage
Date of Test
of the peak response as required under para-
graph 6.2.
9.2.2 Angle of View. Using the data obtained
In accordance with paragraph 6.3.2, calculate
the response of the receiver as a function of
viewing angle In the horizontal and vertical
directions (26 centimeters of arc with a
radius of 3 meters equal 5 degrees). Report
relative angle of view curves as required un-
der paragraph 6.2.
92.3 Angle of Projection. Using the data
obtained In accordance with paragraph 6.3.3,
calculate the response of the photoelectric
detector as a function of projection angie in
the horizontal and vertical directions. Report
relative angle of projection curves as required
under paragraph 6.2.
9.2 4 Calibration Error. Using the data from
paragraph 8.1 (Figure 1-1), subtract the
known filter opacity value from the value
shown by the measurement system for each
of the 15 readings. Calculate the mean and
95 percent confidence interval of the five dif-
ferent values at each test filter value accord-
Low Mid
Range % opacity Range
Span Value % opacity
_% opacity
High
Range
J> opacity
Location of Test
Calibrated Filter
Analyzer Reading
% Opacity
Differences
% Opacity
ls
Mean difference
Confidence interval
Calibration error = Mean Difference + C.I.
Low
Hid
High
Low, mid or high range
Calibration filter opacity - analyzer reading
Absolute value
Figure 1-1- Calibration Error Test
ing to equatirns 11 and 1-2. Report the sum
of the absolute mean difference and the 95
percent confidence interval for each of the
three test filters.
o«t« of Tm
Stun FIU.r
_ Sftonds
_ UCMdt
_ SKOndl
socondl
Second*
_ seconds
_ sccords
.second
SKMdt
Ff^vre !-?. RnpntiM TIM Tnt
9.2.5 Zero Drift. Using the zero opacity
values measured every 24 hours during the
field test (paragraph 8.2), calculate the dif-
ferences between the zero point after clean-
Ing, aligning, and adjustment, and the zero
value 24 hours later just prior to cleaning,
aligning, and adjustment Calculate the
mean value of these points and the confi-
dence interval using equations 1 -1 and 1-2.
Report the sum of the absolute mean value
and the 95 percent confidence interval
9.26 Calibration Drift Using the span
value measured every 24 hours during the
field test, calculate the differences between
the span value after cleaning, aligning, and
adjustment of zero and span, and the span
value 24 hours later just after cleaning
aligning, and adjustment of zero and before
adjustment of span. Calculate the mecn
value of these points and the confidence
interval using equations 1-1 and 1-2 Report
the sum of the absolute mean value and the
confidence interval.
9 2.7 Response Time. Using the data from
paragraph 8.1, calculate the time internal
from filter Insertion to 95 percent of the final
stable value for all upscale and downscale
traverses Report the mean of the 10 upscale
and downscale test times.
9.2.8 Operational Test Period. During the
168-hour operational test period, the con-
tinuous monitoring system shall not require
any corrective maintenance, repair, replace-
ment, or adjustment other than that clearly
specified RS required in the manufacturer's
operation and maintenance manuals as rou-
tine and expected during a one-week period.
If the continuous monitoring system Is oper-
ated within the specified performance pa-
rameters and does not require corrective
maintenance, repair, replacement, or adjust-
ment other than as specified above during
the 168-hour test period, the operational
test period shall have been successfully con-
cluded. Failure of the continuous monitor-
ing system to meet these requirements shall
call for a repetition of the 168-hour test
period. Portions of the tests which were sat-
isfactorily completed need not be repeated.
Failure to meet any performance specifica-
tion^) shall call for a repetition of the
one-week operational test period and that
specific portion of the tests required by
paragraph 8 related to demonstrating com-
pliance with the failed specification. All
maintenance and adjustments required shall
be recorded. Output readings shall be re-
corded before and after all adjustments.
10. References.
10.1 "Exoerimental Statistics," Department
of Commerce. National Bureau of Standards
Handbook 91, 1963, pp. 3-31, paragraphs
3-3.1.4.
10.2 "Performance Specifications for Sta-
tionary-Source Monitoring Systems for Gases
and Visible Emissions," Environmental Pro-
tection Agency, Research Triangle Park,
N.C., EPA-650/2-74-013, January 1974.
Ill-Appendix B-3
-------
Zero Setting
Span Setting
(Se< paragraph 8.2.1) Date of Test
Date Zero Reading Span Reading Calibration
and (Before cleaning Zero Drift (Aftnr clcfnlng and zero adjustment Drift
Time and adjustment) (iZero) but before span adjustment) (&Span)
Zero Drift » Mean Zero Drift* .
Calibration Drift « Mean Span Drift*
. * Cl (Zero)
+ CI (Span)
Absolute value
PERFORMANCE SPECIFICATION 2PERFORMANCE
SPECIFICATIONS AND SPECIFICATION TEST PRO-
CEDURES FOR MONITORS OF SOs AND NOx
FROM STATIONARY SOURCES
l Principle and Applicability.
1.1 Principle. The concentration of sulfur
dioxide or oxides of nitrogen pollutants in
stack emissions is measured by a continu-
ously operating emission measurement sys-
tem. Concurrent with operation of the con-
tinuous monitoring system, the pollutant
concentrations are also measured with refer-
ence methods (Appendix A). An average of
the continuous monitoring system data is
computed for each reference method testing
period and compared to determine the rela-
tive accuracy of the continuous monitoring
system. Other tests of the continuous mon-
itoring system are also performed to deter-
mine calibration error, drift, and response
characteristics of the system.
1.2 Applicability. This performance spec-
ification is applicable to evaluation of con-
tinuous monitoring systems for measurement
of nitrogen oxides or sulfur dioxide pollu-
tants These specifications contain test pro-
cedures, installation requirements, and data
computation procedures for evaluating the
acceptability of the continuous monitoring
systems.
2. Apparatus.
2 1 Calibration Gas Mixtures. Mixtures of
known concentrations of pollutant gas in a
diluent gas shall be prepared. The pollutant
gas shall be sulfur dioxide or the appropriate
oxide(s) of nitrogen specified by paragraph
6 and within subparts For sulfur dioxide gas
mixtures, the diluent gas may be air or nitro-
gen For nitric oxide (NO) gas mixtures, the
diluent gas shall be oxygen-free «10 ppm)
nitrogen, and for nitrogen dioxide (NO2) gas
mixtures the diluent gas shall be air. Concen-
trations of approximately 50 percent and 90
percent of span are required. The 90 percent
gas mixture is used to set and to check the
span and is referred to as the span gas.
2.2 Zero Gas. A gas certified by the manu-
facturer to contain less than 1 ppm of the
pollutant gas or ambient air may be used.
2 3 Equipment for measurement of the pol-
lutant gas concentration using the reference
method specified in the applicable standard.
2 4 Data Recorder. Analog chart recorder
or other suitable device with input voltage
range compatible with analyzer system out-
put The resolution of the recorder's data
output shall be sufficient to allow completion
of the test procedures within this specifi-
cation.
2.5 Continuous monitoring system for SO,
or NO^ pollutants as applicable.
3. Definitions
3.1 Continuous Monitoring System. The
total equipment required for the determina-
tion of a pollutant gas concentration in a
source effluent. Continuous monitoring sys-
tems consist of major subsystems as follows'
3.1.1 Sampling InterfaceThat portion of
an extractive continuous monitoring system
that performs one or more of the following
operations: acquisition, transportation, and
conditioning of a sample of the source efflu-
ent or that portion of an in-situ continuous
monitoring system that protects the analyzer
from the effluent.
3.1.2 AnalyzerThat portion of the con-
tinuous monitoring system which senses the
pollutant gas and generates a signal output
that is a function of the pollutant concen-
tration
3.1.3 Data RecorderThat portion of the
continuous monitoring system that provides
a permanent record of the output signal in
terms of concentration units
3.2' Span. The value of pollutant concen-
tration at which the continuous monitor-
ing system is set to produce the maximum
data display output. The span shall be set
at the concentration specified in each appli-
cable subpart
3.3 Accuracy (Relative). The degree of
correctness with which the continuous
monitoring system yields the value of gas
concentration of a sample relative to the
value given by a denned reference method.
TJiis accuracy is expressed in terms of error,
which is the difference between the paired
concentration measurements expressed as a
percentage of the mean reference value.
3.4 Calibration Error. The difference be-
tween the pollutant concentration mdi-
catec. by the continuous monitoring system
and the known concentration of the test
gas mixture.
3.5 Zero Drift. The change in the continu-
ous monitoring system output over a stated
period of time of normal continuous opera-
tion when the pollutant concentration at
the time for the measurements is zero.
3 6 Calibration Drift The change in the
continuous monitoring system output over
a ste,ted time period of normal continuous
operations when the pollutant concentra-
tion at the time of the measurements is the
same scnown upscale value.
3.7 Response Time. The time interval
from a step change in pollutant concentra-
tion at the input to the continuous moni-
toring system to the time at which 95 per-
cent of the corresponding final value is
reached as displayed on the continuous
mom (ori^g system data recorder.
3 8 Operational Period A minimum period
of time over which a measurement system
is expected to operate within certain per-
formance specifications without unsched-
uled maintenance, repair, or adjustment.
3 9 Stratification. A condition identified
by a difference in excess of 10 percent be-
tween the average concentration in the duct
or stack-and the concentration at any point
more than 1.0 meter from the duct or stack
wall.
4 Installation Specifications. Pollutant
cont.nuous monitoring systems (SO, and
NOy) shall be installed at a sampling^ loca-
tion where measurements can be made which
are d.rectly representative (41), or which
can be corrected so as to be representative
(42) of the total emissions from the affected
facility. Conformance with this requirement
shall be accomplished as follows:
4 1 Effluent gases may be assumed to be
nonsti-atified if a sampling location eight or
more stack diameters (equivalent diameters)
dowiu,tr»am of any air in-leakage is se-
lected. This assumption and data correction
proce'tlures under paragraph 4.2 1 may not
be applied to sampling locations upstream
of an air preheater in a steam generating
facility under Subpart D of this part. For
sampling locations where effluent gases are
either demonstrated (43) or may be as-
sumed to be nonstratifiea (eight diameters),
a poir.t (extractive systems) or path (m-situ
systems) of average concentration may be
monitored. 23
4 2 For sampling locations where effluent
gases cannot be assumed to be nonstrati-
fied (less than eight diameters) or have been
shown under paragraph 4.3 to be stratified,
results obtained must be consistently repre-
sentative (e.g. a point of average concentra-
tion may shift with load changes'! or the
data generated by sampling at a point (ex-
tractive systems) or across a path (in-situ
systems) must be corrected (4.2.1 and 422)
so as to be representative of the total emis-
sions from the affected facility. Conform-
ance with this requirement may be accom-
plished in either of the following ways
4 2 l Installation of a diluent continuous
monitoring system (O,, or CO,, as applicable)
in accordance with the procedures under
paragraph 4 2 of Performance Specification
3 of this appendix. If the pollutant and
diluent monitoring systems are not of the
same type (both extractive or both in-situ),
the extractive system must use a. multipoint
probe.
422 Installation of extractive pollutant
monitoring systems using multipoint sam-
pling probes or in-situ pollutant monitoring
systems that sample or view emissions which
are consistently representative of the total
emissions for the entire cross section. The
Administrator may require data to be sub-
III-Appendix E-4
-------
mitted to demonstrate that the emissions
sampled or viewed are consistently repre-
sentative for several typical facility process
operating conditions.
4.3 The owner or operator may perform a
traverse to characterize any stratification of
effluent gases that might exist In a stack or
duct. If no stratification Is present, sampling
procedures under paragraph 4.1 may be ap-
plied even though the eight diameter criteria
is not met.
4.4 When single point sampling probes for
extractive systems axe Installed within the
stack or duct under paragraphs 4.1 and 4.2.1,
the sample may not be extracted at any point
less than 1.0 meter from the stack or duct
wall. Multipoint sampling probes installed
under paragraph 4.2.2 may be located at any
points necessary to-obtain consistently rep-
resentative samples.
5. Continuous Monitoring System Perform-
ance Specifications.
The continuous monitoring system shall
meet the performance specifications in Table
2-1 to be considered acceptable under "this
method.
TABLE 2-1.Performance specifications
Parameter
Specification
1. Accoracy'
?. Calibration error'.
3. Zero drift (2 h) i
!. Zero drift (24 h) i
5. Calibration drift (2h)'.
8 Calibration drift (24 h) i
7. Response time
8. Operational period
<20 pet of the mean value of the reference method test
data.
< 5 pot of each (50 pet, 90 pet) calibration gas miiture
value.
2 pet of span
Do.
Do.
2.5 pet. of span
15 min maximum.
168 h minimum.
1 Expressed as sum of absolute mean value plus 95 pet confidence interval of a series of.tests.
6. Performance Specification Test Proce-
dures. The following test procedures shall be
used to determine conformance with the
requirements of paragraph 5. For NOX an-
requirements of paragraph 5. For NO» an-
alyzers that oxidize nitric oxide (NO) to
nitrogen dioxide (NO,), the response time
tt'st under paragraph 6.3 of this method shall
be performed using nitric oxide (NO) span
gas. Other tests for NO« continuous monitor-
Ing systems under paragraphs 6.1 and 6.2 and
all tests for sulfur dioxide systems shall be
performed using the pollutant span gas spe-
cified by each subpart.
6 1 Calibration Error Test Procedure. Set
up and calibrate the complete continuous
monitoring system according to the manu-
facturer's writen instructions. This may be
accomplished either in the laboratory or In
the field.
6.1.1 Calibration Gas Analyses. Triplicate
analyses of the gas mixtures shall be per-
furmed within two weeks prior to use using
Reference Methods 6 lor SO, and 7 for NOT.
\nalv2,e each calibration gas mixture (50%,
Gon>) and record the results on the example
sheet shown in Figure 2-1. Each sample test
result must be within 20 percent of the aver-
aged result or the tests shall be repeated.
This step may be omitted for non-extractive
monitors where dynamic calibration gas mix-
tures are not used (8 1.2)
6.1.2 Calibration Error Test Procedure.
Make a total of 15 nonconsecutlve measure-
ments by alternately using zero gas and each
;aliberatlon gas mixture concentration (e.g.,
3-c, 50%, 0%, 90%. 50%, 90%, 50%, 0%,
etc ). For nonextractive continuous monitor-
ing systems, this test procedure may be per-
formed by using two or more calibration gas
.ells whose concentrations are certified by
the manufacturer to be functionally equiva-
lent to these gas concentrations. Convert the
continuous monitoring system output read-
ings to ppm and record the results on the
example sheet shown in Figure 2-2.
6.2 Field Test for Accuracy (Relative),
Zero Drift, and Calibration Drift. Install and
operate the continuous monitoring system In
accordance with the manufacturer's written
instructions and drawings as follows:
6.2.1 Conditioning Period. Offset the zero
setting at least 10 percent of the span so
tnat negative zero drift can be quantified.
Operate the system for an initial 168-hour
conditioning period in normal operating
manner.
6.2.2 Operational Test Period. Operate the
continuous monitoring system for an addi-
tional 168-hour period retaining the zero
offset. The system shall monitor the source
effluent at all tunes except when being
zeroed, calibrated, or backpurged.
6.2.2.1 Field Test for Accuracy (Relative).
For continuous monitoring systems employ-
ing extractive sampling, the probe tip for the
continuous monitoring system and the probe
tip for the Reference Method sampling train
should be placed at adjacent locations in the
duct. For NOT continuous monitoring sys-
tems, make 27 NOX concentration measure-
ments, divided into nine sets, using the ap-
plicable reference method. No more than one
set of tests, consisting of three individual
measurements, shall be performed in any
one hour. All individual measurements of
each set shall be performed concurrently,
or within a three-minute interval and the
results averaged For SO, continuous moni-
toring systems, make nine SO, concentration
measurements using the applicable reference
method. No more than one measurement
shall be performed in any one hour. Record
the reference method test data and the con-
tinuous monitoring system concentrations
on the example data sheet shown In Figure
2-3.
6.2.22 Field Test for Zero Drift and Cali-
bration Drift. For extractive systems, deter-
mine the values given by zero and span gas
pollutant concentrations at two-hour inter-
vals until 15 sets of data are obtained. For
nonextractive measurement systems, the zero
value may be determined by mechanically
producing a zero condition that provides a
system check of the analyzer Internal mirrors
and all electronic circuitry including the
radiation source and detector assembly or
by Inserting three or more calibration gas
cells and computing the zero point from the
upscale measurements. If this latter tech-
nique is used, a graph(s) must be retained
by the owner or operator for each measure-
ment system that shows the relationship be-
tween the upscale measurements and the
zero point. The span of the system shall be
checked by using a calibration gas cell cer-
tified by the manufacturer to be function-
ally equivalent to 50 percent of span concen-
tration. Record the zero and span measure-
ments (or the computed zero drift) on the
example data sheet shown in Figure 2-4.
The two-hour periods over which measure-
ments are conducted need not be consecutive
but may not overlap. All measurements re-
quired under this paragraph may be con-
ducted concurrent with tests under para-
graph 6.2.2.1.
6.2.2.3 Adjustments. Zero and calibration
corrections and adjustments are allowed only
at 24-hour Intervals or at such shorter In-
tervals as the manufacturer's written in-
structions specify. Automatic conectlons
made by the measurement system without
operator intervention or initiation are allow-
able at any time. During the, entire 168-hour
operational test period, record on the ex-
ample sheet shown in Figure 2-5 the values
given by zero and span gas pollutant con-
centrations before and after adjustment at
24-hour intervals.
6.3 Field Test for Response Time.
6.3.1 Scope of Test. Use the entire continu-
ous monitoring system as Installed, including
sample transport lines if used. Flow rates,
line diameters, pumping rates, pressures (eta
not allow the pressurized calibration gas to
change the normal operating pressure In the
sample line), etc., shall be at the nominal
values for normal operation as specified in
the manufacturer's written instructions. If
the analyzer is used to sample more than one
pollutant source (stack), repeat this test for
each sampling point.
6.3.2 Response Time Test Procedure. In-
troduce zero gas into the continuous moni-
toring system sampling interface or as close
to the sampling interface as possible. When
the system outpxit reading has stabilized,
switch quickly to a known concentration of
pollutant gas. Record the time from concen-
tration switch ing to 95 percent of final stable
response. For non-extractive monitor;,, the
highest available calibration gas concentra-
tion shall be switched into and out of the
sample path and response times recorded.
Perform this test sequence three (3) times.
Record the results of each test on the
example sheet shown in Figure 2-6.
7. Calculations, Data Analysis and Heport-
ing.
7.1 Procedure for determination of mean
values and confidence intervals.
7.1.1 The mean value of a data set Is
calculated according to equation 2-1.
n
1 = 1 Equation ? ]
where:
*i- absolute value of the measurements,
£_=sum of the individual values,
x = mean value, and .,
n = number of data points.
7.1.2 The 95 percent confidence interval
(two-sided) Is calcuiated according to equa-
tion 2-2:
nyn 1
Equation 2-2
where:
£x, = sum of all data points,
1 973 =ti a/2, and
C.I.Bi = 9n percent confidence interval
estimate of the average mean
value.
Values for '.975
n
2
3
4
5
6
7
8
9
10
11-.-
12
13
14
15
IB.
'.975
- 12.706
4.303
3.182
2.776
?.57l
2.447
2.385
2.306
2.262
2.22S
2,201
2.179
2,160
2.145
2.131
The values in this table are already cor-
rected for n-1 degrees of freedom. Use n
Til-Appendix B-5
-------
equal to the number of samples as data
points.
12 Data Analysis and Reporting.
75.1 Accuracy (Relative). For each of the
Qlne reference method test points, determine
the average pollutant concentration reported
by the continuous monitoring system. These
average concentrations shall be determined
from, the continuous monitoring system data
recorded under 7,2.2 by Integrating or aver-
aging the pollutant concentrations over each
3f the time Intervals concurrent with each
reference method testing period. Before pro-
ceeding to the next step, determine the basis
(wet or dry) of the continuous monitoring
system data and reference method test data
concentrations. If the bases are not con-
sistent, apply a moisture correction to either
reference method concentrations or the con-
tinuous monitoring system concentrations
as appropriate. Determine the correction
factor by moisture tests concurrent with, the
reference method testing periods. Report the
moisture test method and the correction pro-
cedure employed. For each of the nine test
runs determine the difference for each test
run by subtracting the respective reference
method test concentrations (use average of
each set of three measurements for NO»)
from the continuous monitoring system inte-
grated or averaged concentrations. Using
these data, compute the mean difference and
the 95 percent confidence Interval of the dif-
ferences (equations 2-1 and 2-2). Accuracy
Is reported ao the sum of the absolute value
of the mean difference and the 95 percent
confidence intervaJ of the differences ex
pressed as a percentage of the mean refer-
ence method value. Use the example sheet
shown lu Figure 2-3.
7.2.2 Calibration Error. Using the data
from paragraph 6.1, subtract the measured
pollutant concentration determined under
paragraph 6.1.1 (Figure 2-1) from the value
shown by the continuous mouUonng system
for each of the flve readings at each con-
centration measured under 8.1.2 (Figure 2-2).
Calculate the mean of these difference values
and the 95 percent confidence Intervals ac-
cording to equations 2-1 and 2-2. Report the
calibration error (the sum of the absolute
value of the mean difference and the 95 per-
cent confidence Interval) as a percentage of
each respective calibration gas concentra-
tion. Use example sheet shown In Figure 2-2.
7.2.3 Zero Drift (2-hour). Using the zero
concentration values measured each two
hours during the field test, calculate the dif-
ferences between consecutive two-hour read-
Ings expressed In ppm. Calculate the mean
difference and the confidence Interval using
equations 2-1 and 2-2. Report the zero drift
as the sum of the absolute mean value and
the confidence interval as a percentage of
span. Use example sheet shown In Figure
2-4.
7.2.1 Zero Drift (24-hour). Using the zero
concentration values measured every 24
hours during the field test, calculate the dif-
ferences between the zero point after zero
adjustment and the zero value 24 hours later
Just prior to zero adjustment. Calculate the
mean value of these points and the confi-
dence interval using equations 2-1 and 2-2.
Report the zero drift (the sum of the abso-
lute mean and confidence interval) as a per-
centage of span. Use example sheet shown In
Figure 3-5.
7.2.5 Calibration Drift (2-hour). Using
the calibration values obtained at two-hour
intervals during the field test, calculate the
differences between consecutive two-hour
readings expressed as ppm. These values
should be corrected for the corresponding
zero drift during that two-hour period. Cal-
culate the mean and confidence interval of
these corrected difference values using equa-
tions 2-1 and 2-2. Do not use the differences
between non-consecutive readings. Report
the calibration drift as the sum of the abso-
lute mean and confidence interval as a. per-
centage of span. Use the example sheet shown
in Figure 2-4.
7.2.8 C-Jibration Drift (24-hour). ^Using
the calibration values measured every 24
hours during the field test, calculate the dif-
ferences between the caiibration concentra-
tion reading after zero and calibration ad-
justment, and the calibration concentration
reading 24 hours later alter zero adjustment
but befo.-e calibration adjustment. Calculate
the mean value of these differences and the
confidence Interval using equations 2-1 and
2-2. Report the calibration drift (the sum of
the absolute mean and confidence Interval)
as a percent&ge of span. Use the example
sheet shown In Figure 2-5.
7.2.7 Response Time. Using the charts
from paragraph 6.3, calculate the time inter-
val from concentration switching to 95 per-
cent to the final stable value for all upscale
and downscale tests. Report the mean of the
three upscale test times and the mean of the
three downscale test tunes. The two aver-
age times should not differ by more than 15
percent of the slower time. Report the slower
time as the system response time. Use the ex-
ample sheet shown In Figure 2-6.
7.2.8 Operational Test Period. During the
168-hour performance and operational test
period, the continuous monitoring system
shall not require any corrective maintenance,
repair, replacement, or adjustment other than
that clearly specified as required in the op-
eration and maintenance manuals as routine
and expected during a one-week period. If
the continuous monitoring system operates
within the specified performance parameters
and does not require corrective maintenance,
repair, replacement or adjustment other than
as specified above during the 168-hour test
period, the operational period will be success-
fully concluded. Failure of the continuous
monitoring system to meet this requirement
shall call for a repetition of the 168-hour test
period. Portions of the test which were sail3-
factorllj' completed need not be repeated.
Failure to meet any performance specifica-
tions shall call for a repetition of the one-
week performance test period and that por-
tion of the testing which Is related to the
failed specification All maintenance and ad-
justments required shall be recorded. Out-
put readings shall be recorded before and
after all adjustments.
8. References.
8.1 "Hfonltoring Instrumentation for the
Measurement of Sulfur Dioxide In Stationary
Source Emissions," Environmental Protection
Agency, Research Triangle Park, N.C., Feb-
ruary 1973.
8.2 "Instrumentation for the Determina-
tion of Nitrogen Oxides Content of Station-
ary Source Emissions," Environmental Pro-
tection Agency, Research Triangle Park, N C.,
Volume 1, APTD-0847, October 1971; Vol-
ume 2, APTD-0942, January 1972.
3.3 "Experimental Statistics," Department
of Commerce, Handbook 91, 1963, pp. 3-31,
paragrEiphs 33.1.4.
8.4 ".Performance Specifications for Sta-
tionary-Source Monitoring Systems for Gases
and Visible Emissions," Environmental Pro-
tection Agency, Research Triangle Park, N C.,
EPA-650/2-74-013, January 1974.
Reference Method Us erf
High-Range (spin) Calibration Sis
Fl<|₯re 2-1. Anlyils of hUbrttton Us Miturei
Ill-Appendix B-6
-------
Calibration Gas Mixture Data (From Figure 2-1)
Mid (502) ppm High (90S) ppm
Run #
Calibration Gas
Concentration,ppm
Measurement System
Reading, ppn
Differences, ppm
6_
7_
8
9_
V0_
n
1
15
Mean Difference -t- C.I.
Hid High
Mean difference
Confidence interval
Calibration error =
Calibration gas concentration - measurement system reading
""Absolute value
Ca n braTfoTT GasToncen tra ti on
x 100
Figure t-'i. Calibration Error Determination
lest
Ho.
1
fete
ml
Time
, |
3 1
4 !
Reference Method Samples
S02
Sample 1
HO,
Sampfe 1
(ppm)
IW NO HO Sample
Sample I Sample 3 ! Average
(ppm) (ppm) j (opm)
I !
I
i i
5 , ,
< i
7
B
9
lean
kccur
j
i
reference i
value (S02
Kthod
ntervals
1
1
Analyzer 1-HOur
Average (ppm)*
so2 no,
i
1
Mean reference Kthod
test value (NO )
* PP»
(SOJ *
Hean of tne Differences 4 95, confi«nce"interva) , .
*c1t- Mean reference Mthod value - .
lain and report awUiod used to determine Integrated averages
Difference
SO^'NO,
Mean of
tlw differences
PP*
* (S02
( (KO^
figure 2-3. Accuracy Determination (S0{ and NO^l 57
Ill-Appendix P-7
-------
(Data
Zero Span Calibration
Tim* Zero Drift Span Drift Drift
Begin End Date Reading (aZero) Refilling (ASpan) ( Span- Zero)
B
J_
10
Zero Srift « [Mean Zero Drift* > Cl jZe-o) ] ^ [Spanj x 103
Calibrdtion Drift * [Kean Span Drift* . + CI (Span) ] * [Span] x
Absolute Value.
F;gure 2-4.Zero and Calibrdticn Drift (2 nour)
Date Zero Span Calibration
and Zero Drift Reading Drift
Time Reading (AZero) (After zero adjustment) (aSpan)
Zero Drift = [Mean Zero Drift* _ + C.I. (Zero)
[Instrument Span] x ICO =
Calibration Drift = [Mean Span Drift* ________
+ C.I. (Span) _
» [Instrument Span] x 100
* Absolute value
Figure 2-5. Zero and Calibration Drift (24-hour)
Ill-Appendix B-8
-------
Date of Test
Span Gas Concentration
Analyzer Span Setting
Upscale
Average
Downscale
1
2
_ppir,
_PPm
seconds
seconds
3 seconds
upscale response seconds
1 seconds
2
3
Average downscale
System average response -time (slower
^deviation from slower _ averaqe u
system average response
seconds
seconds
response seconds
time) = seconds.
)scale minus averaqe downscale | ,«
-Imurr t i nr X IUU~
Figure 2-6. Response Time
Performance Specification 3Performance
specifications and specification test proce-
dures for monitors of CO, and O2 from sta-
t.onary sources.
1 Principle and Applicability.
1.1 Principle. Effluent gases are continu-
ously sampled and are analyzed for carbon
Cioxlde or oxygen by a continuous monitor-
ing system. Tests of the system are performed
during a minimum operating period to deter-
mine zero drift, calibration drift, and re-
f.j'jnse time characteristics.
1 2 Applicability. This performance speci-
fication is applicable to evaluation of con-
tinuous monitoring systems for measurement
of carbon dioxide or oxygen. These specifica-
tions contain test procedures, installation re-
quirements, and data computation proce-
dures for evaluating the acceptability of the
continuous monitoring systems subject to
approval by the Administrator. Sampling
r.iay include either extractive or non-extrac-
tive (m-situ) procedures.
2. Apparatus,
2 1 Continuous Monitoring System for
Carbon Dioxide or Oxygen.
2 2 Calibration Gas Mixtures. Mixture of
known concentrations of carbon dioxide or
oxygen in nitrogen or air. Midrange and 90
percent of span carbon dioxide or oxygen
concentrations are required The 90 percent
of span gas mixture is to be used to set and
check the analyzer span and Is referred to
ao span gas For oxygen analyzers, if the
?pan is higher than 21 percent O,, ambient
air may be used in place of the 90 percent of
span calibration gas mixture. Triplicate
analyses of the gas mixture (except ambient
air) shall be performed within two weeks
prior to use using Reference Method 3 of
this part.
2 3 Zero Gas. A gas containing less than 100
ppm of carbon dioxide or oxygen.
2.4 Data Recorder. Analog chart recorder
or other suitable device with input voltage
range compatible with analyzer system out-
put. The resolution of the recorder's data
output shall be sufficient to allow completion
ot the test procedures within this specifica-
tion.
3 Definitions.
3.1 Continuous Monitoring System. The
total equipment required for the determina-
tion of carbon dioxide or oxygen In a given
source effluent. The system consists of three
major subsystems.
3.1.1 Sampling Interface That portion of
the continuous monitoring system that per-
forms one or more of the following opera-
tions: delineation, acquisition, transporta-
tion, and conditioning of a sample of the
source effluent or protection of the analyzer
from the hostile aspects of the sample or
source environment
312 Analyzer That portion of the con-
tinuous monitoring system which senses the
pollutant gas and generates a signal output
that is a tunction of the pollutant concen-
tration
3 1.3 Data Recoraer. That portion of the
continuous monitoring system that provides
a permanent record of the output signal in
terms of concentration units
3 2 Span. The value of oxygen or carbon di-
oxide concentration at which the continuous
monitoring system is set that produces the
maximum data display output. For the pur-
poses of this method, the span shall be set
no less than 1,5 to 2 5 times the normal car-
bon dioxide or normal oxygen concentration
in the stack gas of the affected facility,
3 3 Midrange The- value of oxygen or car-
bon dioxide concentration that is representa-
tive of the normal conditions in the stack
gas of the affected facility at typical operat-
ing rates.
3.4 Zero Drift. The change in the contin-
uous monitoring system output over a stated
period of time of normal continuous opera-
tion when the carbon dioxide or oxygen con-
centration at the time for the measurements
is zero.
3 5 Calibration Drift. The change In the
continuous monitoring system output over a
stated time period of normal continuous op-
eration when the carbon dioxide or oxygen
continuous monitoring system is measuring
the concentration of span gas.
3 6 Operational Test Period. A minimum
period of time over which the continuous
monitoring system Is expected to operate
within Certain performance specifications
without unscheduled maintenance, repair, or
adjustment.
3.7 Response time. The time Interval from
a step change In concentration at the Input
to the continuous monitoring system to the
time at which 95 percent of the correspond-
ing final value Is displayed on the continuous
monitoring system data recorder.
4. Installation Specification.
Oxygen or carbon dioxide continuous mon-
itoring systems1 shall be Installed at a loca-
tion where measurements are directly repre-
sentative of the total effluent from tlie
affected facility or representative of the same
effluent sampled by a SO, or NOX continuous
monitoring system. This" requirement shall
be compiled with by use of applicable re-
quirements In Performance Specification 2 of
this appendix as follows:
4.1 Installation of Oxygen or Carbon Di'
oxide Continuous Monitoring Systems Not
Used to Convert Pollutant Data. A sampling
location shall be selected In accordance with
the procedures under paragraphs 4.2.1 or
4.2.2, or Performance Specification 2 of this,
appendix.
4.2 Installation of Oxygen or Carbon Di-
oxide Continuous Monitoring Systems Used
to Convert Pollutant Continuous Monitoring
System- Data to Units of Applicable Stand-
ards. The diluent continuous monitoring sys-
tem (oxygen or carbon dioxide) shall be In-
stalled at a sampling location where measure-
ments that can be made are representative of
the effluent gases sampled by the pollutant
continuous monitoring system(s). Conform-
ance with this requirement may be accom-
plished in any of the following ways:
4 2.1 The sampling location for the diluent
system shalfbe near the sampling location for
the pollutant continuous monitoring system
such that, the same approximate point(s)
(extractive systems) or path (in-situ sys-
tems) in the cross section is sampled or
viewed.
4.2.2 The diluent and pollutant continuous
monitoring systems may be Installed at dif-
ferent locations it the effluent gases at both
sampling locations are nonstratified as deter-
mined under paragraphs 4.1 or 4.3, Peilotm-
ance Specification 2 of this appendix and
there is no m-leakage occurring between the
two sampling locations. If the effluent gases
are stratified at either location, the proce-
ciures under paragraph 4,2.2, Performance
Specification 2 of this appendix shall be used
for installing continuous monitoring systems
at that location.
5. Continuous Monitoring System Pcjfonn-
ance Specifications.
The continuous monitoring system shall
meet the performance specifications in Table
3-1 to be considered acceptable under this
method.
6. Performance Specification Test Proce-
dures.
The following test procedures shall be uscci
to determine con/ormance with the require-
in 3nts of paragraph 4. Due to the wide varia-
tion existing in analyzer designs and princi-
ples of operation, these procedures are not
applicable to all analyzers. Where this occurs,
alternative procedures, subject to the ap-
proval of the Administrator, may be em-
ployed. Any such alternative procedures must
fulfill the same purposes (verify response,
drift, and accuracy) as the following proce-
dures, and must clearly demonstrate con-
formance with specifications in Table 3-1
6.1 Calibration Cheo.k. Establish a cali-
bration curve foe the continuous moni-
toring system using zero, midrange, and
span concentration gas mixtures. Verify
that the resultant curve of analyzer read-
ing compared with the calibration ga?
value is consistent with the expected re-
sponse curve as described by the analyzei
manufacturer. If the expected response
curve is not produced, additional cali-
bration gas measurements shall be made,
or additional steps undertaken to vcrifv
Ill-Appendix B-9
-------
the accuracy of the response curve of the
analyzer.
6.2 Field Test for Zero Drift and Cali-
bration Drift. Install and operate the
continuous monitoring system in accord-
ance with the manufacturer's written in-
structions and drawings as follows:
TABLE 3-1.Performance specifications
Parameter
Specification
1. Zero drift (2 h)' <0.4 pet 0> or COi.
2. Zero drill (24 hi 1
-------
ita Zero Spin Calibrator.
i«t Tilt Ztro Drift Sp«n Drift Drift
I*. fefi* En4 D)t« hiding (iZerfl) II tad In? (iSpu) (iSpan-iZtro)
4
6
7
a
9
0
4
iero Drift J.K«an Zero Drift* + CI uero)
C»Hbrat1on Drift [H«4n Span Drift* ~ .. * CI (Span"
Absotutt Valut.
3-1, Z»r« »nd CaHSratlon Brtft (Z Hour).
)ate Zero Span Calibration
and Zero Drift Reading Drift
ime Reading (tZero) (After zero adjustment) (ASpan)
Zero Drift » [Mean Zero Drift* + C.I. (Zero)
lalibration Drift = [Mean Span Drift* + C.I. (Span)
* Absolute value
Figure 3-2. Zero and Calibration Drift (24-hour)
Ill-Appendix B-ll
-------
Datfc of Test
Span Gas Concentration ppm
Analyzer Span Setting ppm
T. seconds
Upscale 2. seconds
3. seconds
Average upscale response seconds
1, seconds
Downscalc 2, seconds
3. ssconds
Average downscale response seconds
Sys tern
n average response time (slower tirre) = seconds
K,
-------
APPXNWi CDlTEMiraATIOM 01 EMISSION KAW
CHANOB
1. Introduction.
1.1 The following method shall be nsed to determine
whether a physical of operational change to an editing
facility resulted In an Increase In the emission rate to tb*
atmosphere. The method nsed is the Student's ( test,
commonly nsed to make inferences from small samples.
2. Data.
2 1 Eseh emission test shall consist of « runs (usually
three) which produce » emission rates. Thus two sets of
emission rates are generated, one before and one after the
change, the two sets being of equal size.
2 2 When using manual emission tests, except as pro-
vided in i 80.8(b) of this part, the reference methods of
Appendix A to this part shall be used In accordance with
the procedures specified in the applicable subpart both
before and after the change to obtain the data.
2.3 When using continuous monitors, the facility shall be
operated as If a manual emission tost were being per-
formed Valid data usingtheaveraglngtlmewhlch would
be required If a manual emission test were being con-
ducted shall be used.
9. Procedure.
3.1 Subscripts ft and b denote prechange and post-
change respectively. «
3 2 Calculate the arithmetic mean emission rate, K, lor
each set of data using Equation 1.
E=
(i)
Emission rate for the < th run,
number of runs
JJ Calculate the sample variance, S», tor each set of
data using Equation 2.
n-l
»-l
(2)
3.4 Calculate the pooled estimate,
tion 3.
using Equa-
P(n.-l) S.'+(nt-l) g»'-l
S'=l n.+n,-2 J
(3)
IS Calculate the test statistic, c, using Equation 4.
(4)
4. Rcmltt.
4.1 If Ei>E. and Of, where f is the critical value of
(obtained from Table 1, then with 95% confidence the
difference between Ki and ~K. is significant, and an in.
crease in emission rate to the atmosphere has occurred.
f (9S
percent
confi-
dence
Degree of freedom (n.+»»-2): level)
2 ......................... 2.920
3 ........ . " ................ 2.353
4 ...... .'."" ........ " ..................... 2.132
6" " ................. _ 2.015
8"II"I ..... "."." .......................... ____ L943
7 ................ L895
gllllllllir""... II. I ..................... L8M
For greater than 8 degrees of freedom, see any standard
statistical handbook or text.
5.1 Assume the two performance tests produced the
following set of data:
Testa:
Eunl. 100
Run2. 95
EunS. IK)
Testb
115
1»
: 126
5.3 Using Equation 2
(100-102)'+ (95-102)»+ (110-102)*
3-1
=58.5
f
(115- 120)» + (120- 120)»+ (125-120)*
g^j
«=25
5.4 Using Equation 3
X r(3-D (58.5) + (3-1) (25)"im . .ft
'=L 3 + 3-2 J J=6'48
5.5 Using ^Equation 4
120-102
6-46 +
; = 3.412
S.2 Using Equation 1
5.0 Since (nj+ni-2) =4, f -2.132 (from Table 1). Thus
since 1>C the difference in the values of E. and E, la
significant, and there has been an Increase In emission
rate to the atmosphere.
8. Omttnuout Monitoring Data.
8.1 Hourly averages from continuous monJtortMj de-
vices, where available, should be used as data f »ffi'
tUe above procedure followed.
(Sec. 114. Clean Air Act I* amended (42
U.S.C. 7414)). 68-83
Ill-Appendix C-l
-------
APPENDIX DREQUIRED EMISSION INVENTORY
INFORMATION
(a) Completed NEDS point source form(s)
for the entire plant containing the desig-
nated facility, Including information on the
applicable criteria pollutants. If data con-
cerning the plant 'are already In NEDS, only
that Information must be submitted which
Is necessary to update the existing NEDS
record for that plant. Plant and point Identi-
fication codes for NEDS records shall cor-
respond to those previously assigned In
NEDS; for plants not in NEDS, these codes
shall be obtained from the appropriate
Regional Office.
(b) Accompanying the basic NEDS infor-
mation shall be the following Information
on each designated facility:
(1) The state and county identification
codes, as well as the complete plant and
point identification codes of the designated
facility in NEDS. (The codes are needed to
match these data with the NEDS data.)
(2) A description of the designated facility
including, where appropriate: .
(i) Process name.
(ii) Description and quantity of each
product (maximum per hour and average per
year).
(ill) Description and quantity of raw ma-
terials handled for each product (maximum
per hour and average per year).
(iv) Types of fuels burned, quantities and
characteristics (maximum and average
quantities per hour, average per year).
(v) Description and quantity of solid
wastes generated (per year) and method of
disposal.
(3) A description of the air pollution con-
trol equipment In use or proposed to control
the designated pollutant, including:
(1) Verbal description of equipment.
(ii) Optimum control efficiency, in percent.
This shall be a combined efficiency when
more than one device operate in series. The
method of control efficiency determination
shall be indicated (e.g., design efficiency,
measured efficiency, estimated efficiency).
(ill) Annual average control efficiency, in
percent, taking into account control equip-
ment down time. This shall be a combined
efficiency when more than one device operate
in series.
(4) An estimate of the designated pollu-
tant emissions from the designated facility
(maximum per hour and average per year).
The method of emission determination shall
also be specified (e.g., stack test, material
balance, emission factor).
(Sec. 114. Clean Air Act Ii imended (42
U.SC. 7414)). 6B 83
Ill-Appendix D-l
-------
SECTION IV
FULL TEXT
OF
REVISIONS
-------
IV. FULL TEXT OF REVISIONS
Ref. Page
36 FR 5931, 3/31/71 - List of Categories of Stationary Sources.
36 FR 15704, 8/17/71 - Proposed Standards for Five Categories:
Fossil Fuel-Fired Steam Generators, Portland Cement
Plants, Nitric Acid Plants, and Sulfuric Acid Plants.
1. 36 FR 24876, 12/23/71 - Standards of Performance Promulgated for
Fossil Fuel-Fired Steam Generators, Incinerators, Port-
land Cement Plants, Nitric Acid Plants, and Sulfuric
Acid Plants. 1
1A. 37 FR 5767, 3/21/72 - Supplemental Statement in Connection with
Final Promulgation. 21
2. 37 FR 14877, 7/26/72 - Standard for Sulfur Dioxide; Correction. 25
37 FR 17214, 8/25/72 - Proposed Standards for Emissions During
Startup, Shutdown, and-Malfunction.
3. 38 FR 13562, 5/23/73 - Amendment to Standards for Opacity and
Corrections to Certain Test Methods. 26
38 FR 15406, 6/11/73 - Proposed Standards of Performance for
Asphalt Concrete Plants, Petroleum Refineries, Storage
Vessels for Petroleum Liquids, Secondary Lead Smelters,
Brass and Bronze Ingot Production Plants, Iron and Steel
Plants, and Sewage Treatment Plants.
4. 38 FR 28564, 10/15/73 - Standards of Performance Promulgated for
Emissions During Startup, Shutdown, and Malfunction. 26
4A. 38 FR 10820, 5/2/73 - Proposed Standards of Performance for
Emissions During Startup, Shutdown, & Malfunction. 28
5. 39 FR 9308, 3/8/74 - Standards of Performance Promulgated for
Asphalt Concrete Plants, Petroleum Refineries, Storage
Vessels for Petroleum Liquids, Secondary Lead Smelters,
Brass and Bronze Ingot Production Plants, Iron and Steel
Plants, and Sewage Treatment Plants; and Miscellaneous
Amendments. 30
-------
6. 39 FR 13776, 4/17/74 - Corrections to March 8, 1974 Federal
Register. " 45
7. 39 FR 15396, 5/3/74 - Corrections to March 8, 1974 and April
17, 1974 Federal Register. 46
8. 39 FR 20790, 6/14/74 - Standards of Performance, Miscellaneous
Amendments. 46
39 FR 32852, 9/11/74 - Proposed Standards of Performance -
Emission Monitoring Requirements and Performance Test-
ing Methods.
39 FR 36102, 10/7/74 - Proposed Standards of Performance for
State Plans for the Control of Existing Facilities.
39 FR 36946, 10/15/74 - Proposed Standards of Performance for
Modification, Notification, and Reconstruction.
39 FR 37040, 10/16/74 - Proposed Standards of Performance for
Primary Copper, Zinc, and Lead Smelters.
39 FR 37470, 10/21/74 - Proposed Standards of Performance for
Ferroalloy Production Facilities.
39 FR 37466, 10/21/74 - Proposed Standards of Performance for
Steel Plants: Electric Arc Furnaces.
39 FR 37602, 10/22/74 - Proposed Standards of Performance -
Five Categories of Sources in the Phosphate Fertilizer
Industry.
39 FR 37730, 10/23/74 - Proposed Standards of Performance for
Primary Aluminum Reduction Plants.
39 FR 37922, 10/24/74 - Proposed Standards of Performance for
Coal Preparation Plants.
9. 39 FR 37987, 10/25/74 - Region V Office: New Address. 51
10. 39 FR 39872, 11/12/74 - Opacity Provisions for New Stationary
Sources Promulgated and Appendix A, Method 9 - Visual
Determination of the Opacity of Emissions from Station-
ary Sources. 51
39 FR 39909, 11/12/74 - Response to Remand, Portland Cement
Association v. Ruckelshaus, Reevaluation of Standards.
-------
40 FR 831, 1/3/75 - Reevaluation of Opacity Standards of Perform-
ance for New Sources - Asphalt Concrete Plants.
11. 40 FR 2803, 1/16/75 - Amended Standard for Coal Refuse (promul-
gated December 23, 1971). 57
40 FR 17778, 4/22/75 - Standards of Performance, Proposed Opa-
city Provisions, Request for Public Comment.
12. 40 FR 18169, 4/25/75 - Delegation of Authority to State of
Washington. 58
13. 40 FR 26677, 6/25/75 - Delegation of Authority to State of Idaho. 58
14. 40 FR 33152, 8/6/75 - Standards of Performance Promulgated for
Five Categories of Sources in the Phosphate Fertilizer
Industry. 59
40 FR 39927, 8/29/75 - Standards of Performance for Sulfuric
Acid Plants - EPA Response to Remand.
40 FR 41834, 9/9/75 - Opacity Reevaluation - Asphalt Concrete,
Response to Public Comments.
40 FR 42028, 9/10/75 - Proposed Opacity Standards for Fossil
Fuel-Fired Steam Generators.
40 FR 42045, 9/10/75 - Standards of Performance for Fossil Fuel-
Fired Steam Generators - EPA Response to Remand.
15. 40 FR 42194, 9/11/75 - Delegation of Authority to State of
California. 74
16. 40 FR 43850, 9/23/75 - Standards of Performance Promulgated for
Electric Arc Furnaces in the Steel Industry. 75
17. 40 FR 45170, 10/1/75 - Delegation of Authority to State of
California. 80
18. 40 FR 46250, 10/6/75 - Standards of Performance Promulgated
for Emission Monitoring Requirements and Revisions
to Performance Testing Methods. 81
19. 40 FR 48347, 10/15/75 - Delegation of Authority to State of
New York. 102
20. 40 FR 50718, 10/31/75 - Delegation of Authority to State of
Colorado. 102
21. 40 FR 53340, 11/17/75 - Standards of Performance, Promulgation
of State Plans for the control of Certain Pollutants
from Existing Facilities (Subpart B and Appendix D). 103
m
-------
40 FR 53420, 11/18/75 - Reevaluation of Opacity Standards for
Secondary Brass and Bronze Plants and Secondary Lead
Smelters.
22. 40 FR 58416, 12/16/75 - Standards of Performance, Promulgation
of Modification, Notification and Reconstruction Pro-
visions. 113
23. 40 FR 59204, 12/22/75 - Corrections to October 6, 1975, Federal
Register. 118
24. 40 FR 59729, 12/30/75 - Delegation of Authority to State of
Maine. 118
25. 41 FR 1913, 1/13/76 - Delegation of Authority to State of
Michigan. 119
26. 41 FR 2231, 1/15/76 - Standards of Performance Promulgated for
Coal Preparation Plants. 119
26. 41 FR 2332, 1/15/76 - Standards of Performance Promulgated for
Primary Copper, Zinc and Lead Smelters. 123
27. 41 FR 3825, 1/26/76 - Standards of Performance Promulgated for
Primary Aluminum Reduction Plants. 133
28. 41 FR 4263,1/29/76 - Delegation of Authority to Washington Local
Authorities. 138
41 FR 7447, 2/18/76 - Reevaluation of Opacity Standards for
Municipal Sewage Sludge Incinerators.
29. 41 FR 7749, 2/20/76 - Delegation of Authority to State of
Oregon. 138
30. 41 FR 8346, 2/26/76 - Correction to the Primary Copper, Zinc,
and Lead Smelter Standards Promulgated on 1/15/76. 139
31. 41 FR 11820, 3/22/76 - Delegation of Authority to State of
Connecticut. 139
32. 41 FR 17549, 4/27/76 - Delegation of Authority to State of
South Dakota. 139
33. 41 FR 18498, 5/4/76 - Standards of Performance Promulgated for
Ferroalloy Production Facilities. 140
41 FR 19374, 5/12/76 - Revised Public Comment Summary for Mod-
ification, Notification, and Reconstruction.
41 FR 19584, 5/12/76 - Phosphate Fertilizer Plants, Draft Guide-
lines Document - Notice of Availability.
IV
-------
34. 41 FR 19633, 5/13/76 - Delegation of Authority to Commonwealth
of Massachusetts and Delegation of Authority to State
of New Hampshire. 145
35. 41 FR 20659, 5/20/76 - Correction to Ferroalloy Production
Facilities Standards Promulgated on May 4, 1976. 146
36. 41 FR 21450, 5/26/76 - Delegation of Authority to State of
California. 146
41 FR 23059, 6/8/76 - Proposed Amendments to Reference Methods
1-8.
37. 41 FR 24124, 6/15/76 - Delegation of Authority to State of Utah. 146
38. 41 FR 24885, 6/21/76 - Delegation of Authority to State of
Georgia. 147
39. 41 FR 27967, 7/8/76 - Delegation of Authority to State of
California. 147
40. 41 FR 33264, 8/9/76 - Delegation of Authority to State of
California. 148
41. 41 FR 34628, 8/16/76 - Delegation of Authority to Virgin
Islands. 148
42. 41 FR 35185, 8/20/76 - Revision to Emission Monitoring
Requirements. 149
41 FR 36600, 8/30/76 - Proposed Revisions to Standards of
Performance for Petroleum Refinery Fluid Catalytic
Cracking Unit Catalyst Regenerators.
43. 41 FR 36918, 9/1/76 - Standards of Performance - Avail-
ability of Information. 149
44. 41 FR 40107, 9/17/76 - Delegation of Authority to
State of California. 149
45. 41 FR 40467, 9/20/76 - Delegation of Authority to State of
Alabama. 150
41 FR 42012, 9/24/76 - Proposed Standards of Performance for
Kraft Pulp Mills.
46. 41 FR 43148, 9/30/76 - Delegation of Authority to the State
State of Indiana. 150
41 FR 43866, 10/4/76 - Proposed Revisions to Standards of
Performance for Petroleum Refinery Sulfur Recovery
Plants.
-------
47. 41 FR 44859, 10/13/76 - Delegation of Authority to State of
North Dakota. 150
41 FR 46618, 10/22/76 - Advanced Notice of Proposed Rule-
making of Air Emission Regulations - Synthetic
Organic Chemical Manufacturing Industry.
41 FR 47495, 10/29/76 - Proposed Standards of Performance for
Kraft Pulp Mills; Correction.
48. 41 FR 48342, 11/3/76 - Delegation of Authority to State of
California. 151
41 FR 48706, 11/4/76 - Proposed Revisions to Emission Guide-
lines for the Control of Sulfuric Acid Mist from
Existing Sulfuric Acid Production Units.
49. 41 FR 51397, 11/22/76 - Amendments to Subpart D Promulgated. 151
41 FR 51621, 11/23/76 - Proposed Standards of Performance
for Kraft Pulp Mills - Extension of Comment Period.
41 FR 52079, 11/26/76 - Proposed Revision to Emission Guide-
lines for the Control of Sulfuric Acid Mist from
Existing Sulfuric Acid Production Units; Correction.
50. 41 FR 52299, 11/29/76 - Amendments to Reference Methods
13A and 13B Promulgated. 154
51. 41 FR 53017, 12/3/76 - Delegation of Authority to Pima
County Health Department; Arizona. 155
52. 41 FR 54757, 12/15/76 - Delegation of Authority to State of
California. 155
53. 41 FR 55531, 12/21/76 - Delegation of Authority to the State
of Ohio. 156
41 FR 55792, 12/22/76 - Proposed Revisions to Standards of
Performance for Lignite-Fired Steam Generators.
54. 41 FR 56805, 12/30/76 - Delegation of Authority to the States
of North Carolina, Nebraska, and Iowa. 156
55. 42 FR 1214, 1/6/77 - Delegation of Authority to State of
Vermont. 157
42 FR 2841, 1/13/77 - Proposed Standards of Performance for
Grain Elevators.
-------
56. 42 FR 4124, 1/24/77 - Delegation of Authority to the State
of South Carolina. 158
42 FR 4863, 1/26/77 - Proposed Revisions to Standards of
Performance for Sewage Sludge Incinerators.
42 FR 4883, 1/26/77 - Receipt of Application and Approval
of Alternative Test Method. 158
42 FR 5121, 1/27/77 - Notice of Study to Review Standards
for Fossil Fuel-Fired Steam Generators; SC^
Emissions.
57. 42 FR 5936, 1/31/77 - Revisions to Emission Monitoring
Requirements and to Reference Methods Promulgated. 159
58. 42 FR 6812, 2/4/77 - Delegation of Authority to City of
Philadelphia. 161
42 FR 10019, 2/18/77 - Proposed Standards for Sewage
Treatment Plants; Correction.
42 FR 12130, 3/2/77 - Proposed Revision to Standards of Per-
formance for Iron & Steel Plants; Basic Oxygen
Process Furnaces.
42 FR 13566, 3/11/77 - Proposed Standards of Performance for
Grain Elevators; Extension of Comment Period.
59. 42 FR 16777, 3/30/77 - Correction of Region V Address and
Delegation of Authority to the State of Wisconsin. 161
42 FR 18884, 4/11/77 - Notice of Public Hearing on Coal-
Fired Steam Generators S02 Emissions.
42 FR 22506, 5/3/77 - Proposed Standards of Performance for
Lime Manufacturing Plants.
60. 42 FR 26205, 5/23/77 - Revision of Compliance with
Standards and Maintenance Requirements. 162
42 FR 26222, 5/23/77 - Proposed Revision of Reference
Method 11.
42 FR 32264, 6/24/77 - Suspension of Proposed Standards of
Performance for Grain Elevators.
61. 42 FR 32426, 6/24/77 - Revisions to Standards of Performance
for Petroleum Refinery Fluid Catalytic Cracking Unit
Catalyst Regenerators Promulgated. 162
vn
-------
62. 42 FR 37000, 7/19/77 - Revision and Reorganization of the
Units and Abbreviations. 164
42 FR 37213, 7/20/77 - Notice of Intent to Develop Standards
of Performance for Glass Melting Furnaces.
63. 42 FR 37386, 7/21/77 - Delegation of Authority to the State
of New Jersey. 165
64. 42 FR 37936, 7/25/77 - Applicability Dates Incorporated
into Existing Regulations. 165
65. 42 FR 38178, 7/27/77 - Standards of Performance for
Petroleum Refinery Fluid Catalytic Cracking Unit
Catalyst Regenerators and Units and Measures;
Corrections. 168
66. 42 FR 39389, 8/4/77 - Standards of Performance for Petroleum
Refinery Fluid Catalytic Cracking Unit Catalyst
Regenerators, Correction. 168
67. 42 FR 41122, 8/15/77 - Amendments to Subpart D; Correction. 168
68. 42 FR 41424, 8/17/77 - Authority Citations; Revision 169
69. 42 FR 41754, 8/18/77 - Revision to Reference Methods 1-8 170
Promulgated.
70. 42 FR 44544, 9/6/77 - Delegation of Authority to the State
of Montana. 206
71. 42 FR 44812, 9/7/77 - Standards of Performance, Applicability
Dates; Correction. 206
42 FR 45705, 9/12/77 - Notice of Delegation of Authority to
the State of Indiana.
72. 42 FR 46304, 9/15/77 - Delegation of Authority to the State
of Wyoming. 207
42 FR 53782, 10/3/77 - Proposed Standards of Performance
for Stationary Gas Turbines.
73. 42 FR 55796, 10/18/77 - Emission Guidelines for Sulfuric
Acid Mist Promulgated. 208
74. 42 FR 57125, 11/1/77 - Amendments to General Provisions
and Copper Smelter Standards Promulgated. 209
-------
75. 42 FR 58520, 11/10/77 - Amendment to Sewage Sludge Incin-
erators Promulgated. 211
76. 42 FR 61537, 12/5/77 - Opacity Provisions for Fossil-Fuel-
Fired Steam Generators Promulgated. 212
42 FR 61541, 12/5/77 - Opacity Standards for Fossil-Fuel -
Fired Steam Generators: Final EPA Response to
Remand.
77. 42 FR 62137, 12/9/77 - Delegation of Authority to the
Commonwealth of Puerto Rico. 214
42 FR 62164, 12/9/77 - Proposed Standards for Station-
ary Gas Turbines; Extension of Comment Period.
78. 43 FR 9, 1/3/78 - Delegation of Authority to the State
of Minnesota. 214
79. 43 FR 1494, 1/10/78 - Revision of Reference Method II
Promulgated. 215
80. 43 FR 3360, 1/25/78 - Delegation of Authority to the
Commonwealth of Kentucky. 219
81. 43 FR 6770, 2/16/78 - Delegation of Authority to the
State of Delaware. 220
82. 43 FR 7568, 2/23/78 - Standards of Performance Pro-
mulgated for Kraft Pulp Mills. 221
83. 43 FR 8800, 3/3/78 - Revision of Authority Citations. 249
84. 43 FR 9276, 3/7/78 - Standards of Performance Promul-
gated for Lignite-Fired Steam Generators. 250
85. 43 FR 9452, 3/7/78 - Standards of Performance Promul-
gated for Lime Manufacturing Plants. 253
86. 43 FR 10866, 3/15/78 - Standards of Performance Pro-
mulgated for Petroleum Refinery Claus Sulfur
Recovery Plants. 255
87. 43 FR 11984, 3/23/78 - Corrections and Amendments to
Reference Methods 1-8. 262
43 FR 14602, 4/6/78 - Notice of Regulatory Agenda.
IX
-------
88. 43 FR 15600, 4/13/78 - Standards of Performance Promul-
gated for Basic Oxygen Process Furnaces: Opacity
Standard. 265
89. 43 FR 20986, 5/16/78 - Delegation of Authority to State/
Local Air Pollution Control Agencies in Arizona,
California, and Nevada. 268
43 FR 21616, 5/18/78 - Proposed Standards of Performance
for Storage Vessels for Petroleum Liquids.
43 FR 22221, 5/24/78 - Correction to Proposed Standards
of Performance for Storage Vessels for Petroleum
Liquids.
90. 43 FR 34340, 8/3/78 - Standards of Performance Promulgated
for Grain Elevators. 269
43 FR 34349, 8/3/78 - Reinstatement of Proposed Standards
for Grain Elevators.
91. 43 FR 34784, 8/7/78 - Amendments to Standards of Perform-
ance for Kraft Pulp Mills and Reference Method 16. 277
43 FR 34892, 8/7/78 - Proposed Regulatory Revisions Air
Quality Surveillance and Data Reporting.
43 FR 38872, 8/31/78 - Proposed Priority List for Standards
of Performance for New Stationary Sources.
43 FR 42154, 9/19/78 - Proposed Standards of Performance
for Electric Utility Steam Generating Units arid
Announcement of Public Hearing on Proposed Stan-
dards.
43 FR 42186, 9/19/78 - Proposed Standards of Performance
for Primary Aluminum Industry.
92. 43 FR 47692, 10/16/78 - Delegation of Authority to the
State of Rhode Island. 278
43 FR 54959, 11/24/78 - Public Hearing on Proposed Stan-
dards for Electric Utility Steam Generating Units.
43 FR 55258, 11/27/78 - Electric Utility Steam Generating
Units; Correction and Additional Information.
43 FR 57834, 12/8/78 - Electric Utility Steam Generating
Units; Additional Information.
-------
93. 44 FR 2578, 1/12/79 - Amendments to Appendix A - Reference
Method 16. 279
94. 44 FR 3491, 1/17/79 - Wood Residue-Fired Steam Generators;
Applicability Determination. 280
95. 44 FR 7714, 2/7/79 - Delegation of Authority to State of Texas. 282
96. 44 FR 13480, 3/12/79 - Petroleum Refineries - Clarifying
Amendment. 282
44 FR 15742, 3/15/79 - Review of Performance Standards for
Sulfuric Acid Plants.
44 FR 17120, 3/20/79 - Proposed Amendment to Petroleum Refinery
Claus Sulfur Recovery Plants.
44 FR 17460, 3/21/79 - Review of Standards for Iron & Steel
Plants Basic Oxygen Furnaces.
44 FR 21754, 4/11/79 - Primary Aluminum Plants; Draft Guideline
Document; Availability.
97. 44 FR 23221, 4/19/79 - Delegation of Authority to Washington
Local Agency 284
44 FR 29828, 5/22/79 - Kraft Pulp Mills; Final Guideline Doc-
ument; Availability.
44 FR 31596, 5/31/79 - Definition of "Commenced" for Standards
of Performance for New Stationary Sources.
98. 44 FR 33580, 6/11/79 - Standards of Performance Promulgated for
Electric Utility Steam Generating Units. 285
44 FR 34193, 6/14/79 - Air Pollution Prevention and Control;
Addition to the List of Categories of Stationary Sources.
44 FR 34840, 6/15/79 - Proposed Standards of Performance for
New Stationary Sources; Glass Manufacturing Plants.
44 FR 35265, 6/19/79 - Review of Performance Standards: Nitric
Acid Plants.
44 FR 35953, 6/19/79 - Review of Performance Standards: Sec-
ondary Brass and Bronze Ingot Production.
44 FR 37632, 6/28/79 - Fossil-Fuel-Fired Industrial Steam
Generators; Advanced Notice of Proposed Rulemaking.
44 FR 37960, 6/29/79 - Proposed Adjustment of Opacity Standard
for Fossil-Fuel-Fired Steam Generators.
xi
-------
44 FR 43152, 7/23/79 - Proposed Standards of Performance for
Stationary Internal Combustion Engines.
44 FR 47778, 8/15/79 - Proposed Standards for Glass Manufacturing
Plants; Extension of Comment Period.
99. 44 FR 49222, 8/21/79 - Priority List and Additions to the List of
Categories of Stationary Sources Promulgated. 331
44 FR 49298, 8/22/79 - Kraft Pulp Mills; Final Guideline Document;
Correction.
100. 44 FR 51225, 8/31/79 - Standards of Performance for Asphalt Con-
crete Plants; Review of Standards. 335
44 FR 52324, 9/7/79 - New Source Performance Standards for Sul-
furic Acid Plants; Final EPA Remand Response.
101. 44 FR 52792, 9/10/79 - Standards of Performance for New Station-
ary Sources; Gas Turbines 338
44 FR 54072, 9/18/79 - Standards of Performance for Stationary
Internal Combustion Engines; Extension of Comment Period.
44 FR 54970, 9/21/79 - Proposed Standards of Performance for
Phosphate Rock Plants.
102. 44 FR 55173, 9/25/79 - Standards of Performance for New Station-
ary Sources; General Provisions; Definitions. 354
44 FR 57792, 10/5/79 - Proposed Standards of Performance for
Automobile and Light-Duty Truck Surface Coating Operations.
44 FR 58602, 10/10/79 - Proposed Standards for Continuous
Monitoring Performance Specifications.
44 FR 60759, 10/22/79 - Review of Standards of Performance for
Petroleum Refineries.
44 FR 60761, 10/22/79 - Review of Standards of Performance for
Portland Cement Plants.
103. 44 FR 61542, 10/25/79 - Amendment to Standards of Performance
for Petroleum Refinery Claus Sulfur Recovery Plants. 356
44 FR 62914, 11/1/79 - Proposed Standards of Performance for
Phosphate Rock Plants; Extension of Comment Period.
104. 44 FR 65069, 11/9/79 - Amendment to Regulations for Ambient
Air Quality Monitoring and Data Reporting. 358
xn
-------
44 FR 67934, 11/27/79 - Review of Standards of Performance
for Sewage Treatment Plants.
44 FR 67938, 11/27/79 - Review of Standards of Performance
for Incinerators.
105. 44 FR 69298, 12/3/79 - Delegation of Authority to the State
of Maryland. 358
106. 44 FR 70465, 12/7/79 - Delegation of Authority to the State
of Delaware. 359
44 FR 57408, 12/20/79 - Standards of Performance for Contin-
uous Monitoring Performance Specifications; Extension of
Comment Period.
107. 44 FR 76786, 12/28/79 - Amendments to Standards of Performance
for Fossil-Fuel-Fired Steam Generators. 360
45 FR 2790, 1/14/80 - Proposed Standards of Performance for
Lead-Acid Battery Manufacture.
108. 45 FR 3034, 1/16/80 - Delegation of Authority to Commonwealth
of Pennsylvania. 360
45 FR 3333, 1/17/80 - Proposed Standards of Performance for
Phosphate Rock Plants; Extension of Comment Period.
109. 45 FR 5616, 1/23/80 - Modification, Notification, and Recon-
struction; Amendment and Correction. 361
45 FR 7758, 2/4/80 - Proposed Standards of Performance for
Ammonium Sulfate Manufacture.
110. 45 FR 8211, 2/6/80 - Standards of Performance for Electric
Utility Steam Generating Units; Decision in Response
to Petitions for Reconsideration. 363
45 FR 11444, 2/20/80 - Proposed Standards of Performance
for Continuous Monitoring Specifications.
45 FR 13991, 3/3/80 - Proposed Clarifying Amendment for
Standards of Performance for Petroleum Refineries.
45 FR 20155, 3/27/80 - Notice of Determination of Applicabil-
ity of New Source Performance Standards (NSPS) to Potomac
Electric Power Co. (PEDCo) Chalk Point Unit 4.
45 FR 21302, 4/1/80 - Proposed Adjustment of Opacity Standard
for Fossil-Fuel-Fired Steam Generator.
xm
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111. 45 FR 23374, 4/4/80 - Standards of Performance for Petroleum
Liquid Storage Vessels. 386
45 FR 26294, 4/17/80 - Primary Aluminum Plants; Notice of
Availability of Final Guideline Document.
45 FR 26304, 4/17/80 - Review of Standards of Performance
for Secondary Lead Smelters.
45 FR 26910, 4/21/80 - Review of Standards of Performance
for Electric Arc Furnaces (Steel Industry).
112. 45 FR 36077, 5/29/80 - Adjustment of Opacity Standard for
Fossil Fuel Fired Steam Generator. 394
45 FR 39766, 6/11/80 - Proposed Standards of Performance
for Organic Solvent Cleaners.
113. 45 FR 41852, 6/20/80 - Revised Reference Methods 13A and 13B. 395
114. 45 FR 44202, 6/30/80 - Amendments to Standards of Performance
for Primary Aluminum Industry. 401
xiv
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24S76
RULES AND REGULATIONS
1 Title 40PROTECTION OF
ENVIRONMENT
Chapter IEnvironmental Protection
Agency
SU3CHAPTER CAIR PROGRAMS
PART 60STANDARDS OF PERFORM-
ANCE FOR MEW STATIONARY
SOURCES
On August 17, 1971 (36 F.R. 157C4)
pursuant to section 111 of the Clean Air
Act as amended, the Administrator
proposed standards of performance for
steam generators, Portland cement
plants, incinerators, nitric acid plants,
and sulfuric acid plants. The proposed
standards, applicable to sources the con-
struction or modification of which was
initiated after August 17, 1971, included
emission limits for one or more of four
pollutants (particulate matter, sulfur
(dioxide, nitrogen oxides, and sulfuric
acid mist) for each source category. The
proposal included requirements for per-
formance testing, stack gas monitoring,
record keeping and reporting, and pro-
cedures by which EPA will provide pre-
construction review and determine the
applicability of the standards to specific
sources.
Interested parties were afforded an
opportunity to participate in the rule
making by submitting comments. A total
of more than 200 interested parties, in-
cluding Federal, State, and local agen-
cies, citizens groups, and commercial and
industrial organizations submitted com-
ments. Following a review of the pro-
posed regulations and consideration of
the comments, the regulations, includ-
ing the appendix, have been revised and
are being promulgated today. The prin-
cipal revisions are described below:
1. Particulate matter performance
testing procedures have been revised to
eliminate the requirement for impingers
in the sampling train. Compliance will be
based only on material collected in the
dry filter and the probe preceding the
filter. Emission limits have been adjusted
as appropriate to reflect the change in
test methods. The adjusted standards re-
quire the same degree of particulate con-
trol as the originally proposed standards.
2. Provisions have been added whereby
alternative test methods can be used to
determine compliance. Any person who
proposes the use of an alternative
method will be obliged to provide evi-
dence that the alternative method is
equivalent to the reference method.
3. The definition of modification, as it
pertains to increases in production rate
and changes of fuels, has been clarified.
Increases in production rates up to design
capacity will not be considered a modifi-
cation nor will fuel switches if the equip-
ment was originally designed to accom-
modate such fuels. These provisions will
eliminate inequities where equipment had
been put into partial operation prior to
the proposal of the standards.
4. The definition of a new source was
clarified io include construction which
Is completed within an organization as
well as the more common situations
where the facility is designed and con-
structed by a contractor.
5. The provisions regarding requests
for EPA plan-review and determination
of construction or modification have been
modified to emphasize that the submittal
of such requests and attendant informa-
tion is purely voluntary. Submittal of
such a request will not bind the operator
to supply further information; however,
lack of sufficient information may pre-
vent the Administrator from rendering
an opinion. Further provisions have been
added to the effect that information sub-
mitted voluntarily for such plan review
or determination of applicability will be
considered confidential, if the owner or
operator requests such confidentiality.
6. Requirements for notifying the Ad-
ministrator prior to commencing con-
struction have been deleted. As proposed,
the provision would have required notifi-
cation prior to the signing of a contract
for construction of a new source. Owners
and operators still will be required to
notify the Administrator 30 days prior to
initial operation and to confirm the
action within 15 days after startup.
7. Revisions were incoporated to per-
mit compliance testing to be deferred up
to 60 days after achieving the maximum
production rate but no longer than 180
days after initial startup. The proposed
regulation could have required testing
within 60 days after startup but defined
startup as the beginning of routine
operation. Owners or operators will be
required "to notify the Administrator at
least 10 days prior to compliance testing
so that an EPA observer can be on hand.
Procedures have been modified so that
the equipment will have to be operated
at maximum expected production rate,
rather than rated capacity, during com-
pliance tests.
8. The criteria for evaluating perform-
ance testing results have been simplified
to eliminate the requirement that all
values be within 35 percent of the aver-
age. Compliance will be based on the
average of three repetitions conducted in
the specified manner.
9. Provisions were added to require
owners or operators of affected facilities
to maintain records of compliance tests,
monitoring equipment, pertinent anal-
yses, feed rates, production rates, etc. for
2 years and to make such information
available on request to the Administra-
tor. Owners or operators will be required
to summarize the recorded data daily
and to convert recorded data into the
applicable units of the standard.
10. Modifications were made to the
visible emission standards for steam
generators, cement plants, nitric acid
plants, and sulfuric acid plants. The
Ringelmann standards have been de-
leted; all limits will be based on opacity.
In every case, the equivalent opacity will
be at least as stringent as the proposed
Ringelmann number. In addition, re-
quirements have been altered for three
of the source categories so that allowable
emissions will be less than 10 percent
opacity rather than 5 percent or less
opacity. There were many comments
that observers could not accurately
evaluate emissions of 5 percent opacity.
In addition, drafting errors in the pro-
posed visible emission limits for cemsnt
kilns and steam generators were cor-
rected. Steam generators will be limited
to visible emissions not greater than 20
percent opacity and cement kilns to not
greater than 10 percent opacity.
11. Specifications for monitoring de-
vices \vers clarified, and directives for
calibration were included. The instru-
ments are to be calibrated at least once
a day, or more often if specified by the
manufacturer. Additional guidance on
the selection and use of such instruments
will be provided at a later date.
12. The requirement for sulfur dioxide
monitoring at steam generators was
deleted for those sources which will
achieve the standard by burning low-sul-
fur fuel, provided that fuel_analysi3 is
conducted and recorded daily. American
Society for Testing and Materials
sampling techniques aore specified for
coal and fuel oil.
13. Provisions were added to the steam
generator standards to cover those in-
stances where mixed fuels are burned.
Allowable emissions will be determined
by prorating the heat input of each fuel,
however, in the case of sulfur dioxide, the
provisions allow operators the option of
burning low-sulfur fuels (probably
natural gas) as a means of compliance.
14. Steam generators fired with lignite
have been exempted from the nitrogen
oxides limit. The revision was made in
view of the lack of information on some
types of lignite burning. When more in-
formation is developed, nitrogen oxides
standards may be extended to lignite
fired steam generators.
15. A provision was added to make it
explicit that the sulfuric acid plant
standards will not apply to scavenger
acid plants. As stated in the background
document, APTD 0711, which was issued
at the time the proposed standards were
published, the standards were not meant
to apply to such operations, e.g., where
sulfuric acid plants are used primarily
to control sulfur dioxide or other sulfur
compounds wliich would otherwise be
vented into the atmosphere.
16. The regulation has been revised
to provide that all materials submitted
pursuant to these regulations will be di-
rected to EPA's OfHce of General En-
forcement.
17. Several other technical changes
have also been made. States and inter-
ested parties are urged to make a careful
reading of these regulations.
As required by section 111 of the Act,
the standards of performance promul-
gated herein "reflect the degree of emis-
sion reduction which (taking Into ac-
count the cost of achieving such reduc-
tion) the Administrator determines has
been adequately demonstrated". The
standards of performance are based on
stationary source testing conducted by
the Environmental Protection Agency
and/or contractors and on data derived
from various other sources, including the
available technical literature. In the com-
ments on the proposed standards, many
questions were raised as to costs and
FEDERAL REGISTER, VOL. 36, NO. 247THURSDAY. DECEMBER 23. 1971
LV-1
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RULES AND REGULATIONS
24877
demonstrated capability of control sys-
tems to meet the standards. These com-
ments have been evaluated and investi-
gated, and it is the Administrator's
judgment that emission control systems
capable of meeting the standards have
been adequately demonstrated'and that
the standards promulgated herein are
achievable at reasonable costs..
The regulations establishing standards
of performance for steam generators, in-
cinerators, cement plants, nitric acid
plants, and sulfuric acid plants are here-
by promulgated effective on publication
and apply to sources, the construction or
modification of which was commenced
after August 17,1971.
Dated: December 16, 1971.
WILLIAM D. RUCKELSHATJS,
Administrator,
Environmental Protection Agency.
A new Part 60 is added to Chapter I,
Title 40, Code of Federal Regulations, as
follows:
Subpart AGeneral Provisions
?ec.
30.1 Applicability.
80.2 Definitions.
60.3 Abbreviations.
60.4 Address.
60S Determination of construction or
modification.
60.6 Review of plans.
60.7 Notification and recordkeeplng.
603 Performance tests.
60.9 Availability of information.
60.10 State authority.
Subpart DStandards of Performance for
Fossil Fuel-Fired Steam Generators
fiO.40 Applicability and designation at af-
fected facility.
60.41 Definitions.
80.42 Standard for particulate matter.
60.43 Standard for eulfur dioxide.
60.44 Standard for nitrogen oxides.
60.45 Emission and fuel monitoring.
60.46 Test methods and procedures.
Subpart EStandards of Performance far
Incinerators
60.60 Applicability and designation of af-
fected tenuity.
60.61 Definitions.
80.62 Standard for particulate matter.
60.53 Monitoring of operations.
60.54 Test methods and procedures.
Subpart FStandards of Performance for
Portland Cement Plants
t>0.60 Applicability and designation of
affected facility.
80.61 Definitions.
60.62 Standard for particulate matter.
60.63 Monitoring of operations.
60.64 Test methods and procedures.
Svbpart GStandards of Performance for Nitric
Acid Plants
60.70 Applicability and designation of af-
fected facility.
60.71 Definitions.
60.72 Standard for nitrogen oxides.
60.73 Emission monitoring.
E0.74 Test methods and procedures.
Subpart HStandards of Performance for Sulfuric
Acid Plants
6080 Applicability and designation of ef-
fected facility.
60.81 Definitions.
Sec.
60.82
60.83
60.84
60.85
Standard for sulfur dioxide.
Standard for acid mist.
Emission monitoring.
Test methods and procedures.
APPENDIXTEST METHODS
Method 1Sample and velocity traverses for
stationary sources.
Method 2Determination of stack gas veloc-
.ity and volumetric flow rate (Type S
pitot tube).
Method 3Gas analysis for carbon dioxide,
excess air, and dry molecular weight.
Method 4Determination of moisture in
stack gases.
Method 5Determination of particulate
emissions from stationary sources.
Method 6Determination of sulfur dioxide
emissions from stationary sources.
Method 7Determination of nitrogen oxide
emissions from stationary sources.
Method 8Determination of sulfuric acid
mist and sulfur dioxide emissions
from stationary sources.
Method 9Visual determination of the opac-
ity of emissions from stationary
sources.
ATJTHORITT: The provisions of this Part 60
Issued under sections 111, 114, Clean Air Act;
Public Law 91-604, 84 Stat. 1713.
Subpart AGeneral Provisions
§ 60.1 Applicability.
The provisions of this part apply to
the owner or operator of any stationary
source, which contains an affected facil-
ity the construction or modification of
which is commenced after the date of
publication in this part of any proposed
standard applicable to such facility.
§ 60.2 Definitions.
As used in this part, all terms not
defined herein shall have the meaning
given them in the Act:
(a) "Act" means the Clean Air Act
(42 U.S.C. 1857 et seq., as amended by
Public Law 91-604, 84 Stat. 1676).
(b) "Administrator'' means the Ad-
ministrator of the Environmental Pro-
tection Agency or his authorized repre-
sentative.
(c) "Standard" means a standard of
performance proposed or promulgated
under this part.
(d) "Stationary source" means any
building, structure, facility, or installa-
tion which emits or may emit any air
pollutant.
(e) "Affected facility" means, with
reference to a stationary source, any ap-
paratus to which a standard is applicable.
(f) "Owner or operator" means any
person who owns, leases, operates, con-
trols, or supervises an affected facility
or a stationary source of which an af-
fected facility is a part.
(g) "Construction" means fabrication,
erection, or installation of an affected
facility.
(h) "Modification" means any physical
change in, or change in the method of
operation of, an affected facility which
increases the amount of any air pol-
lutant (to which a standard applies)
emitted by such facility or which results
in the emission of any air pollutant (to
which a standard applies) not previously
emitted, except that:
(1) Routine maintenance, repair, and
replacement shall not be considered
physical changes, and
(2) The following shall not be consid-
ered a change in the method of
operation:
(i) An increase in the production
rate, If such increase does not exceed the
operating design capacity of the affected
facility;
(ii) An increase in hours of operation;
(iii) Use of an alternative fuel or raw
material if, prior to the date any stand-
ard under this part becomes applicable
to such facility, as provided by § 60.1,
the affected facility is designed to ac-
commodate such alternative use.
(i) "Commenced" means that an own-
er or operator has undertaken a con-
tinuous program of construction or
modification or that an owner or opera-
tor has entered into a binding agree-
ment or contractual obligation to under-
take and complete, within a reasonable
time, a continuous program of construc-
tion or modification.
(j) "Opacity" means the degree to
which emissions reduce the transmission
of light and obscure the view of an object
in the background.
(k) "Nitrogen oxides" means all ox-
ides of nitrogen except nitrous oxide, as
measured by test methods set forth, in
this part.
(1) "Standard of normal conditions"
means 70° Fahrenheit (21.1° centi-
grade) and 29.92 in. Hg (760 mm. Hg).
(m) "Proportional sampling" means
sampling at a rate that produces a con-
stant ratio of sampling rate to stack gas
flow rate.
(n) "Isokinetic sampling" means
sampling in which the linear velocity of
the gas entering the sampling nozzle is
equal to that of the undisturbed gas
stream at the sample point.
(o) "Startup" means the setting in
operation of an affected facility for any
purpose.
. § 60.3 Abbreviations.
The abbreviations used in this part
have the following meanings in both
capital and lower case:
B.t.u.British thermal unit.
cal.calorie (s).
cJ.m.cubic feet per minute.
COScarbon dioxide.
g.gram(s).
gr.grain(s).
mg.nailligram(s).
mm.millimeter (s).
1.liter(s).
nm.nanometer(s), 10-' meter,
pg.microgram(s), 10-° gram.
Hg.mercury.
In.Inch(es).
K1,000.
Ib.poxind(s).
ml.rriilliliter(s).
No.number.
%percent.
NOnitric oxide.
NOjnitrogen dioxide.
NOXnitrogen oxides.
NM.aoormal cubic meter.
s.c.f.sitandard cubic feet.
SO,sulfur dioxide.
E,SO4sulfurlc acid.
SO,sulfur trioxide.
FEDERAL REGISTER, VOL. 36. NO. 247THURSDAY, DECEMBER 23, 1971
IV-2
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24878
RULES AND REGULATIONS
ft.'cnbic feet.
ft.-square feet.
mia_minute(s).
hr.liour(s).
§ 60.1 Address.
All applications, requests, submissions,
and reports under this part shall be sub-
mitted in triplicate and addressed to Uie
Environmental Protection Agency, Office
of General Enforcement, Waterside Mall
SW, Washington, DC 20460.
§ 60.5 Determination of construction or
modification.
When requested to dp so by an owner
or operator, the Administrator win make
a determination of whether actions taken
or intended to be taken by such owner or
operator constitute construction or modi-
fication or the commencement thereof
within the meaning of this part.
§ 60.6 Review of plans.
(a) When requested to do so by an
owner or operator, the Administrator will
review plans for construction or modifi-
cation for the purpose of providing
technical advice to the owner or operator.
(b) (1) A separate request shall be
submitted for each affected facility.
(2) Each request shall (i) identify bhe
location of such affected facility, and (ii)
be accompanied by technical information
describing the proposed nature, size,
design, and method of operation of such
facility, including information on any
equipment to be used for measurement or
control of emissions.
(c) Neither a request for plans review
nor advice furnished by the Administra-
tor in response to such request shall (1)
relieve an owner or operator of legal
responsibility for compliance with any
provision of this part or of any applicable
State or local requirement, or (2) prevent
the Administrator from implementing or
enforcing any provision of this part or
taking any other action authorized by the
Act.
§ 60.7 Notification and record keeping.
(a) Any owner or operator subject to
the provisions of this part shall furnish
the Administrator written notification as
follows:
(1) A notification of the anticipated
date of initial startup of an affected
facility not more than -60 days or less
than 30 days prior to such date.
(2) A notification of the actual date
of initial startup of an affected facility
within 15 days after such date.
(b) Any owner or operator subject to
the provisions of this part shall maintain
for a period of 2 years a record of the
occurrence and duration of any startup,
shutdown, or malfunction in operation of
any affected facility.
§ 60.3 Performance lests.
(a) Within 60 days after achieving the
maximum production rate at which the
affected facility will be operated, but not
later than 180 days after initial startup
of such facility and at such other times
as may be required by the Administrator
under section 114 of the Act, the owner
or operator of such facility shall conduct
performance test(s) and furnish the Ad-
ministrator a written report of the results
of such performance test(s).
(b) Performance tests shall be con-
ducted and results reported in accord-
ance with the test method set forth in
this part or equivalent methods approved
by the Administrator; or where the Ad-
ministrator determines that emissions
from the affected facility are not sus-
ceptible of being measured by such
methods, the Administrator shall pre-
scribe alternative test procedures for
determining compliance with the re-
quirements of this part.
(c) The owner or operator shall permit
tha Administrator to conduct perform-
ance tests at any reasonable time, shall
cause the affected facility to be operated
for purposes of such testa under such
conditions as the Administrator shall
specify based on representative perform-
ance of the affected facility, and shall
make available to the Administrator
such records as may be necessary to
determine such performance.
(d) The owner or operator of an
affected facility shall provide the Ad-
ministrator 10 days prior notice of the
performance test to afford the Admin-
istrator the opportunity to have an ob-
server present.
(e) The owner or operator of an
affected facility shall provide, or cause to
be provided, performance testing facil-
ities as follows:
(1) Sampling ports adequate for test
methods applicable to such facility.
(2) Safe sampling platform(s).
(3) Safe access to sampling plat-
form (s).
(4) Utilities for sampling and testing
equipment.
(f) Each performance test shall con-
sist of three repetitions of the applicable
test method. For the purpose of deter-
mining compliance with an applicable
standard of perform ince, the average of
results of all repetitions shall apply.
§ 60.9 Availability of information.
(a) Emission data provided to, or
otherwise obtained by, the Administra-
tor in accordance with the provisions of
this part shall be available to the public.
(b) Except as provided in paragraph
(a) of this section, any records, reports,
or information provided to, or otherwise
obtained by, the Administrator in accord-
ance with the provisions of this part
shall be available to the public, except
that (1) upon a showing satisfactory to
the Administrator by any person that
such records, reports, or information, or
particular part thereof (other than
emission data), if made public, would
divulge methods or processes entitled to
protection as trade secrets of such per-
son, the Administrator shall consider
such records, reports, or information, or
particular part thereof, confidential in
accordance with the purposes of section
1905 6f title 18 of the United States
Code, except that such records, reports,
or information, or particular part there-
of, may be disclosed to other officers, em-
ployees, or authorized representatives of
the United States concerned with carry-
ing out the provisions of the Act or when
relevant in any proceeding under ths
Act; and (2) information received by the
Administrator solely for the purposes of
§5 60.5 and 60.6 shall not be disclosed
if it is identified by the owner or opera-
tor ~as being a trade secret or com-
mercial or financial information which
such owner or operator considers
confidential.
§ 60.10 Slate authority.
The provisions of this part shall not
be construed in any manner to preclude
any State or political subdivision thereof
from:
(a) Adopting and enforcing any emis-
sion standard or limitation applicable to
an affected facility, provided that such
emission standard or limitation is not
less stringent than the standard appli-
cable to such facility.
(b) Requiring the owner or operator
of an affected facility to obtain permits,
licenses, or approvals prior to initiating
construction, modification, or operation
of such facility.
Subpart DStandards of Performance
for Fossil-Fuel Fired Steam Generators
§ 60.40 Applicability and designation of
affected facility.
The provisions of this suBpart are ap-
plicable to each fossil fuel-fired steam
generating unit of more than 250 million
B.t.u. per hour heat input, which is ths
affected facility.
§ 60.41 Definitions.
As used in this subpart, all terms not
defined herein shall have the meaning
given them in the Act, and in Subpart
A of this part.
(a) "Fossil fuel-fired steam generat-
ing unit" means a furnace or boiler used
in the process of burning fossil fuel
for the primary purpose of producing
steam by heat transfer.
(b) "Fossil fuel" means natural gas,
petroleum, coal and any form of solid,
liquid, or gaseous fuel derived from
such materials.
(c) "Particulate matter" means any
finely divided liquid or solid material,
other than uncombined water, as meas-
ured by Method 5.
§ 60.42 Standard for paniculate matter.
On and after the date on which the
performance test required to be con-
ducted by § 60.8 Is initiated no owner
or operator subject to the provisions of
this part shall discharge or cause the
discharge into the atmosphere of par-
ticulate matter -which is:
(a) In excess of 0.10 Ib. per million
B.t.u. heat input (0.18 g. per million caL)
maximum 2-hour average.
(b) Greater than 20 percent opacity,
except that 40 percent opacity shall be
permissible for not more than 2 minutes
in any hour.
(c) Where the presence of unconv
bined water is the only reason for fail-
ure to meet the requirements of para-
graph (b) of this section such failure
shall not be a violation, of this section.
FEDERAL REGISTER, VOL. 36, NO. 247THURSDAY, DECEMBER 23, 1971
IV-3
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RULES AND REGULATIONS
24879
§ 60.43 Standard for gulfur dioxide.
On and after the date on which the
performance test required to be con-
ducted by § 60.8 is initiated no owner
or operator subject to the provisions
of this part shall discharge or cause the
discharge into the atmosphere of sulfur
dioxide in excess of:
(a) 0.80 Ib. per million B.t.u. heat in-
put (1.4 g. per million cal.), maximum 2-
hour average, when liquid fossil fuel is
burned.
(b) 1.2 Ibs. per million B.t.u. heat input
(2.2 g. per million cal.), maximum 2-
hour average, when solid fossil fuel is
burned.
(c) Where different fossil fuels are
burned simultaneously in any combina-
tion, the applicable standard shall be
determined by proration. Compliance
shall be determined using the following
formula:
y(0.80)+z(15)
x+y+z
where:
x Is the percent of total beat input derived
from gaseous fossil fuel and,
y is the percent of total heat input derived
from liquid fossil fuel and,
z is the percent of total heat input derived
from solid fossil fuel.
§ 60,44 Standard for nitrogen oxides.
On and after the date on which the
performance test required to be con-
ducted by § 60.8 is initiated no owner or
operator subject to the provisions of this
part shall discharge or cause the dis-
charge into the atmosphere of nitrogen
oxides in excess of:
(a) 0.20 Ib. per million B.t.u. heat in-
put (0.36 g. per million cal.), maximum
2-hour average, expressed as NO:, when
gaseous fossil fuel is burned.
(b) 0.30 Ib. per million B.t.u. heat in-
put (0.54 g. per million cal.), maximum
2-hour average, expressed as NOs, when
liquid fossil fuel is burned.
(c) 0.70 Ib. per million B.t.u. heat in-
put (1.26 g. per million cal.), maximum
2-hour average, expressed .as NOj when
solid fossil fuel (except lignite) is burned.
(d) When different fossil fuels are
burned simultaneously in any combina-
tion the applicable standard shall be de-
termined by proration. Compliance shall
be determined by using the following
formula:
x(0.20) +y(0.30) +z(0.70)
x+y+z
where:
I is the percent of total heat Input derived
from gaseous fossil fuel and,
y is the percent of total heat input derived
from liquid fossil fuel and,
z is the percent of total heat input derived
from solid fossil fuel.
§ 60.45 Emission and fuel monitoring.
(a) There shall be installed, cali-
brated, maintained, and operated, in any
fossil fuel-fired steam generating unit
subject to the provisions of this part,
emission monitoring instruments as
follows:
(1) A photoelectric or other type
smoke detector and recorder, except
where gaseous fuel is the only fuel
burned.
(2) An instrument for continuously
monitoring and recording sulfur dioxide
emissions, except where gaseous fuel is
the only fuel burned, or where compli-
ance is achieved through low sulfur fuels
and representative sulfur analysis of
fuels are conducted daily in accordance
with paragraph (c) or (d) of this section.
(3) An instrument for continuously
monitoring and recording emissions of
nitrogen oxides.
(b) Instruments and sampling systems
installed and used pursuant to this sec-
tion shall be capable of monitoring emis-
sion levels within ±20 percent with a
confidence level of 95 percent and shall
be calibrated in accordance with the
method(s) prescribed by the manufac-
turer (s) of such instruments; instru-
ments shall be subjected to manufactur-
ers recommended zero adjustment and
calibration procedures at least once per
24-hour operating period unless the man-
ufacturerCs; specifies or recommends
calibration at shorter intervals, in which
case such specifications or recommenda-
tions shall be followed. The applicable
method specified in the appendix of this
part shall be the reference method.
(c) The sulfur content of solid fuels,
as burned, shall be determined iu accord-
ance with the following methods of the
American Society for Testing and
Materials.
(1) Mechanical sampling by Method
D 2234065.
(2) Sample preparation by Method D
2013-65.
(3) Sample analysis by Method D
271-68.
(d) The sulfur content of liquid fuels,
as burned, shall be determined in accord-
ance with the American Society for Test-
ing and Materials Methods D 1551-68, or
D 129-64, or D 1552-64.
(e) The rate of fuel burned for each
fuel shall be measured daily or at shorter
intervals and recorded. The heating
value and ash content of fuels shall be
ascertained at least once per week and
recorded. Where the steam generating
unit is used to generate electricity, the
average electrical output and the mini-
mum and maximum hourly generation
rate shall be measured and recorded
daily.
(f) The owner or operator of any
fossil fuel-fired steam generating unit
subject to the provisions of this part
shall maintain a file of all measurements
required by this part. Appropriate meas-
urements shall be reduced to the units
of the applicable standard daily, and
summarized monthly. The record of any
such measurement (s) and summary
shall be retained for at least 2 years fol-
lowing the date of such measurements
and summaries.
§ 60.46 Test methods and procedures.
<"a) The provisions of this section are
applicable to performance tests for de-
termining emissions of particulate mat-
ter, sulfur dioxide, and nitrogen oxides
from fossil fuel-fired steam generating
units.
(b) All performance tes ts shall be con -
ducted while the affected facility is oper-
ating at or above the maximum steam
production rate at which such facility
will be operated and while fuels or com-
binations of fuels representative of
normal operation are being burned and
under such other relevant conditions as
the Administrator shall specify based
on representative performance of the
affected facility.
(c) Test methods set forth in the
appendix to this part or equivalent
methods approved by the Administrator
shall be used as follows:
(1) For each repetition, the average
concentration of particulate matter shall
be determined by using Method 5.
Traversing during sampling by Method 5
shall be according to Method 1. The
minimum sampling time shall be 2 hours,
and minimum sampling volume shall be
60 ft.;> corrected to standard conditions
on a dry basis.
(2) For each repetition, the SO* con-
centration shall be determined by using
Method 6. The sampling site shall be the
same as for determining volumetric flow
rate. The sampling point in the duct
shall be at the centroid of the cross
section if the cross sectional area is less
than 50 ft." or at a point no closer to the
walls than 3 feet if the cross sectional
area is 50 ft.1 or more. The sample shall
be extracted at a rate proportional to the
gas velocity at the sampling point. The
minimum sampling time shall be 20 min.
and minimum sampling volume shall be
0.75 ft.' corrected to standard conditions.
Two samples shall constitute one repeti-
tion and shall be taken at 1-hour
intervals.
(3) For each repetition the NO, con-
centration shall be determined by using
Method 7. The sampling site and point
shall be the same as for SO.. The sam-
pling time shall be 2 hours, and four
samples shall be taken at 30-minute
intervals.
(4) The volumetric flow rate of the
total effluent shall be determined by using
Method 2 and traversing according to
Method 1. Gas analysis shall be per-
formed by Method 3, and moisture con-
tent shall be determined by the con-
denser technique of Method 5.
(d) Heat input, expressed in B.t.u. per
hour, shall be determined during each 2-
hour testing period by suitable fuel flow
meters and shall be confirmed by a ma-
ts*, ial balance over the steam generation
system.
(e) For each repetition, emissions, ex-
pressed in lb./100 B.t.u. shall be deter-
mined by dividing ihe emission rate in
Ib./hr. by the heat input. The emission
rate shall be determined by the equation,
Ib./hr.Q,Xc where. Q,=volumetric
flow rate of the total effluent in f t.Vhr. at
standard renditions, dry basis, as deter-
mined in accordance with paragraph (c)
(4) of this section.
(1) For particulate matter, c=partic-
Ulate concentration in lb./ft.:l, at deter-
mined in accordance with paragraph (c)
(1) of this .section, corrected to standard
conditions, dry basis.
FEDERAL REGISTER, VOL. 36, NO. 247THURSDAY, DECEMBER 23, 1971
IV-4
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2iSSO
RULES AND REGULATIONS
(2) For SO!, c=SO2 concentration in
Ib./f t.3, as determined in accordance with.
paragraph (c) (2) of this section, cor-
rected to standard conditions, dry basis.
(3) For NO*, c=NO, concentration in
Ib./f t.3, as determined in accordance with
paragraph (c) (3) of this section, cor-
rected to standard conditions, dry basis.
Subpart EStandards of Performance
for Incinerators
§ 60.50 Applicability and designation of
affected facility.
The provisions of this subpart are ap-
plicable to each incinerator of more than
S'j tons per day charging rate, which is
tiie affected facility.
§ 60.51 Definitions.
As used iii this subpart, PlI terms not
denned herein shall have the meaning
.given them in the Act and in Subpart A
of this part.
(a) "Incinerator" means any furnace
used in the process of burning solid waste
for the primary purpose of reducing the
volume of the waste by removing com-
bustible matter.
(b) "Solid waste" means refuse, more
than 50 percent of which is municipal
type waste consisting of a mixture of
paper, wood, yard wastes, food wastes,
plastics, leather, rubber, and other com-
bustibles, and noncombustible materials
such as glass and rock.
(c) "Day" means 24 hours.
(d) "Particulate matter" means any
finely divided liquid or solid material,
other than uncombined water, as meas-
ured by Method 5.
§ 60.52 Standard for particulale matter.
On and after the date on which the
performance test required to be con-
ducted by § 60.8 Is initiated, no owner
or operator subject to the provisions of
this part shall discharge or cause the
discharge into the atmosphere of par-
ticulate matter which is in excess of 0.08
gr./s.c.f. (0.18 g./NM") corrected to 12
percent CO*, maximum 2-hour average.
§ 60.53 Monitoring of operations.
The owner or operator of any In-
cinerator subject to the provisions of thia
part shall maintain a file of daily burn-
ing rates and hours of operation and any
particulate emission measurements. The
burning rates and hours of operation
shall be summarized monthly. The
record(s) and summary shall be retained
for at least 2 years following the date of
such records and summaries.
§ 60.54 Test methods and procedures.
(a) The provisions of this section are
applicable to performance tests for de-
termining emissions of particulate matter
from incinerators.
(b) All performance tests shall be
conducted while the affected facility is
operating at or above the maximum
refuse charging rate at which such facil-
ity will be operated and the solid waste
burned shall be representative of normal
operation and under such other relevant
conditions as the Administrator shall
specify based on representative per-
formance of the affected facility.
(c) Test methods set forth in the ap-
pendix to this part or equivalent methods
approved by the Administrator shall be
used as follows:
(1) For each repetition, the average
concentration of particulate matter shall
be determined by using Method 5. Tra-
versing during sampling by Method 5
shall be according to Method 1. The mini-
mum sampling time shall be 2 hcurs and
the minimum sampling volume snail be
60 ft.1 corrected to standard conditions
on a dry basis.
(2) Gas analysis shall be performed
using the integrated sample technique of
Method 3, and moisture content shall be
determined by the condenser technique
of Method 5. If a wet scrubber is used,
the gas analysis sample shall reflect flue
gas conditions after the scrubber, allow-
ing for the effect of carbon dioxide ab-
sorption.
(d) For each repetition particulate
matter emissions, expressed in gr./s.c.f.,
shall be determined in accordance with
paragraph (c) (1) of this section cor-
rected to 12 percent CO,, dry basis.
Subpart FStandards of Performance
for Portland Cement Plants
§ 60.60 Applicability and designation of
affected facility.
The provisions of the subpart are ap-
plicable to the following affected facili-
ties in Portland cement plants: kiln,
clinker cooler, raw mill system, finish
mill system, raw mill dryer, raw material
storage, clinker storage, finished prod-
uct storage, conveyor transfer points,
bagging and bulk loading and unloading
systems.
§ 60.61 Definitions.
As used in this subpart, all terms not
defined herein shall have the meaning
given them in the Act and in Subpart A
of this part.
(a) "Portland cement plant" means
any facility manufacturing Portland ce-
ment by either the wet or dry process.
(b) "Particulate matter" means any
finely divided liquid or solid material,
other than uncombined water, as meas-
ured by Method 5.
§ 60.62 Standard for partirulate matter.
(a) On and after the date on which
the performance test required to be con-
ducted by § 60.8 is initiated no owner
or operator subject to the provisions of
this part shall discharge or cause the
discharge into the atmosphere of par-
ticulate matter from the kiln which is:
(1) In excess of 0.30 Ib. per ton of feed
to the kiln (0.15 Kg. per metric ton),
maximum 2-hour average.
(2) Greater than 10 percent opacity,
except that where the presence of uncom-
bined water is the only reason for failure
to meet the requirements for this sub-
paragraph, such failure shall Hot be a
violation of this section.
(b) On and after the date on which
the performance test required to be con-
ducted by | 60.8 is initiated no owner
or operator subject to the provisions of
this part shall discharge or cause the dis-
charge into the atmosphere of particulate
matter from the clinker cooler which is:
(1) In excess of 0.10 Ib. per ton of feed
to the kiln (0.050 Kg. per metric ton)
maximum 2-hour average.
(2) 10 percent opacity or greater.
(c) On and after the date on which the
performance test required to be con-
ducted by § 60.8 is initiated no owner
cr operator subject to the provisions of
this part shall discharge or cause the
discharge into the atmosphere of partic-
ulate matter from any affected facility
other than the kiln and clinker cooler
which is 10 percent opacity or greater.
§ 60.63 Monitoring of operations.
The owner or operator of any Portland
cement plant subject to the provisions
of this part shall maintain a file of daily
production rates and kiln feed rates and
any particulate emission measurements.
The production and feed rates shall be
summarized monthly. The record(s) and
summary shall be retained for at least
2 years following the date of such record:.
and summaries.
§ 60.64 Test methods and procedures.
(a) The provisions of this section are
applicable to performance tests for de-
termining emissions of particulate mat-
ter from Portland cement plant kilns
and clinker coolers.
(b) All performance tests shall be
conducted while the affected facility is
operating at or above the maximum
production rate at which such facility
will be operated and under such other
relevant conditions as the Administrator
shall specify based on representative per-
formance of the affected facility.
(c) Test methods set forth in the ap-
pendix to this part or equivalent meth-
ods approved by the Administrator shall
be used as follows:
(1) For each repetition, the average
concentration of particulate matter shall
be determined by using Method 5. Tra-
versing during sampling by Method 5
shall be according to Method 1. The mini-
mum sampling time shall be 2 hours and
the minimum sampling volume shall be
60 ft.' corrected to standard conditions
on a dry basis.
(2) The volumetric flow rate of the
total effluent shall be determined by x:s-
ing Method 2 and traversing according to
Method 1. Gas analysis shall be per-
formed using the integrated sample tech-
nique of Method 3, and moisture content
shall be .determined by the condenser
technique of Method 5.
(d) Total kiln feed (except fuels), ex-
pressed in tons per hour on a dry basis,
shall be determined during each 2-hour
testing period by suitable flow meters
and shall be confirmed by a material
balance over the production system.
(e) For each repetition, particulate
matter emissions, expressed in Ib./ton of
kiln feed shall be determined by dividing
the emission rate hi Ib./hr. by the kiln
feed. The emission rate shall be deter-
mined by the equation, lb./hr.=Q»xc,
FEDERAL REGISTER, VOL. 36, NO. 247THURSDAY, DECEMBER 23, 1971
IV-5
-------
RULES AND REGULATIONS
24881
where Q.=volumetric flow rate of the
total effluent in f t.'/hr. at standard condi-
tions, dry basis, as determined in ac-
"cordance with paragraph (c) (2) of this
section, and, c=particulate concentra-
tion in lb./ft.*, as determined in accord-
ance with paragraph (c) (1) of this
section, corrected to standard conditions.
dry basis.
Subpcrt GStandards of Performance
for Nitric Acid Plants
§ 60.70 Applicability and designation of
affected facility.
The provisions of this subpart are
applicable to each nitric acid production
unit, -which is the affected facility.
§ 60.71 Definitions.
As used in this subpart, all terms not
defined herein shall have the meaning
given them in the Act and in Subpart A
of this part.
(a) "Nitric acid production unit"
means any facility producing weak nitric
acid by either the pressure or atmos-
pheric pressure process.
(b) "Weak nitric acid" means acid
which is 30 to 70 percent in strength.
§ 60.72 Standard for nitrogen oxides.
On and after the date on which the
performance test required to be con-
ducted by § 60.8 is initiated no owner
or operator subject to the provisions of
this part shall discharge or cause the
discharge into the atmosphere of nitro-
gen oxides which are:
(a) In excess of 3 Ibs. per ton of acid
produced (1.5 kg. per metric ton),
maximum 2-hour average, expressed as
NO,,.
(b) 10 percent opacity or greater.
§ 60.73 Emission monitoring.
(a) There shall be installed, cali-
brated, maintained, and operated, in any
nitric acid production unit subject to
the provisions of this subpart, an instru-
ment for continuously monitoring and
recording emissions of nitrogen oxides.
Cb) The instrument and sampling
system installed and used pursuant to
this section shall be capable of monitor-
ing emission levels within ±20 percent
with a confidence level of 95 percent and
shall be calibrated in accordance with
the method (s) prescribed by the manu-
facturer (s) of such instrument, the
Instrument shall be subjected to
manufacturers recommended zero ad-
justment and calibration procedures at
least once per 24-hou: operating period
unless the manufacturerfs) specifies or
recommends calibration at shorter in-
tervals, in which case such specifications
or recommendation.s shall be followed.
The applicable method specified in the
appendix of this part shall be the ref-
erence method.
(c) Production rate and hours of op-
eration shall be recorded daily.
(d) The owner or operator of any
nitric acid production unit subject to the
provisions of this part shall maintain
a file of all measurements required by
this subpart. Appropriate measurements
shall be reduced to the units of the
standard daily and summarized monthly.
The record of-any such measurement
and summary shall be retained for at
least 2 years following the date of such
measurements and summaries.
§ 60.74 Test methods and procedures.
(a) The provisions of this section are
applicable to performance tests for de-
termining emissions of nitrogen oxides
from nitric acid production units.
(b) All performance tests shall be
conducted while the affected facility is
operating at or above the maximum acid
production rate at which such fa.ci.ity
will be operated and under such other
relevant conditions as the Administra-
tor shall specify based on representa-
tive performance of the affected facility.
(c) Test methods set forth in the ap-
pendix to this part or equivalent methods
as approved by the Administrato" shall
be used as follows:
(1) £'or each repetition the NO, con-
centration shall be determined by using
Method 7. The sampling site shall be
selected according to Method 1 and the
sampling point shall be the centroid of
the stack or duct. The sampling time
shall be 2 hours and four samples shall
be taken at 30-minute intervals.
(2) The volumetric flow rate of the
total effluent shall be determined by
using Method 2 and traversing accord-
ing to Method 1. Gas analysis shall be
performed by using the integrated
sample technique of Method 3^ and
moisture content shall be determined by
Method 4.
(d) Acid produced, expressed in tons
per hour of 100 percent nitric acid, shall
be determined during each 2-hour test-
ing period by suitable flow meters and
shall be confirmed by a material bal-
ance over the production system.
(e) For each repetition, nitrogen
oxides emissions, expressed in Ib./ton
of 100.percent nitric acid, shall be de-
termined 'by dividing the emission rate
in Ib./hr. by the acid produced. The
emission rate shall be determined by
the equation, lb./hr.=QsXc, where
Qs=volumetric flow rate of the effluent
in ft.'/hr. at standard conditions, dry
basis, as determined in accordance with
paragraph (c) (2) of this section, and
c=NOi concentration in Ib./ft.!, as de-
termined in accordance with paregr&nh
(c) (1) of this section, corrected to stand-
ard conditions, dry basis.
Subpart H Standards of Performance
for Sulfuric Acid Plants
§ 60.80 Applicability and designation of
affected facility.
The provisions of this subpart are ap-
plicable to each sulfuric acid production
unit, which is the affected facility.
§ 60.81 Definitions.
As used in this subpart, all terms not
denned herein shall have the meaning
given them hi the Act and in Subpart A
of this part.
(a) "Sulfuric acid production unit"
means any facility producing sulfuric
acid by the contact process by burning
elemental sulfur, alkylation acid, hydro-
gen sulfide, organic sulfides and mer-
captans, or acid sludge, but does not in-
clude facilities where conversion to sul-
furic acid is utilized primarily as a means
of preventing emissions to the atmos-
phere of sulfur dioxide or other sulfur
compounds.
(b) "Acid mist" means sulfuric acid
mist, as measured by test methods set
forth in this part.
§ 60.82 Standard for sulfur dioxide.
On and after the date on which the
performance test required to be con-
ducted by § 60.8 is initiated no owner or
operator subject to the provisions of this
part shall discharge or cause the dis-
charge into the atmosphere of sulfur
dioxide in excess of 4 Ibs. per ton of acid
produced (2 kg. per metric ton), maxi-
mum 2-hour average.
§ 60.83 Standard for acid mkt.
On and after the date on which the
performance test required to be con-
ducted. by § 60.8 is initiated no owner or
operator subject to the provisions of this
part shall discharge or cause the dis-
charge into the atmosphere of acid mist
which is:
(a) In excess of 0.15 Ib. per ton of acid
produced (0.075 kg. per metric ton),
maximum 2-hour average, expressed RS
(b) 10 percent opacity or greater.
§ 60.8 1 Emission monitoring.
(a) There shall be installed, cali-
brated, maintained, and operated, in any
sulfuric acid production unit subject to
the provisions of this subpart, an in-
strumeat for continuously monitoring
and recording emissions of sulfur dioxide.
(b) The instrument and sampling sys-
tem installed and used pursuant to this
section shall be capable of monitoring
emission levels within ±20 percent with
a confidence level of 95 percent and sbtUJ
be calibrated in accordance with the
FEDERAL REGISTER. VOL 36. NO. 247THURSDAY, DECEMBER 23, 1971
IV-G
-------
24882
RULES AND REGULATIONS
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CO « ** 'tO 63
CO O> Cn 'CT» C71
to t^*
ro 10 co
O> Ol O>
\o
CO
cn
eo «, o f- CM c, ^
cu
ro O
o
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o
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W
o
TO £
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T- 3
Q> -
S, &
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U- is
o
o
IV-8
-------
!!S84
RULES AND REGULATIONS
222 For rectangular stacks divide the
cross section, into as many equal rectangular
are^s as traverse points, such that the ratio
of the length to the width of the elemental
arcoo is between one and- two. Locate the
tr.worse points at the centroid of each equal
area according to Figure 1-3.
3. References.
Determining Dust Concentration in a Gas
S*,ream, ASME Performance Test Code #27,
New York, N.Y., 1957.
Devorkin, Howard, et al.. Air Pollution
Secures Testing Manual, Air Pollution Control
Dutrict, Los Angeles, Calif. November 1963.
Methods for Determination of Velocity,
Volume, Dust and Mist Content of Gases,
Western Precipitation Division of Joy Manu-
facturing Co., Los Angeles, Calif. Bulletin
WP-30, 1968.
Standard Method for Sampling Stacks for
Partlculate Matter, In: 1971 Book of ASTM
Standards, Part 23, Philadelphia, Pa. 1971,
ASTM Designation D-2928-71.
METHOD 2 DETERMINATION OV STACK GAS
VELOCITY AND VOLUMETRIC FLOW RATE (TYPE
S PTTOT TUBE)
1. Principle and applicability.
1.1 Principle. Stack gas velocity is deter-
mined from the gas density and from meas-
urement of the velocity head using a Type S
(Stauschelbe or reverse type) pitot tube.
1.2 Applicability. This method should be
applied only when specified by the test pro-
cedures for determining compliance with the
New Source Performance Standards.
2. Apparatus.
2.1 Pitot tubeType S (Figure 2-1), or
equivalent, with a coefficient within ±5%
over the working range.
2.2 Differential pressure gaugeInclined
manometer, or equivalent, to measure velo-
city head to witnin 10% of the minimum
value.
2.3 Temperature gaugeThermocouple or
equivalent attached to the pitot tube to
measure stack temperature to within 1.5% of
tho minimum absolute stack temperature.
2.4 Pressure gaugeMercury -filled U- tube
manometer, or equivalent, to measure stack
pressure to within 0.1 in. Hg.
2.5 BarometerTo measure atmospheric
pressure to within 0.1 in. Hg.
2.6 Gas analyzerTo analyze gas composi-
tion for determining molecular weight.
2.7 Pitot tubeStandard type, to cali-
brate Type S pitot tube.
3. Procedure.
3.1 Set up the apparatus as shown In Fig-
ure 2-1. Make sure all connections are tight
and leak free. Measure tHe velocity head and
temperature at the traverse points specified
by Method 1.
3.2 Measure the static pressure in the
stack.
3.3 Determine the stack gas molecular
weight by gas analysis and appropriate cal-
culations as indicated in Method 3.
PIPE COUPLING
TUBING ADAPTER
4. Calibration.
4.1 To calibrate the pitot tube, measure
the velocity head at some point In a flowing
gas stream with both a Type S pitot tube and
a standard type pitot tube with known co-
efficient. Calibration should be done in the
laboratory and the velocity of the flowing gas
stream should be varied over the normal
working range. It is recommended that the
calibration be repeated after use at each field
site.
4.2 Calculate the pitot tube coefficient
using equation 2-1.
APteit equation Z-l
where:
cpt,sl = Pitot tube coefficient of Type s
pitot tube.
CP.,,a=Pitot tube coefficient of standard
type pitot tube (if unknown, use
0.99).
Apitd= Velocity head measured by stand-
ard type pitot tube.
jlpt,,t= Velocity head measured by Type B
pitot tube.
4.3 Compare the coefficients of the Type 8
pitot tube determined first with one leg and
then the other pointed downstream. Use the
pitot tube only if the two coefflciente differ by
no more than 0.01.
5. Calculations.
Use equation 2-2 to calculate the stack gas
velocity.
(V.)..«.=K,,Cp(VAp)«
where:
(V,).r, = Stack gaa velocity, feet per second (f.pj.).
'when these units
»/' "> V
see. VJb. mole-0 JR/
are used.
(T.).
pitot tube coefficient, dimeoslonless.
= Average absolute stack gaa temperature,
°
.
( V5p) , =Average velocity head of stack gas. Indue
HiO (see Fig. 2-2).
P.=Absolute stack gaa pressure, inches Hg.
M, = . Molecular weight of stack gag (wet basis),
Ib./lb.-mole.
Mdd-B.o)+18Bw.
Ma=Dry molecular weight of stack gas (tore
Methods).
B.,=Proportion by volume of water vapor ta
the gas stream (from Method 4).
Figure 2-2 shows a sample recording sheet
for velocity traverse data. Use the averages
In the last two columns of Figure 22 to de-
termine the average stack gas Telocity from
Equation 22.
Use Equation 2-3 to calculate the stack
gas volumetric flow rate.
Figure 2-1. Pitot tube-manometer assembly.
Equation 2-3
where:
Q»=Volumetric flow rate, dry basis, standard condj
tlons, ft.Vhr.
A = Cross-sectional area of stack, ft.1
T«d=- Absolute temperature at standard condition*,
830° E.
P»id= Absolute pressure at standard conditions, 29.91
Inches Hg.
FEDERAL REGISTER, VOL. 36, NO. 247THURSDAY, DECEMBER 23, 1971
IV-9
-------
RULES AND REGULATIONS
Z4885
6. References.
Mark, Ii. S., Mechanical Engineers' Hand-
book, McGraw-Hill Book Co., Inc., New York,
N.Y., 195X.
Perry, J. H., Chemical Engineers' Hand-
book, McGraw-Hill Book Co., Inc., New York,
N.Y., 1960.
Shlgehara, R. T.( W. F. Todd, and W. S.
Smith, Significance of Errors In Stack Sam-
PLANT.
DATE
RUN NO.
STACK DIAMETER, in._
BAROMETRIC PRESSURE, in. Hg._
STATIC PRESSURE IN STACK (Pg), in. Hg._
OPERATORS
pllng Measurements. Paper presented at the
Annual Meeting of the Air Pollution Control
Association, St. Louis, Mo., June 14-19, 1970.
Standard Method for Sampling Stacks for
Paniculate Matter, In: 1971 Book of ASTM
Standards, Part 23, Philadelphia, Pa., 1971,
ASTM Designation D-2928-71.
Vennard, J. K., Elementary Fluid Mechan-
ics, John Wiley & Sons, Inc., New York, N.Y.,
1947.
SCHEMATIC OF STACK
CROSS SECTION
Traverse point
number
Velocity head,
in. H
Stack Temperature
AVERAGE:
Figyre 2-2. Velocity traverse data.
FEDERAL REGISTER, VOL. 36, NO. 247THURSDAY. DECEMBER 23. 1971
IV-10
-------
24886
RULES AND REGULATIONS
METHOD 3 GAS ANALYSIS FOB CASBON O1OXIDE,
EXCESS AIR, AND DRY MOLECCTLAK WEIGHT
1. Principle and applicability.
1.1 Principle. An Integrated or grab gas
sample Is extracted from a sampling point
and analyzed for Its components using an
Orsat analyzer.
1.2 Applicability. This method should be
r.pplied only when specified by the teat pro-
cedures lor determining compliance with the
New Source Performance Standards. The test
procedure will indicate whether a grab sam-
ple or an integrated sample is to be used.
2. Apparatus.
2.1 Grab sample (Figure 3-1).
2.1.1 ProbeStainless steel or Pyrex1
e'p-ss, equipped with a filter to remove partic-
ulate matter.
2.1.2 PumpOne-way squeeze bulb, or
equivalent, to transport gas sample to
analyzer.
1 Trade name.
2.2 Integrated sample (Figure 3-2).
2.2.1 ProbeStainless steel or Pyrex1
glass, equipped with a filter to remove per-
ticulate matter.
2.2.2 Air-cooled condenser or equivalent
To remove any excess moisture.
2.2.3 Needle valveTo adjust flow rate.
2.2.4 PumpLeak-free, diaphragm type,
or equivalent, to pull gas.
2.2.5 Rite meterTo measure a flow
ranga from 0 to 0.035 cfm.
2 2 G Flexible bagTedlar,1 or equivalent,
with a capacity of 2 to 3 cu. It. Leak test the
bag in the laboratory before u^mg.
2.2,7 Picot tubeType S, or equivalent,
attached to the probe so that the sampling
flow rate can be regulated proportional to
the stack gas velocity when velocity is vary-
ing with time or a sample traverse is
conducted.
2.3 Analysis.
2.,? i Gisa', analyzer, or equivalent.
PROBE
FLEXIBLE TUBING
TO ANALYZER
TERIG
FILTER [CLASS WOOL)
SQUEEZE BULB
Figure 3-1. Grab-sampling train.
RATE METER
VALVE
AIR-COOLED CONDENSER / PUMP
PROBE
FILTER [GLASS WOOL)
QUICK DISCONNECT
RIGID CONTAINER"
Figure 3-2. Integrated gas sampling train.
3. Procedure.
3.1 Grab sampling.
3.1.1 Set up the equipment as shown in
Figure 31, making sure all connections are
leak-free. Place the probe in the stack at a
sampling point and purge the sampling line.
3.1.2 Draw sample into the analyze*
3.2 Integrated sampling.
3.2.1 Evacuate the flexible bag. Set up the
equipment as shown in Figure 3-2 with the
bag disconnected. Place the probe 'in the
stack and purge the sampling line. Connect
the bag, making sure that ail connections are
tight and thai there are no leaks.
3.2.2 Sample at a rate proportional to '.he
stack velocity.
3.3 Analysis.
3.3.1 Determine the CO., O,, and CO con-
centrations as sooa as possibie.'Make as many
passes as are necessary to give constant read-
ings. If more than ten passes are necessary,
replace the absorbing solution,
3.3.2 For grab sampling, repeat the sam«
pling and analysis until three consecutive
samples vary no more than 0:5 percent by
volume for each component being analyzed.
3.3.3 For Integrated sampling, repeat tie
analysis of the sample until three consecu-
tive analyses vary no more than 0.2 percent
by volume for each component being
analyzed.
4. Calculations.
4.1 Carbon dioxide. Average tae three con-
secutive runs and report the result to the
nearest 0.1% CO^
4.2 Excess air. Use Equation 3-1 to calcu-
late excess air, and average the runs. Report
the result to the nearest 0.1% excess air.
%EA =
(%0,)-0.5(%CO)
0.264(% Ns)-(% 02)+0.5(%
equation 3-1
where:
%EA=Fercent excess air.
%Oj=Percent oxygen by volume, dry basis.
%N3=Percent nitrogen, by volume, dry
basis.
% CO=Percent carbon monoxide by vol-
ume, dry basis.
0.264=Ratio of oxygea to nitrogen In all
by volume.
4.3 Dry molecular weight. TJse Equation
3-2 to calculate dry molecular weight and
.average the runs. Report the result to th«
nearest tenth.
M«=0.44(%CO.,) +0.32(%
equation 3-3
where:
M*=Ory molecular weight, Ib./lb-mole.
%CO»=Percent carbon dioxide by volume,
dry basis.
%Oi=Percent "oxygen by volume, dry
basis.
%N2=£>ercent nitrogen by volume,, dn
basis.
0.44=Moleeular weight of carbon dioxld*
divided, by 100.
0.32=Molecular weight of oxygen divided
by 100.
OJ28=Molecular weight of nitrogen MM
CO divided by 100.
FEDERAL REGISTER. VOL. 36. NO. 247THURSDAY. DECEMBER 23, 1971
IV-11
-------
RULES AND REGULATIONS
24887
E
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in
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tti
1
I-.
UI O
UJ
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iff \
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^ >
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og
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en
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w-o
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-sS^s^SS
; 2 3 S -.g S1 S tcj
S^SSXS^C
j -^ u ' t> o x
ET:S > PQ
INATION OP MOIS
CK CASES
ET
N
lity.
s removed
and deter;
K a
' P O
Principle and applica
1 Principle. Moisture
gas stream, condense
mctrlcally.
This method Is
ination of mois
tesi
wit
s in
pecified by
compliance
ndards. Thi
uid droplets
and the mois
he dctciminal
eight.
ermi
hen
inin
ce St
en li
rcam
d in
ular
^ ~ -a
c z. <»
5 S3 fe?
5^5 ^8
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-3 ; I g I
en O -M o
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uri0
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de
Appl
or t
.2
le
1.
1.
the
vol
Mack gas only w
ccdurcs for determ
Source Performan
docs not apply wh
cnt in the gas r.tr
subsequently used
stack gas molecu
s-g
°2^
^Is
||[
o £ 'f.
-> o
.0 o
e Slr.l
heated
2. Ap
2 1
fficien
o
o
IV-12
-------
24S88
RULES AND REGULATIONS
4 2 Gas volume.
V
V»--V
--
1 in. Hg V T» ) equation 4-2
where :
Vm. Orj gas volume through, meter ai
standard conditions, cu. ft.
Vm =Dry gas volume measured by meter,
cu. ft.
Pm =Barometrlc pressure at the dry gas
meter. Inches Hg.
P«td=Pressure at standard conditions, 29.92
inches Hg.
T.ta=:Absolute temperature at standard
conditions, 530' R.
Tm ^Absolute temperature at meter ('F+
460). °R-
4.3 Moisture content.
-+B.
-+ (0.025)
equation 4-3
where:
B»o=Proportion by volume of water vapor
In the gas stream, dlmensionless.
V»« =Volume of water vapor collected
(standard conditions), cu. ft.
Vm« =Dry gas volume through meter
(standard conditions), cu. ft.
BwM^Approximate volumetric proportion
of water vapor In the gas stream
leaving the impingers, 0 025.
5. References.
Air Pollution Engineering Manual, Daniel -
sou, J. A, (ed.), TJ.S. DHEW, PHS, National
Center for Air Pollution Control, Cincinnati,
Ohio, PHS Publication No. 999-AP-40, 1967.
Devorkin, Howard, et al., Air Pollution
Source Testing Manual, Air Pollution Con-
trol District, Los Angeles, Calif., November
1963.
Methods for Determination of Velocity,
Volume, Dust and Mist Content of Gases,
Western Precipitation Division of Joy Manu-
facturing Co., Los Angeles, Calif., Bulletin
WP-50, 1968.
METHOO 5DETERMINATION OF PABTICTJLATB
EMISSIONS PROM STATIONABT SOURCES
1. Principle and .applicability.
1.1 Principle. Particulate matter Is with-
drawn Isoklnetioally from the source and its
weight Is determined gravimetrically after re-
moval of uncomfbined water.
1.2 Applicability. This method is applica-
ble for the determination of particul»t« emis-
sions from stationary sources only when
specified by the test procedures for determin-
ing compliance with New Source Perform-
ance Standards.
2. Apparatus.
2.1 Sampling train. The design specifica-
tions of the partlculate sampling train used
by EPA (Figure 5-1) are described in APTD-
O531. Commercial models of this train are
available.
2.1.1 NozzleStainless steel (316) with
sharp, tapered leading edge.
2.1.2 ProbePyrex1 glass with a heating
system capable of maintaining a minimum
gas temperature of 250° F. at the exit end
(luring sampling to prevent condensation
from occurring. When length limitations
(greater than about 8 ft.) are encountered at
temperatures less than 600" P., Incoloy 825 J,
or equivalent, may be used. Probes for sam-
pling gas streams at temperatures in excess
of GOO" F. must have been approved by the
A dmi nlstrator.
2.1.3 Pilot tubeType S, or equivalent,
attached to probe to monitor stack gas
velocity.
2.1.4 Filter HolderPyrex 1 glass with
heating system capable of maintaining mini-
mum temperature of 225° F.
2.1.5 Impingere / CondenserFour Impln-
gers connected in series with glass ball joint
fittings. The first, third, and fourth Impin-
gers are of the Greenburg-Smith design,
modified by replacing the tip with a % -inch
ID glass tube extending to one-half Inch
from the bottom of the flask. The second 1m-
plnger Is of the Greenburg-Smlth design
with the standard tip. A condenser may be
used In place of the implngers provided that
the moisture content of the stack gas can
still be determined.
2.1.6 Metering systemVacuum gauge,
leak-free pump, thermometers capable of
measuring temperature to within 5° P., dry
gas meter with 2% accuracy, and related
equipment, or equivalent, as required to
maintain an Isokinetic sampling rate and to
determine sample volume.
2.1.7 BarometerTo measure atmospheric
pressure to ±0.1 Inches Hg.
2.2 Sample recovery.
2.2.1 Probe brushAt least aa long as
probe.
2.2.2 Glass wash bottlesTwo.
2.2.3 Glass sample storage coutainera.
2.2.4 Graduated cylinder250 ml.
2.3 Analysis.
2 3.1 Glass weighing dishes.
2.3.2 Desiccator,-
2.3.3 Analytical balanceTo measure to
±0.1 mg.
2.3.4 Trip balance300 g. capacity fX3
measure to ±0.05 g.
3. Reagents.
3.1 Sampling.
3.1.1 FiltersGlass fiber, MSA 1106 Bfa »,
or equivalent, numbered for Identification
and preweighed.
3.12 Silica gelIndicating type, 6-lfl
mesh, dried at 175° C. (350* F.) lor 2 hours.
3.1.3 Water.
3.1.4 Crushed ice.
3 2 Sample recovery.
3.2.1 AcetoneReagent grade.
3.3 Analysis.
3.3.1 Water.
REVERSE-TYPE
PITOT TUDE
I.MPINGER* TRAIN OPTIONAL MAY BE REPLACED'
BY Aft EQUIVALENT CONDENSER
HEATED AREA FJLTER HOLDER / THERMOMETER CHECK
,VALVE
,VACUUM
LINE
IMPINGERS ICE BATH
BY-PASS.VALVE
"THERMOMETERS'
VACUUM
GAUGE
MAIN VALVE
DRY TEST METER
AIR-TIGHT
PUMP
Figure 5-1. particulate-sampling train.
3.3 2 DesiccantDrierite," indicating.
4. Procedure.
4.1 Sampling
4.1.1 After selecting the sampling site and
the minimum number of sampling points,
determine the stack pressure, temperature,
moisture, and range of velocity head.
4.1.2 Preparation of collection train.
Weigh to the nearest grain approximately 200
g. of silica gel. Label a filter of proper diam-
eter, desiccate" for at least 24 hours and
weigh to the nearest 0.5 mg. in a room where
the relative humidity is less than 50%. Place
100 ml. of water in each of the first two
implngers, leave the third Impinger empty,
and place approximately 200 g. of preweighed
silica gel in the fourth impinger. Set up the
train without the probe as in Figure 5-1.
Leak check the sampling train at the sam-
pling site by plugging up the inlet to the fil-
ter holder and pulling a 15 in. Hg vacuum. A
leakage rate not in excess of 0.02 cj.m. at a
vacuum of 15 In. Hg is acceptable. Attach
the probe and adjust the heater to provide a
gas temperature of about 250° F. at the probe
outlet. Turn on the filter heating system.
Place crushed Ice around the impingers. Add
'Trade name.
1 Trade name.
"Dry using Drieritei at 70" F. + 10" F.
more ice during the run to keep the temper-
ature of the gases leaving the last Impinger
as low as possible and preferably at 70° F..
or less. Temperatures above 70° F. may result
in damage to the dry gas meter from either
moisture condensation or excessive heat.
4.1.3 Particulate train operation. For each
run, record the data required on the example
sheet shown in Figure 5-2. Take readings at
each sampling point, at least every 5 minutes,
and when significant changes in stack con-
ditions necessitate additional adjustments
in flow rate. To begin sampling, position the
nozzle at the first traverse point with the
tip pointing directly into the gas stream.
Immediately start the pump and adjust the
flow to Isokinetic conditions. Sample for at
least 5 minutes at each traverse point; sam-
pling time must be the same for each point.
Maintain isokinetic sampling throughout the
sampling period. Nomographs are available
which aid in the rapid adjustment of the
sampling rate without other computations.
APTD-0578 details the procedure for using
these nomographs. Turn off the pump at the
conclusion of each, run and record the final
readings. Remove the probe and nozzle from
the stack and handle In accordance witl\ the
sample recovery process described In section
4.2.
FEDERAL REGISTER, VOL. 36. NO. 247THURSDAY, DECEMBER 23, 1971
IV-13
-------
RULES AND REGULATIONS
24889
LOCATON_
KM MO.
AMBIENT IfMKUTUK_
MKUETIUC HBSUf£_
ASSUMED t«ISTUia.X_
MOK KATE*. SETTING
SCHEMATIC OF 5TAOC CHOSS SECTION
KAVftse raw
Muwa
TOTAL
tAWND
11ME
«.*«.
AVCAAGE
STATIC
ncssuie
(PSI.I..H»
STAC!
TEMKIATUK
(Tsl.'F
vtiocm
MAO
It'!).
MESSUK
E»FH«£>IT1AL
AC-OS
OfW ICC
METH
(«.
U. »2O
GASSAWU
VOLUME
IVsl.lt3
GAS SAMPLE TEMPERArUtf
AT ORT GAS MEHR
INLET
IT. h.l.V
»VS.
OUTLEI
(T.^l.'f
A.».
A«J.
SHW1EKJI
TU»EHATU*£,
°F
TWPERJlTOIt
or CAS
LUriKC
CMDEKERtm
LAST WlUCtB
f
TmAverage dry gas meter temperature,
R.
P,,,,Barometric pressure «>t the orifice
meter, inches Hg.
AHAverage pressure drop across the
orifice meter, Inches H2O.
13.6Specific gravity of mercury.
PlltlAbsolute pressure at standard con-
ditions, 29.92 Inches Hg.
6.3 Volume of water vapor.
).0474
cu
ml
JtA
oL;
'Vi
i2 Sample recovery. Exercise care In mov-
ing the collection train trom the test site to
the sample recovery area to minimize tho,
loss of collected sample or the gain of
ertraneous paniculate matter. Set aside a
portion of tbe acetone used In the sample
recovery as a blank tor analysis. Measure the
volume of water from the first three 1m-
pingers, then discard. Place the samples in
containers as follows:
Container No. 1. Remove the filter from
its holder, place in this container, and seal.
Container No. 2. Place loose particulate
matter and acetone washings from all
sample-exposed surfaces prior to the filter
In this container and seal. Use a razor blade,
brush, or rubber policeman to lose adhering
particles.
Container No. 3. Transfer the silica gel
from tbe fourth impinger to the original con-
tainer and seal. Use a rubber policeman as
an aid -in removing silica gel from the
Impinger.
4JJ Analysis. Record the data required on
the example sheet shown In Figure 6-3.
Handle each sample container as follows:
Container No. 1. Transfer the filter and
any loose particulate matter from the sample
container to a tared glass weighing dish,
desiccate, and dry to a constant weight. Re-
port results to the nearest 0.5 mg.
Container No. 2. Transfer the acetone
washings to a tared beaker and evaporate to
dryness at ambient temperature and pres-
sure. Desiccate and dry to a constant weight.
Report results to the nearest 0.5 mg.
I. Paniculate rield data.
Container No. 3. Weigh the spent silica gel
and report to the nearest gram.
5. Calibration.
Use methods and equipment whlcli have
been approved by the Administrator to
calibrate tbe orifice meter, pilot tube, dry
gas meter, and probe heater. Recalibrate
after each test series.
6. Calculations.
6.1 Average dry gas meter temperature
and average orifice pressure drop. See data
sheet (Figure 5-2).
6.2 Dry gas volume. Correct the sample
volume measured by the dry gas meter to
standard conditions (70° P., 29.92 inches Hg)
by using Equation 5-1,
V»_ =
equation 5-2
where:
V»lU°= Volume of water vapor In the gas
sample (standard conditions),
cu. ft.
Vi.-=Total volume of liquid collected in
Impingers and silica gel (see Fig-
ure 5-3), ml.
pB3o-= Density of water, 1 gymL
Msao=Molecular weight of water, 18 lb./
Ib.-mole.
R-=Ideal gas constant, 21.83 Inches
Hgcu. ft./lb.-mole-°R,
T,,j=Absolute temperature at standard
conditions, 530° R.
P,,a=Absolute pressure at standard con-
ditions, 29.92 inches Hg.
6.4 Moisture content.
V
* W«f A
where:
B.. :
equation 5-3
Proportion by volume of water vapor in the p.ts
stream, dimensionless.
V'Std^Volume of water in the gas sample (standaid
conditions), cu. ft.
^°Vd *=Volume of gas sample through tbe dry gas mot nr
(standard conditions), cu. ft.
6.5 Total particulate weight. Determine
the total particulate catch-from the sum ol
the weights on the analysis data sheet
(Figure 5-3).
6.6 Concentration.
6.6.1 Concentration in gr./s.cj.
c'.=
).0154-s^
where:
equation 5-1
= Volume of gas sample through, the
dry gas meter (standard condi-
tions) , cu. ft
= Volume of gas sample through the
dry gas meter (meter condi-
tions) , cu. ft.
= Absolute temperature at standard
conditions, 530° R.
equation 5-4
where:
cV= Concentration of particulate matter In stack
gas. gr./s.c-f., dry basis.
Mn=Total amount of particulate matter collected,
mg.
^".idVolume of gas sample through dry gas meter
(standard conditions), cu. Jt.
FEDERAL REGISTER, VOL 36, NO. 247THURSDAY, DECEMBER 23. 1971
IV-14
-------
24890
RULES AND REGULATIONS
PLANT.
DATE
RUN NO.
CONTAINER
NUMBER
1
2
TOTAL
WEIGHT OF PARTICIPATE COLLECTED,
mg
FINAL WEIGHT
>
-------
RULES AND REGULATIONS
24891
II it
2 ..> 22
v O O O
< *j g ej
« A 0.0
Milli
Itlli
a^a^ls
* OB g "=n
!|a|^i
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5; « g Sing 3
* ° 2
"$.** a
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w "S "*
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EC 1 1 1 -ri O rj W
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g-313 fc.2 £ 25 g
-i
briC'£'rt
^>i+:>C>*-i:3,*
6-
,?
c =
1
= -
"
1
7. References.
Atmospheric E)
lanufacturlng F
Hvlslon of Air PC
:e Publication
)hlo, 1965.
W g
riE
*»-a.
lo
^
UTS
SH*
£ W M
£>;3
S£0
sis
&
|*
"1 fl
*H O
*1
s£
Iqulpment and
Jhemlcal Process
rol Association, .
1ETHOD 7 DETER
EMISSIONS FHI
1. Principle ant
1.1 Principle.
i an evacuated
fS *"
e'S
1s
II
2^
s -
I
tu
s s
CVr*
g «
a«
+Cl
B
si "!"|!
E S 53 M
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IS
i^-*-*
.
rsai II
I l^!si^lilis°
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:§
;
'I
.
i
-
?:i
t
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to
i ^ e g.| g-S -a* | as g-|| || |^| s ,
' (H u/ ! CL"^ j-i1*~^'75''M''~^ CL*"^ 1^4 »o 4^ l-t
-------
RULES AND REGULATIONS
nitrous oxide, are measure colorimetrically
using the phenoldisulfonic acid (PDS)
procedure.
1.2 Applicability. This method is applica-
nt for the measurement of nitrogen oxides
from stationary sources only when specified
by the test procedures for determining com-
pliance with New Source Performance
Standards.
2. Apparatus.
2 1 Sampling. See Figure 7-1.
2.1.1 ProbePyrex1 glass, heated, with
filter to remove partlculate matter. Heating
is unnecessary if the probe remains dry dur-
ing the purging period.
2.1 2 Collection flaskTwo-liter, Pyrex,1
round bottom with short neck and 24/40
standard taper opening, protected against
implosion or breakage.
1 Trade name.
2.1.3 Flask valveT-bore stopcock con-
nected to a 24/40 standard taper Joint.
2.1.4 Temperature gaugeDial-type ther-
mometer, or equivalent, capable of measur-
ing 2° F. intervals from 25' to 125° F.
2.1.5 Vacuum line:Tubing capable ol
withstanding a vacuum of 3 inches Hg abso-
lute pressure, with "T" connection and T-bore
stopcock, or equivalent.
2.1.6 Pressure gaugeU-tube manometer,
36 inches, with 0.1-lnch divisions, or
equivalent.
2 1.7 PumpCapable of producing a vac-
uum of 3 incjies Hg absolute pressure.
2.1.8 Squeeze bulbOne way.
2.2 Simple recovery.
2.2.1 Pipette or dropper.
2.2.2 Glass storage containersCushioned
for shipping.
I EVACUATE
£-M PURGE'
FLASK VAUVEi CT) SAMPLE
SQUEEZE BUL>
FILTER
CROUND-CLASS SOCKET
5 NO. 12/5
3-WAV STOPCOCKr
T-BOB£. I. PYREX,
2-mcriBORe, 8-mmOD
FLASK.
-------
RULES AND REGULATIONS
24893
uffi-8)-(»-»n
P.
mere:
V,,Sample volume at standard condi-
tions (dry basis), ml.
T.,dAbsolute temperature at standard
conditions, 530° R.
P,,4«= Pressure at standard conditions,
29.92 inches Hg.
V, = Volume of flask and valve, ml.
V,Volume of absorbing solution, 25 ml.
(V'~25 "*> -
-i
Pf=Final absolute pressure of flask,
inches Hg.
P, = Initial absolute pressure of flask,
inches Hg.
Tt=Final absolute temperature of flask,
"B.
T,=Inltial absolute temperature of flask,
°R.
6.2 Sample concentration. Read //g. NO.,
for each sample from the plot of eg. NOJ
versus absorbance.
V/ I TT
( Ib./s.c.fA / m \
^Jr' V^'
Where:
CConcentration of NOZ as NOa (dry
basis), lb./s.c.f.
m-=Mass of NO,, in gas sample, fig.
V,e««Sample volume at standard condi-
tions (dry basis), ml.
7. References.
Standard Methods of Chemical Analysis.
6th ed. New York, D. Van Nostrand Co., Inc.,
1M2, Vol. 1, p. 329-330.
. Standard Method of Test for Oxides of
Mttrogen in Gaseous Combustion Products
(Phenoldisulfonic Acid Procedure), In: 1968
Book of ASTM Standards, Part 23, Philadel-
phia, Pa. 1968, ASTM Designation D-1608-60,
p. 725-729.
Jacob, M. B., The Chemical Analysis of Air
Pollutants, New York, N.Y., Interscience Pub-
lishers. Inc., 1960, vol. 10, p. 351-356.
MRHOD 8DETERMINATION OF STJWCRIC ACID
MIST AND SULFOB DIOXIDE EMISSIONS FROM
STATIONARY SOURCES
1. Principle and applicability.
1.1 Principle. A gas sample is extracted
from, ft sampling point in the stack and the
cid mist including siilfur trioxide is sepa-
rated from sulfur dioxide. Both fractions are
measured separately by the barlum-thorin
tttration method.
12 Applicability. This method is applica-
ble to determination of evUfuric acid mist
(including sulfur trioxide) and sulfur diox-
U* from stationary sources only when spe-
cified by the test procedures for determining
x STACK
XT^-WALI.
PROBE r
equation 7-2
compliance with the New Source Perform-
ance Standards.
2. Apparatus.
2.1 Sampling. See Figure 8-1. Many of
the design specifications of this sampling
train are described in APTD-0581.
2.1.1 NozzleStainless steel (316) with
sharp, tapered leading edge.
2.1.2 ProbePyrex1 glass with a heating
system to prevent visible condensation dur-
ing sampling.
2.1.3 Pilot tubeType S, or equivalent,
attached to probe to monitor stack gas
velocity.
2.1 A Filter holderPyrexl glass.
2.1.5 IinpingersFour as shown in Figure
8-1. The first and third are of the Greenburg-
Smith design with standard tip. The second
and fourth are of the Oreenburg-Smith de-
sign, modified by replacing the standard tip
with a Vi-iach ID glass tube extending to
one-half inch from the bottom of the im-
pinger flask. Similar collection systems,
which have been approved by the Adminis-
trator, may be used.
2.1.6 Metering systemVacuum gauge,
leak-free pump, thermometers capable of
measuring temperature to within 5° F., dry
gas meter with 2% accuracy, and related
equipment, or equivalent, as required to
maintain au isokinetic sampling rate and
to determine sample volume.
2.1.7 BarometerTo measure atmospheric
pressure to ±0.1 inch Hg.
1 Trade name.
FILTER HOLDER
Wi^
THERMOMETER
CHECK
VALVE
REVERSE-TYPE
PITOT TUBE
VACUUM
LIN5
VACUUM
GAUGE
MAIN VALVE
AIR-TIGHT
PUMP
DRY TEST METER
Figure 8-1. Su If uric acid mist sampling train.
2.2 Sample recovery.
2.2.1 Wash bottlesTwo.
2.2.2 Graduated cylinders250 ml., 500
ml.
2.2.3 Glass sample storage containers.
2.2.4 Graduated cylinder250 ml.
2.3 Analysis.
2.3.1 Pipette25 ml., 100 ml.
2.3.2 Burette50 ml.
2.3.3 Erlenmeyer flask250 ml.
2.3.4 Graduated cylinder100 ml.
2.3.5 Trip balance300 g. capacity, to
measure to ±0.05 g.
2.3.6 Dropping bottleto add Indicator
solution.
3. Reagents.
3.1 Sampling.
3.1.1 FiltersGlass fiber, MSA type 1108
BH, or equivalent, of a suitable size to fit
in the filter holder.
3.1.2 Silica gelIndicating type. 6-16
mesh, dried at 175" C. (350° F.) for 2 hours.
3.1.3 WaterDeionized, distilled.
3.1.4 Isopropanol, 80%Mix 800 ml. of
isopropanol with 200 ml. of deionized, dis-
tilled water.
3,1.5 Hydrogen peroxide, 3%Dilute 100
ml. of 30% hydrogen peroxide to 1 liter with
deionized, distilled water.
3.1.6 Crushed ice.
3.2 Sample recovery.
3.2.1 WaterDeionized, distilled.
3.2.2 Isopropanol, 80%.
3.3 Analysis.
3.3.1 WaterDeionized, distilled.
3.3.2 Isopropanol.
3.3.3 Thorm Indicatorl-(o-arsoucphen-
yIazo)-2-naphthol-3, 6-disulfonic acid, di-
sodium salt (or equivalent). Dissolve 0.20 g.
in 100 ml. distilled water.
3.34 Barium perchlorate (0.01AT)Dis-
solve 1.95 g. of barium perchlorate [Ba
(CO,),, 3 H,,Oi in 200 ml. distilled water and
dilute to 1 liter with isopropanol. Standardize
with suliuric acid.
3.35 Sulfuric acid standard (0.01N)
Purchase or standardize to ± 0.0002 N against
0.01 N NaOH which, has previously been
standardized -against primary standard po-
tassium acid phtlialate.
4. Procedure.
4.1 Sampling.
4.1.1 After seiecting the sampling site and
the minimum, number of sampling points,
determine the stp,ck pressure, temperatxire,
moisture, and range of velocity head.
4.1.2 Preparation of collection train.
Place 100 ml. of 80% Isopropanol in the first
impinger, 100 m!. of 3% hydrogen peroxide in
both the second, and third Impingers, and
about 200 g. of silica gel in the fourth Im-
pinger. Retain a portion of the reagents for
use as blank solutions. Assemble the train
without the probe as shown in Figure 8-1
with the filter between the first and second
impingers. Leak check the sampling train
at the sampling site by plugging the inlet to
the first impinger and pulling a 15-inch Hg
vacuum. A leakage rate not in excess of 0.02
cXm. at a vacuum of 15 Inches Hg is ac-
ceptable Attach the probe and turn on the
probe heating system. Adjust the probe
heater .setting during sampling to prevent
any visible condensation. Place crushed ice
around the impingers. Add more ice during
the run to keep the temperature of tha gases
leaving the last impinger at 70° F. or less.
4.1.3 Train operation. For each run, re-
cord the data required on the example sheet
shown in Figure 8-2. Take readings at each
sampling point at least every 5 minutes and
when significant changes in stack conditions
necessitate additional adjustments in flow
rate. To begin sampling, position the nozzle
at the first traverse point with the tip point-
ing directly into the gas stream. Stnrt the
pump and immediately adjust the flow to
isokinetic conditions. Maintain isokinetic
sampling throughout the sampling period.
Nomographs are available which aid in the
FEDERAL REGISTER, VOL. 36, NO. 247THURSDAY, DECEMBER 23, 1971
I.V-18
-------
24894
RULES AND REGULATIONS
-*>i-*35s^;fiv« 53
>> -E o H o H o >, o
£>+> 71 rf - - w CT?
H
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-
a-eSSS"! «,
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u*
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IV-19
-------
RULES AND REGULATIONS
24895
Bom, Jerome J., Maintenance, Calibration,
and Operation of Isokiuetic Source Sam-
pling Equipment, Environmental Protection
Agency, Air Pollution Control Office Publi-
cation No. APTD-0576.
Shell Development Co. Analytical Depart-
ment, Determination or Sulfur Dioxide and
Sulfur Trioxide in Stack Gases, Emeryville
Method Series, 4516/59a.
METHOD 9 VISUAL DETEJIMINATION OF THE
oPAcrnr OF EMISSIONS FROM STATIONARY
SOURCES
1. Principle and applicability.
1.1 Principle. The relative opacity of an
emission from a stationary source is de-
termined visually by a qualified observer.
1.2 Applicability. This method is appli-
cable for the determination ol the relative
opacity of visible emissions from stationary
sources only when specified by test proce-
dures for determining compliance with the
New Source Performance Standards.
2. Procedure.
2.1 The qualified observer stands at ap-
proximately two stack heights, but not more
than a quarter of a mile from the base of
the stack with the sun to his back. From a
vantage point perpendicular to the plume,
the observer studies the point of greatest
opacity in the plume. The data required in
Figure 9-1 is recorded every 15 to 30 seconds
to the nearest 5% opacity. A minimum of 25
readings is taken.
3. Qualifications.
3.1 To certify as an observer, a candidate
must complete a smokereadlng course con-
ducted by EPA, or equivalent; in order to
certify the candidate must assign opacity
readings in 5% increments to 25 different
black plumes and 25 different white plumes,
with an error not to exceed 15 percent on
any one reading and an average error not to
exceed 7.5 nercent in each category. The
smoke generator used to qualify tee ob-
servers must be equipped with, a calibrated
smoke indicator or light transmission meter
located in the source stack if the smoke
generator is to determine the actual opacity
of the emissions. All qualified observers must
pass this test every 6 months in order to
remain certified.
4. Calculations.
4.1 Determine the average opacity.
5. References.
Air Pollution Control District Rules and
Regulations, Los Angeles County Air Pollu-
tion Control District, Chapter 2, Schedule 6,
Regulation 4, Prohibition, Rule 50,17 p.
Kudluk, Rudolf, Ringelmann Smoke Chart,
TJ.S. Department of Interior, Bureau of Mines,
Information Circular No. 8333, May 1967.
0
1
2
3
4
S
6
7
B
9
10
11
12
13
14
IS
16
17
It
19
20
21
22
23
24
26
26
27
78
29
.0
IS
30
45
VS|C
«)N>
0
1
2
3
4
&
6
7
8
9
0
1
2
3
4
S
G
47
48
49
SO
51
52
S3
54
55
56
57
58
59
0
15
30
45
Plant
S..t« (Hellion
Ob««r«>r
*>' , , *
T.m.
Dillmnca to fclarb , . , , .
W.nd dir.cdon , , , ,,
Wind &*<* .,, .. ,,.
^ Sunn of not- recorded
Total no. t«»dingt
Figure 9-1. Field dala.
[PR Doc.71-18624'Pilecl 12-22-71;8:45 am]
FEDERAL REGISTER, VOL. 36, NO. 247THURSDAY, DECEMBER 23, 1971
IV-20
-------
NOTICES
5767
IA
STANDARDS OF PERFORMANCE FOR
NEW STATIONARY SOURCES
Supplemental Statement in Connection
With Final Promulgation
1. EPA published Standards of Per-
formance for New Stationary Sources in
final form, prefaced by a "concise gen-
eral statement of their basis and pur-
pose" as required by section 4(c) of the
Administrative Procedure Act, 5 U.S.C.
553(c), on December 23, 1971. 36 F.R.
24876. Petitions for review of certain of
these standards were filed on January 21
and 24 by the Essex Chemical Corp. et
al., the Portland Cement Association,
and the Appalachian Power Co. et al.
(U.S. Court of Appeals for the District
of Columbia, Nos. 72-1072, 72-1073, and
72-1079).
On February 18,1972, almost 2 months
after EPA published the New Stationary
Source Standards, the U.S. Court of Ap-
peals for the District of Columbia Cir-
cuit handed down its decision in
"Kennecott Copper Corp. v. Environ-
mental Protection Agency" (C.AJXC. No.
71-1410), which concerned a national
secondary ambient air quality standard
promulgated by EPA pursuant to sec-
tion 109(b) of the Clean Air Amend-
ments of 1970, 42 U.S.C. 1857C-4(b). The
court there held that although the "con-
cise general statement" prefacing the
standard involved satisfied the require-
ments of section 4(c) of the Administra-
tive Procedure Act, it would nonetheless
remand the cause to the Administrator
for a more specific explanation of how
he had arrived at the standard.
In light of the decision in "Kennecott
Copper," and in the interest of a speedy
judicial determination of the validity of
the Standards of Performance for New
Stationary Sources, we have prepared
this statement of the basis of the Ad-
ministrator's decision to promulgate the
standards to supplement that appearing
as the preface to the final standards as
published in December 1971. Although
if the point were raised it might ulti-
mately be determined that this state-
ment was not necessary to satisfy the
doctrine expressed by the "Kennecott
Copper" opinion, EPA considers it fun-
damental to the national policy embodied
in the Clean Air Amendments of 1970
to expedite all steps of promulgation and
enforcement of standards and imple-
mentation plans to bring about clean
air. The speedy eradication of any un-
certainty as to the validity of the stand-
ards for new stationary sources is an
important part of this process. Accord-
ingly, considering the particular se-
quence of events and pressures of time
involved here,, we think it most appro-
priate to include this supplementary
statement in the record now, thereby
ensuring the rapid conclusion of judicial
review of the validity of the standards.
H. 1. The Particulate Test Method.
Particulate emission limits were pro-
posed for steam generators, incinerators,
and cement plants, based on measure-
ments made with the full EPA sampling
train, which includes a dry filter as well
as impingers, which contain water and
act as condensers and scrubbers. In the
impingers the gases are cooled to about
70,° F. before metering.
There were objections to the use of
impingers in the EPA sampling train,
with suggestions that the participate
standards be based either on the "front
half" (probe and filter) of the EPA sam-
pling train or on the American Society
of Mechanical Engineers test procedure.
Both of these methods measure only
those materials that are solids or liquids
at 250° F. and greater temperatures.
It is the opinion of EPA engineers that
Particulate standards based either on the
front half or the full EPA sampling train
will require the same degree of control
if appropriate limits are applied. Analy-
ses by EPA show that the material col-
lected in the impingers of the sampling
train is usually although not in every
case a consistent fraction of the total
Particulate loading. Nevertheless, there
is some question that all of the material
collected in the impingers would truly
form particulates in the atmosphere un-
der normal dispersion conditions. For
instance, gaseous sulfur dioxide may be
oxidized to a particulate formsulfur
trioxide and sulfuric acidin the sam-
pling train. Much of the material found
in the impingers is sulfuric acid and
sulfates. There has been only limited
sampling with the full EPA train such
that the occasional anomalies cannot be
explained fully at this time. In any case,
the front half of the EPA train is con-
sidered a more acceptable means of
measuring filterable particulates than
the ASME method in that a more effi-
cient filter is required and the filter has
far less mass than the principal ASME
filter in relation to the sample collected.
The latter position was reinforced by a
recommendation of the Air Pollution
Control Association.
Accordingly, we determined that, for
the three affected source categories,
steam * generators, incinerators, and
cement plants, particulate standards
should be based on the front half of the
EPA sampling train with mass emission
limits adjusted as follows:
Recommended
Originally particulate
proposed standards
particulate revised
standards, sample
full EPA method
tram (front halt
only)
Steam Generators-
pounds per million
Btu beat input 0.20
Incinerators grains
per standard cubic
foot at 12 percent
CO2 _ 0.10
Cement Kilus
pounds per ton feed,. 0. 30
Cement Coolers
pounds per ton feed.. 0.10
o.io
0. ns
0.30
0.10
The adjusted standards are based on
EPA sampling results and are designed
to provide the same degree of control as
the originally proposed standards. Iii the
case of steam generators, the installa-
tions which were found to be best con-
trolled showed reasonably large concen-
trations (about 50 percent) of materials
in the impingers. The five Incinerator
Ko. 55Pt. I-
FEDERAl REGISTER, VOL. 37, NO. 55TUESDAY, MARCH 2T, 1972
IV-21
-------
5768
NOTICES
tests which showed compliance with the
originally proposed standard all indi-
cated impinger catches of 20 to 30 per-
cent. All five of these tests Indicate
compliance with the original and the
revised standard.
In the case of cement plants, holding
to the same allowable emission .rate
while changing the sampling method
results in a slight relaxation of the
standard. This permits an electrostatic
precipitator as well as a fabric filter to
meet the emission standard.
2. The Sulfur Dioxide Standard for
Steam Generators of 1.2 Pounds Per
Million B.T.U. Heat Input. The Admin-
istrator took into account the following
facts in determining that there has been
adequate demonstration of the achieva-
bility of the standard.
There are at present three SO» re-
moval systems in operation at U.S. power
stations. Moreover, a total of 13 electric
power companies have contracted for the
construction of seventeen additional
units, most of which will become opera-
tional in the next 2 years. Most of these
employ lime or limestone scrubbing, but
magnesium oxide and sodium hydroxide
scrubbing and catalytic oxidation also
will be used. In addition, seven units will
be equipped with water scrubbers for fly
ash collection in the anticipation that
they may be converted to SO* removal in
the future. Eight different firms are de-
signing the installations. One of the In-
stallations, a sodium hydroxide scrubber,
is guaranteed by the designer to achieve
90 percent or better SO, removal. Four
others are guaranteed at 80 percent or
better. Table I summarizes information
about these installations. Generally, the
standard of 1.2 pounds of sulfur dioxide
per million B.t.u. input can be met by
the removal of 70-75 percent of the
sulfur dioxide formed in the burning of
coal of average sulfur content (i.e., 2.8-3
percent).
A 125-megawafct unit now operated by
the Kansas Power and Light Co. at Law-
rence, Kans., was put into operation in
December 1968. Several problems were
experienced originally and appreciable
revisions have been made to Improve the
system. The most successful operation of
the scrubber has occurred during 1971.
In some respects the plant is atypical
In that it is not required to burn coal
continually. Natural gas is available
much of the time, and the station also
has a supply of fuel oil that can be
burned in emergencies when natural gas
is not available. Kansas Power and Light
has used this flexibility to advantage in
the operation of the scrubber. It fre-
quently switches the unit from coal to
natural gas, bypassing the scrubber, so
that they can inspect the internals for
possible malfunction. The generating
unit was seldom operated longer than 4
weeks on coal firing without making such
inspections. In most instances, little or
no maintenance was required during- the
outage, and the company then merely
inspected the scrubber.
TABLE ISULFOB DIOXIDE REMOVAL SYSTEMS AT U.S. STZAM-ELECTRIC PLANTS
Power station
Unit
size
Designer SO] system
Newer
retro- Scheduled startup
fit
Anticipated
efficiency of
SOi
Limestone Scrubbing:
1. Union Electric Co., Merameo
No. 2.
2. Kansas Power & Light,
Lawrence Station No. 4.
3. Kansas Power & Light,
Lawrence Station No. 5.
4. Kansas City Power & Light,
Hawthorne Station No. 3.
5. Kansas City Power A Light,
Hawthorne, Station No. 4.
6. Kansas City Power & Light,
Lacygne Station.
7. Detroit Edison Co., St. Clair
Station No. 3.
8. Detroit Edison Co., River
Rouge Station No. 1.
9. Commonwealth Edison Co.,
Will County Station No. 1.
10. Northern States Power Co.,
Sherbume County Station,
Minn., No. 1.
11. Arizona Public Service,
Cholla Station Co.
12. Tennessee Valley Authority,
Widow's Creek Station
No. 8.
13. Duquesne Light Co., Philips
Station.
14. Louisville Gas & Electric
Co., Paddy's Run Station.
15. City of Key West, Stock
Island.'
16. Union Electric Co., Meramec
No. 1.
Sodium Hydroxide Scrubbing In-
stallations:
1. Nevada Power Co., Keed
Gardner Station.
MW
140 Combustion Engineer. R
125 Combustion Engineer.. R
430 Combustion Engineer. N
100 Combustion Engineer. R
100 Combustion Engineer. R
800 Babcock&Wilcoi N
180 Peabody R
263 Peabody R
175 Babcock & Wiloox R
700 Combustion Engineer. N
115 Research CottreU R
550 Undecided R
100 Chemico R
70 Combustion Engl- R
neer.
37 Zurn. N
125 Combustion Engineer. R
250 Combustion Equip-
ment Associates.
September 1968. Operated at 73%
efficiency during
EPA test.
Do.
December 1968..
December 1971. -
Late 1972.
Late J972.
Late 1972
Late 1972...
Late 1972_.
February 1972
1976
.. Will start at 66%
and be up-
graded to 83%
.- Guaranteed 70%.
Do.
.. 80% as target.
.. 90% as target.
_ Do.
.. Guaranteed 80%.
December 1973
1974-75
March 1973
Mid-late 1972
Do.
Do.
Magnesium Oiide Scrubbing Instal-
lations:
1. Boston Edison Co., Mystic 150 Chemico
Station No. 6.a
2. Potomac Electric Power, 196 do
Dickerson No. 3.
Catalytic Oxidation:
1. Illinois Power, Wood River -. 109 Monsanto R
Early 1972 Guaranteed 85%
removal.
Spring 1973 80% as target.
1973 Guaranteed 90%
SOj while bora-
ing 1% 3 coal.
February 1972 90% target.
Early 1974 90%.
June 1972 Guaranteed 85%
SO. removal.
' Oil-fired pUnts (remainder are coal-flred).
1 Partial EPA funding.
All water from the pond is recycled
back to the scrubber. Slowdown from
cooling towers constitutes makeup water.
The sludge oxidizej to sulfate in the
pond. Eventually, sulfate may be re-
moved from the system and taken with
the ash to landfills.
The limestone system for the new 430-
megawatt steam-electric unit at the
Lawrence station is essentially the same
as the smaller unit. It has been operated
only on a limited basis to date. The com-
pany plans to operate at 65 percent SO2
removal, then upgrade to 80 percent or
more based on experience with the 125-
megawatt unit. With the new system
sulfate crystallization will be accom-
plished in tanks. The company plans to
run clarified liauor from the crystallizers
directly back to the scrubbers. A solids
content of 6-10 percent will be main-
tained in the recycle liquor to prevent
scaling in exposed surfaces.
Combustion engineering pilot studies.
Pilot studies conducted by the Combus-
tion Engineering Co. on a 1 mw. equiv-
alent stream showed 95 percent SO2 re-
moval with continuous crystallization
and 100 percent water recycle from crys-
tallizers. The studies form the basis upon
which CE is guaranteeing that its new
installations will remove at least 70 per-
cent of SO,.
Battersea scrubber. The principle of
alkaline scrubbing has been demon-
strated at the Battersea Power Station
in England, where a scrubber has been
in use since 1932. A multiple stage proc-
ess is employed. Alkaline river water is
used in the first stage and lime-neutral-
ized liquor in subsequent stages. The
steam generator is of 3,500 million B.t.u.
rating. Reports indicate that the effi-
ciency of this system exceeds 90 percent
when the boiler is fired with 0.8 to 1
percent sulfur coal. Similar systems are
in operation on two 150-mw. oil-fired
boilers at the Bankside Power Station in
England.
Swansea scrubber. Lime scrubbing
processes were installed on coal-fired
units at the Swansea Power Station and
the Fulham Power Station in England
prior to World War H. The system at the
Fulham Station reportedly operated suc-
cessfully until shut down for security rea-
sons early during World War H. It was
not reactivated after the war. The
Swansea installation was operated for
about 2 years on a coal-fired power boiler
FEDERAL REGISTER, VOU 37, NO. 55-TUESDAY, MARCH 21, 1977
IV-2 2
-------
NOTICES
5769
and Is not now in. service. Unlike the
Battersea and Bankside operations, these
units utilized a continuous liquid recycle.
The systems were reported to operate at
SO, efficiencies of 90 percent or greater.
Bahco lime scrubbing. The two-stage
system has been demonstrated at about
98 percent SO> removal over a 6-month
period on a 7-mw. oil-fired steam genera-
tor in Sweden. The process is"now being
offered under license in the United
States by Research Cottrell. None of the
Bahco systems have yet been installed on
coal-fired boilers. Nevertheless, the two-
stage scheme appears to offer definite ad-
vantages over single-stage processes in
achieving high removal efficiencies.
Wellman power gas sulfite scrubbing.
The sulfite-bisulflte system has been in-
stalled on two oil-fired boilers in Japan.
The combined capacity is about 650 mil-
lion B.t.u. per hour. Since it was put into
operation in June 1971, removal ef-
ficiencies of 95 percent have been re-
ported with exit levels of about 0.2 pounds
SO, per million B.t.u. The system has not
been operated on a coal-fired boiler.
However, since precipitators have been
shown to remove particulates down to the
same level as oil-fired units, application
of the sulfite system to coal-fired boilers
should be feasible,
A principal difficulty in operating lime
based scrubbing systems has been the
tendency to form scale on scrubber sur-
faces. Union Electric, TVA, and to a les-
ser extent Kansas Power and Light have
reported scaling problems. The experi-
ence of Kansas Power and Light and
European and Japanese installations
show that scaling can be held to a toler-
able level. Present designs probably will
be revised to optimize cost versus scaling.
The use of two or more stages would ap-
pear desirable for high sulfur coals.
In all probability, there will be some
scale formation in all closed circuit lime
scrubbing systems for SO2 abatement. At
the Bahco installation as at the Kansas
Power and Light installation in the
United States, this is minimized by keep-
ing the solution pH in the acid region.
In addition to this, a Mitsubishi Heavy
Industries pilot plant in Japan has em-
ployed seed crystals and a delay tank and
was reportedly able to operate for 500
hours without any sign of scaling (i.e.,
the scaling took place on the seed
crystals).
In addition to operating at an acid pH,
the Bahco system employs a wide open
scrubber that can tolerate appreciable
scale deposits. It was reported that the
installation of additional spray heads to
more thoroughly wash the wetted sur-
faces at the Bischaff installation in
West Germany helped to prevent scale
formations.
All three installations cited above have
reported successful periods of operation
while employing the above-mentioned
techniques. The most successful of these
is the Bahco unit which has had no
serious operational difficulties since
November 1969. These examples show
that lime systems can be operated with-
out unscheduled shutdown due to scale
problems.
3. Cost of compliance with steam gen-
erator standards. The economic impact
of the new source performance standards
and requisite pollution control expendi-
tures have been developed for a typical
new coal-fired unit of 600-megawatt
(MW) capacity. The investment cost for
such a plant would be $120 million plus
$18 million for sulfur dioxide and partic-
ulate control and $1 million for nitrogen
oxide control. The $19 million total can
be compared to $3.6 million which would
have been expended for particulate con-
trol if sulfur dioxide and nitrogen oxide
abatement were not required.
On an annualized basis the pollution
control costs would be 0.13 cents per kw.-
hr. for sulfur dioxide and particulate
control plus 0.01 cents per kw.-hr. for
nitrogen oxide control. Particulate con-
trol alone would cost 0.01 cents per kw.-
hr. An average revenue of 1.56 cents per
kw.-hr. is assumed. Based on these fig-
ures, the cost of pollution control will
be about 9 percent of the delivered cost
of electricity if all plants operated by the
utility in question had to incur a com-
parable cost. Using a figure of $130 per
year as the average residential electric
bill, the increased cost of electricity to a
residential customer would be about $1
per month if the total cost of control is
passed on to the customer.
An indication of the impact of in-
creased electricity cost on industrial con-
sumers may be obtained by examining
the relationship of electricity cost to pro-
duction costs. An upper limit may be ap-
proximated by considering the alumi-
num industry, a large consumer of elec-
trical energy. If the aluminum industry-
were to incur an increase of nine percent
in electricity cost, production costs would
increase by about 1.4 percent. Although
aluminum smelters usually consume hy-
droelectric power and would not realize
pollution control costs increases, none-
theless, the figures show that even for
a large consumer the impact of increased
electricity cost is fairly small. In general,
the estimated electricity cost increase
will have only a minor impact on pro-
duction costs.
Each year the power industry puts into
operation about 49 new steam-electric
units. On the average, 29 are fired with
coal, seven with oil, and 13 with natural
gas. Most of the oil-fired units and a
few of the coal-fired units may burn low
sulfur fuel. The number requiring flue
gas desulfurization is estimated to be be-
tween 20 and 3Q per year. Most of these,
15 to 20, will be located east of the Mis-
sissippi River.
The foregoing cost projections are
based on estimated costs of $30 per in-
stalled kilowatt for sulfur dioxide scrub-
bing systems which will also be capable
of controlling coal particulate to the level
of the standard. Some power distributors
have questioned the figure and suggest
that the actual cost may be close to $70
per kw. Nevertheless, a review of appli-
cable cost estimates for calcium base SO2
scrubbing system shows support for the
EPA estimate.
The four estimates listed in table n
for new plants range from $18.7 to $25.67
per kw. Three of the plants are large
680 to 1,000 mw. All five estimates for
retrofitting existing plants show greater
cost, ranging from $28.6 to $61.8 per kw.
The retrofit estimates tend to cover
smaller steam generators, only one of the
five being greater than 180, mw. In addi-
tion, the retrofit costs tend to reflect
unusual circumstances which would not
be expected at new plants. All are closed
circuit limestone or calcium hydroxide
systems except for the small unit at Key
West, Fla. In the closed circuit system,
all waters are recycled to avoid problems
of liquid and solid waste disposal.
TABIE n
COST ESTIMATES FOB EQUIPPING COAL FRED BTEAJI-
E1ECTKIC PLANTS WITH CALCTOH BASE SCRUBBING
SYSTEMS (1971 ESTIMATES)
Source of estimate
Size Capital cost
Zurn Industries (Key West 37 MW
installation). (New).
Northern States Power Co.. 2-680 MW
(New).
Baboock & Wilcox (Hypo- 800 MW
thetleal plant in mid- (New).
west).
Tennessee Valley 1000 MW
Authority. (New).
Do 660 MW
(Retro-
fit).
Louisville Gas & Electric 70 MW
Co. (Retro-
fit).
Duquesne Light Co 100 MW
fit)?
Common-wealth Edison 176 MW
Co. (Retro-
fit).
Detroit Edison Co *-180 MW
(Retro-
fit).
$20.4/kw.
$18.7/kw.
$26.67/kw.
$19.20/kw.
$64.6 to
$61.8/kw.
$28.6/kw.
$3S/kw.
$49/kw.
$49.6/kw.
Projected capital costs for nitrogen
control will range from nil to $3.50 per
kw. The greatest cost will be incurred
from those units which will use combina-
tions of flue gas recirculation and off-
stoichiometric combustion to achieve the
standard. Many of these will be gas-fired
boilers which will not have to expend any
capital for sulfur dioxide or particulate
control. The least cost will be for corner-
fired coal burning boilers which should
be able, to meet the standards without
any modification. Corner-fired units are
sold by only one of the four major U.S.
power boiler manufacturers. The other
three firms have experience with nitrogen
oxide reduction schemes for gas and oil
burning but it is uncertain what methods
they will employ with coal burning. Con-
sequently, precise costs are uncertain,
but it is expected that the nitrogen oxide
standard will stimulate interest in com-
bustion techniques which can achieve the
required emission levels at little or 110
increase in cost.
4. The nitrogen oxide standard for
coal-fired steam generators. The stand-
ards set an emission limit of 0.7 pound
of nitrogen oxide per million B.t.u. coal-
fired steam generators. This is roughly
equivalent to a stack gas concentration
of 550 parts per million for a bituminous-
fired operation. Several electric utilities
and three of the four major boiler manu-
facturers commented that the technology
was not fully demonstrated to achieve
the standard.
FEDERAL REGISTER, VOl. 37, NO. 55TUESDAY, MARCH 21, 1972
IV-2 3
-------
5770
NOTICES
The coal standard is based principally
on nitrogen oxide levels achieved with
corner-fired boilers which are manufac-
tured by only one companyCombus-
tion Engineering. This firm has con-
firmed in writing that it will guarantee
to meet the nitrogen oxide standard. In-
vestigations by an EPA contractor
showed that other types of boilers could
meet the standard under modified burn-
ing conditions. In fact, two of the three
remaining companies have informed
EPA they will guarantee that their new
installations will meet the EPA standard
of 0.7 pound/million B.t.u. on new
installations.
5. Particulate standards for kilns in
Portland cement plants. Particulate emis-
sion limits of 0.3 pound per ton of feed
to the kiln were proposed for cement
kilns. This is roughly equivalent to a
stack gas concentration of 0.03 grains per
standard cubic foot.
The Portland Cement Association,
American Mining Congress, a local con-
trol agency and the major cement pro-
ducers commented that the kiln standard
was either too strict or it is not based on
adequately demonstrated technology, i.e.
fabric filters can not be used for all types
of cement plants. On the other hand, a
comment was received from an equip-
ment manufacturer stating that equip-
ment other than fabric filters also can
be used to meet the standard and citing
supportive data for electrostatic preeip-
itators. In addition, the AMC, a local
agency and cement producers commented
that the particulate standards for
cement kilns are stricter than those
promulgated for power plants and
municipal incinerators. Further they ob-
jected to the test method to be used to
determine compliance.
The proposed standard was based prin-
cipally on particulate levels achieved at
a kiln controlled by a fabric filter. Sev-
eral other kilns controlled by fabric
filters had no visible emissions but could
net be tested due to the physical layout
of the equipment. After proposal, but
prior to promulgation a second kiln con-
trolled by a fabric filter was tested and
found to have particulate emissions in
excess of the proposed standard. How-
ever, based on the revised particulate
test method, the second installation
showed particulate emissions to be less
than 0.3 pound per ton of kiln feed.
The promulgated standard is roughly
equivalent to a stack gas concentration of
0.03 grains per standard cubic foot. The
power plant standard is equivalent to
.0.06 grains per standard cubic foot at
normal excess air rates. The incinerators
standard is 0.08 grains per standard ctibic
foot corrected to 12 percent carbon di-
oxide. Uncorrected, at normal conditions
of 7.5 percent carbon dioxide it is equiva-
lent to 0.05 grains per standard cubic
foot. The difference between the particu-
late standard for cement plants and
those for steam generators and incinera-
tors is attributable to the superior tech-
nology available therefor (that is, fabric
filter technology has not been applied to
coal-fired steam generators or incinera-
tors).
In sum, considering the revision of the
particulate test method, there are suffi-
cient data to indicate that cement plants
equipped with fabric filters and precipi-
tators can meet the standard.
6. Cost of achieving particulate stand-
ard for kilns at Portland cement plants.
A limit of 0.3 pounds per ton of feed to
the kiln was proposed. The limit applies
to all new wet or dry process cement
kilns.
Three cement producers commented
that a well-controlled plant would cost
much more than indicated by EPA. A
meeting between American Mining Con-
gress and EPA revealed that that asso-
ciation felt the cost of an uncontrolled
cement plant as reported by EPA was
low by a factor of 1.5 to 2. However, the
association agreed that EPA had accu-
rately estimated the cost of the pollu-
tion control equipment itself. Accord-
ingly, no change in the standard was
warranted on account of cost. Indeed, if
the industry is correct in asserting that
the cost of an uncontrolled plant is
higher than that estimated by EPA, that
means that the cost of pollution control
expressed as a percentage of total cost
is less than the 12 percent figure cited
in the background document, APTD-
0711, which was distributed by EPA at the
time the standards were proposed.
7. Sulfur dioxide and acid mist stand-
ards for sulfuric acid plants. Sulfur di-
oxide emission limits of 4 pounds per
ton of acid produced and acid mist emis-
sion limits of 0.15 pounds per ton of
acid produced were proposed for sulfuric
acid plants.
Several sulfuric acid manufacturers
and the Manufacturing Chemists Asso-
ciation commented that the proposed
SO3 standard is unattainable in day-to-
day operation at one of the plants tested
or that it is unduly restrictive. They as-
serted that to mert th, standard, the
plant would have to be "designed to 2
pounds per ton" to allow for the inevita-
ble gradual loss of conversion efficiency
during a period of operation, and that
units capable of such performance have
not been demonstrated in this country.
Essentially, the same parties commented
that there is published data showing that
due to the vapor pressure of sulfuric acid,
the acid mist standard is not attainable.
The proposed standard was based prin-
cipally on sulfur dioxide levels achieved
with dual absorption acid plants and one
single absorption plant controlling emis-
sions with a sodium sulfite SO2 recovery
system. There are only three dual ab-
sorption plants in this country. Company
emission data at one of the plants tested
indicates the plant was meeting the pro-
posed standard for a year of operation
when the production rate was less than
600 tons per day. The plant is rated at
700 tons per day. At the second U.S.
plant, emissions were about 2 pounds per
ton about two months after startup. Dis-
cussion with foreign dual absorption
plant designers and operators indicates
normal operation at 99.8 percent conver-
sion or higher for 99 percent of the
time over a period of years. This conver-
sion efficiency is equivalent to approxi-
mately 2.5 pounds per ton of acid
produced.
Complaints from the industry that it
cannot meet the acid mist standard ap-
pear to be based on experience with other
test methods than EPA's. Such other
methods measure more sulfur frrkmde
and acid vapor, in addition to acid mist,
than does the EPA method. Tests of sev-
eral plants with the EPA test method
have shown acid mist emissions well be-
low the emission limits as set in the
standards.
8. Cost of achieving sulfur dioxide
standard at sulfuric acid plants. A limit
of 4 pounds of sulfur dioxide per ton of
acid produced is set by the regulation.
The limit applies to all types of new con-
tact acid plants except those operated
for control purposes, as at smelters.
The sulfuric acid industry has com-
mented that (1) the cost of achieving the
proposed sulfur dioxide standard is about
three times the EPA estimate, and (2>
promulgation of a standard 60 percent
less restrictive than proposed by EPA
would reduce the control cost 47 percent
In developing the parallel cost esti-
mates, both the industry and EPA as-
sume the dual absorption process will
be used to control sulfur burning plants
and many spent acid plants. The more
costly Wellman-Power Gas sulfite scrub-
bing system will be used with plants
which process the most contaminated
spent acid feedstocks where capital in-
vestment historically is 80 percent
greater than sulfur burning plants. The
Wellman-Power Gas process would also
be used for retrofitting existing plants
where appropriate. Both the dual absorp-
tion and Wellman-Power Gas processes
have been demonstrated on commercial
installations. Seventy-six dual absorp-
tion plants have been constructed or
designed since the first in 1964. Only
three, however, are located in this coun-
try. One suifite scrubbing process is now
in operation in the United States and
four more will be put into service in 1972.
All are retrofit installations. Two other
such scrubbers are being operated in
Japan. These seven installations consist
of three acid plants, two" claus sulfur
recovery plants, an oil-fired boiler, and
a kraf t pulp mill boiler.
Control costs. EPA engineers have re-
viewed the industry analysis and find no
reason to change their original cost esti-
mate. As summarized in Table in, EPA
estimates that the cost of achieving the
standard is $1.07 to $1.32 per ton of acid
for dual absorption systems and $3.50
per ton for sulnte scrubbing systems. The
industry estimate for a sulfur burning
dual absorption plant is $2.31 greater
than EPA's. We believe the industry's
estimate to be excessive for the following
reasons.
FEDERAL REGISTER, VOL. 37, NO. 55TUESDAY, MARCH 21. 1972
IV-24
-------
MT1MAIED COSTS OI COKTBOIJJNO SOT.FUB DIOXIDE
rBOM CONTACT SULTUBIC ACID PLANTS
Dual absorp- Sodlinn sulfite
lion process scrubbing
In- EPA In- EPA
dustry dustry
Sulfur burning plants:
Direct Investment
(Thousands of i) 2,000
Total Added Cost
($/Ton)o) 3.38
Spent acid-plants:
Direct Investment
(Thousands of $)___ 3,100
Total Added Cost
(VTon)o) 4.4S
8«0 Not antici-
pated for new
1.07 sulfur burning
plants.
900 2,200 2,300
1.32 4.11
3.50
o) Total added cost includes depreciation, taxes, 16%
return on investment after taxes and other allocated
costs.
Seventy-two percent of the difference
between the Du Pont and EPA estimates
is due to direct investment, plant over-
head, and operating costs for auxiliary
process and storage equipment which
Du Pont predicts will be necessary to
satisfy the standards. EPA floes not be-
lieve that such auxiliary equipment will
be necessary in practice to 'meet the
standard.
Twenty percent of the difference is due
to differences in estimates of the cost
and consumption of utilities. Elimination
of auxiliary equipment referred to above
reduces the consumption rate of both
electricity and steam. Eight percent re-
sults from the industry's apportionment
of "other allocated costs" (Corporate
Administration, i.e., sales, research, and
development, main office, etc.) in pro-
portion to their estimate of the additional
investment required for control. Al-
though an accepted procedure for inter-
nal cost accounting, this does not repre-
sent a true out-of-pocket cost.
In sum, the EPA analysis shows that
meeting the proposed standard with a
dual Absorption plant requires a substan-
tial investment over an uncontrolled
plant but only 30 percent as great as
indicated by the industry. Moreover,
relaxation of the proposed standard by
60 percent (to the level recommended by
the industry) would decrease the cost of
control in dual absorption plants only 10
to 15 percent. Por sulfur burning plants
the cost differential would be $0.10 per
ton of acid. For spent acid plants, it
would be $0.17.
Economic impact of proposed stand-
ard. Most sulfuric acid production is cap-
tive to large vertically integrated
chemical, petroleum, or fertilizer manu-
facturers. An increasing volume of pro-
duction also results from the recovery
of sulfur dioxide from stack gases or
the regeneration of spent acid instead
of its discharge into .streams.
Depending on the abatement process
selected and the plant size, the direct
investment for control can range from
14 to 38 percent of the investment in an
uncontrolled acid plant.
The added cost of air pollution con-
trol, coupled with the inherent market
disadvantage of the small manufacturer,
may make future construction of plants
NOTICES
of less than 500 tons per day economi-
cally Unattractive except as a sulfur re-
covery system for another manufactur-
ing process.
It is estimated that the average market
price will increase by $1.07 per ton
reflecting the lower end of the cost range.
This represents a small increase in the
$31 per ton market price and will have
little effect on the demand for acid.
The increasing production of recovered
and regenerated acid, as a result of
abatement efforts, will inhibit the growth
of conventional acid production and
threaten eventually to displace much of
that production.
WILLIAM D. RTJCKELSHATJS,
Administ rotor.
MARCH 16, 1972.
[PR Doc.72-4338 Piled 3-20-72;8:61 am]
2 Title 40PROTECTION
OF ENVIRONMENT
Chapter IEnvironmental Protection
Agency
SUBCHAPTER CAIR PROGRAMS
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY
SOURCES
Standard for Sulfur Dioxide;
Correction
The new source performance standard
published December 23, 1S11 (36 FJR.
24876), which is applicable to sulfur di-
oxide emissions from fossil-fuel fired
steam generators. Incorrectly omits pro-
vision for compliance by burning natural
gas in combination with oil or coal. Ac-
cordingly, in § 60.43 of Title 40 of the
Code of Federal Regulations, paragraph
(c) is revised and a new paragraph (d)
is added, as follows:
§ 60.43 Standard for sulfur dioxide.
*****
(c) Where different fossil fuels are
burned simultaneously in any combina-
tion, the applicable standard shall be-
determined by proration using the fol-
lowing formula:
y(0.80) + z (1.2)
FT^
where:
y Is the percent ol total heat Input de-
rived from liquid fossil fuel and,
z Is the percent of total heat Input derived
from solid fossil fuel.
(d) Compliance shall be based on the
total heat Input from an fossfl fuels
burned, including gaseous fuels.
This amendment shall be effective
upon publication in the FEDERAL REGISTER
(7-25-72).
Dated: July 19,1972.
JOHN QCARLES, Jr.,
Acting Administrator.
[FR Doc.73-11381 Piled 7-25-72;8:49 am]
FEDERAL REGISTER, VOL 37, NO. 144-
-WEDNESOAY, JULY 26, 1971
FEDERAL REGISTER, VOL. 37, NO. 55TUESDAY, MARCH 2J, 1972
IV-25
-------
13562
RULES AND REGULATIONS
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RULES AND REGULATIONS
28565
merits of 1970, 40 T7.S.C. 1857^-6, on De-
cember 23, 1971, for fossil fuel-fired
steam generators, incinerators, Portland
cement plants, and nitric and sulfuric
acid plants (36 FJR. 24876), and proposed
Standards of Performance on June 11,
1973, for asphalt concrete plants, petro-
leum refineries, storage vessels for petro-
leum liquids, secondary lead smelters,
secondary brass and bronze ingot pro-
duction plants, iron and steel plants, and
sewage treatment plants (38 FR 15406).
New or modified sources in these cate-
gories are required to meet standards
for emissions of air pollutants which re-
flect the degree of emissions limitation
achievable through the application of
the best system of emission reduction
which (taking into account the cost of
achieving such reduction) the Admin-
istrator determines has been adequately
demonstrated.
Sources which ordinarily comply with
the standards may during periods of
startup, shutdown, or malfunction un-
avoidably release pollutants in excess of
the standards. These regulations make
it clear that compliance with emission
standards, other than opacity stand-
ards, is determined through performance
tests conducted under representative
conditions. It is anticipated that the ini-
tial performance test and subsequent
performance tests will ensure that equip-
ment is installed which will permit the
standards to be attained and that such
equipment is not allowed to deteriorate
fo the point where the standards are
no longer maintained. In addition, these
regulations require that the plant oper-
ator use maintenance arid operating pro-
cedures designed to minimize emissions.
This requirement will ensure that plant
operators properly maintain and operate
the affected facility and control equip-
ment between performance tests and
during periods of startup, shutdown, and
unavoidable malfunction.
The Environmental Protection Agency
on August 25, 1972, proposed procedures
pursuant to which new sources could be
deemed not to be in violation of the new
source performance standards if emis-
sions during startup, shutdown, and mal-
function unavoidably exceed the stand-
ards (37 PR 17214). Comments received
were strongly critical of the reporting
requirements and the lack of criteria
for determining when a malfunction
occurs.
In response to these comments, the
Environmental Protection Agency re-
scinded the August 25,1972, proposal and
published a new proposal on May 2,
1973 (38 FR 17214). The purpose and
reasoning in support of the May 2, 1973,
proposal are set forth in the preamble
to the proposal. As these regulations
being promulgated are in substance the
same as those of the May 2, 1973. pro-
posal, this preamble will discuss only
the comments received in response to
the proposal and changes made to the
proposal. *
A total of 28 responses were received
concerning the proposal (38 FR 10820).
Twenty-one responses were received
from the industrial sector, three from
State and local air pollution control
agencies, and four from EPA represent-
atives.
Some air pollution control agencies
expressed a preference for more detailed
reporting and for requiring reporting
Immediately following malfunctions and
preceding startups and shutdowns in or-
der to facilitate handling citizens' com-
plaints and emergency situations. Since
States already have authority to require
such reporting and since promulgation
of these reporting requirements does not
preclude any State from requiring more
detailed or more frequent reporting, no
changes were deemed necessary.
Some comments indicated that
changes were needed to more specif-*
ically define those periods of emissions
that must be reported on a quarterly
basis. The regulations have been revised
to respond to this comment. Those pe-
riods which must be reported are defined
in applicable subparts. Continuous mon-
itoring measurements will be used for
determining those emissions which must
be reported. Periods of excess emissions
will be (averaged over specified time pe-
riods in accordance with appropriate
subparts. Automatic recorders are cur-
rently available that produce records on
magnetic tapes that can be processed by
a central computing system for the pur-
pose, of arriving at the necessary aver-
ages. By this method and by deletion of
requirements for making emission esti-
mates, only minimal time will be re-
quired by plant operators in preparing
quarterly reports. The time period for
making quarterly reports has been ex-
tended to 30 days beyond the end of the
quarter to allow sufficient time for pre-
paring necessary reports.
The May 2, 1973, proposal required
that affected facilities be operated and
maintained "in a manner consistent with'
operations during the most recent per-
formance test indicating compliance."
Comments were received questioning
whether it would be possible or wise to
require that all of the operating con-
ditions that happened to exist during
the most recent performance test be
continually maintained. In response to
these comments, EPA revised this re-
quirement to provide that affected facili-
ties shall be operated and maintained
"in a manner consistent with good air
pollution control practice for minimizing
emissions" (§ 60.11(d)).
Comments were received indicating
concern that the proposed regulations
would grant license to sources to con-
tinue operating after malfunctions are
detected. The provision of § 60.11 (d)
requires that good operating and main-
tenance practices be followed and thereby
precludes continued operation in a mal-
functioning condition.
Tliis regulation is promulgated pur-
suant to sections 111 and 114 of the Clean
Air Act as amended (42 U.S.C. 1857c-b,
1857c-9).
This amendment is effective Novem-
ber 14, 1973.
Dated October 10, 1973.
JOHN QUARLES,
Acting Administrator.
Part 60 of Title 40, Code of Federal
Regulations is amended as follows:
1. Section 60.2 is amended by adding
paragraphs (p), (q), and (r) as follows:
§ 60.2 Definitions.
(p) "Shutdown" means the cessation
of operation of an affected facility for
any purpose.
(q) "Malfunction" means any sudden
and unavoidable failure of air pollution
control equipment or process equipment
or of a process to operate in a. normal
or usual manner. Failures that are caused
entirely or in part by poor maintenance,
careless operation, or any other prevent-
able upset condition or preventable
equipment breakdown shall not be con-
sidered malfunctions.
(r) "Hourly period" means any 60
minute period commencing on the hour.
2. Section G0.7 is amended by adding
paragraph (c) as follows:
§ 60.7 Notification and recordkeepiiig.
ic) A written report of excess emis-
sions as defined in applicable subparts
shall be submitted to the Administrator
by each owner or operator for each cal-
endar quarter. The report shall include
the magnitude of excess emissions as
measured by the required monitoring
equipment reduced to the units of the
applicable standard, the date, and time
of commencement and completion of
each period of excess emissions. Periods
of excess emissions due to startup, shut-
down, and malfunction shall be spe-
cifically Identified. The nature and cause
of any malfunction (if known). the cor-
rective action taken, or preventive meas-
ures adopted shall be reported. Each
quarterly report is due by the 30th day
following the end of the calendar quar-
ter. Reports are not required for any
quarter unless there have been periods of
excess emissions.
3. Section 60.8 is amended by revising
paragraph (c) to read as follows:
§ 60.8 Performance tests.
* * * « «
(c) Performance tests shall be con-
ducted under such conditions as the Ad-
ministrator shall specify to the plant op-
erator based on representative
performance of the affected facility. The
owner or operator shall make available
to the Administrator such records as may
be necessary to determine the conditions
of the performance tests. Operations dur-
ing periods of startup, shutdown, and
malfunction shall not constitute repre-
sentative conditions of performance tests
unless otherwise specified in the appli-
cable standard.
4. A new § 60.11 is added as follows:
§ 60.11 Compliance with standards and
m»intenance requirements.
(a) Compliance with standards in this
part, other than opacity standards, shall
be determined only by performance tests
established by § 60.8.
FEDERAL REGISTER, VOL. 38, NO. 198MONDAY, OCTOBER IS, 1973
*Mav 2, 1973 Preamble immediately follows these revisions.
IV-2 7
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28566
RULES AND REGULATIONS
(b) Compliance with opacity stand-
ards In this part shall be determined by
use of Test Method 9 of the appendix.
(c) The opacity standards set forth in
this part shall apply at all times except
during periods of startup, shutdown, mal-
function, and as otherwise provided in
the applicable standard.
(d) At all times, including periods of
startup, shutdown, and malfunction,
owners and operators shall, to the extent
practicable, maintain and operate any
affected facility including associated air
pollution control equipment in a manner
consistent with good air pollution control
practice for minimizing emissions. De-
termination of whether acceptable oper-
ating and maintenance procedures are
being used will be based on information
available to the Administrator which may
Include, but is~not limited to, monitoring
results, opacity observations, review of
operating and maintenance procedures,
and inspection of the source.
5. A new paragraph is added to § 60.45
as follows:
§ 60.45 Emission and fuel monitoring.
*****
(g) For the purpose of reports re-
quired pursuant to J 60.7(c), periods of
excess emissions that shall be reported
are denned as follows:
(1) Opacity. All hourly periods during
which were are three or more one-
minute periods when the average opacity
exceeds 20 percent.
(2) Sulfur dioxide. Any two consecu-
tive hourly periods during which average
sulfur dioxide emissions exceed 0.80
pound per million B.t.u. heat input for
liquid fossil fuel burning equipment or
exceed 1.2 pound per million B.t.u. heat
Input for solid fossil fuel burning equip-
ment; or for sources which elect to con-
duct representatives analyses of .fuels in
accordance with paragraph (c) or (d)
of this section in lieu of installing and
operating a monitoring device pursuant
to paragraph (a) (2) of this section, any
calendar day during which fuel analysis
shows that the limits of ! 60.43 are
exceeded.
(3) Nitrogen oxides. Any two consecu-
tive hourly periods during which the
average nitrogen oxides emissions exceed
0.20 pound per million B.t.u. heat input
for gaseous fossil fuel burning equip-
ment, or exceed 0.30 pound per million
B.tu. for liquid fossil fuel burning equip-
ment, or exceed 0.70 pound per million
B.t.u. heat input for solid fossil fuel
burning equipment.
6. A new paragraph is added to § 60.73
as follows:
§ 60.73 Emission monitoring.
*****
(e) For the purpose of making written
reports pursuant to § 60.7(c), periods of
excess emissions that shall be reported
are defined as any two consecutive hourly
periods during which average nitrogen
oxides emissions exceed 3 pounds per
ton of add produced.
FEDERAL REGISTER VOL. 38, NO. 198MONDAY, OCTOBER 15, 1973
7. A new paragraph is added to § 60.84
as follows:
§ 60.84 Emission monitoring.
*****
(e) For the purpose of making written
reports pursuant to § 60.7(c), periods of
excess emissions that shall be reported
are denned as any two consecutive hourly
periods during which average sulfur
dioxide emissions exceed 4 pounds per
ton of acid produced.
IPB Doc.73-2189« Filed 10-12-73:8:45 am]
ENVIRONMENTAL PROTECTION
AGENCY
[40 CFR Part 60}
STANDARDS OF PERFORMANCE FOR
NEW STATIONARY SOURCES
Emissions During Startup, Shutdown and
Malfunction
The Environmental Protection Agency
promulgated standards of performance
for new stationary sources pursuant to
section 111 of the Clean Air Amendments
of 1910, 40 tT.S.C. 1857c-6, on Decem-
ber 23, 1971, for fossil fuel-fired
steam generators, incinerators, Portland
cement plants, and nitric and sulfuric
acid plants. (36 FR 24876). New or modi-
fied sources in those categories are re-
quired, to meet standards for emissions
of air pollutants which reflect the de-
gree of emissions limitation achievable
through the application of the best sys-
tem of emission reduction which (taking
Into account the cost of achieving such
reduction) the Administrator determined
to be adequately demonstrated.
On August 25,1972, the Environmental
Protection Agency proposed procedures
pursuant to which new sources could
be deemed not to be in violation of the
new source performance standards if
emissions during startup, shutdown and
malfunction unavoidably exceeded the
standards (37 FR 17214). A total of 141
responses were received during the
period allowed for official comment on
the proposal. Comments received were
strongly critical of the various report-
Ing requirements, and the lack of more
specific 'criteria for granting exceptions
to the standards. A number of comments
were directed toward EPA's policy on
delegating enforcement of these proce-
dures to the States as provided under sec-
tion 111 of the Clean Air Act. This new
proposal is intended to respond to these
criticisms. The August 25,1972, proposal
Is hereby withdrawn.
Attempts to classify all of the situ-
ations in which excess emissions due to
malfunction, startup and shutdown could
occur and the amount and duration of
excess emission from each such situ-
ation indicated that it is not feasible to
provide quantitative standards or guides
which would apply to periods- of mal-
functions, startups and shutdowns.
Comments received in response to the
.proposal, however, strongly emphasized
the difficulties in planning and financing
new sources when no assurance could
be made that the sources would be in
compliance with the standards or would
IV-2 8
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PROPOSED RULES
be granted a waiver in those cases where
failure to meet the standard was not the
fault of the plant ownet or operator.
Accordingly, the approach, described
below is now proposed by EPA. This ap-
proach will ensure that new sources
install the best adequately demonstrated
technology and operate and maintain
such equipment to keep emissions as
low as possible.
The proposed regulations make it clear
that compliance with, emission stand-
ards, other than opacity standards, is de-
termined through performance tests
conducted under representative condi-
tions. The present tests for new sources
require that initial performance tests
be conducted within 60 days after achiev-
ing the maximum production rate at
which a facility will be operated but not
later than 180 days after startup and
authorizes subsequent tests from time
to time as required by the Administrator.
It is anticipated that the initial per-
formance test and subsequent perform-
ance tests will ensure that equipment
is installed which will permit the stand-
ards to be attained and that such equip-
ment is not allowed to deteriorate to the
point where the standards are no longer
maintained. In addition, the proposed
regulation requires that the plant oper-
ator use maintenance and operating
procedures designed to minimize- emis-
sions in excess of the standard. This re-
quirement will ensure that plant opera-
tors properly maintain and operate the
affected facility and control equipment
between performance tests and during
periods of startup, shutdown and un-
avoidable malfunction.
Although the requirements in the pres-
ent regulations for continuous monitor-
ing will be unaffected by these proposed
regulations, it is made clear that meas-
urements obtained as the results of such
monitoring will be used as evidence in
determining whether good maintenance
and operating procedures are being fol-
lowed. Thjy will not bt used to determine
compliance with mass emission stand-
ards unless approved as equivalent or al-
ternative method for performance test-
ing. EPA may in the future require that
compliance with new source emissions
standards be determined by continuous
monitoring. In such cases, the applicable
standard will specifically require that
compliance with mass emission limits be
determined by continuous monitoring.
Such standards will provide for malfunc-
tion, startup and shutdown situations to
the extent necessary.
With respect to the opacity standards,
a different approach was used because
this is a primary means of enforcement
using- visual surveillance employed by
State and Federal officials. EPA believes
that the burden should remain on the
plant operator to justify a failure to
comply with opacity standards. This dif-
ference is justified because determina-
tion of mass emission levels requires close
contact with plant personnel, operations
and records and the burden imposed on
enforcement agencies to determine
whether good maintenance and operat-
ing procedures have been followed is
not significantly greater than the burden
of determining mass emission levels.
However, opacity observations are taken
outside the plant and do not require
contact with plant personnel, operations
or records, and the burden of determin-
ing whether good maintenance and op-
erating procedures have been followed
would be much greater than determining
whether opacity standards have been
violated. Nevertheless, EPA has recog-
nized that malfunctions, startups and
shutdowns may result in the opacity
emission levels being exceeded. Accord-
ingly, the standards will not apply in
such cases. However, the burden will be
upon the plant operator rather than EPA
or the States to show that the opacity
standards were not met because of such
situations. In the event of any dispute,
the owner or operator of the source may
seek review in an appropriate court.
The reporting- requirements in these
proposed regulations have- been greatly
simplified. They require only that at the
end of each calendar quarter owners and
operators report emissions measured or
estimated to be greater than those allow-
able under standards applicable during
performance tests.
EPA believes that the proposed report-
ing requirements along with application
of the opacity standards will provide
adequate inf orniattori to enable EPA and
the States to effectively enforce the new
source performance standards. Addi-
tional information and shorter reporting
times would not materally increase en-
forcement capability and could, In fact,
hinder such efforts due to the additional
time and manpower required to process
the information.
The primary purpose of the quarterly
report is to provide EPA and the States
with sufficient information to determine
if further inspection or performance
tests are warranted. It should be noted
that the Administrator can delegate en-
forcement of the standards to the States
as provided by section lll(c)(l) of the
Clean Air Act, as amended. Procedures
for States to request this delegation are
available from EPA regional offices. It is
EPA's policy that upon delegation any
reports required by these proposed regu-
lations will be sent to the appropriate
State. (A change in the address for sub-
mitta] of reports as provided in 40 CFR
60.4 will be made after each delegation.)
These proposed regulations will have
no significant adverse impact on the
public health and welfare. Those sec-
tions of the Clean Air Act which are
specifically required to protect the public
health and welfare, sections 109 and HO
(National Ambient Air Quality Standards
and their implementation), section 112
(National Emission Standards for Haz-
ardous Air Pollutants), and section 303
(Emergency Powers to Stop the Emis-
sions of Air Pollutants Presenting an Im-
minent and Substantial Endangennent
to the Health of Persons), will be un-
affected by these new proposed regula-
tions and -will continue to be effective
controls protecting the public health and
welfare.
Interested persons may participate in
this proposed rulemaking by submitting
written comment in triplicate to the
Emission Standards and Engineering
Division, Environmental Protection
Agency, Research Triangle Park, N.C.
27711, Attention: Mr. Don R. Goodwin,
All relevant comments received not later
than June 18, 1973, will be considered.
Receipt of comments will be acknowl-
edged but the Emission Standards and
Engineering Division will not provide
substantial response to individual com-
ments. Comments received -will be avail-
able for public inspection during normal
business hours at the Office of Public
Affairs, 401 M Street SW., Washington,
D.C. 20460.
This notice of proposed rulemaking is
issued under the authority of sections 111
and 114 of the Clean Air Act, as amended
(42 O.S.C. 1857c-, 1857C-9).
Dated April 27, 1973.
JOHN QUARLES,
Acting Administrator,
Environmental Protection Agency.
FEDERAL REGISTER, VOL 38, NO. 84WEDNESDAY, MAY 2, 1973
IV-2 9
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9308
RULES AND REGULATIONS
** Title 40Protection of Environment
CHAPTER 1ENVIRONMENTAL
PROTECTION AGENCY
SUBCHAPTER CAIR PROGRAMS
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Additions and Miscellaneous Amendments
On June 11, 1973 (38 PR 15406), pur-
suant to section 111 of the Clean Air Act,
as amended, the Administrator proposed
standards of performance for new and
modified stationary sources within seven
categories of stationary sources: (1) As-
phalt concrete plants, (2) petroleum re-
fineries, (3) storage vessels for petroleum
liquids, (4) secondary lead smelters, <5)
secondary brass and bronze ingot pro-
duction plants, J. 6) iron and steel plants,
axid (7) sewage treatment plants. In the
same publication, the Administrator
also proposed amendments to subpart A,
General Provisions, and to the Appendix,
Test Methods, of 40 CFR Part 60.
. Interested parties participated in the
rulemaking by sending comments to EPA.
Some 253 letters, many with multiple
comments, were received from commen-
tators, and about 152 were received from
Congressmen making inquiries on behalf
of their constituents. Copies of the com-
ments received directly are available
from public inspection at the EPA Office
of Public Affairs, 401 M Street SW.,
Washington, D.C. 20460. The comments
have been considered, additional data
have been collected and assessed, and
the standards have been reevaluated.
Where determined by the Adminis-
trator to be appropriate, revisions
have been made to the proposed
standards. The promulgated stand-
ards, the principal revisions to the
proposed standards, and the Agency's re-
sponses to major comments are summar-
ized below. More detail may be found in
Background Information for New Source
Perfc<~mance Sta idards: Asphalt Con-
crete Plants, Petroleum Refineries, Stor~
age Vessels, Secondary Lead Smelters
and Refineries, Brass and Bronze Ingot
Production Plants, Iron and Steel Plants,
and Sewage Treatment Plants, Volume 3,
Promulgated Standards, (APTD-1352C)
which is available on request from the
Emission Standards and Engineering
Division, Research Triangle Park. North
Carolina 27711, Attention: Mr. Don n.
Goodwin.
Discussions of the environmental im-
pact of these standards of performance
for new sources are contained in Volume
1, Main Text CAPTD-1352a), of the
background document. This volume and"
Volume 2, Appendix: Summaries of Test
Data (APTD-1352U), are still available
on request from the office noted above.
In accordance with section 111 of the
Act, these regulations prescribing stand-
ards of performance for the selected sta-
tionary sources are effective on Feb-
ruary 28, 1974 and apply to sources the
construction or modification of which
was commenced after June 11, 1973.
GENERAL PROVISIONS
These promulgated regulations in-
clude changes to subpart A, General Pro-
visions, which applies to all new sources.
The general provisions were published on
December 23, 1971 (36 FR 24876). The
definition of "commenced" has been al-
tered to exclude the act of entering into
a binding agreement to construct or mod-
ify a source from among the specified
acts which, if taken by an owner or op-
erator of a source on or after the date on
which an applicable new source perform-
ance standard is proposed, cause the
source to be subject to the promulgated
standard. The phrase "binding agree-
ment" was duplicate terminology for the
phrase "contractual obligation" but was
being construed incorrectly to apply to
other arrangements. Deletion of the first
phrase and retention of the second
phrase eliminates the problem. The defi-
nition of "standard conditions" replaces
the definition of "standard or normal
conditions" to avoid the confusion, noted
by commentators, created by the dupli-
cate terminology. The promulgated defi-
nition also expresses the temperature
and pressure in commonly used metric
units to be consistent with the Adminis-
trator's policy of converting to the met-
ric system. Four definitions are added:
"Reference method," "equivalent
method," "alternative method," and
"run," to clarify the terms used in
changes to § 60.8, Performance Tests,
discussed below. The definition of "par-
ticulate matter" is added here and re-
moved from each of the subparts specific
to this group of new sources to avoid rep-
etition. The word "run," as used in the
sections pertinent to performance tests,
is defined as the net time required to col-
lect an adequate sample of a pollutant,
and may be either intermittent or con-
tinuous. Section 60.3, Abbreviations, is
revised to include new abbreviations, to
accord more closely with standard usage,
and to alphabetize the listing. Section
60.4, Address, is revised to change the ad-
dress to which all requests, reports, ap-
plications, submittals, and other com-
munications will be submitted to the Ad-
ministrator pursuant to any regulatory
provision. Such communications are now
to be addressed to the Director of the En-
forcement Division in the appropriate
EPA regional office rather than to the
Office of General Enforcement in Wash-
ington, D.C. The addresses of all 10 re-
gional offices are included, and the "in
triplicate" requirement is changed to "in
duplicate." Some of the wording is
changed in § 60.6, Review of Plans, to re-
quire that owners or operators request-
ing review of plans for construction or
modification make a separate request for
each project rather than for each af-
fected facility as previously required;
each such facility, however, must be
identified and appropriately described. ,A
paragraph is added to J 60.7, Notification
and Recordkeeping, to require owners
and operators to maintain a file of all re-
corded information required by the regu-
lations for at least 2 years after the dates
of such information, and this require-
ment is removed from the subparts spe-
cific to each of the new sources in this
group to avoid repetition. Section 60.8,
Performance Tests, Is amended (1) to re-
quire cwners and operators to give the
Adirun.Mrator 30 days' advance notice,
insteac. of 10 days', of performance test-
ing to demonstrate compliance with
standards in order to provide the Admin-
istrator with a better opportunity to have
an observer present, (2) to specify the
Administrator's authority to permit, in
specific cases, the use of minor changes to
reference methods, the use of equivalent
or alternative methods, or the waiver of
the performance test requirement, and
(3) to specify that each performance test
shall consist of three runs except where
the Administrator appioves the use of
two runs because of circumstances be-
yond the control of the owner or opera-
tor. These amendments give the Admin-
istrator needed flexibility for making
judgments for determining compliance
with standards. Section 60.12, Circum-
vention, is added to clearly prohibit own-
ers and operators from using devices or
techniques which conceal, rather than
control, emissions to comply with stand-
ards of performance for new sources. The
standards proposed on June 11, 1973,
contained provisions which required
compliance to be based on undiluted
gases. Many commentators pointed out
the inequities of these provisions and the
vagueness of the language used. Because
many processes require the addition of
air in various quantities for cooling, for
enhancing combustion, and for other
useful purposes, no single definition of
excess dilution air can be sensibly ap-
plied. It is considered preferable to state
clearly what is prohibited and to use the
Administrator's authority to specify the
conditions for compliance testing in each
case to ensure that the prohibited con-
cealment is not used.
OPACITY
It is evident from comments received
that an inadequate explanation was given
for applying both an enforceable opacity
standard and an enforceable concentra-
tion standard to the same source and that
the relationship between the concentra-
tion standard and the opacity standard
was not clearly presented. Because all
but one of the regulations include these
dual standards, this subject is dealt with
here from the general viewpoint. Specific
changes made to the regulations pro-
posed -tor a specific source are described
in the discussions of each source.
A discussion of the major points raised
by the comments on the opacity standard
follows:
1. Several commentators felt that
opacity limits should be only guidelines
for determining when to conduct the
stack tests needed to determine compli-
ance with concentration/mass standards.
Several other commentators expressed
the opinion that the opacity standard
was more stringent than the concentra-
tion/mass standard.
As promulgated below, the opacity
standards are- regulatory requirements,
just like the concentration/mass stand-
ards. It is not necessary to show that the
concentration/mass standard is being
violated in order to support enforcement
of the opacity standard. Where opacity
and concentration/mass standards are
FEDERAL REGISTER, VOL, 39, NO. 47ttlDAY, MARCH 8, 1974
IV-30
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RULES AND REGULATIONS
9309
applicable to the same source, the opacity
standard Is not more restrictive than the
concentration/mass standard. The con-
centration/mass standard, is established
at a level which will result In the design,
installation, and operation of the best
adequately demonstrated system of emis-
sion reduction (taking costs into ac-
count) for each source. The opacity
standard is established at a level which
will require proper operation and mainte-
nance of such control systems on a day-
to-day basis, but not require the design
and installation of a control system more
efficient or expensive than that required
by the concentration/mass standard.
Opacity standards are a necessary sup-
plement to concentration/mass stand-
ards. Opacity standards help ensure that
sources and emission control systems
continue to be properly maintained and
operated so as to comply with concen-
tration/mass standards. Particulate test-
ing by EPA method 5 and most other
techniques requires an expenditure of
$3,000 to $10,000 per test including about
300 man-hours of technical and semi-
technical personnel. Furthermore, sched-
uling and preparation are required such
that it Is seldom possible to conduct a
test with )«ss than 2 weeks notice. There-
fore, method 5 participate tests can be
conducted only on an infrequent basis.
If there were no standards other than
concentration/mass standards, it would
be possible to inadequately operate or
maintain pollution control equipment at
all times except during periods of per-
formance testing. It takes 2 weeks or
longer to schedule a typical stack test.
If only small repairs were required, e.g.,
pump or fan repair or replacement of
fabric filter bags, such remedial action
could be delayed until shortly before the
test is conducted. For some types of
equipment such as scrubbers, the energy
input could be reduced (the pressure drop
through the system) when stack tests
weren't being conducted, which would
result in the release of significantly more
participate matter than normal. There-
fore, EPA has required that operators
properly maintain air pollution control
equipment at all times (40 CFR 60.11
(d)) and meet opacity standards at all
times except during periods of startup,
shutdown, and malfunction (40 CFR
60.11(c)), and during other periods of
exemption as specified in individual
regulations.
Opacity of emissions is Indicative of
whether control equipment is properly
maintained and operated. However, It is
established as an independent enforce-
able standard, rather than an indicator
of maintenance and operating conditions
because information concerning the lat-
ter is peculiarly within the control of
the plant operator. Furthermore, the
time and expense required to prove that
proper procedures have not been fol-
lowed are so great that the provisions of
40 CFR 60.11 (d) by themselves (without
opacity standards) would not provide an
economically sensible means of ensuring
on a day-to-day basis that emissions of
pollutants are within allowable limits.
Opacity standards require nothing more
than a trained observer and can be per-
formed with no prior notice. Normally,
It is not even necessary for the observer
to be admitted to the plant to determine
properly the opacity of stack emissions.
Where observed opacities are within al-
lowable limits, it is not normally neces-
sary for enforcement personnel to enter
the plant or contact plant personnel.
However, in some cases, including times
when opacity standards may not be
violated, a full investigation of operating
and maintenance conditions will be de-
sirable. Accordingly, EPA has require-
ments for both opacity limits and proper
operating and maintenance procedures.
2. Some commentators suggested that
the regulatory opacity limits should be
lowered to be consistent withthe opacity
observed at existing plants; others felt
that the opacity limits were too strin-
gent. The regulatory opacity limits are
sufficiently close to observed opacity to
ensure proper operation and mainte-
nance of control systems on a continuing
basis but still allow some room for minor
variations from the conditions existing
at the time opacity readings were made.
3. There are specified periods during
which opacity standards do not apply.
Commentators questioned the rationale
for these time exemptions, as proposed,
some pointing out that the exemptions
were not justified and some that they
were inadequate. Time exemptions fur-
ther reflect the stated purpose of opacity
standards by providing relief from such
standards during -periods when accept-
able systems of emission reduction are
judged to be incapable of meeting pre-
scribed opacity limits. Opacity standards
do not apply to emissions during periods
of startup, shutdown, and malfunction
(see FEDERAL REGISTER of October 15,
1973,38 FR 28564), nor do opacity stand-
ards apply during periods judged neces-
sary to permit the observed excess emis-
sions caused by soot-blowing and un-
stable process conditions. Some confu-
sion resulted from the fact that the
startup-shutdown-malfunction regula-
tions were proposed separately (see FED-
ERAL REGISTER of May 2, 1973, 38 FR
10820) from the regultions for this group
of new sources. Although this was point-
ed out in the preamble (see FEDERAL REG-
ISTER of June 11, 1973, 38 FR 15406) to
this group of new source performance
'standards, it appears to have escaped the
notice of several commentators.
4. Other comments, along with re-
study of sources and additional opacity
observations, have led to definition of
specific time exemptions, where needed,
to account for excess emissions resulting
from soot-blowing and process varia-
tions. These specific actions replace the
generalized approach to time exemp-
tions, 2 minutes per hour, contained in
all but one of the proposed opacity
standards. The intent of the 2 minutes
was to prevent the opacity standards
from being unfairly stringent and re-
flected an arbitrary selection of a time
exemption to serve this purpose. Com-
ments noted that observed opacity and
operating conditions did not support this
approach. Some pointed out that these
exemptions were not warranted; others.
that they were inadequate. The cyclical
basic oxygen steel-making process, for
example, does not operate In hourly
cycles and the inappropriateness of 2
minutes per hour In this case would ap-
ply to other cyclical processes whteh ex-
ist both in sources now subject to stand-
ards of performance and sources for
which standards will be developed In the
future. The time exemptions now pro-
vide for circumstances specific to the
sources and, coupled with the startup-
shutdown-malfunction provisions and
the higher-than-observed opacity limits,
provide much better assurance that the
opacity, standards are not unfairly
stringent.
ASPHALT CONCRETE PLANTS
The promulgated standards for as-
phalt concerete plants limit particulate
matter emissions to 90 mg/dscm (0.04
gr/dscf and 20 percent opacity.
The majority of the comments re-
ceived on the seven proposed standards
related to the proposed Btandards for as-
phalt concrete plants. Out of the 253
letters, over 65 percent related to the
proposed standards for asphalt concrete
plants. Each of the comments was re-
viewed and evaluated. The Agency's re-
sponses to the comments received are in-
cluded in Appendix E of Volume 3 of the
background information document. The
Agency's rationale for the promulgated
standards for asphalt concrete plants is
summarized below. A more detailed
statement is presented in Volume 3 of
the background information document.
The major differences between the
proposed standards and the promul-
gated standards are:
1. The concentration standard has
been changed from 70 mg/dscm (0.031
gr/dscf) to 90 mg/dscm (0.04 gr/dscf).
2. The opacity standard has been
changed from 10 percent with a 2-
minute-per-hour exemption to 20 per-
cent with no specified time exemption.
3. The definition of affected facility
has been reworded to better define the
applicability of the standards.
The preamble to the proposed stand-
ard- (38 FR 15406) urged all interested
parties to submit factual data during the
comment period to ensure that the
standard for asphalt concrete plants
would, upon promulgation, be consistent
with the requirements of section 111 of
the Act. A substantial amount of in-
formation on emission tests was sub-
mitted in response to this request. The
information is summarized and discussed
In Volume 3 of the background informa-
tion document.
The proposed concentration standard
was based on the conclusion that the
best demonstrated systems of emission
reduction, considering costs, are well de-
signed, operated, and maintained bag-
houses or venturi scrubbers. The emis-
sion test data available at the time of
proposal indicated that such systems
could attain an emission level of 70 rug/
Nm", or 0.031 gr/dscf. After considering
comments on the proposed standard and
new emission test data, & thorough eval-
FEDERAl REGISTER, VOL 39, NO. 47FRIDAY, MARCH 8, 1974
IV-31
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9310
RULES AND REGULATIONS
ulation was made of the acblevability of
the proposed standard. As a result of this
evaluation, the concentration standard
was changed to 90 mg/dscm, or 0.04 gr/
dscf.
With the exception of three cases, the
acceptable data had shown that the pro-
posed concentration standard, 0.031 gr/
dscf, is achievable with a properly de-
signed, instated, operated, and main-
tained baghouse-or venturi scrubber. The
three exceptions, two plants equipped
with baghouses and one with a venturi
scrubber, had emissions between 0.031
and 0.04 gr/dscf.
Some of the major comments received
from the industry were (1) the proposed
concentration standard of 0.031 gr/dscf
cannot be attained either consistently
or at all with currently available equip-
ment; (2) the standard should be 0.06
gr/dscf; (3) the standard should allow
higher emissions when heavy fuel oil is
burned; 44) the type of aggregate used
by a plant changes and affects the emis-
sions; (5) EPA failed to consider the
impact of the standard on mobile plants,
continuous-mix plants, and drum-mixing-
plants; and <6) the EPA control cost
estimates are too low. Responses to these
comments and others are given in Ap-
pendix E to Volume 3 of the background
information document. When considered
as a whole, along with the new emission
data, the comments Justify revising the
Standard. The revision is merely a change
in EPA's judgment about what emission
limit is achievable using the best sys-
tems of emission reduction. The revision
is in noway a change in what EPA con-
.siders to be-the best systems of emission
reduction which, taking into account
the cost of achieving such reduction,
have been adequately demonstrated;
these are still considered to be well
designed, operated, and maintained bag-
houses or venturi scrubbers.
In response to comments received on
the proposed opacity standard, addi-
tional data were obtained on visible
emissions from, three well-controlled
plants. The data are summarized in Vol-
ume 3 of the background information
document. No visible emissions were ob-
served from- the control equipment on
any of the .plants. In addition, one plant
showed no visible fugitive emissions. In-
spection of the two plants having^ visible
fugitive emissions, together with the fact
that one plant had no visible emissions,
shows that all of the fugitive emissions
observed could have been prevented by
proper design, operation, and mainte-
nance of the asphalt plant and Its con-
trol equipment. The data, show no nor-
mal- process variations that would cause
visible emissions, either fugitive or from
the control device, at a well-controlled
plant.
As indicated above in the discussion on
opacity, the opacity standards are set
such that they are not more restrictive
than the applicable concentration stand'
ard. In* the case of asphalt concrete
plants, tt 1* the judgment of the Admin-
istrator that If a plant's ffnUf1""* equal
or exceed 30 percent opacity; the emis-
sions will also clearly exceed the concen-
tration standard of 90 mg/dscm (0.04
gr/dscf). Therefore, the promulgated
standard of 20 percent opacity is not
more restrictive than the concentration
standard and no specific time exemp-
tions are considered necessary.
An additional relief from the opacity
standard is provided by the- regulation
promulgated on October 15,1973 (38 FB
28564), which exempts from opacity
standards any emissions generated dur-
ing startups, shutdowns, or malfunctions.
A general discussion of the purpose of
opacity standards and the issues involved
in setting them is included in Chapter 2,
Volume 3, of the background informa-
tion document.
Section 60.90, applicability and desig-
nation of affected facility, is changed
from that proposed in order to clarify
how and when the standards apply to
asphalt concrete plants. The proposed
regulation was interpreted by some com-
mentators as requiring existing plants
to-meet the standards of performance for
new sources when equipment was nor-
mally replaced or modernized. The pro-
posed regulation specified certain equip-
ment, e.g., transfer and storage systems,
as affected facilities, and, because of reg-
ulatory language, this could have been
interpreted to mean that a new conveyor
system installed to replace a worn-out
conveyor system on an existing plant
was a new source as defined in section
111 (a) (2) of the Act. The promulgated
regulation specifies the asphalt concrete
plant as the affected facility in order to
avoid this unwanted interpretation: An
existing asphalt concrete plant is sub-
ject to the promulgated standards of per-
formance for new sources only if a phys-
ical change to the plant or change in the
method of operating the plant causes an
increase in the amount of air pollutants
emitted. Routine maintenance, repair
and replacement; relocation of a portable
plant; change of aggregate; and transfer
of ownership are not considered modifi-
cations- which would require an existing
plant to comply with the standard.
Industry's comments on the cost esti-
mates pertinent to the proposed stand-
ards pointed out some errors and over-
sights. The cost estimates have been re-
vised to include: (1) An increase in the
investment cost for baghouses, (2) 'a
change of credit for mineral filler from
$9.00 to $3.40 per ton, and (3) an in-
crease in the disposal costs. The changes
Increased the estimated investment cost
of the control equipment by approxi-
mately 20 percent. The revised cost esti-
mates are presented in Volume 3 of the
background information document. It is
concluded after evaluating the revised
estimates that a baghouse designed with
a 8-to-l air-to-cloth ratio or a venturi
scrubber with a pressure drop of at least
20 inches water gauge can be installed,
operated, and maintained at a reasonable
cost. It should be noted that the cost esti-
mates were revised because the original
estimates contained some errors and
oversights, not because the concentration
standard was changed
PETROLEUM REFINERIES
The promulgated standards for petro-
leum refineries limit emissions of sulfur
dioxide from fuel gas combustion systems
and limit emissions of particulate mat-
ter and carbon monoxide from fluid cata-
lytic cracking unit catalyst regenerators.
Each of the comments received on the
proposed standards was reviewed and
evaluated. The Agency's responses to the
comments received are included in Ap-
pendix E of Volume 3 of the background
information document. The Agency's
rationale for the promulgated standards
for petroleum refineries is summarized
below. A more detailed statement is pre-
sented in Volume 3 of the background
information document.
The major differences between the pro-
mulgated standards and the proposed
standards are:
1. The combustion of process upset
gases in flare systems has been exempted.
2. Hydrogen sulfide. in fuel gases com-
busted in any number of facilities may
be monitored at one location if sampling
at this location yields results represent-
ative of the hydrogen sulflde-concentra-
tion in the fuel gas combusted in each
facility.
3. The-opacity standard for catalyst re-
generators has been changed from the
proposed level of less than 20 percent ex-
cept for 3 minutes in any 1 hour to less
than 30 percent except for 3 minutes in
any 1 hour.
4. The standard for particulate mat-
ter has been changed from the proposed
level of 50 mg/Nm3 (0.022 gr/dscf) to
1.0 kilogram per 1,000 kilograms of coke
burn-off, in the catalyst regenerator
(0.027 gr/dscf).
The two changes made to the proposed
standard for fuel gas combustion systems
do not represent any change in the
Agency's original intent. It was evident
from the comments received, however,
that the intent of the regulation was not
clear. Therefore, explicit provisions were
incorporated into the promulgated stand-
ard to exempt the flaring of process
upset gases and to permit monitoring at
one location of the hydrogen sulflde con-
tent of fuel gases combusted in any num-
ber of combustion devices. Although hy-
drogen sulflde monitors are widely used
by industry, the Agency has not evaluated
the operating characteristics of such in-
struments. For this reason, calibration
and zero specifications have been pre-
scribed in only general terms. On the
basis of evaluation programs currently
underway, these requirements will be re-
vised, or further guidance will be pro-
vided concerning the selection, operation
and maintenance of such instruments.
Commentators suggested that small
petroleum refineries be exempt from the
standard for fuel gas combustion systems
since compliance with the standard
would impose a severe economic penalty
on small refineries. This problem was
considered during the development of the
proposed standard. It was concluded,
however, that the proposed standard
would have little or no adverse economic
impact on petroleum refineries.. In light
FEDERAL REGISTER, VOL 39, NO 47FRIDAY. MARCH 8, 1974
IV-3 2
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RULES AND REGULATIONS
9311
of ttie -comments received, the Agency
reexamined this point with particular
attention to the small refiner.
Tlie details of the anlaysis are pre-
sented in Appendix C to Volume 3 of the
background information document. The
domestic petroleum Industry is ex-
tremely -complex and highly sophisti-
cated. Thus, any analysis of the petro-
leum refining industry will of necessity be
based on a number of simplifying as-
sumptions. Although the assumptions in
the economic impact statement appear
reasonable, the statement should not be
viewed as definitively identifying specific
costs; rather it identifies a range of costs
and approximate impact "points. The an-
alysis examines more than the economic
Impact of the standard lor fuel gas com-
bustion systems.' It afeo examines the
combined economic impact -of this
standard for fuel gas -combustion sys-
tems, the standards for fluid catalytic
cracking units, the water quality effluent
guidelines being developed for petroleum
refineries, and EPA's regulations requir-
ing the reduction of lead in gasoline.
Essentially, the economic impact of 'pol-
lution control' is reviewed in light of
the petroleum import license-fee pro-
gram being administered by the Oil and
Gas Offse of the Department of the In-
terior <38 PR 9645 and 38 PR 16195).
This program is designed to encourage
expansion and -construction of U.S. pe-
troleum refining capacity and -expansion
of U.S. crude oil production by imposing
a fee or tariff ori imported petroleum
products and crude oil. Although this
program is currently being phased into
practice with the full impact not to be
felt until mid-1975, the central feature
of the program is to impose a fee of 21c
per barrel above world price on imported
crude oil and a fee of 63c per barrel above
world price on imported petroleum prod-
ucts such as gasoline, fuel oils, and -(un-
finished' or intermediate petroleum
products.
Under the conditions currently exist-
ing in the United States, which are fore-
cast to -continue throughout the re-
mainder of this decade and most of the
next decade, and with domestic demand
for crude oil und petroleum products
far outstripping domestic supply and pe-
troleum refining capacity, the import li-_
cense-fee program will encourage domes-
tic prices of crude oil and petroleum
products to increase to world levels plus
the fee or tariff. Thus, -an incentive of
42 tf per barrel (630 per barrel minus 21tf
per barrel) is provided to domestic re-
finers by this program. In cases where
'independent* refiners continue to enjoy
a captive supply of domestic crude oil, or
where "major" refiners engaged in the
exploration and production of domestic
crude are successful in supplying their
refineries -with domestic crude on, this
incentive will approach the full 63
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9312
RULES AND REGULATIONS
trol of hydrocarbon emissions may be
used ia lieu of the systems specified by
the standard. An example of an equiv-
alent control system is one which in-
cinerates with an auxiliary fuel th&
hydrocarbon emissions from the storage
tank before such emissions are released
into the atmosphere.
The storage of crude oil and conden-
sate at producing fields is specifically
exempted from the standard. The pro-
posed regulation had Intended such an
exemption by applying the standard
only to storage vessels with capacities
above 65,000 gallons. Industry repre-
sentatives indicated that this action
would exempt essentially all of the pro-
ducing field storage, but later data
showed that larger tanks are used in
these locations. The specific jxemptlon
in the promulgated regulation better
suits the intention. The standard now
applies at capacities greater than 40,000
gallons, the size originally selected as
being most consistent with existing State
and local regulations before It was in-
creased to exempt producing field stor-
age. Producing field storage is exempt
because the low level of emissions, the
relatively small size of these tanks, and
their commonly remote locations argue
against justifying the switch from the
bolted-construction, fixed-roof tanks in
common use to the welded-construction,
floating-roof tanks that would be re-
quired for new sources to comply with
the standards.
The proposed standard required the
use of conservation vents when petro-
leum liauids were stored at true vapor
pressures less than 78 mm Hg. This re-
quirement is deleted because, as com-
mentators validly argued, certain stocks
foul these vents, in cold weather the
vents must be locked open or removed to
prevent freezing, and the beneficial ef-
fects of such vents are minimal.
The monitoring and recordkeeping
requirements are substantially reduced
from those which were proposed. Over
half of those who commented on this
regulation argued that an unjustifiable
burden was placed on owners and op-
erators of remote tank farms, terminals,
and marketing operations. EPA agrees.
The basis for the proposed standard was
the large, modern refinery which could
have met the proposed requirements with
little difficulty. The reduced require-
ments aid both enforcement officials
and owners/operators by reducing
paperwork without sacrificing the ob-
jectives of the regulation.
Some specific maintenance require-
ments were proposed but are deleted.
Commentators pointed out that these re-
quirements were not sufficiently explicit.
A recent change to the General Provi-
sions, subpart A, (see FEDERAL REGISTER
of October 15, 1973, 38 PR 28564) re-
quires that all affected facilities and
emission control systems be operated
and maintained in a manner consistent
with good air pollution control practice
for minimizing emissions. This provision
will ensure the use of good maintenance
practices for storage vessels, which was
the intent of the proposed maintenance
requirements.
SECONDARY LEAD SMELTERS AND REFINERIES
The promulgated standards limit
emissions of particulate matter (1) from
blast (cupola) and reverberatory fur-
naces to no more than 50 mg/dscm
(0.022 gr/dscf) and to less than 20 per-
cent opacity, and (2) from pot furnaces
having charging capacities equal to or
greater than 250 kilograms to less than
10 percent opacity.
These standards are the same as those
proposed except that the 2-minutes-per-
hour exemption is removed from both
opacity standards. The general rationale
for this change is presented above in the
discussion of opacity. Two factors led
to this change in the opacity standards:
(1) The separately promulgated regula-
tions that provide exemptions from the
opacity standards during periods of
startup, shutdown, and malfunction (see
FEDERAL REGISTER of October 15, 5973,
38 FR 28564), and (2) the comments,
reevaluation of data, and collection of
new data and information which show
that there is no basis for time exemp-
tions hi addition to those provided for
startups, shutdowns, and malfunctions,
and that the opacity standard is not
more restrictive than the concentration
standard.
Minor changes to the proposed version
of the regulation have been made to
clarify meanings and to exclude repeti-
tive provisions and definitions which are
now included in subpart A, General Pro-
visions, and which are applicable to all
new source performance standards.
SECONDARY BRASS AND BRONZE INGOT
PRODUCTION PLANTS
The promulgated standards limit the
emissions of particulate matter (1) from
reverberatory furnaces having produc-
tion capacities equal to or greater than
1,000 kg (2205 Ib) to no more than 50
mg/dscm (0.022 gr/dscf) and to less than
20 percent opacity, (2) from electric
furnaces having capacities equal to or
greater than 1,000 kg (2,205 Ib) to less
than 10 percent opacity, and (3) from
blast (cupola) furnaces having capacities
equal to or greater than 250 kg/hr (550
Ib/hr) to less than 10 percent opacity.
These standards are the same as those
proposed except that the opacity limit
for emissions from the affected reverber-
atory furnaces is increased from less
than 10 percent to less than 20 percent
and the 2-minutes-per-hour exemption
is removed from all three opacity stand-
ards. The general rationale for these
changes is presented in the discussion of
opacity above. The three factors which
led to these changes are (1) the data and
comments, summarized in Volume 3 of
the background information document,
which show, in the judgment of the
Administrator, that the opacity standard
proposed for reverberatory furnaces was
too restrictive and that the promulgated
opacity standard is not more restricted
than the concentration standard, (2)
the separately promulgated regulations
which provide exemptions from opacity
standards during periods of startup,
shutdown, and malfunction (see FED-
ERAL REGISTER of October 15, 1973, 38
FR 28564). and (3) the comments, re-
evaluation of data, and collection of new
data and information which show .that
there is no basis for additional time
exemptions.
Minor changes to the proposed version
of the regulation have been made to
clarify meanings and to exclude repeti-
tive provisions and definitions which
are now included in subpart A, General
Provisions, and which are applicable to
all new source performance standards.
IRON AND STEEL PLANTS
The promulgated standards limit the
emissions of particulate matter from
basic oxygen process furnaces to no more
than 50 mg/dscm (0.022 gr/dscf). This
is the same concentration limit as was
proposed. The opacity standard and the
attendant monitoring requirement are
not promulgated at this tune. Sections
of the regulation are reserved for the
inclusion of these portions at a later date.
Commentators pointed out the inappro-
priateness of the proposed opacity stand-
ard (10 percent opacity except for 2
minutes each hour) for this cyclic steel-
making process. The separate promul-
gation of regulations which provide ex-
emptions from opacity standards during
periods of startup, shutdown, and mal-
function (see FEDERAL REGISTER of Octo-
ber 15, 1973, 38 FR 28564) add another
dimension to the problem, and new data
show variations in opacity for reasons
not yet well enough identified.
The promulgated regulation represents
no substantial change to that proposed.
Some wording is changed to clarify
meanings and, as discussed under Gen-
eral Provisions above, several provisions
and definitions are deleted from this sub-
part and added to subpart A, which ap-
plies to all new source performance
standards, to avoid repetition.
SEWAGE TREATMENT PLANTS
The promulgated standards for sludge
incinerators at municipal sewage treat-
ment plants limit particulate emissions
to no more than 0.65 g/kg dry sludge
input (1.30 Ib/ton dry sludge input) and
to less than 20 percent opacity. The pro-
posed standards would have- limited
emissions to a concentration of 70 mg/
Nm3 (0.031 gr/dscf) and to less than 10
percent opacity except for 2 minutes in
any 1 hour. The level of control required
by the standard remains the same, but
the units are changed from a concentra-
tion to a mass basis because the deter-
mination of combustion ah* as .opposed
to dilution air for these facilities is par-
ticularly difficult and could lead to un-
acceptable degrees of error. The section
on test methods is revised In accord-
ance with the change of units for the
standard.
A section Is added specifying instru-
mentation and sampling access points
needed to determine sludge charging
rate. Determination of this rate is neces-
sary as a result of the change of units
for the standard. Flow measuring devices
with an accuracy of ±5. percent must be
installed to determine either the mass
or volume of the sludge charged to the
incinerator, and access to the sludge
charged must be provided BO «
FEDERAL REGISTER, VOL- 3», NO.. 47FRIDAY, MARCH 8, 1974
IV-3 4
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RULES AND REGULATIONS
9313
mixed representative grab sample of the
sludge can be obtained.
The general rationale for the change
In the opacity standard is presented
in the discussion of opacity above.
The three factors .which led to this
change are (I) the data, summarized
in Volume 3 of the background informa-
tion document, which, in the judgment
of the Administrator, show that the pro-
posed opacity standard was too restric-
tive and that the promulgated standard
is not more restrictive than the mass
standard, (2) the separately promulgated
regulations which provide exemptions
from opacity standards during periods of
startup, shutdown, and malfunction (see
FEDERAL REGISTER of October 15,1973, 38
PR 28564), And <3) reevaluation of data
md collection of new data and informa-
,ion which show that there is no basis
"or additional time exemptions.
Minor changes to the proposed version
af the regulation have been made to
:larify meanings and to exclude repeti-
tive provisions and definitions which are
now included in subpart A, General Pro-
visions, and are applicable to all new
source performance standards.
TEST METHODS
Test Methods 10 and 11 as proposed
contained typographical errors that are
now corrected in both text and equations.
Some wording is changed to clarify
meanings and procedures as well.
In Method 10, which is for determina-
tion of CO emissions, the term "grab
sampling" is changed to "continuous
sampling" to prevent confusion. The
Orsat analyzer is deleted from the list
of analytical equipment because a less
complex method of analysis -was judged
sufficiently sensitive. For clarification, a
sentence is added to the section on re-
agents requiring calibration gases to be
certified by the manufacturer. Tempera-
ture of the silica -gel is changed from
m-C (35CTF) to 175'C (34TF) to be
consistent with the emphasis on metric
units as the primary units. A technique
for' determining the CO, -content of the
gas has been added to both the con-
tinuous and integrated sampling proce-
dures. This technique may be used rather
than the technique described in Method
3. Use of the latter technique was re-
quired in the ^proposed Method 10.
Method 11, which is for determination
of H-S emissions. Is modified to require
five midget impingers rather than the
proposed four. The fifth impinger con-
tains hydrogen peroxide to remove sul-
fur dioxide as an interferant. A para-
graph is added specifying the .hydrogen
peroxide solution to be used, and the
procedure description is altered to in-
clude procedures specific to the fifth im-
pinger. The term "iodine number flask" is
changed to "iodine flask" to prevent con-
fusion.
Dated: February 22, 1974.
RUSSELL E. TRAIN,
Administrator.
Part 60. Chapter I. Title 40, Code of
Federa! Regulations, is amended by re-
vising subpart A, by adding new subparts
I,J,K,L,M,N, and O, and by adding
Methods 10 and 11 to the Appendix, as
follows :
Subpart A General Provisions
Sec.
60 2 Definitions.
60.3 Abbreviations.
60.4 Address.
60.6 Reviewer plans.
60.7 Notification and lecordkeeptag.
60*. Performance tests.
60.12 Circumvention.
Subpart I Standards of Performance for Asphalt
Concrete Plants
60.90 Applicability and designation of af-
fected facility.
60.91 Definitions.
60.92 Standard for particulate matter.
60 93 Test methods And procedures.
Subpart J Standards of Performance for
Petroleum Refineries
60.1OO Applicability and designation of af-
fected facility.
60J01 .Definitions.
60.102 Standard for particulate matter.
60.103 Standard for carbon monoxide.
60.104 Standard for sulfur dioxide.
60.105 Emission monitoring.
60.106 Test methods and procedures.
Subpart K Standards of Performance for Storage
Vessels for Petroleum Liquids
60.110 Applicability and designation of
affected facility.
60.111 Definitions.
60.112 Standard for hydrocarbons.
60 ) 13 Monitoring of operations.
Subpart L Standards of Performance for
Secondary Lead Smelters
60.120 Applicability and designation of
affected facility.
60.121 Definitions.
60.122 Standard for particulate matter.
60.123 Test methods and procedures.
Subpart M Standards of Performance for Sec-
ondary Brass and Bronze Ingot Production Plants
60.130 Applicability and designation of
affected facility
60.131 Definitions.
60.132 Standard for particulate matter.
60.133 Test methods and procedures.
Subpart N Standards of Performance for Iron
and Steel Plants
60.140 Applicability and designation of
affected .facility .
60.141 Definitions.
60.142 Standard for particulate matter.
60.143 [Reservedl
80 144 Test methods »nd procedures.
Subpart O Standards of Performance for
Sewage Treatment Wants
60.150 Applicability and designation of
affected facility.
60.151 Definitions.
60.162 Standard for particulate matter.
60.153 Monitoring of operations.
60.154 Test methods and procedures.
TEST METHODS
Method 10 Determination of carbon mon-
oxide emissions from sta-
tionary sources.
Method 11 Determination of hydrogen sul-
fide emissions from stationary
sources.
AUTHORrrr: Sees. Ill, 114, "Pub. L. -91-604
(42 TJJS.C. 1857 (c) (6) and
Subpart AGeneral Provisions
1. Section 60.2 is amended by revising
paragraphs (i) and (1) and adding para-
graphs (s), (t), (u). (v), and
-------
9314
RULES AND REGULATIONS
hrIhour(s)
HC1hydrochloric acid
Hgmercury
upwater
H.Shydrogen sulflda
KpO4sulfurlc acid
in.IncH(es)
Kdegree Kelvin
k1,000
kgkilogram (s)
1llter(s)
1pmllter(s) per minute
Ibpound (s)
mmeter(s)
meqmUllequlvalent(8)
jnlnmlnuite(s)
mgmilligram (s)
mlmllllllter(s)
mmmillimeter (6)
mol. wt.molecular weight
mVmillivolt
N.,nitrogen
nmnanometer(s)10-* meter
NOnitric oxide
NOanitrogen dioxide
NO,nitrogen oxides
O2oxygen
ppbparts per billion
ppmparts per million
psiapounds per square Inch absolute
«Bdegree Rankdne
6at standard conditions
secsecond
SOasulfur dioxide
SO3sulfur trloxlde
pgmlcrogram(s)10-« gram
3. Section 60.4 Is revised to read as
follows:
§ 60.4 Address,
All requests, reports, applications, sub-
mittals, and other communications to the
Administrator pursuant to this part shall
be submitted In duplicate and addressed
to the appropriate Regional Office of the
Environmental Protection Agency, to the
attention of the Director, Enforcement
Division. The regional offices-are as fol-
lows:
Region I (Connecticut, Maine, New Hamp-
shire, Massachusetts, Rhode Island, Ver-
mont), John P. Kennedy Federal Building,
Boston, Massachusetts 02203.
Reg'sn II (New York, New Jersey, Puerto
Rico, Virgin Islands), Federal Office Building,
28 Federal Plaza (Foley Square), New York,
N.T.10007.
Region m (Delaware, District of Colum-
bia, Pennsylvania, Maryland, Virginia, West
Virginia), Curtis Building, Sixth and Walnut
Streets, Philadelphia, Pennsylvania 19106.
Region IV (Alabama, Florida, Georgia, Mis-
sissippi, Kentucky, North Carolina, South
Carolina, Tennessee), Suite 300, 1421 Peach-
tree Street, Atlanta, Georgia 30309.
Region V (Illinois, Indiana, Minnesota,
Michigan, Ohio, Wisconsin), 1 North Wacker
Drive, Chicago, Illinois 60606.
Region VI (Arkansas, Louisiana, New Mexi-
co, Oklahoma, Texas), 1600 Patterson Street.
Dallas, Texas 75201.
Region vn (Iowa, Kansas, Missouri, Ne-
braska), 173S Baltimore Street, Kansas City,
Missouri 64108.
Region Vm (Colorado, Montana, North
Dakota, South Dakota, Utah, Wyoming), S16
Lincoln Towers, 1860 Lincoln Street, Denver,
Colorado 80203.
Region EK (Arizona, California, Hawaii,
Nevada, Guam. American Samoa), 100 Cali-
fornia Street, San Francisco, California 94111.
Region X (Washington, Oregon, Idaho,
Al»»ka), 1300 Sixth Avenue, Seattle, Wash-
ington 98101.
4. In § 60.6, paragraph (b) Is revised
to read as follows:
§ 60.6 Review of plans.
*****
(b) (1) A separate request shall be sub-
mitted for each, construction or modifica-
tion project.
(2) Each request shall identify the lo-
cation of such project, and be accom-
panied by technical information describ-
ing the proposed nature, size, design, and
method of operation of each affected fa-
cility involved in such project, including
information on any requipment to be
used for measurement or control of emis-
sions.
5. In } 60.7 paragraph (d) is added as
follows:
§ 60.7 Notification and recordkeeping.
» * * « t
(d) Any owner or operator subject to
the provisions of this part shall maintain
a file of all measurements, including
monitoring and performance testing
measurements, and all other reports arid
records required- by all applicable sub-
parts. Any such measurements, reports
and records shall be retained for at least
2 years following the date of such meas-
urements, reports, and records.
6. Section 60.8 is amended by revising
paragraphs (b) and (f) and by deleting
in paragraph (d) the number "10" after
the word "Administrator" and substitut-
ing the number "30." The revised para-
graphs (b) and (f) read as follows:
§ 60.8 Performance testa.
*****
Cb) Performance tests shall be con-
duc'-ed and 'data reduced in accordance
'with the test methods and procedures
contained in each applicable subpart
unless the Administrator (1) specifies
or approves, in specific cases, the use of
a reference method with minor changes
in methodology, (2) approves the use
of an equivalent method, (3) approves
the use of an alternative method the re-
sults of which he has determined to be
adequate for indicating whether a spe-
cific source is in compliance, or (4)
waives the requirement for performance
tests because the owner or operator of
a source has demonstrated by other
means to the Administrator's satisfac-
tion that the affected facility is in com-
pliance with the standard. Nothing in
this paragraph shall be construed to
abrogate the Administrator's authority
to require testing under section 114 of
the Act.
(f) Each performance test shall con-
sist of three separate runs using the
applicable test method. Each run shall
be conducted for the time and under the
conditions specified In the applicable
standard. For the purpose of determin-
ing compliance with an applicable
standard, the arithmetic means of re-
sults of the three 'runs shall apply. In
the event that a sample is accidentally
lost or conditions occur In which one of
the three runs must be discontinued be-
cause of forced shutdown, failure of an
irreplaceable portion of the sample
train, extreme meteorological conditions,
or other circumstances, beyond the
owner or operator's control, compliance
may, upon the Administrator's approval,
be determined using the arithmetic mean
of the results of the two other runs.
7. A new § 60.12 is added to subpart
A as follows:
§ 60.12 Circumvention.
No owner or operator subject to the
provisions of this part shall build, erect,
install, or use any article, machine,
equipment or process, the use of which
conceals an emission which would other-
wise constitute a violation of an applica-
ble standard. Such concealment in-
cludes, but Is not limited to, the use of
gaseous diluents to achieve compliance
with an opacity standard or with a
standard which is based on the concen-
tration of a pollutant, in the gases dis-
charged to the atmosphere.
8. In Part 60, Subparts I, J, K, L, M,
N, and O are added as follows:
Subpart IStandards of Performance for
Asphalt Concrete Plants
§ 60.90 Applicability and designation of
affected facility.
The affected facility to which the pro-
visions of this subpart apply is each
asphalt concrete plant. For the purpose
of this subpart, an asphalt concrete plant
is comprised only of any combination of
the following: Dryers; systems for
screening, handling, storing, and weigh-
ing hot aggregate; systems for loading,
transferring, and storing mineral filler;
systems for mixing asphalt concrete;
and the loading, transfer, and-storage
systems associated with emission control
systems.
§ 60.91 Definitions.
As used to this subpart, all terms not
denned herein shall have the meaning
given them in the Act and in subpart A
of this part.
(a) "Asphalt concrete plant" means
any facility, as described In § 60.90, used
to manufacture asphalt concrete by
heating and drying aggregate and mix-
ing with asphalt cements.
§ 60.92 Standard for paniculate matter.
(a) On and after the date on which
the performance test required to be con-
ducted by S 60.8 is completed, no owner
or operator subject to the provisions of
this subpart shall discharge or cause the
discharge Into the atmosphere from any
affected facility any gases which:
(1) Contain particulate matter in ex-
cess of 90 mg/dscm (0.04 gr/dscf).
(2) Exhibit 20 percent opacity, or
greater. Where the presence of uncom-
blned water is the only reason for failure
to meet the requirements of this para-
graph, such failure shall not be a viola-
tion of this section.
§ 60.93 Test methods and procedures.
(a) The reference methods appended
to this part, except as provided for in
5 60.8Co), shall be used to determine
RDEIM UCISTER. VOL. 39, NO. 47FRIDAY, MARCH 8, 1974
IV-3 6
-------
AND REGULATIONS
9315
compliance with the standards prescribed
in § 60.92 as follows:
(1) Method 5 for the concentration of
particulate matter and the associated
moisture content,
(2) Method 1 for sample and velocity
traverses,
(3) Method 2 for velocity and volu-
metric flow rate, and
(4) Method 3 for gas analysis.
(b) For Method 5, the sampling time
for each run shall be at least 60 minutes
and the sampling rate shall be at least 0.9
dscm/nr <0.53 dscf/min) except that
shorter sampling times, when necessi-
tated by process variables or other fac-
tors, may be approved by the Adminis-
trator.
Subpart JStandards of Performance for
Petroleum Refineries
§ 60.100 Applicability end -designation
of affected facility.
.The provisions of this subpart are ap-
plicable to the following affected facil-
ities in petroleum refineries: Fluid cata-
lytic cracking unit catalyst regenerators,
fluid catalytic cracking unit incinerator-
waste heat boilers, and fuel gas combus-
tion devices.
§ 60.101 Definitions.
As used in this subpart, all terms not
defined herein shall have the meaning
given them in the Act and in subpart A.
(a) "Petroleum refinery" means any
facility engaged in producing gasoline,
kerosene, distillate fuel oils, residual fuel
oils, lubricants, or other - products
through distillation of petroleum or
through redistillation, cracking or re-
forming of unfinished petroleum
derivatives.
(b) "Petroleum" means the crude -oil
removed from the earth and the oils de-
rived from tar sands, shale, and coal.
(c) "Process gas" means any gas gen-
erated by a petroleum refinery process
unit, except fuel gas and process upset
gas as defined to this section.
(d) "Fuel gas" means any gas which
is generated by a petroleum refinery
process unit and which is combusted, in-
cluding any gaseous mixture of natural
gas and fuel gas which is combusted.
(e) "Process upset gas" means any gas
generated by a petroleum refinery process
unit as a result of start-up, shut-down,
upset or malfunction.
tf) "Refinery process "unit" means any
segment of the petroleum refinery in
which a specific processing1 operation is
conducted.
Og) "Fuel gas combustion device"
means any equipment, such as process
heaters, boilers and flares used to com-
bust fuel gas, but does not include fluid
coking unit and fluid catalytic cracking
unit incinerator-waste heat boilers or fa-
cilities in which gases are combusted to
produce sulfur or sulfuric acid.
(h) "Coke bum-off" means the coke
removed from the surface of the fluid
catalytic cracking unit catalyst by com-
bustion in the catalyst regenerator. The
rate of coke burn-off is calculated by the
formula specified in § 60.106.
§60.102 Standard tor paniculate
matter.
(a) On and after the date on which
the performance testTequired to be con-
ducted by I 80.8 is completed, no owner
or operator subject to the provisions of
this subpart shall discharge or cause the
discharge into the atmosphere from any
fluid catalytic cracking unit catalyst re-
generator or from any fluid catalytic
cracking unit incinerator-waste heat
boiler:
(1) Particulate matter in excess of
1.0 kg/1000 kg <1.0 lb/1000 Ib) of coke
burn-off in the catalyst regenerator.
(2) Oases exhibiting 30 percent opac-
ity or greater, except for 3 minutes in
any 1 hour. Where the presence of un-
combined water is the only reason for
failure to meet the requirements of this
subparagraph, such failure shall not be a
violation of this section.
(b) In those instances in which aux-
iliary liquid or solid fossil fuels are
burned in the fluid catalytic cracking
unit incinerator-waste heat boiler, par-
ticular matter in excess of that permit-
ted by paragraph (a) (1) of this section
may be emitted to the atmosphere, ex-
cept that the incremental rate of partic-
ulate emissions shall not exceed 0.18 g/
million cal (0,10 Ib/million Btu) of heat
input attributable to such liquid or solid
fuel.
§ 60.103 Standard for carbon monoxide.
(a) On and after the date on which
the performance test required to be con-
ducted by § 60.8 is completed, no owner
or operator subject to the provisions of
this subpart shall discharge or cause the
discharge into the atmosphere from the
fluid catalytic cracking unit catalyst
regenerator any gases which contain car-
bon monoxide in excess of 0.050 percent
by volume.
§ 60.104 Standard for sulfur dioxide.
(a) On and after the date on which
the performance test required to be con-
ducted by § 60.8 is completed, no own-
er or operator subject to the provisions of
this subpart shall burn in any fuel gas
combustion device any fuel gas which
contains HjS in excess of 230 mg/dscm
(0.10 gr/dscf), except as provided to
paragraph (b) of this section. The com-
bustion of process upset gas to a flare,
or the combustion in a flare of process
gas or fuel gas which is released to the
flare as a result of relief valve leakage, is
exempt from this paragraph.
(b) The owner or operator may elect
to treat the gases resulting from the com-
bustion of fuel gas in a manner which
limits the release of SO? to the atmos-
phere if it is shown to the satisfaction
of the Administrator that this prevents
SOj emissions -as effectively as compli-
ance with tile requirements of paragraph
-------
9316
RULES AND REGULATIONS
of the gases discharged Into the atmos-
phere from any fluid catalytic cracking
unit catalyst regenerator subject to
§ 60.102 exceeds 30 percent.
(2) Carbon monoxide. All hourly pe-
riods during which the average carbon
monoxide concentration in the gases dis-
charged into the atmosphere from any
fluid catalytic cracking unit catalyst re-
generator subject to § 60.103 exceeds
0.050 percent by volume; or any hourly
period in which O, concentration and
firebox temperature measurements indi-
cate that the average concentration of
CO in the gases discharged into the at-
mosphere exceeds 0.050 percent by
volume^for sources which combust the
exhaust gases .from any fluid catalytic
cracking unit catalyst regenerator sub-
ject to § 60.103 in an incinerator-waste
heat boiler and for which the owner or
operator elects to monitor in accordance
with § 60.105(a)(3).
(3) Hydrogen svlfi.de. All hourly pe-
riods during which the average hydrogen
sulflde content of any fuel gas combusted
in any fuel gas combustion device sub-
ject to I 60.104 exceeds 230 mg/dscm
(0.10 gr/dscf) except where the require-
ments of § 60.104(b) are met.
(4) Sulfur dioxide. All hourly periods
during which the average sulfur dioxide
emissions discharged into theatmos-
phere from any fuel gas combustion de-
vice subject to § 60.104 exceed the-level
specified in § 60.104(b), except where the
requirements of § 60.104(a) are met.
§ 60.106 Test methods and procedures.
(a) For the purpose of determining
compliance with § 60.102(a) (1), the fol-
lowing reference methods and calcula-
tion procedures shall be used:
(1) -For gases released to the atmos-
phere from the fluid catalytic cracking
unit catalyst regenerator:
(i) Method 5 for the concentration of
particulate matter and moisture con-
tent,
(ii) Method 1 for sample and velocity
traverses, and
(iil) Method 2 for velocity and volu-
metric flow rate.
(2> For Method 5, the sampling time
for each run shall be at least 60 minutes
and the sampling rate shall be at least
0.015 dscm/min (0.53 dscf/min), except
that shorter sampling times may be ap-
proved by the Administrator when proc-
ess variables or other factors preclude
sampling for at least 60 minutes.
(3) For exhaust gases from the fluid
catalytic cracking unit catalyst regenera-
tor prior to the emission control system:
the integrated sample techniques of
Method 3 and Method 4 for gas analysis
and moisture content, respectively;
Method 1 for velocity traverses; and
Method 2 for velocity and volumetric flow
rate.
(4) Coke bum-off rate shall be deter-
mined by the following formula:
R.=0.2982 QHB (%COi+%CO)+2.088 QRA-0.0»« Q»« (^~+%COt+%or) (Metric Units)
B.=0.0186 QRB (%COi+%CO)-r-0.1303QRA -0.0082 Qm
(English Units)
where:
R,=coke bum-«ff rate, kg/hr (English unite: Ib/br).
0.2982=metnc units material balance factor divided by 100, kg-mln/hr-m1.
O.OlSO^English units material balance factor divided by 100, Ib-min/hr-ft5.
QRE=fluid catalytic cracking unit catalyst regenerator exhaust gas flow rate before entering the emission
control system, as determined by method 2, Cscm/min (English units: dscf/min).
%COi=percent carbon dioxide by volume, dry basis, as determined by Method 3.
% CO = percent carbon monoxide by volume, dry basis, as determined by Method 3.
% 02=* percent oxygen by volume, dry basis, as determined by Method 3.
2.088=metric units 'material balance factor divided by 100, kg-min/hr-Bi'.
0.1303=English uni ts material balance factor divided by 100, Ib-rnin/hr-ft'.
QaA = air rate to fluid catalytic cracking unit catalyst regenerator, as determined from fluid catalytic cracking
unit control room instrumentation, dscnr/min (English units: dscf/min).
0.0994 metric units material balance factor divided by 100, kg-min/hr-m'.
0.0062=Enghsh units material balance factor divided by 100, lb-min/hr-It!.
(5) Particulate emissions shall be determined by the following equation-
RB=(80X10-«)QavC. (Metric Units)
or
R*=(8.57X10-»)QRvC. (English Units)
where:
RE= particulate emission rate, kg/hr (English unite: Ib/hr).
6flX10->=metric units conversion factor, min-kg/hr-mg.
8.67X10-3=English units conversion factor, min-lb/hr-gr.
QBv = volumetnc flow rate of gases discharged into the atmosphere from the fluid catalytic cracking unit
catalyst regenerator following the emission control system, as determined by Method 2, dscm/min
(English units: dscf/mm).
C«=piirUculate emission concentration discharged mto tbe atmosphere, as determined by Method 6,
mg/dscm (English units: gr/dscf).
(6) For each run, emissions expressed in kg/1000 kg (English units: lb/1000 Ib)
of coke bum-off in the catalyst regenerator shall be determined by the following-
equation :
^ (Metric or English Units)
where:
R1 = particulate emission rate, kg/1000 kg (English units Ib/1000 Ib) of coke bum-off in the fluid catalytic crack-
ing unit catalyst regenerator.
1000=conversion factor, kg to 1000 kg (English units: Ib to 1000 Ib) .
RE=particulate emission rate, kg/far (English units: Ib/hr).
Rc=coke bum-oil rate, kg/hr (English units: Ib/nr).
(7) In those Instances in which auxiliary liquid or solid fossil fuels are 'burned
in an incinerator-waste heat boiler, the rate of particulate matter emissions per-
mitted under § 60. 102 (b) must be determined. Auxiliary fuel heat input, expressed
in millions of cal/hr (English units: Millions of Btu/hr) shall be calculated for'
each run by fuel flow rate measurement and analysis of the liquid or solid auxiliary
fossil fuels. For each run, the rate of particulate emissions permitted under
§ 60.102(b) shall be calculated from the following equation:
R,=S.C
, 0.18 H
(Metric Units)
H.=1.0+S^?-(English Units)
-tte
where'
H*=aHowable particulate emission rate, kg/1000 kg (English units: IbAOOO Ib) of coke bum-ofl in the
fluid catalytic cracking unit catalyst regenerator.
1.0=emission standard, 1.0 kg/1000 kg (English units: 1.0 lb/1000 Ib) of coke burn-ofl in the fluid catalytic
cracking unit catalyst regenerator.
0.18=metric units maximum allowable incremental rate ol particulate emissions, g/milh'on cal.
0.10=English units maximum allowable incremental rate of partioulate emissions, Ib/nullion Btn.
H=he»t input, from solid or lifpiid fossil fuel, million cal/hr (English units: million Btn/br).
R«=coke burn-oB rate, kg/hr (English units: Ib/hr).
(b) For the purpose of determining
compliance with § 60.103, the integrated
sample technique of Method 10 shall be
used. The sample shall be extracted at a
rate proportional to the gas velocity at a
sampling point near the centroid of the
duct. The sampling time shall not be less
than 60 minutes.
(c) For the purpose of determining
compliance with § 60.104
-------
RULES AND REGULATIONS
9317
two samples shall constitute one run.
Samples shall be taken at approximately
1-hour intervals. For most fuel gases,
sample times exceeding 20 minutes may
result in depletion of the collecting solu-
tion, although fuel gases containing low
concentrations of hydrogen sulfide may
necessitate sampling for longer periods of
time.
(d) Method 6 shall be used for de-
termining concentration of SO* in de-
termining compliance with 5 60.104 (b),
except that H>5 concentration of the fuel
gas may be determined instead. Method
1 shall be used for velocity traverses and
Method 2 for determining velocity and
volumetric flow rate. The sampling site
for determining SO. concentration by
Method 6 shall be the same as for
determining volumetric flow rate by
Method 2. The sampling point in the
duct for determining SO> concentration
by Method 6 shall be at the centroid of
the cross section if the cross sectional
area is less than 5 m* (54 ft") or at a
point no closer to the walls than 1 m
(39 inches) if the cross sectional area
is 5 m* or more and the centroid is more
than one meter from the wall. The
sample shall be extracted at a rate pro-
portional to the gas velocity at the
sampling point. The minimum sampling
time shall be 10 minutes and the mini-
mum sampling volume 0.01 dscm (0.35
dscf) for each sample. The arithmetic
average of two samples shall constitute
one run. Samples shall be taken at ap-
proximately 1-hour intervals.
Subpart KStandards of Performance for
Storage Vessels for Petroleum Liquids
§ 60.110 Applicability and designation
of affected facility.
. (a) Except as provided in §-60.110(b),
the affected facility to which this sub-
part applies is each storage vessel for
petroleum liquids which has a storage
capacity greater than 151,412 liters
(40,000 gallons).
(b) This subpart does not apply to
storage vessels for the crude petroleum
or condensate stored, processed, and/or
treated at a drilling and production
facility prior to custody transfer.
§ 60.111 Definitions.
As used in this subpart, all terms not
defined herein shall have the meaning
given them in the Act and in subpart A
of this part.
(a) "Storage vessel" means any tank,
reservoir, or container used for the
storage of petroleum liquids, but does
not include:
(1) Pressure vessels which are designed
to operate in excess of 15 pounds per
square inch gauge without emissions to
the atmosphere except under emergency
conditions,
(2) Subsurface caverns or porous rock
reservoirs, or
(3) Underground tanks if the total
volume of petroleum liquids added to
and taken from a tank annually does
not exceed twice the volume of the tank.
(b) "Petroleum liquids" means crude
petroleum, condensate, and any finished
or intermediate products manufactured
in a petroleum refinery but does not
mean Number 2 through Number 6 fuel
oils as specified in ASTM-D-396-69, gas
turbine fuel oils Numbers 2-GT through
4-GT as specified in ASTM-D-2880-71.
or diesel fuel oils Numbers 2-D and 4-D
as specified in ASTM-D-975-68.
(c) "Petroleum refinery" means any
facility engaged in producing gasoline,
kerosene, distillate fuel oils, residual fuel
oils, lubricants, or other products through
distillation of petroleum or through
redistillation, cracking, or reforming of
unfinished petroleum derivatives.
(d) "Crude petroleum" means a nat-
urally occurring mixture which consists
of hydrocarbons and/or sulfur, nitrogen
and/or oxygen derivatives of hydrocar-
bons and which is a liquid at standard
conditions.
(e) "Hydrocarbon" means any organic
compound consisting predominantly of
(f) "Condensate" means hydrocarbon
liquid separated from natural gas which
condenses due to changes in the tem-
perature and/or pressure and remains
liquid at standard conditions.
(g) "Custody transfer" ' means the,
transfer of produced crude petroleum
and/or condensate, after processing and/
or treating in the producing operations.
from storage tanks or automatic trans-
fer facilities to pipelines or any other
forms of transportation.
(h) "Drilling and production facility"
means all drilling and servicing equip-
ment, wells, flow lines, separators, equip-
ment, gathering lines, and auxiliary non-
transportation-related equipment used in
the production of crude petroleum but
does not include natural gasoline plants.
(i) "True vapor pressure" means the
equilibrium partial pressure exerted by
a petroleum liquid as determined in ac-
cordance with methods described in
American Petroleum Institute Bulletin
2517,' Evaporation Loss from Floating
Roof Tanks, 1962.
(j) "Floating roof" means a storage
vessel cover consisting of a double deck,
pontoon single deck, internal floating
cover or covered floating roof, which rests
upon and is supported by the petroleum
liquid being contained, and is equipped
with a closure seal or seals to close the
space between the roof edge and tank
wall.
(k) "Vapor recovery system" means a
vapor gathering system capable of col-
lecting all hydrocarbon vapors and gases
discharged from the storage vessel and
a vapor disposal system capable of proc-
essing such hydrocarbon vapors and
gases so as to m event their emission to
the atmosphere.
(1) "Reid vapor pressure" is the abso-
lute vapor pressure of volatile crude oil
and volatile non-viscous petroleum
liquids, except liquified petroleum gases,
as determined by ASTM-D-323-58 (re-
approved 1968).
§ 61.112 Standard for hydrocarbons.
(a) The owner or operator of any^stor-
age vessel to which this subpart applies
shall store petroleum liquids as follows:
(1) If the true vapor pressure of the
petroleum liquid, as stored, is equal to
or greater than 78 mm Hg (1.5 psia) but
not greater than 570 mm Hg (11.1 psia),
th? storage vessel shall be equipped with
a floating roof, a vapor recovery system,
or their equivalents.
(2) If the true vapor pressure of the
petroleum liquid as stored Is greater than
570 mm Hg (11.1 psia), the storage ves-
sel shall be equipped with a vapor re-
covery system or its equivalent.
§ 60.113 Monitoring of operations.
(a) The owner or operator of any
storage vessel to which this subpart ap-
plies shall for each such storage vessel
maintain a file of each type of petroleum
liquid stored, of the typical Reid vapor
pressure of each type of petroleum liquid
stored, and of the dates of storage. Dates
on which the storage vessel is empty shall
be shown.
(b) The owner or operator of any stor-
age vessel to which this subpart applies
shall for each such storage vessel deter-
mine and record the average monthly
storage temperature and true vapor pres-
sure of the petroleum liquid stored at
such temperature if:
(1) The petroleum liquid has a true
vapor pressure, as stored, greater than
26 mm Hg (0.5 psia) but less than 78 mm
Hg (1.5 psia) and Is stored in a storage
vessel other than one equipped with a
floating roof, a vapor recovery system
or their equivalents; or
(2) The petroleum liquid has a true
vapor pressure, as stored, greater than
470 mm Hg (9.1 psia) and is stored in
a storage vessel other than one equipped
with a vapor recovery system or Its
equivalent.
(c) The average monthly storage tem-
perature is an arithmetic average cal-
culated for each calendar month, or por-
tion thereof if storage is for less than a
month, from bulk liquid storage tem-
peratures determined at least once
every 7 days.
(d) The true vapor pressure shall be
determined by the procedures in API
Bulletin 2517. This procedure is de-
pendent upon determination of the
storage temperature and the Reid vapor
pressure, which requires sampling of the
petroleum liquids in the storage vessels.
Unless the Administrator requires ia
specific cases that the stored petroleum
liquid be sampled, the true vapor pres-
sure may be determined by using the
average monthly storage temperature
and the typical Reid vapor .pressure. For
those liquids for which certified specifi-
cations limiting the Reid vapor pressure
exist, that Reid vapor pressure may be
used. For other liquids, supporting ana-
lytical data must be made available on.
request to the Administrator when typi-
cal Reid vapor pressure isNused.
Subpart LStandards of Performance for
Secondary Lead Smelters
§ 60.120 Applicability and designation
of affected facility.
The provisions of this subpart are ap-
plicable to the following affected facil-
FEDERAL REGISTER, VOL. 39, NO. 47FRIDAY, MARCH », 1974
IV-3 9
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9318
RULES AND REGULATIONS
ities in secondary lead smelters: Pot
furnaces of more than 250 kg (550 Ib)
charging capacity, blast (cupola) fur-
naces, and reverberatory furnaces.
§ 60.121 Definitions.
As used In this subpart, all terms not
denned herein shall have the meaning
given them in the Act and in subpart A
of this part.
(a) "Reverberatory furnace" includes
the following types of reverberatory fur-
naces: stationary, rotating, rocking,
and tilting.
(b) "Secondary lead smelter" means
any facility producing lead from a lead-
bearing scrap material by smelting to the
metallic form.
(c) "Lead" means elemental lead or
allows in which the predominant com-
ponent is lead.
§ 60.122 Standard for paniculate mat-
ter.
(a) On and after the date on which
the performance test required to be con-
ducted by § 60.8 is completed, no owner
or operator subject to the provisions of
this subpart shall discharge or cause the
discharge into the atmosphere from a
blast (cupola) or reverberatory furnace
any gases which:
(1) Contain particulate matter in ex-
cess of 50 mg/dscm (0.022 gr/dscf).
(2) Exhibit 20 percent opacity or
greater.
(b) On and after the date on which
the performance test required to be con-
ducted by § 60.8 is completed, no owner
or operator subject to the provisions of
this subpart shall discharge or cause the
discharge into the atmosphere from any
pot furnace any gases which exhibit 10
percent opacity or greater.
(c) Where the presence of uncombined
water is the only reason for failure to
meet the requirements of paragraphs (a)
(2) or (b) of this section, such failure
shall not be a violation of this section.
§ 60.123 Test methods and procedures.
(a) The reference methods appended
to this part, except as provided for in
§60.8 (b), shall be used to determine
compliance with the standards prescribed
in § 60.122 as follows:
(1) Method 5 for the concentration of
particulate matter and the associated
moisture content,
(2) Method 1 for sample and velocity
traverses,
(3) Method 2 for velocity and volu-
metric flow rate, and
(4) Method 3 for gas analysis.
(b) For method 5, the sampling time
for eachrrun shall be at least 60 minutes
and the sampling rate shall be at least
0.9 dscm/hr (0.53 dscf/min) except that
shorter sampling times, when necesi bated
by process variables or other factors,
may be approved by the Administrator.
Parttculate sampling shall be conducted
during representative periods of furnace
operation, including charging and tap-
ping.
Subpart MStandards of Performance for
Secondary Brass and Bronze Ingot Pro*
duction Plants
§ 60.130 Applicability and designation
of affected facility.
The provisions of this subpart are ap-
plicable to the following affected facil-
ities in secondary brass or bronze ingot
production plants: Reverberatory and
electric furnaces of 1,000 kg (2,205 Ib) or
greater production capacity and' blast
(cupola) furnaces of 250 kg/hr (550 Ib/
hr) or greater production capacity.
§ 60.131 Definitions.
As used in this subpart, all terms not
denned herein shall have the meaning
given them in the Act and in subpart A
of this part.
(a) "Brass or bronze" means any metal
alloy containing copper as its predom-
inant constituent, and lesser amounts of
zinc, tin, lead, or other metals.
(b) "Reverberatory furnace" includes
the following types of reverberatory fur-
naces: Stationary, rotating, rocking, and
tilting.
(c) "Electric furnace" means any fur-
nace which uses electricity to produce
over 50 percent of the heat required in
"the production of refined brass or bronze.
(d) "Blast furnace" means'any fur-
nace used to recover metal from slag.
§ 60.132 Standard for paniculate matter.
(a) On and after the date on which
the performance test required to be con-
ducted by § 60.8 is completed, no owner
or operator subject to the provisions of
this subpart shall discharge or cause the
discharge into the atmosphere from a
reverberatory furnace any gases which:
(1) Contain particulate matter in ex-
cess of 50 mg/dscm (0.022 gr/dscf).
(2) Exhibit 20 percent opacity or
greater.
(b) On and after the date on which
the performance test required to be con-
ducted by § 60.8 is completed, no owner
or operator subject to the provisions of
this subpart shall discharge or cause the
discharge into the atmosphere from any
blast (cupola) or electric furnace any
gases which exhibit 10 percent opacity
or greater.
(c) Where the presence of uncom-
bined water is the only reason for fail-
ure to meet the requirements of para-
graphs (a) (2) or (b) of this section,
such failure shall not be a violation of
this section.
§ 60.133 Test methods and procedures.
(a) The reference methods appended
to this part, except as provided for in
§60.8(b), shall be used to determine
compliance with the standards pre-
scribed in § 60.132 as follows:
(1) Method 5 for the concentration
of particulate matter and the associated
moisture content.
(2) Method 1 for sample and velocity
traverses,^
C3) Method 2 for velocity and volu-
metric flow rate, and
(4) Method 3 for gas analysis.
(b) For Method 5, the sampling time
for each run shall be at least 120
minutes and the sampling rate shall be
at least 0.9 dscm/hr (0.53 dscf/min)
except that shorter sampling times, when
necessitated by process variables or other
factors, may be approved by the Admin-
istrator. Particulate matter sampling
shall be conducted during representative
periods of charging and refining, but
not during pouring of the heat.
Subpart NStandards of Performance fn«
Iron and Steel Plants
§ 60.140 Applicability and designation
of affected facility.
The affected facility to which the pro-
visions of this subpart apply is each basic
oxygen process furnace.
§ 60.141 Definitions.
As used in this subpart, all terms not
defined herein shall have the meaning
given them in the Act and in subpart A
of this part.
(a,) "Basic oxygen process furnace"
(BOPF) means any furnace producing
steel by charging scrap steel, hot metal,
and flux materials into a vessel and in-
troducing a high volume of an oxygen-
rich gas.
(b) "Steel production cycle" means
the operations required to produce each
batch of steel and includes the following
major functions: Scrap charging, pre-
heating (when used), hot metal charg-
ing, primary oxygen blowing, additional
oxygen, blowing (when used), and tap-
ping.
§ 60.142 Standard for paniculate mat'
ter.
(a) On and after the date on which
the performance test required to be con-
ducted by § 60.8 is completed, no owner
or operator subject to the provisions of
this subpart shall discharge or cause
the discharge into the atmosphere from.
any affeoted facility any gases which:
(1) Contain particulate matter in ex-
cess of 50 mg/dscm (0.022 gr/dscf).
(2) (Reserved.]
§ 60.143 [Reserved]
§ 60.144 Test methods and procedures.
(a) The reference methods appended
to this part, except as provided for in
§60.8(b), shall be used to determine
compliance with the standards prescribed
in § 60.142 as follows:
(1) Method 5 for concentration of
particulate matter and associated mois-
ture content,
(2) Method 1 for sample and velocity
traverses,
(3) Method 2 for volumetric flow rate,
and
(4) Method 3 for gas analysis.
(b) For Method 5, the sampling for
each run shall continue for an integral
number of cycles with total duration of
at least 60 minutes. The sampling rate
shall be at least 0.9 dscm/hr (0.53 dscf/
min) except that shorter sampling times,
FEDERAL REGISTER, VOL 39, NO. 47FRIDAY. MARCH 8, 1974
iy-40
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RULES AND REGULATIONS
9319
when necessitated by process variables
jr other factors, may be approved by the
Administrator. A cycle shall start at the
beginning of either the scrap preheat
ar the oxygen blow and shall terminate
immediately prior to tapping.
Subpart 0Standards of Performance for
Sewage Treatment Plants
£ 60.150 Applicability and designation
of affected facility.
The affected facility to which the pro-_
visions of this subpart apply is each
incinerator which burns the sludge pro-
duced by municipal sewage treatment
facilities.
% 60.151 Definitions.
As used in this subpart, all terms not
defined herein shall have the meaning
given them in the Act and in subpart A
of this part.
§ 60.152 Standard for paniculate mat-
ter.
(a) On and after the date on which the
performance test required to be con-
ducted by § 60.8 is completed, no owner
or operator of any sewage sludge incin-
erator subject to the provisions of this
subpart shall discharge or cause the dis-
charge into the atmosphere of:
(1) Participate matter at a rate in ex-
cess of 0.65 g/kg-dry sludge input (1.30
Ib/ton dry sludge input).
(2) Any gases which exihibit 20 per-
cent opacity or greater. Where the pres-
ence of uncombined water is the -only
reason for failure to meet the require-
ments of this paragraph, such failure
shall not be a violation of this section.
§60.153 Monitoring of operations.
(a) The owner or operator of any
sludge incinerator subject to the provi-
sions of this subpart shall:
(1) Install, calibrate, maintain, and
operate a flow measuring device which
can be used to determine either the mass
or volume of sludge charged to the incin-
erator. The flow measuring device shall
have an accuracy of ±5 percent over its
operating range.
(2) Provide access to the sludge
charged so that a well-mixed represen-
tative grab sample of the sludge can be
obtained.
§60.154 Tesl -Methods and Procedures.
(l). If total input
during a run is measured by a flow meas-
uring device, such readings shall be used.
Otherwise, record the flow measuring de-
vice readings at 5-minute intervals dur-
ing a run. Determine the quantity
charged during each interval by averag-
ing the flow rates at the beginning and
end of the interval and then multiplying
the average for each interval by the time
for each interval. Then add the quantity
for each interval to determine the total
quantity charged during the entire run,
(SM) or (Sv).
(2) Collect samples of the sludge
charged to the incinerator in non-porous
collecting jars at the beginning of each
run and at approximately 1-hour in-
tervals thereafter until the test ends, and
determine for each sample the dry sludge
content (total solids residue) in accord-
ance with "224 G. Method for Solid and
Semisolid Samples," Standard Methods
for the Examination of Water and
Wastewater, Thirteenth Edition, Ameri-
can Public Health Association, Inc., New
York, N.Y., 1971, pp. 539-41, except that:
(i) Evaporating dishes shall be ignited
to at least 103°C rather tlian the 550°C
specified in step 3(a) (1).
(ii) Determination of volatile residue,
step 3 (b) may be deleted.
(iii) The Quantity of dry sludge per
unit sludge charged shall be determined
in terms of either RDT (metric units: mg
dry sludge/liter sludge charged or Eng-
lish units: lb/ft') or BD« (metric units:
mg dry sludge/mg sludge charged or
English units: Ib/lb).
(3) Determine the quantity! of dry
sludge per unit sludge charged In terms
of either RDT or RD*.
(i) If the volume of sludge charged is
used:
SD-(60X10-;) ~~ (Metric Units)
SD= (8.021) 52I§5 (English Units)
Where:
Eo=average dry sludge charging rate during the ran, kg/hr (English units: lu,", ).
Rov=average quantity of dry sludge per unit volume ot sludge charged to the Incinerator, mc/I (English
units: lb/ft«).
iSv-sludge charged to the incinerator during the run, m» (English units: gal);
T=duration of run, min (English units: mill).
60Xl(H=rnetric units conversion factor, l-kg-min/m»-mg-hr.
8.021English units conversion factor, ft»-min/gal-hr.
(ii) If the mass of sludge charged is used:
SD=(50) Rp^S.M (Metric or English Units)
where:
6D=average ary sludge charging rate during the run, kg/hr (English units: .Jb/hr):
B»M=average ratio of quantity ol dry sludge to quantity of sludge charged to the incinerator, mg/mg (English
units: Ib/lb).
8M>=sIudge charged during the run, kg (English units: Ib).
T=dnration of run, tnln (Metric or English units).
80=eonversion factor, min/hr (Metric or English units).
(d) Particulate emission rate shall be determined by:
c"W=c8Qs (Metric or English Units)
where:
c"=particulate matter mass emissions, mg/hr (English units: Ib/hr).
c'=particulate matter concentration, mg/m' (English units: Ib/dscf).
Q"= volumetric stack gas flow rate.-dsem/hr (English units: dscfyhr).
-------
9320
RULES AND REGULATIONS
tiring In the 0 to 100 ppm range. Interference
ratios can be as high as 3.5 percent H,O per
25 ppm CO and 10 percent CO, per 50 ppm
CO. The use of silica gel and ascarlte traps
will alleviate the major Interference prob-
lems. The measured gas volume must be
corrected If these traps are usedi-
4. Precision and. accuracy.
4.1 Precision. Tne precision of most NDIR
analyzers Is approximately ±2 percent of
span.
4.2 Accuracy. The accuracy of most NDIR
analyzers Is approximately ±5 percent of
span after calibration.
5. Apparatus.
6.1 Continuous sample (Figure 10-1).
5.1.1 Probe. Stainless steel or sheathed
Pyrex»glass, equipped with a filter to remove
particulate matter.
5.1.2 Air-cooled condenser, or equivalent.
To remove any excess moisture.
C.2 Integrated sample (Figure 10-2).
5.2.1 Probe. Stainless steel or sheathed
Pyrex glass, equipped with a filter to remove
particulate matter.
6.2.2 Air-cooled condenser or equivalent.
To remove any excess moisture.
5.2.3 Valve. Needle valve, or equivalent, to
to adjust flow rate.
52.4 Pump. Leak-free diaphragm type, or
equivalent, to transport gas.
5.2.5 Bate meter. Botameter, or equivalent,
to measure ft flow range from 0 to 1.0 liter
per mln. (0.035 cfm).
6.2.6 Flexible bag. Tedlar, or equivalent,
with a capacity of 60 to 90 liters (2 to 3 f t«).
Leak-test the bag In the laboratory before
using by evacuating bag with a pump fol-
lowed by a dry gas meter. 'When evacuation
Is complete, there should be no flow through
the meter.
AM-COCUD CONDENSE*
WOK
TOWUUza
5.3.1 Carbon monoxide analyzer. Nondlsper-
sive infrared spectrometer, or equivalent.
This Instrument should be demonstrated,
preferably by the manufacturer, to meet or
exceed manufacturer's specifications and
those described in- this method.
5.3.2 Drying tube. To- contain approxi-
mately 200 g of silica gel.
5.3.3 Calibration gas. Refer to paragraph
6.1.
53.4 Filter. As recommended by NDIR.
manufacturer.
5.3.5 CO, removal tube. To contain approxi-
mately 500 g of ascarlte.
6.3.6 Ice water bath.. For ascarlte and silica
gel tubes.
5.3.7 Valve. Needle valve, or equivalent, to
adjust flow rate
63.8 Sate meter. Botameter or equivalent
to measure gas flow rate of 0 to 1.0 liter per
rain. (0.035 cfm) through NDIR.
6.3.9 Recorder (optional). To provide per-
manent record of NDIR readings,
6. Reagents.
6.1 Calibration gases. Known concentration
of CO in nitrogen (N,) for Instrument span,
prepurtfled grade of N> for zero, and two addi-
tional concentrations corresponding approxi-
mately to 60 percent and 30 percent span. The
span concentration shall not exceed 1.6 times
the applicable source performance standard.
The calibration gases shall be certified by
the manufacturer to be within ±2 percent
of the-specified concentration.
6.2 Sitiea gel. Indicating type, 6 to 16 mesh,
dried at 175° C (347« F) for 2 hours.
6.3 Ascarite. Commercially available.
1. Procedure.
7.1 Sampling.
7.1.1 Continuous sampling. Set up the-
equipment as shown. In Figure 10-1 making
sure all connections are leak free. Place the
probe in the stack at a sampling point and,
purge the sampling line. Connect the ana-
lyzer and begin drawing sample into the
analyzer. Allow 5 minutes for the system
to stabilize, then record the analyzer read-
ing as required by the test procedure. (See
t 72 and 8).-CO> content of the gas may be
determined by using the Method 3 Inte-
grated sample procedure (36 FR 24886), or
by weighing the ascarite CO, removal tube
and computing CO, concentration from the
gas volume sampled and the weight gain
of the tube.
7.12 Integrated sampling. .Evacuate the
flexible bag. Set up the equipment as shown
in Figure 10-2 with the bag disconnected.
Place the probe In the stack and purge the
sampling line. Connect the bag. making sure
that all connections are leak free. Sample at
a rate proportional to the stack velocity.
CO, content of the gas may bo determined
by using the Method 3 integrated sample-
procedures (30 FR 24886), or by weighing
the ascarite CO2 removal tube and comput-
ing CO., concentration from the gas volume
sampled and the weight gain of the tube.
12 CO Analysis. Assemble the apparatus a»
shown in Figure 10-3, calibrate the instru-
ment, and perform other required operations
as described in paragraph 8. Purge analyzer
with Na prior to Introduction, of each sample.
Direct thfe sample stream through the Instru-
ment for the test period, recording tlift read-
ings. Check the zeio and span again after the
test to assure that any drift or malfunction
is detected. Record the sample data on Table
10-1.
8. Calibration. Assemble the apparatus ac-
cording to Figure 10-3. Generally an instru-
ment requires a warm-up period before sta-
bility is obtained. Follow the manufacturer's
Instructions for specific procedure. Allow a
minimum tune of one hour for warm-up.
During this time check the sample condi-
tioning apparatus, i.e., filter, condenser, dry-
ing tube, and CO» removal tube, to ensure
that each component Is In good operating
condition. Zero and calibrate the Instrument
according to the manufacturer's procedures
using, respectively, nitrogen and the calibra-
tion gasee.
TABLE 10-1.Field Oattt
Clock time
Botameter setting, liters per minute
(cubic feet per minute)
52.7 Pttot tube. Type S, or equivalent, at-
tached, to the probe so that the sampling
rate can he regulated proportional to the
stack gas velocity when velocity is varying
with the time or a sample traverse is con-
ducted.
6.3 Analysis (Figure 10-3).
0. CalculationConcentration of carbon monoxide. Calculate the concentration of carboa
monoxide in the stack using equation 10-L.
where:
cco.Uok
equation 10-1
1 Mention of trade names or specific prod-
ucts does- not constitute endorsement by th«
Environmental Protection Agency.
Cco.w.k=concentration of CO In stack, ppm by volume (dry bads).
" concentration of-CO measured by NDIR analyzer, ppm by volume (dry
basis).
FCO»= volume fraction of C0» Is sample, Le., percent COt from Orsat analysto
divided by 10O.
KEDERAt REGISTER, VOL 39, NO. 47FRIDAY, MARCH >, 1974
IV-4 2
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RULES AND REGULATIONS
9321
10. Bibliography.
10.1 McElroy, Prank, The Intertech NDIR-CO
Analyzer, Presented at llth Methods
Conference on Air Pollution, University
ol California, Berkeley, Calif, April 1,
1970.
10.2 Jacobs, M. B., «t til., Continuous -Deter-
mination of Carbon Monoxide and Hy-
drocarbons In Air by a Modified Infra-
red Analyzer, J. Air Pollution Control
Association, 9(2) :110-114, August 1959.
10.3 MSA LIRA Infrared Gas and Liquid
Analyzer Instruction Book, Mine Safety
Appliances Co., Technical Products Di-
vision, Pittsburgh, Pa,
10.4 Models 215A, 315A, and 415A Infrared
Analyzers, Beck-man Instruments, Inc.,
Beckman Instructions 1635-B, Fuller-
ton, Calif., October 1967.
10.5 Continuous CO Monitoring System,
Model A5611, Intevtech Corp., Princeton,
NJ.
10.6 UNOR Infrared Gas Analyzers, Bendix
Corp., Ronceverte, West Virginia,
ADDENDA
A.. Performance Specifications -for NDIR Carbon Monoxide Analyzers.
Range (minimum) 0-lOOOppm,
Output (minimum) 0-10mV
Minimum detectable sensitivity 20ppm.
Rise time, 90 percent (max!mum) 30seconds.
Fall time. 90 percent (maximum) 30 seconds.
Zero drift (maximum) * 10% In 8 hours.
Span drift (maximum) 10% In 8 hours.
Precision (minimum) -± 2% of full scale.
Noise (maximum) ± 1 % of full scale.
linearity (maximum deviation) 2 % of full scale.
Interference rejection ratio.- COs1000 to 1, H2O500 to 1.
B. Definitions of Performance Specifica-
tions.
RangeThe minimum and maximum
measurement limits.
OutputElectrical jignal which lJ propor-
tional to the measurement; Intended for con-
nection to readout or data processing devices.
Usually expressed as millivolts or milliamps
full scale at a given impedance.
Full scaleThe maximum measuring limit
for a given range.
Minimum detectable sensitivityThe
smallest amount of input concentration that
can be detected as the concentration ap-
proaches zero.
AccuracyThe degree of agreement be-
tween a measured value tind the true value;
usually expressed as ± percent of full scale.
Time to 90 percent responseThe time in-
terval from a step change in the input con-
centration at the instrument inlet to a read*
Ing of 90 percent of the ultimate recorded
concentration.
Rise Time {90 percent)The Interval be-
tween initial response time and time to 90
percent response after a step increase in the
inlet concentration.
Fall Time (90 percent)The interval be-
tween initial response time and time to 90
percent response after a step decrease In the
inlet concentration.
Zero DriftThe change in instrument out-
put over a stated time period, usually 24
hours, of unadjusted continuous operation
when the input concentration is zero; usually
expressed as percent full scale.
Span DriftThe change in instrument out-
ptit over a stated time period, usually 24
hours, of unadjusted continuous operation
when the input concentration is a stated
upscale value; usually expressed as percent
full scale.
PrecisionThe degree of agreement be-
tween repeated measurements of the same
concentration, expressed as the average de-
viation of the single results from the mean.
NoiseSpontaneous deviations from a
mean output not caused by input concen-
tration changes.
LinearityThe maximum deviation be-
tween an actual Instrument reading and the
reading predicted by a straight line drawn
between upper and lower calibration points.
MCTHOO 11 DETERMINATION OT HYDROGEN -SUI,-
TIDE EMISSIONS FROM STATIONARY SOURCES
1. Principle and applicability.
1.1 Principle. Hydrogen sulfide (H2S) is
collected from the source in a series of midget
impingers and reacted with alkaline cad-
mium hydroxide [Cd(OH)s] to form cad-
mium sulfide (CdS). The precipitated CdS
is then dissolved in hydrochloric acid and
absorbed in a known volume -of iodine solu-
tion. The iodine consumed is a measure of
the HjS content of the gas. An impinger con-
taining hydrogen peroxide is included to re-
move SO, as an interfering species.
12 Applicability. This method is applica-
ble for the determination of hydrogen sul-
fide emissions from stationary sources only
when specified by the test procedures for
determining compliance with the new source
performance standards.
2. Apparatus.
2.1 Sampling train.
2.1.1 Sampling line{>- to 7-mm (%-inch)
Teflona tubing to connect sampling train to
sampling valve, with provisions for heating
to prevent condensation. A pressure reduc-
ing valve prior to the Teflon sampling line
may be required depending on sampling
stream pressure.
2.1.2 ImpingersFive midget impingers,
-each with 30-mI capacity, or equivalent.
2.1.3 Ice bath containerTo maintain ab-
sorbing solution at a constant temperature.
2.1.4 Silica gel drying tubeTo protect
pump and dry gas meter.
2.1.5 Needle valve, or equivalentStainless
steel or other corrosion resistant material, to
adjust gas flow rate.
2.1.6 PumpLeak free, diaphragm type, or
equivalent, to transport gas. (Not required
if sampling stream under positive pressure.)
2.1.7 Dry gas meterSufficiently accurate
to measure sample volume to within 1 per-
cent.
2.1.8 Rate meterHotameter, or equivalent,
to measure a flow rate of 0 to 3 liters per
minute (0.1 ft'/mln).
2.1.9 Graduated cylinder25 ml.
2.1.10 BarometerTo measure atmospheric
pressure within ±2.5 mm (0.1 In.) Hg
23 Sample Recovery.
2.2.1 Sample container500-ml glass-stop-
pered iodine flask.
2.2.2 Pipette50-ml volumetric type.
2.2.3 Beakers250 ml.
2.2.4 Wash bottleGlass.
2.3 Analysis.
2.3.1 Flask500-ml glass-stoppered iodine
flask.
1 Mention of trade names or specific prod-
ucts does not constitute endorsement by th«
Environmental Protection Agency.
2.3.2 BuretteOne 50 ml.
2.3.2 Flask125-ml conical.
3. Reagents.
3.1 Sampling.
3.1.1 Absorbing solutionCadmium hy-
droxide (Cd(OH).,)Mix 4.3 g cadmium sul-
fate hydrate (3 CdSOj.BHjO) and 0.3 g ol
sodium hydroxide (NaOH) in 1 liter of dis-
tilled water (H.O). Mix well.
Note: The cadmium hydroxide formed in
this mixture will precipitate as a.white sus-
pension. Therefore, this solution must be
thoroughly mixed before using to ensure an
even distribution of the cadmium hydroxide.
3.1.2 Hydrogen peroxide, 3 percentDilute
30 percent hydrogen peroxide to 3 percent
as needed. Prepare fresh dally;
3.2 Sample recovery.
3.2.1 Hydrochloric acid «olution <{HCl), JO
percent by weightMix 230 ml of concen-
trated HC1 (specific gravity 1.19) andT70 ml
of distilled R,O.
3,2.2 Iodine solution, 01 NDissolve 24 g
potassium iodide (KI) in 30 ml of distilled
H»O In a 1-liter graduated cylinder. Weigh
12.7 g of resublimed iodine (I2) into a weigh-
ing bottle and add to the potassium iodide
solution. Shake the mixture until the iodine
is completely dissolved. Slowly dilute the -so-
lution to 1 liter -with distilled H2O, with
swirling. Filter the solution, if cloudy, and
store in a brown glass-stoppered bottle.
3.2.3 Standard iodine solution, 0.01 NDi-
lute 100 ml of the 0.1 N iodine solution in a
volumetric flask to 1 liter with -distilled
water.
Standardize daily as follows: Pipette 25 ml
of the 0.01 N iodine solution Into a 125-ml
conical flask. Titrate with standard 0.01 N
thiosulfate solution (see paragraph 3.32) un-
til the solution is a light yellow. Add a few
drops of the starch solution and continue
titrating until the blue color Just disap-
pears. From the .results of this titration, cal-
culate the exact normality of the iodine
solution (seeparagraph S.I).
3.2.4 Distilled, deionized water,
3.3 Analysis.
3.3.1 Sodium thiosulfate solution, standard
OJ. NFor each liter of solution, dissolve
24.8 g of sodium thiosulfate (NA^O, 5H..O)
in distilled water and add 0.01 g of anhydrous
sodium carbonate (Na2CO,) «nd 0.4 ml of
chloroform (CHC13) to stabilize. Mix thor-
oughly by shaking or by aerating with nitro-
gen for approximately 15 minutes, and «tore
in a glass-stoppered glass bottle.
Standardize frequently as follows: Weigh
into a 500-ml volumetric flask about 2 g of
potassium dichromate (K.CTjO7) weighed
to the nearest milligram and dilute to the
500-ml mark with distilled HjO. Use di-
chromate which has been crystallized from
distilled water and oven-dried at 182°C to
199°C (360"F to 390'F). Dissolve approxi-
mately 3 g of potassium iodide (KI) in 50 ml
of distilled water In a glass-stoppered, 500-ml
conical flask, then add 5 ml of 20-percent
hydrochloric acid solution. Pipette 50 ml of
the dichromate solution Into this mixture.
Gently swirl the solution once and allow it
to stand in the dark for 5 minutes. Dilute
the solution with 100 to 200 ml of distilled
water, washing down the sides of the flask
with part of the water. Swirl the solution
slowly and titrate with the thoisulfate solu-
tion until the solution is light yellow. Add
4 ml of starch solution and continue with a
slow titration with tie thiosulfate until the
bright blue color has disappeared and only
the pale green color of the chromic Ion re-
mains. From thlE titration, calculate the ex-
act normality of the sodium thiosulfate solu-
tion (see paragraph 5.2).
3.3.2 Sodium thiosulfate solution, standard
0.01 NPipette 100 ml of the standard O.I N
thiosulfate solution into a volumetric flask
and dilute to one liter with distilled water.
FEDERAL REGISTER, VOL 39, NO. 47FRIDAY, MARCH t, 1974
IV-4 3
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9322
RULES AND REGULATIONS
3.3.3 Starch indicator solutionSuspend
10 g of soluble starch In 104 ml of distilled
water and acid 15 g of potassium hydroxide
pellets. Stir until dissolved, dilute with 900
ml of distilled water, and let stand 1 hour.
Neutralize the alkali with concentrated hy-
drochloric acid, using an Indicator paper
similar to Alkacid test ribbon, then add 2 ml
of glacial acetic acid as a preservative.
Test for decomposition by titrating 4 ml of
starch solution In 200 ml of distilled water
with 0.01 N Iodine solution. If more than 4
drops of the 0.01 N Iodine solution are re-
quired to obtain the blue color, make up a
fresh starch solution.
4. Procedure.
4.1 Sampling.
4.1.1 Assemble the sampling train as shown
in Figure 11-1, connecting the five midget
imptngers In series. Place 15 ml of 3 percent
hydrogen peroxide in the first impinger. Place
15 ml of the absorbing solution In each of
the next thre« Impingers, leaving the filth,
dry. Place crushed Ice around the Impingers.
Add more ice during the run to keep the
temperature of the gases leaving -the last
impinger at about 20°C (70"F), or less.
4.1.3 Purge the connecting line between
the sampling valve and the first Impinger.
Connect the sample line to the train. Record
the initial reading on the dry gaa meter as
shown in Table 11-1.
CBM
FlgnlM. HzS ttnplln) Kltt.
TABLE 11-1.Field data
Location Comments:
Test .
Date
Operator
Barometric pressure-
Clock
time
Gas voluma
through
meter (Vm),
liters (cubic
feet)
Botameter
setting, Lpm
(cubic feet
per minute)
Meter
temperature,
C (° F)
4.1.3 Open the flow control valve and ad-
just the sampling rate to 1.13 litera per
minute (0.04 cfm). Bead the meter temper-
ature and record on Table 11-1.
4.1.4 Continue sampling a minimum of 10
minutes. If the yellow color of cadmium sul-
flde is visible In the third Impinger, analysis
should confirm that the applicable standard
has been exceeded. At the end of the sample
time, 'cloee the flow control valve and read
the final meter volume and temperature.
4.1.5 Disconnect the impinger tram from
the sampling line. Purge the train with clean
ambient air for 15 minutes to ensure that all
H.S is removed from the hydrogen peroxide.
Cap th» open ends and move to the sample
clean-up area.
4.3 Sample recovery.
4.2.1 Pipette 50 ml of 0.01 N iodine solution
into a 250-ml beaker. Add 50 ml of 10 percent
HC1 to the solution. Mix well,
45.2 Discard the contents of the hydrogen
peroxide Impinger. Carefully transfer the con-
tents of the remaining four impingers to a
500-ml Iodine flask.
4.2.3 Rinse the four absorbing impingers
and connecting glassware with three portions
of the acidified iodine solution. Use the en-
tire 100 ml of acidified iodine for this pur-
pose. Immediately after pouring the acidified
iodine into an impinger, stopper it and shake
for a few moments before transferring the
rinse to the iodine flask. Do not transfer any
rinse portion from one impinger to another;
transfer it directly to the iodine flask. Onc«
acidified Iodine solution has been poured into
any glassware containing cadmium sulfide
sample, the container must be tightly stop-
pered at all times except when adding more
solution, and this must be done as quickly
and carefully as possible. After adding any
acidified iodine solution to the iodine flask,
allow a few minutes for absorption of the H,S
Into the iodine before adding any further
rinses.
4.3.2 ntrat* the blanks in the same ma.n-
ner as t he samples.
4 2.4 Tollow this rinse with two more rinses
using distilled water. Add the distilled water
rinses to the iodine flask. Stopper the flask
and shake well. Allow about 30 minutes for
absorption of the HS Into the Iodine, then
complex the analysis titratlon.
Cautum: Keep the iodine flask stoppered
except when adding sample or titrant.
425 Prepare a blank in &u iodine flask
using 45 ml of the absorbing solution, 50 ml
of 0.01 N iodine solution, and 50 ml of 10
percent HC1. Stopper the flask, shake well
and analyze with the samples.
4.3 Analysis.
Note: This analysis titratton, should be
conducted at the sampling location in order
to pre pent loss of iodine from the sample.
Titration should never be made in direct
sunlight.
4.3.1 Titrate the solution la the flask with
0.01 N sodium thiosulfate solution, until the
solution is light yellow. Add 4 ml of the
starch indicator solution and continue
titrating until the blue color just disappears.
5. Calculations.
5.1 Normality of the standard iodine solution.
where:
NI
equation 11-1
normality of iodine, g-eq/liter.
i= volume of Iodine used, ml.
NT= normality of sodium thiosulfate, g-eq/iiter.
VT volume of sodium thiosulfate used, ml.
6.2 Normality of the standard thiosulfate sulution.
where:
W= weight of K}Cra07 used, g.
VT volume of NaiSjOs used, ml.
/Vr= normality of standard thiosulfate solution, g-eq/liter.
2.04=conversion factor
_(6 eq Jj/mole gaCr207) (1,000 ml/1)
equation 11-2
(294.2 g £jOjO./mole) (10 aliquot factor).
5.3 Dry gas volume. Correct the sample volume measured by the dry gas meter to
standard conditions [21°C(70°F)1 and 760 mm (29.92 Inches) Hg] by using equation 11-3.
3W (F^>
equation 11-3
where i
Vrajtd= volume at standard conditions of gas sample through the dry gas meter,
standard liters (scf).
Vm volume of gas sample through the dry gas meter ^meter conditions), litera
(cu. ft.).
3*i id absolute temperature at standard conditions, 294<>K (530°H).
Tm= average dry gas meter temperature, °K (°R).
PH, barometric pressure at the orifice meter, mm Hg On. Hg)..
P.td=absolute pressure at standard conditions, 760 mm Hg (29.92 in. Hg).
5.4 Concentration of H2S. Calculate the concentration of H2S in the gaa stream at
standard conditions using equation 11-4)
where (metric units):
CH,8=concentration of H2S at standard conditions, mg/dscn?
Byconversion factor=17.0X103
(34.07 g/mole HiS)( 1,000 I/M»)( 1,000 mg/g)
~ (1,000 ml/l)(2HaS eq/mole)
Vj=volume of standard iodine solution, ml.
Njnormality of standard iodine solution, g-eq/liter.
Vf= volume of standard sodium thiosulfate solution, ml,
)Vj-normality of standard sodium thiosulfate solution, g-cq/litet,
F«.itd = dry gas volume at standard conditions, liters.
FEDERAL REGISTER, VOL 39, NO. 47FRIDAY, MARCH 8, 1974
ry-44
-------
RULES AND REGULATIONS
93Z3
where (Engllrfi units):
17.0(15.43 gr/s)
" (1,000 l/m»
K=0.263=
CH,s=gr/dscf.
6. References.
ft.l Determination of Hydrogen Sulfide, Ammoniacal Cadmium Chloride Method,
API Method 772-54. In: Manual on Disposal of Refinery Wastes, Vol. V: Sampling
and Analysis of Waste Gases and Particulate Matter, American Petroleum Institute,
Washington, D.C., 1954.
6.2 Tentative Method for Determination of Hydrogen Sulfide and Mercaptan Sulfur
In Natural Gas, Natural Gaa Processors Association, Tulsa, Oklahoma, NGPA Publi-
cation No. 2265-65, 1965.
[PR Doc.74-4784 Filed 3-7-74:8:45 am]
FEDERAL REGISTER, VOL 3*. NO. 47MOAT, MAKCH ». 1974
No. 47Pt.n-
0 .RULES AND REGULATIONS
Title 40Protection of Environment
CHAPTER IENVIRONMENTAL
PROTECTION AGENCY
SU3CHAFTER CAIR PROGRAMS
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Additions and Miscellaneous Amendments
Correction
In PR Doc. 74-4784 appearing at page
9307 as the Part n ol the issue of Friday,
March 8, 1974, make the following
changes:
1. After the last line of 160.111 (e). in-
sert "carbon and hydrogen".
2. In the second, column on page 9317,
what is now designated as "§ 61.112
Standard for hydrocarbons", should read
"§ 60.112 Standard lor hydrocarbons".
3. In the second line of § 60.121 Cc), the
word "allows" should read "alloys",
4. In §60.154:
a. In the last line of the formula in
paragraph (c)<3)U), "ft"' should read
"ft"'.
b. In the first line of the formula in
paragraph (c) (3) (ii), "SD= (50>" should
read"SD=(60)".
c. The formula in paragraph (d)
should read as follows:
(Metric Units)
or
SD.
(English Units)
where:
Cd.=particulate emission- discharge,
g/kg dry sludge (English units:
Ib/ton dry sludge).
10~s= Metric conversion factor, g/mg.
2000= English conversion factor, lb/
ton.
5. On page 9320, under paragraph 9.
CalculationConcentration of carbon
monoxide, in the second equation
Tinder "where" ""CO.-*" should read
6. In the third column on page 9321,
in the ninth line from the bottom of
paragraph two under "3.3.1 Sodium thi-
osulfate solution, standard 0.1 N", "thoi-
suHate" should read "thlosulf ate".
7. In the third column on page 9322,
paragraph "4.3.2" should be transferred
to appear below paragraph "4.3.1".
8. In paragraph 5.2 on page 9322, the
last word "sulution" should read "solu-
tion".
9. In- the formula on page 9323, put a
closed parenthesis after "m"\
FEDERAL REGISTER, .VOL- 39, NO. 75WEDNESDAY, APRIL 17, 1974
IV-45
-------
RUtES AND REGULATIONS
7 Title 40-Protection of Environment
CHAPTER IENVIRONMENTAL
PROTECTION AGENCY
SUBCHAPTEH CAIR PROGRAMS
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Additions and Miscellaneous Amendments
Correction
In PK Doc. 74-4784 appearing at page
9307 as the Part U of the issue of Friday,
March 8, 1974, and corrected on page
13776 in the issue of Wednesday,
April 17,1974, on page 13776, "paragraph
c." should read as follows:
c. The formula in paragraph (d)
should read as follows:
(d) Particulate emission rate shall be
determined by:
c«»=C3 Qa (Metric or English. Units)
where:
e«« = Particulate matter mass emissions,
mg/hr (English units: lb/hr).
c«=Partlculate matter concentration,
mg/m-' (Ecgllsh units: Ib/dscf).
Qa=Volumetric stack gas flow rate.
dscm/hr (English units: dscf/hr).
Qu and ca shall be determined using
Methods 2 and 5, respectively.
FEDERAL REGISTER, VOL 39, NO. 87FRIDAY MAY 3, 1974
8 SUBCHAPTER C-AIR PROGRAMS
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Miscellaneous Amendments
On December 23.1971 (33 FR 24875).
^pursuant to section. Ill of the dean Air
Act, as amended, the Administrator
promulgated subpart A, General Provi-
sions, and subparts D. E, F. O, and H
which set forth standards of performance
for new and modified facilities within
five categories of stationary sources: (l)
Fossil fuel-fired steam generators, (2)
Incinerators, (3) Portland cement plants,
(4) nitric acid plants, and (5) sulfuric
acid plants- Corrections to these stand-
ards were published on July 26,1972 (37
FR 14877), and on May 23* 1973 (38 FR
13562). On. October 15, 1973 (38 FR
28564), the Administrator amended sub-
part A, General Provisions, by adding
provisions to regulate compliance with
standards of performance during startup,
shutdown, and malfunction. On March 8.
1974 (39 FR 9308), the Administrator
promulgated Subparts X, J, K, L, M, N,
and O which, set forth standards of per*
formance for new and modified facilities
within seven, categories of stationary
sources: (1) Asphalt concrete plants, (2)
petroleum refineries, (3) storage vessels
for petroleum, liquids, (4) secondary
lead smelters, (5) brass and bronze ingot
production plants, (6) Iron and steel
plants, and (7) sewage treatment plants.
In the same publication, the Administra-
tor also promulgated amendments to
subpart A, General Provisions. Correc-
tions to these standards were published.
on April 17, 1974 (39 FR 13776).
Subpart D, E. P, G>, and H are revised
below to be consistent with the October
15,1973, and March 8,1974, amendment1}
to subpart A. At the same time, changes
In wording are made to clarify the regu-
lations. These amendments do not mod-
ify the control requirements of the
standards of performance. Also, to be
consistent with the Administrator's pol-
icy of converting to the metric system,
the standards of performance and other
numerical entries, which were originally
expressed in. English units, are converted
to metric units. Some of the numerical
entries are rounded after conversion to
metric units. It should be noted that the
numerical entries in the reference
methods in the appendix win be changed
to metric units at a later date.
The new source performance standards
promulgated March 8.. 1974, applicable
to petroleum storage vessels, Included
within their coverage storage vessels in
the 40,000 to 65,000 gallon size range.
The- preamble to that publication dis-
cussed the fact that vesrtJs of that si7.h
had not been included in the proposed
rule, and set forth the reasons for their
subsequent Inclusion. However, through
oversight, nothing was set forth in the
regulations or preamble prescribing the
effective date of the standards as to
vessels within the 40,000 to 65,000 gallon
range.
Section 111 (a) (2) of the Act specifies
that only a source for which construc-
tion la commenced after the date on
which a pertinent new source standard
is prescribed is subject to Jhe standard
unless the source was covered by the
standard aa proposed. In this case, the
date of prescription or promulgation of
the standard Is clearly the operative date
since there was no proposal date. Ac-
cordingly, J 60.1 is amended below to
conform to the language of section 111
(a) (2), and all persons are advised
hereby that the provisions of Fart 60
FEDERAL REGISTER, VOL 39. NO- II*flUDAYT JUttt 14, 1»74
IV-4 6
-------
RULES AND REGULATIONS
20791
promulgated March 8, 1974, apply to
storage vessels for petroleum liquids tn
the 40,000 to 65,000 gallon size range for
which construction Is commenced on or
after that date.
On March 8,1974, S 60.7(d) was added
to require owners and operators to re-
tain all recorded information, Including
monitoring and performance testing
measurements, required by the regula-
tions for at least 2 years after the date
on which the Information was recorded.
This requirement Is therefore deleted
from Subparts D, E, F, Q, and H specific
to each new source In this group to avoid
repetition. On March 8,1974, the defini-
tions of "partlculate matter" and "run"
were added to ! 60.2". Therefore the defi-
nition of "particular matter" Is removed
from Subparts D, E. F. G, and H, and
the term "repetition," used In these sub-
parts In sections pertinent to perform-
ance tests, Is changed to "run."
On October 16,1973, f 60.8(c) was re-
vised to require that performance tests
be conducted under conditions specified
by the Administrator based on represent-
ative performance of the affected fa-
cility. For that reason, the sections In
Subparts D, E, F, G. and H specifying
operating conditions to be met during
performance tests are deleted.
Sections 60.40. 60.41 (b) and 60.42 (a)
(1) are revised to clarify that the per-
formance standards for steam generators
do not apply when an existing unit
changes to accommodate the use of com-
bustible materials other than fossil fuel
as defined In { 60.41 (b).
Sections 60.41 (a) and 60.51(a) are re-
vised to eliminate the requirement that a
unit have a "primary" purpose. This
change is Intended to prevent circum-
vention of a standard by simply denning
the primary purpose of a unit as some-
thing other than steam production or
reducing the volume of solid waste.
In I 60.46, AJS.TJM. Methods D2015-
66 (Reapproved 1972), D240-64 (Heap-
proved 1973), andD1826-64 (Reapproved
1970) are specified for measuring heat-
ing value. Prior to this issue no method
was specified lor determining heating
value.
The phrase "maximum 2-hour aver-
age" in the standards of performance
prescribed in S§ 60.42. 60.52, 60.62, 60.72,
and 60.82 is deleted. Concurrently, in
§§ 60.46, 60.54, 60.64, and 60.85 the sam-
pling time requirements for particulate
matter and acid mist are changed from a
minimum of 2 hours to a minimum of 60
minutes per run. The phrase "maximum
2-hour average" is not consonant with
§ 60.8(f) which requires that compliance
be determined by averaging the results of
three runs. Results from performance
tests conducted at power plants and
other sources have not shown any de-
crease in the accuracy or precision of
1-hour samples as compared with 2-hour
samples, and therefore the extra hour
required to sample for 2 hours Is not
justified. The time Interval between sam-
ples for sulfur dioxide and nitrogen
oxides was originally established so that
one run would be completed at approx-
imately the same time as the particulate
matter run. To maintain this relation-
ship, the sampling intervals specified in
SS 60.46 and 80.74 are shortened to be
consistent with the 60-mlnute-per-run
requirement.
The requirement prescribed in { { 60.46.
60.64, 60.74 and 60.85 for using "suit-
able flow meters" for measuring fuel and
product flow rates Is deleted. Such meters
may be used If available, but other suit-
able methods of determining the flow
rate of fuel or product during the test
period may also be used.
A procedure specifying how to allow for
carbon dioxide absorption in a wet scrub-
ber and a formula for correcting par-
ticulate matter emissions to a basis of
12 percent CO, are added to { 60.54.
In anticipation of adding other ap-
pendices, the present appendix to Part
60 is being retitled "Appendix ARefer-
ence Methods." The definitions of "ref-
erence method" and "partlculate matter"
are amended to be consistent with this
change.
In the regulations tn Subpart K set-
ting forth the performance standard for
storage vessels for petroleum liquids, the
definition of "crude petroleum" was to
have been changed to be consistent with
the definition of "petroleum" In Subpart
J. This change was Inadvertently not
made in 39 FR 9308 and thus {{ 60.110
and 60.111 are amended by replacing
the term "crude petroleum" with
"petroleum."
The remaining structural and word-
ing changes are made for purposes of
clarification.
On June 29, 1973, the U.S. Court of
Appeals for, the District of Columbia re-
manded to EPA for further consideration
the new source performance standards
for Portland cement plants. Portland
Cement Association v. Ruckelshaus, 486
F.2d 375. On September 10, 1973, the
same Court remanded to EPA for fur-
ther consideration the new source per-
formance standards for sulfuric acid
plants and coal-fired steam electric gen-
erators. Essex Chemical Co. v. Ruckels-
haus, 486 F.2d 427. The Agency has not
completed Its consideration with respect
to the remanded standards. These
amendments are not Intended to constl~
tute a response to the remands. At the
time the Agency completes its considera-
tion with respect to the remanded stand-
ards, it will publicly announce its deci-
sion and at that time if any revisions of
the standards are deemed necessary or
desirable, will make such revisions.
These actions are effective on June 14,
1974. The Agency finds good cause exists
for not publishing these actions as a no-
tice of proposed rulemaking and for
making them effective immediately upon
publication for the following reasons:
1. These actions are intended for clar-
ification and for maintaining consistency
throughout the regulations. They are not
intended to alter the substantive con-
tent of the regulations.
2. Immediate effectiveness of the ac-
tions enables the sources involved to pro-
ceed with certainty hi conducting their
affairs, and persons wishing to seek ju-
dicial review of the actions may do to
without delay.
<43 UJB.C. 1867 («) («) «ad (6))
Dated: June 10,1974.
JOHN QVAULES,
Acting Administrator*
Part 60 of Chapter I. Title 40 of the
Code of Federal Regulations Is amended
as follows:
1. Section 60.1 Is revised to read as
follows:
g 60.1 Applicability.
The provisions of this part apply to
the owner or operator of any stationary
source which contains an affected fa-
cility the construction or modification of
which Is commenced after the date of
publication in this part of any standard
(or, If earlier, the date of publication of
any proposed standard) applicable to
such facility.
2. Section 60.2 Is amended by revising
paragraphs (s) and (v) as follows:
§ 60.2 Definitions.
*
(s) "Reference method" means any
method of sampling and analyzing for
an air pollutant as described in Ap-
pendix A to this part.
*
(v) "Particulate matter" means any
finely divided-solid or liquid material,
other than unoombined water, as meas-
ured by Method 5 of Appendix A to this
part or an equivalent or alternative
method.
3. Section 60.40 is revised to read as
follows:
§ 60.40 Applicability and designation of
affected facility.
The provisions of this subpart are ap-
plicable to each fossil fuel-fired steam
generating unit of more than 63 million
kcal per hour heat input (250 million Btu
per hour), which Is the affected facility.
Any change to an existing fossil fuel-
fired steam generating unit to accommo-
date the use of combustible materials,
other than fossil fuels as defined In this
subpart, shall not bring that unit under
the applicability of this subpart.
4. Section 60.41 is amended by deleting
"primary" in paragraph (a), revising
paragraph (b), and deleting paragraph
(c)'. As amended, § 60.41 reads as follows:
§ 60.41 Definitions.
" As used in this subpart, all terms not
defined herein shall have the meaning
given them in the Act, and In subpart A
of this part.
(a) "Fossil iuel-flred steam generat-
ing unit" means a furnace or boiler used
In the process of burning fossil fuel for
the purpose of producing steam by heafe
transfer.
(b) "Fossil fuel" means natural gas,
petroleum, coal, and any form of solid,
liquid, or gaseous fuel derived from such
materials for the purpose of creating use-
ful heat.
FEDERAL REGISTER, VOL. 39, NO. 11«FRIDAY, JUNE 14, 1974
IV-47
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20792
RULES AND REGULATIONS
5. Section 60.42 la revised to read as
follows;
§ 60.42 Standard for partienlate matter.
(a) On and after- the date on which
the performance test required to be con-
ducted by i 60.8 Is completed, no owner
or operator subject to the provisions of
this subpart shall cause to be discharged
Into the atmosphere from any affected
facility any gases which:
(1> Contain particulate matter in ex-
cess of 0.18 g per million cal heat input
(0.10 Ib per million Btu) derived from
fossil f ueL
(2) Exhibit greater than 20 percent
opacity except that a maximum of 40
percent opacity shall be permissible for
not more than 2 minutes in. any hour.
Where the presence of uncombined water
is the only reason for failure to meet the
requirements of this paragraph, such
failure will not be a violation of this sec-
tion.
6. Section 60.43 is revised to read as
follows:
(3) 1.26 g per million cal heat input
(0.70 Ib per million BtiO derived from,
solid fossil fuel (except lignite) .
(b> When different fossil fuels- are
burned simultaneously In any combina-
tion, the applicable standard shall be
determined by proratlon, Compliance
shall be determined by using the follow-
ing formula;
where:
x la the percentage of total beat Input de-
rived from gaseous fossil fuel.
y 1« the percentage of total heat input de-
rived from liquid fossil fuel, and
r U tixe percentage of total beat Input de-
rived from solid fossil, fuel (except
lignite).
§ 60.45 [Amended]
8. Section 60.45 Is amended by delet-
ing and reserving paragraph (f).
9. Section 60.46 is revised to read as
follows:
§60.43 Standard for «ulf« dkodd*. 8 60.46 Te* method. «id procedwes.
(a> On and after the date on which
the performance test required to be con-
ducted by ! 60.8 Is completed, no owner
or operator subject to the provisions of
this subpart shall cause to be discharged
into the atmosphere from any affected
facility any gases which contain sulfur
dioxide in excess of:
(1) --1.4 g per million cal heat taptrt
(0.80 Ib per million Btu) derived from
liquid fossil fuel.
(2) 2.2 g per million cal heat input
(1.2 Ib per million Btu) derived from
solid fossil fuel.
(b) When different fossil fuels are
burned simultaneously in any combina-
tion, the applicable standard shall be
determined by proration using the fol-
lowing formula:
3T( 1.4)+2(2.2)
y+*
where:
y is the percentage or total heat input de-
rived from liquid tosstt fu«», «ad
3 Is the percentage of total heat input de-
rived from solid fossil fueL
(c) Compliance shall be based on the
total heat input from all fossa fuels
burned. Including gaseous fuels,
7. Section 60.44 is revised to read a»
follows:
$ 6O.44 Standard for nitrogen oxides,
(a) On and after the date on which
the performance test required to be con-
ducted by S 60.a Is completed, no owner
or operator subject to the provisions of
this subpart shall cause to be discharged
into the atmosphere from any affected
facility any gases which, contain, nitro-
gen oxides, expressed as NO, In excess of:
(1) 0.36 g par million cal heat input
(0.20 Ib per minion Btu) derived from.
gaseous fossil fueL
(2) 0.54 g per million cal heat input
(030 Q> per mutton Bto> derived from.
liquid fond foei.
(a) The reference methods ta Ap-
pendix A to this part, except as provided
for In 5 60.8fb), shall be used to deter-
mine compliance with the standards
prescribed in §5 60.42, 69.43, and 60.44
as follows:
(1) Method 1 for sample and velocity
traverses;
(2) Method 2 for velocity and volu«
metric flow rate:
(3) Method 3 for gas analysis:
(4) Method 5 for the concentration of
particulate matter and the associated
moisture content;
(5) Method 6 for the concentrationr
ofSO>;and
(8) Method 7 for the concentration
ofNO».
(b> For Method 5, the sampling time
for each run shaH be at least 60 min-
utes and the minimum sample volume
shall be 0.85 dscm (30.0 dscf) except
that sm'tfler sampling toes or sample
volumes, when necessitated by process
variables or other factors, may be ap-
proved by the Administrator.
(c) For Methods 6 and 7, the sampling
site shall be the same as that for deter-
mining volumetric flow rate. The sam-
pling point in the duct shall be at the
centroid of the cross section or at a
point no closer to the waits than 1 m
(3.28 ft).
(d) For Method 6, the minimum sam-
pling time shall be 20 minutes and the
minimum sample volume, shall be 0.02
dscm (0.71 dscf) except that smaller
sampling times or sample volumes, when
necessitated by process variables or
other factors, may be approved by the
Administrator. The sample shall be ex-
tracted at & rate proportional to the gas
velocity at the sampling point. The
arithmetic average of two samples shall
constitute one run. Samples shall be
taken ^at approximately 30-minute
intervals.
(e) Par Method 7. each run shall con-
sist of st least four grab samples taken
at approximately 15-minute - intervals.
The- arithmetic mean of the samples
shall constitute the run values.
(f> Heat input, expressed in cai per
hr (Btu/hr), shall be determined dur-
ing each testing period by multiplying
the heating value of the fuel by the
rate of fuel burned. Heating value shall
be determined -in accordance with
AJS.T.M. Method D2015-66 (Reapproved
1972), D240-64 (Reapproved 1973), or
D1826-64 (Beapproved 1970>. The rate
of fuel burned during each testing period
shall be determined by suitable methods;
and shall be.confirmed by a material
balance over the steam generation
system.
(g) For each run, emissions expressed
in g/mUlion cal shall be determined b?
dividing the emission rate in g/hr by
the heat input. The emission rate shall
be determined by the equation g/hr
Qa x c where- Q9=volumetric flow rate
of the total effluent in dscm/hr as deter-
mined for each run in accordance with.
paragraph (a) (2) of this section.
(1) For particulate matter. c=partic-
ulate concentration in g/dscm. as deter-
mined in accordance with paragraph
(a) (4) of this section.
(2) For SOj. c=SOi concentration In
g/dscm, as determined in accordance
with paragraph (a} (5) of this section.
(3) For TTOx, cNOx concentration in
g/dscm, as determined to accordance
with paragraph (a) (8) of this section.
10. Section 60.50 is revised to read as
follows:
§ 60.50 Applicability- and designation of
affected facility.
The provisions of this subpart are ap-
plicable to each incinerator of more than
45 metric tons per day charging rate
(50 tons/day) which is the affected
facility.
§ 6O.51 [Amended]
11. Section 60.51 is amended by strik-
ing the word "primary" in paragraph
(a) and by deleting paragraph (d).
12. Section 60.52 is revised to read
as follows:,
§ 60.52 Standard for particnlate matter.
(a) On and after the date on whtch
the performance test required to be con-
ducted by § 60.8" is completed, no owner
or operator subject to the provisions of
this part shall cause to be discharged
into the atmosphere from any affected
facility any gases which contain par--
ticulate matter in excess of 0.18 g/dscm
(0.08 gr/dscf> corrected to 12 percent
CO*
13. Section. 60.53 Is revised to read as
follows:
§ 6O.53 Monitoring of operation*.
(a) The owner or operator of any in-
cinerator subject to the provisions of this
part shall record the daily charging rates
and hours of operation.
14. Section 60.54 is revised to read as
follows:
VOL, 39, NO. 116RH>AY^.JUNft 14. 1974
IV-4 8
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RUtES AND REGULATIONS
20793:
§ 60.54 Test methods and procedures.
(a) The reference methods In Ap-
pendix A to this part, except as provided
for in 160.8(h) f ghg11 be used to deter-
mine compliance with the standard, pre-
scribed in I 60.52 as follows:
(1) Method 5 for the concentration of
parfciculate matter and the associated
moisture content;
(2) Method 1 for sample and velocity
traverses;
(3) Method 2 for velocity and volu-
metric flow rate; and
(4) Method 3 for gas analysis and cal-
culation of excess air, using the inte-
grated sample technique.
" (hX For Method 5, the sampling time
for each run shall be at least 60 minutes
and the minimum sample volume shall
be 0.85 dscm (30.0 dscf) except that
smaller sampling times or sample vol-
umes, when necessitated by process vari-
ables or other factors, may be approved
by the Administrator.
(c) If a wet scrubber is used, the gas
analysis sample shaE reflect flue gas con-
ditions after the scrubber, allowing for
carbon dioxide absorption by sampling
the gas on the scrubber inlet and outlet
sides according to either ttie procedure
under paragraphs (c) (1) through (c) (5)
of this section or the procedure under
paragraphs (c)U), (c) (2) and (c) (6)
of this section as follows:
(1) The outlet sampling site shall be
the same as for the particulate matter
measurement. The inlet site shall be
selected according to Method 1, or as
specified by the Administrator.
(2) Randomly select 9 sampling points
within the cross-section at both the Inlet
and outlet sampling sites. Use the first
set of three for the first run, the second
set for the second run, and the third set
for the third ran.
(3) Simultaneously with each par-
ticulate matter run, extract and analyze
for CO, an integrated gas sample accord-
Ing to Method 3, traversing the three
sample points and sampling at each
point for equal increments of time. Con-
duct -the runs at both Inlet and- outlet
sampling srtes.
(4) Measure the volumetric flow rate
at the inlet during each particulate mat-
ter run according to Method 2, using the
full number of traverse points. For the
Inlet make two fuH velocity traverses ap-
proximately one hour apart during each
run and average the results. The outlet
volumetric flow rate may be determined
from the particulate matter run
(Methods).
(5) Calculate the adjusted CO, per-
centage using the following equation:
(% C0t)^j=(% C0i)« («*j/Q*0
where:
(% COi)t4j Is the adjusted COs percentage
which removes the effect of
CO, absorption and dilution
air,
(% CO,) « to the percentage of CO, meas-
ured before th« scrubber, dry
basis.
th» volumetric flow rate be-
lore the scrubber, average at
two runs, dscl/mln (using
Method 2), and
Qt<, is the volumetric flow rate after
the scrubber, dscf/mln (us-
ing Methods 2 and 5}
(6) Alternatively, the following pro-
cedures may be substituted for the pro-
cedures under paragraphs (c) (3), (4).
and (5) of this sections
(i) Simultaneously with each particu-
late matter run, extract and analyze for
CO3, O3, and N. an integrated gas sample
according to Method 3, traversing the'
three, sample points and sampling for
equal increments of time at each point.
Conduct the runs at both the inlet and
outlet sampling sites.
(ii) After completing the analysis of
the gas sample, calculate the percentage
of excess air ( % EA) for both the inlet
and outlet sampling sites using equation
3-1 in Appendix A to this part.
(iii) Calculate the adjusted CO, per-
centage using the following equation:
_
where:
(% CO,)i<) Is the adjusted outlet CO, per-
centage,
( % COa) *i Is the percentage of COs meas-
ured before the scrubber, dry
basis,
(% EA) i Is the percentage of excess air
at the Inlet, end
( % EA) o Is the percentage of excess air
at the- outlet.
(d) Particulate matter emissions, ex-
pressed in g/dscm, shall be corrected to
12 percent CO, by using the following
formula:
12c
C-n -
% CO,
where:
CM te the concentration of particuiatei
matter corrected to 12 percent
CO,,
c Ic the concentration of paxtlculat*
matter as measured by Method 5.
Rod
% CO, Is the percentage of CO* as meas-
ured by Method 3, or when ap-
plicable, the adjusted outlet OO»
percentage as determined by
paragraph, (c) of this section.
§ 60.61 [Amended!
15. Section 60.61 Is amended by delet-
ing paragraph (b).
16. Section 60.62 is revised to read as
follows:
§ 60.62 Standard for particulate matter.
(a) On and after the date on which.
the performance test required to be con-
ducted by I 60.8 is completed, no owner
or operator subject to the provisions of
this subpart shall cause to be discharged
into the atmosphere from any kiln any
gases which:
(1) Contain particulate matter in ex-
cess of 0.15 kg per metric ton of feed
(dry basis) to the kiln (0.30 Ib per ton) .
(2) Exhibit greater than 10 percent
opacity.
(b) On and after the date on which
the performance test required to be con-
ducted by § 60.8 is completed, no owner
or operator subject to the provisions of
this subpart shall cause to be discharged
into the atmosphere from any clinker
cooler any gases which:
(1) Contain particulate matter in ex-
cess of 0.050 kg per metric toa of feed
(dry basis) to the kiln (0.10 Ib per ton).
(2) Exhibit 10 percent opacity, or
greater.
(c) On and after the date on which
the performance test required to be con-
ducted by § 60.8 is completed, no owner
or operator subject to the provisions of
this subpart shall cause to be discharged
into the atmosphere from any affected
facility other than the kiln and clinker
cooler any gases which exhibit 10 percent
opacity, or greater.
(d) Where the presence of unoom-
bined water is the only reason for failure
to meet the requirements of paragraphs
(a) (2), (b) (2), and (c), such failure will
not be a violation of this section.
17. Section 60.63 is revised to read as
follows:
§ 60.63 Monitoring of operations.
(a) The owner or operator of any
Portland cement plant subject to the pro-
visions of this part shall record the daily
production rates and kiln feed rates.
.18. Section 60.64 is revised to read as
follows:
§ 60.64 Test methods and procedures.
(a) The reference methods in Appen-
dix A to this part, except as provided for
in § 60.8(b), shall be used to determine
compliance with the standards pre-
scribed in § 60.62 as follows:
(1) Method 5 for the concentration
of particulate matter and the associated
moisture content;
(2) Method 1 for sample and velocity
traverses;
(3) Method 2 for Telocity and volu-
metric flow rate; and
(4) Method 3 for gas analysis.
(b) For Method 5, the minimum sam-
pling time and minimum sample volume
for each run, except when process varia-
bles or other factors justify otherwise to
the satisfaction of the Administrator.
shall be as follows:
(1) 60 minutes and 0.85 dscm (30.0
dscf) for the kiln.
(2) 60 minutes and 1.15 dscm (40.6
dscf) for the clinker cooler.
(c) Total kiln feed rate (except fuels),
expressed in metric tons per hour on a
dry basts, sriaJI be determined during
each testing period by suitable methods;
and shall be confirmed by a material bal-
ance over the production system.
(d> For each run, particulate matter
emissions, expressed in g/metric ton of
kiln feed, shall be determined by divid-
ing the emission rate in g/hr by the kiln
feed rate. The emission rate shall bs
determined by the equation, g/hr=Qsx
c, where Q,=volumetrlc flow rate of the
total effluent in dscm/hr as determined
in accordance with paragraph (a) (3) of
this section, and c=partlculate concen-
tration in g/dscm as determined in ac-
cordance with paragraph (a) (1) of this
section.
19, Section 60.72 is revised to read as
follows:
FEDERAl REGISTER, VOL 39, NO. 116FRIDAY1, JUNE 14, V974
IV-4 9
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20794
RULES AND REGULATIONS
§ 60.72 Standard for nitrogen o\ides.
(a) On and after the date on which
the performance test required to be con-
ducted by § 60.8 is completed, no owner
or operator subject to the provisions of
this subpart shall cause to be discharged
into the atmosphere from any affected
facility any gases which:
(1) Contain nitrogen oxides, ex-
pressed as NO:, In excess of 1.5 kg per
metric ton of acid produced (3.0 Ib per
ton), the production being expressed as
100 percent nitric acid.
(2) Exhibit 10 percent opacity, or
greater. Where the presence of uncom-
bined water is the only reason for failure
to meet the requirements of this para-
graph, such failure will not be a viola-
tion of this section.
§ 60.73 [Amended]
20. Section 60.73 is amended by delet-
ing and reserving paragraph (d).
21. Section 60.74 Is revised to read as
follows:
§ 60.74 Test methods and procedures.
(a) The reference methods in Appen-
dix A to this part, except as provided for
in f 60.8(b), shall be used to determine
compliance with the standard prescribed
in§ 60.72 as follows:
(1) Method 7 for the concentration of
NO,:
(2) Method 1 for sample and velocity
traverses;
(3) Method 2 for velocity and volu-
metric flow rate; and
(4) Method 3 for gas analysis.
(b) For Method 7, the sample site shall
be selected according to Method 1 and
the sampling point shall be the centroid
of the stack or duct or at a point no
closer to the walls than 1 m (3.28 ft).
Each run shall consist of at least four
grab samples taken at approximately 15-
mlnutes intervals. The arithmetic mean
of the samples shall constitute the run
value. A velocity traverse shall be per-
formed once per run.
(c) Acid production rate, expressed in
metric tons per hour of 100 percent nitric
acid, shall be determined during each
testing period by suitable methods and
shall be confirmed by a material balance
over the production system.
(d) For each run, nitrogen oxides, ex-
pressed in g/metrlc ton of 100 percent
nitric acid, shall be determined by divid-
ing the emission rate in g/hr by the acid
production rate. The emission rate shall
be determined by the equation,
g/hr=Q.Xc
where Q.=volume trie flow rate of the
effluent in dscm/hr, as determined in ac-
cordance with paragraph (a) (3) of this
section, and c = NO, concentration in
g/dscm, as determined in accordance
with paragraph (a) (1) of this section.
22. Section 60.81 Is amended by revis-
ing paragraph (b) as follows:
§ 60.81 Definitions.
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RULES AND REGULATIONS
Title 40Protection of the Environment
[FRL 285-2]
CHAPTER IENVIRONMENTAL
PROTECTION AGENCY
SUBCHAPTER CAIR PROGRAMS
PART 52APPROVAL AND PROMULGA-
TION OF IMPLEMENTATION PLANS
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
PART 61NATIONAL EMISSION STAND-
ARDS FOR HAZARDOUS AIR POLLU-
TANTS
Region V Office: New Address
The Region V Office of EPA has been
relocated. The new address is: EPA, Re-
gion V, Federal Building, 230 South Dear-
bom, Chicago, Illinois 60604. This change
revises Region V's office address appear-
ing in §J 52.16, 60.4 and 61.04 of Title 40,
Code of Federal Regulations.
Dated: October 21,1974.
ROGER STRELOW,
Assistant Administrator for
Air and Waste Management.
Parts 52, 60 and 61, Chapter I, Title 40
of the Code of Federal Regulations are
amended as follows:
§§ 52.16, 60.4, 61.04 [Amended]
1. The address of the Region V office is
revised to read:
Region V (Illinois, Indiana, Minnesota, Ohio,
Wisconsin) Federal Building, 230 Bouth
Dearborn, Chicago, Illinois 60606.
[FB Doc.74-24019 Filed 10-24-74;8:45 am]
FEDEPAL REGISTER, VOL. 39, NO. 208-
-FRIDAY, OCTOBER 25, 1974
10
FEDERAL REGISTER, VOL. 39, NO. 219-
-TUESDAY, NOVEMBER II, 197'
Title 40Protection of the Environment
CHAPTER IENVIRONMENTAL
PROTECTION AGENCY
SUBCHAPTER CAIR PROGRAMS
IFBL 29i-ej
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Opacity Provisions
On June 29, 1973, the United States
Court of Appeals for the District of
Columbia in "Portland Cement Associa-
tion v. Ruckelshaus," 486 P. 2d 375 (1973)
remanded to EPA the standard of per-
formance for Portland cement plants (40
CFR 60.60 et seq.) promulgated by EPA
under section 111 of the Clean Air Act.
In the remand, the Court directed EPA to
reconsider among other things the use
of the opacity standards. EPA has pre-
pared a response to the remand. Copies
of this response are available from the
Emission Standards and Engineering
Division, Environmental Protection
Agency, Research Triangle Park, N.C.
27711, Attn: Mr. Don R. Goodwin. In de-
veloping the response, EPA collected and
evaluated a substantial amount of In-
formation which is summarized and ref-
erenced In the response. Copies of this
information are available for inspection
during normal office hours at EPA's Office
of Public Affairs. 401 M Street SW.,
Washington, D.C. EPA determined that
the Portland cement plant standards
generally did not require revision but did
not find that certain revisions are ap-
propriate to the opacity provisions of
the standards. The provisions promul-
gated herein include a revision to § 60.11,
Compliance with Standards and Mainte-
nance Requirements, a revision to the
opacity standard for Portland cement
plants, and revisions to Reference Meth-
od 9. The bases for the revisions are dis-
cussed in detail in the Agency's response
to the remand. They are summarized
below.
The revisions to § 60.11 include the
modification of paragraph (b) and the
addition of paragraph (e). Paragraph
(b) has been revised to indicate that
while Reference Method 9 remains the
primary and accepted means for deter-
mining compliance with opacity stand-
ards in this part, EPA will accept as
probative evidence in certain situations
and under certain conditions the results
of continuous monitoring by transmis-
someter to determine whether a violation
has in fact occurred. The revision makes
clear that even hi such situations the
results of opacity readings by Method 9
remain presumptively valid and correct.
The provisions in paragraph (e) pro-
vide a mechanism for an owner or op-
erator to petition the Administrator to
establish an opacity standard for an af-
fected facility where such facility meets
all applicable standards for which a per-.
fonnance test is conducted under § 60.8
but fails to meet an applicable opacity
standard. This provision is intended pri-
marily to apply to cases where a source
Installs a very large diameter stack which
causes the opacity of the emissions-to be
IV-51
-------
RULES AND -REGULATIONS
3987J
greater than if a stack -of the -diameter
ordinarily used In the Industry were In-
stalled. Although this situation is con-
sidered to be very unlikely to occur, this
provision will accommodate such a situa-
tion. The provision could also apply to
other situations where for any reason an
affected facility could fail to meet opacity
standards while meeting mass emission
standards, although no such situaUons
are expected to occur.
A revision to the opacity standard for
Portland cement plants is promulgated
herein. The revision changes the opacity
limit for kilns from 10 percent to 20 per-
cent. This revision is based tm EPA's
policy on opacity standards and the new
emission data from Portland cement
plants evaluated by EPA during its re-
consideration. The preamble to the
standards of performance which were
promulgated on March 8. 1974 (39 PR
9308) sets forth EPA's policy on opacity
standards: (1) Opacity limits are inde-
pendent enforceable standards; (2>
where opacity and mass/concentration
standards -are applicable to the same
source, the mass/concentration stand-
ards are established at a level which
will result in the design, installation, and
operation of the best adequately demon-
strated system of emission reduction
(taking costs into account); and (3) the
opacity standards are established at a
level which will require proper operation
and maintenance of such control systems.
The new data Indicate that increasing
the opacity limits for kilns from 10 per-
cent to 20 percent Is justified, because
such a standard will still require the de-
sign, installation, and operation of the
best adequately demonstrated system of
emission reduction (taking costs into ac-
count) while eliminating or minimizing
the situations where it will be necessary
to promulgate a new opacity standard
irnderf 60.11 (e).
In evaluating the accuracy of results
from qualified observers following the
procedures of Reference Method 9, EPA
determined that come revisions to Ref-
erence Method 9 are consistently able to
evaluation showed that observers
trained and certified in accordance with
the procedures prescribed under Ref-
erence Method 9 are consistently able to
read opacity with errors not exceeding
-f 7.5 percent based upon single sets of
the average of 24 readings. The revisions
to Reference Method fl include the
following:
1. -An introductory section is added.
This Includes a discussion of the con-
cept of visible emission reading and de-
scribes the effect of variable viewing con-
ditions. Information is also presented
concerning the accuracy of the method
noting that the accuracy of the method
must be taken into account when de-
termining possible violations of appli-
cable opacity standards.
2. Provisions are added which specify
that the determination of opacity re-
moires averaging 24 readings taken at 15-
second Intervals. The purpose for taking
24 readings is both to extend the averag-
ing time over which the observations are
made, and to take sufficient readings to
inrure .acceptable accuracy.
3. More specific .criteria concerning
observer position with respect to the sun
are added. Specifically, the sun must be
within a 140° sector to the observer's
back.
4. Criteria concerning an observer's
position with respect to the plume are
-added. Specific guidance is also provided
lor reading emissions from rectangular
emission points with large length, to
width ratios, and for reading emissions
from multiple stacks. In each of these
cases, emissions are to be read across
the shortest path length.
5. Provisions are added to make clear
that opacity of contaminated water or
steam plumes is to be read at a point
where water does not exist in condensed
form. Two specific instructions are pro-
vided: One for the -case where opacity
can be observed prior to the formation
of the condensed water plume, and one
lor the case where opacity is to be ob-
served after, the condensed water plume
has dissipated.
6. Specifications are added for the
smoke generator used for qualification
of observers so that State or local air
pollution control agencies may provide
observer qualification training consistent
With EPA training
In developing this regulation we have
taken into account the comments re-
ceived in response to the September 11,
1974 O9 FR 35852) notice of proposed
rulemaking which proposed among other
things certain minor changes to Refer-
ence Method 9. This regulation repre-
sents the rulemaking with respect to the
revisions to Method 9.
The determination of compliance ^ith
applicable opacity standards will be
based on an average of 24 consecutive
opacity readings taken at 15 second in-
tervals. This approach is a satisfactory
means of enforcing opacity standards hi
cases where the violation is a continuing
one and time exceptions are not part of
the applicable opacity standard. How-
ever, the opacity standards for steam
electric generators in 40 CFB 60.42 and
fluid catalytic cracking unit catalyst
regenerators in 40 CFR 60J02 and nu-
merous opacity standards in State im-
plementation plans specify various time
exceptions. Many State and local air pol-
lution control agencies use a different
approach in enforcing opacity standards
than the six-minute average period
specified in this revision to Method 9.
EPA recognizes that certain types of
opacity violations that are intermittent
in,nature require a different approach
in applying the opacity standards than
this revision to Method 9. It is'EPA's in-
tent to propose an additional revision to
Method 9 specifying an alternative
method to enforce opacity standards. It
is our intent that this method specify a
minimum number of readings that must
be taken, such as a minimum of ten read-
ings above the standard in any one hour
period prior to citing a violation. EPA is
in the process of analyzing available data
and determining the error involved In
reading opacity to this manner and will
propose this revision to Method 9 BS soon
as this analysis is completed. The Agency
solicits comments and recommendations
on the need for this additional revision to
'Method -9 and would welcome any sug-
gestions particularly from air pollution
control agencies on how we might make
Method 9 more responsive to the needs of
these agencies.
These actions are effective on Novem-
ber 12,1974. The Agency finds good cause
exists for not publishing these actions
as a notice of proposed rulemaking and
for making them effective immediately
upon publication lor the following
reasons:
(1) Only minor amendments are be-
ing made to the opacity standards which
were remanded.
(2) The UJ3. Court of Appeals for
the District of Columbia instructed EPA
to complete the remand proceeding with
respect to the Portland cement plant
standards by November 5,1974.
X3> Because opacity standards are the
subject of other litigation, It Is necessary
to reach a final determination -with re-
spect to the basic issues involving opacity
at this time in order to properly respond
to this issue -with respect to snch other
litigation.
These regulations are issued under the
authority of sections 111 and 114 of the
Clean Air Act. as amended (42 T7.S.C.
1857c~6 and 9).
Dated: November 1,1674.
JOHN QUARLES,
Acting Administrator.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amended
as follows:
1. Section 60.11 is amended by revis-
ing paragraph (b) and adding paragraph
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39874
RULES AND REGULATIONS
Istrator to determine opacity of emis-
sions from the affected facility during
the initial performance tests required by
? 60.8.
(2) Upon receipt from such owner or
operator of the written report of the re-
sults of the performance tests required
by § 60.8, the Admlnistrator__win make
a finding concerning compliance with
opacity and other applicable standards.
If the Administrator finds that an af-
fected facility is In compliance with all
applicable standards for which perform-'
ance tests are conducted In accordance
with § 60.8 of this part but during the
time such performance tests are being
conducted fails to meet any applicable
opacity .standard, he shall notify the
owner or operator and advise him that he
may petition the Administrator within
10 days of receipt of notification to make
appropriate adjustment to the opacity
standard for the affected facility.
(3) The Administrator will grant such
a petition upon a demonstration by the
owner or operator that the affected fa-
cility and associated air pollution con-
trol equipment was operated and main-
tained In a manner to minimize the
opacity of emissions during the perform-
ance tests; that the performance tests
were performed under the conditions es-
tablished by the Administrator; and that
the affected facility and associated ah*
pollution control equipment were In-
capable of being adjusted or operated to
meet the applicable opacity standard.
(4) The Administrator will establish
an opacity standard for the affected
facility meeting the above requirements
at a level at which the source will be
able, as indicated by the performance
and opacity tests, to meet the opacity
standard at all times during which the
source is meeting the mass or concentra-
tion emission standard. The Adminis-
trator will promulgate the new opacity
standard hi the FEDERAL REGISTER.
2. In $ 60.62, paragraph (a) (2) is re-
vised to read as follows:
§ 60.62 Standard for paniculate matter.
(a) *
(2) Exhibit greater than 20 percent
opacity.
*
3. Appendix AReference Methods Is
amended by revising Reference Method
9 as follows:
APPETTOIS AREFERENCE METHODS
METHOD 9TISVAL DETEBMINATIOW Of TBX
OPACITY OT EMISSIONS FEOM STATIONABY
somtcsa
Many stationary sources discharge visible
emissions Into the atmosphere; these emis-
sions are usually In the shape of a plume.
This method Involves the determination of
plume opacity by qualified observers. The
method Includes procedures for the training
and certification of observers, and procedures
to be used In the field for determination of
plume opacity. The appearance of a plume as
viewed by an observer depends upon a num-
ber of variables, some of which may be con-
trollable and some of which may not be
controllable In the field. Variables which can
be controlled to an extent to which they no
longer exert a significant Influence upon
plume appearance Include; Angle of the ob-
server with respect to the plume; angle of the
observer with respect to the sun; point of
observation of attached and detached steam
plume; and angle of the observer with re-
spect to a plume emitted from a rectangular
stack with a large length to width ratio. The
method includes specific criteria applicable
to these variables.
Other variables which ma; not be control-
lable In the field are luminescence and color
contrast between the plume and the back-
ground against which the plume la viewed.
These variables exert an influence upon the
appearance of a plume as viewed by an ob-
server, and can affect the ability of the ob-
server to accurately assign opacity values
to the observed plume. Studies of the theory
of plume opacity and field studies have dem-
onstrated that a plume Is most visible and
presents the greatest apparent opacity when
viewed against a contrasting background. It
follows from this, and Is confirmed by field
trials, that the opacity of a plume, viewed
under conditions where a contrasting back-
ground is present can be assigned with the
greatest degree of accuracy. However, the po-
tential for a positive error is also the greatest
when a plume is viewed under such contrast-
Ing conditions. Under conditions presenting
a less contrasting background, the apparent
opacity of a plume Is less and approaches
zero as the color and luminescence contrast
decrease toward zero. As a result, significant
negative bias and negative errors can be
made when a plume is viewed tinder less
contrasting conditions. A negative bias de-
creases rather than increases the possibility
that a plant operator will be cited for a vio-
lation of opacity standards, due to observer
error.
Studies have been undertaken to determine
the magnitude of positive errors which can
be made by qualified observers while read-
Ing plumes under contrasting conditions and
using the procedures set forth in this
method. The results of these studies (field
trials) which involve a total of 769 sets of
25 readings each are as follows:
(I) For black plumes (133 sets at a smoke
generator). 100 percent of the sets were
read with a positive error1 of less than 7.6
percent .opacity; 99 percent were read with
a positive error of less than 5 percent opacity.
(2) For white plumes (170 sets at a smoke
generator, 168 sets at a coal-fired power plant,
298 sets at a sulfuric acid plant), 99 percent
of the sets were read with a positive error of
less than 7.5 percent opacity; 95 percent were
read with a positive error of less than 6 per-
cent opacity.
The positive observational error associated
with an average of twenty-five readings Is
therefore established. The accuracy of the
method must be taken Into account-when
determining possible violations of appli-
cable opacity standards.
1. Principle and applicability.
1.1 Principle. The opacity of emissions
from stationary sources Is determined vis-
ually by a qualified observer.
1.2 Applicability. This method Is appli-
cable for the determination of the opacity
of emissions from stationary sources pur-
suant to 5 60.11 (b) and for qualifying ob-
servers for visually determining opacity of
emissions.
2. Procedures. The observer qualified In
accordance with paragraph 3 of this method
shall use the following procedures for vis-
ually determining the opacity of emissions:
'For a set, positive error=average opacity
determined by observers' 25 observations
average opacity determined from ttmnsmls-
someter's 25 recordings.
2.1 Position.,The qualified observer shall
stand at a distance sufficient to provide a
clear view of the emissions with the sun
oriented in the 140* sector to his back. Con-
sistent with-maintaining the above require-
ment, the observer shall, as much as possible,
make his observations from a position such
that his. line of vision. Is approximately
perpendicular to the plume direction, and
when observing opacity of emissions from
rectangular outlets (e.g. roof monitors, open
bagbouses, noncircular stacks), approxi-
mately perpendicular to the longer axis of
the outlet. The observer's line of sight should
not Include more than one plume at a time
when multiple stacks are Involved, and in
any case the observer should make his ob-
servations with his line of sight perpendicu-
lar to the longer axis of such a set of multi-
ple stacks (e.g. stub'stacks on baghouses).
2.3 Field records. The observer shall re-
cord the name of the plant, emission loca-
tion, type facility, observer's name and
affiliation, and the date on a field data sheet
(Figure 9-1). The time, estimated distance
to the emission location, approximate wind
direction, estimated wind speed, description
of the sky condition (presence and color of
clouds), and plume background are recorded
on a field data sheet at the time opacity read-
ings are initiated and completed.
2.3 Observations., Opacity observations
shall be made at the point of greatest opacity
In that portion of the plume where con.
densed water vapor is not present. The ob-
server shall not look continuously at the
plume, but Instead shall observe the plume
momentarily at 16-iecond intervals.
2.3.1 Attached steam plumes. When con-
densed water vapor Is present within the
plume as it emerges from the emission out-
let, opacity observations shall be made be-
yond the point In the plume at which con-
densed water vapor is no longer visible. The
observer shall record the approximate dis-
tance from the emission outlet to the point
in the plume at which the observations are
made.
232 Detached steam plume. When water
vapor in the plume condenses and becomes
visible at a distinct distance from the emis-
sion outlet, the opacity of emissions should
be evaluated at the emission outlet prior to
the condensation of water vapor and the for-
mation of the steam plume.
2.4 Recording observations. Opacity ob-
servations shall be recorded to the nearest S
percent at 15-second Intervals on an ob-
servational record sheet. (See Figure 9-2 for
an example.) A minimum of 24 observations
shall be recorded. Each momentary observa-
tion recorded shall be deemed to represent
the average opacity of emissions for a 15-
second period.
2.5 Data Reduction. Opacity shall be de-
termined as an average of 24 consecutive
observations recorded at 15-second intervals.
Divide the observations recorded on the rec-
ord sheet Into sets of 24 consecutive obser-
vations. A set is composed of any 24 con-
secutive observations. Sets need not be con-
secutive in time and.In no case shall two
sets overlap. For each set of 24 observations,
calculate the average by summing the opacity
of the 24 observations and dividing this sum
by 24. If an applicable standard specifies an
averaging time requiring more than 24 ob-
servations, calculate the average for all ob-
servations made during the specified time
period. Record the average opacity on a record
sheet. (See Figure 9-1 for an example.)
3. Qualifications and. testing.
3.1 Certification requirements. To receive
certification as a qualified observer, a can-
didate must be tested and demonstrate the
ability to assign opacity readings In 5 percent
Increments to 25 different black plumes and
33 different white plumes, with an error
FEDERAL .REGISTER,..VOL. 39, NO. 219TUESDAY. .NOVEMBER 13, 1974
IV-53
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RULES AND REGULATIONS
39875
not to exceed 15 percent opacity on any one
reading and an average error not to exceed
7.5 percent opacity In each category. Candi-
dates shall be tested according to the pro-
cedure? described in paragraph 32. Smoke
generators used pursuant to paragraph 82
shall be equipped with a smoke meter which
meets the requirements of paragraph 3.3.
The certification shall be valid for a period
of 6 months, at which time the qualification
procedure must be repeated by any observer
In order to retain certification.
3.2 Certification procedure. The certifica-
tion test consists of showing the candidate a
complete run of 50 plumes25 black plumes
and 25 white plumesgenerated by a smoke
generator. Plumes within each set of 26 black
and 25 white runs shall be presented In ran-
dom order. The candidate assigns an opacity
value to each plume and records his obser-
vation on a suitable form. At the completion
of each run of 60 readings, the score of the
candidate Is determined. If a candidate falls
to qualify, the complete run of 50 readings
must be repeated In any retest. The smoke
test may be administered as part of a smoke
school or training program, and may be pre-
ceded by training or familiarization runs of
the smoke generator during which candidates
are shown, black and white plumes of known.
opacity.
. 33 Smoke generator specifications. Any
emoke generator used for the purposes of
paragraph 32 shall be equipped with a smoke
meter Installed to measure opacity across
the diameter of the smoke generator stock.
The smoke meter output shall display in-
stack opacity based upon a pathlengih equal
to the stack exit diameter, on a full 0 to 100
percent chart recorder scale. The smoke
meter optical design and performance shell
meet the specifications shown in Table 9-1.
Tbs smoke meter shall be calibrated as pre-
scribed in paragraph 3.3.1 prior to the con-
duct of each smoke reading test. At tho
completion of each test, the xero and span
drift shall be checked and if the drift ex-
ceeds ±1 percent opacity, the condition shall
be corrected prior to conducting any subse-
quent test runs. The smoke meter shall ba
demonstrated, at the time of installation, to
meet the specifications listed in Table 9-1.
This demonstration shall be repeated fol-
lowing any subsequent repair or replacement
of the photocell or associated electronic cir-
cuitry including the chart recorder or output
meter, or every 6 months, whichever occurs
first.
TABLE 6-1SMOKE METEB DESIGN AND
PKRFOEMANCE SPECIFICATIONS
Parameter: Specification
a. Light source- Incandescent lamp
operated at nominal
rated voltage.
Parameter: Specification
b. Spectral response Photoplc (daylight
of pnotocelL. spectral response of
the human eye
reference 4.3).
c. Angle of view 15* tnATiTmim total
angle.
d. Angle of projec- 15* maximum total
tlon. angle.
e. Calibration error. ±3% opacity, maxi-
mum.
I. Zero and span ±1% opacity, 30
drift. minutes.
g. Response time S5 seconds.
3.3.1 Calibration. The smoke meter ia
calibrated after allowing a minimum of 30
minutea warmup by alternately producing
simulated opacity of 0 percent and 100 per-
cent. When stable respouee at 0 percent or
100 percent Is noted, the smoke meter Is ad-
Justed to produce an output of 0 percent or
100 percent, as appropriate. This calibration
shall be repeated until stable 0 percent and
100 percent readings are produced without
adjustment. Simulated 0 percent and 100
percent opacity values may be produced, by
alternately switching the power to the light
source on and off while the smoke- generator
Is not producing smoke.
3.32 Smoke meter evaluation. The smoke
meter design and performance are to be
evaluated as follows:
3.3.2.1 Light source. Verify from manu-
facturer's data and from voltage measure-
ments made at the lamp, aa Installed, that
the lamp Is operated within ±6 percent of
the nominal rated voltage.
3.3.2.2 Spectral response of photocell.
Verily from manufacturer's data that the
phfjtocell has a photoplc response; I.e., the
spectral sensitivity of the cell shall closely
approximate the standard spectral-luminos-
ity curve lor photopic vision which Is refer-
enced In (b) of Table 9-1.
3.32.3 Angle of view. Check construction
geometry to ensure that the total angle ol
view of the smoke plume, AS seen by the
photocell, does not exceed 15*. The total
angle of view may be calculated from: 0=2
tan-* d/2L. where «=total angle of view;
d=the sum of the photocell diameter+the
diameter of the limiting; aperture; and
L=the distarice from the photocell to the
limiting aperture. The limiting aperture ia
the point in the path between the photocell
and the smoke plume where the angle of
view la most restricted. In smoke generator
Emoke meters this is normally an orifice
plate.
3.3.2.4 Angle of projection. Check: con-
struction geometry to ensure that the total
angle of projection of the lamp on the
smoke plume does not exceed 16*. The total
angle of projection may be calculated from:
6=2 tan-1 d/2L, where 6= total angle of pro-
jection; d= the sum of the length of the
lamp filament + the diameter of the limiting
aperture; and L= the distance from the lamp
to the limiting aperture.
3.3.2.5 Calibration error. Using ceutral-
density filters of known opacity, check the
error between the actual response and the
theoretical linear response of the smoke
meter. This check Is accomplished by first
calibrating the smoke meter according to
3.S.I and then Inserting a series of three
neutral-density niters of nominal opacity of
20, 50, and 75 percent in the smote meter
pathlength. Filters callbarted within :t2 per-
cent shall be used. Care should be taken
when inserting the .filters to prevent stray
light from affecting the meter. Make a total
of five noneonsecutlve readings for each
filter. The maxiraum error on any one read-
ing shall be 3 percent opacity.
3.32.6 Zero and span drift. Determine
the zero and span drift by calibrating and
operating the Gmoke generator in. a normal
manner over a 1-hour period. The drift is
measured by checking the zero and span at
the end of this period.
3.32.7 Response time. Determine the re-
sponse time by producng the series cf five
simulated 0 percent and 100 percent opacity
values and observing the time required to
reach stable response. Opacity values of 0
percent and 100 percent may be simulated
by alternately switching the power to the
light source off and on while "the smoke
generator is not operating.
4. References.
4.1 .Air Pollution Control District Rules
and Regulations, Los Angeles County Air
Pollution Control District, Regulation IV,
Prohibitions, Rule 50.
42 Weisburd, Melvin L, Field Operations
and Enforcement Manual for Air, VS. Envi-
ronmental Protection Agency, Research Tri-
angle Park, N.C- APTD-1100, August 1972.
pp. 4.1-458.
iS Condon, E. XT., and OdJshaw, EL, Hand-
book of Physios, McGraw-Hill Co., N.Y, K.7,
1958, Table 3.1, p. 6-62.
FEDERAL REGISTER, VOL 39, NO. 219TUESDAY, NOVEMBER 12, 19M
IV-5 4
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39876
RULES AND REGULATIONS
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RULES AND REGULATIONS
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RULES AND REGULATIONS
2S03
11
[FBL 306-9]
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Coal Refuse
On December 23, 1971 (36 FR 24876),
pursuant to section 111 of the Clean Air
Aot, ad amended, the Administrator
promulgated standards of performance
for nitrogen oxides emissions from fossil
fuel-fired steam generators of more than
63 million kcal per hour (250 million Btu
per hour) heat input. The purpose of
this amendment is to clarify the applica-
bility of § 60.44 with regard to units
burning significant amounts of coal
refuse.
Coal refuse is the low-heat value, low-
volatile, high-ash content waste sep-
arated from coal, usually at the mine
site. It can prevent restoration of the
land and produce acid water runoff. The
low-heat value, high-ash characteristics
of coal refuse preclude combustion ex-
cept in cyclone furnaces with current
technology, which because of the furnace
design emit nitrogen oxides (NO,) in
quantities greater than that permitted
by the standard of performance. Prelimi-
nary test results on an experimental unit
and emission factor calculations indi-
cate that NO, emissions would be two to
three times the standard of 1.26 g per
million cal heat input (0.7 pound per
million Btu). At the time of promulga-
tion of f 60.44 in 1971, EPA was unaware
of the possibility of burning coal refuse
in combination with other fossil-fuels,
and thus the standards of performance
were not designed to apply to coal refuse
combustion. However, since coal refuse is
a fossil fuel, as defined under i 60.4Kb),
its combustion is included under the
present standards of performance.
Upon learning of the possible problem
of coal refuse combustion units meeting
the standard of performance for NOx,
the Agency investigated emission data,
combustion characteristics of the mate-
rial, and the possibility of burning it in
other than cyclone furnaces before con-
sideration was given to revising the
standards of performance. The investi-
gation indicated no reason to exempt
coal refuse-fired units from the partlcu-
late matter or sulfur dioxide standards of
performance, since achievement of these
standards is.not entirely dependent on
furnace design. However, the investiga-
tion convinced the Agency that with cur-
rent technology it is not possible to burn
significant amounts of coal refuse and
achieve the NOx standard of perform-
ance.
Combustion of coal refuse piles would
reduce the volume of a solid waste that
adversely affects the environment, would
decrease the quantity of coal that needs
to be mined, and would reduce acid water
drainage as the piles are consumed.
While NOx emissions from coal refuse-
fired cyclone boilers are expected to be
up to three times the standard of per-
formance, the predicted maximum
ground-level concentration increase for
the only currently planned coal refuse-
fired unit (173 MW) is only two micro-
grams NOx per cubic meter. This pre-
dicted increase would raise the total
ground-level concentration around this
source to only five micrograms NOx per
cubic meter, which is well below the na-
tional ambient standard. For these rea-
sons, § 60.44 is being amended to exempt
steam generating units burning at least
25 percent (by weight) coal refuss from
the NOx standard of performance. Such
units must comply with the sulfur di-
oxide and particulate matter standards
of performance.
Since this amendment is a clarification
of the existing standard of performance
and is expected to only apply to one
source, no formal impact statement is
required for this rulemaking, pursuant to
section Kb) of the "Procedures for the
Voluntary Preparation of Environmental
Impact Statements" (39 FR 37419),
This action is effective on January 18,
1975. The Agency finds good cause exists
for not publishing this action as a notice
of proposed rulemaking- and for making
it effective immediately upon publication
because:
1. The action is a clarification of an
existing regulation and is not intended
to alter the overall substantive content
' of that regulation.
2. The action will affect only one
planned source and is not ever expected
to have wide applicability.
3. Immediate effectiveness of the ac-
tion enables the source involved to pro-
ceed with certainty in conducting its
affairs.
(42 UJS.C. 1847c-«, 9)
Dated: January 8,1975.
JOHN QTJARX.ES,
Acting Administrator.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amended
as follows:
1. Section 60.41 is amended by adding
paragraph (c) as follows:
60.41 Definitions.
* *
(c) "Coal refuse" means waste-prod-
ucts of coal mining, cleaning1, and coal
preparation operations (e.g. culm, gob,
etc.) containing coal, matrix material,
clay, and other organic and Inorganic
material.
2. Section 60.44 Is amended by revising
paragraphs (a) (3> and (b) as follows:
60.44 Standard for nitrogen oxides.
(a)
(3) 1.26 g per million cal heat input
(0.70 pound per million Btu) derived
from solid fossfl fuel (except lignite or
a solid fossil fuel containing 25 percent,
by weight, or more of coal refuse) .
(b) When different fossil fuels are
burned simultaneously in any combina-
tion, the applicable standard shall be
determined by pi-oration using the fol-
lowing formula:
X (0.36) +y (0.54) +z (126)
where:
x la the percentage of total beat Input de-
rived, from gaseous fossil fuel,
y is the percentage of total beet Input de-
rived from liquid fossil fuel, and
z Is the percentage of total heat Input de-
rived from solid fossil fuel (except
lignite or a solid fossil fuel containing
25 percent, by weight, or more of coal
refuse).
When lignite or a solid fossil fuel con-
taining 25 percent by weight, or more of
coal refuse is burned in combination with
gaseous, liquid or other solid fossil fuel,
the standard for nitrogen oxides does
not apply.
[KB Doc.75-1544 Piled l-15-75;8:45
FEDERAL REGISTER, VOL 40, NO. 11THURSOAY, JANUARY 16, 1975
IV-5 7
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RULES AND REGULATIONS
J 2 IFKL 364-7]
SUBCHAPTER CAIR PROGRAMS
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Delegation of Authority to State of
Washington
Pursuant to the delegation of authority
for the standards of performance for new
stationary sources (NSPS) to the State
of Washington on February 28,1975, EPA
is today amending 40 CFR 60.4 Address.
A notice announcing this delegation was
published on April 1,1975 (40 FR 14632).
The amended § 60.4 is set forth below.
The Administrator finds good cause
for making this rulemaking effective im-
mediately as the change is an adminis-
trative change and not one of substan-
tive content. It imposes no additional
substantive burdens on the parties
affected.
This rulemaking is effective immedi-
ately, and is issued under the authority
of section 111 of the Clean Air Act, as
amended. 42 U.S.C. 1857C-6.
Dated: April 2,1975.,
ROGER STRELOW,
Assistant Administrator for
Air and Waste Management.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amended
as follows:
Subpart AGeneral Provisions
1. Section 60.4 Is revised to read as
follows:
§60.4 Address.
(a) AH requests, reports, applications,
submlttals, and other communications to
the Administrator pursuant to this part
shall be submitted In duplicate and ad-
dressed to the appropriate Regional Of-
fice of the Environmental Protection
Agency, to the attention of the Director.
Enforcement Division. The regional of-
fices are as follows:
Region I (Connecticut, Maine, New Harop-
chire. Massachusetts. Rhode Island, Ver-
mont), John F. Kennedy Federal Building.
Boston, Massachusetts 02203.
Region II (New York. New Jersey, Puerto
Rico, Virgin Islands). Federal Offlco-Build-
ing. 26 Federal Plaza (Poley Square).'New-
York, N.T. 10007.
Region HI (Delaware, District of Columbia.
Pennsylvania, Maryland, Virginia, West Vir-
ginia), Curtis Building, Sixth and Walnut
Streets, Philadelphia, Pennsylvania 19106.
Region XV- {Alabama,' Florida, Georgia.
Mississippi, Kentucky, North Carolina, South,
Carolina, Tennessee), Suite 300. 1421 Peach-
tree Street. Atlanta, Georgia 80309.
Region V (Illinois, Indiana, Minnesota.
Michigan, Ohio, Wisconsin), 1 North Wacker
Drive, Chicago, Illinois 60606.
Region VI (Arkansas, Louisiana, New
Mexico, Oklahoma, Texas), 1600 Patterson
Street, Dallas, Texas 75201.
Region VII (Iowa, Kansas, Missouri, Ne-
braska) , 1735 Baltimore Street, Kansas City.
Missouri 63108.
Region vm (Colorado, Montana, Norta
Dakota, South Dakota, Utah, Wyoming), 196
Lincoln Towers, 1860 Lincoln Street, Denver.
Colorado 80203.
Region IX (Arizona, California, Hawaii.
Nevada. Guam, American Samoa), 100 Cali-
fornia Street, San Francisco, California 94111.
Region X (Washington, Oregon, Idaho,
Alaska), 1200 Sixth Avenue, Seattle, Wash-
ington 98101.
(b) Section lll(c) directs the Admin-
istrator to delegate to each State, when
appropriate, the authority to implement
and enforce standards of performance
for new stationary sources located in
such State. All information required to
be submitted to EPA under paragraph
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14 33152
RULES AND REGULATIONS
Title 40Protection of Environment
CHAPTER IENVIRONMENTAL
PROTECTION AGENCY
[FBL 392-7]
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Five Categories of Sources in the
Phosphate Fertilizer Industry
On October 22, 1974 (39 PR 37602),
under section 111 of the Clean Air Act,
as amended, the Administrator proposed
standards of performance for five new
affected facilities within the phosphate
fertilizer industry as follows: Wet-
process phosphoric acid plants, super-
phosphoric acid plants, diammonium
phosphate plants, triple superphosphate
plants, and granular triple superphos-
phate storage facilities.
Interested parties participated in the
rulemaking by sending comments to
EPA. The Freedom of Information Cen-
ter, Rm 202 West Tower, 401 M ^Street,
SW., Washington, D.C. has copies of the-
comment letters received and a summary
of the issues and Agency responses avail-
able for public inspection. In addition,
copies of the issue summary and Agency
responses may be obtained upon written
request from the EPA Public Informa-
tion Center (PM-215), 401 M Street, SW.,
Washington, D.C. 20460 (specify "Com-
ment Summary: Phosphate Fertilizer
Industry"). The comments have been
considered and where determined by the
Administrator to be appropriate, revi-
sions have been made to the proposed
standards, and the revised version of the
standards of performance for five source
categories within the phosphate fertilizer
industry are herein promulgated. The
principal revisions to the proposed stand-
ards and the Agency's responses to major
comments are summarized below.
DEFINITIONS
The comment was made that the desig-
nation of affected facilities (§§60.200,
60.210, 60.220, 60.230, and 60.240) were
confusing as written in the proposed
regulations. As a result of the proposed
wording, each component of an affected
facility could have been considered a
separate affected facility. Since this was
not the intent, the affected facility desig-
nations have been reworded. In the new
wording, the listing of components of an
affected facility is intended for identifi-
cation of those emission sources to which
the standard for fluorides applies. Any
sources not listed are not covered by the
standard. Additionally, the definition of
a "superphosphoric acid plant" has been
changed to include facilities which con-
centrate wet-process phosphoric acid to
66 percent or greater P;O: content in-
stead of 60 percent as specified in the
proposed regulations. This was the result
of a comment stating that solvent ex-
tracted acids could be evaporated to
greater than 60 percent P2O-, using con-
ventional evaporators in the wet-process
phosphoric acid plant. The revision clar-
ifies the original intention of preventing
certain wet-process phosphoric acid
plants from being subject to the more
restrictive standard for superphosphoric
acid plants.
One commentator was concerned that
a loose interpretation of the definition of
the affected facility for diammonium
phosphate plants might result in certain
liquid fertilizer plants becoming subject
to the standards. Therefore,, the word
"granular" has been inserted before
"diammonium phosphate plant" in the
appropriate places in subpart V to clarify
the intended meaning.
Under the standards for triple super-
phosphate plants in §60.231(b)-, the
term "by weight" has been added to the
definition of "run-of-pile triple super-
phosphate." Apparently it was not clear
as to whether "25 percent of which
(when not caked), will pass through a
16 mesh screen" referred to percent by
weight or by particle count.
OPACITY STANDARDS
Many commentators challenged the
proposed opacity standards on the
grounds that EPA had shown no correla-
tion between fluoride emissions and
plume opacity, and that no data were
presented which showed that a violation
of the proposed opacity standard would
indicate simultaneous violation of the
proposed fluoride standard. For the
opacity standard to be used as an en-
forcement tool to indicate possible vio-
lation of the fluoride standard, such a
correlation must be established. The
Agency has reevaluated the opacity test
data and determined that the correlation
is insufficient to support a standard.
Therefore, standards for visible emissions
for diammonium phosphate plants, triple
superphosphate plants, and granular
triple superphosphate storage facilities
have been deleted. This action, however,
is not meant to set a precedent re-
garding promulgation of visible emission
standards. The situation which necessi-
tates this decision relates only to fluoride
emissions. In the future, the Agency will
continue to set opacity standards for
affected facilities where such standards
are desirable and warranted based on
test data.
In place of the opacity standard, a pro-
vision has been added which requires an
owner or operator to monitor the total
pressure drop across an affected facility's
scrubbing system. This requirement will
provide an affected facility's scrubbing
system. This requirement will provide for
a record of the operating conditions of
the control system, and will serve as an
effective method for monitoring compli-
ance with the fluoride standards.
REFERENCE METHODS ISA AND 13B
Reference Methods 13A and 13B,
which prescribed testing and analysis
procedures for fluoride emissions, were
originally proposed along with stand-
ards of performance for the primary
aluminum industry (39 PR 37730). How-
ever, these methods have been included
with the standards of performance for
the phosphate fertilizer industry and the
the fertilizer standards are being prom-
ulgated before the primary aluminum
standards. Comments were received tram
the phosphate fertilizer industry and the
primary aluminum industry as the meth-
ods are applicable to both industries. The
majority of the comments discussed pos-
sible changes to procedures and to equip-
ment specifications. As a result of these
comments some minor changes were
made. Additionally, it has been deter-
mined that acetone causes a positive
interference in the analytical procedures.
Although the bases for the standard are
not affected, the acetone wash has been
deleted in both methods to prevent po-
tential errors. Reference Method 13A has
been revised to restrict the distillation
procedure (Section 7.3.4) to 175°C in-
stead of the proposed 180°C in order to
prevent positive interferences introduced
by sulfuric acid carryover in the distil-
late at the higher temperatures. Some
commentators expressed a desire to re-
place the methods with totally different
methods of analysis. They felt they
should not be restricted to using only
those methods published by the Agency.
However, in response to these comments,
an equivalent or alternative method may
be used after approval by the Adminis-
trator according to the provisions of
§ 60.8(b) of the regulations (as revised
in 39 FR 9308).
FLUORIDE CONTROL
Comments were received which ques-
tioned the need for Federal fluoride
control because fluoride emissions are lo-
calized and ambient fluoride concentra-
tions are very low. As discussed in the
preamble to the proposed regulations,
fluoride was the only pollutant other
than the criteria pollutants, speciflsally
named as requiring Federal action in
the March 1970 "Report of the Secre-
tary of Health, Education, and Welfare
to the United States (91st) Congress."
The report concluded that "inorganic
fluorides are highly irritant and toxic
gases" which, even in low ambient con-
centrations, have adverse effects on
plants and animals. The United States
Senate Committee on Public Works in
its report on the Clean Air Amendments
of 1970 (Senate Report No. 91-1196, Sep-
tember 17, 1970, page 9) included fluo-
rides on a list of contaminants wliich
have broad national impact and require
Federal action.
One commentator questioned EPA's
use of section 111 of the Clean Air Act, as
amended, as a means of controlling fluo-
ride air pollution, Again, as was men-
tioned in the preamble to the proposed
regulations, the "Preferred Standards
Path Report for Fluorides" (November
1972) concluded that the most appro-
priate control strategy is through section
111. A copy of this report is available
for inspection during normal business
hours at the Freedom of Information
Center, Environmental Protection
Agency, 401 M Street, SW., Washington,
D.C.
Another objection was voiced concern-
ing the preamble statement that the
"phosphate fertilizer industry is a major
source of fluoride air pollution." Accord-
ing to the "Engineering and Cost Effec-
tiveness Study of Fluoride Emissions
FEDERAL REGISTER, VOL. 40, NO. 152WEDNESDAY, AUGUST 6, 1975
IV-59
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RULES AND REGULATIONS
33153
Control" (Contract EHSD 71-14) pub-
lished in January 1972, the phosphate
fertilizer industry ranks near the top
of the list of fluoride emitters in the
U.S., accounting for nearly 14 percent
of the total soluble fluorides emitted
every year. The Agency contends that
these facts justify naming the phosphate
fertilizer industry a major source of
fluorides.
DIAMMONIUM PHOSPHATE STANDARD
One commentator contended that the
fluoride standard for diammonium phos-
phate plants could not be met under
certain extreme conditions. During pe-
riods of high air flow rates through the
scrubbing system, high ambient temper-
atures, and high fluoride content in
scrubber liquor, the commentator sug-
gested that the standard would not be
met even by sources utilizing best dem-
onstrated control technology. This com-
ment was refuted for two reasons: (1)
The surmised extreme conditions would
not occur and (2) even if the conditions
did occur, the performance of the control
system would be such as to meet the
standard anyway. Thus the fluoride
standard for diammonium phosphate
plants was not revised.
POND WATER STANDARDS
The question of the standards for pond
water was raised in the comments. The
commentator felt that it would have
been more logical if the Agency had post-
poned proposal of the phosphate fer-
tilizer regulations until standards of per-
formance for pond water had also been
decided upon, instead of EPA saying that
such pond water standards might be set
in the future. EPA researched pond
water standards along with the other
fertilizer standards, but due to the com-
plex nature of pond chemistry and a gen-
eral lack of available information, si-
multaneous proposal was not feasible.
Rather than delay new source fluoride
control regulations, possibly for several
years, the Agency decided to proceed
with standards for five categories of
sources within the industry.
ECONOMIC IMPACT
As was indicated by the comments re-
ceived, clarification of some of the
Agency's statements concerning the eco-
nomic impact of the standards is neces-
sary. First, the statement that "for three
of the five standards there will be no
Increase in power consumption over that
which results from State and local stand-
ards" is misleading as written in the
preamble to the proposed regulations.
The statement should have been qualified
in that this conclusion was based on pro-
jected construction in the industry
through 1980, and was not meant to be
applicable past that time. Second, some
comments suggested that the cost data in
the background document were out of
date. Of course the time between the
gathering of economic data and the pro-
posal of regulations may be as long as a
year or two because of necessary inter-
mediate steps in the standard setting
process, however, the economic data are
developed with future industry growth
and financial status in mind, and there-
fore, the analysis should be viable at the
time of standard proposal. Third, an ob-
jection was raised to the statement that
"the disparity in cost between triple
superphosphate and diammonium phos-
phate will only hasten the trend toward
production of diammonium phosphate."
The commentator felt that EPA should
not place itself in a position of regulating
fertilizer production. In response, the
Agency does not set standards to regu-
late production. The standards are set to
employ the best system of emission re-
duction considering cost. The standards
will basically require use of a packed
scrubber for compliance in each of the
five phosphate fertilizer source catego-
ries. In this instance, control costs (al-
though considered reasonable for both
source categories) are higher for triple
superphosphate plants than for diam-
monium phosphate plants. The reasons
for this are that (1) larger gas volumes
must be scrubbed in triple superphos-
phate facilities and (2) triple suprephos-
phate storage facility emissions must also
be scrubbed. However, the greater costs
can be partially offset in a plant produc-
ing both granular triple superphosphate
and diammonium phosphate with the
same manufacturing facility and same
control device. Such a facility can op-
timize utilization of the owner's capital
by operating his phosphoric acid plant at
full capacity and producing a product
mix thft will maximize profits. The in-
formation gathered by the Agency indi-
cates that all new facilities equipped to
manufacture diammonium phosphate
will also produce granular triple super-
phosphate to satisfy demand for direct
application materials and exports.
CONTROL OF TOTAL FLUORIDES
Most of the commentators objected to
EPA's control of "total fluorides" rather
than "gaseous and water soluble flu-
orides." The rationale for deciding to set
standards for total fluorides is presented
on pages 5 and 6 of volume 1 of the back-
ground document. Essentially the ra-
tionale is that some "insoluble" fluoride
compounds will slowly dissolve if allowed
to remain in the water-impinger section
of the sample train. Since EPA did not
closely control the time between capture
and filtration of the fluoride samples, the
change was made to insure a more ac-
curate data base. Additional comments on
this subject revealed concern that the
switch to total fluorides would bring
phosphate rock operations under the
standards. EPA did not intend such op-
erations to be controlled by these regula-
tions, and did not include them in the
definitions of affected facilities; however,
standards for these operations are cur-
rently under development within the
Agency.
MONITORING REQUIREMENTS
v Several comments were received with
regard to the sections requiring a flow
measuring device which has an accuracy
of ± 5 percent over its operating range.
The commentators felt that this accu-
racy could not be met and that the
capital and operating costs outweighed
anticipated utility. First of all, "weigh-
belts" are common devices in the phos-
phate fertilizer industry as raw material
feeds are routinely measured. EPA
felt there would be no economic impact
resulting from this requirement because
plants would have normally installed
weighing devices anyway. Second, con-
tacts with the industry led EPA to be-
lieve that the ± 5 percent accuracy re-
quirement would be easily met, and a
search of pertinent literature showed
that weighing devices with ± 1 percent
accuracy are commercially available.
PERFORMANCE TEST PROCEDURES
Finally some comments specifically
addressed | 60.245 (now § 60.244) of the
proposed granular triple superphosphate
storage facility standards. The first two
remarks contended that it is impossible
to tell when the storage building is filled
to at least 10 percent of the building
capacity without requiring an expensive
engineering survey, and that it was also
impossible to tell how much triple super-
phosphate in the building is fresh and
how much is over 10 days old. EPA's ex-
perience has been that plants typically
make surveys to determine the amount
of triple superphosphate stored, and
typically keep good records of the move-
ment of triple superphosphate into and
out of storage so that it is possible to
make a good estimate of the age and
amount of product. In light of data
gathered during testing, the Agency
disagrees with the above contentions and
feels the requirements are reasonable. A
third comment stated that § 60.244 (pro-
posed § 60.245) was too restrictive, could
not be met with partially filled storage
facilities, and that the 10 percent re-
quirement was not valid or practical. In
response, the requirement of § 60.244(d)
(1) is that "at least 10 percent of the
building capacity" contain granular
triple superphosphate. This means that,
for a performance test, an owner or op-
erator could have more than 10 percent
of the building filled. In fact it is to his
advantage to have more than 10 percent
because of the likelihood of decreased
emissions (in units of the standard) as
calculated by the equation in § 60.244(g).
The data obtained by the Agency
show that the standard can be met with
partially filled buildings. One commenta-
tor did not agree with the requirement in
§60.244(e) [proposed §60.245(e)l to
have at least five days maximum produc-
tion of fresh granular triple superphos-
phate in the storage building before a
performance test. The commentator
felt this section was unreasonable
because it dictated production schedules
for triple superphosphate. However,
this section applies only when the re-
quirements of § 60.244(d) (2) [proposed
§ 60.245(d) (2) 1 are not met. In ad-
dition this requirement is not unreason-
able regarding production schedules
because performance tests are not re-
quired at regular intervals. A perform-
ance test is conducted after a facility
begins operation; additional perform-
ance tests are conducted only when the
facility is suspected of violation of the
standard of performance.
FEDERAL REGISTER, VOL. 40. NO. 152WEDNESDAY, AUGUST 6. 19/5
IV-60
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33154
RULES AND REGULATIONS
Effective date. In accordance with sec-
tion 111 of the Act, these regulations pre-
scribing standards of performance for
the selected stationary sources are effec-
tive on August 4. 1975, and apply to
sources_at which construction or modifi-
cation commenced after October 22,1974.
RTTSSELLE. TRAIN,
Administrator.
JULY 25, 1975.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amend-
ed as follows:
1. The table of sections Is amended fay
adding Subparts T, U, V, W, and X and
revising Appendix A to read as follows:
Subpart TStandards of Performance for the
Phosphate Fertilizer Industry: Wet Process
Phosphoric Acid Plants
60200 Applicability and designation of
affected facility.
60 201 Definitions.
CO 202 Standard for fluorides.
60.203 Monitoring of operations.
60 204 Test methods and procedures.
Subpart UStandards of Performance for the
Phosphate Fertilizer Industry: Superphosphoric
Acid Plants
60 210 Applicability and designation of
affected facility.
00.211 Definitions.
60212 Standard for fluorides.
60213 Monitoring of operations.
60.214 Test methods and procedures.
Subpart VStandards of Performance for the
Phosphate Fertilizer Industry: Diammonium
Phosphate Plants
60 220 Applicability and designation of
affected facility.
60221 Definitions.
60 222 Standard for fluorides.
60 223 Monitoring of operations.
60.224 Test methods and procedures.
Subpart WStandards of Performance for the
Phosphate Fertilizer Industry: Triple Super-
phosphate Plants
60 230 Applicability and designation of af-
fected facility.
C0.231 Definitions.
60 232 Standard for fluorides.
60 233 Monitoring of operations.
60.234 Test methods and procedures.
Subpart XStandards of Performance for the
Phosphate Fertilizer Industry: Granular Triple
Superphosphate Storage Facilities
60.240 Applicability and. designation of af-
fected facility.
00241 Definitions.
60 242 Standard for fluorides.
60.243 Monitoring of operations.
60.244 Test methods and procedures.
APPENDIX AREFERENCE METHODS
Method 1Sample and velocity traverses for
stationary sources.
Method 2Determination of stack gas ve-
locity and volumetric flow rate (Type S
pitot tube).
Method 3Gas analysis for carbon dioxide,
excess air, and dry molecular weight.
Method 4Determination of moisture in
stack gases.
Method 5Determination of particulate
emissions from stationary sources.
Method 6Determination of sulfur dioxide
emissions from stationary sources.
Method 7Determination of nitrogen oxide
emissions from stationary sources.
Method 8Determination of sulfuric acid
mist and sulfur dioxide emissions from
stationary sources.
Method 9Visual determination of the opac-
ity of emissions from stationary sources.
Method 10Determination of carbon monox-
ide emissions from stationary sources.
Method 11Determination of hydrogen sul-
flde emissions from stationary sources.
Method 12Reserved.
Method 13ADetermination of total fluoride
emissions from stationary sources
SPADNS Zirconium Lake Method.
Method 13BDetermination of total fluoride
emissions from stationary sourcesSpe-
cific Ion Electrode Method.
2. Part 60 is amended by adding sub-
parts T, U, V, W, and X as follows:
Subpart TStandards of Performance for
the Phosphate Fertilizer Industry: Wet-
Process Phosphoric Acid Plants
§ 60.200 Applicability and designation
of affected facility.
The affected facility to which the pro-
visions of this subpart apply is each wet-
process phosphoric acid plant. For the
purpose of this subpart, the affected
facility includes any combination of: re-
actors, filters, evaporators, and hotwells.
§ 60.201 Definitions.
As used in this subpart, all terms not
defined herein shall have the meaning
given them in the Act and In subpart A
of this part.
(a) "Wet-process phosphoric acid
plant" means any facility manufactur-
ing phosphoric acid by reacting phos-
phate rock and acid.
(b) "Total fluorides" means elemental
fluorine and all fluoride compounds as
measured by reference methods specified
in § 60.204, or equivalent or alternative
methods.
(c) "Equivalent P:Oo feed" means the
quantity of phosphorus, expressed as
phosphorous pentoxide, fed to the proc-
ess.
§ 60.202 Standard for fluorides.
(a) On and after the date on which
the performance test required to be con-
ducted by § 60.8 is completed, no owner
or operator subject to the provisions of
this subpart shall cause to be discharged
into the atmosphere from any affected
facility any gases which contain total
fluorides in excess of 10.0 g/metric ton
of equivalent PX>5 feed (0.020 Ib/ton).
§ 60.203 Monitoring of operations.
(a) The owner or operator of any wet-
process phosphoric acid plant subject to
the provisions of this subpart shall in-
stall, calibrate, maintain, and operate a
monitoring device which can be used to
determine the mass flow of phosphorus-
bearing feed material to the process. The
monitoring device shall have an accu-
racy of ±5 percent over its operating
range.
(b) The owner or operator of any wet-
process phosphoric acid plant shall
maintain a daily record of equivalent
P=OS feed by first determining the total
mass rate in metric ton/hr of phosphorus
bearing feed using a monitoring device
for measuring mass flowrate which meets
the requirements of paragraph (a) of
this section and then by proceeding ac-
cording to § 60.204(d) (2).
(c) The owner or operator of any wet-
process phosphoric acid subject to the
provisions of this part shall install, cali-
brate, maintain, and operate a monitor-
ing device which continuously measures
and permanently records the total pres-
sure drop across the process scrubbing
system. The monitoring device shall have
an accuracy of ±5 percent over its op-
erating range.
§ 60.201 Test methods and procedures.
(a) Reference methods in Appendix A
of this part, except as provided in § 60.8
(b), shall be used to determine compli-
ance with the standard prescribed in
§ 60.202 as follows:
(1) Method ISA or 13B for the concen-
tration of total fluorides and the asso-
ciated moisture content,
(2) Method 1 for sample and velocity
traverses,
(3) Method 2 for velocity and vol-
umetric flow rate, and
(4) Method 3 for gas analysis.
(b) For Method 13A or 13B, the sam-
pling time for each run shall be at least
60 minutes and the minimum sample
volume shall be 0.85 dscm (30 dscf) ex-
cept that shorter sampling times or
smaller volumes, when necessitated by
process variables or other factors, may
be approved by the Administrator.
(c) The air pollution control system
for the affected facility shall be con-
structed so that volumetric flow rates
and total fluoride emissions can be ac-
curately determined by applicable test
methods and procedures.
(d) Equivalent P-OB feed shall be de-
termined as follows:
(1) Determine the total mass rate in
metric ton/hr of phosphorus-bearing
feed during each run using a flow
monitoring device meeting the require-
ments of § 60.203(a).
(2) Calculate the equivalent P»O3 feed
by multiplying the percentage P,Or, con-
tent, as' measured by the spectrophoto-
metric molybdovanadophosphate method
(AOAC Method 9), times the total mass
rate of phosphorus-bearing feed. AOAC
Method 9 is published in the Official
Methods of Analysis of the Association
of Official Analytical Chemists, llth edi-
tion. 1970, pp. 11-12. Other methods may
be approved by the Administrator.
(e) For each run, emissions expressed
in g/metric ton of equivalent P£>s feed
shall be determined using the following
equation:
j!^(C,Q.) IP"3
where:
E = Emissions of total fluorides in g/
metric ton of equivalent P..OS
feed.
C, = Concentration of total fluorides in
mg/dscm. as determined by
Method 13A or 13B.
-------
RULES AND REGULATIONS
Subpart UStandards of Performance for
the Phosphate Fertilizer Industry: Super-
phosphoric Acid Plants
§60.210 Applicability and designation
of affcclod facility.
The affected facility to which the pro-
visions of this subpart apply is each
superphosphoric acid plant. For the pur-
pose of this subpart, the affected facility
includes any combination of: evapora-
tors, hotwells, acid, sumps, and cooling
tanks.
§ 60.211 Definitions.
As used in this subpart, all terms not
defined hereia shall have the meaning
given them in the Act and in subpart A
of this part.
(a) "Superphosphoric acid plant"
means any facility which concentrates
wet-process phosphoric acid to 66 per-
cent or greater PX>-, content by weight
for eventual consumption as a fertilizer.
(b> "Total fluorides" means elemen-
tal fluorine and all fluoride compounds
as measured by reference methods spe-
cified in 5 60.214, or equivalent or alter-
native methods.
(c) "Equivalent P.O., feed" means the
quantity of phosphorus, expressed as
phosphorous pentoxide, fed to the
process.
§ 60.212 Standard for fluorides.
(a) On and after the date on which
the performance test required to be con-
ducted by § 60.8 is completed, no owner
or operator subject to the provisions of
this subpart shall cause to be discharged
into the atmosphere from any affected
facility any gases which contain total
fluorides in excess of 5.0 g/metric ton of
equivalent P:O0 feed (0.010 Ib/ton).
§ 60.213 Monitoring of operations.
(a) The owner or operator of any
superphosphoric acid plant subject to
the provisions of this subpart shall in-
stall, calibrate, maintain, and operate
a flow monitoring device which can be
used to determine the mass flow of
phosphorus-bearing feed material to the
process. The flow monitoring device shall
have an accuracy of ± 5 percent over its
operating range.
(b) The owner or operator of any
superphosphoric acid plant shall main-
tain a daily record of equivalent P,O,
feed by first determining the total mass
rate in metric ton/hr of phosphorus-
bearing feed using a flow monitoring de-
vice meeting the requirements of para-
graph (a) of this section and then by
proceeding according to § 60.214(d) (2).
(c) The owner or operator of any
superphosphoric acid plant subject to the
provisions of this part shall install, cali-
brate, maintain, and operate a monitor-
ing device which continuously measures
and permanently records the total pres
sure drop across the process scrubbing
system. The monitoring device shall have
an accuracy of ± 5 percent over its
operating range.
§ 60.214 Test methods and procedures.
(ai Reference methods in Appendix
A of this part, except as provided In
S60.8(b), shall be used to determine
compliance with the standard prescribed
in § 60.212 as follows:
(1) Method ISA or 13B for the concen-
tration of total fluorides and the asso-
ciated moisture content.
(2) Method 1 for sample and velocity
traverses,
(31 Method 2 for velocity and volu-
metric flow rate, and
(4) Method 3 for gas analysis.
(b) For Method 13A or 13"', the sam-
pling time for each run shall be at least
60 minutes and the minimum sample
volume shall be at least 0.85 dscm (30
dscf) except that shorter sampling times
or smaller volumes, when necessitated by
process variables or other factors, may
be approved by the Administrator.
(c) The air pollution control system
for the affected facility shall be con-
structed so that volumetric flow rates and
total fluoride emissions can be accurately
determined by applicable test methods
and procedures.
(d) Equivalent P_O; feed shall be deter-
mined as follows:
(1) Determine the total mass rate in
metric ton/hr of phosphorus-bearing
feed during each run using a flow moni-
toring device meeting the requirements
of § 60.213(a).
(2) Calculate the equivalent P,O:. feed
by multiplying the percentage P,O, con-
tent, as measured by the spectrophoto-
metric molybdovanadophosphate method
(AOAC Method 9), times the total mass
rate of phosphorus-bearing feed. AOAC
Method 9 is published in the Official
Methods of Analysis of the Association of
Official Analytical Chemists, llth edition,
1970, pp. 11-12. Other methods may be
approved by the Administrator.
(e) For each run, emissions expressed
in g/metric ton of equivalent P.d feed,
shall be determined using the following
equation:
where:
E = Emisslons of total fluorides In g/
metric ton of equivalent P.O.
feed.
C*, = Concentration of total fluorides In
mg/dscm as determined by
Method ISA or 13B.
Q, Volumetric flow rate of the effluent
gas stream in dscm/hr as deter-
mined by Method 2.
10-'=:Conversion factor for mg to g.
Mrj>2 Equivalent PjO,, feed in metric
ton/hr as determined by 5 60.-
214(d).
Subpart VStandards of Performance for
the Phosphate Fertilizer Industry: Diam-
monium Phosphate Plants
§ 60.220 Applicability and designation
of affected facility.
The affected facility to which the pro-
visions of this subpart apply is each
granular diammonium phosphate plant.
For the purpose of this subpart, the af-
fected facility includes any combination
of: reactors, granulators, dryers, coolers,
screens and mills.
§ 60.221 Definitions.
As used in this subpart, all terms not
defined herein shall have the meaning
given them in the Act and in subpart A
of this part.
(a) "Granular diammonium phos-
phate plant" means any plant manu-
facturing granular diammonium phos-
phate by reacting phosphoric acid with
ammonia.
.
(c* The owner or operator of any
granular diammonium phosphate plant
subject to the provisions of this part shall
install, calibrate, maintain, and operate
a monitoring device which continuously
measures and permanently records the
total pressure drop across the scrubbing
system. The monitoring device shall have
an accuracy of ±5 percent over its op-
erating range.
§ 60.22 t T.-st methods and procedures.
(a) Reference methods in Appendix A
of this part, except as provided for in
§ 60.8 (b), shall be used to determine com-
pliance with the standard prescribed in
§ 60.222 as follows:
(1) Method 13A or 13B for the con-
centration of total fluorides and the as-
sociated moisture content,
(2) Method 1 for sample and velocity
traverses,
(3) Method 2 for velocity and volu-
metric flow rate, and
(4) Method 3 for gas analysis.
(b) For Method 13A or 13B, the
sampling time for each run shall be at
least 60 minutes and the minimum
sample volume shall be at least 0.85 dscm
(30 dscf) except that shorter sampling
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RULES AND REGULATIONS
times or smaller volumes when neces-
sitated by process variables or other
factors, may be approved by the Ad-
ministrator.
(c) The air pollution control system
for the affected facility shall be con-
structed so that volumetric flow rates
and total fluoride emissions can be ac-
curately determined by applicable test
methods and procedures.
(d) Equivalent P20S feed shall be de-
termined as follows:
(1) Determine the total mass rate in
metric ton/hr of phosphorus-bearing
feed during each run using a flow moni-
toring device meeting the requirements
of § 60.223(a).
(2) Calculate the equivalent PA feed
by multiplying the percentage PA con-
tent, as measured by the spectrophoto-
metric molybdovanadophosphate method
(AOAC Method 9), times the total mass
rate of phosphorus-bearing feed. AOAC
Method 9 is published in the Official
Methods of Analysis of the Association
of Official Analytical Chemists, llth edi-
tion, 1970, pp. 11-12. Other methods may
be approved by the Administrator.
(e) For each run, emissions expressed
in g/metric ton of equivalent PA feed
shall be determined using the following
equation:
E=(C.Q,) 10^
A//>2o5
where:
E = Emissions of total fluorides in g/
metric ton of equivalent P,,O5.
Ct Concentration of total fluorides in
mg/dscm as determined by
Method 13A or 13B.
Qt = Volumetric flow rate of the effluent
gas stream In dscm/hr as deter-
mined by Method 2.
10-' = Conversion factor for mg to g.
AfraoB=Equivalent P.,O, feed In metric
ton/hr as determined by 160.-
224(d).
Subpart WStandards of Performance for
the Phosphate Fertilizer Industry: Triple
Superphosphate Plants
§ 60.230 Applicability and designation
of affected facility.
The affected facility to which the pro-
visions of this subpart apply is each
triple superphosphate plant. For the
purpose of this subpart, the affected
facility includes any combination of:
Mixers, curing belts (dens), reactors,
granulators, dryers, cookers, screens,
mills and facilities which store run-of-
pile triple superphosphate.
§ 60.231 Definitions.
As used in this subpart, all terms not
defined herein shall have the meaning
given them in the Act and in subpart A
of this part.
(a) "Triple superphosphate plant"
means any facility manufacturing triple
superphosphate by reacting phosphate
rock with phosphoric acid. A rule-of-pile
triple superphosphate plant includes
curing and storing.
(b) "Run-of-pile triple superphos-
phate" means any triple superphosphate
that has not been processed in a granu-
lator and is composed of particles at
least 25 percent by weight of which
(when not caked) will pass through a 16
mesh screen.
(c) "Total fluorides" means ele-
mental fluorine and all fluoride com-
pounds as measured by reference
methods specified In § 60.234, or equiva-
lent or alternative methods.
(d) "Equivalent P2O5 feed" means the
quantity of phosphorus, expressed as
phosphorus pentoxide, fed to the process.
§ 60.232 Standard for fluorides.
(a) On and after the date on which the
performance test required to be con-
ducted by § 60.8 is completed, no owner
or operator subject to the provisions of
this subpart shall cause to be discharged
into the atmosphere from any affected
facility any gases which contain total
fluorides in excess of 100 g/metric ton of
equivalent P.O= feed (0.20 Ib/ton).
§ 60.233 Monitoring of operations.
(a) The owner or operator of any triple
superphosphate plant subject to the pro-
visions of this subpart shall install, cali-
brate, maintain, and operate a flow moni-
toring device which can be used to deter-
mine the mass flow of phosphorus-bear-
ing feed material to the process. The flow
monitoring device shall have an accuracy
of ±5 percent over its operating range.
(b) The owner or operator of any
triple superphosphate plant shall main-
tain a daily record of equivalent P^O^ feed
by first determining the total mass rate
in metric ton/hr of phosphorus-bearing
feed using a flow monitoring device meet-
ing the requirements of paragraph (a)
of this section and then by proceeding
according to § 60.234(d) (2).
(c) The owner or operator of any triple
superphosphate plant subject to the pro-
visions of this part shall install, calibrate,
maintain, and operate a monitoring de-
vice which continuously measures and
permanently records the total pressure
drop across the process scrubbing system.
The monitoring device shall have an ac-
curacy of ±5 percent over its operating
range.
§ 60.234 Test methods and procedures.
(a) Reference methods in Appendix A
of this part, except as provided for in
§ 60.8(b), shall be used to determine com-
pliance with the standard prescribed in
§ 60.232 as follows:
(1) Method 13A or 13B for the concen-
tration of total fluorides and the asso-
ciated moisture content,
(2) Method 1 for sample and velocity
traverses,
(3) Method 2 for velocity and volu-
metric flow rate, and
(4) Method 3 for gas analysis.
(b) For Method 13A or 13B, the sam-
pling time for each run shall be at least
60 minutes and the minimum sample
volume shall be at least 0.85 dscm (30
dscf) except that shorter sampling times
or smaller volumes, when necessitated by
process variables or other factors, may
be approved by the Administrator.
(c) The air pollution control system
for the affected facility shall be con-
structed so that volumetric flow rates
anii total fluoride emissions can be ac-
curately determined by applicable test
methods and procedures.
(d) Equivalent P2O0 feed shall be deter-
mined as follows:
(1) Determine the total mass rate in
metric ton/hr of phosphorus-bearing
feed during each run using a flow moni-
toring device meeting the requirements
of § 60.233(a).
(2) Calculate the equivalent P=O0 feed
by multiplying the percentage P2Oc con-
tent, as measured by the spectrophoto-
metric molybdovanadophosphate method
(AOAC Method 9), times the total mass
rate of phosphorus-bearing feed. AOAC
Method 9 is published in the Official
Methods of Analysis of the Association of
Official Analytical Chemists, llth edition,
1970, pp. 11-12. Other methods may be
approved by the Administrator.
(e) For each run, emissions expressed
in g/metric ton of equivalent P2O0 feed
shall be determined using the following
equation :
(C,Q,) 10-3
where :
E = Emissions of total fluorides In g/
metric ton of equivalent P3O,
feed.
C, = Concentration of total fluorides In
mg/dscm as determined by
Method 13A or 13B.
Q, = Volumetric flow rate of the effluent
gas stream in dscm/hr as deter-
mined by Method 2.
10-3:= Con version factor 'for mg to g.
Mp^n^ Equivalent P.O.. feed In metric
ton/hr as determined by § 60. -
234 (d).
Subpart X Standards of Performance for
the Phosphate Fertilizer Industry: Gran-
ular Triple Superphosphate Storage Fa-
cilities
§ 60.240 Applicability and designation
of affected facility.
The affected facility to which the pro-
visions of this subpart apply is each
granular triple superphosphate storage
facility. For the purpose of this subpart,
the affected facility includes any com-
bination of: storage or curing piles, con-
veyors, elevators, screens and mills.
§ 60.241 Definitions.
As used in this subpart, all terms not
denned herein shall have the meaning
given them in the Act and in subpart A
of this part.
(a) "Granular triple superphosphate
storage facility" means any facility cur-
ing or storing granular triple superphos-
phate.
(b) "Total fluorides" means elemental
fluorine and all fluoride compounds as
measured by reference methods specified
in § 60 244, or equivalent or alternative
methods.
(c) "Equivalent P.O-, stored" means
the quantity of phosphorus, expressed as
phosphorus pentoxide, being cured or
stored in the affected facility.
(d) "Fresh granular triple superphos-
phate" means granular triple superphos-
phate produced no more than 10 days
prior to the date of the performance test.
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RULES AM> REGULATIONS
33157
§ 60.242 Standard for fluorides.
(a) On and after the date on which the
performance test required to be con-
ducted by § 60.8 is completed, no owner
or operator subject to the provisions of
this subpart shall cause to be discharged
into the atmosphere from any affected
facility any gases which contain total
fluorides in excess of 0.25 g/hr/metric
ton of equivalent P,O-, stored (5.0 x 10"'
Ib/hr/ton of equivalent P/X stored).
§ 60.213 Monitoring of operations.
(a) The owner or operator of any
jranular triple superphosphate storage
facility subject to the provisions of this
subpart shall maintain an accurate ac-
sount of triple superphosphate in storage
to permit the determination of the
amount of equivalent P2O5 stored.
(b) The owner or operator of any
granular triple superphosphate storage
facility shall maintain a daily record of
total equivalent P2O-, stored by multiply-
ing the percentage PsO5 content, as
determined by § 60.244(f) (2), times the
total mass of granular triple superphos-
phate stored.
(c) The owner or operator of any
granular triple superphosphate storage
facility subject to the provisions of this
part shall install, calibrate, maintain,
and operate a monitoring device which
continuously measures and permanently
records the total pressure drop across the
process scrubbing sytem. The monitoring
device shall have an accuracy of ±5 per-
cent over its operating range.
§ 60.244 Test methods and procedures.
(a) Reference methods in Appendix A
of this part, except as provided for in
§60.8(b), shall be used to determine
compliance with the standard prescribed
in§ 60.242 as follows:
(1) Method 13A or 13B for the con-
centration of total fluorides and the as-
sociated moisture content,
(2) Method 1 for sample and velocity
traverses,
(3) Method 2 for velocity and volu-
metric flow rate, and
(4) Method 3 for gas analysis.
(b) For Method 13A or 13B, the sam-
pling time for each run shall be at least
60 minutes and the minimum sample
volume shall be at least 0.85 dscm (30
dscf) except that shorter sampling times
or smaller volumes, when necessitated
by process variables or other factors, may
be approved by the Administrator.
(c) The air pollution control system
for the affected facility shall be con-
structed so that volumetric flow rates
and total fluoride emissions can be ac-
curately determined by applicable test
methods and procedures.
(d) Except as provided under para-
graph (e) of this section, all perform-
ance tests on granular triple superphos-
phate storage facilities shall be con-
ducted only when the following quanti-
ties of product are being cured or stored
in the facility:
(1) Total granular triple superphos-
phateat least 10 percent of the build-
ing capacity.
(2) Fresh granular triple superphos-
phateat least 20 percent of the amount
of triple superphosphate in the building.
(e) If the provisions set forth in para-
graph (d) (2) of this section exceed pro-
duction capabilities for fresh granular
triple superphosphate, the owner or oper-
ator shall have at least five days maxi-
mum production of fresh granular triple
superphosphate in the building during
a performance test.
(f) Equivalent PXX stored shall 'be
determined as follows:
(1) Determine the total mass stored
during each run using an accountability
system meeting the requirements of
§60.243(a).
(2) Calculate the equivalent p,O,
stored by multiplying the percentage
P^O- content, as measured by the spec-
trophotometric molybdovanadophos-
phate method (AOAC Method 9), times
the total mass stored. AOAC Method 9
is published in the Afficial Methods of
Analysis of the Association of Official
Analytical Chemists, llth edition, 1970,
pp. 11-12. Other methods may be ap-
proved by the Administrator.
(g) For each run, emissions expressed
in g/hr/metric ton of equivalent P_.O3
stored shall be determined using the fol-
lowing equation:
(C',Q.) 10-'
where:
E = Emissions of total fluorides in g/
hr/metrlc ton of equivalent PaO0
stored.
Ct Concentration of total fluorides in
mg/dscm as determined by
Method 13A or 13B.
Q, = Volumetric flow rate of the effluent
gas stream in dscm/hr as deter-
mined by Method 2.
10-*= Con version factor for mg to g.
Mj>j00=Equivalent Pf>, feed in metric
tons as measured by § 60.244(d).
3. Part 60 is amended by adding Reference
Methods 13A and 13B to Appendix A as
follows:
METHOD 13 DETETMINATION OF TOTAL FLUO-
RIDE EMISSIONS FHOM STATIONARY SOURCES
SPADNS ZIRCONIUM LAKE METHOD
1. Principle and Applicability.
1.1 Principle. Gaseous and participate
fluorides are withdrawn isokinetically from
the source using a sampling train. The fluo-
rides are collected In the impinger water and
on the filter of the sampling train. The
weight of total fluorides in the train Is de-
termined by the SPADNS Zirconium Lake
colorimetric method.
1.2 Applicability. This method Is applica-
ble for the determination of fluoride emis-
sions from stationary sources only when
specified ,by the test procedures for deter-
mining compliance with new source per-
formance standards. Fluorocarbons, such as
Freons, are not quantitatively collected or
measured by this procedure.
2. Range and Sensitivity.
The SPADNS Zirconium Lake analytical
method covers the range from 0-1.4 /ig/ml
fluoride, sensitivity has not been determined.
3. Interferences.
During the laboratory analysis, aluminum
In excess of 300 nag/liter and silicon dioxide
In excess of 300 ^g/Hter will prevent com-
plete recovery of fluoride. Chloride will distill
over and interfere with the SPADNS Zirconl-
xim Luke color reaction. If chloride ion is
present, use of Specific Ion Electrode (Method
13B) is recommended; otherwise a chloride
determination is required and 5 mg of silver
sulfate (seo section 7.3.6) must be added for
each ing of chloride to prevent chloride In-
terference. If sulfuric acid Is carried over in
the distillation, it will cause a positive inter-
ference. To avoid sulfuric acid carryover, it
Is important to stop distillation at 175°C.
4. Precision, Accuracy and Stability.
4.1 Analysis. A relative standard devia-
tion of 3 percent was obtained from twenty
replicate intralaboratory determinations on
stack emission samples with a concentration
range of 39 to 360 mg/1. A phosphate rock
standard which was analyzed by this pro-
cedure contained a certified value of 3.84
percent. The average of five determinations
was 3.88 percent fluoride.
4.2 Stability. The color obtained when
tlie sample and colorimetric reagent are
mixed is stable for approximately two hours.
After formation of the color, the absorbances
of the sample and standard solutions should
be measured at the same temperature. A 3°C
temperature difference between sample and
standard solutlnos will produce an error of
approximately 0 005 mg P/liter.
5. Apparatus.
5 1 Sample train. See Figure 13A-1; It is
similar to the Method 5 train except for the
interchangeability of the position of the fil-
ter. Commercial models of this train are
available. However, if one desires to build his
own, complete construction details are de-
scribed in APTD-0581; for changes from .the
APTD-0581 document and for allowable
modifications to Figure 13A-1, see the fol-
lowing subsections.
The operating and maintenance procedures
for the sampling train are described in
APTD-0576. Since correct usage is important
in obtaining valid results, all users should
read the APTD-0576 document and adopt
the operating and maintenance procedures
outlined In it, unless otherwise specified
herein.
5.1.1 Probe nozzleStainless steel (316)
with Bliarp, tapered leading edge. The angle
of taper shall be f3Q° and the taper shall
be on the outside to preserve a constant
internal diameter. The probe nozzle shall be
of the button-hook or elbow design, unless
otherwise specified by the Administrator. The
wall thickness of the nozzle shall be less than
or equal to that of 20 gauge tubing, 1 e.,
0 165 cm (0.065 in.) and the distance from
the tip of the nozzle to the first bend or
point of disturbance shall be at least two
times the outside nozzle diameter. The nozzle
shall be constructed from seamless stainless
steel tubing. Other configurations and con-
struction material may be used with approval
from the Administrator.
A range of sizes suitable for isokinetic
sampling should be available, e.g., 0.32 cm
C/8 in.) up to 1.27 cm <'/2 in.) (or larger if
higher volume sampling trains are used) in-
side diameter (ID) nozzles in increments of
0.16 era (Vir, In.). Each nozzle shall be cali-
brated according to the procedures outlined
in the calibration section.
5.1.2 Probe linerBorosilicate glass or
stainless steel (316). When the filter Is lo-
cated immediately after the probe, a probe
heating system may be used to prevent filter
plugging resulting from moisture condensa-
tion. The temperature in the probe shall not
exceed 120 -t- 14'C (248 ± 25'F).
5.1 3 Pitot tubeType S, or other device
approved by the Administrator, attached to
probe to allow constant monitoring of the
stack gas velocity. The face openings of the
pitot tube and the probe nozzle shall be
adjacent and parallel to each other, not
necessarily on the same plane, during sam-
pling. The free space between the nozzle and
FEDERAL REGISTER, VOL. 40. NO. 152WEDNESDAY. AUGUST 6, 1975
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33158
RULES AND REGULATIONS
pilot tube shall be at least 1.9 cm (0.75 In.).
The free space shall be set based on a 1.3 cm
(0 5 In.) ID nozzle, which is the largest «ize
nozzle used.
The pltot tube must also meet the criteria
specified In Method 2 and be calibrated ac-
cording to the procedure In the calibration
section of that method.
5.1.4 Differential pressure gaugeIn-
clined manometer capable of measuring ve-
locity head to within 10% of the minimum
measured value. Below a differential pressure
of 1.3 mm (0.05 in.) water gauge, micro-
manometers with sensitivities of 0.013 mm
(0.0005 in.) should be used. However, micro-
manometers are not easily adaptable to field
conditions and are not easy to use with pul-
sating flow. Thus, other methods or devices
acceptable to the Administrator may be
used when conditions warrant.
5.1.5 Filter holderBorosilicate glass with
a glass frit filter support and a sillcone rub-
ber gasket. Other materials of construction
may be used with approval from the Ad-
ministrator, e.g., if probe liner is stainless
steel, then filter holder may be stainless steel.
The holder design shall provide a positive
seal against leakage from the outside or
around the filter.
5.1.6 Filter heating systemWhen mois-
ture condensation is a problem, any heating
system capable of maintaining a temperature
around the filter holder during sampling of
no greater than 120±14°C (248±25°F).
A temperature gauge capable of measuring
temperature to within 3°C (5.4°F) 'shall be
Installed so that when the filter heater is
used, the temperature around the filter
holder can be regulated and monitored dur-
ing sampling. Heating systems other than
the one shown in APTD-0581 may be used.
5.1.7 ImpingersFour implngers con-
nected as shown in Figure 13A-1 with ground
glass (or equivalent), vacuum tight fittings.
The first, third, and fourth implngers are
of the Greenburg-Smith design, modified by
replacing the tip with a l',4 cm (V4 in.)
inside diameter glass tube extending to 1 !/4
cm ('/a in.) from the bottom of the flask.
The second implnger is of the Greensburg-
Smith design with the standard tip.
6.1.8 Metering systemVacuum gauge,
leak-free pump, thermometers capable of
measuring temperature to within 3°C
(~5°F), dry gas meter with 2% accuracy at
the required sampling rate, and related
equipment, or equivalent, as required to
maintain an isokinetic sampling rate and
to determine sample volume. When the
metering system is used in conjunction with
a pltot tube, the system shall enable checks
of isokinetic rates.
5.1.9 BarometerMercury, aneroid, or
other barometers capable of measuring at-
mospheric pressure to within 2.5 mm Hg
(0.1 in. Hg), In many cases, the barometric
reading may be obtained from a nearby
weather bureau station, In which case the
station value shall be requested and an ad-
justment for elevation differences shall be
applied at a rate of minus 2.5 mm Hg (0.1
in. Hg) per 30 m (100 ft) elevation increase.
5.2 Sample recovery.
5.21 Probe liner and probe nozzle
brushesNylon bristles with stainless steel
wire handles. The probe brush shall have
extensions, at least as long as the probe, of
stainless steel, teflon, or similarly inert mate-
rial. Both brushes shall be properly sized and
shaped to brush out the probe liner and
nozzle.
5.2.2 Glass wash bottlesTwo.
5.2.3 Sample storage containersWide
mouth, high density polyethylene bottles,
1 liter.
5.2.4 Plastic storage containersAir tight
containers ol sufficient volume to store silica
gel.
5.2,5 Graduated cylinder250 ml.
5.2.6 Funnel and rubber policemanto
aid in transfer of silica gel to container; not
necessary if silica gel Is weighed In the field.
5.3 Analysis.
5.3.1 Distillation apparatusGlass distil-
lation apparatus assembled as shown in Fig-
ure 13A-2.
5.3.2 Hot plateCapable of heating to
500° G.
5.3.3 Electric muffle furnaceCapable of
heating to 600° C.
6.3.4 CruciblesNickel, 75 to 100 ml ca-
pacity.
5 3.5 Beaker, 1500 ml.
5.3.6 Volumetric flask50 ml.
5.3.7 Erlenmeyer flask or plastic bottle
500 ml.
5.3.8 Constant temperature bathCapa-
ble of maintaining a constant temperature of
±1.0° C in the range of room temperature.
5.3 9 Balance300 g capacity to measure
to ±0.5 g.
5.3.10 Spectrophotometer Instrument
capable of measuring absorbance at 570 nm
and providing at least a 1 cm light path.
5.3.11 Spectrophotometer cells1 cm.
6. Reagents
6.1 Sampling.
6.1.1 FiltersWhatman No. 1 filters, or
equivalent, sized to fit filter holder.
6.1.2 Silica gelIndicating type, 6-16
mesh. If previously used, dry at 175° C
(350° F) for 2 hours. New silica gel may be
used as received.
6.1.3 WaterDistilled.
6.1.4 Crushed Ice.
6.1.5 Stopcock greaseAcetone insoluble,
heat stable silicone grease. This is not neces-
sary if screw-on connectors with teflon
sleeves, or similar, are used.
6.2 Sample recovery.
6.2.1 WaterDistilled from same con-
tainer as 6.1.3.
6.3 Analysis.
6.3.1 Calcium oxide (CaO)Certified
grade containing 0.005 percent fluoride or
less.
6.3.2 Phenolphthaleln Indicator0.1 per-
cent in 1:1 ethanol-water mixture.
6.3.3 Silver sulfate (AgjSO.)ACS re-
agent grade, or equivalent.
6.3.4 Sodium hydroxide (NaOH) Pellets.
ACS reagent grade, or equivalent.
63.5 Sulfuric acid (H2SO,)Concen-
trated, ACS reagent grade, or equivalent.
6.3.6 FiltersWhatman No. 541, or equiv-
alent.
6.3.7 Hydrochloric acid (HC1)Concen-
trated, ACS reagent grade, or equivalent.
6.3 8 WaterDistilled, from same con-
tainer as 6.1.3.
6.3.9 Sodium fluorideStandard solution.
Dissolve 0.2210 g of sodium fluoride In 1
liter of distilled water. Dilute 100 ml of this
solution to 1 liter with distilled water. One
millUiter of the solution contains 0.01 mg
of fluoride.
6.3 10 SPADNS solution[4,5dlhydroxy-
3-(p-sulfophenylazo)-2,7-naphthalene - di-
sulfonic acid trisodium salt]. Dissolve 0.960
± 010 g of SPADNS reagent in 500 ml dis-
tilled water. This solution is stable for at
least one month, if stored in a well-sealed
bottle protected from sunlight.
63.11 Reference solutionAdd 10 ml of
SPADNS solution (6 3.10) to 100 ml distilled
water and acidify with a solution prepared by
diluting 7 ml of concentrated HC1 to 10 ml
with distilled water. This solution is used to
set the Spectrophotometer zero point and
should be prepared daily.
6 3.12 SPADNS Mixed ReagentDissolve
0.135 ±0.005 g of zirconyl chloride octahy-
drate (ZrOCl2.8H2O), in 25 ml distilled water.
Add 350 ml of concentrated HC1 and dilute to
500 ml With distilled water. Mix equal vol-
umes of this solution and SPADNS solution
to form a single reagent. This reagent Is
stable for at least two months.
7. Procedure.
NOTE: The fusion and distillation steps of
this procedure will not be required, if it can
be shown to the satisfaction of the Adminis-
trator that the samples contain only water-
soluble fluorides.
7.1 Sampling. The sampling shall be con-
ducted by competent personnel experienced
with this test procedure.
7.1.1 Pretest preparation. All train com-
ponents shall be maintained and calibrated
according to the procedure described in
APTD-0576, unless otherwise specified herein.
Weigh approximately 200-300 g of silica gel
in air tight containers to the nearest 0.5 g.
Record the total weight, both silica gel and
container, on the container. More silica gel
may be used but care should be taken during
sampling that it is not entrained and carried
out from the impinger. As an alternative, the
silica gel may be weighed directly in the im-
pinger or its sampling holder Just prior to
the train assembly.
7.1.2 Preliminary determinations. Select
the sampling site and the minimum number
of sampling points according to Method 1 or
as specified by the Administrator. Determine
the stack pressure, temperature, and the
range of velocity heads using Method 2 and
moisture content using Approximation Meth-
od 4 or its alternatives for the purpose of
making isokinetic sampling rate calculations.
Estimates may be used. However, final results
will be based on actual measurements made
during the test.
Select a nozzle size based on the range of
velocity heads such that it is not necessary
to change the nozzle size in order to main-
tain isokinetic sampling rates. During the
run, do not change the nozzle size. Ensure
that the differential pressure gauge Is capable
of measuring the minimum velocity head
value to within 10%, or as specified by the
Administrator.
Select a suitable probe liner and probe
length such that all traverse points can be
sampled. Consider sampling from opposite
sides for large stacks to reduce the length of
probes.
Select a total sampling time greater than
or equal to the minimum total sampling time
specified in the test procedures for the spe-
cific industry such that the sampling time
per point is not less than 2 mln. or select
some greater time interval as specified by the
Administrator, and such that the sample
volume that will be taken will exceed the re-
quired minimum total gas sample volume
specified in the test procedures for the spe-
cific industry. The latter is based on an ap-
proximate average sampling rate. Note also
that the minimum total sample volume is
corrected to standard conditions.
It is recommended that a half-integral or
integral number of minutes be sampled at
each point in order to avoid timekeeping
errors.
In some circumstances, e.g. batch cycles, it
may be necessary to sample for shorter times
at the traverse points and to obtain smaller
gas sample volumes. In these cases, the Ad-
ministrator's approval must first be obtained.
7 1.3 Preparation of collection train. Dur-
ing preparation and assembly of the sam-
pling train, keep all openings where contami-
nation can occur covered until just prior to
assembly or until sampling is about to begin.
Place 100 ml of water in each of the first
two impingers, leave the third implnger
empty, and place approximately 200-300 g
or more, if necessary, of preweighed silica
gel In the fourth impinger. Record the weight
of the silica gel and container on the data
sheet. Place the empty container in a clean
place for later use in the sample recovery.
Place a filter in the filter holder. Be sure
that the filter is properly centered and the
FEDERAL REGISTER, VOL. 40, NO. 152WEDNESDAY, AUGUST 6, 1975
IV-65
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RULES AND REGULATIONS
33159
gasket properly placed so as to not allow the
sample gas stream to circumvent the filter.
Check filter for tears after assembly is com-
pleted.
When glass liners are used, Install selected
nozzle using a Viton A O-ring; the Vlton A
O-ring is installed as a seal where the nozzle
is connected to a glass liner. See APTD-057C
for details. When metal liners are used, In-
stall the nozzle as above or by a leak free
direct mechanical connection. Mark the
probe with heat resistant tape or by some
other method to denote the proper distance
into the stack or duct for each sampling
point.
Unless otherwise specified by the Admin-
istrator, attach a temperature probe to the
metal sheath of the sampling probe so that
the sensor extends beyond the probe tip and
does not touch any metal. Its position should
)e about 1.9 to 2.54 cm (0.75 to 1 in.) from
;he pitot tube and probe nozzle to avoid
nterference with the gas flow.
Assemble the train as shown in Figure
13A-1 with the filter between the third and
fourth impingers. Alternatively, the filter
may be placed between the probe and the
flrst impinger. A filter heating system may
be used to prevent moisture condensation,
but the temperature around the filter holder
shall not exceed 120±14°C (248±25°F).
[(Note: Whatman No. 1 filter decomposes at
150°C (300°F)).] Record filter location on
the data sheet.
Place crushed ice around the Impingers.
7.14 Leak check procedureAfter the
sampling train has been assembled, turn on
and set (if applicable) the probe and filter
heating system(s) to reach a temperature
sufficient to avoid condensation in the probe.
Allow time for the temperature to stabilize.
Leak check the train at the sampling site by
plugging the nozzle and pulling a 380 mm Hg
(15 in. Hg) vacuum. A leakage rate in ex-
cess of 4% of the average sampling rate or
0.00057 mVmin. (0.02 cfm), whichever is less,
is unacceptable.
The following leak check instructions for
the sampling train described in APTD-0576
and APTD-0581 may be helpful. Start the
pump with by-pass valve fully open and
coarse adjust valve completely closed Par-
tially open the coarse adjust valve and slowly
close the by-pass valve until 380 mm Hg (15
In. Hg) vacuum is reached. Do not reverse
direction of by-pass valve. This will cause
water to back up into the filter holder. If
380 mm Hg (15 In. Hg) is exceeded, either
leak check at this higher vacuum or end the
leak check as described below and start over.
When the leak check Is completed, first
slowly remove the plug from the inlet to the
probe or filter holder and immediately turn
off the vacuum pump. This prevents the
water in the impingers from being forced
backward into the filter holder (if placed
before the Impingers) and silica gel from
being entrained backward into the third
impinger.
Leak checks shall be conducted as described
whenever the train is disengaged, e g. for
silica gel or filter changes during the test,
prior to each test rim, and at the completion
of each test run, If leaks are found to be in
excess of the acceptable rate, the test will be
considered invalid. To reduce lost time due
to leakage occurrences, it is recommended
that leak checks be conducted between port
changes.
715 Participate train operationDuring
the sampling run, an isokinetic sampling rate
within 10%, or as specified by the Adminis-
trator, of true Isokinetic shall be maintained.
For each run, record the data required on
the example data sheet shown in Figure 13A-
3. Be sure to record the Initial dry gas meter
reading. Record the dry gas meter readings at
the beginning and end of each sampling time
increment, when changes in flow rates are
made, and when sampling is halted. Take
other data point readings at least once at
each sample point during each time incre-
ment and additional readings when signifi-
cant changes (207,, variation in velocity head
readings) necessitate additional adjustments
in flow rate. Be sure to level and zero the
manometer.
Clean the portholes prior to the test run to
minimize chance of sampling deposited
material. To begin sampling, remove the
nozzle cap, verify (if applicable) that the
probe heater is working and filter heater is
up to temperature, and that the pitot tube
and probe are properly positioned. Position
the nozzle at the flrst traverse point with the
tip pointing directly into the gas stream. Im-
mediately start the pump and adjust the
flow to isokinetic conditions. Nomographs are
available for sampling trains using type S
pitot tubes with 085i0.02 coefficients (Ci.),
and when sampling in air or a stack gas with
equivalent density (molecular weight, M.I,
equal to 29^4), which aid in the rapid ad-
justment of the isokinetic sampling rate
without excessive computations. APTD-0576
details the procedure for using these nomo-
graphs. If Ci> and Md are outside the above
stated ranges, do not use the nomograph
unless appropirate steps are taken to com-
pensate for the deviations.
When the stack is under significant nega-
tive pressure (height of impinger stem), take
care to close the coarse adjust valve before
Inserting the probe into the stack to avoid
water backing into the filter holder. If neces-
sary, the pump may be turned on with the
coarse adjust valve closed.
When the probe is in position, block off
the openings around the probe and porthole
to prevent unrepresentative dilution of the
gas stream.
Traverse the stack cross section, as required
by Method 1 or as specified by the Adminis-
trator, being careful not to bump the probe
nozzle into the stack walls when sampling
near the walls or when removing or inserting
the probe through the portholes to minimize
chance of extracting deposited material.
During the test run, make periodic adjust-
ments to keep the probe and (if applicable)
filter temperatures at their proper values. Add
more ice and, if necessary, salt to the ice
bath, to maintain a temperature of less than
20°C (68'F) at the impinger/silica gel outlet,
to avoid excessive moisture losses. Also, pe-
riodically check the level and zero of the
manometer.
If the pressure drop across the filter be-
comes high enough to make isokinetic sam-
pling difficult to maintain, the filter may be
replaced in the midst of a sample run. It is
recommended that another complete filter
assembly be used rather than attempting to
change the filter itself. After the new filter or
filter assembly Is installed conduct a leak
check. The final emission results shall be
based on the summation of all filter catches.
A single train shall be used for the entire
sample run, except for filter and silica gel
changes. However, if approved by the Admin-
istrator, two or more trains may be used for
a single test run when there are two or more
ducts or sampling ports. The final emission
results shall be based on the total of all
sampling train catches.
At the end of the sample run, turn off the
pump, remove the probe and nozzle from
the stack, and record the final dry gas meter
reading. Perform a leak check.1 Calculate
percent Isokinetic (see calculation section)
to determine whether another test run
should be made. If therms difficulty in main-
taining isokinetic rates due to source con-
1 With acceptability of the test run to be
based on the same criterion as in 7.1.4.
ditions, consult with the Administrator for
possible variance on the Isokinetic rates.
7 2 Sample recovery. Proper cleanup pro-
cedure begins as soon as the probe is re-
moved from the stack at the end of the
sampling period
When the probe can be safely handled,
wipe off all external particulate matter neat
the tip of the probe nozzle and place a cap
over it to keep from losing part of the
sample. Do not cap off the probe tip tightly
while the sampling train is cooling down, as
this would create a vacuum in the filter
holder, thus drawing water from the im-
pingers into the filter.
Before moving the sample train to the
cleanup site, remove the probe from the
sample train, wipe off the sllicone grease, and
cap the open outlet of the probe. Be careful
not to lose any condensate, if present. Wipe
off the silicone grease from the filter inlet
where the probe was fastened and cap it.
Remove the umbilical cord from the last
Impinger and cap the impinger. After wip-
ing off the silicone grease, cap off the filter
holder outlet and impinger inlet. Ground
glass stoppers, plastic caps, or serum caps
may be used to close these openings.
Transfer the probe and fllter-implnger as-
sembly to the cleanup area. This area should
be clean and protected from the wind so that
the chances of contaminating or losing the
sample will be minimized.
Inspect the train prior to and during dis-
assembly and note any abnormal conditions.
Using a graduated cylinder, measure and re-
cord the volume of the water in the flrst
three impingers, to the nearest ml; any con-
densate in the probe should be included in
this determination. Treat the samples as
follows:
721 Container No. 1. Transfer the im-
pinger water from the graduated cylinder to
this container. Add the filter to this con-
tainer. Wash all sample exposed surfaces,
Including the probe tip, probe, flrst three
impingers, impinger connectors, filter holder,
and giaduated cylinder thoroughly with dis-
tilled water. Wash each, component three
separate times with water and clean the
probe and nozzle with brushes. A maximum
wash of 500 ml is used, and the washings are
added to the sample container which must
be made of polyethylene.
7.2.2 Container No. 2. Transfer the silica
gel from the fourth Impinger to this con-
tainer and seal.
7.3 Analysis. Treat the contents of each
sample container as described below.
7.3 1 Container No. 1.
7311 Filter this container's contents, In-
cluding the Whatman No. 1 filter, through
Whatman No. 541 filter paper, or equivalent
into a 1500 ml beaker. Note: If filtrate volume
exceeds 900 ml make filtrate basic with
NaOH to phenolphthaleln and evaporate to
less than 900 ml.
7.3.1.2 Place the Whatman No. 541 filter
containing the insoluble matter (including
the Whatman No. l filter) in a nickel cruci-
ble, add a few nil of water and macerate the
filter with a glass rod.
Add 100 mg CaO to the crucible and mix
the contents thoroughly to form a slurry.
Add a couple of drops of phenolphthaleln
indicator. The indicator will turn red in a
basic medium. The slurry should remain
basic during the evaporation of the water
or fluo'ule ion will be lost. If the indicator
turns colorless during the evaporation, an
acidic condition is indicated. If this happens
add CaO until the color turns red again.
Place the crucible in a hood under infrn-
red lamps or on a hot plate at low heat. Evap-
orate the water completely.
After evaporat Ion of the water, place the
crucible on a hot plate under a hood and
slowly increase the temperature until the
paper chars. It may take several hours for
complete charring of the filter to occur.
FEDERAL REGISTER, VOL. 40, NO. 152WEDNESDAY, AUGUST 6, 1975
IV-6 6
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33160
RULES ANH REGULATIONS
Place the crucible In a cold muffle furnace
and gradually (to prevent smoking) Increase
the temperature to 600'C. and maintain un-
til the contents are reduced to an ash. Re-
move the crucible from the furnace and allow
It to cool.
7 3.1 3 Add approximately 4 g of crushed
NaOH to the crucible and mix. Return the
crucible to the muffle furnace, and fuse the
sample for 10 minutes at 800"C.
Remove the sample from the furnace and
cool to ambient temperature. Using several
rinsings of warm distilled water transfer the
contents of the crucible to the beaker con-
taining the filtrate from container No. 1
(73.1). To assure complete sample removal,
rinse finally with two 20 ml portions of 25
percent (v/v) sulfuric acid and carefully add
to the beaker. Mix well and transfer a one-
liter volumetric flask. Dilute to volume with
distilled water and mix thoroughly. Allow
any undissolved solids to settle.
7.3 2 Container No. 2. Weigh the spent
silica gel and report to the nearest 0.5 g.
733 Adjustment of acid/water ratio in
distillation flask(Utilize a protective shield
when carrying out this procedure.) Place 400
ml of distilled water In the distilling flask
and add 200 ml of concentrated H,SO4 Cau-
tion: Observe standard precautions when
mixing the H,SO4 by slowly adding the acia
to the flask with constant swirling. Add some
soft glass beads and several small pieces of
broken glass tubing and assemble the ap-
paratus as shown in Figure 13A-2 Heat the
flask until It reaches a temperature of 175rC
to adjust the acid/water ratio for subsequent
distillations. Discard the distillate.
7.3 4 DistillationCool the contents of
the distillation flask to below 80 C. Pipette
an aliquot of sample containing less than 0 6
nig F directly Into the distilling flask and add
distilled water to make a total volume of 220
ml added to the distilling flask. [For an es-
timate of what size aliquot does not exceed
0 G mg F, select an aliquot of the solution
and treat as described in Section 736. This
will give an approximation of the fluoride
content, but only an approximation since
interfering ions have not been removed by
the distillation step. |
Place a 250 ml volumetric flask at the con-
denser exit. Now begin distillation and grad-
ually increase the lieat and collect all the
distillation up to 175°C. Caution: Heating
the solution above 175°C will cause sulfuric
acid to distill over.
The acid in the distilling flask can be used
until there is carryover of interferences or
poor fluoride recovery An occasional check of
fluoride recovery with standard solutions is
advised. The acid should be changed when-
ever there is less than 90 percent recovery
or blank values are higher than 0.1 ,,g/ml.
Note: If the sample contains chloride, add
5 mg Ag.,SO, to the flask for every mg of
chloride. Gradually Increase the heat and
collect at the distillate up to 175°C. Do not
exceed 175°C.
735 Determination of Concentration
Bring the distillate in the 250 ml volumetric
flnsk to the mark with distilled water and
mix thoroughly. Pipette a suitable aliquot
from the distillate (containing 10 ^g to 40
Atj fluoride) and dilute to 50 ml with dis-
tilled water. Acid 10 ml of SPADNS Mixed Rea-
gent (see Section 6 3 12) and mix thoroughly.
After mixing, place the sample in a con-
Elont temperature bath containing the stand-
ard solution for thirty minutes before read-
ing the absorbance with the spectropho-
tometer.
Set the spectrophotometer to zero absorb-
ance at 570 nm with reference solution
(6.3.11), and check the spectrophotometer
calibration with the standard solution. De-
termine the absorbance of the samples and
determine the concentration from the cali-
bration curve. If the concentration does not
fall within the range of the calibration curve,
repeat the procedure using a different size
aliquot.
8. Cahbiation.
Maintain a laboratory log of all calibrations.
8.1 Sampling Train.
8 1.1 Probe nozzleUsing a micrometer,
measure the inside diameter of the noz?!e
to the nearest 0.025 mm (0.001 in ). Make
3 separate measurements using different
diameters each time and obtain the average
of the measurements. The difference between
the high and low numbers shall not exceed
0.1 mm (0.004 in.).
When nozzles become nicked, dented, or
corroded, they shall be reshaped, sharpened,
and recalibrated before use.
Each nozzle shall be permanently and
uniquely identified.
8.1 2 Pitot tubeThe pitot tube shall be
calibrated according to the procedure out-
lined in Method 2.
8 1.3 Dry gas meter and orifice meter.
Both meters shall be calibrated according to
the procedure outlined in APTD-057C. When
diaphragm pumps with by-pass valves are
used, check for proper metering system de-
sign by calibrating the dry gas meter at an
additional flow rate of 0.0057 mVmin (02
cfm) with the by-pass valve fully opened
and then with it fully closed If there is more
than ±2 percent difference in flow rates
when compared to the fully closed position
of the by-pass valve, the system is not de-
signed properly and must be corrected
8 1.4 Probe heater calibrationThe probe
heating system shall be calibrated according
to the procedure contained in APTD-0576.
Probes constructed according to APTD-0581
need not be calibrated if the calibration
curves in APTD-057C are used.
8.1 5 Temperature gaugesCalibrate dial
and liquid filled bulb thermometers against
mercury-in-gla.ss thermometers. Thermo-
couples need not be calibrated For other
devices, check with the Administrator.
8 2 Analytical Apparatus Spectrophotom-
eter Prepare the blank standard by adding
10 ml of SPADNS mixed reagent to 50 my of
distilled water. Accurately prepare a series
of standards from the standard fluoride solu-
tion (see Section 63.9) by diluting 2, 4, 6,
8, 10, 12, nnd 14 ml volumes to 100 ml with
distilled water. Pipette 50 ml from each solu-
tion and transfer to a 100 ml beaker. Then
add 10 ml of SPADNS mixed reagent to each.
These standards will contain 0, 10. 20, 30,
40, 50, 60, and 70 us of fluoride (01.4 ng/ml)
respectively.
After mixing, place the refeience standards
and reference solution in a constant tem-
perature bath for thirty minutes before read-
ing the absorbance with the spectrophotom-
eter. All samples should be adjusted to this
same temperature before analyzing. Since
a 3'C temperature difference between samples
and standards will produce an error of ap-
proximately 0 005 mg F/liter, care must be
taken to see that samples and standards are
at nearly identical temperature1) when ab-
sorbances are recorded
With the spectrophotometer at 570 nm.
use the reference solution (see section 6311)
to set the absorbance to zero
Determine the absorbance of the stand-
ards Prepare a calibration curve by plotting
jug F '60 ml versus absorbance on linear graph
paper. A standard curve should be prepared
initially and thereafter whenever the
SPADNS mixed reagent is newly made Also,
a calibration standard should be run with
each set of samples and if it differs frtun the
calibration curve by ±2 percent, » new
standard curve should be prepared.
9. Calculations.
Carry out calculations, retaining at least
one extra decimal figure beyond that of the
acquired data. Round, off figures after final
calculation.
9.1 Nomenclature.
A* --. Aliquot of distillate taken for color
development, ml.
An Cross sectional area of nozzle, m' (ft*).
A i T-Aliquot of total sample added to still,
ml.
Em Water vapor in the gas stream, propor-
tion by volume.
C< Concentration of fluoride In stack gas,
mg/m1, corrected to standard conditions
of 20° C, 760 mm Hg (68' F, 29.92 in. Hg)
on dry basis.
F< = Totnl weight of fluoride In sample, mg.
^,gF Concentration from the calibration
curve, ,,g.
7 = Percent of isoklnetic sampling.
win-Total amount of partlcvilate matter
collected, mg.
M« Molecular weight of water, 18 g/g-mole
(18 Ib/lb-mole).
Tn. = Mass of residue of acetone after evap-
oration, mg.
Pi,»r Barometric pressure at the sampling
site, mm Hg (in. Hg).
P. Absolute stack gas pressure, mm Hg (in.
Hg).
P,t,i = standard absolute pressure, 760 mm
Hg (29.92 in. Hg).
R Ideal gas constant, 006236 mm Hg-m1/
K-g-mole (2183 ill. Hg-ft1/°R-lb-mole).
Tm Absolute average dry gas meter tem-
perature (see fig. 13A-3), °K (°R).
Ti = Absolute average stack gas temperature
(see fig. 13A-3), °K (°R).
Tt 1.1=: Standard absolute temperatxire. 293"
K (528° R).
Va = Volume of acetone blank, ml
Vow Volume of acetone used in wash, ml.
Vd = Volume of distillate collected, ml.
Vir Total volume of liquid collected In im-
plngers and slhra gel, ml. Volume of water
in .silica gel equals silica gel weight in-
ciease in grams times 1 ml/gram. Volume
of liquid collected In Impinger equals final
volume minus initial volume.
Vm Volume of gas sample as measured by
dry gas meter, dcm (dcf).
Vm« = Volume of gas sample measured by
the dry gas meter corrected to standard
conditions, dscm (dscf).
Vu nidi Volume of water vapor in the gas
sample corrected to standard conditions,
scm (scf).
Vt Total volume of sample, ml.
v, = Stack gas .velocity, calculated by Method
2, Equation 2 7 using data obtained from
Method 5, m/sec (ft/sec).
Wo = Weight of residue In acetone wash, mg.
A//= Average prebsuie differential across the
orifice (see fig. 13A-3), met«r, mm H:O
(in. H.O).
pa = Density of acetone, mg/ml (see label on
bottle).
p,,, Density of water, 1 g/ml (000220 lb/
ml).
f) Total sampling time, rain.
13.6r-Specific gravity of mercury.
CO- Sec/min.
100 = Conversion to percent.
D 2 Average dry gas meter temperature
and average orifice piessure drop. See data
sheet (fig 13A-3).
9 3 Dry gas volume. Correct the sample
volume measured by the dry gas meter to
standard conditions (20° C, 760 mm Hg (68°
F, 29.92 inches Hg)] by using equation
13A-I.
FEDERAL REGISTER, VOL. 40, NO. 152WEDNESDAY, AUGUST 6. 1975
IV-6 7
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RULES AND REGULATIONS
33161
--KVn,
Pt,r + AH/13.6
Tm
where :
If=0.3855 °K/mm Hg for metric units.
= 17.65 °R/ln. Hg for English units.
9.4 Volume of water vapor.
»(,(,!) = ic
equation 13A-1
equation 13A-2
where:
K = 0 00134 mVml for metric units.
=0.0472 ftVml for English units.
9.5 Moisture content.
equation 13A-3
If the liquid droplets are present in the
gas stream assume the stream to be saturated
and use a psychrometric chart to obtain an
approximation of the moisture percentage.
9 6 Concentration.
9.6.1 Calculate the amount of fluoride in
the sample according to Equation 13A-4.
equation 13A-4
where :
K-10-~mg//ig.
9 6.2 Concentration of fluoride in stack
gas. Determine the concentration of fluoride
In the stack gas according to Equation 13A-5.
equation 13A-5
where :
K = 35.31 ft"m\
9.7 Isoklnetlc variation.
9.7.1 Calculations from raw data.
100
. /!
equation 13A-6
where:
K = 0.00346 mm Hg-mVml-"K for metric
units.
=0.00267 In. Hg-ftVml-"B for English
units.
9.7.2 Calculations from Intermediate val-
ues.
, __ ?i!><"">Z'-!- ~i "" _ i
lJ.v.A,0 (l-
equation 13A-7
where:
K = 4.323 for metric units.
=0.0944 for English units.
9.8 Acceptable results. The following
range sets the limit on acceptable isoklnetic
sampling results:
If 90 percent
-------
33162
RULES AND REGULATIONS
!nM^CT TEMPERATURE
'V5'"1' , SENSOR ,
--\ T S. I ., PROBE
.
1.9cm (075 in I
CHECK
VALVE
AIRTICI'T
PUMP
i 13A I riu.,ml" timiili
CrjNNCCT'MGTUBE
1? Rim ID
£24 40
THERMOMETER TIPMUST EXTEND BELOW
THE LIQUID LEVEL
WITH J 10/30
{24/40
524/40
CONDENSER
HEATING
MANTLE
250ml
VOLUMETRIC
FLASK
Figure 13A-2. Fluoride Distillation Apparatus
FEDERAL REGISTER, VOL. 40, NO. 152WEDNESDAY, AUGUST 6, 1975
IV-6 9
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RULES AND REGULATIONS
IOCATION
0 ft HATCH.
DATE
PUS NO
METER A
C f &CTO
AMBIENT TEMPERATURE
BAROMETRIC "RESSURE .
T TUBE COEFFICIENT, C
SCHEMATIC OF STACK CHOSS SECTION
HDZZII IDENTIFICATION NO
AVERAGE CAUBRATED NOZZLE DIAMETER, c
PROflE HEATER SEUWG
LEAK RATE, mVmm IcFm)
PROBE LINER MATERIAL
TB*\FflSE POINT
NUMBfR
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METHOD 13B DETFRMINAT1ON OF TOTAL FLUO-
RIDE EMISSIONS FROM STATIONARY SOURCES
SPECIFIC ION ELECTRODE METHOD.
I Principle and Applicability.
1 1 Principle. Gaseous and participate flu-
orides are withdrawn Isokinetlcally from the
source using a sampling train. The fluorides
are collected in the impmger water and on
the niter of the sampling train The weight
of total fluorides in the tram is determined
by the specific ion electrode method
1 2 Applicability. This method is ap-
p'linble for the determination of fluoride
emissions from stationary sources only when
specified by the test procedure:, for deter-
mining compliance with new source pei-
formance standards Fluoiocarbons surh as
Picons, are not quantitatively collected or
measured by this procedure.
2 Range and Sensiiinly
The fluoride specific ion elecliode analyti-
cal method covers the range of 0 02-2,000 //g
F; ml; however, measuiements of less than
0 1 /ig F/ml require extra care Sensitivity has
not been determined.
3. Interference*
During the laboratory analysts, aluminum
in excess of 300 mg'liter and silicon dioxide
in excess of 300 /jg, liter will prevent complete
recovery of fluoride.
4 Precision, Accuracy and Stability.
The accuracy of fluoride electrode measure-
ments has been reported by various re-
searchers to be in the range of 1-5 percent In
a concentration range of 0 04 to 80 mg/1. A
change in the temperature of the sample will
change the electrode response, a change of
I°C will produce a 1 5 percent lelative error
In the measurement Lack of stability In the
electrometer used to measuie EMF can intro-
dute error An error of 1 millivolt in the EMF
measurement produces a relative error of 4
percent regardless of the absolute concen-
tiation being measured.
5 Apparatus.
."> 1 Sample train. See Figure 13A-1
(Method 13A); it is similar to the Method 5
train except for the Interchangeability of
the position of the filter. Commercial models
of this train are available. However, If one
desires to build his own, complete construc-
tion details are described In APTD-0581; for
changes from the APTD-0581 document and
for allowable modifications to Figure 13A-1,
see the following subsections.
The operating and maintenance procedures
for the sampling train are described in
APTD-0576 Since correct usage is impor-
tant in obtaining valid results, all users
should read the APTD-0576 document and
adopt the operating and maintenance pro-
cedures outlined In it, unless otherwise spec-
ified herein.
511 Probe nozzleStainless steel (31G)
with sharp, tapered leading edge. The angle
of taper shall be £30° and the taper shall be
on the outside to preserve a constant inter-
nal diameter. The probe nozzle shall be of
the button-hook or elbow design, unless
otherwise specified by the Administrator.
The wall thickness of the nozzle shall be
less than or equal to that of 20 gauge tub-
ing, ie . 0.165 cm (0.065 in.) and the distance
from the tip of the nozzle to the first bend
or point of disturbance shall be at least two
times the outside nozzle diameter. The noz-
zle shall be constructed from seamless stain-
less steel tubing Other configurations and
construction material may be used with ap-
proval from the Administrator.
A range of sizes suitable for isokinetic
sampling should be available, e.g , 0.32 cm
('a in ) up to 1.27 cm (", in ) (or larger if
higher volume sampling trains are used)
inside diameter (ID) nozzles in increments
of 0.16 crn ('in in). Each nozzle shall be
calibrated according to the procedures out-
lined in the calibration section.
5 1 2 Probe linerBorosilicate glass or
stainless steel (316) When the filter is lo-
cated immediately after the probe, a probe
heating system may be used to prevent filter
plugging resulting from moisture conden-
sation. The temperature in the probe shall
not exceed 120±1 BarometerMercury, aneroid, or
other barometers capable of measuring at-
mospheric pressure to within 2 5 mm Hg (0 1
in Hg) In many cases, the barometric read-
ing may be obtained from a nearby weather
bureau station, in which case the station
value shall be requested and an adjustment
for elevation differences shall be applied at a
rale of minus 2 f> mm Hg (0.1 in. Hg) per 30
m (100 It) elevation increase.
6 2 Sample recovery.
521 Probe liner and probe nozzle
bruphc" --Nylon bristles with stainless steel
wire handles. The probe brush shall have
extensions, at least as long as the probe, of
stainless steel, teflon, or similarly inert mate-
rial. Both brushes shall be properly sized and
shaped :o brush out the probe liner and noz-
zle
522 Glass wash bottlesTwo
523 Sample storage containersWide
mouth, high density polyethylene bottles, 1
liter
5,2 4 Plastic sloiage containersAir tight
containers of sutttcleiit volume to store silica
gel.
525 Graduated cylinder250 ml.
52.6 Funnel and rubber policemanTo
aid in tritnsfer of silica gel to container; not
necessary If silica gel is weighed In the field.
FEDERAL REGISTER. VOL. 40, NO. 152WEDNESDAY AUGUST 6, 197S
IV-70
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331&4
RULES AND REGULATIONS
5 3 Analysis.
5.3.1 Distillation apparatusGlass distil-
lation apparatus assembled as shown In Fig-
ure 13A-2 (Method 13A).
5.3 2 Hot plateCapable of heating to
600°C.
5.3.3 Electric muffle furnaceCapable of
heating to 600 "C.
5.3.4 CruciblesNickel, 75 to 100 ml
capacity.
5.3 5 Beaker1500 ml.
5.3.6 Volumetric flask50 ml.
5.3.7 Erlenmeyer flask or plastic bottle
500 ml.
5.3.8 Constant temperature bathCap-
able of maintaining a constant temperature
of ±1.0°C In the range of room temperature.
5.3.9 Trip balance300 g capacity to
measure to ±0.5 g.
5.3.10 Fluoride ion activity sensing elec-
trode.
5.3.11 Reference electrodeSingle Junc-
tion; sleeve type. (A combination-type elec-
trode having the references electrode and
the fluoride-Ion sensing electrode built Into
one unit may also be used).
5.3.12 ElectrometerA pH meter with
millivolt scale capable of ±0.1 mv resolu-
tion, or a specific Ion meter made specifically
lor specific ion use.
5.3.13 Magnetic stirrer and TFE fluoro-
carbon coated stripping bars.
6. Reagents.
6.1 Sampling.
6.1.1 FiltersWhatman No. 1 niters, or
equivalent, sized to fit filter holder.
6.1.2 Silica getIndicating type, 6-16
mesh. If previously used, dry at 175°C
(35Q°F) for 2 hours. New silica gel may be
used as received.
6.1.3 WaterDistilled.
6.1.4 Crushed Ice.
6.1.5 Stopcock greaseAcetone Insoluble,
heat stable silicone grease. This Is not neces-
sary if screw-on connectors with teflon
sleeves, or similar, are used.
6.2 Sample recovery.
6.2.1 WaterDistilled from same con-
tainer as 6.1.3.
6.3 Analysis.
6.3.1 Calcium oxide (CaO)Certified
grade containing 0.005 percent fluoride or
less.
6.3.2 Phenolphthalein Indicator0.1 per-
cent In 1:1 ethanol water mixture.
6.3.3 Sodium hydroxide (NaOH)Pel-
lets, ACS reagent grade or equivalent.
6.3.4 Sulfurlc acid (H,SO()Concen-
trated, ACS reagent grade or equivalent.
63.' FiltersWhatman No. 541, or
equivalent.
6.3.6 WaterDistilled, from same con-
tainer as 6.1.3.
6.3.7 Total Ionic Strength Adjustment
Buffer (TISAB)Place approximately 500
ml of distilled water in a 1-liter beaker. Add
57 ml glacial acetic acid, 58 g sodium chlo-
ride, and 4 g CDTA (Cyclohexylene dinitrilo
tetraacetlc acid). Stir to dissolve. Place the
beaker in a water bath to cool it. Slowly
add 5 M NaOH to the solution, measuring
the pH continuously with a calibrated pH/
reference electrode pair, until the pH is 5.3.
Cool to room temperature Pour into a 1-liter
flask and dilute to volume with distilled
water. Commercially prepared TISAB buffer
may be substituted for the above.
638 Fluoride Standard Solution0.1 M
fluoride reference solution Add 4.20 grams of
reagent grade sodium fluoride (NaF) to a 1-
liter volumetric flask and add enough dis-
tilled water to dissolve. Dilute to volume
with distilled water.
7. Procedure.
NOTE: The fusion and distillation steps of
this procedure will not be required, if it can
be shown to the satisfaction of the Admin-
istrator that the samples contain only water-
soluble fluorides.
7.1 Sampling. The sampling shall be con-
ducted by competent personnel experienced
with this test procedure
7.1.1 Pretest preparation. All train com-
ponents shall be maintained and calibrated
according to the procedure described in
APTD-0576, unless otherwise specified
herein.
Weigh approximately 200-300 g of silica gel
In air tight containers to the nearest 0.5 g.
Record the total weight, both silica gel and
container, on the container. More silica gel
may be used but care should be taken during
sampling that It Is not entrained and carried
out from the Impinger. As an alternative, the
silica gel may be weighed directly In the im-
pinger or its sampling holder just prior to
the train assembly.
7.1.2 Preliminary determinations. Select
the sampling site and the minimum number
of sampling points according to Method 1 or
as specified by the Administrator. Determine
the stack pressure, temperature, and the
range of velocity heads using Method 2 and
moisture content using Approximation
Method 4 or its alternatives for the purpose
of making isoklnetic sampling rate calcula-
tions. Estimates may be used. However, final
results will be based on actual measure-
ments made during the test.
Select a nozzle size based on the range of
velocity heads such that it Is not necessary
to change the nozzle size in order to maintain
isokinetic sampling rates. During the run, do
not change the nozzle size. Ensure that the
differential pressure gauge is capable of
measuring the minimum velocity head value
to within 10 percent, or as specified by the
Administrator.
Select a suitable probe liner and probe
length such that all traverse points can be
sampled. Consider sampling from opposite
sides for large stacks to reduce the length of
probes.
Select a total sampling time greater than
or equal to the minimum total sampling
time specified in the test procedures for the
specific Industry such that the sampling time
per point is not less than 2 min. or select
some greater time interval as specified by
the Administrator, and such that the sample
volume that will be taken will exceed the re-
quired minimum total gas sample volume
specified in the test procedures for the spe-
cific industry. The latter is based on an ap-
proximate average sampling rate. Note also
that the minimum total sample volume is
corrected to standard conditions.
It is recommended that a half-integral or
integral number of minutes be sampled at
each point in order to avoid timekeeping
errors.
In some circumstances, e g. batch cycles, it
may be necessary to sample for shorter times
at the traverse points and to obtain smaller
gas sample volumes. In these cases, the Ad-
ministrator's approval must first be obtained.
7 13 Preparation of collection tram Dur-
ing preparation and assembly of the sampling
train, keep all openings where contamination
can occur covered until Just prior to assembly
or until sampling is about to begin.
Place 100 ml of water in each of the first
two impingers, leave the third impinger
empty, and place approximately 200-300 g or
more, if necessary, of preweighed silica gel in
the fourth Impinger Record the weight of
the silica gel and container 011 the data sheet.
Place the empty container in a clean place
for later use in the sample recovery
Place a filter in the filter holder Be sure
that the filter is properly centered and the
gasket properly placed so as to not allow the
sample gas stream to circumvent the filter.
Check filter for tears after assembly is com-
pleted.
When glass liners are used, install selected
nozzle using a Viton A O-rlng; the Viton A
O-ring is installed as a seal where the nozzle
is connected to a glass liner. See APTD-0576
for details. When metal liners are used, in-
stall the nozzle as above or by a leak free
direct mechanical connection. Mark the probe
with heat resistant tape or by some other
method to denote the proper distance into
the stack or duct for each sampling point.
Unless otherwise specified by the Admin-
istrator, attach a temperature probe to the
metal sheath of the sampling probe so that
the sensor extends beyond the probe tip and
does not touch any metal. Its position should
be about 1.9 to 2 54 cm (0.75 to 1 in.) from,
the pltot tube and probe nozzle to avoid in-
terference with the gas flow.
Assemble the train as shown In Figure
13A-1 (Method 13A) with the filter between
the third and fourth Impingers. Alterna-
tively, the filter may be placed between the
probe and first impinger. A filter heating sys-
tem may be used to prevent moisture con-
densation, but the temperature around the
filter holder shall not exceed 1200±14"C
(248-t25°F). [(Note: Whatman No. 1 filter
decomposes at 150°C (300°F)).) Record
filter location on the dita sheet.
Place crushed Ice around the Impingers.
7 1.4 Leak check procedureAfter the
sampling train has been assembled, turn on
and set (if applicable) the probe and filter
heating system(s) to reach a temperature
sufficient to avoid condensation in the probe.
Allow time for the temperature to stabilize.
Leak check the train at the sampling site by
plugging the nozzle and pulling a 380 mm
Hg (15 in. Hg) vacuum. A leakage rate in ex-
cess of 4% of the average sampling rate of
0 0057 mVmin. (0.02 cfm), whichever is less,
is unacceptable.
The following leak check Instruction for
the sampling train described in APTD-0576
and APTD-0581 may be helpful. Start the
pump with by-pass valve fully open and
coarse adjust valve completely closed. Par-
tially open the coarse adjust valve and slow-
ly close the by-pass valve until 380 mm Hg
(15 in. Hg) vacuum is reached. Do Not re-
verse direction of by-pass valve. This will
cause water to back up Into the filter holder.
If 380 mm Hg (15 in. Hg) Is exceeded, either
leak check at this higher vacuum or end the
leak check as described below and start over.
When the leak check is completed, first
slowly remove the plug from the inlet to the
probe or filter holder and immediately turn
off the vacuum pump. This prevents the
water in the impingers from being forced
backward Into the filter holder (if placed
before the impingers) and silica gel from.
being entrained backward into the third
Impinger.
Leak checks shall be conducted as de-
scribed whenever the train is disengaged, e g.
for silica gel or filter changes during the test,
prior to each test run, and at the completion
of each test run. If leaks are found to be in
excess of the acceptable rate, the test will be-
considered invalid. To reduce lost time due to
leakage occurrences, it is recommended that
leak checks be conducted between port
changes.
715 Farticulale train operationDuring
the sampling run. an isokinetic sampling
rate within 10%. or as specified by the Ad-
ministrator, of true isokinetic shall be main-
tained.
For each run. record the data required on
the example data sheet shown in Figure
13A-3 (Method ISA). Be sure to record the
initial dry gas meter reading. Record the
dry gas meter readings at the beginning and
end of each sampling time increment, when
changes in flow rates are made, and when
sampling is halted. Take other data point
readings at least once at each sample point
during each time increment and additional
readings when significant changes (20%
variation in velocity head readings) neces-
FEDERAL REGISTER, VOL. 40, NO. 152WEDNESDAY, AUGUST 6, 1975
iy-7i
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RULES AND REGULATIONS
-itate additional adjustments in flow rate. Be
.ure to level and zero the manometer.
Clean the portholes prior to the test run
to minimize chance of sampling deposited
material. To begin sampling, remove the
icrale cap, verify (if applicable) that the
.irotae heater Is working and filter heater is
up to temperature, and that the pitot tube
and probe are properly positioned. Position
I he nozzle at the first traverse point with
'he tip pointing directly into the gas stream.
Immediately start the pump and adjust the
flow to ibOkmetic conditions. Nomographs are
available for sampling trains using type S
pilot tubes with 0.85±002 (coefficients (CP),
and when sampling in air or a stack gas with
equivalent density (molecular weight, M,,,
equal to 29±4), which aid in the rapid ad-
justment of the isokmetic sampling rate
without excessive computations. APTD-0576
details the procedure for using these nomo-
graphs. If Cp and Md are outside the above
stated ranges, do not use the nomograph un-
less appropriate steps are taken to compen-
sate for the deviations.
When the stack is under significant neg-
ative pressure (height of Impinger stem),
take care to close the coarse adjust valve
before inserting the probe into the stack to
avoid water backing into the filter holder. It
necessary, the pump may be turned on with
the coarse adjust valve closed.
When the probe is in position, block off
the openings around the probe and porthole
to prevent unrepresentative dilution of the
gns stream.
Traverse the stack cross section, as re-
quired by Method 1 or as specified by the Ad-
ministrator, being careful not to bump the
probe nozzle Into the stack walls when
sampling near the walls or when removing
or inserting the probe through the port-
holes to minimize chance of extracting de-
posited material.
During the test run, make periodic adjust-
ments to keep the probe and (if applicable)
filter temperatures at their proper values.
Add more Ice and, If necessary, salt to the
ice bath, to maintain a temperature of less
than 20"C (68°F) at the impinger/silica gel
outlet, to avoid excessive moisture losses.
Also, periodically check the level and zero
of the manometer.
If the pressure drop across the filter be-
comes high enough to make isokinetic sam-
pling difficult to maintain, the filter may be
replaced In the midst of a sample run. it is
recommended that another complete filter as-
sembly be used rather than attempting to
change the filter itself. After the new filter
or filter assembly Is Installed, conduct a
leak check. The final emission results shall
be based on the summation of all filter
catches.
A single train shall be used for the entire
sample run, except for filter and silica gel
changes. However, If approved by the Admin-
istrator, two or more trains may be used for
a single test run when there are two or more
ducts or sampling ports. The final emission
results shall be based on the total of all
sampling train catches.
At the end of the sample run, turn off the
pump, remove the probe and nozzle from
the stack, and record the final dry gas meter
reading. Perform a leak check.1 Calculate
percent Isokinetic (see calculation section) to
determine whether another test run should
be made. If there Is difficulty in maintaining
I'okinetlc rates due to source conditions, con-
sult with the Administrator for possible
variance on the Isokinetic rates.
'With acceptability of the test run to be
based on the same criterion as In 7.1.4.
7 2 Sample recovery. Proper cleanup pro-
cedure begins as soon as the probe is re-
moved from the stack at the end of the
sampling period.
When the probe can be safely handled,
wipe off all external particulate matter near
the tip of the probe nozzle and place a cap
over it to keep from losing part of the sam-
ple. Do not cap off the probe tip tightly
while the sampling train is cooling down,
as this would create a vacuum in the filter
holder, thus drawing water from the 1m-
pingers into the filter
Before moving the sample train to the
cleanup site, remove the probe from the
sample train, wipe off the slhcone grease,
and cap the open outlet of the probe. Be
careful not to lose any condensate, if pres-
ent. Wipe off the silicone grease fiom the
filter inlet where the probe was fastened
and cap it. Remove the umbilical cord from
the last impinger and cap the impinger. After
wiping off the silicone grease, cap off the
filter holder outlet and impinger inlet.
Ground glass stoppers., plastic caps, or serum
caps may be used to close these openings.
Transfer the probe and filter-impmger as-
sembly to the cleanup area. This area should
be clean and protected from the wind so that
the chances of contaminating or losing the
sample will be minimized.
Inspect the train prior to and during dis-
assembly and note any abnormal conditions.
Using a graduated cylinder, measure and re-
cord the volume of the water in the first
three implngers, to the nearest ml; any con-
densate in the probe should be included in
this determination. Treat the samples as
follows:
No. 71778, Pauley, J. E., 8-5-75
7.2.1 Container No. 1. Transfer the im-
pinger water from the graduated cylinder
to this container. Add the filter to this
container. Wash all sample exposed sur-
faces, including the probe tip, probe, first
three impingers, impinger connectors, filter
holder, and graduated cylinder thoroughly
with distilled water. Wash each component
three separate times with water and clean
the probe and nozzle with brushes. A max-
imum wash of 500 ml Is used, and the wash-
ings are added to the sample container
which must be made of polyethylene.
7.2.2 Container No. 2. Transfer the silica
gel from the fourth impinger to this con-
tainer and seal.
7.3 Analysis. Treat the contents of each
sample container as described below.
7.3.1 Container No. 1.
7.3.1.1 Filter this container's contents, in-
cluding the Whatman No 1 filter, through
Whatman No. 541 filter paper, or equivalent
Into a 1500 ml beaker. NOTE: If filtrate vol-
ume exceeds 900 ml make filtrate basic with
NaOH to phenolphthalein and evaporate to
less than 900 ml.
7.31.2 Place the Whatman No. 541 filter
containing the insoluble matter (including
the Whatman No. 1 filter) in a nickel cru-
cible, add a few ml of water and macerate
the filter with a glass rod.
Add 100 mg CaO to the crucible and mix
'fhe contents thoroughly to form a slurry. Add
a couple of drops of phenolphthalein Indi-
cator. The indicator will turn red In a basic
medium. The slurry should remain basic
during the evaporation of the water or
fluoride Ion will be lost. If the Indicator
turns colorless during the evaporation, an
acidic condition Is indicated. If this happens
ad4 CaO until the color turns red again.
Place the crucible In a hood under in-
frared lamps or on a hot plate at low heat.
Evaporate the water completely.
After evaporation of the water, place the
crucible on a hot plate under a hood and
t-lovvly increase the temperature until the
paper chars. It may take several hours for
comp.ete charring of the filter to occur.
Place the crucible in a cold muffle furnace
and gradually (to prevent smoking) increase
the temperatuie to 600°C, and maintain until
the contents are reduced to an ash. Remove
the ci ucible from the furnace and allow it to
cool.
7313 Add approximately 4 g of crushed
NaOIl to the crucible and mix. Return the
crucible to the muffle furnace, and fuse the
sample for 10 minutes at 600"C.
Remove the sample from the furnace and
cool to ambient temperature. Using several
rmsuips of warm distilled water transfer
the contents of the crucible to the beaker
containing the filtrate Irom container No
1 (7.31). To assure complete sample re-
moval, rinse finally with two 20 ml portions
of 25 percent (v/v) sulfuric acid and care-
fully add to the beaker. Mix well and trans-
fer to a one-liter volumetric flask. Dilute
to volume with distilled water and mix
thoroughly. Allow any undissolved solids to
settle.
732 Container No. 2. Weigh the spent
silica gel and report to the nearest 0.5 g.
7 3.3 Adjustment of acid/water ratio in
distillation flask(Utilize a protective shield
when carrying out this procedure). Place 400
ml of distilled water in the distilling flask
and add 200 ml of concentrated H.,SO4. Cau-
tion: Observe standard precautions when
mixing the H.,SO4 by slowly adding the acid
to the flask with constant swirling. Add some
soft glass beads and several small pieces of
broken glass tubing and assemble the ap-
paratus as shown in Figure 13A-2. Heat the
flask until it reaches a temperature of 175°C
to adjust the acid/water ratio for subsequent
distillations. Discard the distillate.
7.3.4 DistillationCool the contents of
the distillation flask to below 80°C. Pipette
an aliquot of sample containing less
than 0,6 mg F directly Into the distilling
flask and add distilled water to make a total
volume of 220 ml added to the distilling
flask. [For an estimate of what size aliquot
does not exceed 06 mg F, select an aliquot
of the solution and treat as described in
Section 73.6. This will give an approxima-
tion of the fluoride content, but only an ap-
proximation since Interfering ions have not
been removed by the distillation step.]
Place a 250 ml volumetric flask at the con-
denser exist. Now begin distillation and
gradually increase the heat and collect all the
distillate up to 175"C. Caution: Heating the
solution above 175°C will cause sulfuric acid
to distill over.
The acid in the distilling flask can be
used until there is carryover of interferences
or poor fluoride recovery. An occasional
check of fluoride recovery with standard
solutions is advised. The acid should
be changed whenever there is less than 9C
percent, recovery or blank values are higher
than 0 1 ug/ml.
7.3.5 Determination of concentration
Bring the distillate in the 250 ml volumetric
flask to the mark with distilled water and
mix thoroughly. Pipette a 25 ml aliquot from
the distillate. Add an equal volume of TISAB
and mix. The sample should be at the
same temperature as the calibration stand-
ards when measurements nre made. If
ambient lab temperature fluctuates more
than +2°C from the temperature at which
the calibration standards were measured,
condition samples and standards in a con-
stant temperature bath measurement. Stir
the sample with a magnetic stirrer during
measurement to minimize electrode response
FEDERAL REGISTER, VOL. 40, NO, 152WEDNESDAY, AUGUST 6. 1975
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RULES AND REGULATIONS
time If the stirrer generates enough heat to
change solution temperature, place a piece
of Insulating material such as cork
between the stirrer and the beaker. Dilute
samples (below 10-* M fluoride ion content)
should be held In polyethylene or poly-
propylene beakers during measurement.
Insert the fluoride and reference electrodes
into the solution. When a steady millivolt
reading is obtained, record it This may take
several minutes Determine concentration
from the calibration curve Between elec-
trode measurements, soak the fluoride sens-
ing electrode in distilled water for 30 seconds
and then remove and blot dry.
8 Calibration.
Maintain a laboratory log of all
calibrations.
8 1 Sampling Train
811 Probe nozzleUsing a micrometer,
measure the inside diameter of the nozzle
to the nearest 0025 mm (0001 in.) Make
3 separate measurements using different
diameters each time and obtain the average
of the measurements. The difference between
the high and low numbers shall not exceed
0.1 mm (0004 in.).
When nozzles become nicked, dented, or
corroded, they shall be reshaped, sharpened,
and recalibrated before use.
Each nozzle shall be permanently and
uniquely identified.
8.1.2 Pltot tubeThe pitot tube shall be
calibrated according to the procedure out-
lined in Method 2.
8.1.3 Dry gas meter and orifice meter.
Both meters shall be calibrated according to
the procedure outlined In APTD-0576. When
diaphragm pumps with by-pass valves are
used, check for proper metering system
design by calibrating the dry gas meter at an
additional flow rate of 0 0057 mVmin. (0 2
cfm) with the by-pass valve fully opened
and then with it fully closed If there is
more than ±2 percent difference in flow
rates when compared to the fully closed posi-
tion of the by-pass valve, the system is not
designed properly and must be corrected.
8.1 4 Probe heater calibrationThe probe
heating system shall be calibrated according
to the procedure contained in APTD-0576.
Probes constructed according to APTD-0581
need not be calibrated if the calibration
curves in APTD-0576 are used.
8 1.5 Temperature gaugesCalibrate dial
and liquid filled bulb thermometers against
mercury-in-glass thermometers. Thermo-
couples need not be calibrated For other
devices, check with the Administrator.
8 2 Analytical Apparatus
8 2.1 Fluoride ElectrodePrepare fluoride
standardizing solutions by serial dilution of
the 0.1 M fluoride standard solution Pipet
10 ml of 0 1 M NaF into a 100 ml volumetric
flask and make up to the mark with distilled
water for a 10~2 M standard solution. Use 10
ml of 10-5 M solution to make a 10-1 M solu-
tion in the same manner Reapt 10-* and 10-'
M solutions.
Pipet 50 ml of each standard into a sep-
arate beaker. Add 50 ml of TISAB to each
beaker. Place the electrode in the most dilute
standard solution. When a steady millivolt
reading is obtained, plot the value on the
linear axis of semi-log graph paper versus
concentration on the log axis. Plot the
nominal value for concentration of the
standard on the log axis, e g., when 50 ml of
10-= M standard is diluted with 50 ml TISAB,
the concentration is still designated "10-2M".
Between measurements soak the fluoride
sensing electrode In distilled water for 30
seconds, and then remove and blot dry.
Analyze the standards going from dilute to
concentrated standards. A straight-line cali-
bration curve will be obtained, with nominal
concentrations of 10P, 10P, 10-3, 10-2, 10'1
concentrations of 10-=, 10-', 10-\ 10-', 1Q-1
concentrations of 1Q-5, 10-', 10-1, 10f-, 10f
fluoride molanty on the log axis plotted
versus electrode potential (in millivolts) on
the linear scale.
Calibrate the fluoride electrode daily, and
check it hoxtrly. Prepare fresh fluoride stand-
ardizing solutions daily of 10-2 M or less.
Store fluoride standardizing solutions in
polyethylene or polypropylene containers.
(Note: Certain specific ion meters have been
designed specifically for fluoride electrode
use and give a direct readout of fluoride ion
concentration. These meters may be used in
lieu of calibration curves for fluoride meas-
urements over narrow concentration ranges.
Calibrate the meter according to manufac-
turer's instructions.)
9. Calculations.
Carry out calculations, retaining at least
one extra decimal figure beyond that of the
acquired data. Round off figures after final
calculation.
9.1 Nomenclature.
Xn = Cross sectional area of nozzle, m- (ft-).
Ai = Aliquot of total sample added to still,
ml.
B«, = Water vapor in the gas stream, propor-
tion by volume.
Ci Concentration of fluoride in stack gas,
mg/m1, corrected to standard conditions
of 20° C, 760 mm Hg (68° F, 29.92 in. Hg)
on dry basis.
.Fi=Total weight of fluoride in sample, mg.
1 = Percent of isokinetic sampling.
M = Concentration of fluoride from calibra-
tion curve, molanty.
m>i = Total amount of particulate matter
collected, mg.
Ma = Molecular weight of water, 18 g/g-mole
(18 Ib/lb-mole).
m« = Mass of residue of acetone after evap-
oration, mg.
Ph»r Barometric pressure at the sampling
site, mm Hg (in. Hg).
P, = Absolute stack gas pressure, mm Hg (in.
Hg).
P. 1.1 = Standard absolute pressure, 760 mm
Hg (29.92 in. Hg).
R = Ideal gas constant, 006236 mm Hg-m1/
°K-g-mole (21.83 in. Hg-ftV°R-lb-mole).
Tm Absolute average dry gas meter tem-
perature (see fig. 13A-3), °K (°R).
Ti = Absolute average stack gas temperature
(see fig. 13A-3), "K (°R),
TJ 1,1 = Standard absolute temperature, 293°
K (528° R).
V« Volume of acetone blank, ml.
Veu = Volume of acetone used in wash, ml.
Vd = Volume of distillate collected, ml.
Vic = Total volume of liquid collected in im-
pingers and silica gel, ml. Volume of water
in silica gel equals silica gel weight in-
crease in grams times 1 ml/gram. Volume
of liquid collected in impinger equals final
volume minus initial volume.
Vm = Volume of gas sample as measured by
dry gas meter, dcm (dcf).
Vm<*n> Volume of gas sample measured by
the dry gas meter corrected to standard
conditions, dscm (dscf).
Vice, i « = Volume of water vapor in the gas
sample corrected to standard conditions,
som (scf).
Vi = Total volume of sample, ml.
D» = Stack gas velocity, calculated by Method
2, Equation 2-7 using data obtained from
Method 5, m/sec (ft/sec).
Wa = Weight of residue in acetone wash, mg.
&H= Average pressure differential across the
orifice (see fig. 13A-3), meter, mm HaO
(in H.O).
p,, = Density of acetone, mg/ml (see label on
bottle).
pr Density of water, 1 g/ml (0.00220 lb/
ml).
O = Total sampling time, min.
13.6=iSpecific gravity of mercury.
60 = Sec/min.
100 = Conversion to percent.
9.2 Average dry gas meter temperature
and average orifice pressure drop. See data
sheet (Figure 13A-3 of Method 13A).
9 3 Dry gas volume. Use Section 9.3 of
Method 13 A.
9 4 Volume of Water Vapor. Use Section
9 4 of Method 13A.
9 5 Moisture Content. Use Section 9.5 of
Method 13A.
9 6 Concentration
961 Calculate the amount of fluoride in
the sample according to equation 13B-1.
V,
F,=K-(V«) (M)
A,
where'
K = 19 mg/ml.
9.62 Concentration of fluoride in stack
gas. Use Section 9 6 2 of Method 13A.
97 Isokinetic variation. Use Section 9.7
of Method 13A.
9 8 Acceptable results. Use Section 9.8 of
Method 13A
10. References.
Bellack, Ervln, "Simplified Fluoride Distil-
lation Method." Journal of the American
Water Works Association #50: 530-6 (1958).
MacLeod, Kathryn E , and Howard L. Crist,
"Comparison of the SPADNSZirconium
Lake and Specific Ion Electrode Methods of
Fluoride Determination In Stack Emission
Samples," Analytical Chemistry 45: 1272-1273
(1973).
Martin, Robert M. "Construction Details of
Isokinetic Source Sampling Equipment,"
Environmental Protection Agency, Air Pol-
lution Control Office Publication No. APTD-
0581
1973 Annual Book of ASTM Standards, Part
23. Designation: D 1179-72.
Pom, Jerome J., "Maintenance, Calibration,
and Operation of Isokinetic Source Sampling
Equipment," Environmental Protection
Agency. Air Pollution Control Office Publica-
tion No APTD-0576.
Standard Methods for the Examination of
Water and Waste Water, published jointly by
American Public Health Association, Ameri-
can Water Works Association and Water Pol-
lution Control Federation, 13th Edition
(1971).
(Sections 111 and 114 of the Clean Air Act,
as amended by section 4(a) of Pub. L. 91-604,
84 Stat. 1678 (42 U.S C. 1857 c-6, c-9))
[FR Doc.75-20478 Filed 8-5-75;8:45 am)
FEDERAL REGISTER, VOL. 40, NO. 152WEDNESDAY, AUGUST 6, 1975
IV-7 3
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RULES AND REGULATIONS
15
[PRL 428-4]
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Delegations of Authority to State of Cali-
fornia on Behalf of Bay Area, Monterey
Bay Unified, Humboldt County and Del
Norte County Air Pollution Control Dis-
tricts
Pursuant to the delegations of author-
ity for the standards of performance for
new stationary sources (NSPS) to the
State of California on behalf of the Bay
Area and Monterey Bay Unified-Air Pol-
lution Control Districts (dated May 23,
1975), and on behalf of the Humboldt
County and Del Norte County Air Pol-
lution Control Districts (dated July 10,
1975), EPA is today amending 40 CFB
60.4, Address, to reflect these delegations.
Notices announcing these delegations
are published today in the Notices Sec-
tion of this issue. The amended § 60.4
is set forth below. It adds the addresses
of the Bay Area, Monterey Bay Unified,
Humboldt County and Del Norte County
Air Pollution Control Districts, to which
must be addressed all reports, requests,
applications, submittals, and communi-
cations pursuant to this part by sources
subject to the NSPS located within these
Air Pollution Control Districts.
The Administrator finds good cause
for foregoing prior public notice and for
making this rulemaklng effective im-
mediately in that It is an administrative
change and not one of substantive con-
tent. No additional substantive burdens
are imposed on the parties affected. The
delegations -which are reflected by this
administrative amendment were effec-
tive on May 23, 1975 (Bay Area and
Monterey Bay Districts) and on July 10,
1975 (Humboldt County and Del Norte
County Districts) and it serves no pur-
pose to delay the technical change of
this addition of the Air Pollution Control
D'strict addresses to the Code cf Federal
Regulations.
This rulemaklng is effective Immedi-
ately, and Is issued tinder the authority
of section 111 of the Clean Air Act, as
amended. 42 U.S.C. 1857c-6.
Dated: September 6,1975.
STANLEY W. LEGRO,
Assistant Administrator for
Enforcement.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations Is amended
as follows:
1. In § 60.4, paragraph (b) is amended
by revising subparagraph (F) ,.to read as
follows:
§ 60.4 Address.
*****
(b) * *
(A)-(E) * * -
(P) California
Bay Area Air Pollution Control District,
939 Ellis St., San Francisco, CA 04109.
Del Norte County Ate Pollution Control
District, 5600 3. Broadway, Eureka, CA
85501.
Humboldt County Air Pollution Control
District, 5600 S. BroadTiray, Eureka, CA 98501.
Monterey Bay Unified Air Pollution Control
District, 420 Church St. (P.O. Box 487), Sa-
linas, CA 93901.
[PR Doc.75-24202 Piled 9-10-75;8'45 am]
FEDERAL REGISTER, VOL 40, NO. 177-
-THURSDAY, SEPTEMBER 11, 1975
IV-74
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43850
RULES AND REGULATIONS
Title 40Protection of Environment
CHAPTER IENVIRONMENTAL
PROTECTION AGENCY
SUSCHAFTER CAIR PROGRAMS
[FRL 407-3]
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Electric Arc Furnaces in the Steel Industry
On October 21, 1974 (39 FR 37466),
under section 111 of the Clean Air Act,
as amended, the Environmental Protec-
tion Agency (EPA) proposed standards
of performance for new and modified
electric arc furnaces in the steel industry.
Interested persons participated in the
rulemaklng by submitting written com-
ments to EPA. A total of 19 comment let-
ters was received, seven of which came
from the industry, eight from State and
local air pollution control agencies, and
four from Federal agencies. The Free-
dom of Information Center, Room 202
West Tower, 401 M Street, S.W., Wash-
ington, D.C., has copies of the comment
letters received and a summary of the
Issues and Agency responses available for
public inspection. In addition, copies of
the issue summary and Agency responses
may be obtained upon written request
from the EPA Public Information Cen-
ter (PM-215), 401M Street, S.W., Wash-
ington, D.C. 20460 (specifyPublic
Comment Summary: Electric Arc Fur-
naces in the Steel Industry). The com-
ments have been carefully considered,
and where determined by the Adminis-
trator to be appropriate, changes have
been made to the proposed regulation
and are incorporated in the regulation
promulgated herein.
The bases for the proposed standards
are presented in "Background Informa-
tion for Standards of Performance:
Electric Arc Furnaces in the Steel In-
dustry," (EPA-450/2-74-017a, b). Copies
of this document are available on request
from the Emission Standards and En-
gineering Division, Environmental Pro-
tection Agency, Research Triangle Park,
N.C. 27711, Attention: Mr. Don R.
Goodwin.
SDMMAHY OF REGULATION
The promulgated standards of per-
formance for new and modified electric
arc furnaces in the steel industry
limit particulate matter emissions from
the control device, from the shop, and
from the dust-handling equipment.
Emissions from the control device are
limited to less than 12 mg/dscm (0.0052
gr/dscf) and 3 percent opacity. Furnace
emissions escaping capture by the collec-
tion system and exiting from the shop
are limited to zero percent opacity, but
emissions greater than this level are
allowed during charging periods and
tapping periods. Emissions from the
clust-handling equipment are limited to
less than 10 percent opacity. The regula-
tion requires monitoring of flow rates
through each separately ducted emission
capture hood and monitoring of the
pressure inside the electric arc furnace
for direct shell evacuation systems. Ad-
ditionally, continuous monitoring of
opacity of emissions from the control de-
vice is required.
SIGNIFICANT COMMENTS AND CHANGES
MADB TO THE PROPOSED RECITATION
All of the comment letters received by
EPA contained multiple comments. The
most significant comments and the dif-
ferences between the proposed and pro-
mulgated regulations are discussed below.
In addition to the discussed changes, a
number of paragraphs and sections of
the proposed regulation were reorganized
In the regulation promulgated herein.
(1) Applicability. One commentator
questioned whether electric arc furnaces
that use continuous feeding of prere-
duced ore pellets as the primary source
of Iron can comply with the proposed
standards of performance since the
standards were based on data from con-
ventionally charged furnaces. Electric
arc furnaces that use prereduced ore
pellets were not Investigated by EPA
because this process was still being re-
searched by the steel industry during
development of the standard and was
several years from extensive use on com-
mercial sized furnaces. Emissions from
this type of furnace are generated at
different rates and in different amounts
over the steel production cycle than
emissions from conventionally charged
furnaces. The proposed standards were
structured for the emission cycle of a
conventionally charged electric arc
furnace. The standards, consequently,
are not suitable for application to electric
arc furnaces that use prereduced ore
pellets- as the primary source of iron.
Even with use of best available control
technology, emissions from these fur-
naces may not be controllable to the level
of all of the standards promulgated
herein; however, over the entire cycle the
emissions may be less than those from
a well-controlled conventional electric
arc furnace. Therefore, EPA believes that
standards of performance for electric arc
furnaces using prereduced ore pellets
require a different structure than do
standards for conventionally charged
furnaces. An investigation into the emis-
sion reduction achievable and best avail-
able control technology for these fur-
naces will be conducted in the future and
standards of performance will be estab-
lished. Consequently, electric arc fur-
naces that use continuous feeding of pre-
reduced ore pellets as the primary source
of iron are not subject to the require-
ments of this subpart.
(2) Concentration standard for emis-
sions from the control device. Four com-
mentators recommended revising the
concentration standard for the control
device effluent to 18 mg/dscm (0.008 gr/
dscf) from the proposed level of 12 mg/
dscm (0.0052 gr/dscf). The argument for
the higher standard was that the pro-
posed standard had not been demon-
strated on either carbon steel shops or on
combination direct shell evacuation-
canopy hood control systems. Emission
measurement data presented in "Back-
ground Information for Standards of
Performance: Electric Arc Furnaces In
the Steel Industry" show that carbon
steel shops as well as alloy steel shops
can reduce particulate matter emissions
to less than 12 mg/dscm by application
of -well-designed fabric filter collectors.
These data also show that combination
direct shell evacuation-canopy hood sys-
tems can control emission levels to less
than 12 mg/dscm. EPA believes that re-
vising the standard to 18 mg/dscm would
allow relaxation of the design require-
ments of the fabric filter collectors which
are installed to meet the standard. Ac-
cordingly, the standard promulgated
herein limits particulate matter emis-
sions from the control device to less than
12 mg/dscm.
Two commentators requested that spe-
cific concentration and opacity stand-
ards be established for emissions from
scrubber controlled direct shell evacua-
tion systems. The argument for a sep-
arate concentration standard was that
emissions from scrubber controlled direct
shell evacuation systems can be reduced
to only about 50 mg/dscm (0.022 gr/
dscf) and, thus, even with the proposed
proration provisions under § 60.274(b).
It Is not possible to use scrubbers and
comply with the proposed concentration
standard. The commentators also argued
that a separate opacity standard was
necessary for scrubber equipped systems
because the effluent is more concentrated
and, thus, reflects and scatters more vis-
ible light than the effluent from fabric
filter collectors.
EPA would like- to emphasize that use
of venturi scrubbers to control the efflu-
ent from direct shell evacuation systems
is not considered to be a "best system of
emission reduction considering costs."
The promulgated standards of perform-
ance for electric arc furnaces reflect
the degree of emission reduction achiev-
able for systems discharging emissions
through fabric filter collectors. EPA be-
lieves, however, that the regulation does
not preclude use of control systems that
discharge direct shell evacuation system
emissions through venturi scrubbers.
Available Information Indicates that
effluent from a direct shell evacuation
system can be controlled to 0.01 gr/dsci
or less using a high energy venturi scrub-
ber (pressure drop greater than 60 in.
w.g.). If the scrubber reduces particulate
matter emissions to 0.01 gr/dscf, then the
fabric filter collector is only required to
reduce the-emissions from the canopy
hood to about 0.004 gr/dscf in order for
the emission rates to be less than 0.0052
gr/dscf. Therefore, it is technically feasi-
ble for a faculty to use a high energy
scrubber and a fabric filter to control the
combined furnace emissions to less than
0.0052 gr/dscf. A concentration standard
of 0.022 gr/dscf for scrubbers would not
require installation of control devices
which have a collection efficiency com-
parable to that of best control technology
(well-designed and well-operated fabric
filter collector). In addition, electric arc
furnace particulate matter emissions are
invisible to the human eye at effluent
concentrations less than 0.01 gr/dscf
FEDERAL REGISTER, VOL. 40, NO. 185TUESDAY, SEPTEMBER 23, 1975
IV-75
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RULES AND REGULATIONS
43831
when emitted from average diameter'
stacks. For the reasons discussed above,
neither a separate concentration stand-
ard nor a separate opacity standard will
be established as suggested by the com-
mentators.
(3) Control device opacity standard.
Four commentators suggested that the
proposed control device opacity stand-
ard either be revised from less than five
percent opacity to less than ten percent
opacity based on six-minute average val-
ues or that a time exemption be provided
for visible emissions during the cleaning
cycle of shaker-type fabric filter collec-
tors.
EPA's experience indicates that a time
exemption to allow for puffing during
the cleaning cycle of the fabric filter col-
lector is not necessary. For this appli-
cation, a well-designed and well-main-
tained fabric filter collector should nave
no visible emissions during all phases of
the operating cycle. The promulgated
opacity standard, therefore, does not pro-
vide a time exemption for puffing of the
collector during the cleaning cycle.
The suggested revision of the proposed
opacity standard to ten percent (based on
six-minute average values) was con-
sidered in light of recent changes in
Method 9 of Appendix A to this part (39
FR 39872). The revisions to Method 9
require that compliance with opacity
standards be determined by averaging
sets of 24 consecutive observations taken
at 15-second intervals (six-minute aver-
ages). All six-minute average values of
the opacity data used as the basis for
the proposed opacity standard are zero
percent. EPA believes that the ten per-
cent standard suggested by the com-
mentators would allow much less effec-
tive operation and maintenance of the
control device than is required by the
concentration standard. On the basis of
available data, a five percent opacity
standard (based on six-minute average
values) also is unnecessarily lenient.
The proposed opacity standard of zero
percent was revised slightly upward to be
consistent with previously established
opacity standards which are less strin-
gent than their associated concentration
standards without being unduly lax. The
promulgated opacity .standard limits
emissions from the control device to less
than three percent opacity (based on
averaging sets of 24 consecutive observa-
tions taken at 15-second intervals). Use
of six-minute average values to deter-
mine compliance with applicable opacity
standards makes opacity levels of any
value possible, instead of the previous
method's limitation of values at discrete
intervals of five percent opacity.
(4) Standards on emissions from the
shop. Twelve commentators questioned
the value of the shop opacity standards,
arguing that the proposed standards
are unenforceable, too lenient, or too
stringent
Commentators arguing for less strin-
gent or more stringent standards sug-
gested various alternative opacity values
for the charging or tapping period stand-
ards, different averaging periods, and a
different limitation on emissions f romthe
shop during the meltdown and refining
period of the EAF operation. Because of
these comments, the basis for these
standards was thoroughly reevaluated.
including a review of all available data
and follow-up contacts with commenta-
tors who had offered suggestions. The
follow-up contacts revealed that the sug-
gested revisions were opinions only and
were not based on actual data. The re-
evaluation of the data bases of the pro-
posed standards reaffirmed that the
standards represented levels of emission
control achievable by application of best
control technology considering costs.
Hence, EPA concluded that the standards
are reasonable (neither too stringent nor
too lenient) and that revision of these
standards is not warranted in the ab-
sence of specific information indicating
such a need.
Four commentators believed that the
proposed standards were impractical to
enforce for the following reasons:
(1) Intermingling of emissions from
non-regulated sources with emissions
from the electric arc furnaces would
make enforcement of the standards
impossible.
(2) Overlap of operations at multi-
furnace shops would make it difficult to
identify the periods in which the charg-.
ing and tapping standards are applicable.
(3) Additional manpower would be
required in order to enforce these
standards.
(4) The standards would require ac-
cess to the shop, providing the source
with notice of surveillance and the re-
sults would not be representative of rou-
tine emissions.
(5) The standards would be unen-
forceable at facilities with a mixture of
existing and new electric arc furnaces
in the same shop.
EPA considered all of the comments on
the enforceability of the proposed stand-
ards and concluded that some changes
were appropriate. The proposed regula-
tion was reconsidered with the intent of
developing more enforceable provisions
requiring the same level of control. This
effort resulted in several changes to the
regulation, which are discussed below.
The promulgated regulation retains the
proposed limitations on the opacity of
emissions exiting from the shop except
for the exemption of one minute/hour
per EAF during the refining and melt-
down periods. The purpose of this ex-
emption was to provide some allowance
for puffs due to "cave-ins" or addition of
iron ore or burnt lime through the slag
door. Only one suspected "cave-in" and
no puffs due to additions occurred during
15 hours of observations at a well-con-
trolled facility; therefore, it was con-
cluded that these brief uncontrolled puffs
do not occur frequently and whether or
not a "cave-in" has occurred is best eval-
uated on a case-by-case basis. This ap-
proach was also necessitated by recent
revisions to Method 9 (39 FR 39872)
which require basing compliance on six-
minute averages of the observations. Use
of six-minute averages of opacity read-
Ings is not consistent with allowing a
time exemption. Determination of
whether brief puffs of emissions occiir-
ring during refining and meltdown pe-
riods are due to "cave-ins" will be made
at the time of determination of compli-
ance. If such emissions are considered to
be due to a "cave-in" or other uncontroll-
able event, the evaluation may be re-
peated without any change in operating
conditions.
The purpose of the proposed opacity
standards limiting the opacity of en:is-
sions from the shop was to require good
capture of the furnace emissions. The
method for routinely enforcing these
capture requirements has been revised
in the regulation promulgated herein in
that the owner or operator is now re-
quired to demonstrate compliance with
the shop opacity standards just prior to
conducting the performance test on the
control device. This performance evalua-
tion will establish the baseline operating
flow rates for each of the canopy hoods
or other fume capture hoods and the
furnace pressures for the electric arc fur-
nace using direct shell evacuation sys-
tems. Continuous monitoring of the flow
rate 'through each separately ducted con-
trol system is required for each electric
arc furnace subject to this regulation.
Owners or operators of electric arc fur-
naces that use a direct shell evacuation
system to collect the refining and melt-
down period emissions are required to
continuously monitor the pressure inside
the furnace free space. The flow rate and
pressure data will provide a continuous
record of the operation of the control
systems. Facilities that use a building
evacuation system for capture and con-
trol of emissions are not subject to the
flow rate and pressure monitoring re-
quirements if the building roof is never
opened.
The shop opacity standards promul-
gated herein are applicable only during
demonstrations of compliance of the af-
fected facility. At all other times the
operating conditions must be maintained
at the baseline values or better. Use of
operating conditions that will result in
poorer capture of emissions constitutes
unacceptable operation and maintenance
of the affected facility. These provisions
of the promulgated regulation will allow
evaluation of the performance of the col-
lection system without interference from
other emission sources because the non-
regulated sources can be shut down for
the duration of the evaluation. The moni-
toring of operations requirements will
simplify enforcement of the regulation
because neither the enforcing agency
nor the owner or operator must show
that any apparent violation was or was
not due to operation of non-regulated
sources.
The promulgated regulation's monitor-
ing of operation requirements will add
negligible additional costs to the total
cost of complying with the promulgated
standards of performance. Flow rate
monitoring devices of sufficient accuracy
to meet the requirements of § 60.274 (b)
can be installed for $600-$4000 depend-
ing on the flow profile of the area being
monitored and the complexity of the
monitoring device. Devices that mo'nitor
FEDERAL REGISTER, VOL 40, NO. 185TUESDAY, SEPTEMBER 23, 1975
IV-7 6
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43852
RULES AND REGULATIONS
the pressure inside the free space of an.
electric arc furnace equipped with a di-
rect shell evacuation system are installed
by most owners or operators in order to
obtain better control of the furnace oper-
ation. Consequently, for most owners or
operators, the "pressure monitoring re-
quirements will only result in the addi-
tional costs for installation and operation
of a strip chart recorder. A suitable strip
chart recorder can be installed for less
than $600.
There are no data reduction require-
ments in the flow rate monitoring pro-
visions. The pressure monitoring pro-
visions for the direct shell evacuation
control systems require recording of the
pressures as 15-minute integrated aver-
ages. The pressure inside the electric arc
furnace above the slag and metal fluctu-
ates rapidly. Integration of the data over
15-minute periods is necessary to provide
an indication of the operation of the sys-
tem. Electronic and mechanical integra-
tors are available at an initial cost of less
than $600 to accomplish this task. Elec-
tronic circuits to produce a continuous
Integration of the data can be built di-
rectly into the monitoring device or can
be provided as a separate modular com-
ponent of the monitoring system. These
devices can provide a continuous inte-
grated average on a strip chart recorder.
(5) Emission monitoring. Three com-
mentators suggested deletion of the pro-
posed opacity monitoring requirements
because long path lengths and multiple
compartments in pressurized fabric filter
collectors make monitoring infeasible.
The proposed opacity monitoring require-
ments have not been deleted because
opacity monitoring is feasible on the con-
trol systems of interest (closed or suction
fabric filter collectors). This subpart also
permits use of alternative control sys-
tems which are not amenable to testing
and monitoring using existing proce-
dures, providing the owner or operator
can demonstrate compliance by alterna-
tive methods. If the owner or operator
plans to install a pressurized fabric filter
collector, he should submit for the Ad-
ministrator's approval the emission test-
ing procedures and the method of mon-
itoring the emissions of the collector. The
opacity of emissions from pressurized
fabric filter collectors can be monitored
using present instrumentation at a rea-
sonable cost. Possible alternative methods
for monitoring of emissions from pres-
surized fabric filter collectors include:
(1) monitoring of several compartments
by a conventional path length transmis-
someter and rotation of the transmis-
someter to other groups of collector"com-
partments on a scheduled basis or (2)
monitoring with several conventional
path length transmissometers. In addi-
tion to monitoring schemes based on con-
ventional path length transmissometers,
a long path transmissometer could be
used to monitor emissions from a pres-
surized fabric filter collector. Transmis-
someters capable of monitoring distances
up to 150 meters are commercially avail-
able and have been demonstrated to ac-
curately monitor opacity. Use of long
path transmissometers on pressurized
fabric filter collectors has yet to be dem-
onstrated, but if properly installed there
Is no reason to believe that the transmis-
someter will not accurately and repre-
sentatively monitor emissions. The best
location for a long path transmissometer
on a fabric filter collector will depend on
the specific design features of both;
therefore, the best location and monitor-
ing procedure must be established on an
individual basis and is subject to the
Administrator's approval.
Two commentators argued that the
proposed reporting requirements would
result in excessive paperwork for the
owner or operator. These commentators
.suggested basing the reporting require-
ments on hourly averages of the moni-
toring data. EPA believes that one-hour
averaging periods would not produce
values that would meaningfully relate to
the operation of the fabric filter collec-
tor and would not be useful for com-
parison with Method 9 observations. In
light of the revision of Method 9 to base
compliance on six-minute averages, all
six-minute periods In which the average
opacity is three percent or greater shall
be reported as periods of excess emis-
sions. EPA does not believe that this re-
quirement will result in an excessive
burden for properly operated and main-
tained facilities.
(6) Test methods and procedures.
Two commentators questioned the pre-
cision and accuracy of Method 5 of Ap-
pendix A to this part when applied to gas
streams with particulate matter con-
centrations less than 12 mg/dscm. EPA
has reviewed the sampling and analytical
error .associated with Method 5 testing
of low concentration gas streams. It was
concluded that if the recommended
minimum sample volume (160 dscf) is
used, then the errors should be within
the acceptable range for the method.
Accordingly, the recommended minimum
sample volumes and times of the pro-
posed regulation are being promulgated
unchanged.
Three commentators questioned what
methodology was to be used in testing of
open or pressurized fabric filter collec-
tors. These commentators advocated that
EPA develop a reference test method for
testing of pressurized fabric filter collec-
tors. Prom EPA's experience, develop-
ment of a single test procedure for repre-
sentative sampling of all pressurized
fabric filter collectors is not feasible be-
cause of significant variations in the de-
sign of these control devices. Test proce-
dures for demonstrating compliance with
the standard, however, can be developed
on a case-by-case basis. The promulgated
regulation does require that the owner
or operator design and construct the
control device so that representative
measurement of the particulate matter
emissions is feasible.
Provisions in 40 CFR 60.8 (b) allow the
owner or operator upon approval by the
Administrator to show compliance with
the standard of performance by use of
an "equivalent" test method or "alterna-
tive" test method. For pressurized fabric
filter collectors, the owner or operator is
responsible for development of an "alter-
native" or "equivalent" test procedure
which must be approved prior to the de-
termination of compliance.
Depending on the design of the pres-
surized fabric filter collector, the per-
formance test may require use- of an
"alternative" method which would pro-
duce results adequate to demonstrate
compliance. An "alternative" method
does not necessarily require that the
effluent be discharged through a stack.
A possible alternative procedure for test-
ing is representative sampling of emis-
sions from a randomly selected, repre-
sentative number of compartments of
the collector. If the flow rate of effluent
from the compartments or other condi-
tions are not amenable to isokinetic
sampling, then subisokinetic sampling
(that is, sampling at lower velocities
than the gas stream velocity, thus biasing
the sample toward collection of a greater
concentration than is actually present)
should be used. If a suitable "equivalent"
or "alternative" test procedure is not de-
veloped by the owner or operator, then
total enclosure of the collector and test-
ing by Method 5 of Appendix A to this
part is required.
A new paragraph has been added to
clarify that during emission testing of
pressurized fabric filter collectors the
dilution air vents must be blocked off for
the period of testing or the amount of
dilution must be determined and a cor-
rection' applied in order to accurately
determine the emission rate of the con-
trol device. The need for dilution air cor-
rection was discussed in "Background
Information for Standards of Perform-
ance: Electric Arc Furnaces in the Steel
Industry" but was not an explicit re-
quirement hi the proposed regulation.
(7) Miscellaneous. Some commenta-
tors on the proposed standards of per-
formance for ferroalloy production facil-
ities (39 FR 37470) questioned the ra-
tionale for the differences between the
electric arc furnace regulation and the
ferroalloy production facilities regulation
with respect to methods of limiting fugi-
tive emissions. The intent of both regu-
lations is to require effective capture and
control of emissions from the source. The
standards of performance for electric arc
furnaces regulate collection efficiency by
placing limitations on the opacity of
emissions from the shop. The perform-
ance of the control system is evaluated
at the shop roof and/or other areas of
emission to the atmosphere because it is
not possible to evaluate the performance
of the collection system inside the shop.
In electric arc furnace shops, collection
systems for capture of charging and tap-
ping period emissions must be located at
least 30 or 40 feet above the furnace to
allow free movement of the crane which
charges raw materials to the furnace.
Fumes from charging, tapping, and other
activities rise and accumulate in the
upper areas of the building, thus obscur-
ing visibility. Because of the poor visibil-
ity within the shop, the performance of
the emission collection system can only
be evaluated at the point .where emis-
sions are discharged to the atmosphere.
Ferroalloy electric submerged arc fur-
FEDERAL REGISTER, VOL. 40, NO. 185TUESDAY, SEPTEMBER 23, 1975
IV-7 7
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RULES AND REGULATIONS
43833
nace operations do not require this large
free space between the furnace and the
collection device (hood). Visibility
around the electric submerged axe fur-
nace is good. Consequently, the perform-
ance of the collection device on a ferro-
alloy furnace may be evaluated at the
collection area rather than at the point _
of discharge to the atmosphere.
Effective date. In accordance with sec-
tion 111 of the Act, these regulations pre-
scribing standards of performance for
electric arc furnaces in the steel indus-
try are effective on September 23, 1975,
and apply to electric arc furnaces and
their associated dust-handling equip-
ment, the construction or modification
of which was commenced after Octo-
ber 31, 1974.
Dated: September 15, 1975.
JOHN QUARLES,
Acting Administrator.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amended
as follows:
1. The table of sections is amended by
adding subpart AA as follows:
» * » *
Subpart AAStandards of Performance for Steel
Plants: Electric Arc Furnaces
60.270 Applicability and designation of af-
fected facility.
60.271 Definitions.
60.272 Standard for partlculate matter.
S0.273 Emission monitoring.
50.274 Monitoring of operations.
60.275 Test methods and procedures.
*****
2. Fart 60 is amended by adding sub-
part AA as follows:
*****
Subpart AAStandards of Performance
for Steel Plants: Electric Arc Furnaces
§ 60.270 Applicability and designation
of affected facility.
The provisions of this subpart are ap-
plicable to the following affected facili-
ties in steel plants: electric arc furnaces
and dust-handling equipment.
§ 60.271 Definitions.
As used in this subpart, all terms not
denned herein shall have the meaning
given them in the Act and in subpart A
of this part.
(a) "Electric arc furnace" (EAF)
means any furnace that produces molten
steel and Cheats the charge materials
with electric arcs from carbon electrodes.
Furnaces from which the molten steel is
cast into the shape of finished products,
such as in a foundry, are not affected fa-
cilities included within the scope of this
definition. Furnaces which, as the pri-
mary source of iron, continuously feed
prereduced ore pellets are not affected
facilities -within the scope of this
definition.
(b) "Dust-handling equipment" means
any equipment used to handle particu-
late matter collected by the control de-
vice and located at or near the control
device for an EAF subject to this sub-
part.
(c) "Control device" means the air
pollution control equipment used to re-
move particulate matter generated by
an EAF(s) from the effluent gas stream.
(d) "Capture system" means the
equipment (including ducts, hoods, fans,
dampers, etc.) used tp capture or trans-
port particulate matter generated by an
EAF to the air pollution control device.
(e) "Charge" means the addition of
iron and steel scrap or other materials
into the top of an electric arc furnace.
(f) "Charging period" means the time
period commencing at the moment an
EAF starts to open and ending either
three minutes after the EAF roof is
returned to its closed position or six
minutes after commencement of open-
ing of the roof, whichever is longer.
(g) "Tap" means the pouring of
molten steel from an EAF.
(h) "Tapping period" means the time
period commencing at the moment an
EAF begins to tilt to pour and ending
either- three minutes after an EAF re-
turns to an upright position or six
minutes after commencing to tilt, which-
ever is longer.
(i) "Meltdown and refining" means
that phase of the steel production cycle
when charge material is melted and un-
desirable elements are removed from the
metal.
(j) "Meltdown and refining period"
means the time period commencing at
the termination of the initial charging
period and ending at the initiation of the
tapping period, excluding any intermedi-
ate charging periods.
(k) "Shop opacity" means the arith-
metic average of 24 or more opacity ob-
servations of emissions from the shop
taken in accordance with Method 9 of
Appendix A of this part for the applica-
ble time periods.
(1) "Heat time" means the period
commencing when scrap is charged to an
empty EAF and terminating when the
EAF tap is completed.
(m) "Shop" means the building which
houses one or more EAF's.
(n) "Direct shell evacuation system"
means any system that maintains a neg-
ative pressure within the EAF above the
slag or metal and ducts these emissions
to the control device.
§ 60.272 Standard for paniculate mat-
ter.
(a) On and after the date on which
the performance test required to be con-
ducted by 5 60.8 is completed, no owner
or operator subject to the provisions of
this subpart shall cause to be discharged
into the atmosphere from an electric arc
furnace any gases which:
(1) Exit from a control device and
contain particulate matter in excess of
12 mg/dscm (0.0052 gr/dscf).
(2) Exit from a control device and ex-
hibit three percent opacity or greater.
(3) Exit from a shop and, due solely
to operations of any EAF(s), exhibit
greater than zero percent shop opacity
except:
(i) Shop opacity greater than zero per-
cent, but less than 20 percent, may occur
during charging periods.
(ii) Shop opacity greater than zero
percent, but less than 40 percent, may
occur during tapping periods.
(iii) Opacity standards under para-
graph (a) (3) of this section shall apply
only during periods when flow rates and
pressures are being established under
160.274 (c) and (f).
(iv) Where the capture system is op-
erated such that the roof of the shop is
closed during the charge and the tap,
and emissions to the atmosphere are pre-
vented until the roof is opened after
completion of the charge or tap, the shop
opacity standards under paragraph (a)
(3) of this section shall apply when the
roof is opened and shall continue to ap-
ply for the length of time defined by the
charging and/or tapping periods.
(b) On and after the date on which the
performance test required to be con-
ducted by § 60.8 is completed, no owner
or operator subject to the provisions of
this subpart shall cause to be discharged
into the atmosphere from dust-handling
equipment any gases which exhibit 10
percent opacity or greater.
§ 60.273 Emission monitoring.
(a) A continuous monitoring system
for the measurement of the opacity of
emissions discharged into the atmosphere
from the control device(s) shall be in-
stalled, calibrated, maintained, and op-
erated by the owner or operator subject
to the provisions of this subpart.
(b) For the purpose of reports under
§ 60.7 (c), periods of excess emissions that
shall be reported are defined as all six-
minute periods during which the aver-
age opacity is three percent or greater.
§ 60.274 Monitoring of operations.
(a) The owner or operator subject to
the provisions of this subpart shall main-
tain records daily of the following infor-
mation:
(1) Time and duration of each
charge;
(2) Time and duration of each tap;
(3) All flow rate data obtained under
paragraph (b). of this section, or equiva-
lent obtained under paragraph (d) of
this section; and
(4) .All pressure data obtained under
paragraph (e) of this section.
(b) Except as provided under para-
graph (d) of this section, the owner or
operator subject to the provisions of this
subpart shall install, calibrate, and
maintain a monitoring device that con-
tinously records the volumetric flow rate
through each separately ducted hood.
The monitoring device(s) may be in-
stalled in any appropriate location in
the exhaust duct such that reproducible
flow'rate monitoring will result. The flow
rate monitoring device (s) shall have an
accuracy of ± 10 percent over its normal
operating range and shall be calibrated
according to the manufacturer's instruc-
tions. The Administrator may require
the owner or operator to demonstrate
the accuracy of the monitoring devicefs>
relative to Methods 1 and 2 of Appendix
A of tills part.
(c) When the owner or operator of
an EAF is required to demonstrate com-
pliance with the standard under I 60.272
(a) (3) and at any other time the Ad-
ministrator may require (under section
114 of the Act, as amended), the volu-
FEDiRAl REGISTER, VOL. 40, NO. 185TUESDAY, SEPTEMBER 23, 1975
IV-7 8
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43854
RULES AND REGULATIONS
metric flow rate through each separately
ducted hood shall be determined during
all periods in which the hood is operated
for the purpose of capturing emissions
from the EAF using the monitoring de-
vice under paragraph (b) of this section.
The owner or operator may petition the
Administrator for reestablishment of
these flow rates whenever the owner or
operator can demonstrate to the Admin-
istrator's satisfaction that the EAF oper-
ating conditions upon which the flow
rates were previously established are no
longer applicable. The flow rates deter-
mined during the most recent demon-
stration of compliance shall be main-
tained (or may be exceeded) at the ap-
propriate level for each applicable period.
Operation at lower flow rates may be
considered by the Administrator to be
unacceptable operation and maintenance
of the affected facility.
(d) The owner or operator may peti-
tion the Administrator to approve any
alternative method that will provide a
continuous record of operation of each
emission capture system.
(e) Where emissions during any phase
of the heat time are controlled by use
of a direct'shell evacuation system, the
owner or operator shall install, calibrate,
and maintain a monitoring device that
continuously records the pressure in the
free space inside the EAP. The pressure
shall be recorded as 15-minute inte-
grated averages. The monitoring device-
may be installed in any appropriate lo-
cation in the EAF such that reproduc-
ible results will be obtained. The pres-
sure monitoring device shall have an ac-
curacy of ±5 mm of water gauge over
its normal operating range and shall be
calibrated according to the manufac-
turer's instructions.
(f) When the owner or operator of an
EAF Is required to demonstrate compli-
ance with the standard under § 60.272
(a) (3) and at any other time the Ad-
ministrator may require (under section
114 of the Act, as amended), the pressure
ia the free space inside the furnace shall
be determined during the meltdown and
refining period(s) using the monitoring
device under paragraph (e) of this sec-
tion. The owner or operator may peti-
tion the Administrator for reestablish-
ment of the 15-minute integrated aver-
age pressure whenever the owner or
operator can demonstrate to the Admin-
istrator's satisfaction that the EAF op-
erating conditions upon which the pres-
sures were previously established are no
longer applicable. The pressure deter-
mined during the.most recent demon-
stration of compliance shall be main-
tained at all times the EAF is operating
in a meltdown and refining period. Op-
eration at higher pressures may be con-
sidered by the Administrator to be un-
acceptable operation and maintenance
of the affected facility.
(g) Where the capture system is de-
signed and operated such that all emis-
sions are captured and ducted to a con-
trol device, the owner or operator shall
not be subject to the requirements of this
section.
§ 60.275 Test methods and procedures.
(a) Reference methods in Appendix A
of this part, except as provided under
§ 60.8(b), shall be used to determine
compliance with the standards pre-
scribed under § 60.272 as follows:
(1) Method 5 for concentration of par-
ticulate matter and associated moisture
content;
(2) Method 1 for sample and velocity
traverses;
(3) Method 2 for velocity and volu-
metric flow rate; and
(4) Method 3 for gas analysis.
(b) For Method 5, the sampling time
for each run shall be at least four hours.
When a single EAF is sampled, the sam-
pling time for each run shall also in-
clude an integral number of heats.
Shorter sampling times, when necessi-
tated by process variables or other fac-
tors, may be approved by the Admin-
istrator. The minimum sample volume
shall be 4.5 dscm (160 dscf).
(c) For the purpose of this subpart,
the owner or operator shall conduct the
demonstration of compliance with 60.-
272(a)(3) and furnish the Adminis-
trator a written report of the results of
the test.
(d) During any performance test re-
quired under § 60.8 of this part, no gase-
ous diluents may be added to the
effluent gas stream after the fabric in
any pressurized fabric filter collector,
unless the amount .of dilution is sepa-
rately determined and considered in the
determination of emissions.
(e) When more than one control de-
vice serves the EAF(s) being tested, the
concentration of particulate matter shall
be determined using the following
equation:
.
If
where:
C.=concentration of particular matter
In mg/dscm (gr/dscf) aa determined
by method 5.
A'= total number of control devices
tested.
Q,=votumetric! flow rate of the effluent
g.is stream in dscm/br (dscf/hr) S3
determined by method 2.
(C',Q,)a or (Q.),=vulue ol the applicable parameter for
each control device tested.
(f) Any control device subject to the
provisions of this subpart shall be de-
signed and constructed to allow meas-
urement of emissions using applicable
test methods and procedures.
(g) Where emissions from any EAF(s)
are combined with emissions from facili-
ties not subject to the provisions of this
subpart but controlled by a common cap-
ture system and control device, the owner
or operator may use any of the follow-
ing procedures during a. performance
test:
(1) Base compliance on control of the
combined emissions.
(2) Utilize a method acceptable to
the Administrator which compensates
for the emissions from the facilities not
subject to the provisions of this subpavt.
(3) Any combination of the criteria
of paragraphs (g) (1) and (g) (2) of this
section.
(h) Where emissions from any EAF(s)
are combined with emissions from facili-
ties not subject to the provisions of
this subpart, the owner or operator may
use any of the following procedures for
demonstrating compliance with § 60.272
(a) (3):
(1) Base compliance on control of the
combined emissions.
(2) Shut down operation of facilities
not subject to the provisions of this
subpart.
(3) Any combination of the criteria
of paragraphs (h) (1) and (h) (2) of thla
section.
(Sees. Ill and 114 of the Clean Air Act, as
amended by see. 4 (a) of Pub. L. 91-604, 84
Stat. 1678 (43 UJ3.O. 18570-6, 1857O-0))
[PR Doc.76-25138 Filed fr-22-75;8:45 am]
FEDERAL REGISTER, VOL 40, NO. 185TUESDAY, SEPTEMBER 23, 1975
IV-7 9
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17
Title 40Protection of Environment
CHAPTER IENVIRONMENTAL
PROTECTION AGENCY
SUBCHAPTER C-A: PROGRAMS
[FRL 438-3]
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Delegation of Authority To State of Cali-
fornia on Behalf of Kern County and
Trinity County Air Pollution Control Dis-
tricts
Pursuant to the delegation of authority
for the standards of performance for
new stationary sources (NSPS) to the
State of California on behalf of the Kern
County Air Pollution Control District
and the Trinity County Air Pollution
Control District, dated August 18, 1975,
EPA is today amending 40 CPR 60.4,
Address, to reflect this delegation. A No-
tice announcing this delegation is pub-
lished today at 40 FR ????. The amended
§ 60.4 is set forth below. It adds the ad-
dresses of the Kern County and Trinity
County Air Pollution Control Districts, to
which must be adressed all reports, re-
quests, applications, submittals, and
communications pursuant to this part
by sources subject to the NSPS located
within these Air Pollution Control Dis-
tricts.
The Administrator finds good cause for
foregoing prior public notice and for
making this rulemaking effective imme-
diately in that it is an administrative
change and not one of substantive con-
tent. No additional substantive burdens
are imposed on the parties affected. The
delegation which is reflected by this ad-
ministrative amendment was effective on
August 18, 1975, and it serves no pur-
pose to delay the technical change of this
addition of the Air Pollution Control Dis-
trict addresses to the Code of Federal
Regulations.
This rulemaking is effective Immedi-
ately, and is issued under the authority
of Section 111 of the Clean Air Act, as
amended. 42 U.S.C. 1857C-6.
Dated: September 25, 1975.
STANLEY W. LEGRO,
Assistant Administrator for
Enforcement.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations Is amended
as follows:
1. In § 60.4 paragraph (b) is amended
by revising paragraph F, to read as
follows:
§ 60.4 Address.
RULES ANO REGULATIONS
Trinity County Air Pollution Control Dis-
trict, Box AJ, Weaverville, CA 96093.
*****
;FR Doc.75-26271 Filed 9-30-76;8:45 omj
(b) * * *
(A)(E) »
FCalifornia
Bay Area Air Pollution Control District,
939 Ellis St., San Francisco, CA 94109.
Del Norte County Air Pollution Control
District, Courthouse, Crescent City, CA 95591.
Humboldt County Air Pollution Control
District, 5600 S. Broadway, Eureka, CA 95501.
Kern County Air Pollution Control Dis-
trict, 1700 Flower St. (P.O. Box 997), Bakers-
field, CA 93302.
Monterey Bay Unified Air Pollution Con-
trol District, 420 Church St. (P.O. Box 487).
Salinas, CA 93901.
FEDERAL REGISTER, VOL. 40, NO. 191WEDNESDAY, OCTOBER 1, 1975
IV-80
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46250
RULES AND REGULATIONS
18
(FRL 4=23-7]
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Emission Monitoring Requirements and
Revisions to Performance Testing
Methods
On September 11, 1974 (39 PR 32852),
the Environmental Protection Agency
'SPA) proposed revisions to 40 CFR Part
60, Standards of Performance for New
Stationary Sources, to establish specific
requirements pertaining to continuous
emission monitoring system performance
specifications, operating procedures, data
reduction, and reporting requirements23
These requirements would apply to new
and modified facilities covered under
Part 60, but would not apply to existing
facilities.
Simultaneously (39 FR 32871), the
Agency proposed revisions to 40 CFR
Part 51, Requirements for the Prepara-
tion, Adoption, and Submittal of Imple-
mentation Plans, which would require
States to revise their State Implementa-
tion Plans (SIP's) to include legal en-
forceable procedures requiring certain
specified stationary sources to monitor
emissions on a continuous basis. These
requirements would apply to existing fa-
cilities, which are not covered under Part
60.
Interested parties participated in the
rulemaking by sending comments to EPA.
A total of 105 comment letters were re-
ceived on the proposed revisions to Part
60 from monitoring equipment manufac-
turers, data processing equipment manu-
facturers, industrial users of monitoring
equipment, air pollution control agencies
including State, local, and EPA regional
offices, other Federal agencies, and con-
sultants. Copies of the comment letters
received and a summary of the issues and
EPA's responses are available for inspec-
tion and copying at the U.S. Environ-
mental Protection Agency, Public Infor-
mation Reference Unit, Room 2922 (EPA
Library), 401 M Street, S.W., Washing-
ton, D.C. In addition, copies of the issue
summary and EPA responses may be ob-
tained upon written request from the
EPA Public Information Center (PM-
215), 401 M Street,-S.W., Washington,
D C. 20460 (specify Public Comment
Summary: Emission Monitoring Require-
ments) . The comments have been care-
fully considered, additional information
has been collected and assessed, and
where determined by the Administrator
to be appropriate, changes have been
made to the proposed regulations. These
changes are incorporated in the regula-
tions promulgated herein.
BACKGROUND
At the time the regulations were pro-
posed (September 11, 1974), EPA had
promulgated 12 standards of perform-
ance for new stationary sources under
section 111 of the Clean Air- Act, as
amended, four of which required the af-
fected facilities to install and operate
systems which continuously monitor the
levels of pollutant emissions, where the
technical feasibility exists using cur-
rently available continuous monitoring
technology, and where the cost of the
systems is reasonable. When the four
standards that require monitoring "sys-
tems were promulgated, EPA had limited
knowledge about the operation of such.
systems because only a few systems had
been installed; thus, the requirements
were specified in general terms. EPA
initiated a program to develop perform-
ance specifications and obtain informa-
tion on the operation of continuous
monitoring systems. The program was
designed to assess the systems' accuracy,
reliability, costs, and problems related
to installation, operation, maintenance,
and data handling. The proposed regu-
lations (39 FR 32852) were based on the
results of this program.
The purpose of regulations promul-
gated herein is to establish minimum
performance specifications for continu-
ous monitoring systems, minimum data
reduction requirements, operating pro-
cedures, and reporting requirements for
those affected facilities required to in-
stall continuous monitoring systems.
The^ specifications and procedures are
designed to assure that the data obtained
from continuous monitoring systems will
be accurate and reliable and provide the
necessary information for determining
whether an owner or operator is follow-
ing proper operation and maintenance
procedures.
SIGNIFICANT COMMENTS AND CHANGES
MADE To PROPOSED REGTTLATIONS
Many of the comment letters received
by EPA contained multiple comments.
The most significant comments and the
differences between the proposed and
final regulations are discussed below.
(1) Subpart AGeneral Provisions.
The greatest number of comments re-
ceived pertained to the methodology and
expense of obtaining and reporting con-
tinuous monitoring system emission
data. Both air pollution control agencies
and affected users of monitoring equip-
ment presented the view that the pro-
posed regulations requiring *hat all
emission data be reported were exces-
sive, and that reports of only excess
emissions and retention of all the data for
two years on the affected facility's
premises is sufficient. Twenty-five com-
mentators suggested that the effective-
ness of the operation and maintenance of
an affected facility and its air pollution
control system could be determined by
reporting only excess emissions. Fifteen
others recommended deleting the report-
ing requirements entirely.
EPA has reviewed these comments and
has contacted vendors of monitoring and
data acquisition equipment for addi-
tional information to more fully assess
the impact of the proposed reporting
requirements. Consideration was also
given to the resources that would be re-
quired of EPA to enforce the proposed
requirement, the costs that would be
incurred by an affected source, and the
effectiveness of the proposed require-
ment in comparison with a requirement
to report only excess emissions. EPA
concluded that reporting only excess
emissions would assure proper operation
and maintenance of the air pollution
control equipment and would result in
lower costs to the source and allow more
effective use of EPA resources by elimi-
nating the need for handling and stor-
ing large amounts of data. Therefore,
the regulation promulgated herein re-
quires owners or operators to report only
excess emissions and to maintain a
permanent record of all emission data
for a period of two years.
In addition, the proposed specification
of minimum data reduction procedures
has been changed. Rather than requiring
integrated averages as proposed, the reg-
ulations promulgated herein also spec-
ify a method by which a minimum num-
ber of data points may be used to com-
pute average emission rates. For exam-
ple, average opacity emissions over a six-
minute period may be calculated from a
minimum of 24 data points equally
spaced over each six-minute period. Any
number of equally spaced data points in
excess of 24 or continuously integrated
data may also be used to compute six-
minute averages. This specification of
minimum computation requirements
combined with the requirement to report
only excess emissions provides source
owners and operators with maximum
flexibility to select from a wide choice of
optional data reduction procedures.
Sources which monitor only opacity and
which infrequently experience excess
emissions may choose to utilize strip
chart recorders, with or without contin-
uous six-minute integrators; whereas
sources monitoring two or more pollut-
ants plus other parameters necessary to
convert to units of the emission stand-
ard may choose to utilize existing com-
puters or electronic data processes in-
corporated with the monitoring system.
All data must be retained for two years,
but only excess emissions need be re-
duced to units of the standard. However,
in order to report excess emissions, ade-
quate procedures must be utilized to in-
sure that excess emissions are identified.
Here again, certain sources with minimal
excess emissions can determine excess
emissions by review of strip charts, while
sources with varying emission and ox-
cess air rates will most likely need to
reduce all data to units of the standard to
identify any excess emissions. The regu-
lations promulgated herein allow the use
of extractive, gaseous monitoring systems
on a time sharing basis by installing sam-
pling probes at several locations, provided
the minimum number of data points
(four per. hour) are obtained.
Several commentators stated that the
averaging periods for reduction of moni-
toring data, especially opacity, were too
short and would result in an excessive
amount of data that must be reduced and
recorded. EPA evaluated these comments
and concluded that to be useful to source
owners and operators as well as enforce-
ment agencies, the averaging time for the
continuous monitoring data should be
reasonably consistent with the averag-
ing time for the reference methods used
during performance tests. The data re-
duction requirements for opacity have
been substantially reduced because the
averaging period was changed from one
FEDERAL REGISTER, VOL. 40, NO. 194MONDAY, OCTOBER 6, 1975
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RULES AND REGULATIONS
46251
minute, which was proposed, to six min-
utes to be consistent with revisions made
to Method 9 (39 FR 39872).
Numerous comments were received on
proposed § 60.13 which resulted in several
changes. The proposed section has been
reorganized and revised in several re-
spects to accommodate the comments
and provide clarity, to more specifically
delineate the equipment subject to Per-
formance Specifications in Appendix B.
and to more specifically define require-
ments for equipment purchased prior to
September 11, 1974. The provisions in
§ 60.13 are not intended to prevent the
use of any equipment that can be demon-
strated to be reliable and accurate;
therefore, the performance of monitor-
ing systems is specified in general terms
with minimal references to specific equip-
ment types. The provisions in § 60.13(i)
are included to allow owners or operators
and equipment vendors to apply to the
Administrator for approval to use alter-
native equipment or procedures when
equipment capable of producing accurate
results may not be commercially avail-
able (e.g. condensed water vapor inter-
feres with measurement of opacity),
when unusual circumstances may justify
less costly procedures, or whe.i the owner
or operator or equipment vendor may
simply prefer to use other equipment De-
procedures that are consistent with his
cuirent practices.
Several paragraphs in § 80.13 have
been changed on the basis of the com-
ments received. In response to comments
that the monitor operating frequency re-
quirements did not consider periods when
the monitor is inoperative or undergo-
ing maintenance, calibration, and adjust-
ment, the operating frequency require-
ments have been changed. Also the fre-
quency of cycling requirement for opacity
monitors has been changed to be con-
sistent with the response time require-
ment in Performance Specification 1,
which reflects the capability of commer-
cially available equipment.
A second area that received comment
concerns maintenance performed upon
continuous monitoring systems. Six
commentators noted that the proposed
regulation requiring extensive retesting
of continuous monitoring systems for all
minor failures would discourage proper
maintenance of the systems. Two other
commentators noted the difficulty of de-
termining a general list of critical com-
ponents, the replacement of which would
automatically require a retest of the sys-
tem. Nevertheless, it is EPA's opinion
that some control must be exercised to
insure that a suitable monitoring system
is not rendered unsuitable by substantial
alteration or a lack of needed mainte-
nance. Accordingly, the regulations pro-
mulgated herein require that owners or
operators submit with the quarterly re-
port information on any repairs or modi-
fications made to the system during the
reporting period. Based upon this infor-
mation, the Administrator may review
the status of the monitoring system with
the owner or operator and, if determined
to be necessary, require retesting of the
continuous monitoring system (s).
Several commentators noted that the
proposed reporting requirements are un-
necessary for affected facilities not re-
quired to install continuous monitoring
systems. Consequently, the regulations
promulgated herein do not contain the
requirements.
Numerous comments were received
which indicated that some monitoring
systems may not be compatible with the
proposed test procedures and require-
ments. The comments were evaluated
and, where appropriate, the proposed
test procedures and requirements were
changed. The procedures and require-
ments promulgated herein are applicable
to the majority of acceptable systems;
however, EPA recognizes that there may
be some acceptable systems available
now or in the future which could not
meet the requirements. Because of this,
the regulations promulgated herein in-
clude a provision which allows the Ad-
ministrator to approve alternative testing
procedures. Eleven commentators noted
that adjustment of the monitoring in-
struments may not be necessary as a re-
sult of daily zero and span checks. Ac-
cordingly, the regulations promulgated
herein require adjustments only when
applicable 24-hour drift limits are ex-
ceeded. Four commentators stated that
it is not necessary to introduce calibra-
tion gases near the probe tips. EPA has
demonstrated in field evaluations that
this requirement is necessary in order to
assure accurate results; therefore, the
requirement has been retained. The re-
o,uirement enables detection of any dilu-
tion or absorption of pollutant gas by the
plumbing and conditioning systems prior
to the pollutant gas entering the gas
analyzer.
Provisions have been added to these
regulations to require that the gas mix-
tures used for the daily calibration check
of extractive continuous monitoring sys-
tems be traceable to National Bureau of
Standards (NBS) reference gases. Cali-
bration gases used to conduct system
evaluations under Appendix B must
either be analyzed prior to use or shown
to be traceable to NBS materials. This
traceability requirement will assure the
accuracy of the calibration gas mixtures
and the comparability of data from sys-
tems at all locations. These traceability
requirements will not be applied when-
ever the NBS materials are not available.
A list of available NBS Standard Refer-
ence Materials may be obtained from the
Office of Standard Reference Materials,
Room B311, Chemistry Building, Na-
tional Bureau of Standards, Washington,
D.C. 20234.
Recertification of the continued ac-
curacy of the calibration gas mixtures is
also necessary and should be performed
at intervals recommended by the cali-
bration gas mixture manufacturer. The
NBS materials and calibration gas mix-
tures traceable to these materials should
not be used after expiration of their
stated shelf-life. Manufacturers of cali-
bration gas mixtures generally use NBS
materials for traceability purposes,
therefore, these amendments to the reg-
ulations will not impose additional re-
quirements upon most manufacturers.
(2) Subpart- DFossil-Fuel Fired
Steam Generators. Eighteen commenta-
tors had questions or remarks concern-
ing the proposed revisions dealing with
fuel analysis. The evaluation of these
comments and discussions with coal sup-
pliers and electric utility companies led
the Agency to conclude that the pro-
posed provisions for fuel analysis are not
adequate or consistent with the current
fuel situation. An attempt was made to
revise the proposed provisions; however,
it became apparent that an in-depth
study would be necessary before mean-
ingful provisions could be developed. The
Agency has decided to promulgate all of
the regulations except those dealing with
fuel analysis. The fuel analysis provi-
sions of Subpart D have been reserved
in the regulations promulgated herein.
The Agency has initiated a study to ob-
tain the necessary information on the
variability of sulfur content in fuels, and
the capability of fossil fuel fired steam
generators to use fuel analysis and
blending to prevent excess sulfur dioxide
emissions. The results of this study will
be used to determine whether fuel anal-
ysis should be allowed as a means of
measuring excess emissions, and if al-
lowed, what procedure should be re-
quired. It should be pointed out that
this action does not affect facilities which
use flue gas desulfurization as a means
of complying with the sulfur dioxide
standard; these facilities are still re-
quired to install continuous emission
monitoring systems for sulfur dioxide.
Facilities which use low sulfur fuel as a
means of complying with the sulfur di-
oxide standard may use a continuous
sulfur dioxide monitor or fuel analysis.
For facilities that elect to use fuel anal-
ysis procedures, fuels are not required
to be sampled or analyzed for prepara-
tion of reports of excess emissions until
the Agency finalizes the procedures and
requirements.
Three commentators recommended
that carbon dioxide continuous monitor-
ing systems be allowed as an alternative
for oxygen monitoring for measurement
of the amount of diluents in flue gases
from steam generators. The Agency
agrees with this recommendation and has
included a provision which allows the use
of carbon dioxide monitors. This pro-
vision allows the use of pollutant moni-
tors that produce data on a wet basis
without requiring additional equipment
or procedures for correction of data to a
dry basis-JWhere CO; or O- data are not
collected on a consistent basis (wet or
dry) with the pollutant data, or where
oxygen is measured on a wet basis, al-
ternative procedures to provide correc-
tions for stack moisture and excess air
must be approved by the Administrator,
Similarly, use of a carbon dioxide con-
tinuous; monitoring system downstream
of a flue gas desulfurization system is not
permitted without the Administrator's
prior approval due to the potential for
absorption of CO. within the control
device. It should be noted that when any
fuel is fired directly in the stack gases
FEDERAL REGISTER, VOL. 40, NO. 194MONDAY, OCTOBER 6, 1975
iy-82
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46252
RULES AND REGULATIONS
for reheating, the- P and_ £' * factors
promulgated herein must be prorated
based upon the total heat input of the
fuels fired within the facility-regardless
of the locations of fuel firing. Therefore,
any facility using a flue gas desulfuriza-
tion system may be limited to dry basis
monitoring instrumentation due to the
restrictions on use of a CO. diluent moni-
tor unless water vapor is also measured
subject to the Administrator's approval.
Two commentators requested that an
additional factor (P ») be developed for
use with oxygen continuous monitoring
systems that measure flue gas diluents on
a wet basis. A factor of this type was
evaluated by EPA, but is not being pro-
mulgated with the regulations herein.
The error in the accuracy of the factor
may exceed ±5 percent without addi-
tional measurements to correct for va-
riations in flue gas moisture content due
to fluctuations in ambient humidity or
fuel moisture content. However, EPA will
approve installation of wet basis oxygen
systems on a case-by-case basis if the
owner or operator will proposed use of
additional measurements and procedures
to control the accuracy of the Pw factor
within acceptable limits. Applications for
approval of such systems should include
the frequency and type of additional
measurements proposed and the resulting
accuracy of the Pw factor under the ex-
tremes of operating conditions
anticipated.
One commentator stated that the pro-
posed requirements for recording heat
input are superfluous because this infor-
mation is not needed to convert monitor-
ing data to units of the applicable stand-
ard. EPA has reevaluated this require-
ment and has determined that the con-
version of excess emissions into units of
the standards will be based upon the
B1 factors and that measurement of the
rates of fuel firing will not be needed ex-
cept when combinations of fuels are fired.
Accordingly, the regulations promulgated
herein require such measurements only
\vhen multiple fuels are fired.
Thirteen commentators questioned the
rationale for the proposed increased op-
erating temperature of the Method 5
sampling train for fossil-fuel-fired steam
generator particulate testing and the
basis for raising rather than lowering
the temperature. A brief discussion of the
rationale behind this revision was pro-
vided in the preamble to the proposed
regulations, and a more detailed discus-
sion is provided here. Several factors are
of primary importance in developing the
data base for a standard of performance
and in specifying the reference method
for use in conducting a performance test,
including:
a. The method used for data gathering
to establish 9, standard must be the
same as, or must have a known relation-
ship to, the method subsequently estab-
lished as the reference method.
b. The method should measure pollut-
ant emissions indicative of the perform-
ance of the best systems of emission re-
duction. A method meeting this criterion
will not necessarily measure emissions
as they would exist after dilution and
cooling-to ambient temperature and pres-
sure, as would occur upon release to the
atmosphere. As such, an emission factor
obtained through use of such a method
would, for example, not necessarily be of
use in an ambient dispersion modeLThis
seeming inconsistency results from the
fact that standards of performance are
intended to result in installation, of sys-
tems, of emission reduction which are
consistent with best demonstrated tech-
nology, considering cost. The Adminis-
trator, in establishing1 such standards, is
required to identify best demonstrated
technology and to develop standards
which reflect such technology. In order
for these standards to be meaningful,
and for the required control' technology
to be predictable, the compliance meth-
ods must measure emissions which are
indicative of the performance of such
systems.
c. The method should include sufficient
detail as needed to produce consistent
and reliable test results.
EPA relies primarily upon Method 5
for gathering a consistent data base for
particulate matter standards. Method 5
meets the above criteria by providing de-
tailed sampling methodology and in-
cludes an out-of-stack filter to facilitate
temperature control. The latter is needed
to define particulate matter on a com-
mon basis since it is a function of tem-
perature and is not an absolute quantity.
If temperature is not controlled, and/or
if the effect of temperature upon particu-
late formation is unknown, the effect on
an emission control limitation for partic-
ulate matter may be variable and un-
predictable.
Although selection of temperature can
be varied from industry to industry, EPA
specifies a nominal sampling tempera-
ture of 120° C for most source categories
subject to standards of performance.
Reasons for selection of 120° C include
the following:
a. Piltrr temperature must be held
above 100° C at sources where moist gas
streams are present. Below 100° C, con-
densation can occur with resultant plug-
ging of filters and possible gas/liquid re-
actions. A temperature of 120° C allows
for expected temperature variation
within the train, without dropping below
100° C.
b. Matter existing in particulate form
at 120"" C is indicative of the perform-
ance of the best particulate emission re-
duction systems for most industrial proc-
esses. These include systems of emission
reduction that may involve not only the
final control device, but also the process
and stack gas conditioning systems.
c. Adherence to one established tem-
perature (even though some variation
may be needed for some source categor-
ies) allows comparison of emissions from
source category to source category. This
limited standardization used in the de-
velopment of standards of performance
is a benefit to equipment vendors and to
source owners by providing a consistent
basis for comparing test results and pre-
dicting control system performance. In
comparison, in-stack filtration takes
place at stack temperature, which usually
is not constant-from one source to- the
next. Since the temperature varies, in-
stack filtration does not necessarily pro-
vide a, consistent definition of particulate
matter and does not allow for compari-
son of various systems of -control. On
these bases, Method 5 with a sampling
filter temperature controlled at approxi-
mately 120° C was promulgated as the
applicable test method for new fossil-fuel
fired steam generators.
Subsequent to the promulgation of the
standards of performance for steam
generators, data became available indi-
cating that certain combustion products
which do not exist as particulate matter
at the elevated temperatures existing in
steam generator stacks may be collected
by Method 5 at lower temperatures (be-
low 360° C). Such material, existing in
gaseous form at stack temperature,
would not be controllable by emission re-
duction systems involving electrostatic
precipitators (ESP). Consequently,
measurement of such condensible matter
would not be indicative of the control
system performance. Studies conducted
in the past two years have confirmed that
such condensation can occur. At sources
where fuels containing 0.3 to 0.85 percent
sulfur were burned, the incremental in-
crease in particulate matter concentra-
tion resulting from sampling at 120° C
as compared to about 150° C was found
to be variable, ranging from 0.001 to
0.008 gr/scf. The variability is not neces-
sarily predictable, since total sulfur oxide
concentration, boiler design and opera-
tion, and fuel additives each appear to
have a potential effect. Eased upon these
data, it is concluded that the potential
increase in particulate concentration at
sources meeting the standard of per-
formanor for sulfur oxides is not a seri-
ous problem in comparison with the par-
ticulate standard which is approximately
0.07 gr/scf. Nevertheless, to insure that
an unusual case will not occur where a
high concentration of condensible mat-
ter, not controllable with an ESP, would
prevent attainment of the particulate
standard, the samnling temperature al-
lowed at fossil-fuel fired steam boilers is
being raised to 160° C. Since this tem-
perature is attainable at new steam gen-
erator stacks, sampling at temperatures
above 160" C would not yield results nec-
essarily representative of the capabilities.
of the best systems of emission reduction.
In evaluating particulate sampling
techniques and the effect of sampling
temperature, particular attention has
also been given to the possibility that
SO* may react in the front half of the
Method 5 train to form particulate mat-
ter. Based upon a series of comprehen-
sive tests involving both source and con-
trolled environments, EPA has developed
data that show such reactions do not oc-
cur to a significant degree.
Several control agencies commented on
the increase in sampling temperature
and suggested that the need is for sam-
pling at lower, not higher, temperatures.
This is a relevant comment and is one
which must be considered in terms of the
basis upon which standards are estab-
lished.
FEDERAL REGISTER. VOL. 40. NO.-194MONDAY. OCTOBER 6, 1975
IV-8 3
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RULES AND REGULATIONS
46253
For existing boilers which are not sub-
ject to this standard, the existence of
higher stack - temperatures and/or the
use of higher sulfur fuels may result in
significant condensation and resultant
high indicated particulate concentra-
tions when- sampling is conducted at
120° C. At one coal fired steam generator
burning coal containing approximately
three percent sulfur, EPA measurements
at 120" C showed an increase of 0.05 gr/
dscf over an average of seven runs com-
pared to samples collected at approxi-
mately 150° C. It is believed that this in-
crease resulted, in large part, if not
totally, from SO3 condensation which
would occur also when the stack emis-
sions are released into the atmosphere.
Therefore, where standards are based
upon emission reduction to achieve am-
bient air quality standards rather than
on control technology (as is the case
with the .standards promulgated herein),
a lower sampling temperature may be
appropriate.
Seven commentators questioned the
need for traversing for oxygen at 12
points within a duct during performance
tests. This requirement, which is being
revised to apply only when particulate
sampling is performed (no more than 12
points are required) is included to in-
sure that potential stratification result-
ing from air in-leakage will not ad-
versely affect the accuracy of the
particulate test.
Eight commentators stated that the
requirement for continuous monitoring
of nitrogen oxides should be deleted be-
cause only two air quality control re-
gions have ambient levels of nitrogen
dioxide that excee'd the national ambient
air quality standard for nitrogen dioxide.
Standards of performance issued under
section 111 of the Act are designed to re-
quire affected facilities to design and in-
stall the best systems of emission reduc-
tion (taking into account the cost of such
reduction). Continuous emission mon-
itoring systems jare required to insure
that the emission control systems are
operated and maintained properly. Be-
cause of .this, the Agency does not feel
that it is appropriate to delete the con-
tinuous emission monitoring system re-
quirements for nitrogen oxides; however,
in evaluating these comments the Agency
found that some situations may exist
where the nitrogen oxides monitor is not
necessary to Insure proper operation
and maintenance. The quantity of nitro-
gen oxides emitted from certain types of
furnaces is considerably below the nitro-
gen oxides emission limitation. The low
emission level is achieved through the
design of the furnace and does not re-
quire specific operating procedures or
maintenance on a continuous basis to
keep the nitrogen oxides emissions below
the applicable standard. Therefore, in
this situation, a continuous emission
monitoring system for nitrogen oxides is
unnecessary. The regulations promul-
gated herein do not require continuous
emission monitoring systems for nitrogen
oxides on facilities whose emissions are
30 percent or more below the applicable
standard.
Three commentators requested that
owners or operators of steam generators
be permitted to use NOX continuous mon-
itoring systems capable of measuring
only nitric oxide (NO) since the amount
of nitrogen dioxide (NO-) in the flue
gases is comparatively small. The reg-
ulations proposed and those promulgated
herein allow use of such systems or any
system meeting all of the requirements
of Performance Specification 2 of Ap-
pendix B. A system that measures only
nitric oxide (NO) may meet these specifi-
cations including the relative accuracy
requirement (relative to the reference
method tests which measure NO -f NO2)
without modification. However, in the
interests of maximizing the accuracy of
the system and creating conditions favor-
able to acceptance of such systems (the
cost of systems measuring only NO is
less), the owner or operator may deter-
mine the proportion of NO. relative to
NO in the flue gases and use a factor to
adjust the continuous monitoring system
emission data (e.g. 1.03 X NO = NO,)
provided that the factor is applied not
only to the performance evaluation data,
but also applied consistently to all data
generated by the continuous monitoring
system thereafter. This procedure is lim-
ited to facilities that have less than 10
percent NO. (greater than 90 percent
NO) in order to not seriously impair the
accuracy of the system due to NO= to NO
proportion fluctuations.
Section 60.45(g)(l) has been reserved
for the future specification of the excess
emissions for opacity that must be re-
ported. On November 12, 1974 (39 FR
39872), the Administrator promulgated
revisions to Subpart A, General Provi-
sions, pertaining to the opacity provi-
sions and to Reference Method 9, Visual
Determination of the Opacity of Emis-
sions from Stationary Sources. On
April 22. 1975 (40 FR 17778), the Agency
issued a notice soliciting comments on
the opacity provisions and Reference
Method 9. The Agency intends to eval-
uate the comments received and make
any appropriate revision to the opacity
provisions and Reference Method 9. In
addition, the Agency is evaluating the
opacity standards for fossil-fuel fired
steam generators under § 60.42(a) (2) to
determine if changes are needed because
of the new Reference Method 9. The pro-
visions on excess emissions for opacity
will be issued after the Agency completes
its evaluation of the opacity standard.
(3) Subpart GNitric Acid Plants.
Two commentators questioned the .long-
term validity of the proposed conversion
procedures for reducing data to units of
the standard. They suggested that the
conversion could be accomplished by
monitoririg the flue gas volumetric rate.
EPA reevaluated the proposed procedures
and found that monitoring the flue gas
volume would be the most direct method
and would also be an accurate method of
converting monitoring data, but would
require the installation of an additional
continuous monitoring system. Although
this option is available and would be ac-
ceptable subject to. the Administrator's
approval, EPA does not believe that the
additional expense this method (moni-
toring volumetric rate) would entail is
warranted. Since nitric acid plants, for
economic and technical reasons, typi-
cally operate within a fairly narrow
range of conversion efficiencies (90-96
percent) and tail gas diluents (2-5 per-
cent oxygen), the flue gas volumetric
rates are reasonably proportional to the
acid production rate. The error that
would be introduced into the data from
the maximum variation of these param-
eters is approximately 15 percent and
would usually be much less. It is expected
that the tail gas oxygen concentration
(an indication of the degree of tail gas
dilution) will be rigidly controlled at fa-
cilities using catalytic converter control
equipment. Accordingly, the proposed
procedures for data conversion have been
retained due to the small benefit that
would result from requiring additional
monitoring equipment. Other procedures
may be approved by the Administrator
under 560.13(1).
(4) Subpart HSulfuric Acid Plants.
Two commentators stated that the pro-
posed procedure for conversion of moni-
torinft data to units of the standard
would result in large data reduction
errors. EPA has evaluated morv, closelv
the operations of sulf uric acid plants and
agrees that the proposed procedure is in-
adequate. The proposed conversion pro-
cedure assumes that the operating con-
ditions of the affected facility will re-
main approximately the same as during
the continuous monitoring system eval-
uation tests. For sulfuric acid plants this
assumption is invalid. A sulfuric acid
plant is typically designed to operate at
a constant volumetric ,. throughput
(scfm). Acid production rates are altered
by by-passing portions of the process air
around the furnace or combustor to vary
the concentration of the gas entering
the converter. This procedure produces
widely varying amounts of tail gas dilu-
tion relative to the production rate. Ac-
cordingly, EPA has developed new con-
version procedures whereby the appro-
priate conversion factor is computed
from an analysis of the SO: concentra-
tion entering the converter. Air injection
plants must make additional corrections
for the diluent air .added. Measurement
of the inlet SO. is a normal quality con-
trol procedure used by most sulfuric acid
plants and does not represent an addi-
tional cost burden. The Reich test or
other suitable procedures may be used.
(5) Subpart JPetroleum Refineries.
One commentator stated that the re-
quirements for installation of continuous
monitoring systems for oxygen and fire1-"
box temperature are unnecessary and
that installation of a flame detection de-
vice would toe superior for process con-
trol purposes. Also, EPA has obtained
data which show no identifiable rela-
tionship between furnace temperature,
percent oxygen in the flue gas, and car-
bon monoxide emissions when the facil-
ity is operated in compliance with the
applicable standard. Since firebox tem-
perature and oxygen measurements may
not be preferred "by source owners and
operators for process control, and no
FEDERAL REGISTER, VOL 40, NO. 194MONDAY. OCTOBER 6, 1975
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RULES AND REGULATIONS
known method is available for transla-
tion of these measurements into quanti-
tative reports of excess carbon monoxide
emissions, this requirement appears to
be of little-use to the affected facilities
or to EPA. Accordingly, requirements for
installation of continuous monitoring
systems for measurements of firebox
temperature and oxygen are deleted from
the regulations.
Since EPA has not yet developed per-
formance specifications for carbon mon-
oxide or hydrogen sulfide continuous
monitoring systems, the type of equip-
ment that may be installed by an owner
or operator in compliance with EPA re-
quirements is undefined. Without con-
ducting performance evaluations of such
equipment, little reliance can be placed
upon the value of any data such systems
would generate. Therefore, the sections
of the regulation requiring these systems
are being reserved until EPA proposes
performance specifications-applicable to
H?S and CO monitoring systems. The
provisions of § 60.105(a) (3) do not apply
to an owner or operator electing to moni-
tor HjS. In that case, an H=S monitor
should not be installed until specific H:S
monitoring requirements are promul-
gated. At the time specifications are pro-
posed, all owners or operators who have
not entered into binding contractual ob-
ligations to purchase continuous moni-
toring equipment by October 6, 1975 23'
will be required to install a carbon
monoxide continuous monitoring system
and a hydrogen sulfide continuous moni-
toring system (unless a sulfur dioxide
continuous monitoring system -has been
installed) as applicable.
Section 60105(a)(2), which specifies
the excess emissions for opacity that
must be reported, has been reserved for
the same reasons discussed under fossil
fuel-fired steam generators. 23
(6) Appendix BPerformance Speci-
fications. A large number of comments
were received in reference to specific
technical and editorial changes needed
in the specifications. Each of these com-
ments has been reviewed and several
changes in format and procedures have
been made. These include adding align-
ment procedures for opacity monitors
and more specific instructions for select-
ing a location for installing the monitor-
ing equipment. Span requirements have
been specified so that commercially pro-
duced equipment may be standardized
where possible. The format of the speci-
fications was simplified by redefining the
requirements in terms of percent opacity,
or oxygen, or carbon dioxide, or percent
of span. The proposed requirements were
in terms of percent of the emission
standard which is less convenient or too
vague since reference to the emission
standards would have represented, a
range of pollutant concentrations de-
pending upon the amount of diluents (i.e.
excess air and water vapor) that are
present in the effluent. In order to cali-
orate gaseous monitors in terms of a
specific concentration, the requirements
were revised to delete reference to the
emission standards.
Four commentators noted that the ref-
erence methods used to evaluate con-
tinuous monitoring system performance
may be less accurate than the systems
themselves. Five other commentators
questioned the need for 27 nitrogen ox-
ides reference method tests. The ac-
curacy specification for gaseous monitor-
ing systems was specified at 20 percent, a
value in excess of the actual accuracy
of monitoring systems that provides tol-
erance for reference method inaccuracy.
Commercially available monitoring
equipment has been evaluated using these
procedures and the combined errors (i.e.
relative accuracy) in the reference meth-
ods and the monitoring systems have
been shown not to exceed 20 percent after
the data are averaged by the specified
procedures.
Twenty commentators noted that the
cost estimates contained in the proposal
did not fully reflect installation costs,
data reduction and recording costs, and
the costs of evaluating the continuous
monitoring systems. As a result, EPA
reevaluated the cost analysis. For opac-
ity monitoring alone, investment costs
including data reduction equipment and
performance tests are approximately
$20,000, and annual operating costs are
approximately $8,500. The same location
on the stack used for conduri.ing per-
formance tests with Reference Method 5
(particulate) may be used by installing
a separate set of ports for the monitoring
system so that no additional expense for
access is required. For power plants that
are required to install opacity, nitrogen
oxides, sulfur dioxide, and diluent (Oj
or CO;) monitoring systems, the invest-
ment cost is approximately $55,000, and
the operating cost is approximately $30,-
000. These v are significant costs but are
not unreasonable in comparison to the
approximately seven million dollar in-
vestment cost for the smallest steam
generation facility affected by these regu-
lations.
Effective date. These regulations are
promulgated under the authority of sec-
tions ill, 114 and 301(a) of the Clean
Air Act as amended [42 U.S.C. 1857c-6,
1857c-9, and 1857g(a) ] and become ef-
fective October 6, 1975.
Dated: September 23, 1975.
JOHN QTTARLES,
Acting Administrator
40 CFR Part 60 is amended by revising
Subparts A, D, F, G, H, I, J, L, M, and O,
and adding Appendix B as follows:
1. The table of sections is amended by
revising Subpart A and adding Appen-
dix B as follows:
Subpart AGeneral Provision*
* * # »
60.13 Monitoring requirements.
» * » » »
APPENDIX BPERFORMANCE SPECIFICATIONS
Performance Specification 1Performance
specifications and specification test proce-
dures tor transmissometer systems for con-
tinuous measurement of the opacity of stack
emissions.
Performance Specification 2Performance
specifications and specification "test proce-
dures for monitors-of SO, and NO, from
stationary sources.
Performance Specification 3Performance
specifications and specification test proce-
dures for monitors of COa and O, from, sta-
tionary sources
* » * * '
Subpart AGeneral Provisions
Section 60.2 is amended by revising
paragraph (r) and by adding paragraphs
(x), (y), and (z) as follows:
§ 60.2 Definitions.
* * « "* »
(r) "One-hour period" jneans any 60
minute period commencing on- the
hour.
*****
(x) "Six-minute period" means any
one of the 10 equal parts of a one-hour
period.
(y) "Continuous monitoring system"
means the total equipment, required
under the emission monitoring -sections
in applicable subparts, used to sample
and condition (if applicable), to analyze,
and to provide a permanent record of
emissions or process parameters.
(z) "Monitoring device" means the
total equipment, required under the
monitoring of operations sections in ap-
plicable subparts, used to measure and
record (if applicable) process param-
eters.
3. In § 60.7, paragraph (a) (5) is added
and paragraphs (b), (c), and (d) are
revised. The added and revised provisions
read as follows:
§ 60.7 Notification and record keeping.
(a) * * *
(5) A notification of the date upon
which demonstration of the continuous
monitoring system performance com-
mences in accordance with §60.13(c).
Notification shall be postmarked not less
than 30 days prior to such date.
(b) Any owner or operator subject to
the provisions of this part shall main-
tain records of the occurrence and dura-
tion of any startup, shutdown, or mal-
function in the operation of an affected
facility; any malfunction of the air pol-
lution control equipment; or any periods
during which a continuous monitoring
system or monitoring device is inopera-
tive.
(c) Each owner or operator required
to install a continuous monitoring sys-
tem shall submit a written report of
excess emissions (as defined in applicable
subparts) to the Administrator for every
calendar quarter. All quarterly reports
shall be postmarked by the 30th day fol-
lowing the end of each calendar quarter
and shall include the following informa-
tion:
(1) The magnitude of excess emissions
computed in accordance with § 60.13(h),
any conversion factor(s) used, and the
date and time of commencement and
completion of each time period of excess
emissions.
(2) Specific identification of each
period of excess emissions that occurs
during startups, shutdowns, and Dial-
functions 'of the affected facility. The.
nature and cause of any malfunction -(if
known), the corrective action taken or
preventative measures adopted
FEDERAL REGISTER, VOL. 40, NO. 194MONDAY, OCTOBER 6, 1975
IV-8 5
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RULES AND REGULATIONS
46255
(3) The date and time identifying each
period during which the~-continuous
monitoring system was inoperative ex-
cept for zero and-span checks and the
nature of the system repairs or adjust-
ments.
(4) When no excess emissions have
occurred or the continuous monitoring
systemXs) have not been inoperative, re-
paired, or adjusted, such information
shall be stated in the report.
(d) Any owner or operator subject to
the provisions of this part shall maintain
a file of all measurements, including con-
tinuous monitoring system,' monitoring
device, and performance testing meas-
urements ; all continuous monitoring sys-
tem performance evaluations; all con-
tinuous monitoring system or monitoring
device calibration checks; adjustments
and maintenance performed on these
systems or devices; and all other infor-
mation required by this part recorded in
a permanent form suitable for inspec-
tion. The file shall be retained for at least
two years following the date of such
measurements, maintenance, reports, and
records.
4. A new § 60.13 is added as follows:'
§60.13 Monitoring requirements.
(a) Unless otherwise approved by the
Administrator, or specified in applicable
subparts, the requirements of this sec-
tion shall apply to all continuous moni-
toring systems required under applicable
subparts.
(b) All continuous monitoring systems
and monitoring devices shall be installed
and operational prior to conducting per-
formance tests under § 60.8. Verification
of operational status shall, as a mini-
mum, consist of the following:
(1) For continuous monitoring sys-
tems referenced in paragraph (c) (1) of
this section, completion of the condi-
tioning period specified by applicable
requirements in Appendix B.
(2) For continuous monitoring sys-
tems referenced in paragraph (c) (2) of
this section, completion of seven days of
operation.
(3) For-monitoring devices referenced
in applicable subparts, completion of the
manufacturer's written requirements or
recommendations for checking the op-
eration or calibration of the device.
(c) During any performance tests
required under § 60.8 or within 30 days
thereafter and at such other times as
may be required by the Administrator
under section 114 of the Act, the owner
or operator of any affected facility shall
conduct continuous monitoring system
performance evaluations and furnish the
Administrator within 60 days thereof two
or, upon request, more copies of a written
report of the results of such tests. These
continuous monitoring system perform-
ance evaluations shall be conducted in
accordance with the following specifica-
tions and procedures:
(1) Continuous monitoring systems
listed within this paragraph except as
provided in paragraph (c) (2) of this sec-
tion shall be evaluated in accordance
with the requirements and-procedures
contained in the applicable perform-
ance specification -of Appendix B as
follows:
(i) Continuous monitoring systems for
measuring opacity of emissions shall
comply with Performance Specification 1.
(ii) Continuous monitoring systems for
measuring nitrogen oxides emissions
shall comply with Performance Specifi-
cation 2.
(iii) Continuous monitoring systems for
measuring sulfur dioxide emissions shall
comply with Performance Specification 2.
(iv) Continuous monitoring systems for
measuring the oxygen content or carbon
dioxide content of effluent gases shall
comply with Performance Specification
3.
(2) An owner or operator who, prior
to September 11, 1974, entered into a
binding contractual obligation to pur-
chase specific continuous monitoring
system components except as referenced
by paragraph (ci (2) (iii) of this section
shall comply with the following require-
ments:
(i) Continuous monitoring systems for
measuring opacity of emissions shall be
capable of measuring emission levels
within, ±20 percent with a confidence
level of 95 percent. The Calibration Error
Test and associated calculation proce-
dures set forth in Performance Specifi-
cation 1 of Appendix B shall be used for
demonstrating compliance with this
specification.
(ii) Continuous monitoring systems
for measurement of nitrogen oxides or
sulfur dioxide shall be capable of meas-
uring emission levels within ±20 percent
with a confidence level of 95 percent. The
Calibration Error Test, the Field Test
for Accuracy (Relative), and associated
operating and calculation procedures set
forth in Performance Specification 2 of
Appendix B shall be used for demon-
strating compliance with this specifica-
tion.
(iii) Owners or operators of all con-
tinuous monitoring systems installed on
an affected facility prior to [date of pro-
mulgation] are not required to conduct
tests under paragraphs (c) (2) (i) and/or
(ii) of this section unless requested by
the Administrator.
(3) All continuous monitoring systems
referenced by paragraph (c) (2) of this
section shall be upgraded or replaced (if
necessary) with new continuous moni-
toring systems, and such improved sys-
tems shall be demonstrated to comply
with applicable performance specifica-
tions under paragraph (c)(l) of this
section by September 11, 1979.
(d) Owners or operators of all con-
tinuous monitoring systems installed in
accordance with the provisions of this
part shall check the zero and span drift
at least once daily in accordance with
the method prescribed by the manufac-
turer of such systems unless the manu-
facturer recommends adjustments at
shorter intervals, in which case such
recommendations shall be followed. The
zero and span shall, as a minimum, be
adjusted whenever the 24-hour zero drift
or 24-hour calibration drift limits of the
applicable performance specifications in
Appendix B are exceeded. For continuous
monitoring systems measuring opacity of
emissions, the optical surfaces exposed
to the effluent gases shall be cleaned prior
to performing the zero or span drift ad-
justments except that for systems using
automatic zero adjustments, the optical
surfaces shall be cleaned when the cum-
ulative automatic zero compensation ex-
ceeds four percent opacity. Unless other-
wise approved by the Administrator, the
following procedures, as applicable, shall
be followed:
(1) For extractive continuous moni-
toring systems measuring gases, mini-
mum procedures shall include introduc-
ing applicable zero and span gas mixtures
into the measurement system as near the
probe as is practical. Span and zero gases
certified by their manufacturer to be
traceable to National Bureau of Stand-
ards reference gases shall be used when-
ever these reference gases are available.
The span and zero gas mixtures shall be
the same composition as specified in Ap-
pendix B of this part. Every six months
from date of manufacture, span and zero
gases shall be reanalyzed by conducting
triplicate analyses with Reference Meth-
ods 6 for SO2, 7 for NO,, and 3 for O2
and CO2, respectively. The gases may be
analyzed at less frequent intervals if
longer shelf lives are guaranteed by the
manufacturer.
(2) For non-extractive continuous
monitoring systems measuring gases,
minimum procedures shall include up-
scale check(s) using a certified calibra-
tion gas cell or test cell which is func-
tionally equivalent to a known gas con-
centration. The zero check may be per-
formed by computing the zero value from
upscale measurements or by mechani-
cally producing a zero condition.
(3) For continuous monitoring systems
measuring opacity of emissions, mini-
mum procedures shall include a method
for producing a simulated zero opacity
condition and an upscale (span) opacity
condition using a certified neutral den-
sity filter or other related technique to
produce a known obscuration of the light
beam. Such' procedures shall provide a
system check of the analyzer internal
optical surfaces and all electronic cir-
cuitry including the lamp and photode-
tector assembly.
(e) Except for system breakdowns, re-
pairs, calibration checks, and zero and
span adjustments required under para-
graph (d) of this section, all continuous
monitoring systems shall be in contin-
uous operation and shall meet minimum
frequency of operation requirements as
follows:
(1) All continuous monitoring systems
referenced by paragraphs (c) (1) and
(2) of this section for measuring opacity
of emissions shall complete a minimum of
one cycle of operation (sampling, ana-
lyzing, and data recording) for each suc-
cessive 10-second period.
(2) All continuous monitoring systems
referenced by paragraph (c) (1) 'of tills
section for measuring oxides of nitrogen,
sulfur dioxide, carbon dioxide, or oxygen
shall complete a minimum of one cycle
of operation (sampling, analyzing, and
data recording) for each, successive 15-
minute period.
FEDERAL REGISTER, VOL 40, NO. .194MONDAY, OCTOBER 6.,1975
IV-8 6
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RULES AND REGULATIONS
(3) All continuous monitoring systems
referenced by paragraph (c) (2) of this
section, except opacity, shall complete a
minimum of one cycle of operation (sam-
pling, analyzing, and data recording)
for each successive one-hour period.
(f) All continuous monitoring systems
or monitoring devices shall be installed
such that representative measurements
of emissions or process parameters from
the affected facility are obtained. Addi-
tional procedures for location of contin-
uous monitoring systems contained in
the applicable Performance Specifica-
tions of Appendix B of this part shall be
used.
(g) When the effluents from a single
affected facility or two or more affected
facilities subject to the same emission
standards are combined before being re-
leased to the atmosphere, the owner or
operator may install applicable contin-
uous monitoring systems on each effluent
or on the combined effluent. When the af-
fected facilities are not subject to the
same emission standards, separate con-
tinuous monitoring systems shall be in-
stalled on each effluent. When the efflu-
ent from one affected facility is released
to the atmosphere through more than
one point, the owner or operator shall
install applicable continuous monitoring
systems on each separate effluent unless
the installation of fewer systems is ap-
proved by the Administrator.
(h) Owners or operators of all con-
tinuous monitoring systems for measure-
ment of opacity shall reduce all data to
six-minute averages and for systems
other than opacity to one-hour averages
for time periods under § 60.2 (x) and (r)
respectively. Six-minute opacity averages
shall be calculated from 24 or more data
points equally spaced over each six-
minute period. For systems other than
opacity, one-hour averages shall be com-
puted from four or more data points
equally spaced over each one-hour pe-
riod. Data recorded during oeriods of sys-
tem breakdowns, repairs, calibration
checks, and zero and span adjustments
shall not be included in the data averages
computed under this paragraph. An
arithmetic or integrated average of all
data may be used. The data output of all
continuous monitoring systems may be
recorded in reduced or nonreduced form
(e.R. ppm pollutant and percent O. or
Ib/million Btu of pollutant). All excess
emissions shall be converted into units
of the standard using the applicable con-
version procedures specified in subparts.
After conversion into units of the stand-
ard, the data may be rounded to the same
number of significant digits used in sub-
parts to specify the applicable standard
(e.g., rounded to the nearest one percent
opacity).
(1) Upon written application by an
owner or operator, the Administrator may
approve alternatives to any monitoring
procedures or requirements of this part
including, but not limited to the follow-
ing:
(i) Alternative monitoring require-
ments when installation of a continuous
monitoring system or monitoring device
specified by this part would not provide
accurate measurement* due to liquid wa-
ter or other interferences caused by sub-
stances with the effluent gases.
(ii> Alternative monitoring require-
ments when the affected facility is infre-
quently operated.
(iii) Alternative monitoring' require-
ments to accommodate continuous moni-
toring systems that require additional
measurements to correct for stack mois-
ture conditions.
(iv) Alternative locations for installing
continuous monitoring systems or moni-
toring devices when the owner or opera-
tor can demonstrate that installation at
alternate locations will enable accurate
and representative measurements.
(v) Alternative methods of converting
pollutant concentration measurements to
units of the standards.
(vi) Alternative procedures for per-
forming daily checks of zero and span
drift that do not involve use of span gases
or test cells.
(vii) Alternatives to the A.S.TJvt. test
methods or sampling procedures specified
by any subpart.
(viii) Alternative continuous monitor-
ing systems that do not meet the design
or performance requirements in Perform-
ance Specification 1, Appendix B, but
adequately demonstrate a definite and
consistent relationship between its meas-
urements and the measurements of
opacity by a system complying with the
requirements in Performance Specifica-
tion 1. The Administrator may require
that such demonstration be performed
for each affected facility.
(ix) Alternative monitoring require-
ments when the effluent from a single
affected facility or the combined effluent
from two or more affected facilities are
released to the atmosphere through more
than one point.
Subpart DStandards of Performance for
Fossil Fuel-Fired Steam Generators
§ 60.42 [Amended]
5. Paragraph (a) (2) of § 60.42 is
amended by deleting the second sen-
tence.
6. Section 60.45 is amended by revis-
ing paragraphs (a), (b), (c), (d), (e),
(f), and (g) as follows:
§ 60.45 Emission and fuel monitoring.
(a) A continuous monitoring system
for measuring the opacity of emissions,
except where gaseous fuel is the only
fuel burned, shall be installed, calibrated,
maintained, and operated by the owner
or-operator. The continuous monitoring1
system shall be spanned at 80 or'90 or
100 percent opacity.
(b) A continuous monitoring system
for measuring sulfur dioxide emissions,
shall be installed, calibrated, maintained
and operated by the owner or operator
except where gaseous fuel is the only
fuel burned or where low sulfur fuels are
used to achieve compliance with the
standard under § 60.43 and fuel analyses
under paragraph (b) (2) of this section
are conducted. The following procedures
shall be used for monitoring sulfur di-
oxide emissions:
U) For affected facilities which use
continuous monitoring systems, Refer-
ence>. The span
value for the continuous monitoring sys-
tem shall be determined as follows:
(i) For affected facilities firing liquid
fossil fuel the span value shall be 1000
ppm sulfur dioxide.
(ii) For affected facilities firing solid
fossil fuel the span value shall be 1500
ppm sulfur dioxide.
(iii) For affected facilities firing fossil
fuels in any combination, the span value
shall be determined by computation in
accordance with the following formula
and rounding to the nearest 500 ppm
sulfur dioxide:
1000y-fl500z
where:
y=the fraction of total heat Input derived
from liquid fossil fuel, and
z=the fraction of total heat Input derived
from solid fossil fuel.
(iv) For affected facilities which fire
both fossil fuels and nonfossil fuels, the
span value shall be subject to the Admin-
istrator's approval.
(2) [Reserved]
(3) For affected facilities using flue gas
desulfurization systems to achieve com-
pliance with sulfur dioxide standards
under § 60.43, the continuous monitoring
system for measuring sulfur dioxide
emissions shall be located downstream
of the desulfurization system and in ac-
cordance with requirements in Perform-
ance Specification 2 of Appendix B and
the following:
(i) Owners or operators shall Install
CO: continuous monitoring systems, if
selected under paragraph (d) of this sec-
tion, at a location upstream of the desul-
furization system. This option may be
used only if the owner or operator can
demonstrate that air is not added to the
flue gas between the CO= continuous
monitoring system and the SO: continu-
ous monitoring system and each system
measures the CO, and SO- on a dry basis.
(ii) Owners or operators who install O-
continuous monitoring systems under
paragraph (d) of this section shall select
a location downstream of the desulfuri-
zation system and all measurements shall
be made on a dry basis.
(iii) If fuel of a different type than is
used in the boiler is fired directly into the
flue gas for any purpose (e.g., reheating)
the F or Fc factors used shall be pro-
rated under paragraph (f) (6) of this
section with consideration given to the
fraction of total heat input supplied by
the additional fuel. The pollutant, opac-
ity, CO-, or O3 continuous monitoring
system(s) shall be installed downstream
of any location at which fuel is fired di-
rectly into the flue gas.
(c) A continuous monitoring system
for the measurement of nitrogen oxides
emissions shall be installed, calibrated,
maintained, and operated by the owner
FEDERAL REGISTER, VOL. 40, NO. 194MONDAY, OCTOBER 6, 1975
IV-8 7
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46257
or operator except for any affected facil-
ity (demonstrated during performance
testi under S 60.8 to emit nitrogen oxides
pollutants at levels 30 percent or more
below applicable standards under § 60.44
of this part. The following procedures
shall be used for determining the span
and for calibrating nitrogen oxides con-
tinuous monitoring systems:
(1) The span value shall be determined
as follows:
(i) For affected facilities firing gaseous
fossil fuel the span value shall be 500
ppm nitrogen oxides.
(ii) For affected facilities firing liquid
fossil fuel the span value shall be 500
ppm nitrogen oxides.
(iii) For affected facilities firing solid
fossil fuel the span value shall be 1000
ppm nitrogen oxides.
(iv) For affected facilities firing fos-
sil fuels in any combination, the span
value shall be determined by computa-
tion in accordance with the following
formula and rounding to the nearest 500
ppm nitrogen oxides:
soo (x-f y) +ioooz
where:
x the fraction of tota.1 heat Input derived
from gaseous fossil fuel,
y = tbe fraction of total heat Input derived
from liquid fossil fuel, and
z=the fraction of total heat input derived
from solid fossil fuel.
(v) For affected facilities which fire
both fossi! fuels and nonfossil fuels, the
span value shall be subject to the Ad-
ministrator's approval.
(2) The pollutant gas used to prepare
calibration gas mixtures under para-
graph 2.1, Performance Specification 2
and for calibration checks under § 60.13
(d) to this part, shall be nitric oxide
(NO) . Reference Method 7 shall be used
for conducting monitoring system per-
formance evaluations under §60.13(c).
(d) A continuous monitoring system
for measuring either oxygen or carbon
dioxide in the "flue gases shall be in-
stalled, calibrated, maintained, and op-
erated by the owner or operator.
(e) An owner or operator required to
install continuous monitoring systems
under paragraphs (b) and (c) of this
section shall for each pollutant moni-
tored use the applicable conversion pro-
cedure for the purpose of converting con-
tinuous monitoring data into units of the
applicable standards (g/million cal, lb/
millionBtu) as follows:
(1) When the owner or operator elects
under paragraph (d) of this section to
measure oxygen in the flue gases, the
measurement of the pollutant concentra-
tion and oxygen concentration shall each
be on a dry basis and the following con-
version procedure shall be used:
20-9
(wet or dry) and the following conver-
sion procedure shall be used:
F-CF f 10° 1
cL%coj
where:
E, C, F,., and %CO? are determined under
paragraph (f) of this section.
(f) The values used in the equations
under paragraphs (e) (1) and (2) of this
section are derived as follows:
(1) E = pollutant emission, g/million
cal (lb/million Btu).
(2) C = pollutant concentration, g/
dscm (Ib/dscf), determined by multiply-
ing the average concentration (ppm) for
each one-hour priod by 4.15x10-' M g/
dscm per ppm (2.59X10-" M Ib/dscf per
ppm) where M = pollutant molecular
weight, g/g-mole (Ib/lb-mole). M =
64.07 for sulfur dioxide and 46.01 for
nitrogen oxides.
(3) %Oj, %CO== oxygen or carbon
dioxide volume (expressed as percent),
determined with equipment specified un-
der paragraph (d) of this section.
(4) F, Fc= a factor representing a
ratio of the volume of dry flue gases
generated to the calorific value of the
fuel combusted (F), and a factor repre-
senting a ratio of the volume of carbon
dioxide generated to the calori*ic value
of of the fuel combusted (Fr), respective-
ly. Values of F and Fc are given as fol-
lows :
(i) For anthracite coal as classified ac-
cording to A.S.T.M. D388-66, F=1.139
dscm/million cal (10140 dscf/rnilhon
Btu) and F,== 0.222 scm CO./million cal
(1980 scf CO-/millionBtu).
(ii) For sub-bituminous and bitumi-
nous coal as classified according to ASTM
D388--66, F=l .103 dscm/million cal (9820
dscf/million Btu) and Fr=0.203 scm CO../
million cal (1810 scf CO/million Btu).
(iii) For liquid fossil fuels including
crude, residual, and distillate oils, F=
1 036 dscm/million cal (9220 dscf/million
Btu) and Fc=0.161 scm CO.Vmillion cal
(1430 scf COs/million Btu).
(iv> For gaseous fossil fuels, F=0.982
dscm/million cal (8740 dscf/million
Btu). For natural gas, propane, and bu-
tane fuels, Fc-=0.117 scm CO=/million cal
(1040 scf CC>2/million Btu) for natural
gas, 0.135 scm CO./million cal (1200 scf
CO:/rnillion Btu) for propane, and 0.142
scm CO=/million cal (1260 scf COVmil-
lionBtu) for butane.
(5) The owner or operator may use
the following equation to determine an
F factor (dscm/million cal, or dscf/
million Btu) on a dry basis (if it is de-
sired to calculate F on a wet basis, con-
sult with the Administrator) or Ff factor
(scm CO/ million cal, or scf CO^/milHon
Btu) on either basis in lieu of the F or Fr
factors specified in paragraph (f) (4) of
this section:
.fi%N-28.5%Cn
--- - --
. . . .
(metric units)
_
F=
GCV
r
(English units)
Fc =
20.0 %c
GCV
321X103%C
GCV
V,20.9-%o
where:
E, C, F and %Oj are determined under
paragraph (f) of this section.
(2) When the owner or operator elects
under paragraph (d) of this section to
measure carbon dioxide in the flue gases,
the measurement of the pollutant con-
centration and the carbon dioxide con-
centration shall be on a consistent basis
(i) H, C, 6, N, and O are content by
weight of hydrogen, carbon, sulfur, ni-
trogen, and oxygen (expressed as per-
cent) , respectively, as determined on the
same basis as GCV by ultimate analysis
of the fuel fired, using A.S.T.M. method
D3178-74 or D317d (solid fuels), or com-
puted from results using A.S.T.M. meth-
ods D1137-53(70), D1945-64(73), or
D1946-67(72) (gaseous fuels) as applica-
ble.
(ii) GCV is the gross calorific value
(cal/g, Btu/lb) of the fuel combusted,
determined by the A.S.T.M. test methods
D2015-66(72) for solid fuels and D1826-
64(70) for gaseous fuels as applicable.
(6) For affected facilities firing com-
binations of fossil fuels, the F or Fc fac-
tors determined by paragraphs (f) (4)
or (5) of this section shall be prorated
in accordance with the applicable for-
mula as follows:
where:
x, y, z = the fraction of total heat
input derived from, gas-
eous, liquid, and solid fuel.
respectively.
Pi, Fj, Fi =t the value of F for gaseous,
liquid, and solid fossil
fuels respectively under
paragraphs (f) (4) or (5)
of this section.
(metric units)
(English units)
i = l
where:
xj=the fraction of total heat in-
put derived from each type fuel
(e.g., natural gas, butane, crude,
bituminous coal, etc.).
(Fc)i=the applicable Fc factor for
each fuel type determined in
accordance with paragraphs
(f) (4) and (5) of this section.
(iii) For affected facilities which fire
both fossil fuels and nonfossil fuels, the
F or Fc value shall be subject to the Ad-
ministrator's approval.
(g) For the purpose of reports required
under! 60.7(c), periods of excess emis-
sions that shall be reported are defined
as follows:
(1) [Reserved]
(2) Sulfur dioxide. Excess emissions
for affected facilities are defined as:
(i) Any three-hour- period during
which the average emissions (arithmetic
average of three contiguous one-hour p£-
riods) of sulfur dioxide as measured by a
continuous monitoring system exceed the
applicable standard under § 60.43.
(ii) [Reserved]
(3) Nitrogen oxides. Excess emissions
for affected facilities using a continuous
monitoring system for measuring nitro-
FEDERAL REGISTER, VOL. 40, NO. 194MONDAY, OCTOBER 6, 1975
IV-8 8
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46258
RULES AND REGULATIONS
gen oxides are defined as any three-hour
period during which the average emis-
sions (arithmetic average of~ three con-
tiguous one-hour periods) exceed the ap-
plicable standards under i 60.44.
7. Section 60. 46 is revised to read as
follows :
§ 60.46 Test methods and procedures.
(a) The reference methods in Appen-
dix A of this part, except as provided in,
§ 60. 8 (b) , shall be used to determine com-
pliance with the standards as prescribed
in §§ 60.42, 60.43, and 60.44 as follows:
(1) Method 1 for selection of sampling
site and sample traverses.
(2) Method 3 for gas analysis to be
used when applying Reference Methods
5, 6 and 7.
( 3 ) Method 5 for concentration of par-
ticulate matter and the associated mois-
ture content.
(4) Method 6 for concentration of SO-.
and
(5) Method 7 for concentration of
"NOx.
For Methods 6 and 7, the sampling
site shall be the same as that selected
for Method 5. The sampling point in the
duct shall be at the centroid of the cross
section or at a point no closer to the
walls than 1 m (3.28 ft). For Method 6,
the sample shall be extracted at a rate
proportional to the gas velocity at the
sampling point.
(d) For Method 6, the minimum sam-
pling time shall be 20 minutes and the
minimum sampling volume 0.02 dscm
(0.71 dscf) for each sample. The arith-
metic mean of two samples shall con-
stitute one run. Samples shall be taken
at approximately 30-minute intervals.
(e) For Method 7, each run shall con-
sist of at least four grab- samples taken
at approximately 15-minute intervals.
The arithmetic mean of the samples
shall constitute the run value.
(f) For each run using the methods
specified by paragraphs (a) (3) , (4) , and
(5) of this section, the emissions ex-
pressed in g/million cal (lb/million Btu)
shall be determined by the following
procedure:
20"9
oxygen shall be determined by using the In-
tegrated or grab sampling and analysis pro-
cedures of Method 3 as applicable. The sam-
ple shall be obtained as follows :
(i) For determination of sulfur diox-
ide and nitrogen oxides emissions, the
oxygen sample shall be obtained simul-
taneously at the same point in the duct
as used to obtain the samples for Meth-
ods 6 and 7 determinations, respectively
[§ 60.46(c)]. For Method 7, the oxygen
sample shall be obtained using the grab
sampling and analysis procedures of
Method 3.
(ii) For determination of particulate
emissions, the oxygen sample shall be
obtained simultaneously by traversing
the duct at the same sampling location
used for each run of Method 5 under
paragraph (b) of this section. Method ]
shall be used for selection of the number
of traverse points except that no more
than 12 sample points are required.
(4) F = a factor as determined in
paragraphs (f) (4), (5) or (6) of § 60.45.
(g) When combinations of fossil fuels
are flred, the heat input, expressed in
cal/hr (Btu/hr) , shall be determined
during each testing period by multiply-
ing the gross calorific value of each fuel
fired by the rate of each fuel burned.
Gross calorific value shall be determined
in accordance with A.S.T.M. methods
D2015-66(72) (solid fuels), D240-64(73)
(liquid fuels), or D 1826-64 (70) (gaseous
fuels) as applicable. The rate of fuels
burned during each testing period shall
be determined by suitable methods and
shall be confirmed by a material balance
over the steam generation system.
Subpart F Standards of Performance for
Portland Cement Plants
§ 60.62 [Amended]
8. Section 60.62 is amended by deleting
paragraph (d) .
Subpart G Standards of Performance for
Nitric Acid Plants
§ 60.72 [Amended]
9. Paragraph (a) (2) of §60.72 is
amended by deleting the second sentence.
10. Section 60.73 is amended by revis-
ing paragraphs (a), (b) , (c), and (e)
to read as follows :
§ 60.73 Emission monitoring.
(a) A continuous monitoring system
for the measurement of nitrogen oxides
shall be installed, calibrated, maintained,
and operated by the owner or operator.
The pollutant gas used to prepare cali-
bration gas mixtures under paragraph
2.1, Performance Specification 2 and for
calibration checks under I 60.13 (d) to
this part, shall be nitrogen dioxide (NO-) .
The span shall be set at 500 ppm of nitro-
gen dioxide. Reference Method 7 shall
be used for conducting monitoring sys-
tem performance evaluations under § 60.-
where:
(1) E pollutant emission g/nuillon cal
(Ib/mllllon Btu)
(2) C = pollutant concentration, g/dscm
(Ib/dscf). determined by Methods 5, 6, or 7
(3) %O, oxygen content by volume
(expressed as percent), dry basis. Percent
(b) The owner or operator shall estab-
lish a conversion factor for the purpose
of converting monitoring data into units
of the applicable standard (kg/metric
ton, Ib/short ton) . The conversion factor
shall be established by measuring emis-
sions with the continuous monitoring
system concurrent with measuring .emis-
sions with the applicable reference meth-
od tests. Using only that portion of the
continuous monitoring emission data
that represents emission measurements
concurrent with the reference method
test periods, the conversion factor shall
be determined by dividing the reference
method test data averages by the moni-
toring data averages to obtain a ratio ex-
pressed in units of the applicable stand-
ard to units of the monitoring data, i.e.,
kg/metric ton per ppm (Ib/short ton per
ppm). The conversion factor shall be re-
established during any performance test.
under § 60.8 or any continuous .monitor-
ing system performance evaluation under
§60.13(c).
(c) The owner or operator shall record
the daily production rate and hours of
operation.
*****
(e) For the purpose of reports required
under § 60.7 (c), periods of excess emis-
sions that shall be reported are defined
as any three-hour period during which
the average nitrogen oxides emissions
(arithmetic average of three contiguous
one-hour periods) as measured by a con-
tinuous monitoring system exceed the
standard under § 60.72 (a) .
Subpart H Standards of Performance for
Sulfuric Acid Plants
§ 60.83 [Amended]
11. Paragraph (a) (2) of §60.83 is
amended by deleting the second sentence.
12. Section 60.84 is amended by revis-
ing paragraphs (a), (b), (c), and (e) to
read as follows :
§ 60.84 Emission monitoring.
(a) A continuous monitoring system
for the measurement of sulfur dioxide
shall be installed, calibrated, maintained,
and operated by the owner or operator.
The pollutant gas used to prepaie cali-
bration gas mixtures under paragraph
2.1, Performance Specification 2 and for
calibration checks under § 60.13(d) to
this part, shall be sulfur dioxide (SO.).
Reference Method 8 shall be used for
conducting monitoring system perform-
ance evaluations under § 60.13(c) ex-
cept that only the sulfur dioxide portion
of the Method 8 results shall be used. The
span shall be set at 1000 ppm of sulfur
dioxide.
(b) The owner or operator shall estab-
lish a conversion factor for the purpose
of converting monitoring data into units
of the applicable standard (kg/metric
ton, Ib/short ton) . The conversion fac-
tor shall be determined, as a minimum,
three times daily by measuring the con-
centration of sulfur dioxide entering the
converter using suitable methods (e.g.,
the Reich test, National Air Pollution
Control Administration Publication No.
999-AP-13 and calculating the appro-
priate conversion factor for each eight-
hour period as follows:
J
FEDERAL REGISTER, VOL. 40, NO. 194MONDAY, OCTOBER 6, 1975
IV-8 9
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RULES AND REGULATIONS
46259
where:
CF ^conversion factor (kg/metric ton per
ppm, Ib/short ton per.ppm).
k ^constant derived from material bal-
ance. For determining CF In metric
units, k = 0.0653. For determining CF
In English units, k = 0.1306.
I == percentage of Bulfur dioxide by vol-
ume entering the gas converter. Ap-
propriate corrections must be made
for air Injection plants subject to the
Administrator's approval.
s = percentage of sulfur dfoxide by vol-
ume In the emissions to the atmos-
phere determined by the continuous
monitoring system required under
paragraph, (a) of this section.
(c) The owner or operator shall re-
:ord all conversion factors and values un-
der paragraph (b) of this section from
vhich they were computed (i.e., CP, r,
and s)
(e) For the purpose of reports under
§60.7(c), periods of excess emissions
shall be all three-hour periods (or the
arithmetic average of three consecutive
one-hour periods) during which the in-
tegrated average sulfur dioxide emissions
exceed the applicable standards under
§ 60.82.
Subpart IStandards of Performance for
Asphalt Concrete Plants
§ 60.92 [Amended]
13. Paragraph (a) (2) of § 60.92 is
amended by deleting the second sentence.
Subpart JStandards of Performance for
Petroleum Refineries
§ 60.102 [Amended]
14. Paragraph (a) (2) of §60.102 is
amended by deleting the second sentence.
15. Section 60.105 is amended by re-
vising paragraphs (a), (b), and (e) to
read as follows:
§ 60.105 Emission monitoring.
(a) Continuous monitoring systems
shall be installed, calibrated, maintained,
and operated by the owner or operator as
follows:
(1) A continuous monitoring system
for the measurement of the opacity of
emissions discharged into the atmosphere
from the fluid catalytic cracking unit cat-
alyst regenerator. The continuous moni-
toring system shall be spanned at 60, 70,
or 80 percent opacity.
(2) t Reserved!
(3) A continuous monitoring system
for the measurement of sulfur dioxide in
the gases discharged into the atmosphere
from the combustion of fuel gases (ex-
cept where a continuous monitoring sys-
tem for the measurement of hydrogen
sulfide is installed under paragraph (a'*
(4) of this section). The pollutant gas
used to prepare calibration gas mixtures
under paragraph 2.1, Performance Speci-
fication 2 and for calibration checks un-
der § 60.13 (d) to this part, shall be sul-
fur dioxide (SO2). The span shall be»set
at 100 ppm. For conducting monitoring
system performance evaluations under
§ 60.13(c), Reference Method 6 shall be
used.
(4) [Reserved]
(b) [Reserved]
*****
(e) For the purpose of reports under
§ 60.7(c)', periods of excess emissions that
shall be reported are defined as follows:
(1) [Reserved]
(2) [Reserved]
(3) [Reserved]
(4) Any six-hour period during which
the average emissions (arithmetic aver-
age of six contiguous one-hour periods)
of sulfur dioxide as measured by a con-
tinuous monitoring system exceed the
standard under § 60.104.
Subpart LStandards of Performance for
Secondary Lead Smelters
§ 60.122 [Amended]
16. Section 60.122 is amended by de-
leting paragraph (c).
*****
Subpart MStandards of Performance for
Secondary Brass and Bronze Ingot Pro-
duction Plants
§ 60.132 [Amended]
17. Section 60.132 is amended by de-
leting paragraph (c).
*****
Subpart 0Standards of Performance for
Sewage Treatment Plants
§ 60.152 [Amended]
18. Paragraph (a) (2) of § 60.152 is
amended by deleting the second sentence.
*****
19. Part 60 is amended by adding Ap-
pendix B as follows:
APPENDIX BPERFORMANCE SPECIFICATIONS
Performance Specification 1Performance
specifications and specification test proce-
dures for transmissometer systems for con-
tinuous monitoring system exceed the emis-
sions.
1 Principle and Applicability.
1 1 Principle The opacity of particulate
matter in stack emissions is measured by a
continuously operating emission measure-
ment system. These systems are based upon
the principle of transmissometry which is a
direct measurement of the attenuation cf
visible radiation (opacity) by particulate
matter in a stack effluent. Light having spe-
cfic spectral characteristics is projected from
a lamp across the stack of a pollutant source
to a light sensor. The light is attenuated due
to absorption and scatter by the particulate
matter in the effluent The percentage of
visible light attenuated Is denned as the
opacity of the emission. Transparent stack
emissions that do not attenuate light will
have a transmittance ol 100 or an opacity of
0. Opaque stack emissions that attenuate all
of the visible light will have a transmittance
of 0 or an opacity of 100 percent. The trans-
missometer is evaluated by use of neutral
density filters to determine the precision of
the continuous monitoring system. Tests of
the system are performed to determine zero
drift, Calibration drift, and response time
characteristics of the system.
1.2 Applicability. This performance spe-
cification is applicable to the continuous
monitoring systems specified In the subparts
for measuring opacity cf emissions. Specifi-
cations for continuous measurement of vis-
ible emissions are given in terms of design,
performance, and Installation parameters.
Thtse specifications contain test procedures,
installation requirements, and data compu-
tation procedures for evaluating the accept-
ability of the continuous monitoring systems
subject to approval by the Administrator.
2. Apparatus.
2.1 Calibrated Filters. Optical filters with
neutral spectral characteristics and known
optical densities to visible light or screens
known to produce specified optical densities
Calibrated filters with accuracies certified by
the manufacturer to within rt3 percent
opacitv shall be used. Filters required are
low, mid, and high-range filters with nom-
inal optical densities as follows 'When the
transmxssometer Is spanned at opacity levels
specified by applicable subparts:
Calibrated filter optical densities
with equivalent opacity in
Span value
50. . .
60
70
M)
90 -
100
PI
Low-
range
0.1 (20)
1 (20)
.1 (20)
.1 (20)
.1 (20)
.1 (20)
irenthesis
Mid-
range
0.2 (37)
.2 (37)
.3 (50)
.3 (50)
.4 (60)
.4 (60)
High-
ranpc
0.3 (50)
.3 (50)
.4 (60;
.6 (75)
.7 rso)
.9 (Si'A)
It is recommended that filter calibrations
be checked with a well-colllmated photopic
transmissometer of known linearity prior 'to
use. The filters shall be of sufficient size
to attenuate the entire light beam of the
transnrssometer.
22. Data Recorder. Analog chart recorder
or other suitable device with Input voltage
range compatible with the analyzer system
output. The resolution of the recorder's
data output shall be sufficient to allow com-
pletion of the test procedures within this
specification.
2.3 Opacity measurement System. An in-
stack transmlssometer (folded or single
path) with the optical design specifications
designated below, associated control units
and apparatus 1/o keep optical surfaces clean.
3. Definitions.
3.1 Continuous Monitoring System. The
total equipment required for the determina-
tion of pollutant opacity in a source effluent,
Continuous monitoring systems consist of
major subsystems as follows:
3.1 1 Sampling Interface. The portion of a
continuous monitoring system for opacity
that protects the analyzer from the effluent
3.1.2 Analyzer. That portion of the con-
tinuous monitoring system which senses the
pollutant and generates a signal output that
is a fur.ction of the pollutant opacity.
3 1.3 Data Recorder. That portion of the
continuous monitoring system that processes
the anelyzer output and provides a perma-
nent re x>rd of the output signal In terms of
pollutant opacity.
3.2 Transmissometer. The portions of a
continuous monitoring system for opacity
that Include the sampling Interface end the
analyze".
3.3 Span. The value of opacity at which
the continuous monitoring system is set to
produce the maximum data display output.
The span shall be set at an opacity specified
In each applicable subpart.
3.4 Calibration Error. The difference be-
tween the opacity reading Indicated by the
continuous monitoring system and the
known values of a iserles of test standards
For this method the test standards are a
series of calibrated optical filters or screens.
3.5 Zero Drift. The change In continuous
monitoring system output over a stated pe-
riod of xime of normal continuous operation
FEDERAL REGISTER, VOL. 40, NO. 194MONDAY, OCTOBER 6, 197.5
IV-90
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46260
RULES AND REGULATIONS
when, the pollutant concentration at the
time of the measurements Is. zero.
3.6 Calibration Drtft. The change In the
continuous monitoring: system output over
a stated period of time of normal continuous
operation when, the pollutant concentration
at the time of the measurements Is the same
known upscale value.
3.7 System Response. The time Interval
from a step change In opacity In the stack
at the input to the continuous monitoring
system to the time at -which 95 percent of
the corresponding final value Is reached as
displayed on the continuous monitoring sys-
tem data recorder.
3.8 Operational Test Period. A minimum
period of time over which a continuous
monitoring system is expected to operate
within certain performance specifications
without unscheduled maintenance, repair,'
or adjustment.
3.9 Transmlttance. The fraction of Incident
light that is transmitted through an optical
medium of interest.
3.10 Opacity. The fraction of incident light
that Is attenuated by an optical medium of
interest. Opacity (O) and transmittance (T)
are related as follows:
O-l T
3.11 Optical Density. A logarithmic meas-
ure of the amount of light that it attenuated
by an optical medium of interest. Optical
density (D) is related to the transmittance
and opacity as follows:
D = -log,0T
3 12 Peak Optical Response. The wave-
length of maximum sensitivity of the instru-
ment.
3.13 Mean Spectral Response. The wave-
lengtn which bisects the total area under
the curve obtained pursuant to paragraph
9.2.1.
3.14 Angle of View. The maximum (total)
angle of radiation detection by the photo-
detector assembly of the analyzer.
3 15 Angle of Projection. The maximum
(total) angle that contains 95 percent of
the radiation projected from the lamp assem-
bly of the analyzer.
3.16 Pathlength. The depth of effluent in
the light beam between the receiver and the
transmitter of the single-pass transmissom-
eter, or the depth of effluent between the
transceiver and reflector of a double-pass
transmissometer. Two pathlengths are refer-
enced by this specification:
3.16.1 Monitor Pathlength. The depth of
effluent at the installed location of the con-
tinuous monitoring system.
3.16.2 Emission Outlet Pathlength. Trie
depth of effluent at the locaaon emissions are
released to the atmosphere
4. Installation Specification.
4 I Location The transmissometer must
be located across a section of duct or stack
that will provide a particulate matter flow
through the optical volume of the trans-
missometer that is representative of the par-
ticulate matter flow through the duct or
stack It is recommended that the monitor
pathlength or depth of effluent for the trans-
missometer include the entire diameter of
the duct or stack. In installations using a
shorter pathlength. extra caution must be
used in determining the measurement loca-
tion representative of the particulate matter
flow through the duct or stack.
411 The transmissometer location shall
be downstream from all particulate control
equipment.
4.1 2 The transmissometer shall be located
as far from bends and obstructions as prac-
tical.
4.1.3 A transmissometer that Is located
in the duct or stack following a bend shall
be installed in the plane defined by the
bend where possible.
4.1.4 ,The transmissometer should be In-
stalled in an accessible location.
4.1.5 When required by the Administrator,
the owner or operator of a source must
demonstrate that the transmissometer is lo-
cated In a section of duct or stack where
a representative particulate matter distribu-
tion exists. The determination shall be ac-
complished by examining the opacity profile
of the effluent at a series of positions across
the duct or stack while the plant is In oper-
ation at maximum or reduced operating rates
or by other tests acceptable to the Adminis-
trator.
4.2 Slotted Tube. Installations that require
the use of a slotted tube shall use a slotted
tube of sufficient size and blackness so as
not to interfere with the free flow of effluent
through the entire optical volume of the
transmissometer or reflect light into the
transmissometer photodetector. Light re-
flections may be prevented by using black-
ened baffles within the slotted tube to pre-
vent the lamp radiation from impinging upon
the tube walls, by restricting the angle of
projection of the light and the angle of view
of the photodetector assembly to less than
the cross-sectional area of the slotted tube,
or by other methods. The owner or operator
must show that the manufacturer of the
monitoring system has used appropriate
methods to minimize light reflections for
systems using slotted tubes.
4.3 Data Recorder Output. The continuous
monitoring system output shall permit ex-
panded display of the span opacity on a
standard 0 to 100 percent scale Smce all
opacity standards are based on the opacity
of the effluent exhausted to the atmosphere.
the system output shall be based upon the
emission outlet pathlength and permanently-
recorded. For affected facilities whose moni-
tor pathlength is different from the facility's
emission outlet pathlength, a graph shall be
provided with the installation to show the
relationships between the continuous moni-
toring system recorded opacity based upon
the emission outlet pathlength and the opac-
ity of the effluent at the analyzer location
(monitor paf'nlength) Tests for measure-
ment of opacity that are required by this
performance specification are based upon the
monitor pathlength. The graph necessary to
convert the data recorder output to the
monitor pathlength basis shall be established
as follows:
log (1-0.) = (V12log (1-0,,)
where:
O^the opacity of the effluent based upon
li-
0, = the opacity of the effluent based upon
!.
lt:=the emission outlet pathlength.
l,=:the monitor pathlength.
5. Optical Design Specifications.
The optical design specifications set forth
In Section 6.1 shall be met in order for a
measurement system to comply with the
requirements of this method
6. Determination of Conformance with De-
sign Specifications
6 1 The continuous monitoring system for
measurement of opacity shall be demon-
strated to conform to the design specifica-
tions set forth as follows:
8.1 1 Peak Spectral Response. The peak
spectral response of the continuous moni-
toring systems shall occur between 500 nm
and 600 rim. Response at any wavelength be-
low 400 nm or above 700 nm shall be less
than 10 percent of the peak response-of the
continuous monitoring system.
6.1.2 Mean Spectral Response. The mean
spectral response of the continuous monitor-
ing system shall occur between 500 nm and
600 nm.
6 1.3 Angle of View. The total angle of view
shall be no greater than 5 degrees.
6.1.4 Angle of Projection. The total angle
of projection shall be no greater than 5 de-
gress.
6.2 Conformance with requirements under
Section 6.1 of this specification may be dem-
onstrated by the owner or operator _of the
affected facility or by the manufacturer of
the opacity measurement system. Where con-
formance is demonstrated by the manufac-
turer, certification that the tests were per-
formed, a description of the test procedures,
and the test results shall be provided by the
manufacturer, n the source owner or opera-
tor demonstrates conformance, the proce-
dures used and results obtained shall be re-
ported.
6.3 The general test procedures to be fol-
lowed to demonstrate Conformance with Sec-
tion 6 requirements are given as follows:
(These procedures will not be applicable to
all designs and will require modification In
some cases. Where analyzer and optical de-
sign is certified by the manufacturer to con-
form with the angle of view or angle of pro-
jection specifications, the respective pro-
cedures may be omitted.)
6.3.1 Spectral Response. Obtain spectral
data for detector, lamp, and filter components
used in the measurement system from their
respective manufacturers.
6 3.2 Angle of View. Set the received up
as specified by the manufacturer. Draw an
arc with radius of 3 meters. Measure the re-
ceiver response to a small (less than 3
centimeters) non-directional light source at
5-centimeter Intervals on the arc for 26 centi-
meters on either side of the detector center-
line. Repeat the test in the vertical direction.
6 3.3 Angle of Projection. Set the projector
up as specified by the manufacturer. Draw
an arc with radius of 3 meters. Using a small
photoelectric light detector (less than 3
centimeters), measure the light intensity at
5-centimeter intervals on the arc for 28
centimeters on either side of the light source
oentorline of projection. Repeat the test in
the vertical direction.
7. Continuous Monitoring System Per-
formance Specifications.
The continuous monitoring system shall
meet the performance specifications In Table
1-1 to be considered acceptable under this
method.
TABLE 1-1 Performance specifications
Parameter
Sprcificalions
a. -Calibration error <3 pet opacity.1
b Z.TO drift (24 h)..- ^2 pet opacity.1
c.Calibration drift (24 h) <2 pet opacity.1
d Response time , 10 s (maximum).
e. Operational test period 168 h.
1 Expressed as sum o( absolute mean value and the
95 pet confidence interval of a series of tests.
8. Performance Specification Test Proce-
dures. The following test procedures shall be
used to determine Conformance with the re-
quirements of paragraph 7:
8.1 Calibration Error and Response Time
Test. These tests are to be performed prior to
Installation of the system on the stack and
may be performed at the affected facility or
at other locations provided that proper notifl -
cation Is given. Set up and calibrate the
measurement system as specified by the
manufacturer's written instructions for the
monitor pathlength to be used in the In-
stallation. Span the analyzer- as specified in
applicable subparts.
8 1.1 Calibration Error Test. Insert a series
of calibration filters in the transmissometer
path at the midpoint. A minimum of three
calibration filters (low, mid, and high-
range) selected in accordance with the table
under paragraph 2 1 and calibrated within
3 percent must be used. Make a total of five
nonconsecutlve readings for each filter.
FEDERAL REGISTER, VOL. 40. NO. 194MONDAY, OCTOBER 6, 1975
iy-9i
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RULES AND REGULATIONS
46261
Record the measurement system output
readings In percent opacity. (See Figure 1-1.)
8.1.2 System Response Test. Insert the
hign-range filter In the transmlssometer
path five times and record the-time required
for the system to respond to 95 percent of
final zero and high-range filter values. (See
Figure 1-2.)
8.2 Field" Test for Zero Drift and Calibra-
tion Drift. Install the continuous monitoring
system on the affected facility and perform
the following alignments:
85.1 Preliminary Alignments. As soon as
possible after installation and once a year
thereafter when the facility is not In opera-
tion, perform the following optical and zero
alignments:
8.2.1.1 Optical Alignment. Align the light
beam from the transmlssometer upon the op-
tical surfaces located across the effluent (i.e.,
the retrofiector or photodetector as applica-
ble) in accordance with the manufacturer's
Instructions.
8.2.1.2 Zero Alignment. After the transmls-
someter has been optically aligned and the
transmissorneter mounting is mechanically
stable (i.e., no movement of the mounting
due to thermal contraction of the stack,
duct, etc.) and a clean stack condition has
been determined by a steady zero opacity
condition, perform the zero alignment. This
alignment is performed by balancing the con-
tinuous monitor system response so that any
simulated zero check coincides with an ac-
tual zero check performed across the moni-
tor pathlength of the clean stacK
8.2.1.3 Span. Span the continuous monitor-
Ing system at the opacity specified in sub-
parts and offset the zero setting at least 10
percent of span so that negative drift can be
quantified.
8.2.2. Final Alignments. After the prelimi-
nary alignments have been completed and the
affected facility has been started up and
reaches normal operating temperature, re-
check the optical alignment In accordance
with 8.2.1.1 of this specification". If the align-
ment has shifted, realign the optics, record
any detectable shift In the opacity measured
by the system that can be attributed to the
optical realignment, and notify the Admin-
istrator. This condition may not be objec-
tionable if the affected facility operates with-
in a fairly constant and adequately narrow
range of operating temperatures that does
not produce significant shifts in optical
alignment during normal operation of the
facility. Under circumstances where the facil-
ity operations produce fluctuations In the
effluent gas temperature that result in sig-
nificant misalignments, the Administrator
may require Improved mounting structures or
another location for Installation of the .trans-
missorneter.
8.2.3 Conditioning Period. After complet-
ing the post-startup alignments, operate the
system for an Initial 168-hour conditioning
period in a normal operational manner.
8.2.4 Operational Test Period. After com-
pleting the conditioning period, operate the
system lor an additional 168-hour period re-
taining the zero offset. The system shall mon-
itor the source emuent at all times except
when being zeroed or calibrated. At 24-hour
Intervals the zero and span shall be checked
according to the manufacturer's Instructions.
Minimum procedures used shall provide a
system check of the analyzer Internal mirrors
and all electronic circuitry Including the
lamp and photodetector assembly and shall
Include a procedure for producing a simu-
lated zero opacity condition and a simulated
upscale (span) opacity condition as viewed
by the receiver. The manufacturer's written
instructions may be used providing that they
equal or exceed these minimum procedures.
Zero and span the transmlssometer, clean all
optical lurfaceg exposed to the effluent, rea-
lign optics, and make any necessary adjust-
ments to the calibration of the system daily.
These zero and calibration adjustments and
optical realignments are allowed only at 24-
hour intervals or at such shorter intervals as
the manufacturer's written Instructions spec-
ify. Automatic corrections made by the
measurement system without operator inter-
vention are allowable at any time. The mag-
nitude of any zero or span drift adjustments
shall be recorded. During this 168-hour op-
erational test period, record the following at
24-hour intervals: (a) the zero reading and
span readings after the system is calibrated
(these readings should be set at the same
value at the beginning of each 24-hour pe-
riod);. (b) the zero reading after each 24
hours of operation, but before cleaning and
adjustment; and (c) tr>e span reading after
cleaning and zero adjustment, but before
span adlustment. (See Figure 1-3 )
9. Calculation, Data Analysis, and Report-
Ing.
9.1 Procedure for Determination of Mean
Values and Confidence Intervals.
9.1.1 The mean value of the data set is cal-
culated according to equation 1-1.
i
i=i Equation 1-1
where x,=r absolute value of the individual
measurements,
S = sum of the individual values.
x mean value, and
n = number of data points.
9.1.2 The 95 percent confidence interval
(two-sided) is calculated according to equa-
tion 1-2 :
Equation 1-2
where
£xi = sum of all data points,
t.»rs=ti a/2, and
C.I.S5 = 95 percent confidence interval
estimate of the average mean
value.
Values for t.975
n
2 .
3 -.
s".".~.""."'-""
6
7
8
9
..975
12.706
4 303
3.182
2.776
2 571
2 447
2 365
2.306
n
10
11
12
13
14
15
16
'.975
2 2C2
2 '28
2 201
2.170
2 100
2 145
2.131
The values in this table are already cor-
rected for n-1 degrees of freedom. Use n equal
to the number of samples as data points.
9.2 Data Analysis and Reporting.
9.2.1 Spectral Response. Combine the
spectral data obtained in accordance with
paragraph 6.3.1 to develop the effective spec-
tral response curve or the transmissometer.
Report the wavelength at which the peak
response occurs, the wavelength at which the
mean response occurs, and the maximum
response at any wavelength below 400 nm
and above 700 nm expressed as a percentage
of the peak response as required under para-
graph 6.2.
9.2.2 Angle of View. Using the data obtained
In accordance with paragraph 6.3.2, calculate
the response of the receiver as a function of
viewing angle in the horizontal and vertical
directions (26s centimeters of arc with a
radius of 3 meters equal 5 degrees). Report
relative angle of view curves as -required un-
der paragraph 6.2,
9.2.3 Angle of Projection. Using the data
obtained in accordance with paragraph 6.3.3,
calculate the response of the photoelectric
detector as a function of projection angle to
the horizontal and vertical directions. Report
relative angle of projection curves as required
under paragraph 6.2.
9.2.4 Calibration Error. Using the data from
paragraph 8.1 (Figure 1-1), subtract the
known filter opacity value from the value
shown by the measurement system for each
of the 15 readings. Calculate the mean and
95 percent confidence interval of the five dif-
ferent values at each test filter value accord-
ing to equations 1-1 and 1-2. Report the sum
of the absolute mean difference and the 95
percent confidence interval for each of the
three lest filters.
9.2.5 Zero 'Drift. Using the zero opacity
values measured every 24 hours during the
field test (paragraph 8.2), calculate the dif-
ferences between the zero point after clean-
ing, aligning, and adjustment, and the zero
value 24 hours later just prior to cleaning,
aligning, and adjustment. Calculate the
mean value of these points and the confi-
dence interval using equations 1-1 and 1-2.
Report the sum of the absolute mean value
and the 95 percent confidence Interval.
9.2.t5 Calibration Drift. Using the span
value measured every 24 hours during the
field test, calculate the differences between
the span value after cleaning, aligning, and
adjustment of zero and span, and the span
value 24 hours later just after cleaning,
aligning, and adjustment of zero and before
adjustment of span. Calculate the mean
value of these points and the confidence
interval using equations 1-1 and 1-2. Report
the sum of the absolute mean value and the
confidence Interval.
9.2.7 Response Time. Using the data from
paragraph 8.1, calculate the time interval
from filter Insertion to 95 percent of the final
stable value for all upscale and downscale
traverses. Report the mean of the 10 upscale
and downscale test times.
9.2.8 Operational Test Period. During the
168-hour operational test period, the con-
tinuous monitoring system shall not require
any corrective maintenance, repair, replace-
ment, or adjustment other than that clearly
specified as required In the manufacturer's
operation and maintenance manuals as rou-
tine and expected during a one-week period.
If the continuous monitoring system is oper-
ated within the specified performance pa-
rameters and does not require corrective
maintenance, repair, replacement, or adjust-
ment other than as specified above during
the 168-hour test period, the operational
test period shall have been successfully con-
cluded. Failure of the continuous monitor-
ing system to meet these requirements shall
call lor a repetition of the 168-hour test
period Portions of the tests which were sat-
isfactorily completed need not be repeated.
Failure to meet any performance specifica-
tion (s) shall call for a repetition of the
one-week operational test period and that
specific portion of the tests required by
paragraph 8 related to demonstrating com-
pliance with the failed specification. All
maintenance and adjustments required shall
be recorded. Output readings shall be re-
corded before and after all adjustments.
10. References.
10.1 "Experimental Statistics," Department
of Commerce, National Bureau of Standards
Handbook 91, 1963, pp. 3-31, paragraphs
3-3.1.4.
10.2 "Performance Specifications for Sta-
tionary-Source Monitoring Systems for Gases
and Visible Emissions," Environmental Pro-
tection Agency, Research Triangle Park,
N.C., tP A-650/2-74-018, January 1974.
FEDERAL REGISTER, VOL. 40. NO.-194MONDAY. OCTOBER 6. 1975
IV-92
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46262
RULES AND REGULATIONS
Calibrated Neutral Density Filter Data
(See paragraph 8.1.1)
Date of Test
Low Mid
Range % opacity Range
Span Value X opacity
_X opacity
High
Range _Jt opacity
Location of Test
Calibrated Filter'
Analyzer Reading
% Opacity
Differences
% Opacity
15
Mean difference
Confidence Interval
Calibration error = Mean Difference + C.I.
Low Hid
High
Low, mid or high range
2
Calibration filter opacity - analyzer reading
Absolute value
D«t« of Tm
Stun Filter
U«t1«A »f Twfc _____ |: ^
Jt OMCfty
Anilrtv SH* StttfiM X OMCttr
tttscal* V _MCMto
2 .,,.r_ MCM*
5
OOMRSC41* 1 SKO^i
»«co
-------
RULES AND REGULATIONS
Zero Setting
Span Setting
(Se« paragraph 8.2.1) Oite of Test
Date Zero Redding Span Reading Calibration
and (Before cleaning Zero Drift (Affr clefntng and zero adjustment Drift
Time and adjustment) 'iZero) hut before span adjustment) (aSpan)
Zero Drift ? Mean Zero Drift*
CI (Zero)
Calibration Brlft » Mean Span Drift"
CI (Span)
Absolute value
Figure 1-3. Zero and Calibration Drift Test
PERFORMANCE SPBCTTICATION 2PERFORMANCE
SPECIFICATIONS AND SFECIFICATION TEST FRO-
CFDUBES FOB MONITORS OT SOl AVD MOx
FROM STATIONABT SOURCES
1. Principle and Applicability.
1.1 Principle. The concentration of sulfur
dioxide or oxides of nitrogen pollutants in
stack emissions is measured 'oy a continu-
ously operating emission measurement sys-
tem. Concurrent with operation of the con-
tinuous monitoring system, \ihe pollutant
concentrations are also measured with refer-
ence methods (Appendix A). An average of
the continuous monitoring system data is
computed for each reference method testing
period and compared to determine the rela-
tive accuracy of the continuous monitoring
system. Other tests of the continuous mon-
itoring system are also performed to deter-
mine calibration error, drift, and response
characteristics of the system.-
1.2 Applicability. This performance spec-
ification is applicable to evaluation of con-
tinuous monitoring systems for measurement
of nitrogen oxides or sulfur dioxide pollu-
tants. These specifications contain test pro-
cedures, installation requirements, and data
computation procedures for evaluating the
acceptability of the continuous monitoring
systems.
2. Apparatus.
2.1 Calibration Gas Mixtures. Mixtures of
known concentrations of pollutant gas In a
diluent gas shall be prepared. The pollutant
gas shall be sulfur dioxide or the appropriate
oxide(s) of nitrogen specified by paragraph
6 and within subparts. For sulfur dioxide gas
mixtures, the diluent gas may be air or nitro-
gen. For nitric oxide (NO) gas mixtures, the
diluent gas shall be oxygen-tree «10 ppm)
nitrogen, and for nitrogen dioxide (NO.) gas
mixtures the diluent gas shall be air. Concen-
trations of approximately 50 percent and 90
percent of span are required. The 90 percent
gas mixture is used to set and to check the
span and is referred to as the span gas.
2.2 Zero Gas. A gas certified by the manu-
facturer to contain less than 1 ppm of the
pollutant pas or ambient air may be used.
2.3 Equipment for measurement of the pol-
lutant gas concentration using the reference
method specified in the applicable standard.
2.4 Data Recorder. Analog chart recorder
or other suitable device with input voltage
range compatible with analyzer system out-
. put. The resolution of the recorder's data
output shall be sufficient to allow completion
of the test procedures within this specifi-
cation.
2.5 Continuous monitoring system for SO,
or NO* pollutants as applicable.
3. Definitions.
3.1 Continuous Monitoring System. The
total equipment required for the determina-
tion of a pollutant gas concentration in a
source effluent. Continuous monitoring sys-
tems consist of major subsystems as follows:
3.1.1 Sampling InterfaceThat portion of
an extractive continuous monitoring system
that performs one or more of the following
operations: acquisition, transportation, and
conditioning of a sample of the source efflu-
ent or that portion of an in-situ continuous
monitoring system that protects the analyzer
from the effluent.
3.1.2 AnalyzerThat portion of the con-
tinuous monitoring system which senses the
pollutant gas and generates a signal output
that is a function of the pollutant concen-
tration.
3.1.3 Data RecorderThat portion of the
continuous monitoring system that provides
a permanent record of the output signal In
terms of concentration units.
32 Span. The value of pollutant concen-
tration at which the continuous monitor-
Ing system Is set to produce the maximum
data display output. The span shall be set
at the concentration specified in each appli-
cable subpart.
3.3 Accuracy (Relative) The degree of
correctness with which the continuous
monitoring system yields the value of gas
concentration of a sample relative to the
value, given by a defined reference method.
This accuracy Is expressed in terms of error,
which is the difference between the paired
concentration measurements expressed as a
percentage of the mean reference value.
46263
3.4 Calibration Error. The difference be-
tween the pollutant concentration indi-
cated by the continuous monitoring system
and the known concentration of the test
gas mixture.
3.5 Zero Drift. The change In the continu-
ous monitoring system output over a stated
period of time of normal continuous opera-
tion v,-hen the pollutant concentration at
the time for the measurements Is zero.
3.6 Calibration Drift. The change In the
continuous monitoring system-output over
a stated time period of normal continuous
operations when the pollutant concentra-
tion ai; the time of the measurements is the
same k nown upscale value.
3.7 Response Time. The time Interval
from 81 step change in pollutant concentra-
tion at the Input to the continuous moni-
toring system to the time at which 95 per-
cent of the corresponding final value is
reached as displayed on the continuous
monitoring system data recorder.
3.8 Operational Period. A minimum period
of time over which a measurement system
is expected to operate within certain per-
formance specifications without unsched-
uled maintenance, repair, or adjustment.
3.9 Stratification. A condition Identified
by a difference In excess of 10 percent be-
tween the average concentration In the duct
or stack and the concentration at any point
more than 1.0 meter from the duct or stack
wall.
4. Installation Specifications. Pollutant
continuous monitoring systems (SO, and
NOX) shall be Installed at a sampling loca-
tion where measurements can be made which
are directly representative (4.1), or which
can be corrected so as to be representative
(4.2) of the total emissions from the affected
facility. Conformance with this requirement
shall be accomplished as follows:
4.1 Effluent gases may be assumed to be
nonstratified if a sampling location eight or
more stack diameters (equivalent diameters)
downstream of any air in-leakage is se-
lected. This assumption and data correction
procedures under paragraph 4.2.1 may not
be applied to sampling locations upstream
of an air preheater in a stream generating
facility under Subpart D of this part. For
sampling locations where effluent gases are
either demonstrated (4.3) or may be as-
sumed to be nonstratifled (eight diameters),
a point (extractive systems) or path (in-situ
systems) of average concentration may be
monitored.
4.2 For sampling locations where effluent
gases cannot be assumed to be nonstrati-
fled (less than eight diameters) or have been
shown under paragraph 4.3 to be stratified,
results obtained must be consistently repre-
sentative (e.g. a point of average concentra-
tion may shift with load changes) or the
data generated by sampling at a point (ex-
tractive systems) or across a path (in-sltu
system:.) must be corrected (4.2.1 and 42.2)
so as to be representative of the total emis-
sions from the affected facility. Conform-
ance with this requirement may be accom-
plished In either of the following ways:
4.2.1 Installation of a diluent continuous
monitoring system (O, or CO, as applicable)
In accordance with the procedures under
paragraph 4.2 of Performance Specification
3 of this appendix. If the pollutant and
diluent monitoring systems are not of the
same type (both extractive or both In-situ),
the extractive system must use a multipoint
probe.
4.2.2 Installation of extractive pollutant
monitoring systems using multipoint sam-
pling probes or In-situ pollutant monitoring
systems that sample or view emissions which
are consistently representative of the total
emissions for the entire cross section. The
Administrator may require data to be sub-
FEDERAL REGISTER,'VOL. 40, MO. 194MONDAY, OCTOBER «, 1975
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46264
RULES AND REGULATIONS
mltted to demonstrate that the emissions
sampled or viewed are consistently repre-
sentative for several typical facility process
operating conditions.
4.3 The owner or operator may perform a
traverse to characterize any stratification of
effluent gases that might exist In a stack or
duct. If no stratification Is preseat, sampling
procedures under paragraph 4.1 may be ap-
plied even though the eight diameter criteria
Is not met.
4.4 When single point sampling probes for
extractive systems are Installed within the
stack or duct under paragraphs 4.1 and 4.2.1,
the sample may not be extracted at any point
less than 1.0 meter from the stack or duct
wall. Multipoint sampling probes Installed
under paragraph 4.2.2 may be located at any
points necessary to-obtain consistently rep-
resentative samples.
5. Continuous Monitoring System Perform-
ance Specifications.
The continuous monitoring system shall
meet the performance specifications In Table
2-1 to be considered acceptable under'this
method.
TABLE 2-1.Performance specifications
Parameter
Specification
1. Accuracy1 , <20 pet of the mean value of the reference method test
data.
2. Calibration error' < 5 pet of each (50 pet, 90 pet) calibration gas miiture
value.
3. Zero drift (2h)' 2 pet of span
4. Zero drift (24 h) > Do.
5. Calibration drift (2 h) i Do.
6. Calibration drift (24 h)' 2.5 pet. of span
7. Response time 15 rain maximum.
8. Operational period 168 h minimum.
1 Expressed as sum of absolute mean value plus 95 pet confidence interval of a series of tests.
6. Performance Specification Test Proce-
dures. The following test procedures shall be
used to determine conformance with the
requirements of paragraph 5. For NO, an-
requirements of paragraph 5. For NOx an-
alyzers that oxidize nitric oxide (NO) to
nitrogen dioxide (NO,), the response time
test under paragraph 6~.3 of this method shall
be performed using nitric oxide (NO) span
gas. Other tests for NO« continuous monitor-
ing systems under paragraphs 6.1 and 6.2 and
all tests for sulfur dioxide systems shall be
performed using the pollutant span gas spe-
cified by each subpart.
6 1 Calibration Error Test Procedure. Set
up and calibrate the complete continuous
monitoring system according to the manu-
facturer's writen instructions. This may be
accomplished either In the laboratory or In
the field.
6.1.1 Calibration Gas Analyses, Triplicate
analyses of the gas mixtures shall be per-
formed within two weeks prior to use using
Reference Methods 6 for SO and 7 for NOx.
Analyze each calibration gas mixture (50%,
90%) and record the results on the example
sheet shown In Figure 2-1. Each sample test
result must be within 20 percent of the aver-
aged result or the tests shall be repeated.
This step may be omitted for non-extractive
monitors where dynamic calibration gas mix-
tures are not used (6.1.2).
61.2 Calibration Error Test Procedure.
Make a total of 15 nonconsecutlve measure-
ments by alternately using zero gas and each
callberation gas mixture concentration (e.g.,
0~c. 50%, 0%, 90%, 50%, 90%, 50%, 0%,
etc.). For nonextractive continuous monitor-
ing systems, this test procedure may be per-
formed by using two or more calibration gas
cells whose concentrations are certified by
the manufacturer to be functionally equiva-
lent to these gas concentrations. Convert the
continuous monitoring system output read-
ings to ppm and record the results on the
example sheet shown In Figure 2-2.
6.2 Field Test for Accuracy (Relative),
Zero Drift, and Calibration Drift. Install and
operate the continuous monitoring system In
accordance with the manufacturer's written
instructions and drawings as follows:
6.2.1 Conditioning Period. Offset the zero
setting at least 10 percent of the span so
that negative zero drift can be quantified.
Operate the system for an Initial 168-hour
conditioning period In normal operating
manner.
6.2.2 Operational Test Period. Operate the
continuous monitoring system for an addi-
tional 168-hour period retaining the zero
offset. The system shall monitor the source
effluent at all times except when being
zeroed, calibrated, or backpurged.
6.2.2.1 Field Test for Accuracy (Relative)
For continuous monitoring systems employ-
Ing extractive sampling, the probe tip for the
continuous monitoring system and the probe
tip for the Reference Method sampling train
should be placed at adjacent locations in the
duct. For NOX continuous monitoring sys-
tems, make 27 NOX concentration measure-
ments, divided into nine sets, using the ap-
plicable reference method. No more than one
set of tests, consisting of three individual
measurements, shall be performed in any
one hour. All individual measurements of
each set shall be performed concurrently,
or within a three-minute Interval and the
results averaged. For SO, continuous moni-
toring systems, make nine SO. concentration
measurements using the applicable reference
method. No more than one measurement
shall be performed in any one hour. Record
the reference method test data and the con-
tinuous monitoring system concentrations
on the example data sheet shown In Figure
2-3.
6.2.25 Field Test for Zero Drift and Cali-
bration Drift. For extractive systems, deter-
mine the values given by zero and span gas
pollutant concentrations at two-hour inter-
vals until 15 sets of data are obtained. For
nonextractive measurement systems, the zero
value may be determined by mechanically
producing a zero condition that provides a
system check of the analyzer internal mirrors
and all electronic circuitry Including the
radiation source and detector assembly or
by Inserting three or more calibration gas
cells and computing the zero point from the
upscale measurements. If this latter tech-
nique is used, a graph(s) must be retained
by the owner or operator for each measure-
ment system that shows the relationship be-
tween the upscale measurements and the
zero point. The span of the system shall be
checked by using a calibration gas cell cer-
tified by the manufacturer to be function-
ally equivalent to 50 percent of span concen-
tration. Record the zero and span measure-
ments (or the computed zero drift) on the
example data sheet shown in Figure 2-4.
The two-hour periods over which measure-
ments are conducted need not be consecutive
but may not overlap. All measurements re-
quired under this paragraph may be con-
ducted concurrent with tests under para-
graph 6.2.2.1.
82.2.3 Adjustments, zero and calibration
corrections and adjustments are allowed only
at 24-hour Intervals or at such shorter In-
tervals as the manufacturer's written In-
structions specify. Automatic corrections
made by the measurement system without
operator Intervention or initiation are allow-
able at any time. During the entire 168-hour
operational test period, record on the ex-
ample sheet shown In Figure 2-5 the values
given by zero and span gas pollutant con-
centrations before and after adjustment at
24-hour Intervals.
6.3 Field Test for Response Time
63.1 Scope of Test. Use the entire continu-
ous monitoring system as Installed, Including
sample transport lines if used. Flow rales,
line diameters, pumping rates, pressures (do
not allow the pressurized calibration gas to
change the normal operating pressure In the.
sample line), etc., shall be at the nominal
values for normal operation as specified in
the manufacturer's written Instructions. If
the analyzer Is used to sample more than one
pollutant source (stack), repeat this test for
each sampling point.
6.32 Response Time Test Procedure. In-
troduce zero gas into the continuous moni-
toring system sampling interface or as close
to the sampling interface as possible. When
the system output reading has stabilized,
switch quickly to a known concentration of
pollutant gas. Record the time from concen-
tration switching to 95 percent of final stable
response. For non-extractive monitors, the
highest available calibration gas concentra-
tion shall be switched into and out of the
sample path and response times recorded.
Perform this test sequence three (3) times.
Record the results of each test on the
example sheet shown In Figure 2-6.
7. Calculations, Data Analysis and Report-
Ing.
7.1 Procedure for determination of mean
values and confidence Intervals.
7.1.1 The mean value of a data set is
calculated according to equation 2-1,
1 "
n 1 = 1 Equation 2-1
where:
x, := absolute value of the measurements,
2 = sum of the individual values,
x=mean value, and
n = number of data points.
7.1.2 The 9s percent confidence interval
(two-sided) is calculated according to equa-
tion 2-2:
r1 T _ l-"s
0.1.95 = T=.
Equation 2-2
where:
]Cx, = sum of all data points,
t9?3=:tj a/2, and
C.I.S5 = 95 percent confidence interval
estimate of the average mean
value.
Values for '.975
The
rected
i
2..
3
5
6...
7 ;
8..
9
10....
12-
13
14 _
15
16
values in this table
for n-l degrees of
'.975
12.706
4.303
3.182
2. V76
2.571
2.447
2. 365
2.309
Z262
2.228
2.201
2.179
2160
2.145
2.131
are already cor-
frecdom. Use n
FEOERAl REGISTER, VOL. 40, NO. J 94MONDAY, OCTOBER 6. 1975
IV- 9 5
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RULES AND REGULATIONS
46265
equal to the number of samples as data
points.
12 Data Analysis and Reporting.
75.1 Accuracy (Relative). For each of the
nine reference method test points, determine
the average pollutant concentration reported
by the continuous monitoring system. These
average concentrations shall be determined
from the continuous monitoring system data
recorded under 7.2.2 by Integrating or aver-
aging the pollutant concentrations over each
of the time Intervals concurrent with each
reference method testing period. Before pro-
ceeding to the next step, determine the basis
(wet or dry) of the continuous monitoring
system data and reference method test data
concentrations. If the bases are not con-
sistent, apply a moisture correction to either
reference method concentrations or the con-
tinuous monitoring system concentrations
as appropriate. Determine the correction
factor by moisture tests concurrent with the
reference method testing periods. Report the
moisture test method and the correction pro-
cedure employed. For each of the nine test
runs determine the difference lor each test
run by subtracting the respective reference
method test concentrations (use average of
each set of three measurements for NOx)
from the continuous monitoring system Inte-
grated or averaged concentrations. Using
these data, compute the mean difference and
the 95 percent confidence Interval of the dif-
ferences (equations 2-1 and 2-2). Accuracy
is reported as the sum of the absolute value
of the mean difference and the 95 percent
confidence Interval of the differences ex-
pressed as a percentage of the mean refer-
ence method value. Use the example sheet
shown In Figure 2-3.
7.2.2 Calibration Error. Using the data
from paragraph 6.1, subtract the measured
pollutant concentration determined under
paragraph 8.1.1 (Figure 2-1) from the value
shown by the continuous monitoring system
for each of the five readings at each con-
centration measured under 6.1.2 (Figure 2-2).
Calculate the mean of these difference values
and the 95 percent confidence intervals ac-
cording to equations 2-1 and 2-2. Report the
calibration error (the sum of the absolute
value of the mean difference and the 95 per-
cent confidence Interval) as a percentage of
each respective calibration gas concentra-
tion. Use example sheet shown In Figure 2-2.
7.2.3 Zero Drift (2-hour). Using the zero
concentration values measured each two
hours during the field test, calculate the dif-
ferences between consecutive two-hour read-
Ings expressed In ppm. Calculate the mean
difference and the confidence Interval using
equations 2-1 and 2-2. Report the zero drift
as the sum of the absolute mean value and
the confidence Interval as a percentage of
span. Use example sheet shown In Figure
2-4.
7.2.4 Zero Drift (24-hour). Using the zero
concentration values measured every 24
hours during the field test, calculate the dif-
ferences between the zero point after zero
adjustment and the zero value 24 hours later
Just prior to zero adjustment. Calculate the
mean value of these points and the confi-
dence Interval using equations 2-1 and 2-2.
Report the zero drift (the sum of the abso-
lute mean and confidence Interval) as a per-
centage of span. Use example sheet shown In
Figure 2-6.
7.2.5 Calibration Drift (2-hour). Using
the calibration values obtained at two-hour
intervals during the field test, calculate the
differences between consecutive two-hour
readings expressed as ppm. These values
should be corrected for the corresponding
zero drift during that two-hour period. Cal-
culate the mean and confidence Interval of
these corrected difference Values using equa-
tions 2-1 and 2-2. Do not use the differences
between non-consecutive readings. Report
the calibration drift as the sum of the abso-
lute mean and confidence Interval as a per-
centage of span. Use the example sheet shown
In Figure 2-4.
7.2.8 C-llbratlon Drift (24-hour). ,Using
the calibration values measured every 24
hours during the field test, calculate the dif-
ferences between the calibration concentra-
tion reading after zero and calibration ad-
justment, and the calibration concentration
reading 21 hours later after zero adjustment
but before calibration adjustment. Calculate
the mean value of these differences and the
confidence Interval using equations 2-1 and
2-2. Report the calibration drift (the sum of
the absolute mean and confidence interval)
as a percentage of span. Use the example
sheet shown In Figure 2-5.
7.2.7 Response Time. Using the charts
from paragraph 6.3, calculate- the time inter-
val from concentration switching to 95 per-
cent to the final stable value for all upscale
and downscale tests. Report the mean of the
three upscale test times and the mean of the
three downscale test times. The two aver-
age times should not differ by more than 15
percent of the slower time. Report the slower
time as tlw system response time. Use the ex-
ample sheet shown in Figure 2-6.
7.2.8 Operational Test Period. During the
168-hour performance and operational test
period, the continuous monitoring system
shall not require any corrective maintenance,
repair, replacement, or adjustment other than
that clearly specified as required In -the op-
eration and maintenance manuals as routine
and expected during a one-week period. If
the continuous monitoring system operates
within the specified performance parameters
and does not require corrective maintenance,
repair, replacement or adjustment other than
as specified above during the 168-hour test
period, the operational period will be success-
fully concluded. Failure of the continuous
monitoring system to meet this requirement
shall call for a repetition of the 168-hour test
period. Portions of the test which were satis-
factorily completed need not be repeated.
Failure to meet any performance specifica-
tions shall call for a repetition of the one-
week performance test period and that por-
tion of the testing which is related to the
failed specification. All maintenance and ad-
justments required shall be recorded. Out-
put readings shall be recorded before and
after all adjustments.
8. References.
8.1 "Monitoring Instrumentation for the
Measurement of Sulfur Dioxide in Stationary
Source Emissions," Environmental Protection
Agency, Research Triangle Park, N.C,, Feb-
ruary 1973.
8.2 "Instrumentation lor the Determina-
tion of Nitrogen Oxides Content of Station-
ary Source Emissions," Environmental Pro-
tection Agency, Research Triangle Park, N.C.,
Volume 1, APTD-0847, October 1971; Vol-
ume 2, AFTD-O942, January 1972.
8.3 "ExperUjental Statistics," Department
of Commerce, Handbook 91, 1963, pp. 3-31,
paragraphs 3-3.1.4.
8.4 "Performance Specifications for Sta-
tionary-Source Monitoring Systems for Gases
and Visible Emissions," Environmental Pro-
tection Agency, Research Triangle Park, N.C.,
EPA-650/2-74-013, January 1974.
Ktferenct Krthjxi Used
Hlcll-»«i<« tlMnl CallbMttcn Gil Mxtura
S4.pl. T pp.
S»pt. Z pp.
S»pl« J
of bllnmlen Gu xlitum
FEDERAL REGISTER, VOL 40, NO. 194MONDAY, OCTOBH 6, 1973
IV-9 6
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46266
RULES AND REGULATIONS
Calibration Gas Mixture Data (From Figure 2-1)
Mid {505} ppm High (903!) ppm
Calibration Gas
Run f Concentration,pom
Measurement System
Reading, ppm
Differences, ppm
n
15
Hid High
Mean difference
Confidence interval
Average C
" + C I.
Concentration x 10°
Calibration gas concentration - measurement system reading
"Absolute value
Figure 2-2. Calibration Error Determination
Test
No.
1
7
.1
4
c
6
1
8
9
lean
:est
lean
Date
and
Time
Reference Method Saroles
Samp.e 1
(ppm}
reference method
value (SOj)
difference!
NO
Sa.Tipre I
(ppm)
NO
j
(_
*» »
Mean referei
test value
ppm (SO-h
*5X Confidence Intervals » * * ppm
tccu
E«
* N
m
Sarp?- 3
(ppm)
NO Saiiple
Average
(ppm)
nee method
PP» (N
(SO,), - t
Analyzsr 1-Hour
Average (ppmj*
S02 NO,
Oi f f erence
(ppm)
Average of
the difference*
V-
. _ PW
Mean difference (absolute va ue) « 95! confidence interval , r ,PA
acl" " Mean reference method value * IDD * lj°2
)lain and report method used to detent ne integrated averages.
an differences > the average of the differences minus the mean reference method test va
(NOX).
), - t (my
lue.
Figure 2-3. Accuracy Determination (SOj and NOX)
FEDERAL REGISTER, VOL 40, NO. 194MONDAY, OCTOBER 6, 1975
iy-97
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RULES AND REGULATIONS
46267
Time
Scgln End
zero
Reading
Zero
Drift
UZero)
Span
Spin- Drift
Reeding (iSpan)
Calibration
Drift
( Span- Zero)
Zero Drift [Mean Zero Drift* * CI (Zero) J ISpan] x ^00 -
Calibration Drift * [Kean Span Drift*+ CI (Span) j * [Span] x 10'
Absolute Value.
Figure 2-4.Zero and Calibration Drift (2 hour}
Date Zero Span Calibration
and Zero Drift Reading Drift
Time Reading (AZero) (After zero adjustment) (,iSpan)
Zero Drift « [Mean Zero Drift*
c.I. (Zero)
s [Instrument Span] x 100
Calibration Drift = [Mean Span Drift*
. + C.I. (Span)
* [Instrument Span] x 100 =
* Absolute value
Figure 2-5. Zero and Calibration Drift (24-hour;
FEDERAL REGISTER, VOL 40. NO. 194MONDAY, OCTOBER 6, 1975
IV-9 8
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46268
RULES AND REGULATIONS
Date of Test
Span Gas Concentration.
Analyzer Span Setting
ppm
_seconds
Upscale
Z '_ _ seconds
3 _ seconds
Average upscale response
seconds
Downscale
_seconds
_seconds
seconds
Average downscale response
System average response time (slower time) =
_seconds
seconds
^deviation from slov/er
system average response
iwer _ a\
lonse I
average upscale minus average downscale inns
slower tipeI x
Figure 2-6. Response Time
Performance Specification 3Performance
specifications and specification test proce-
dures for monitors of CO2 and O2 from sta-
tionary sources.
1. Principle and Applicability.
1.1 Principle. Effluent gases are continu-
ously sampled and are analyzed for carbon
dioxide or oxygen by a continuous monitor-
ing system. Tests of the system are performed
during a minimum operating period to deter-
mine zero drift, calibration drift, and re-
sponse time characteristics.
1 2 Applicability. This performance speci-
fication is applicable to evaluation of con-
tinuous monitoring systems for measurement
of carbon dioxide or oxygen. These specifica-
tions contain test procedures, installation re-
quirements, and data computation proce-
dures for evaluating the acceptability of the
continuous monitoring systems subject to
approval by the Administrator. Sampling
may include either extractive or non-extrac-
tive (in-situ) procedures.
2. Apparatus.
2.1 Continuous Monitoring System for
Carbon Dioxide or Oxygen.
22 Calibration Gas Mixtures. Mixture of
known concentrations of carbon dioxide or
oxygen in nitrogen or air. Midrange and 90
percent of span carbon dioxide or oxygen
concentrations are required. The 90 percent
of span gas mixture is to be used to set and
check the analyzer span and Is referred to
as span gas. For oxygen analyzers, if the
span is higher than 21 percent O,, ambient
air may be used in place of the 90 percent of
span calibration gas mixture. Triplicate
analyses of the gas mixture (except ambient
air) shall be performed within two weeks
prior to use using Reference Method 3 of
this part.
2.3 Zero Gas. A gas containing less than 100
ppm of carbon d>ioxlde or oxygen.
2.4 Data Recorder. Analog chart recorder
or other suitable device with input voltage
range compatible with analyzer system out-
put. The resolution of the recorder's data
output shall be sufficient to allow completion
of the test procedures within this specifica-
tion.
3. Definitions.
3.1 Continuous Monitoring System. The
total equipment required for the determina-
tion of carbon dioxide or oxygen In a given
source effluent. The system consists of three
major subsystems:
3 1.1 Sampling Interface. That portion of
the continuous monitoring system that per-
forms one or more of the following opera-
tions: delineation, acquisition, transporta-
tion, and conditioning of a sample of the
source effluent or protection of the analyzer
from the hostile aspects of the sample or
source environment.
3 1.2 Analyzer. That portion of the con-
tinuous monitoring system which senses the
pollutant gas and generates a signal output
that is a function of the pollutant concen-
tration.
3.1.3 Data Recorder. That portion of the
continuous monitoring system that provides
a permanent record of the output signal in
terms of concentration units.
3.2 Span. The value of oxygen or carbon di-
oxide concentration at which the continuous
monitoring system Is set that produces the
maximum data display output. For the pur-
poses of this method, the span shall be set
no less than 1.5 to 2.5 times the normal car-
bon dioxide or normal oxygen concentration
in. the stack gas of the affected facility.
3.3 Midrange. The value of oxygen or car-
bon dioxide concentration that is representa-
tive of the normal conditions in the stack
gas of, the affected facility at typical operat-
ing rates.
3.4 Zero Drift. The change In the contin-
uous monitoring system output over a stated
period of time of normal continuous opera-
tion when the carbon dioxide or oxygen con-
centration at the time for the measurements
Is zero.
3.5 Calibration Drift. The change In the
continuous monitoring system output over a
stated time period of normal continuous op-
eration when the carbon dioxide or oxygen
continuous monitoring system Is measuring
the concentration of span gas.
3.6 Operational Test Period. A minimum
period of time over which the continuous
monitoring system Is expected to operate
within Certain performance specifications
without unscheduled maintenance, repair, or
adjustment.
3.7 Response time. The time Interval from
a step change In concentration at the input
to the continuous monitoring system to the
time at which 95 percent of the correspond-
ing final value Is displayed on the continuous
monitoring system data recorder.
4. Installation Specification.
Oxygen or carbon dioxide continuous mon-
Itortng systems'shall-be Installed at a loca-
tion where measurements are directly repre-
sentative of -the total effluent from the
affected facility or representative of the same
effluent sampled by a SO., or NO, continuous
monitoring system. This" requirement- shall
be compiled with by use of applicable re-
quirements In Performance Specification 2 of
this appendix as follows:
4.1 Installation of Oxygen or Carbon Di-
oxide continuous Monitoring Systems Not
Used to Convert Pollutant Data. A sampling
location shall be selected In accordance with
the procedures under paragraphs 4.2.1 or
4.2.2, or Performance Specification 3 of this
appendix.
4.2 Installation of Oxygen or Carbon Di-
oxide Continuous Monitoring Systems Used
to Convert Pollutant Continuous Monitoring
System- Data to Units of Applicable Stand-
ards. The diluent continuous monitoring sys-
tem (oxygen or carbon dioxide) shall be in-
stalled at a sampling location where measure-
ments that can be made are representative of
the effluent gases sampled by the pollutant
continuous monitoring system (s). Conform -
ance with this requirement may be accom-
plished In any of the following ways:
4.2.1 The sampling location for the diluent
system shalfbe n«ar the sampling location for
the pollutant continuous monitoring system
such that the same approximate point(s)
(extractive systems) or path (in-sltu sys-
tems) in the cross section is sampled or
viewed.
4.2 2 The diluent and pollutant continuous
monitoring systems may be Installed at dlf-
fsrent locations If the effluent gases at both
sampling locations are nonstratifled as deter-
mined under paragraphs 4.1 or 43, Perform-
ance Specification 2 of this appendix and
there Is no Jn-leakage occurring between the
two sampling locations. If the effluent gases
are stratified at either location, the proce-
dures under paragraph 4.2.2, Performance
Specification 2 of this appendix shall be used
for installing continuous monitoring systems
at that location.
5. Continuous Monitoring System Perform-
ance Specifications.
The continuous monitoring system shall
meet the performance specifications in Table
3-1 to be considered acceptable under this
method.
6. Performance Specification Test Proce-
dures.
The following test procedures shall be used
to determine conformauce with the require-
msnts of paragraph 4. Due to the wide varia-
tion existing In analyzer designs and princi-
ples of operation, these- procedures are not
applicable to all analyzers. Where this occurs,
alternative procedures, subject to the ap-
proval of the Administrator, may be em-
ployed. Any such alternative procedures must
fulfill the same purposes (verify response,
drift, and accuracy) as the following proce-
dures, and must clearly demonstrate con-
formance with specifications In Table 3-1.
6.1 Calibration Check. Establish a cali-
bration curve for the continuous moni-
toring system using zero, midrange, and
span concentration gas mixtures. Verify
that the resultant curve of analyzer read-
ing compared with the calibration gas
value is consistent with the expected re-
sponse curve as described by the analyzer
manufacturer. If the expected response
curve is not produced, additional cali-
bration gas measurements shall be made,
or additional steps undertaken to verify
FEDERAL REGISTER, VOL 40, NO. 194MONDAY, OCTOBER 6, 197J
LV-S9
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RULES AND REGULATIONS
46269
the accuracy ol the response curve of the
analyzer.
6.2 Field Test for Zero Drift and Cali-
bration Drift. Install and operate the
continuous monitoring system in accord-
ance with the manufacturer's written in-
structions and drawings as follows:
TABLE 3-1.Performance specifications
Parameter
Specification
1. Zero drift (2 h) i <0.4 pet Oi or COi.
2. Zero drift (24 h) i <0.5 pet dor CO*.
3. Calibration drift (2 h)'. <0.4 pet Oi or COj.
4. Calibration drift (24 h)'. <0.5 pet Oi or COi.
3. Operational period 168 h minimum^
6. Response tlffle lOmin.
1 Expressed as sum of absolute mean value pluses pet
confidence luterval of a series of tests.
6.2.1 Conditioning Period. Offset the zero
setting at least 10 percent of span so that
negative zero drift may be quantified. Oper-
ate the continuous monitoring system for
an initial 168-hour conditioning period in a
normal operational manner.
6.2,2.~Operatlonal Test Period. Operate the
continuous monitoring system Tor an addi-
tional 168-hour period maintaining the zero
offset. The system shall monitor the source
effluent at all times except' when - being
zeroed, calibrated, or backpurged.
6.2.3 Field Test for Zero Drift and Calibra-
tion Drift. Determine the values given bj
zero and midrange gas concentrations at two-
hour intervals until 19 sets of data arc ob-
tained. For non-extractive continuous moni-
toring systems, determine the zero value
given by a mechanically produced zero con-
dition cr by computing the zero value from
upscale measurements using calibrated gas
cells certified by the manufacturer. The mid-
range checks shall be performed by using
certified calibration gas cells functionally
equivalent to less than 50 percent of span.
Record these readings on the example sheet
shown in Figure 3-1. These two-hour periods
need not be consecutive but may not overlap.
In-situ CO, or O, analyzers which cannot be
fitted with "a calibration gas cell may be cali-
brated by alternative procedures acceptable
to the Administrator. Zero and calibration
corrections and adjustments are allowed
only at 24-hour Intervals or at such shorter
Intervals as the manufacturer's written In-
structions specify. Automatic corrections
made by the continuous monitoring system
without operator Intervention or initiation
are allowable at any time. During the en-
tire 168-hour test period, record the values
given by zero and span gas concentrations
before and after adjustment at 24-hour In-
tervals In the example sheet shown in Figure
3-2.
6.3 Field Teat for Response Time.
6.3.1 Scope of Test.
This test shall be accomplished using the-
continuous monitoring system as Installed,
Including sample transport lines if used.
Flow rates, line diameters, pumping rates,
pressures (do not allow the pressurized cali-
bration gas to change the -normal operating
pressure in the sample line), etc., shall be
at the nominal values for normal operation
as specified In the manufacturer's written
Instructions. If the analyzer Is used to sample
more than one source (stack), this test shall
be repeated for each sampling point.
6.3.2 Response Time Test Procedure.
Introduce zero gas Into the continuous
monitoring system sampling Interface or as
close to the sampling Interface as possible.
When the *y»tem output reading has stabi-
lized, switch quickly to a- known concentra-
tion of gas at 90 percent of span. Record the
time from concentration switching to 95
percent of final stable response. After the
system response has stabilized at the upper
level, switch quickly to a zero gas. Record
the time from concentration switching to 95
percent of final stable response. Alterna-
tively, for nonextractive continuous monitor-
ing systems, the highest available calibration
gas concentration shall be switched into and
out of the sample path and response times
recorded. Perform this test sequence three
(3) times. For each test, record the results
on the data sheet shown in Figure 3-3.
7. Calculations, Data Analysis, and Report-
Ing.
7.1 Procedure for determination of mean
values and confidence intervals.
7.1.1 The mean value of a data set Is cal-
culated according to equation 3-1.
n i=i ' Equation 3-1
where :
Xj = absolute value of the measurements,
2 = sum of the individual values,
x = mean value, and "
n= number of data points.
7.2.1 The 95 percent confidence interval
(two-sided) is calculated according to equa-
tion 3-2 :
n\n
Equation 3-2
where:
2Xr=sum of all data points,
'.975 = tI-a/2, and
C.I^,. = 95 percent confidence interral es-
timated of the average mean value.
value.
Values for >.975
n 1.975
2 12.706
3 4.303
4 3.182
5 2.776
6 2.571
7 2.447
8 2.365
9 2.306
10 2.262
11 - 2.228
12 , 2.201
13 2. 179
14 2.160
15 2. 145
16 2.131
The values In this table are already corrected
for n-1 degrees of freedom. Use n equal to
the number of samples as data points.
7.2 Data Analysis and Reporting.
7.2.1 Zero Drift (2-hour). Using the zero
concentration values measured each two
hours during the field test, calculate the dif-
ferences between the consecutive two-hour
readings expressed In ppm. Calculate the
mean difference and the confidence interval
using equations 3-1 and 3-2. Record the sum
of the absolute mean value and the confi-
dence Interval on the data sheet shown in
Figure 3-1.
7.2.2 Zero Drift (24-hour). Using the zero
concentration values measured every 24
hours during the field test, calculate the dif-
ferences between the zero point after zero
adjustment and the zero value 24 hours
later just prior to zero adjustment. Calculate
the mean value of these points and the con-
fidence interval using equations 3-1 and 3-2.
Record the zero drift (the sum of the ab-
solute mean and confidence Interval) on the
data sheet shown in Figure 3-2.
7-2.3 Calibration Drift (2-hour). Using the
calibration values obtained at two-hour in-
tervals during the field test, calculate the
differences between consecutive two-hour
readings expressed as ppm. These values
should be corrected for the corresponding
zero drift during that two-hour period. Cal-
culate the mean and confidence Interval of
these corrected difference values using equa-
tions 3-1 and 3-2. Do not use the differences
between non-consecutive readings. Record
the sum of the absolute mean and confi-
dence interval upon the data sheet shown
in Fieure 3-1.
7.2.4 Calibration Drift (24-hour). Using the
calibration values measured every 24 hours
during the field test, calculate the differ-
ences between the calibration concentration
reading after zero and calibration adjust-
ment and the calibration concentration read-
ing 24 hours later after zero adjustment but
before calibration adjustment. Calculate the
mean value of these differences and the con-
fidence interval using equations 3-1 and 3-2.
Record the sum of the absolute mean and
confidence interval on the data sheet shown
in Figvtre 3-2.
7.2.5 Operational Test Period. During the
168-hour- performance and operational test
period, the continuous monitoring system
shall not receive any corrective maintenance,
repair, replacement, or adjustment other
than that clearly specified as required in the
manufacturer's written operation and main-
tenance manual* as routine and expected
during a one-week period. If the continuous
monitoring system operates within the speci-
fied performance parameters and does not re-
quire' corrective maintenance, repair, replace-
ment, or adjustment other than as specified
above during the 168-hour test period, the
operational period will be successfully con-
cluded. Failure of the continuous monitoring
system to meet this requirement shall ca'l
for a repetition of the 168 hour test period.
Portions of the test which were satisfactorily
completed need not be repeated. Failure to
meet any performance specifications shall
call for a repetition of the one-week perform-
ance test period and that portion of the test-
ing which is related to the failed specifica-
tion. All maintenance and adjustments re-
quired shall be recorded. Output reading:
shall be recorded before and after all ad-
justments.
7.2 6 Response Time. Using the data devel-
oped under paragraph 5.3, calculate the time
Interval from concentration switching to 9£
percent to the final stable value for all up-
scale and downscale tests. Report the mean of
the three upscale test times and the mean of
the three downscale test times. The two av-
erage times should not differ by more than
15 percent of the slower time. Report the
slower time as the system response time. Re-
cord the results on Figure 3-3.
8. References.
8.1 "Performance Specifications for Sta-
tionary Source Monitoring Systems for Gases
and Visible Emissions," Environmental Pro-
tection Agency, Research Triangle Park, N.C.,
EPA-850/2-74-013, January 1974.
8.2 "Experimental Statistics," Department
of Commerce, National Bureau of Standards
Handbook 91, 1663, pp. 3-31, paragraphs
3-3.1.4.
(Sees. Ill and 114 of the Clean Air Act, as
amended by sec. 4(o) of Pub. L. 91-604, 84
Stat. 1678 (42 U.S.C. 1867C-6, by sec. 15(c) (2)
of Pub. L. 91-604. 85 Stat. 1713 (42 U.S.C.
1857g)).
FEDERAL REGISTER, VOL 40. NO. 194MONDAY, OCTOBER 6, 1975
IV-IOO
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RULES AND REGULATIONS
53341
and submit plans containing emission
standards for control of that pollutant
from designated facilities [§ 60.23(a) L
For health-related pollutants. State
emission standards must ordinarily be at
least as stringent as the corresponding
EPA guidelines to be approvable f§ 60.24
(c>). However, States may apply lesa
stringent standards to particular sources
(or classes of sources) when economic
factors or physical limitations specific to
particular sources (or classes of sources)
make such application significantly more
reasonable [§ 60.24(f> ]. For welfare-re-
lated pollutants, States may balance the
emission guidelines and other informa-
tion provided in EPA's guideline docu-
ments against other factors of public
concern in establishing their emission
standards, provided that appropriate
consideration is given to the information
presented in the guideline documents
and at public hearings and that other
requirements of Subpart B axe met
[S 60.24(d)L
Within four months after the date re-
quired for submission of a plan, the Ad-
ministrator will approve or disapprove
the plan or portions thereof [§ 60.27(b) ].
If a State plan (or portion thereof) Is
disapproved, the Administrator will pro-
mulgate a plan (or portion thereof)
within 6 months after the date required
for plan submission [§ 60.27(d) ]. The
plan submlttal, approval/disapproval,
and promulgation procedures are basi-
cally patterned after section 110 of the
Act and 40 CFR Part 51 (concerning
adoption and submittal of State imple-
mentation plans under section 110).
For health-related pollutants, the
emission guidelines and compliance times
referred to above will appear in a new
Subpart C of Part 60. As indicated previ-
ously, emission guidelines and compli-
ance times for welfare-related pollutants
will appear only in the guideline docu-
ments published under §60.22(a). Ap-
provals and disapprovals of State plans
and any plans (or portions thereof)
promulgated by the Administrator will
appear in a new Part 62.
COMMENTS RECEIVED OK PROPOSED REGU-
LATIONS AND CHANGES MADE IN FINAL
REGULATIONS
Many of the comment letters received
by EPA contained multiple comments.
The most significant comments and dif-
ferences between the proposed and final
regulations are discussed below. Copies
of the comment letters and a summary
of the comments with EPA's responses
(entitled "Public Comment Summary:
Section lll(d) Regulations") are avail-
able for public inspection and copying at
the EPA Public Information Reference
Unit, Room 2922 (EPA Library), 401 M
Street, SW., Washington, D.C. 20460. In
addition, copies of the comment sum-
mary may be obtained upon written re-
quest from the EPA Public Information
Center (PM-215), 401 M Street, SW.,
Washington, D.C. 20460 (specify "Public
Comment Summary: Section lll(d)
Regulations").
(1) Definitions and basic concepts.
The term "emission limitation" as de-
fined in proposed 5 60.21 (e) has appar-
ently caused some confusion. As used in
the proposal, the term was not intended
to mean a legally enforceable national
emission standard as some comments
suggested. Indeed, the term was chosen
in an attempt to avoid such confusion.
EPA's rationale for using the emission
limitation concept is presented below in
the discussion of the basis for approval or
disapproval of State plans. However, to
emphasize that a legally enforceable
standard is not intended, the term "emis-
sion limitation" has been replaced with
the term "emission guideline" (see
§ 60.21 (e) 3. In addition, proposed § 60.27
(concerning publication of guideline
documents and so forth) has been moved
forward in the regulations (becoming
§ 60.22) to emphasize that publication of
a final guideline document is the
"trigger" for State action under subse-
quent sections of Subpart B [see
§60.23(a)l.
Many commentators apparently con-
fused the degree of control to be reflected
in EPA's emission guidelines under sec-
tion lll(d) with that to be required by
corresponding standards of performance
for new sources under section 111 (b). Al-
though the general principle (application
of best adequately demonstrated control
technology, considering costs) will be the
same in both cases, the degrees of con-
trol represented by EPA's emission
guidelines will ordinarily be less stringent
than those required by standards of per-
formance for new sources because the
costs of controlling existing facilities will
ordinarily be greater than those for con-
trol of new sources. In addition, the reg-
ulations have been amended to make
clear that the Administrator will specify
different emission guidelines for differ-
ent sizes, types, and classes of designated
facilities when costs of control, physical
limitations, geographical location, and
similar factors make subcategorization
approprate [§ 60.22(b) (5) 1. Thus, while
there may be only one standard of per-
formance for new sources of designated
pollutants, there may be several emission
guidelines specified for designated facil-
ities based on plant configuration, size,
and other factors peculiar to existing
facilities.
Some comments evidenced confusion
regarding the relationship of affected
facilities and designated facilities. An
affected facility, as defined in § 60.2(e),
is a new or modified facility subject to a
standard of performance for new sta-
tionary sources. An existing facility
[§ 60.2(aa) 1 is a facility of the same type
as an affected facility, but one the con-
struction of which commenced before
the date of proposal of applicable stand-
ards of performance. A designated facil-
ity r§60.21(d)J is an existing facility
which emits a designated pollutant.
A few industry comments argued that
the proposed regulations would permit
EPA to circumvent the legal and tech-
nical safeguards required under sections
108, 109, ,and 110 of the Act, sections
which the commentators characterized
as the basic statutory process for control
of existing facilities. Congress clearly in-
tended control of existing facilities under
sections other than 108,109, and 110. Sec-
tions 112 and 303 as well as lll(d) itself
provide for control of existing facilities.
Moreover, action under section lll(d) is
subject to a number of significant safe-
guards: (1) Before acting under section
lll(d) the Administrator must have
found under section lll(b) that a source
category may significantly contribute to
air pollution which causes t>r contributes
to the endangerment of public health or
welfare, and this finding must be tech-
nically supportable; (2) EPA's emission
guidelines will be developed in consulta-
tion with industrial groups and the Na-
tional Air Pollution Control Techniques
Advisory Committee, and they will be
subject to public comment before they
are adopted; (3) emission standards and
other plan provisions must be subjected
to public hearings prior to adoption; (4)
relief is available under § 60.24(f) or
§ 60.27(e) (2) where application of emis-
sion standards to particular sources
would be unreasonable; and (5) judicial
review of the Administrator's action in
approving or promulgating plans (or
portions thereof) is available under sec-
tion 307 of the Act.
A number of commentators suggested
that special provisions for plans sub-
mitted under section lll(d) are un-
necesssary since existing facilities are
covered by State implementation plans
(SIPs) approved or promulgated under
section 110 of the Act. By its own terms,
however, section lll(d) requires the Ad-
ministrator to prescribe regulations for
section lll(d) plans. In addition, the
pollutants to which section lll(d) ap-
plies (i.e., designated pollutants) are not
controlled as such under the SIPs. Under
section 110, the SIPs only regulate cri-
teria pollutants; i.e., those for which na-
tional ambient air quality standards
have been established under section 109
of the Act. By definition, designated
pollutants are non-criteria pollutants
[§ 60.21(a)L Although some designated
pollutants may occur in particulate as
well as gaseous forms and thus may be
controlled to some degree under SIP
provisions requiring control of particu-
late matter, specific rather than inci-
dental control of such pollutants is re-
quired by section lll(d). For these rea-
sons, separate regulations are necessary
to establish the framework for specific
control of designated pollutants under
section 111 (d).
Comments of a similar nature argued
that if there are demonstrable health
and welfare effects from designated pol-
lutants, either air quality criteria should
be established and SIPs submitted under
sections 108-110 of the Act, or the pro-
visions of section 112 of the Act should
be applied. Section lll(d) of the Act
was specifically designed to require con-
trol of pollutants which are not presently
considered "hazardous" within the
meaning of section 112 and for which
ambient air quality standards have not
been promulgated. Health and welfare
effects from these designated pollutants
often cannot be quantified or are of such
a nature that the effects are cumulative
and not associated with any particular
FEDERAL REGISTER, VOL 40, NO. 2^2MONDAY, NOVEMBER 17, 1975
IV-104
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53340
RULES AND REGULATIONS
2 I Title 40Protection of Environment
CHAPTER IENVIRONMENTAL
PROTECTION AGENCY
SUBCHAFTER CAIR PROGRAMS
[FRL 437-4]
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
State Plans for the Control of Certain
Pollutants From Existing Facilities
On October 7, 1974 (39 FR 36102),
EPA proposed to add a new Subpart B to
Part 60 to establish procedures and re-
quirements for submittal of State plans
for control of certain pollutants from
existing facilities under section lll(d)
of the Clean Air Act, as amended (42
U.S.C. 1857c-6(d)). Interested persons
participated in the rulemaking by send-
ing comments to EPA. A total of 45 com-
ment letters was received, 19 of which
came from industry, 16 from State and
local agencies, 5 from Federal agencies,
and 5 from other interested parties. All
comments have been carefully consid-
ered, and the proposed regulations have
been reassessed. A number of changes
suggested in comments have been made,
as well as changes developed within the
Agency.
One significant change, discussed more
fully below, is that different procedures
and criteria will apply to submittal and
approval of State plans where the Ad-
ministrator determines that a particular
pollutant may cause or contribute to the
endangerment of public welfare, but
that adverse effects on public health
have not been demonstrated. Such a de-
termination might be made, for example,
in the case of a pollutant that damages
crops but has no known adverse effect on
public health. This change is intended
to allow States more flexibility in estab-
lishing plans for the control of such
pollutants than is provided for plans in-
volving pollutants that may affect public
health.
Most other changes were of a relatively
minor nature and, aside from the change
just mentioned, the basic concept of the
regulations is unchanged. A number of
provisions have been reworded to resolve
ambiguities or otherwise clarify their
meaning, and some were combined or
otherwise reorganized to clarify and
simplify the overall organization of Sub-
part B.
BACKGROUND
When Congress enacted the Clean Air
Amendments of 1970, if addressed three
general categories of pollutants emitted
from stationary sources. See Senate Re-
port No. 91-1196, 91st Cong., 2d Sess.
18-19 (1970>. The first category consists
of pollutants (often referred to as "cri-
teria pollutants") for which air quality
criteria and national ambient air quality
standards are established under sections
108 and 109 of the Act. Under the 1970
amendments, criteria pollutants are con-
trolled by State implementation plans
(SIP's) approved or promulgated under
section 110 and, in some cases, by stand-
ards of performance for new sources es-
tablished under section 111. The second
category consists of pollutants listed as
hazardous pollutants under section 112
and controlled under that section.
The third category consists of pol-
lutants that are (or may be) harmful to
public health or welfare but are not or
cannot be controlled under sections
108-110 or 112. Section lll(d) requires
control of existing sources of such pol-
lutants whenever standards of perform-
ance (for those pollutants) are estab-
lished under section lll(b) for new
sources of the same type.
In determining which statutory ap-
proach is appropriate for regulation of a
particular pollutant, EPA considers the
nature and severity of the pollutant's
effects on public health or welfare, the
number and nature of its sources, and
similar factors prescribed by the Act.
Where a choice of approaches is pre-
sented, the regulatory advantages and
disadvantages of the various options are
also considered. As indicated above, sec-
tion lll(d) requires control of existing
sources of a pollutant if a standard of
performance is established for new
sources under section lll(b) and the pol-
lutant is not controlled under sections
108-110 or 112. In general, this means
that control under section lll(d) is ap-
propriate when the pollutant may cause
or contribute to endangerment of public
health or welfare but is not known to be
"hazardous" within the meaning of sec-
tion 112 and is not controlled under sec-
tions 108-110 because, for example, it is
not emitted from "numerous or diverse"
sources as required by section 108.
For ease of reference, pollutants to
which section lll(d) applies as a result
of the establishment of standards of per-
formance for new sources are defined in
§60.21(a) of the new Subpart B as
"designated pollutants." Existing facil-
ities which emit designated pollutants
and which would be subject to the stand-
ards of performance for those pollutants,
if new, are defined in §60 2Kb) as
"designated facilities."
As indicated previously, the proposed
regulations have been revised to allow
States more flexibility in establishing
plans where the Administrator deter-
mines that a designated pollutant may
cause or contribute to endangerment of
public welfare, but that adverse effects
on public health have not been demon-
strated. For convenience of discussion,
designated pollutants for which the Ad-
ministrator makes such a determination
are referred to in this preamble as "wel-
fare-related pollutants" (ie, those re-
quiring control solely because of their
effects on public welfare^. All other
designated pollutants are referred to as
"health-related pollutants "
To date, standards of performance have
been established under section 111 of the
Act for two designated pollutantsfluo-
rides emitted from five categories of
sources in the phosphate fertilizer indus-
try (40 FR 33152, August 6, 1975) and
sulfuric acid mist emitted from sulfuric
acid production units (36 FR 24877, De-
cember 23, 1971). In addition, standards
of performance have been proposed for
fluorides emitted from primary alumi-
num plants (39 FR 37730, October 23,
1974), and final action on these stand-
ards will occur shortly. EPA will publish
draft guideline documents (see next sec-
tion) for these pollutants in the near
future. Although a final decision has not
been made, it is expected that sulfuric
acid mist will be determined to be a
health-related pollutant and that fluo-
rides will be determined to be welfare-
related.
SUMMARY OF REGULATIONS
Subpart B provides that after a stand-
ard of performance applicable to emis-
sions of a designated pollutant from new
sources is promulgated, the Administra-
tor will publish guideline documents con-
taining information pertinent to control
of the same pollutant from designated
(i.e., existing) facilities f§ 60.22 (a) ]. The
guideline documents will include "emis-
sion guidelines" (discussed below) and
compliance times based on factors speci-
fied in §60.22(b)(5) and will be made
available for public comment in draft
form before being published in final
form. For health-related pollutants, the
Administrator will concurrently propose
and subsequently promulgate the emis-
sion guidelines arid compliance times
referred to above I § 60.22(c)]. For wel-
fare-related pollutants, emission guide-
lines and compliance times will appear
only in the applicable guideline docu-
ments [§ 60.22(d)(l)].
The Administrator's determination
that a designated pollutant is heath-
related, welfare-related, or both and the
rationale for the determination will be
provided in the draft guideline document
for that pollutant. In making this de-
termination, the Administrator will con-
sider such factors as: (1) Known and
suspected effects of the pollutant on pub-
lic health and welfare; (2) potential am-
bient concentrations of the pollutant;
(3) generation of any secondary pol-
lutants for which the designated pollut-
ant may be a precursor; (4) any syn-
ergistic effect with other pollutants; and
(5) potential effects from accumulation
in the environment (e.g , soil, water and
food chains). After consideration of
comments and other information a final
determination and rationale will be pub-
lished in the final guidelines document.
For both health-related and welfare-
related pollutants, emission guidelines
will reflect the degree of control attain-
able with the application of the best sys-
tems of emission reduction which (con-
sidering the cost of such reduction) have
been adequately demonstrated for desig-
nated facilities L§ 60.21 (e) ]. As discussed
more fully below, the degree of control
reflected in EPA'is emission guidelines
will take into account the costs of retro-
fitting existing facilities and thus will
probably be less stringent than corre-
sponding standards of performance for
new sources.
After publication of a final guideline
document for a designated pollutant, the
States will have nine months to develop
FEDERAL REGISTER, VOL 40, NO. 22?MONDAY. NOVEMBER 17. 1975
IV-103
-------
RULES AND REGULATIONS
46271
Date of Test
Span Gas Concentration
Analyzer Span Setting
1.
Upscale
2.
3.
ppra
ppm
seconds
seconds
seconds
Average upscale response
seconds
Downscale
1.
2.
3.
seconds
seconds
seconds
Average downscale response
seconds
System average response time (slower time) =
seconds
from slower _ average upscale rrp'r.us average downscale
system average response
slower time
x 1002
Figure 3-3. Response
1 9 Title 40Protection of Environment
CHAPTER IENVIRONMENTAL
PROTECTION AGENCY
SUBCHAPTER CAIR PROGRAMS
|FRL442-3]
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCE
Delegation of Authority to State of
New York
Pursuant to the delegation of author-
ity for the standards of performance for
new stationary sources (NSPS) to the
State of New York on August 6, 1975,
EPA is today amending 40 CPR 60 4, Ad-
dress, to reflect this delegation. A Notice
announcing this delegation is published
elsewhere in today's FEDERAL REGISTER.
The amended § 60.4, which adds the ad-
dress of the New York State Department
of Environmental Conservation, to which
reports, requests, applications, submit-
tals, and communications to the Admin-
istrator pursuant to this part must also
be addressed, is set forth below.
The Administrator finds good cause for
foregoing prior public notice and for
making this rulemaklng effective imme-
diately in that it is an administrative
change and not one of substantive con-
tent. No additional substantive burdens
are imposed on the parties affected. The
delegatipn which is reflected by this ad-
ministrative amendment was effective on
August G, 1975, and it serves no purpose
to delay the technical change of this
addition of the State address to the Code
of Federal Regulations. This rulemaklng
is effective immediately, and Is Issued
under the authority of Section 111 of the
Clean Air. Act, as amended. 42 U.S.C.
1857C-6.
(FB Doc.75-26565 Filed 10-3-75;8:45 am)
Dated: October 4,1975.
STANLEY W LEGRO,
Assistant Administrator
for Enforcement.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations Is amended
as follows:
1. In § GO.4 paragraph (b) is amended
by revising subparagraph (HH) to read
as follows:
§ 60.4 Address.
* *
(b) * * *
(HH)New York: New York State De-
partment of Environmental Conservation, 60
Wolf Road, New York 12233, attention: Divi-
sion of Air Resources.
(FR Doc.75-27682 Filed 10-14-75:8:48 am]
FEDERAL REGISTER, VOL. 40, NO. 700-
-WEDNESDAY, OCTOBER 15, 1975
20 [449-4|
PART 60STANDARDS OF PERFORM
ANCE FOR NEW STATIONARY SOURCE
Delegation of Authority to State of Coloradr
initials, and communications to the Ad-
ministrator pursuant to this part must
also be addressed. Is set forth below.
The Administrator finds (rood cause for
foregoing prior public notice find for
making this rulemaking effective Im-
mediately in that it is an administrative
change and not one of substantive con-
tent. No additional substantive burdens
are imposed on the parties affected. The
delegation which Is reflected bv this ad-
ministrative amendment was effective on
August 27, 1975, and It serves no purpose
to delay the technical change of this ad-
dition of the State address to the Code
of Federal Regulations.
This rulemaktng Is effective im-
mediately, and Is Issued under the au-
thority of Section 111 of the Clean Air
Act, as amended, 42 TJ.S.C. 1857C-6.
Dated: October 22, 1975.
STANLEY W LEGRO,
Assistant Administrator
for Enforcement.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations Is amended
as follows:
1. In § 60.4 paragraph (b) Is amended.
by revising subparagraph (G) to read as
follows:
Pursuant to the delegation of authorllo § 60.4 Address.
for the standards of, performance fo « .
eleven categories of new stationary
sources (NSPS) to the State of Colorado
on August 27. 1975. EPA is today amend-
ing 40 CFR 60.4, Address, to reflect this
delegation. A Notice announcing this
delegation Is published today in the FED-
ERAL REGISTER. The amended 5 60.4,
which adds the address of the Colorado
Air Pollution Control Division to which
all reports, requests, applications, sub-
(b) *
(G)State of Colorado, Colorado Air
Pollution Control Division. 4210 East
IHh Avenue, Denver, Colorado 80220.
* * * *
|FR Doc.75-29234 Filed 10-30-75:8:45 am]
KDERAl REGISTER, VOL. 40, NO. 211-
-FRIDAY, OCTOBER 31, 1975
IV-1Q2
-------
46270
RULES AND REGULATIONS
Dat* Zero Spin
>«t Tint Zero Drift Jpjn Drift
io. Begin End Date Reading f&Zero) Reading (aSpan)
1
Z
3
4
5
6
7
8
9
10
11
12
13
14
IS
Calibration Drift [Mean Span Drift* + Cl (Span J~~ *
'Absolute Value.
Calibration
Drift
(ASpan-AZero)
Figure 3-1. Zero and Calibration Drift (2 Hour).
)ate Zero Span Calibration
and Zero Drift Reading Drift
ime Reading (iZero) (After zero adjustment) (iSpan)
Zero Drift = [Haan Zero Drift*
+ C.I. (Zero)
:a!1brat1on Drift = [Mean Span Drift*
+ C.I. (Span)
* Absolute value
Figure 3-2, Zero and Calibration Drift (24-hour)
FEDERAL REGISTER, VOL. 40. NO.. 194MONDAY, OCTOBER 6, 1975
iv-ioi
-------
53342
RULES AND REGULATIONS
ambient level. Quite often, health and
welfare problems caused by such pol-
lutants are highly localized and thus an
extensive procedure, such as the SIPs
require, is not justified. As previously
indicated, Congress specifically recog-
nized the need for control of a third
category of pollutants; it also recognized
that as additional information be-
comes available, these pollutants might
later be reclassified as hazardous or cri-
teria pollutants.
Other commentators reasoned that
since designated pollutants are defined
as non-criteria and non-hazardous pol-
lutants, only harmless substances would
fall within this category. These com-
mentators argued that the Administra-
tor should establish that a pollutant has
adverse effects on public health or wel-
fare before it could be regulated under
section lll(d>. Before acting under sec-
tion lll(d), however, the Administrator
must establish a standard of perform-
ance under section 11 Kb). In so doing,
the Administrator must find under sec-
tion lll(b) that the source category cov-
ered by such standards may contribute
significantly to air pollution which causes
or contributes to the endangerment of
public health or welfare.
(2) Basis for approval or disapproval
of State plans. A number of industry
comments questioned EPA's authority to
require, as a basis for approval of State
plans, that the States establish emission
standards that (except in cases of eco-
nomic hardship) are equivalent to or
more stringent than EPA's emission
guidelines. In general, these comments
argued that EPA has authority only to
prescribe procedural requirements for
adoption and submittal of State plans,
leaving the States free to establish emis-
sion standards on any basis they deem
necessary or appropriate. Most State
comments expressed no objection to
EPA's interpretation on this point, and
a few explicitly endorsed it.
After careful consideration of these
comments, EPA continues to believe, for
reasons summarized below, that its in-
terpretation of section lll(d) is legally
correct. Moreover, EPA believes that its
interpretation is essential to the effective
implementation of section lll(d), par-
ticularly where health-related pollutants
are involved. As discussed more fully
below, however, EPA has decided that it
is appropriate to allow States somewhat
more flexibility in establishing plans for
the control of welfare-related pollutants
and has revised the proposed regulations
accordingly.
Although section lll(d) does not spec-
ify explicit criteria for approval or disap-
proval of State plans, the Administrator
must disapprove plans that are not "sat-
isfactory" [Section lll(d) (2) (A) 1. Ap-
propriate criteria must therefore be
inferred from the language and context
of section lll(d) and from its legislative
history. It seems clear, for example, that
the Administrator must disapprove plans
not adopted and submitted in accord-
ance with the procedural requirements
he prescribes under section lll(d), and
none of the commentators questioned
this concept. The principal questions,
therefore, are whether Congress in-
tended that the Administrator base ap-
provals and disapprovals on substantive
as well as procedural criteria and, if so,
on what types of substantive criteria.
A brief summary of the legislative his-
tory of section lll(d) will facilitate dis-
cussion of these questions. Section 111
(d) was enacted as part of the Clean Air
Amendments of 1970. No comparable pro-
vision appeared in the House bill. The
Senate bill, however, contained a sec-
tion 114 that would have required the
establishment of national emission
standards for "selected air pollution
agents." Although the term "selected air
pollution agent" did not include pollu-
tants that might affect public welfare
[which are subject to control under sec-
tion lll(d) 1, its definition otherwise cor-
responded to the description of pollu-
tants to be controlled under section
lll(d). Section 114 of the Senate bill
was rewritten in conference to become
section lll(d). Although the Senate re-
port and debates include references to
the intent of section 114, neither the con-
ference report nor subsequent debates in-
clude any discussion of section lll(d) as
finally enacted. In the absence of such
discussion, EPA believes inferences con-
cerning the legislative intent of section
lll(d) may be drawn from the general
purpose of section 114 of the Senate bill
and from the manner in which it was
rewritten in conference.
After a careful examination of section
lll(d), its statutory context, and its
legislative history, EPA believes the fol-
lowing conclusions may be drawn:
(1) As appears from the Senate report
and debates, section 114 of the Senate
bill was designed to address a specific
problem. That problem was how to reduce
emissions of pollutants which are (or
may be) harmful to health but which,
on the basis of information likely to be
available in the near term, cannot be
controlled under other sections of the
Act as criteria pollutants or as hazardous
pollutants. (It was made clear that such
pollutants might be controlled as criteria
or hazardous pollutants as more defini-
tive information became available.) The
approach taken in section 114 of the
Senate bill was to require national emis-
sion standards designed to assure that
emissions of such pollutants would not
endanger health.
(2) The Committee of Conference
chose to rewrite the Senate provision as
part of section 111, which in effect re-
quires maximum feasible control of pol-
lutants from new stationary sources
through technology-based standards (as
opposed to standards designed to assure
protection of health or welfare or both).
For reasons summarized below, EPA be-
lieves this choice reflected a decision in
conference that a similar approach (mak-
ing allowances for the costs of controlling
existing sources) was appropriate for the
pollutants to be controlled under section
lll(d).
(3) As reflected in the Senate report
and debates, the pollutants to be con-
trolled under section 114 of the Senate
bill were considered a category distinct
from the pollutants for which criteria
documents had been written or might
soon be written. In part, these pollutants
differed from the criteria pollutants in
that much less information was avail-
able concerning their effects on public
health and welfare. For that reason, it
would have been difficultif not im-
possibleto prescribe legally defensible
standards designed to protect public
health or welfare for these pollutants
until more definitive information became
available. Yet the pollutants, by defini-
tion, were those which (although not cri-
teria pollutants and not known to be
hazardous) had or might be expected
to have adverse effects on health.
(4) Under the circumstances, EPA be-
lieves, the conferees decided (a) that
control of such pollutants on some basis
was necessary; (b) that, given the rela-
tive lack of information on their health
and welfare effects, a technology-based
approach (similar to that for new
sources) would be more feasible than one
involving an attempt to set standards
tied specifically to protection of health;
and (c) that the technology-based ap-
proach (making allowances for the costs
of controlling existing sources) was a
reasonable means of attacking the prob-
lem until more definitive information be-
came known, particularly because the
States would be free under section 116
of the Act to adopt more stringent stand-
ardse if they believed additional control
was desirable. In short, EPA believes the
conferees chose to rewrite section 114 as
part of section 111 largely because they
intended the technology-based approach
of that section to extend (making allow-
ances for the costs of controlling existing
sources) to action under section lll(d).
In this view, it was unnecessary (al-
though it might have been desirable) to
specify explicit substantive criteria in
section lll(d) because the intent to re-
quire a technology-based approach could
be inferred from placement of the pro-
vision in section 111.
Related considerations support this in-
terpretation of section lll(d). For ex-
ample, section lll(d) requires the Ad-
ministrator to prescribe a plan for a
State that fails to submit a satisfactory
plan. It is obvious that he could only pre-
scribe standards on some substantive
basis. The references to section 110 of the
Act suggest that (as in section 110) he
was intended to do generally what the
States in such cases should have done,
which in turn suggests that (as in section
110) Congress intended the States to pre-
scribe standards on some substantive
basis. Thus, it seems clear that some sub-
stantive criterion was intended to govern
not only the Administrator's promulga-
tion of standards but also his review of
State plans.
Still other considerations support
EPA's interpretation of section lll(d).
Even a cursory examination of the legis-
lative history of the 1970 amendments re-
veals that Congress was dissatisfied with
air pollution control efforts at all levels
FEDERAL REGISTER, VOL. 40, NO. 222MONDAY, NOVEMBER 17, 1975
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RULES AND REGULATIONS
of government and was convinced that
relatively drastic measures were neces-
sary to protect public health and welfare.
The result was a series of far-reaching
amendments which, coupled with virtu-
ally unprecedented statutory deadlines,
required EPA and the States to take
swift and aggressive action. Although
Congress left initial responsibility with
the States for control of criteria pollut-
ants under section 110, it set tough mini-
mum criteria for such action and re-
quired Federal assumption of responsi-
bility where State action was inadequate.
It also required direct Federal action for
control of new stationary sources, haz-
ardous pollutants, and mobile sources.
Finally, in an extraordinary departure
from its practice of delegating rulemak-
ing authority to administrative agencies
(a departure intented to force the pace
of pollution control efforts in the auto-
mobile industry), Congress itself enacted
what amounted to statutory emission
standards for the principal automotive
pollutants.
Against this background of Congres-
sional firmness, the overriding purpose of
which was to protect public health and
welfare, it would make no sense to inter-
pret section lll(d) as requiring the Ad-
ministrator to base approval or disap-
proval of State plans solely on procedural
criteria. Under that interpretation,
States could set extremely lenient stand-
ardseven standards permitting greatly
increased emissionsso long as EPA's
procedural requirements were met Given
that the pollutants in question are for
may be) harmful to public health and
welfare, and that section lll(d) is the
only provision of the Act requiring their
control, it is difficult to believe that Con-
gress meant to leave such a gaping loop-
hole in a statutory scheme otherwise de-
signed to force meaningful action.
Some of the comments on the pro-
posed regulations assume that the States
were intended to set emission standards
based directly on protection of public
health and welfare. EPA believes this
view is consistent with its own view that
the Administrator was intended to base
approval or disapproval of State plans on
substantive as well as procedural criteria
but believes Congress intended a technol-
ogy-based approach rather than one
based directly on protection of health
and welfare. The principal factors lead-
ing EPA to this conclusion are sum-
marized above. Another is that if Con-
gress had intended an approach based
directly on protection of health and wel-
fare, it could have rewritten section 114
of the Senate bill as part of section 110,
which epitomizes that approach, rather
than as part of section 111. Indeed, with
relatively minor changes in language,
Congress could simply have retained sec-
tion 114 as a separate section requiring
action based directly on protection of
health and welfare.
Still another factor is that asking each
of the States, many of which had limited
resources and expertise in air pollution
control, to set standards protective of
health and welfare in the absence of ade-
quate information would have made even
less sense than requiring the Administra-
tor to do so with the various resources at
his command. Requiring a technology-
based approach, on the other hand, would
not only shift the criteria for decision-
making to more solid ground (the avail-
ability and costs of control technology)
but would also take advantage of the in-
formation and expertise available to EPA
from its assessment of techniques for the
control of the same pollutants from the
same types of sources under section ? 11
(b), as well as its power to compel sub-
mission of information about such tech-
niques under section 114 of the Act (42
U.S.C. 1857c-9). Indeed, section 114 was
made specifically applicable for the pur-
pose (among others) of assisting in the
development of State plans under section
lll(d). For all of these reasons, EPA be-
lieves Congress intended a technology-
based approach rather than one based
directly on protection of health and
welfare.
Some of the comments argued that
EPA's emission guidelines under section
lll(d) will, in effect, be national emis-
sion standards for existing sources, a con-
cept they argue was rejected in section
lll(d). In general, the comments rely on
the fact that although section 114 of the
Senate bill specifically provided for na-
tional emission standards, section lll(d)
calls for establishment of emission stand-
ards by States. EPA believes that the re-
writing of section 114 in conference is
consistent with the establishment of na-
tional criteria by which to judge the ade-
quacy of State plans, and that the ap-
proach taken in section lll(d) may be
viewed as largely the result of two deci-
sions: (1) To adopt a technology-based
approach similar to that for new sources;
and (2) to give States a greater role than
was provided in section 114. Thus, States
will have primary responsibility for de-
veloping and enforcing control plans
under section lll(d); under section 114,
they would only have been invited to seek
a delegation of authority to enforce Fed-
erally developed standards. Under EPA's
interpretation of section lll(d), States
will" also have authority to grant vari-
ances in cases of economic hardship; un-
der section 114, only the Administrator
would have had authority to grant such
relief. As with section 110, assigning pri-
mary responsibility to the States in these
areas is perfectly consistent with review
of their plans on some substantive basis.
If there is to be substantive review, there
must be criteria for the review, and EPA
believes it is desirable (if not legally re-
quired) that the criteria be made known
in advance to the States, to industry, and
to the general public. The emission guide-
lines, each of which will be subjected to
public comment before final adoption,
will serve this function.
In any event, whether or not Congress
"rejected" the concept of national emis-
sion standards for existing sources, EPA's
emission guidelines will not have the pur-
pose or effect of national emission stand-
ards. As emphasized elsewhere in this
preamble, they will not be requirements
enforceable against any source. Like the
national ambient air quality standards
prescribed under section 109 and the
items set forth in section 110(a) (2) (A)-
(H), they will only be criteria for judging
the adequacy of State plans.
Moreover, it is Inaccurate to argue (as
did one comment) that, because EPAs
emission guidelines will reflect best avail-
able technology considering cost, States
will be unable to set more stringent
standards. EPA's emission guidelines will
reflect its judgment of the degree of con-
trol that can be attained by various
classes of existing sources without unrea-
sonable costs. Particular sources within
a class may be able to achieve greater
control without unreasonable costs.
Moreover, States that believe additional
control is necessary or desirable will be
free under section 116 of the Act to
require more expensive controls, which
might have the effect of closing other-
wise marginal facilities, or to ban par-
ticular categories of sources outrighl;.
Section 60.24(g) has been added to clar-
ify this point. On the other hand, States
will be free to set more lenient standards,
subject to EPA review, as provided in
§§ 60.24(d) arid (f) in the case of wel-
fare-related pollutants and in cases of
economic hardship.
Finally, as discussed elsewhere in this
preamble, EPA's emission guidelines will
reflect subcategorization within source
categories where appropriate, taking
into account differences in sizes and
types of facilities and similar con-
§§ 60.24 (d) and (f) in the case of wel-
siderations, including differences in con-
trol costs that may be involved for
sources located in different parts of the
country. Thus, EPA's emission guidelines
will in effect be tailored to what is rea-
sonably achievable by particular classes
of existing sources, and States will be
free to vary from the levels of control
represented by the emission guidelines in
the ways mentioned above. In most if
not all cases, the result is likely to be sub
stantial variation in the degree of control
required for particular sources, rather
than identical standards for all sources.
In summary, EPA believes section
lll(d) is a hybrid provision, intended to
combine primary State responsibility for
plan development and enforcement (as in
section 110) with the technology-based
approach (making allowances for the
costs of controlling existing sources)
taken in section 111 generally. As indi-
cated above, EPA believes its interpreta-
tion of section 11 Kd) is legally correct in
view of the language, statutory context
and legislative history of the provision.
Even assuming some other interpreta-
tion were permissible, however, EPA
believes its interpretation is essential
to the effective implementation of
section lll(d), particularly where
health-related pollutants are involved.
Most of the reasons for this con-
clusion are discussed above, but It may be
useful to summarize them here. Given
the relative lack of information concern-
ing the effects of designated pollutants on
public health and welfare, it would be
FEDERAL REGISTER, VOL. 40, NO. 222MONDAY, NOVEMBER 17, 1975
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RULES AND REGULATIONS
difficultif not impossiblefor the
States or EPA to prescribe legally defen-
sible standards based directly on pro-
tection of health and welfare. By con-
trast, a technology-based approach takes
advantage of the information and ex-
pertise available to EPA from its assess-
ment of techniques for the control of the
same pollutants from the same types of
sources under section lll(b), as well as
EPA's power to compel submission of in-
formation about such techniques under
section 114 of the Act. Given the variety
of circumstances that may be encount-
ered in controlling existing as opposed to
new sources, it makes sense to have the
States develop plans based on technical
information provided by EPA and make
judgments, subject to EPA review, con-
cerning the extent to which less stringent
requirements are appropriate. Finally,
EPA review of such plans for their sub-
stantive adequacy is essential (partic-
ularly for health-related pollutants) to
assure that meaningful controls will bo
imposed. For these reasons, given a choice
of permissible interpretations of section
lll(d), EPA would choose the interpre-
tation on which Subpart B is based on
the ground that it is essential to the
effective implementation of the provision,
particularly where health-related pol-
lutants are involved.
As indicated previously, however, EPA
has decided that it is appropriate to
allow the States more flexibility in es-
tablishing plans for the control of
welfare-related pollutants than is pro-
vided for plans involving health-related
pollutants. Accordingly, the proposed
regulations have been revised to provide
that States may balance the emission
guidelines, compliance times and other
information in EPA's guideline docu-
ments against other factors in establish-
ing emission standards, compliance
schedules, and variances for welfare-
related pollutants, provided that appro-
priate consideration is given to the in-
formation presented in the guideline
documents and at public hearings, and
. that all other requirements of Subpart B
are met [§60.24(d)l. Where sources of
pollutants that cause only adverse effects
to crops are located in nonagricultural
areas, for example, or where residents
of a local community depend on an eco-
nomically marginal plant for their liveli-
hood, such factors could be taken into
account. Consistent with section 116 of
the Act, of course, States will remain
free to adopt requirements as stringent
as (or more stringent than) the corre-
sponding emission guidelines and com-
pliance times specified in EPA's guide-
line documents if they wish tsee
§ 60.24(g)l.
A number of factors influenced EPA's
decision to.allow States more flexibility
in establishing plans for control of
welfare-related pollutants than is pro-
vided for plans involving health-related
pollutants. The dominant factor, of
course, is that effects on public health
would not be expected to occur in such
cases, even if State plans required no
greater controls than are presently in
effect. In a sense, allowing the States
greater latitude in such cases simply
reflects EPA's view (stated in the pre-
amble to the proposed regulations) that
requiring maximum feasible control of
designated pollutants may be unreason-
able in some situations. Although pol-
lutants that cause only damage to vege-
tation, for example, are subject to con-
trol under section lll(d), few would
argue that requiring maximum feasible
control is as important for such pollut-
ants as it is for pollutants that endanger
public health.
This fundamental distinctionbe-
tween effects on public health and effects
on public welfareis reflected in section
110 of the Act, which requires attain-
ment of national air quality standards
that protect public health within a cer-
tain time (regardless of economic and
social consequences) but requires attain-
ment of national standards that protect
public welfare only within "a reasonable
time." The significance of this distinc-
tion is reflected in the legislative history
of section 110; and the legislative history
of section lll(d), although inconclusive,
suggests that its primary purpose was to
require control of pollutants that en-
danger public health. For these reasons,
EPA believes it is both permissible under
section lll(d) and appropriate as a
matter of policy to approve State plans
requiring less than maximum feasible
control of welfare-related pollutants
where the States wish to take into ac-
count considerations other than tech-
nology and cost.
On the other hand, EPA believes sec-
tion lll(d) requires maximum feasible
control of welfare-related pollutants in
the absence of such considerations and
will disapprove plans that require less
stringent control without some reasoned
explanation. For similar reasons, EPA
will promulgate plans requiring maxi-
mum feasible control if States fail to sub-
mit satisfactory plans for welfare-related
pollutants L§ 60.27(e) (D.I Under § 60.27
(e) (2), however, relief will still be avail-
able for particular sources where eco-
nomic hardship can be shown.
(3) Variances. One comment asserted
that neither the letter nor the intent of
section 111 allows variances from plan
requirements based on application of
best adequately demonstrated control
systems. Although section HKd) does
not explicitly provide for variances, it
does require consideration of the cost of
applying standards to existing facilities.
Such a consideration is inherently dif-
ferent than for new sources, because
controls cannot be included in the de-
sign of an existing facility and because
physical limitations may make installa-
tion of particular control systems impos-
sible or unreasonably expensive in some
cases. For these reasons, EPA believes the
provision [$ 60.24(f)l allowing States to
grant relief in cases of economic hard-
ship (where health-related pollutants are
involved) is permissible under section
lll(d). For the same reasons, language
has been included in £ 60 24(d> to make
clear that variances are also permissible
where welfare-related pollutants are In-
volved, although the flexibility provided
by that provision may make variances
unnecessary.
Several commentators urged that pro-
posed §60.23(e) [now §60.24(f)l be
amended to indicate that States are not
required to consider applications for var-
iances if they do not feel it appropriate
to do so. The commentators contended
that the proposed wording would invite
applications for variances, would allow
sources to delay compliance by submit-
ting such applications, might conflict
with existing State laws, and would prob-
ably impose significant burdens on State
and local agencies. In addition, there is
some question whether the mandatory
review provision as proposed would fee
consistent with section 116 of the Act,
which makes clear that States are free
to adopt and enforce standards more
stringent than Federal standards. Ac-
cordingly, the proposed wording has been
amended to permit, but not require,
State review of facilities for the purpose
of applying less stringent standards. To
give the States more flexibility, § 60.24
(f) has also been amended to permit
variances for particular classes of sources
as well as for particular sources.
Other comments requested that EPA
make clear whether proposed § 60.23(e)
fnow § 60.24(f) ] would allow permanent
variances or whether EPA intends ulti-
mate compliance with the emission
standards that would apply in the ab-
sence of variances. Section 60.24(f) is
intended to utilize existing State vari-
ance procedures as much as possible.
Thus it is up to the States to decide,
whether less stringent standards are to
be applied permanently or whether ulti-,
mate compliance will be required.
Another commentator suggested that
compliance with or satisfactory progress
toward compliance with an existing State
emission standard should be a sufficient
reason for applying a less stringent
standard under § 60.24(f). Such compli-
ance is not necessarily sufficient becausi
existing standards have not always been
developed with the intention of requiring
maximum feasible control. As Indicated
in the preamble to the proposed regula-
tions, however, if an existing State emis-
sion standard is relatively close to the
degree of control that would otherwise
be required, and the cost of additional
control would be relatively great, there
may be justification to apply a less strin-
gent standard under § 60.24(f).
One thoughtful comment suggested
that consideration of variances under
Subpart B could in effect undermine re-
lated SIP requirements; e.g., where des-
ignated pollutants occur in participate
forms and are thus controlled to some
extent under SIP requirements appli-
cable to parliculate matter. Nothing In
section lll(d) or Subpart B, however,
will preempt SIP requirements. In the
event of a conflict, protection of health
and welfare under section 110 must con-
trol.
(4> Public hearing requirement. Based
on comments that the requirement for a
public hearing on the plan in each AQCR
FEDERAL REGISTER. VOL. 40. NO. 222MONDAY, NOVEMBER 17, 1975
IV-107
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RULES AND REGULATIONS
53315
containing a designated facility is too
burdensome, the proposed regulation has
been amended to require only one hear-
ing per State per plan. While the Agency
advocates public participation in en-
vironmental rulemaking, it also recog-
nizes the expense and effort involved
in holding multiple hearings. States are
urged to hold as many hearings as prac-
ticable to assure adequate opportunity
for public participation. The hearing re-
quirements have also been amended to
provide that a public hearing is not re-
quired in those States which have an
existing emission standard that was
adopted after a public hearing and is at
least as stringent as the corresponding
EPA emission guidelines, and to permit
approval of State notice and hearing
procedures different than those specified
in Subpart B in some cases.
(5) Compliance schedules. The pro-
posed regulation required that all com-
pliance schedules be submitted with the
plan. Several commentators suggested
that this requirement would not allow
sufficient time for negotiation of sched-
ules and could cause duplicative work
If the emission standards were not ap-
proved. For this reason a new § 60.24
(e) (2) has been added to allow submis-
sion of compliance schedules after plan
submission but no later than the date
of the first semiannual report required
by § 60.25(e).
(6) Existing regulations. Several com-
ments dealt with States which have ex-
isting emission standards for designated
pollutants. One commentator urged that
such States be exempted from the re-
quirements of adopting and submitting
plans. However, the Act requires EPA to
evaluate both the adequacy of a State's
emission standards and the procedural
aspects of the plan. Thus, States with
existing regulations must submit plans.
Another commentator suggested that
the Administrator should approve exist-
ing emission standards which, because
they are established on a different basis
(e.g., concentration standards vs. proc-
ess-weight-rate 'type standards), are
more stringent than the corresponding
EPA emission guideline for some facil-
ities and less stringent for others. The
Agency cannot grant blanket approval
for such emission standards; however,
the Administrator may approve that part
of an emission standard which Is equal
to or more stringent than the EPA emis-
sion guideline and disapprove that por-
tion which Is less stringent. Also, the less
stringent portions may be approvable in
some cases under § 60.24 (d) or (f). Fi-
nally, subcategorizatlon by size of source
under § 60.22(b) (5) will probably limit
the number of cases in which this situa-
tion will arise.
Other commentators apparently as-
sumed that some regulations for desig-
nated pollutants were approved In the
State implementation plans (SIPs). Al-
though some States may have submitted
regulations limiting emissions of desig-
nated pollutants with the SIPs, such reg-
ulations were not considered In the ap-
proval or disapproval of those plans and
are not considered part of approved plans
because, under section 110, SIPs, apply
only to criteria pollutants.
(7) Emission inventory data and re-
ports. Section 60.24 of the proposed reg-
ulations tnow § 60.251 required emission
inventory data to be submitted on data
forms which the Administrator was to
specify in the future. It was expected
that a computerized subsystem to the Na-
tional Emission Data System (NEDS)
would be available that would accom-
modate emission inventory information
on the designated pollutants. However,
since this subsystem and concomitant
data form will probably not be developed
and approved in time for plan develop-
ment, the designated pollutant informa-
tion called for will not be required in
computerized data format. Instead, the
States will be permitted to submit this
information in a non-computerized
format as outlined in a new Appendix D
along with the basic facility information
on NEDS forms (OMB #158-R0095) ac-
cording to procedures in APTD 1135,
"Guide for Compiling a Comprehensive
Emission Inventory" available from the
Air Pollution Technical Information
Center, Environmental Protection
Agency, Research Triangle Park, North
Carolina 27711. In addition, § 60.25 ff) (5)
has been amended to require submission
of additional information with the semi-
annual reports in order to provide a bet-
ter tracking mechanism for emission in-
ventory and compliance monitoring pur-
poses.
(8) Timing. Proposed § 60.27(a) re-
quired proposal of emission guidelines
for designated pollutants simultaneously
with proposal of corresponding standards
of performance for new (affected) facil-
ities. ThiG section, redesignated § 60.22,
has been amended to require proposal (or
publication for public comment) of an
emission guideline after promulgation of
the corresponding standard of perform-
ance. Two written comments and several
Informal comments from industrial rep-
resentatives Indicated that more time
was needed to evaluate a standard of
performance and the corresponding
emission guideline than would be allowed
by simultaneous proposal and promulga-
tion. Also, by proposing (or publishing)
an emission guideline after promulgation
of the corresponding standard of per-
formance, the Agency can benefit from
the comments on the standard of per-
formance In developing the emission
guideline.
Proposed I 60.27(a) required proposal
of sulfurtc acid mist emission guidelines
within 30 days after promulgation of
Subpart B. This provision was included
as an exception to the proposed general
rule (requiring simultaneous proposal of
emission guidelines and standards of
performance) because it was impossible
to propose the acid mist emission guide-
line simultaneously with the correspond-
ing standard of performance, which had
been promulgated previously. The change
in the general rule, discussed above,
makes the proposed exception unneces-
sary, so it has been deleted. As previously
stated, the Agency intends to establish
emission guidelines for sulfuric acid mist
[and for fluorides, for which new source
standards were promulgated (40 FR
33152) after proposal of Subpart Bl as
soon as possible,
(9) Miscellaneous. Several commenta-
tors argued that the nine months pro-
vided for development of State plans
after promulgation of an emission
guideline by EPA would be insufficient. In
most cases, much of the work involved in
plan development, such as emission in-
ventories, can be begun when an emis-
sion guideline is proposed (or published
for comment) by EPA; thus, sevenal
additional months will be gained. Exten-
sive control strategies are not required,
and after the first plan is submitted, sub-
mitted, subsequent plans will mainly
consist of adopted emission standards.
Section lll(d) plans will be much less
complex than the SIPs, and Congress
provided only nine months for SIP de-
velopment. Also, States may already have
approvable procedures and legal author-
ity [see §§60.25(d) and 60.26(b>], and
the number of designated facilities per
State should be few. For these reasons,
the nine-month provision has been
retained.
Some comments recommended that
the requirements for adoption and sub-
mittal of section lll(d) plans appear in
40 CFR Part 51 or in some part of 40
CFR other than Part 60, to allow differ-
entiation among such requirements,
emission guidelines, new source stand-
ards and plans promulgated by EPA. The
Agency believes that the section lll(d)
requirements neither warrant a separate
part nor should appear in Part 51, since
Part 51 concerns control under section
110 of the Act. For clarity, however, sub-
part B of Part 60 will contain the re-
quirements for adoption and submittal
of section lll(d) plans; Subpart C of
Part 60 will contain emission guidelines
and times for compliance promulgated
under § 60.22 (c); and a new Part 62 will
be used for approval or disapproval of
section 111 (d) and for plans (or portions
thereof) promulgated by EPA where
State plans are disapproved in whole or
in part.
Two comments suggested that the
plans should specify test methods ar.d
procedures to be used In demonstrating
compliance with the emission standards.
Only when such procedures and methods
are known can the stringency of the
emission standard be determined. Ac-
cordingly, tlus change has been included
ln§60.24(b).
A new § 60.29 has been added to make
clear that the Administrator may revise
plan provisions he has promulgated un-
der |60.27(d>, and § 60.27(e) has been
revised to make clear that he will con-
sider applications for variances from
emission standards promulgated by EPA.
Effective Dale. These regulations be-
come effective on December 17,1975.
(Sections 111, 114, and 301 of the Clean Air
Act, as amended by sec, 4 (a) of Pub. L. 91-
604. 84 Stat. 1678, and by sec. 15(0) (2) of
Pub. L. 91-604, 84 Stat. 1713 (43 U.S.C.
1857C-6, and 1857c-9, 1857g).
Dated: Novembers, 1975.
JOHN QUARLES,
Acting Administrator.
FEDERAL REGISTER, VOL. 40, NO. 222MONDAY. NOVEMBER 17, 1975
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53346
RULES AND REGULATIONS
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amended
as follows:
1. The table of sections for Part 60 is
amended by adding a list of sections for
Subpart B and by adding Appendix D to
the list of appendixes as follows:
Subpart BAdoption and Submittal of State
Plans for Designated Facilities
Sec
00 20 Applicability.
50.21 Definitions.
50 22 Publication of guideline documents,
emission guidelines, and final com-
pliance times.
30.23 Adoption and submittal of State
plans; public hearings.
50 24 Emission standards and compliance
schedules.
60.25 Emission inventories, source sur-
veillance, reports.
60 26 Legal authority.
80 27 Actions by the Administrator.
B0.28 Plan revisions by the State.
60.29 Plan revisions by the Administrator.
APPENDIX DREQUIRED EMISSION INVENTORY
INFORMATION
2. The authority citation at the end of
the table of sections for Part 60 Is re-
vised to read as follows:
AUTHORITY: Sees. Ill and 114 of the .Clean
Air Act, as amended by sec. 4(a) of Pub. L.
91-604, 84 Stat. 1678 (42 U.S C. 1857C-6,
1857c-9). Subpart B also Issued under sec.
301 (a) of the Clean Air Act, as amended by
sec. 16(c)(2) of Pub. L. 91-604, 84 Stat.
1713 (42 U.S.C. 1857g).
3. Section 60.1 is revised to read as
follows:
§60.1 Applicability.
Except as provided in Subparts B and
C, the provisions of this part apply to
the owner or operator of any stationary
source which contains an affected facil-
ity, the construction or modification of
which is commenced after the date of
publication in this part of any standard
(or, if earlier, the date of publication of
any proposed standard) applicable to
that facility.
4. Part 60 is amended by adding Sub-
part B as follows:
Subpart BAdoption and Submittal of
State Plans for Designated Facilities
§ 60.20 Applicability.
The provisions of this subpart apply
to States upon publication of a final
guideline document under §60.22(a).
§ 60.21 Ucnniiion«.
Terms used but not defined in this
subpart shall have the meaning given
them in the Act and in subpart A:
(a) "Designated pollutant" means any
air pollutant, emissions of which are
subject to a standard of performance for
new stationary sources but for which air
quality criteria have not been issued,
and which is not included on a list pub-
lished under section 108 (a) or section
112(b)(l) (A) of the Act.
(b) "Designated facility" means any
existing facility (see 560.2(aa)) which
emits a designated pollutant and which
would be subject to a standard of per-
formance for that pollutant if the exist-
ing facility were an affected facility (see
$60.2(e)).
(c) "Plan" means a plan under sec-
tion lll(d) of the Act which establishes
emission standards for designated pol-
lutants from designated facilities and
provides for the implementation and
enforcement of such emission standards.
(d) "Applicable plan" means the plan,
or most recent revision thereof, which
has been approved under § 60.Z7(b) or
promulgated under 5 60.27(d).
(e) "Emission guideline" means a
guideline set forth in subpart C of this
part, or in a final guideline document
published under §60.22(a), which re-
flects the degree of emission reduction
achievable through the application of the
best system of emission reduction which
(taking into account the cost of such
reduction) the Administrator has de-
termined has been adequately demon-
strated for designated facilities.
(f) "Emission standard" means a
legally enforceable regulation setting
forth an allowable rate of emissions into
the atmosphere, or prescribing equip-
ment specifications for control of air pol-
lution emissions.
(g) "Compliance schedule" means a
legally enforceable schedule specifying
a date or dates by which a source or cate-
gory or sources must comply with specific
emission standards contained in a plan
or with any increments of progress to
achieve such compliance.
(h) "Increments of progress" means
steps to achieve compliance which must
be taken by an owner or operator of a
designated facility, including:
(1) Submittal of a final control plan
for the designated facility to the appro-
priate air pollution control agency;
(2) Awarding: of contracts for emis-
sion control systems or for process modi-
fications, or issuance of orders for the
purchase of component parts to accom-
plish emission control or process modi-
'fication.
(3) Initiation of on-site construction
or installation of emission control equip-
ment or process change:
(4) Completion of on-site construc-
tion or installation of emission control
equipment or process change; and
(5) Final compliance.
(i) "Region" means an air quality con-
trol region designated under section 107
of the Act and described in Part 81 of
this chapter.
(j) "Local agency" means any local
governmental agency.
$ 60.22 Publication of guideline docu-
ments, emission £Uf (1) If the Administrator determines
that a designated pollutant may cause
or contribute to endangerment of public
welfare, but that adverse effects on pub-
lic health have not been demonstrated,
he will include the determination in the
draft guideline document and in the FED-
ERAL REGISTER notice of its availability.
Except as provided in paragraph (d) (2)
or this section, paragraph (c) of this
section shall be inapplicable In such
cases.
(2) If the Administrator determines at
any time on the basis of new information
that a prior determination under para-
graph (d) (1) of this section is incorrect
or no longer correct, he will publish
notice of the determination In the FED-
ERAL REGISTER, revise the guideline docu-
ment as necessary under paragraph (a)
of this section, and propose and promul-
gate emission guidelines and compliance
times under paragraph (c) of this
section.
FEDERAL REGISTER, VOL. 40. NO. 222MONDAY, NOVEMBER 17. 197S
IV-109
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RULES AND REGULATIONS
53347
§ 60.23 Adoption and submitlal of Slate
plans; public hearings.
(a) (1> Within nine months after no-
tice of the availability of a final guide-
line document is published under § 60.22
(a), each State shall adopt and submit
to the Administrator, in accordance with
§ 60.4, a plan for the control of the desig-
nated pollutant to which the guideline
document applies.
(2) Within nine months after notice of
the availability of a final revised guide-
line document is published as provided
in § 60.22(d) (2), each State shall adopt
and submit to the Administrator any
plan revision necessary to meet the re-
quirements of this subpart.
(b) If no designated facility is located
within a State, the State shall submit
a letter of certification to that effect to
the Administrator within the time spe-
cified in paragraph (a) of this section.
Such certification shall exempt the State
from the requirements of this subpart
for that designated pollutant.
(c) (1) Except as provided in para-
graphs (c) (2) and
and shall include such additional in-
crements of progress as may be necessary
to permit close and effective supervision
of progress toward final compliance.
(2) A plan may provide that compli-
ance schedule;; for individual sources or
categories of sources will be formulated
after plan submittal. Any such schedule
shall be the subject of a public hearing
held according to I 60.23 and shall ba
submitted to the Administrator within 63
days after the date of adoption of ths
schedule but in no case later than the
date prescribed for submittal of the first
semiannual report required by § 60.25(e).
(f) On a case-by-case basis for par-
ticular designated facilities, or classes of
facilities, States may provide for the ap-
plication of less stringent emission
standards or longer compliance schedules
than those otherwise required by para-
graph (c) of this section, provided that
the State demonstrates with respect to
each such facility (or class of facilities):
(1) Unreasonable cost of control re-
sulting from plant age, location, or baste
process design;
(2) Physical impossibility of installing
necessary control equipment; or
(3) Other factors specific to the facility
(or class of facilities) that make applica-
tion of a less stringent standard or final
compliance time significantly more rea-
sonable.
(g) Nothing; in this subpart shall b-3
construed to preclude any State or po-
litical subdivision thereof from adopting
or enforcing (1) emission standard:?
more stringent than emission guideline?
specified in subpart C of this part or in
applicable guideline documents or (2>
compliance schedules requiring final
compliance at earlier times than those
specfied in subpart C or in applicable
guideline documents.
§ 60.25 Emission inventories, source
surveillance, reports.
(a) Each plan shall include an inven-
tory of all designated facilities, including
emission data for the designated pollut-
ants and information related to emission;}
as specified in Appendix D to this part.
Such data shall be summarized in this
plan, and emission rates of designated
pollutants from designated facilities shall
be correlated with applicable emission
standards. As used in this subpart, "cor-
related" means presented in such a man-
ner as to show the relationship between
measured or estimated amounts of emis-
sions and the amounts of such emissions
FEDERAL REGISTER, VOL. 40, NO. 222MONDAY, NOVEMBER 17, 1975
IV-110
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53348
RULES AND REGULATIONS
allowable under applicable emission
standards.
(b) Each plan shall provide for moni-
toring the status of compliance with ap-
plicable emission standards. Each plan
shall, as a minimum, provide for:
(1) Legally enforceable procedures for
requiring owners or operators of desig-
nated facilities to maintain records and
periodically report to the State informa-
tion on the nature and amount of emis-
sions from such facilities, and/or such
other information as may be necessary
to enable the State to determine whether
such facilities are in compliance with ap-
plicable portions of the plan.
(2) Periodic inspection and, when ap-
plicable, testing of designated facilities.
(c) Each plan shall provide that in-
formation obtained by the State under
paragraph (b) of this section shall be
correlated with applicable emission
standards (see §60.25(a)) and made
available to the general public.
(d) The provisions referred to in par-
agraphs (b) and (c) of this section sTiall
be specifically identified. Copies of such
provisions shall be submitted with the
plan unless:
(1) They have been approved as por-
tions of a preceding plan submitted un-
der this subpart or as portions of an
implementation plan submitted under
section 110 of the Act, and
(2) The State demonstrates:
(i) That the provisions are applicable
to the designated pollutant(s) for which
the plan is submitted, and
(ii) That the requirements of § 60.26
are met.
(e) The State shall submit reports on
progress in plan enforcement to the Ad-
ministrator on a semiannual basis, com-
mencing with the first full report period
after approval of a plan or after promul-
gation of a plan by the Administrator.
The semiannual periods are January 1-
June 30 and July 1-December 31. Infor-
mation required under this paragraph
shall be included In the semiannual re-
ports required by § 51.7 of this chapter.
(f) Each progress report shall include:
(1) Enforcement actions initiated
against designated facilities during the
reporting period, under any emission
standard or compliance schedule of the
plan.
(2) Identification of the achievement
of any increment of progress required by
the applicable plan during the reporting
period.
(3) Identification of designated facili-
ties that have ceased operation during
the reporting period
'4) Submission of emission inventory
data as described in paragraph (a) of
this section for designated facilities that
were not in operation at the time of plan
development but began operation during
the reporting period
(5> Submission of additional data as
necessary to update the information sub-
mitted under paragraph > llir Administrator.
(a) The Administrator may, whenever
he determines necessary, extend the pe-
riod for submission of any plan or plan
revision or portion thereof.
(b) After receipt of a plan or plan re-
vision, the Administrator will propose the
plan or revision for approval or dis-
approval. The Administrator will, within
four months after the date required for
submission of a plan or plan revision,
approve or disapprove such plan or revi-
sion or each portion thereof.
(c) The Administrator will, after con-
sideration of any State hearing record,
promptly prepare and publish proposed
regulations setting forth a plan, or por-
tion thereof, for a State if:
(1) The State fails to submit a plan
within the time prescribed;
(2) The State fails to submit a plan
revision required by § 60.23(a) (2) within
the time prescribed; or
(3) The Administrator disapproves the
State plan or plan revision or any por-
tion thereof, as unsatisfactory because
the requirements of this subpart have not
been met.
The Administrator will, within six
months after the date required for sub-
mission of a plan or plan revision,
promulgate the regulations proposed un-
der paragraph (c) of this section with
such modifications as may be appropriate
unless, prior to such promulgation, the
State has adopted and submitted a plan
or 'plan revision which the Administra-
tor determines to be approvable
and will require final compliance with
such standards as expeditiously as prac-
ticable but no later than the Umes speci-
fied in the guideline document.
(2) Upon anplication by the owner or
operator of a designated facility to which
regulations proposed and promulgated
under this section will apply, the Ad-
ministrator may provide for the appli-
cation of less stringent emission stand-
ards or longer compliance schedules than
those otherwise required by this section
in accordance with the criteria specified
in § 60.24(f).
(f) If a State failed to hold a public
hearing as required by §60,23(ci, the
Administrator will provide opportunity
for a hearing within the State prior to
promulgation of a plan under paragraph
(d) of this section.
§ 60.28 Plan regions !>) tin- Stair.
(a) Plan revisions which have the
effect of delaying compliance with ap-
plicable emission standards or incre-
ments of progress or of establishing less
stringent emission standards shall be
submitted to the Administrator within
60 days after adoption in accordance with
the procedures and requirements appli-
cable to development and submission of
the original plan.
(b) More stringent emission standards.
or orders which have the effect of ac-
FEDERAL REGISTER, VOL. 40, NO. 222MONDAY, NOVEMBER 17, 1975
IV-111
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RULES AND REGULATIONS
53349
celerating compliance, may be submitted
to the Administrator as plan revisions
in accordance with the procedures and
requirements applicable to development
and submission of the original plan.
(c) A revision of a plan, or any portion
thereof, shall not be considered part of
an applicable plan until approved by the
Administrator in accordance with this
subpart.
§ 60.29 Plan roiMons l>y the Adminis-
trator.
After notice and opportunity for pub-
lic hearing in each affected State, the
Administrator may revise any provision
of an applicable plan if:
(a) The provision was promulgated by
the Administrator, and
(b) The plan, as revised, will be con-
sistent with the Act and with the require-
ments of this subpart..
5. Part 60 is amended by adding Ap-
pendix D as follows:
APPENDIX DREQUIRED EMISSION INVENTORY
INFORMATION
(a) Completed NEDS point source form(s)
for the entire plant containing the desig-
nated facility, Including Information on the
applicable criteria pollutants. If data con-
cerning the plant are already In NEDS, only
that information must be submitted which
Is necessary to update the existing NEDS
record for that plant Plant and point Identi-
fication codes for NEDS records shall cor-
respond to those previously assigned In
NEDS; for plants not In NEDS, these codes
shall be obtained from the appropriate
Regional Office.
(b) Accompanying the basic NEDS Infor-
mation shall be the following Information
on each designated facility:
(1) The state and county Identification
codes, as well as the complete plant and
point identification codes of the designated
facility In NEDS. (The codes are needed to
match these data with the NEDS data )
(2)A description of the designated facility
Including, where appropriate:
(1) Process name.
(ii) Description and quantity of each
product (maximum per hour and average per
year).
(Ill) Description and quantity of raw ma-
terials handled for each product (maximum
per hour and average per year).
(iv) Types of fuels burned, quantities and
characteristics (maximum and average
quantities per hour, average per year).
(v) Description and quantity of solid
wastes generated (per year) and method of
disposal.
(3) A description of the air pollution con-
trol equipment In use or proposed to contiol
the designated pollutant, Including:
(1) Verbal description of equipment
(11) Optimum control efficiency, in percent.
This shall be a combined efficiency when
more than one device operate In series. The
method of control efficiency determination
shall be indicated (eg., design efficiency,
measured efficiency, estimated efficiency).
(ill) Annual average control efficiency, in
percent, taking Into account control equip-
ment down time. This shall be a combined
efficiency when more than one device operate
In series.
(4) An estimate of the designated pollu-
tant emissions from the designated facility
(maximum per hour and average per year).
The method of emission determination shall
also be specified (eg., stack test, material
balance, emission factor).
(Sees in, 114, and 301 of the Clean Air Act,
as amended by sec. 4(a) of Pub. L. 91-604,
84 Stat. 1678, and by sec. 15(c) (2) of Pub. L.
91-604, 84 Stat. 1713 (42 U.S.C. 1857c-<3.
1857C-9, 1857g))
[PR Doc.75-30611 Piled 11-14-75:8:45 ami
FEDERAL REGISTER, VOL. 40, NO. 222MONDAY, NOVEMBER 17, 1975
IV-112
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58416
2 2 Title 40Protection of Environment
CHAPTER IENVIRONMENTAL
PROTECTION AGENCY
SUBCHAPTER CAIR PROGRAMS
[FRL 402-8]
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Modification, Notification, and
Reconstruction
On October 15, 1974 (39 FR 36946),
under section 111 of the Clean Air Act, as
amended (42 U.S.C. 1857), the Environ-
mental Protection Agency (EPA) pro-
posed amendments to the general provi-
sions of 40 CFR Part 60. These amend-
ments included additions and revisions
to clarify the definition of the term
"modification" appearing in the Act, to
require notification of construction or
potential modification, and to clarify
when standards of performance are ap-
plicable to reconstructed sources. These
regulations apply to all stationary
sources constructed or modified after the
proposal date of an applicable standard
of performance.
Interested parties participated in the
rulemaking by sending comments to EPA.
Fifty-three comment letters were re-
ceived, 43 of which came from industry,
with the remainder coming from State
and Federal agencies. Copies of the com-
ment letters received and a summary of
the comments with EPA's responses are
available for public inspection and copy-
ing at the EPA Public Information Re-
ference Unit, Room 2922 (EPA Library),
401 M Street SW., Washington, D.C. In
addition, copies of the comment summary
and Agency responses may be obtained
upon written request from the EPA Pub-
lic Information Center (PM-215), 401 M
Street SW., Washington, D.C. 20460 (spe-
cify Public Comment SummaryModi-
fication, Notification, and Reconstruc-
tion) . The comments have been care-
fully considered, and where determined
by the Administrator to be appropriate,
changes have been made to the proposed
regulations and are incorporated in the
regulations promulgated herein. The
most significant comments and the differ-
ences between the proposed and promul-
gated regulations are discussed below.
TERMINOLOGY
Understandably there has been some
confusion as to the difference between
the various types of "sources" and "facil-
ities" defined in § 60.2 of these regula-
tions. Generally speaking, "sources" are
entire plants, while "facilities" are iden-
tifiable pieces of process equipment or
individual components which when taken
together would comprise a source. "Af-
fected facilities" are facilities subject to
standards of performance, and are spe-
cifically identified in the first section of
each subpart of Part 60. An "existing
facility" is generally a piece of equipment
or component of the same type as an
affected facility, but which differs in that
it was constructed prior to the date of
proposal of an applicable standard of
performance. This distinction is some-
what complicated because an existing
RULES AND REGULATIONS
facility which undergoes a modification
within the meaning of the Act and these
regulations becomes an affected facility.
However, generally speaking, the distinc-
tion between "affected facilities" and
"existing facilities" depends on the date
of construction. The terms are intended
to be the direct regulatory counterparts
of the statutory definitions of "new
source" and "existing source" appearing
in section 111 of the Act.
"Designated facilities" form a sub-
category of "existing facilities." A "des-
ignated facility" is an existing facility
which emits a "designated pollutant,"
i.e., a pollutant which is neither a haz-
ardous pollutant, as defined by section
112 of the Act, nor a pollutant subject to
national ambient air quality standards.
The term "designated facilities," how-
ever, has no special relevance to the issue
of modification.
DEFINITION OF "CAPITAL EXPENDITURE"
Several commentators argued that the
proposed definition of "capital expendi-
ture," as applicable to the exemption for
increasing the production rate of an ex-
isting facility in § 60.14(e) (2), was too
vague. The regulations promulgated
herein correct this deficiency by incorpo-
rating by reference and by requiring the
application of the procedure contained
in Internal Revenue Service Publication
534, which is available from any IRS of-
fice. The procedure set forth in IRS Pub-
lication 534 is relatively straightfor-
ward. First, the total cost of increasing
the production or operating rate must be
determined. All expenditures necessary to
increasing the facility's operating rate
must be included in this total. However,
for purposes of § 60.14(e) (2) this amount
must not be reduced by any "excluded
additions," as defined in IRS Publication
534, as would be done for tax purposes.
Next, the facility's basis (usually its
cost), as defined by Section 1012 of the
Internal Revenue Code, must be deter-
mined. If the product of the appropriate
"annual asset guideline repair allowance
percentage" tabulated in Publication 534
and the facility's basis exceeds the cost
of increasing the operating rate, the
change will not be treated as a modifica-
tion. Conversely, if the cost of making
the change is more than the above prod-
uct and the emissions have increased, the
change will be treated as a modification.
The advantage of adopting the proce-
dure in IRS Publication 534 is that firm
and precise guidance is provided as to
what constitutes a capital expenditure.
The procedure involves concepts and in-
formation which are available to all own-
ers and operators and with which they
are familiar, and it is the Administrator's
opinion that it adequately responds to
the complaints of vagueness made in
comments.
NOTIFICATION OF CONSTRUCTION
The regulations promulgated herein
contain a requirement that owners or op-
erators notify EPA within 30 days of
the commencement of construction of
an affected facility. Some commentators,
however, questioned the Agency's legal
authority to require such a notification
and questioned the need for such Infor-
mation.
Section 301 (a) of the Act provides the
Administrator authority to issue regula-
tions "necessary to carry out his func-
tions under [the! Act." The Agency has
learned through experience with admin-
istering the new source performance
standards that knowledge of the sources
which may become subject to the stand-
ards is important to the effective imple-
mentation of section 111. This notifica-
tion will not be used for approval or
disapproval of the planned construction;
the purpose is to allow the Administrator
to locate sources which will be subject to
the regulations appearing in this part,
and to enable the Administrator to in-
form the sources about applicable regu-
lations in an effort to minimize future
problems. In the case of mass produced
facilities, which are purchased by the
-ultimate user when construction is com-
pleted, the construction notification re-
quirement will not apply. Notification
prior to startup, however will still be
required.
USE OF EMISSION FACTORS
The proposed regulations listed emis-
sion factors as one possible method to
be used in determining whether a facility
has increased its emissions. Emission
factors have two major advantages.
First, they are inexpensive to use. Second,
they may be applied prospectively, i.e.,
they can be used in some cases to deter-
mine whether a particular change will in-
crease a facility's emissions before the
change is implemented. This is important
to owners or operators since they can
thereby obtain advance notice of the
consequences of proposed changes they
are planning prior to commitment to a
particular course of action. Emission fac-
tors do not, however, provide .results as
precise as other methods, such as actual
stack testing. Nevertheless, in many
cases the emission consequences of a pro-
posed change can be reliably predicted
by the use of emission factors. In such
cases, where emissions will clearly in-
crease or will clearly not increase, the
Agency will rely primarily on emission
factors. Only where the resulting change
in emission rate is ambiguous, or where
a dispute arises as to the result ob-
tained by the use of emission factors, will
other methods be used. Section 60.14(b)
has been revised to reflect this policy.
THE "BUBBLE CONCEPT"
The phrase "bubble concept" has been
used to refer to the trading off of emis-
sion increases from one facility under-
going a physical or operational change
with emission reductions from another
facility, in order to achieve no net in-
crease in the amount of any air pollut-
ant (to which a standard applies) emit-
ted into the atmosphere by the stationary
source taken as a whole.
Several commentators suggested that
the "bubble concept" be extended to cover
"new construction." Under the proposed
regulations, the "bubble concept" could
be utilized to offset emission increases
FEDERAL REGISTER, VOL. 40, NO. 24 JTUESDAY, DECEMBER 16. 1975
IV-113
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RULES AMD REGULATIONS
58417
from a facility undergoing a physical or
operational change (as distinguished
from a "new facility") at a lower eco-
nomic cost than would arise if the facil-
ity undergoing the change were to be
considered by EPA as being modified
within the meaning of section 111 of the
Act and consequently required to meet
standards of performance. Under the
suggested approach a new facility could
be added to an existing source without
having to meet otherwise applicable
standards of performance, provided the
amount of any air pollutant (to which a
standard applies) emitted into the
atmosphere by the stationary source
taken as a whole did not increase. If
adopted, this suggestion could exempt
most new construction at existing sources
from having to comply with otherwise
applicable standards of performance.
Such an interpretation of the section 111
provisions of the Act would grant a sig-
nificant and unfair economic advantage
to owners or operators of existing sources
replacing facilities with new construc-
tion as compared to someone wishing to
construct an entirely new source.
If the bubble concept were extended to
cover new construction, large sources of
air pollution could avoid the application
of new source performance standards in-
definitely. Such sources could continu-
ally replace obsolete or worn out facili-
ties with new facilities of the same type.
If the same emission controls were
adopted, no overall emission increase
would result. In this manner, the source
could continue indefinitely without ever
being required to upgrade air pollution
control systems to meet standards of per-
formance for new facilities. The Admin-
istrator interprets section 111 to require
that new producers of emissions be sub-
ject to the standards whether con-
structed at a new plant site or an exist-
ing one. Therefore, where a new facility
is constructed, new source performance
standards must be met. In situations in-
volving physical or operational changes
to an existing facility which increase
emissions from that facility, greater
flexibilty is permitted to avoid the im-
position of large control costs if the pro-
jected increase can be offset by con-
trolling other plant facilities.
Several commentators argued that If
the Administrator adopted the proposed
Interpretation of the term "modifica-
tion", which would consider a modifica-
tion to have occurred even if there was
only a relatively minor detectable emis-
sion rate increase (thus requiring appli-
cation of standards of performance), the
Administrator would in effect prevent
owners or operators from implementing
physical or operational changes neces-
sary to switch from gas and oil to coal in
comport with the President's policy of
reducing gas and oil consumption. The
Administrator has concluded that if such
situations exist, they will be relatively
rare and, in any event, will be peculiar
to the group of facilities covered by a
particular standard of performance
rather than to all facilities in general.
Therefore, the Administrator has further
concluded that it would be more appro-
priate to consider such circumstances
and possible avenues of relief in connec-
tion with the promulgation of or amend-
ment to particular standards of perform-
ance rather than through the amend-
ment of the general provisions of 40
CFR Part 60.
Where the use of the bubble concept
is elected by an owner or operator, some
guarantee is necessary to insure that
emissions do not subsequently increase
above the level present before the physi-
cal or operational change in question.
For example, reducing a facility's oper-
ating rate is a permissible means of off-
setting emission increases from another
facility undergoing a physical or opera-
tional change. If the exemption provided
by § 60.14(e) (2) as promulgated herein
were subsequently used to increase the
first facility's operating rate back to the
prior level, the intent of the Act would
be circumvented and the compliance
measures previously adopted would be
nullified. Therefore, in those cases where
utilization of the exemptions under
§ 60.14(e) (2), (3), or (4) as promulgated
herein would effectively negate the com-
pliance measures originally adopted, use
of those exemptions will not be permitted.
One limitation placed on utilization of
the "bubble concept" by the proposed
regulation was that emission reductions
could be credited only if achieved at an
"existing" or "affected" facility. The pur-
pose of this requirement was to limit the
"bubble concept" to those facilities which
could be source tested by EPA reference
methods. One commentator pointed out
that some facilities other than "existing"
or "affected" facilities (I.e., facilities of
the type for which no standards have
been promulgated) lend themselves to
accurate emission measurement. There-
fore, § 60.14(d) has been revised to per-
mit emission reductions to be credited
from all facilities whose emissions can
be measured by reference, equivalent, or
alternative methods, as defined in § 60.2
(s), (t), and (u). In addition, when a
facility which cannot be tested by any
of these methods is permanently closed,
the regulations have been revised to per-
mit emission rate reductions from such
closures to be used to offset emission rate
increases if methods such as emission
factors clearly show, to the Administra-
tor's satisfaction that the reduction off-
sets any increase. The regulation does
not allow facilities which cannot be tested
by any of these methods to reduce their
production as a means of reducing emis-
sions to offset emission rate increases be-
cause establishing allowable emissions for
such facilities and monitoring compli-
ance to insure that the allowable emis-
sions are not exceeded would be very
difficult and even impossible in many
cases.
Also, under the proposed regulations
applicable to the "bubble concept," ac-
tual emission testing was the only per-
missible method for demonstrating that
there has been no increase in the total
emission rate of any pollutant to which
a standard applies from all facilities
within the stationary source. Several
commentators correctly argued that if
methods such as emission factors are
sufficiently accurate to determine emis-
sion rates under other sections of the
regulation U.e. §60.14(b)l, they should
be adequate for the purposes of utiliza-
tion of the bubble concept. Thus, the
regulations have been revised to permit
the use of emission factors in those cases
where it can be demonstrated to the Ad-
ministrator's satisfaction that they will
clearly show that total emissions wll
or will not increase. Where the Admin-
istrator is not convinced of the reliability
of emission factors in a particular case,
other methods will be required.
OWNERSHIP CHANGE
The regulation has been amended by
adding § 60.14(e) (6) which states that a,
change in ownership or relocating a
source does not by itself bring a sourcs
under these modification regulations.
RECONSTRUCTION
Several commentators questioned the
Agency's legEd authority to propose
standards of performance on recon-
structed sources. Many commentators
further believed that the Agency is at-
tempting to delete the emission increase
requirement from the definition of modi-
fication. The Agency's actual intent is to
prevenr, circumvention of the law. Sec-
tion 111 of the Act requires compliance
with standards of performance in two
cases, new construction and modifica-
tion. The reconstruction provision is in-
tended to apply where an existing facil-
ity's components are replaced to such an
extent that it is technologically and
economically feasible for the recon-
structed facility to comply with the ap-
plicable standards of performance. In
the case of an entirely new facility the
proper time to apply the best adequately
demonstrated control technology is when
the facility is originally constructed. As;
explained in the preamble to the pro-
posed regulation, the purpose of the re-
construction provision is to recognize
that replacement of many of the com-
ponents of a facility can be substantially
equivalent to totally replacing it at the
end of its useful life with a newly con-
structed affected facility. For existing
facilities which substantially retain their
character as existing facilities, applica-
tion of best adequately demonstrated
control technology is considered appro-
priate when any physical or operational
change is made which causes an increase
in emissions to the atmosphere (this is
modification). Thus, the criteria for "re-
construction" are independent from the
criteria for "modification."
Sections 60.14 and 60.15 set up the pro-
cedures and criteria to be used in making
the determination to apply best ade-
quately demonstrated control technology
to existing facilities to which some
changes have been made.
Under the proposed regulations, the
replacement of a substantial portion of
an existing facility's components con-
stituted reconstruction. Many commen-
tators questioned the meaning of "sub-
stantial portion." After considering the
comments and the vagueness of this
term, the Agency decided to revise the
proposed reconstruction provisions to
FEDERAL REGISTER, VOL. 40. NO. 242TUESDAY. DECEMBER 16. 197$
IV-114
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5&18
RULES AND REGULATIONS
better clarify to owners or operators what
actions they must take and what action
the Administrator will take. Section 60.15
of the regulations as revised specifies
that reconstruction occurs upon replace-
ment of components if the fixed capital
cost of the new components exceeds 50
percent of the fixed capital cost that
would be required to construct a com-
parable entirely new facility and it is
technologically and economically feasi-
ble for the facility after the replace-
ments to comply with the applicable
standards of performance. The 50 per-
cent replacement criteria is designed
merely to key the notification to the
Administrator; it is not an independent
basis for the Administrator's determina-
tion. The term "fixed capital cost" is de-
fined as the capital needed to provide all
the depreciable components and is in-
tended to include such things as the costs
of engineering, purchase, and installa-
tion of major process equipment, con-
tractors' fees, instrumentation, auxiliary
facilities, buildings, and structures. Costs
associated with the purchase and instal-
lation of air pollution control equipment
(e g., baghouses, electrostatic precipita-
tors, scrubbers, etc.) are not considered
In estimating the fixed capital cost of a
comparable entirely new facility unless
that control equipment is required as
part of the process (e.g., product re-
covery) .
The revised § 60.15 leaves the final de-
termination with the Administrator as
to when It is technologically and eco-
nomically feasible to comply with the
applicable standards of performance.
Further clarification and definition is
not possible because the spectrum of re-
placement projects that will take place
in the future at existing facilities is so
broad that it is not possible to be any
more specific. Section 60.15 sets forth
the criteria which the Administrator will
use in making his determination. For
example, if the estimated life of the
facility after the replacements is sig-
niflicantly less than the estimated life
of a new facility, the replacement may
not be considered reconstruction. If the
equipment being replaced does not emit
or cause an emission of an air pollutant,
It may be determined that controlling
the components that do emit air pol-
lutants is not reasonable considering
cost, and standards of performance for
new sources should not be applied. If
there is Insufficient space after the re-
placements at an existing facility to in-
stall the necessary air pollution control
system to comply with the standards of
performance, then reconstruction would
Qot be determined to have occurred.
Finally, the Administrator will consider
all technical and economic limitations
the facility may have in complying with
the applicable standards of performance
after the proposed replacements.
While . § 60.15 expresses the basic
Agency policy and interpretation regard-
Ing reconstruction, Individual subparts
may refine and delimit the concept as
applied to individual categories of
faculties.
RESPONSE TO REQUESTS FOR
DETERMINATION
Section 60.5 has been revised to in-
dicate that the Administrator will make
a determination of whether an action
by an owner or operator constitutes re-
construction within the meaning of
§ 60.15. Also, in response to a public com-
ment, a new § 60.5(b) has been added to
indicate the Administrator's intention to
respond to requests for determinations
within 30 days of receipt of the request.
STATISTICAL TEST
Appendix C of the regulation incorpo-
rates a statistical procedure for deter-
mining whether an emission increase has
occurred. Several individuals commented
on the procedure as proposed. After con-
sidering all these comments and con-
ducting further study into the subject,
the Administrator has determined that
a statistical procedure is substantially
superior to a method comparing average
emissions, and that no other statistical
procedure is clearly superior to the one
adopted (Student's t test). A more de-
tailed analysis of this issue can be found
In EPA's responses to the comments
mentioned previously.
Effective date. These regulations are
effective on December 16, 1975. Since
they represent a clarification of the
Agency's existing enforcement policy,
good cause Is found for not delaying the
effective date, as required by 5 U.S.C.
553(d) (3). However, the regulations will,
in effect, apply retroactively to any en-
forcement activity now in progress since
they do reflect present Agency policy.
(Sections 111, 114, and 301 of the Clean Air
Act, as amended (42 U.S.C. 1857c-6, 1857C-9,
and 1857g))
Dated: December 8, 1975.
RUSSELL E. TRAIN,
Administrator.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations Is amended
as follows:
1. The table of sections is amended by
adding §5 60.14 and 60.15 and Appendix
C as follows:
Subpart AGeneral Provisions
*****
Sec.
60.14 Modification.
60.15 Reconstruction.
Appendix CDetermination of Emission
Rate Change.
2. In § 60.2, paragraphs (d) and (h)
are revised and paragraphs (aa) and
(bb) are added as follows:
§ 60.2 Definitions.
(d) "Stationary source" means any
building, structure, facility, or installa-
tion which emits or may emit any air
pollutant and which contains any one or
combination of the following:
(1) Affected facilities.
(2) Existing facilities.
(3) Facilities of the type for which no
standards have been promulgated in this
part.
(h) "Modification" means any physi-
cal change in, or change in the method
of operation of, an existing facility which
increases the amount of any air pollutant
(to which a standard applies) emitted
Into the atmosphere by that facility or
which results in the emission of any air
pollutant (to which a standard applies)
into the atmosphere not previously
emitted.
*****
(aa) "Existing facility" means, with
reference to a stationary source, any ap-
paratus of the type for which a standard
is promulgated in this part, and the con-
struction or modification of which was
commenced before the date of proposal
of that standard; or any apparatus
which could be altered in such a way as
to be of that type.
(bb) "Capital expenditure" means an
expenditure for a physical or operational
change to an existing facility which ex-
ceeds the product of the applicable "an-
nual asset guideline repair allowance
percentage" specified in the latest edi-
tion of Internal Revenue Service Publi-
cation 534 and the existing facility's
basis, as defined by section 1012 of the
Internal Revenue Code.
3. Section 60.5 is revised to read as
follows:
§ 60.5 Determination of eonstmclion or
Biodifioalion,
(a) When requested to do so by an
owner or operator, the Administrator
will make a determination of whether
action taken or intended to be taken by
such owner or operator constitutes con-
struction (including reconstruction) or
modification or the commencement
thereof within the meaning of this part.
(b) The Administrator will respond to
any request for a determination under
paragraph (a) of this section within 30
days of receipt of such request.
4. In §60.7, paragraphs (a)(l) and
(a) (2) are revised, and paragraphs
(a) (3), (a) (4), and (e) are added as
follows:
§ 60.7 Notification and recordkeeping.
(a) Any owner or operator subject to
the provisions of this part shall furnish
the Administrator written notification
as follows:
(DA notification of the date construc-
tion (or reconstruction as defined under
§ 60.15) of an affected facility is com-
menced postmarked no later than 30
days after such date. This requirement
shall not apply in the case of mass-pro-
duced facilities which are purchased in
completed form.
(2) A notification of the anticipated
date of initial startup of an affected
facility postmarked not more than 60
days nor less than 30 days prior to such
date.
(3) A notification of the actual date
of initial startup of an affected facility
postmarked within 15 days after such
date.
(4) A notification of any physical or
operational change to an existing facil-
ity which may increase the emission rate
of any air pollutant to which a stand-
ard applies, unless that change Is spe-
FEDERAL REGISTER. VOL. 40. NO. 242TUESDAY. DECEMBER 16. 1975
IV-115
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RULES AND REGULATIONS
58419
:ifically exempted under an applicable
sUbpart or in § 60.14ie) and the exemp-
tion is not denied under §60.14(dX4>.
This notice shall be postmarked 60 days
or as soon as practicable before the
change is commenced and shall include
information describing the precise na-
ture of the change, present and proposed
emission control systems, productive
capacity of the facility before and after
the change, and the expected comple-
tion date of the change. The Administra-
tor may request additional relevant in-
formation subsequent to this notice.
* * * * *
(e) If notification substantially similar
to that in paragraph (a) of this section
is required by any other State or local
agency, sending the Administrator a
copy of that notification will satisfy the
requirements of paragraph (a) of this
section.
5. Subpart A is -amended by adding
§§ 60.14 and 60.15 as follows:
§ 60.14 Modification.
(a) Except as provided under para-
graphs (d), (e) and (f) of this section,
any physical or operational change to
an existing facility which results in an
Increase in the emission rate to the
atmosphere of any pollutant to which a
standard applies shall be considered a
modification within the meaning of sec-
tion 111 of the Act. Upon modification.
an existing facility shall become an af-
fected facility for each pollutant to
which a standard applies and for which
there is an increase in the emission rate
to the atmosphere.
(b) Emission rate shall be expressed as
kg/hr of any pollutant discharged into
the atmosphere for which a standard is
applicable. The Administrator shall use
the following to determine emission rate:
(1) Emission factors as specified in
the latest issue of "Compilation of Air
Pollutant Emission Factors," EPA Pub-
lication No. AP-42, or other emission
factors determined by the Administrator
to be superior to AP-42 emission factors,
in cases where utilization of emission
factors demonstrate that the emission
level resulting from the physical or op-
erational change will either clearly in-
crease or clearly not increase.
(2) Material balances, continuous
monitor data, or manual emission tests
In cases where utilization of emission
factors as referenced in paragraph (b)
(1) of this section does not demonstrate
to the Administrator's satisfaction
whether the emission level resulting from
the physical or operational change will
either clearly increase or clearly not in-
crease, or where an owner or operator
demonstrates to the Administrator's
satisfaction that there are reasonable
grounds to dispute the result obtained by
the Administrator utilizing emission fac-
tors as referenced in paragraph (b)(l)
of this section. When the emission rate
is based on results from manual emission
tests or continuous monitoring systems,
the procedures specified in Appendix C
of this part shall be used to determine
whether an Increase in emission rate has
occurred. Tests shall be conducted under
such conditions as the Administrator
shall specify to the owner or operator
based on representative performance of
the facility. At least three valid test
runs must be conducted before and at
least three after the physical or opera-
tional change. All operating parameters
which may affect emissions must be held
constant to the maximum feasible degree
for all test runs.
(c) The addition of an affected facility
to a stationary source as an expansion
to that source or as a replacement for
an existing facility shall not by itself
bring within the applicability of this
part any other facility within that
source.
(d) A modification shall not be deemed
to occur if an existing facility undergoes
a physical or operational change where
the owner or operator demonstrates to
the Administrator's satisfaction (by any
of the procedures prescribed under para-
graph (b> of this section) that the total
emission rate of any pollutant has not
increased from all facilities within the
stationary source to which appropriate
reference, equivalent, or alternative
methods, as defined in § 60.2 (s), (t) and
(u), can be applied. An owner or operator
may completely and permanently close
any facility within a stationary source
to prevent an increase in the total emis-
sion rate regardless of whether such
reference, equivalent or alternative
method can be applied, if the decrease
in emission rate from such closure can
be adequately determined by any of the
procedures prescribed under paragraph
(b) of this section. The owner or oper-
ator of the source shall have the burden
of demonstrating compliance with this
section.
(1) Such demonstration shall be in
writing and shall include:
(3) of this section shall be a violation of
these regulations except as otherwise
provided in paragraph (e) of this sec-
tion. However, any owner or operator
electing to demonstrate compliance un-
der this paragraph (d) must apply to
the Administrator to obtain the use of
any exemptions under paragraphs (ei
(2), (e)(3), and (e) (4) of this section.
The Administrator will grant such ex-
emption only if, in his judgment, the
compliance originally demonstrated un-
der this paragraph will not be circum-
vented or nullified by the utilization of
the exemption.
(5) The Administrator may require
the use of continuous monitoring devices
azid compliance with necessary reporting
procedures for each facility described in
paragraph (dXlXiii) and (dXIXv) of
this section.
(e> The following shall not, by them-
selves, be considered modifications under
this part:
(1) Maintenance, repair, and replace-
ment which the Administrator deter-
mines to be routine for a source category,
subject to the provisions of paragraph
'c) of this section and § 60.15.
(2) An increase in production rate of
an existing facility, if that increase can
be accomplished without a capital ex-
penditure on the stationary source con-
taining that facility.
(3) An increase in the hours of opera-
tion.
(4) Use of an alternative fuel or raw
material if, prior to the date any stand-
ard under this part becomes applicable
to that source type, as provided by § 60.1,
the existing facility was designed to ac-
commodate that alternative use. A
facility shall be considered to be designed
to accommodate an alternative fuel or
raw material if that use could be accom-
plished under the facility's construction
FEDERAL REGISTER, VOL. 40. NO. 242TUESDAY DECEMRFP 16 1975
IV-116
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58420
RULES AND REGULATIONS
specifications, as amended, prior to the
change. Conversion to coal required for
energy considerations, as specified In sec-
tion 119(d)(5) of the Act, shall not be
considered a modification.
(5) The addition or use of any system
or device whose primary function Is the
reduction of air pollutants, except when
an emission control system Is removed
or Is replaced by a system which the Ad-
ministrator determines to be less en-
vironmentally beneficial.
(6) The relocation or change In
ownership of an existing facility.
(f) Special provisions set forth under
an applicable subpart of this part shall
supersede any conflicting provisions of
this section.
(g) Wfthin 180 days of the comple-
tion of any physical or operational
change subject to the control measures
specified In paragraphs (a) or (d) of
this section, compliance with all appli-
cable standards must be achieved.
§ 60.15 Reconstruction.
(a) An existing facility, upon recon-
struction, becomes an affected facility,
Irrespective of any change In emission
rate.
(b) "Reconstruction" means the re-
placement of components of an existing
facility to such an extent that:
(1) The fixed capital cost of the new
components exceeds 50 percent of the
fixed capital cost that would be required
to construct a comparable entirely new
facility, and
(2) It is technologically and econom-
Icall.' feasible to meet the applicable
standards set forth in this part.
"Fixed capital cost" means the
capital needed to provide all the de-
preciable components.
(d) If an owner or operator of an
existing facility proposes to replace com-
ponents, and the fixed capital cost of the
new components exceeds 50 percent of
the fixed capital cost that would be re-
quired to construct a comparable en-
tirely new facility, he shall notify the
Administrator of the proposed replace-
ments. The notice must be postmarked
60 days (or as soon as practicable) be-
fore construction of the replacements is
commenced and must include the fol-
lowing informatipn:
(1) Name and address of the owner
or operator.
(2) The location of the existing facil-
ity.
(3) A brief description of the existing
facility and the components which are to
be replaced*
(4) A description of the existing air
pollution control equipment and the
proposed air pollution control ecjuip-
ment.
(5) An estimate of the fixed capital
cost of the replacements and of con-
structing a comparable entirely new
faculty.
. (6) The estimated life of the existing
facility after the replacements.
(7) A discussion of any economic or
technical limitations the facility may
have in complying with the applicable
standards of performance after the pro-
posed replacements.
(e) The Administrator will deter-
mine, within 30 days of the receipt of the
notice required by paragraph (d) of this
section and any additional Information
he may reasonably require, whether the
proposed replacement constitutes re-
construction.
(f) The Administrator's determination
under paragraph (e) shall be based on:
(1) The fixed capital cost of the re-
placements in comparison to the fixed
capital cost that would be required to
construct a comparable entirely new
facility;
(2) The estimated life of the facility
after the replacements compared to the
life of a comparable entirely new facility;
(3) The extent to which the compo-
nents being replaced cause or contribute
to the emissions from the facility; and
(4) Any economic or technical limita-
tions on 'compliance with applicable
standards of performance which are in-
herent In the proposed replacements.
(g) Individual subparts of this part
may Include specific provisions which
refine and delimit the concept of recon-
struction set forth In this section.
6. Part 60 Is amended by adding Ap-
pendix C as follows:
APPENDIX CDETEBMIVATION or EMISSION RATS
CHANGE
1. Introduction.
1.1 The following method shall be used to determine
whether a physical or operational change to an existing
facility resulted In an Increase In the emission rate to the
atmosphere. The method used Is the Student's ( test.
commonly used to mako inferences from small samples.
1. Data.
2 I Each emission test shall consist of n runs (usually
three) which produce n emission rates. Thus two sets of
emission rates are generated, one before and one after the
change, the two sets betng of equal sire.
2 2 When using maminl emission tests, eicept as pro-
vided In 5 GO 8(h) of tins part, the reference methods of
Appendix A to this part shall be used In accordance with
the procedures specified in the applicable subpart both
before and after the change to obtain the data.
2.3 When using continuous monitors, the facility shall be
operated as if a manufil emission test were being per-
formed. Valid data using the averaging time which would
be required If a manual emission test wore being con-
ducted shall be used,
3 Procedure.
3.1 Subscripts a and b denote prechange and post-
change respectively.
3.2 Calculate the arithmetic mean emission rat«, E, tor
each set of data using Equation 1.
3.4 Calculate the pooled estimate, B*. aatnf Iqoa.
Uon 3,
where:
E," Emission rate IDT tije i th run.
of runs
8.3 Calculate tbe sample variance, S1, lor each aet of
data using Equation 2,
. + nt-2
Jk'T
(3)
Calculate the tost statistic, (, using Equation 4.
t--
?' Ln.+nt
r
nj
4.1 If Kt> 7:. and Of', where f Is the critical value of
t obtained from Table 1. then with 95% confidence the
difference between Kt and K. Is significant, and an In.
crease In emission rate to the atmosphere has occurred.
TABLE 1
f(SS
fcrcent
conft-
dena
Degree of freedom (n.+ni-2): kxl)
2 2.920
3 2.353
4 2. 132
B _ Z015
8 L943
7 L89S
8 L860
For greater than 8 degrees of freedom, see any standard
statistical handbook or text.
6.1 Assume the two performance tests produced tbe
following sat of data:
Test a: Test b
Run 1. 100 115
Run 2. 95 120
Run3. 110 _ 125
6.2 Using Equation 1
,, 100 + 05 + 110
B.= 3 =
E =H5f 120+125
* 3
6.3 Using Equation 2
:102
:120
(100-102)'+(95-102)'+(110-102)'
= 3-1
=58.5
>>
(115-120)'+(120-120)'+(125-120)*
~ 3-1
=25
6.4 Using Equation 3
5,=
-(3-1) (58.5)4(3-1) (25)
L 3+3-2
6.6 Using Equation 4
120-102
= 6.46
= 3.412
n-1
6.461 i+n-
6.6 Since (m+ni-2)=4, r-2.132 (from Table I). Thus
rinee tyf the difference In the values of Km and Ki Is
significant, and there has been an increase In emission
rate to tbe atmosphere.
6. Continuous Monitoring Data,
6.1 Hourly averages from continuous monitoring de-
vices where available, should be used as data points and
Uie above procedure followed.
(Bees. Ill and 114 of the Clean Air Act, as amended by
tec. 4(a) of Pub. L. 91-404, 84 Stet 1878 (42 U.8.C. 1857o-
8,1857e-fl))
[FB DOC.7&-33612 Filed 12-16-76;8:45 am]
FEDERAL REGISTER, VOL. 40, NO. 242TUESDAY. DECEMBER 16, 1975
IV-117
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RULES AND REGULATIONS
23 [FKL 471-6]
J>£feT 60STANDARDS OF PERFORMANCE
FOR NEW STATIONARY SOURCES
Emission Monitoring Requirements and Re-
visions to Performance Testing Methods;
Correction
In FR Doc. 75-26565 appearing at page
46250 in the FEDERAL REGISTER of October
6, 1975, the following changes should be
made in Appendix B:
1 On page 4G2GO. paragraph 4 3, line
21 is corrected to read as follows:
log U-0,)=(li/l.) log (1-0-0
2. On page 462G3, paragraph 4.1, line 8
is corrected to read as follows:
of an air preheater in a steam generating
3. On page 46269, paragraph 7.2.1, the
definition of C.I.« is corrected to read
as follows:
CI...1-95 percent confidence interval
estimates of the average mean value
Dated: December 16,1975.
ROGER STRELOW,
Assistant Administrator tor
Air and Waste Management.
|F'R Doc.75-34514 Filed 12-19-76,8.45 am|
24
last word, now reading "capacity", should
read "opacity".
4 In paragraph (c) (2) (iii) of §60.13
on page 46255, the parenthetical phrase
"(date of promulgation" should read,
"October 6, 1975".
5. In § 60.13, the paragraphs desig-
nated (g)(l) and (g)UHi) through
(ix) on page 46256 should be designated
paragraph (i) and 1 through (9).
6. In the second line of the formula
in paragraph CD (4) of §6045 on page
46257, the figure now reading "6.34"
should read "3 64".
7. The last line of the first paragraph
in Appendix B on page 46259 should be
changed to read "tinuous measurement
of the opacity of stack emissions".
8. The paragraph now numbered "22"
in Appendix B on page 4G259 should be
numbered "2.2".
9. In the next to last line of paia-
graphs 9.1.1 and 7.1.1 on pages 462G1
and 46264 respectively "x" should read
"x"
10. The first column in the table in
paragraph 7 1 2 on page 4G264, the first
column should be headed by the letter
"n" and figures 1 through 10 should read
2 through 11.
IFRL, 423-7]
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Emission Monitoring Requirements and Re-
visions to Performance Testing Methods
Correction
In FR Doc. 75-26565, appearing at page
46250 in the issue for Monday, October 6,
1975, the following; changes should be
made:
1. In the first paragraph on page
46250, the words "reduction, and report-
ing requirements" should be inserted im-
mediately following the eighth line.
2. In the seventh from last line of the
first full paragraph on page 46254, the
parenthetical phrase should read, "Octo-
ber 6, 1975".
3. In the second line of the second full
paragraph on page 46254, the next to
HDEKAL MOISTER, VOt. 40, NO. J46MONDAY, DtCEMMR M,
SUBCHAPTER CAIR PROGRAMS
[PRL 474-3]
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCE
Delegation of Authority to State of Maine
Pursuant to the delegation of authority
for the standards of performance for new
stationary sources (NSPS) to the. State
of Maine on November 3, 1975, EPA Is
today amending 40 CFB 60.4, Address,
to reflect this delegation. A Notice an-
nouncing this delegation is published to-
day in the FEDERAL REGISTER.1 The
amended § 60.4, which adds the address
of the Maine Department of Environ-
mental Protection to which all reports,
requests, applications, submittals, and
communications to the Administrator
pursuant to this part must also be ad-
dressed, is set forth below.
The Administrator finds good cause for
foregoing prior public notice and for
making this rulemaking effective imme-
diately in that it is an administrative
change and not one of substantive con-
tent. No additional substantive burdens
are Imposed on the parties affected. The
delegation which is reflected by this ad-
ministrative amendment was effective on
October 7, 1975, and it serves no purpose
to delay the technical change of this ad-
dition to the State address to the Code of
Federal Regulations,
This rulemaking is effective immedi-
ately, and is issued under the authority
of Section 111 of the Clean Air Act, as
amended.
(42 US.C. 1857C-6)
Dated: December 22,1975.
BIAKLET W. LEGRO,
Assistant Administrator
for Enforcement.
1 See FR Doc. 7,5-35063 appearing elsewhere
In the Notices section of today's FEDERAL REG-
ISTER.
Part 60 of Chapter I, Tltte 40 of the
Code of Federal Regulations Is amended
as follows:
1. In 5 60.4 paragraph Ob) is amended
by revising subparagraph (tT) to read as
follows:
§ 60.4 Address.
**»**
(b) * *
(U) State of Maine, Department of Envi-
ronmental Protection, State House, Augusta,
Maine 04330.
[FR Doc.76-35066 Piled ia-39-*76-.8:
FEDERAL REGISTER, VOL. 40, NO. 250-
-TUESDAY, DECEMBER 30, 1975
IV-118
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RULES AND REGULATIONS
25
|FBL 477-7]
SUBCHAPTER CAIR PROGRAMS
PART 60STANDARDS OF PERFORMANCE
FOR NEW STATIONARY SOURCES
Delegation of Authority to the State of
Michigan
Pursuant to the delegation of au-
thority to implement and enforce the
standards of performance for new sta-
tionary sources (NSPS) to the State of
Michigan on November 5, 1975, EPA is
today amending 40 CFR 60.4 Address, to
reflect this delegation.1 The amended
§ 60.4, which adds the address of the Air
Pollution Control Division, Michigan De-
partment of Natural Resources to that
list of addresses to which all reports,
requests, applications, submittals, and
communications to the Administrator
pursuant to this part must be sent, is
set forth below.
The Administrator finds good cause for
foregoing prior public notice and for
making this rulemaking effective im-
mediately in that it is an administrative
change and not one of substantive con-
tent. No additional substantive burdens
are imposed on the parties affected. The
delegation which is reflected by this ad-
ministrative amendment was effective on
November 5, 1975, and it serves no pur-
pose to delay the technical change of this
addition of the State address to the Code
of Federal Regulations.
1A Notice announcing this delegation is
published in the Notices section of this Issue.
This rulemaking is effective immedi-
ately, and is issued under the authority
of section 111 of the Clean Air Act, as
amended. 42 U.S.C. 1857c-6.
Dated: December 31, 1975.
STANLEY W. LECRO,
Assistant Administrator
for Enforcement.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulation is amended
as follows:
1. In § 60.4, paragraph (b) is amended
by revising paragraph (b) X, to read as
follows:
60.4 Address.
*****
[FBL 447-8]
(b) * * *
(A)-(W) * *
(X)State of Michigan, Air Pollution
Control Division, Michigan Department of
Natural Resources, Stevens T Mason Build-
Ing, 8th Floor, Lansing, Michigan 48926
* * * - * *
[PR Doc.76-847 Filed 1-12-76,8 45 am]
FEDERAL REGISTER, VOL. 41, NO. 8-
-TUESDAY, JANUARY 13, 1976
26
[PRL 462-7]
PART 60 STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Coal Preparation Plants
On October 24, 1974 (39 FR 37922).
uncrer section 111 of the Clean Air Act,
as amended, the Environmental Protec-
tion Agency (EPA) proposed standards
of performance for new and modified
coal preparation plants. Interested par-
ties were afforded an opportunity to par-
ticipate in the rulemaking by submitting
written comments. Twenty-seven com-
ment letters were received; six from coal
companies, four from Federal agencies,
four from steel companies, four from
electric utility companies, three from
State and local agencies, three from coal
industry associations and three from
other interested parties.
Copies of the comment letters and a
supplemental volume of background in-
formation which contains a summary
of the comments with EPA's responses
are available for public inspection and
copying at the U.S. Environmental Pro-
tection Agency, Public Information Ref-
erence Unit, Room 2922, 401 M Street,
S.W., Washington, D.C. 20460. In addi-
tion, the supplemental volume of back-
ground Information which contains cop-
ies of the comment summary with EPA's
responses may be obtained upon written
request from the EPA Public Informa-
tion Center (PM-215), 401 M Street
S.W., Washington, D.C. 20460 (specify
Background Information for Standards
of Performance: Coal Preparation
Plants, Volume 3: Supplemental Infor-
mation) , The comments have been care-
fully considered, and where determined
by the Administrator to be appropriate,
changes have been made to the proposed
regulations and are incorporated in the
regulations promulgated herein.
The bases for the proposed standards
are presented in "Background Informa-
tion for Standards of Performance: Coal
Preparation Plants" (EPA 450/2-74-021a,
b). Copies of this document are available
on request from the Emission Standards
Protection Agency, Research Triangle
and Engineering Division, Environmental
Park, North Carolina 27711, Attention:
Mr. Don R. Goodwin.
Summary of Regulation. The promul-
gated standards of performance regulate
particulate matter emissions from coal
preparation and handling facilities proc-
essing more than 200 tons/day of bitu-
minous coal (regardless of their location)
as follows: (1) emissions from thermal
dryers may not exceed 0.070 g/dscm
(0.031 gr/dscf) and 20% opacity, (2)
emissions from pneumatic coal cleaning
equipment may not exceed 0.040 g/dscm
(0.018 gr/ dscf) and 10% opacity, and
(3) emissions from coal handling and
storage equipment (processing non-
bituminous as well as bituminous coal)
may not exceed 20% opactity.
Significant Comments and Revisions to
the Proposed Regulations. Many of the
comment letters received by EPA con-
tained multiple comments. These are
summarized as follows with discussions of
any significant differences between the
proposed and promulgated regulations.
1. 4.pr>licability.Comments were re-
ceived noting that the proposed stand-
ards would apply to any coal handling
operation regardless of size and would
require even small tipple operations and
domestic coal distributors to comply with
the proposed standards for fugitive
emissions. In addition, underground
mining activities may have been inad-
vertently included under the proposed
standards. EPA did not intend to regu-
late either these small sources or under-
ground mining activities. Only sources
which break, crush, screen, clean, or dry
large amounts of coal were intended to be
covered. Sources which handle large
ampunts of coal would include coal han-
dling operations at sources such as barge
loading facilities, power plants, coke
ovens, etc. as well as plants that pri-
marily clean and/or dry coal. EPA con-
cluded that sources not intended to be
covered by the regulation handle less
than 200 tons/day; therefore, the regu-
lation promulgated herein exempts such
sources.
Comments were received questioning
the application of the standards to
facilities processing nonbituminous coals
(including lignite). As was stated in the
preamble to the proposed regulation, it
is intended for the standards to havf
broad applicability when appropriate. A
the time the regulation was proposed,
EPA considered the parameters relating
to the control of emissions from thermal
FEDERAL REGISTER, VOL. 41, NO. 10THURSDAY, JANUARY 15, 1976
IV-119
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RULES AND REGULATIONS
2233
dryers to be sufficiently similar, whether
bituminous or nonbituminous coal was
being dried. Since the time of proposal
EPA has reconsidered the application of
standards to the thermal drying of non-
bituminous coal. It has concluded that
such application is not prudent in the
absence of specific data demonstrating
the similarity of the drying character-
istics and emission control character-
istics to those of bituminous coal. There
p.re currently very few thermal dryers or
pneumatic air cleaners processing non-
bituminous fuels. The facilities tested
by EPA to demonstrate control equip-
ment representative of best control tech-
nology were processing bituminous coal.
Since the majority of the EPA test data
and other information used to develop
the standards are based upon bituminous
coal processing, the particulate matter
standards for thermal dryers and pneu-
matic coal cleaning equipment have been
revised to apply only to those facilities
processing bituminous coal.
The opacity standard for control of
fugitive emissions is applicable to non-
bituminous as well as bituminous coal
since nonbituminous processing facili-
ties will utilize similar equipment for
transporting, screening, storing, and
loading coal, and the control techniques
applicable for minimizing fugitive par-
ticulate matter emissions will be the
same regardless of the type of coal proc-
essed. Typically enclosures with some
type of low energy collectors are utilized.
The opacity of emissions can also be re-
duced by effectively covering or sealing
the process from the atmosphere so that
any avenues for escaping emissions are
small. By minimizing the number and
the dimensions of the openings through
which fugitive emissions can escape, the
opacity and the total mass rate of emis-
sions can be reduced independently of
the air pollution control devices. Also,
water sprays have been demonstrated to
be very effective for suppressing fugitive
emissions and can be used to control even
the most difficult fugitive emission prob-
lems. Therefore, the control of fugitive
emissions at all facilities will be required
since there are several control techniques
that can be applied regardless of the
type of coal processed.
2. Thermal dryer standard.One com-
mentator presented data and calcula-
tions which indicated that because of the
large amount of fine particles in the coal
his company processes, compliance with
the proposed standard would require the
application of a venturi scrubber with
a pressure drop of 50 to 52 inches of water
gage. The proposed standard was based
on the application of a venturi scrubber
with a pressure drop of 25 to 35 inches.
EPA thoroughly evaluated this comment
and concluded that the commentator's
calculations and extrapolations could
have represented the actual situation.
Bather than revise the standard on the
basis of the commentator's estimates,
EPA decided to perform emission tests at
a plant which processes the coal under
question. The plant tested Is controlled
with a venturi scrubber and was operated
at a pressure drop of 29 Inches during
the emission tests. These tests showed
emissions of 0.080 to 0.134 g/dscm (0.035
to 0.058 gr/dscf). These results are
numerically greater than the proposed
standard; however, calculations indicate
that if the pressure drop were increased
from 29 inches to 41 inches, the proposed
standard would be achieved. Supplemen-
tal Information regarding estimates of
emission control needed to achieve the
mass standard is contained in Section II,
Volume 3 of the supplemental back-
ground information document.
Since the cost analysis of the proposed
standard was based on a venturi scrubber
operating at 25 to 35 inches venturi pres-
sure loss, the costs of operating at higher
pressure losses were evaluated. These re-
sults indicated that the added cost of
controlling pollutants to the level of the
proposed standard is only 14 cents per
ton of plant product even if a 50 inch
pressure loss were used, and only five
cents per ton in excess of the average
control level required by state regulations
in the major coal producing states. In
comparison to the $18.95 per ton deliv-
ered price of U.S. coal in 1974 and even
higher prices today, a maximum five
cents per ton economic impact attribut-
able to these regulations appears almost
negligible. The total Impact of 14 cents
per ton for controlling particulate matter
emissions can easily be passed along to
the customer since the demand for
thermal drying due to freight rate sav-
ings, the elimination of handling prob-
lems due to freezing, and the needs of
the customer's process (coke ovens must
control bulk density and power plants
must control plugging of pulverizers' will
remain unaffected by these regulations.
Therefore, the economic impact of the
standard upon thermal drying will not
be large and the inflationary impact of
the standard on the price of coal will be
insignificant (one percent or less). From
the standpoint of energy consumption,
the power requirements of the air pollu-
tion control equipment are exponentially
related to the control level such that a
level of diminishing return is reached.
Because the highest pressure loss that
has been demonstrated by operation of
a venturi scrubber on a coal dryer is
41 inches water gage, which is also the
pressure loss estimated by a scrubber
vendor to be needed to achieve the 70
mg/dscm standard, and because energy
consumption increases dramatically at
lower control levels «70 mg/dscm), a
particulate matter standard lower than
70 mg/dscm was not selected. At the 70
mg/dscm control level, the trade-off be-
tween control of emissions at the thermal
dryer versus the increase in emissions at
the power plant supplying the energy is
favorable even though the mass quantity
of all air pollutants emitted by the power
plant (SO, NOx, and particulate matter)
are compared only to the reduction in
thermal dryer particulate matter emis-
sions. At lower than 70 mg/dscm, this
trade-off is not as favorable due to the
energy requirements of venturi scrubbers
at higher pressure drops. For this source,
alternative means of air pollution control
have not been fully demonstrated. Hav-
ing considered all comments on the par-
ticulate matter regulation proposed 1'or
thermal dryers, EPA finds no reason suf-
ficient to alter the proposed standard of
70 mg/dscm except to restrict Its ap-
plicability to thermal dryers processing
bituminous coal.
3. Location of thermal drying sys-
tems.Comments were received on the
applicability of the standard for power
plants with closed thermal drying sys-
tems where the air used to dry the coal is
also used in the combustion process. As
indicated in § 60.252(a), the standard is
concerned only with effluents which r..re
discharged into the atmosphere from the
drying equipment. Since the pulverized
coal transported by heated air is charged
to the steam generator in a closed system,
there is no discharge from the dryer di-
rectly to the atmosphere, therefore, these
standards for thermal dryers are not ap-
plicable. Effluents from steam generators
are regulated by standards previously
promulgated (40 CFR Part 60 subps.rt
D). However, these standards do apply
to all bituminous coal drying operations
that discharge effluent to the atmosphere
regardless of their physical or geograph-
ical location. In additiona to thermal
dryers located in coal preparation plans,
usually in the vicinity of the mines, dry-
ers used to preheat coal at coke ovens are
alsoregulated by these standards. These
coke oven thermal dryers used for pre-
heating are similar in all respects, in-
cluding the air pollution control equip-
ment, to those used in coal preparation
plants_
4. Opacity standards.The opacity
standards for thermal dryer and pneu-
matic coal cleaners were reevaluated as
a result of revisions to Method 9 for con-
ducting opacity observations (39 FR
39872). The opacity stndards were pro-
posed prior to the revisions of Method 9
and were not based upon the concept of
averaging sets of 24 observations for six-
minute periods. As a result, the proposed
standards were developed in relation to
the peak emissions of the facility rathur
than the average emissions of six-minute
periods. The opacity data collected by
EPA have been reevaluated in accordance
with the revised Method 9 procedures,
and opacity standards for thermal dry-
ers and pneumatic coal cleaners have
been adjusted to levels consistent with
these new procedures. The opacity stand-
ards for thermal dryers and pneumatic
coal cleaners have been adjusted from 30
and 20 percent to 20 and 10 percent
opacity, respectively. Since the proiwsed
standards were based upon peak rather
than average opacity, the revised stand-
ards are numerically lower. Each of these
levels is justified based primarily upon
six-minute averages of EPA opacity ob-
servations. These data are contained in
Section in, Volume 3 of the supplemental
background Information document.
5. Fugitive emission monitoring.
Several commentators identified somi;
difficulties with the proposed procedure;?
for monitoring the surface moisture of
thermally dried coal. The purpose of this
proposed requirement was to determine
the probability of fugitive emissions oc-
curing from coal handling operations
FEDERAL REGISTER, VOL. 41, NO. 10THURSDAY, JANUARY 15, 1976
IV-120
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2234
RULES AND REGULATIONS
and to estimate their extent. The com-
mentators noted that the proposed
A S.T.M. measurement methods are diffi-
cult and cumbersome procedures not
typically used by operating facilities.
Also, H was noted that there is too little
uniformity of techniques within industry
for measuring surface moisture to spe-
cify a general method. Secondly, esti-
mation of fugitive emissions from such
data may not be consistent due to differ-
ent coal characteristics. Since the opac-
ity standard promulgated herein can
readily be utilized by enforcement per-
sonnel, the moisture monitoring require-
ment is relatively unimportant. EPA has
therefore eliminated this requirement
from the regulation.
6. Open storage piles.The proposed
regulation applied the fugitive emission
standard to coal storage systems, which
were defined as any facility used to store
coal. It was EPA's intention that this
definition refer to some type of structure
such as a bin, silo, etc. Several com-
mentators objected to the potential ap-
plication of the fugitive emission stand-
ard to open storage piles. Since the
fugitive emission standard was not de-
veloped for application to open storage
piles, the regulations promulgated here-
in clarifies that open storage piles of coal
are not regulated by these standards.
7. Thermal dryer monitoring equip-
ment.A number of commentators felt
that important variables were not being
considered for monitoring venturi scrub-
ber operation on thermal dryers. The
proposed standards required monitoring
the temperature of the gas from the
thermal dryer and monitoring the
venturi scrubber pressure loss. The
promulgated standard requires, in addi-
tion to the above parameters, monitor-
ing of the water supply pressure to the
venturi scrubber. Direct measurement
of the water flow rate was considered
but rejected due to potential plugging
problems as a result of solids typically
found In recycled scrubber water. Also,
the higher cost of a flow rate meter in
comparison to a simpler pressure moni-
toring device was a factor in the selec-
tion of a water pressure monitor for
Verifying that the scrubber receives ade-
quate water for proper operation. This
revision to the regulations will insure
monitoring of major air pollution control
device parameters subject to variation
which could go undetected and unnoticed
and could grossly affect proper opera-
tion of the control equipment. A pressure
sensor, two transmitters, and a two pen
chart recorder for monitoring scrubber
venturi pressure drop and water supply
pressure, which are commercially avail-
able, will cost approximately two to three
thousand dollars installed for each
thermal dryer. This cost is only one-
tenth of one percent of the total invest-
ment cost of a 500-ton-per-hour thermal
dryer. The regulations also require moni-
toring of the thermal dryer exit tem-
perature, but no added cost will result
because this measurement system Is
normally supplied with the thermal dry-
ing equipment and Is used as a control
point for the process control system.
Effective date.In accordance with
section 111 of the Act, as amended, these
regulations prescribing standards of
performance for coal preparation plants
are effective on January 15, 1976, and
apply to thermal dryers, pneumatic coal
cleaners, coal processing and conveying
equipment, coal storage systems, and
coal transfer and loading systems, the
construction or modification of which
was commenced after October 24, 1974.
Dated: January 8, 1976.
RUSSELL E. TRAIN,
Administrator.
Part 60 of Chapter I of Title 40 of the
Code of Federal Regulations is amended
as follows:
1. The table of contents is amended by
adding subpart Y as follows:
* * »
Subpart YStandards of Performance for Coal
Preparation Plants
Sec.
60.250 Applicability and designation of
affected facility.
60.251 Definitions.
60.252 Standards for participate matter
60.253 Monitoring of operations.
60.254 Test methods and procedures
AUTHORITY: Sees 111 and 114 of the Clean
Air Act, as amended by sec. 4(a) of Pub. L.
91-604, 84 Stat. 1678 (42 U.S.C. 1857C-6, 1857
c-9).
2. Part 60 is amended by adding sub-
part Y as follows:
* *
Subpart YStandards of Performance for
Coal Preparation Plants
§ 60.250 Applicability and designation
of affected facility.
The provisions of this subpart are
applicable to any of the following af-
fected facilities in coal preparation plants
which process more than 200 tons per
day: thermal dryers, pneumatic coal-
cleaning equipment (air tables), coal
processing and conveying equipment (in-
cluding breakers and crushers), coal
storage systems, and coal transfer and
loading systems.
§ 60.251 Definitions.
As used in this subpart. all terms not
defined herein have the meaning given
them in the Act and in subpart A of this
part.
(a) "Coal preparation plant" means
any facility (excluding underground
mining operations) which prepares coal
by one or more of the following proc-
esses: breaking, crushing, screening, wet
or dry cleaning, and thermal drying.
(b) "Bituminous coal" means solid fos-
sil fuel classified as bituminous coal by
A.S.T.M. Designation D-388-66.
(c) "Coal" means all solid fossil fuels
classified as anthracite, bituminous, sub-
bituminous, or lignite by A.S.T.M. Des-
ignation D-388-66.
(d) "Cyclonic flow" means a splraling
movement of exhaust gases within a duct
or stack.
(e) "Thermal dryer" means any fa-
cility in which the moisture content of
bituminous coal Is reduced by contact
with a heated gas stream which is ex-
hausted to the atmosphere.
(f) "Pneumatic coal-cleaning equip-
ment" means any facility which classifies
bituminous coal by size or separates bi-
tuminous coal from refuse by application
of air stream(s).
(g) "Coal processing and conveying
equipment" means any machinery used
to reduce the size of coal or to separate
coal from refuse, and the equipment used
to convey coal to or remove coal and
refuse from the machinery. This in-
cludes, but is not limited to, breakers,
crushers, screens, and conveyor belts.
(h) "Coal storage system" means any
facility used to store coal except for open
storage piles.
(i) "Transfer and loading system"
means any facility used to transfer and
load coal for shipment.
§ 60.252 Standards for parliculalc mat-
ter.
(a) On and after the date on which
the performance test required to be con-
ducted by § 60.8 is completed, an owner
or operator subject to the provisions of
this subpart shall not cause to be dis-
charged into the atmosphere from any
thermal dryer gases which:
(1) Contain participate matter in ex-
cess of 0.070 g/dscm (0.031 gr/dscf).
(2) Exhibit 20 percent opacity or
greater.
(b) On and after the date on which the
performance test required to be con-
ducted by § 60.8 is completed, an owner
or operator subject to the provisions of
this subpart shall not cause to be dis-
charged into the atmosphere from any
pneumatic coal cleaning equipment,
gases which:
(1) Contain particulate matter in ex-
cess of 0.040 g/dscm (0.018 gr/dscf).
(2) Exhibit 10 percent opacity or
greater.
(c) On and after the date on which
the performance test required to be con-
ducted by | 60.8 is completed, an owner
or operator subject to the provisions of
this subpart shall not cause to be dis-
charged into the atmosphere from any
coal processing and conveying equip-
ment, coal storage system, or coal trans-
fer and loading system processing coal,
gases which exhibit 20 percent opacity
or greater.
§ 60.253 Monitoring of operations.
(a) The owner or operator of any ther-
mal dryer shall Install, calibrate, main-
tain, and continuously operate monitor-
ing devices as follows:
(1) A monitoring device for the meas-
urement of the temperature of tiie gas
stream at the exit of the thermal dryer
on a continuous basis. The monitoring
device is to be certified by the manu-
facturer to be accurate within ±3° Fahr-
enheit.
(2) For affected facilities that use ven-
turi scrubber emission control equip-
ment:
(1) A monitoring device for the con-
tinuous measurement of the pressure loss
through the venturi constriction of the
FEDERAL REGISTER, VOL. 41, NO. 10THURSDAY, JANUARY 15, 1976
IV-121
-------
control equipment. The monitoring de-
vice is to be certified by the manufac-
turer to be accurate within ± 1 Inch
water gage.
(ii) A monitoring device for the con-
tinuous measurement of the water sup-
ply pressure to the control equipment.
The monitoring device is to be certified
by the manufacturer to be accurate with-
in ±5 percent of design water supply
pressure. The pressure sensor or tap must
be located close to the water discharge
point The Administrator may be con-
sulted for approval of alternative loca-
tions.
(b> All monitoring devices under para-
graph (a) of this section are to be recali-
brated annually in accordance with pro-
cedures under § 60.13(b) (3) of this part.
§ 60.254 Test methods and procedures.
(a) The reference methods in Ap-
pendix A of this part, except as provided
In § 60.8(b), are used to determine com-
pliance with the standards prescribed in
§ 60.252 as follows:
(1) Method 5 for the concentration of
particulate matter and associated mois-
ture content,
(2) Method 1 for sample and velocity
traverses,
(3) Method 2 for velocity and volu-
metric flow rate, and
(4) Method 3 for gas analysis.
(b) For Method 5, the sampling time
for each run is at least 60 minutes and
the minimum sample volume is 0.85 dscm
(30 dscf) except that shorter sampling
times or smaller volumes, when necessi-
tated by process variables or other fac-
tors, may be approved by the Adminis-
trator. Sampling is not to be started until
30 minutes after start-up and is to be
terminated before shutdown procedures
commence. The owner or operator of the
affected facility shall eliminate cyclonic
flow during performance tests in a man-
ner acceptable to the Administrator.
(c) The owner or operator shall con-
struct the facility so that particulate
emissions from thermal dryers or pneu-
matic coal cleaning equipment can be
accurately determined by applicable test
methods and procedures under para-
graph (a) of this section.
[FR Doc.76-1249 Filed 1-14-76,8-45 am]
FEDERAL REGISTER, VOL. 41, NO. 10THURSDAY, JANUARY 15, 1976
IV-122
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2332
RULES AND REGULATIONS
Title 40Protection of Environment
CHAPTER IENVIRONMENTAL
PROTECTION AGENCY
SUBCHAPTER CAIR PROGRAMS
[PRL 452-3]
PART 60STANDARDS OF PERFORMANCE
FOR NEW STATIONARY SOURCES
Primary Copper, Zinc, and Lead Smelters
On October 16, 1974 (39 FR 37040),
pursuant to section 111 of the Clean Air
Act, as amended, the Administrator pro-
posed standards of performance for new
and modified sources within three cate-
gories of stationary sources: (1) primary
copper smelters, (2) primary zinc smelt-
ers, and (3) primary lead smelters. The
Administrator also proposed amend-
ments to Appendix A, Reference
Methods, of 40 CFR Part 60.
Interested persons representing in-
dustry, trade associations, environmental
groups, and Federal and State govern-
ments participated in the rulemaking by
sending comments to the Agency. Com-
mentators submitted 14 letters contain-
ing eighty-five comments. Each of these
comments has been carefully considered
and where determined by the Adminis-
trator to be appropriate, changes have
been made to the proposed regulations
which are promulgated herein.
The comment letters received, a sum-
mary of the comments contained in these
letters, and the Agency's responses to
these comments are available for public
Inspection at the Freedom of Information
Center, Room 202 West Tower, 101 M
Street, S.W., Washington, D.C. Copies
of the comment summary and the
Agency's responses may be obtained by
writing to the EPA Public Information
Center (PM-215), 401 M Street, S.W.,
Washington, D.C. 20460, and requesting
the Public Comment SummaryPrimary
Copper, Zinc and Lead Smelters.
The bases for the proposed standards
are presented in "Background Informa-
tion for New Source Performance Stand-
ards: Primary Copper, Zinc and Lead
Smelters, Volume 1, Proposed Stand-
ards" (EPA-450/2-74-002a) and "Eco-
nomic Impact of New Source Perform-
ance Standards on the Primary Copper
Industry: An Assessment" (EPA Con-
tract No. 68-02-1349Task 2). Copies
of these documents are available on re-
quest from the Emission Standards and
Engineering Division, Environmental
Protection Agency, Research Triangle
Park, North Carolina 27711, Attention:
Mr. Don R. Goodwin.
SUMMARY OF REGULATIONS
The promulgated standards of per-
formance for new and modified primary
copper smelters limit emissions of par-
ticulate matter contained in the gases
discharged into the atmosphere from
dryers to 50 mg/dscm (0.022 gr/dscf). In
addition, the opacity of these gases Is
limited to 20 percent.
Emissions of sulfur dioxide contained
tat the gases discharged Into the atmos-
phere from roasters, smelting furnaces
and copper converters are limited to
0.063 percent by volume (650 parts per
million) averaged over a six-hour period.
Reverberatory smelting furnaces at pri-
mary -copper smelters which process an
average smelter charge containing a high
level of volatile impurities, however, are
exempt from this standard during those
periods when such a charge is processed.
A high level of volatile Impurities is de-
fined to be more than 0.2 weight percent
arsenic, 0.1 weight percent antimony, 4.5
weight percent lead or 5.5 weight percent
zinc. In addition, where a sulfuric acid
plant is used to comply with this stand-
ard, the opacity of the gases discharged
Into the atmosphere is limited to 20 per-
cent.
The regulations also require any pri-
mary copper smelter that makes use of
the exemption provided for reverbera-
tory smelting furnaces processing a
charge of high volatile impurity content
to keep a monthly record of the weight
percent of arsenic, antimony, lead and
zinc contained In this charge. In addi-
tion, the regulations require continuous
monitoring systems to monitor and re-
cord the opacity of emissions discharged
into the atmosphere from any dryer sub-
ject to the standards and the concentra-
tion of sulfur dioxide in the gases dis-
charged into the atmosphere from any
roaster, smelting furnace, or copper con-
verter subject to the standard. While
these regulations pertain primarily to
sulfur dioxide emissions, the Agency rec-
ognizes the potential problems posed b^
arsenic emissions and Is conducting stud-
ies to assess these problems. Appropriate
action will be taken at the conclusion of
these studies.
The promulgated standards of per-
formance for new and modified primary
zinc smelters limit emissions of particu-
late matter contained in the gases dis-
charged into the atmosphere from sinter-
ing machines to 50 mg/dscm (0.022 gr/
dscf). The opacity of these gases is
limited to 20 percent.
Emissions of sulfur dioxide contained
in the gases discharged into the atmos-
phere from roasters and from any sinter-
ing machine which eliminates more than
10 percent of the sulfur initially con-
tained in the zinc sulfide concentrates
processed are limited to 0 065 percent by
volume (650 parts per million) averaged
over a two-hour period. In addition,
where a sulfuric acid plant is used to
comply with this standard, the opacity
of the gases discharged into the atmos-
phere is limited to 20 percent.
The regulations also require continu-
ous monitoring systems to monitor and
record the opacity of emissions dis-
charged into the atmosphere from any
sintering machine subject to the stand-
ards, and the concentration of sulfur di-
oxide in the garcs discharged mto the
atmosphere from any roasters or sinter-
ing machine subject to the standard lim-
iting emissions of sulfur dioxide.
The promulgated standards of per-
formance for new and modified primary
lead smelters limit emissions of particu-
late matter contained in the gases dis-
charged into the atmosphere from blast
furnaces, dross reverberatory furnaces
and sintering machine discharge ends to
50 mg/dscm (0.022 gr/dscf). The opacity
of these gases is limited to 20 percent.
Emissions of sulfur dioxide contained
in the gases discharged into the atmos-
phere from sintering machines, electric
smelting furnaces and converters are
limited to 0.065 percent by volume (650
parts per million) averaged over a two-
hour period. Where a sulfuric acid plant
is used to comply with this standard, the
opacity of the gases discharged into the
atmosphere is limited to 20 percent.
The regulations also require con-
tinuous monitoring systems to monitor
and record the opacity of emissions dis-
charged into the atmosphere from any
blast furnace, dross reverberatory fur-
nace, or sintering machine discharge
end subject to the standards, and the
concentration of sulfur dioxide in the
gases discharged into the atmosphere
from any sintering machine, electric
furnace or converter subject to the
standards.
MAJOR COMMENTS AND CHANGES MADE TO
THE PROPOSED STANDARDS
PRIMARY COPPER SMELTERS
Most of the comments submitted to the
Agency concerned the proposed stand-
ards of performance for primary copper
smelters. As noted in the preamble to the
proposed standards, the domestic copper
smelting industry expressed strong ob-
jections to these standards during their
development. Most of the comments sub-
mitted by the industry following pro-
posal of these standards reiterated these
objections. In addition, a number of
comments were submitted by State agen-
cies, environmental organizations and
private individuals, also expressing ob-
jections to various aspects of the pro-
posed standards. Consequently, it is ap-
propriate to review the basis of toe pro-
posed standards before discussing the
comments received, the responses to these
comments and the changes made to the
standards for promulgation.
The proponed standards would have
limited the concentration of sulfur di-
oxide contained in gases discharged into
the atmosphere from all new and modi-
fied roasters: reverberatory, flash and
electric smelting furnaces; and copper
converters at primary copper smelters tc
650 parts per million. Uncontrolled roast-
ers, flash and electric smelting furnaces
and copper converters discharge ga>
streams containing more than 3>2 per-
cent sulfur dioxide. The cost of control-
ling these gas .streams with sulfuric acid
plants was considered reasonable. Re-
verberatory smelting furnaces, however,
normally discharge gas streams contain-
ing less than 3\'2 percent sulfur dioxide.
and the cost of controlling these gas
streams through the use of various sul-
fur dioxide scrubbing systems currently
available was considered unreasonable
in most cases It was the Administrator's
conclusion, however, that flash and elec-
tric smelting considered together were
applicable to essentially the full range
of domestic primary copper smelting op-
erations. Consequently, standards were
proposed which applied equally to new
FEDERAL REGISTER, VOL. 41, NO. 10THURSDAY, JANUARY 15, 1976
IV-123
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RULES AND REGULATIONS
flash, electric and reverberatory smelting
furnaces. The result was standards which
favored construction of new flash and
electric smelting furnaces over new
reverberatory smelting furnaces.
Most of the increase In copper produc-
tion over the next few years will probably
result from expansion of existing copper
smelters. Of the sixteen domestic pri-
mary copper smelters, only one employs
flash smelting and only two employ elec-
tric smelting. The remaining tliirteen
employ reverberatory smelting, although
one of these thirteen has initiated con-
struction to convert to electric smelting
and another has initiated construction to
convert to a new smelting process re-
ferred to as Noranda smelting. (The No-
tanda smelting process discharges a gas
stream of high sulfur dioxide concentra-
tion which is easily controlled at reason-
able costs. By virtue of the definition of
a smelting furnace, the promulgated
standards also apply to Noranda fur-
naces.)
In view of the Administrator's judg-
ment that the cost of controlling sulfur
dioxide emissions from reverberatory
furnaces was unreasonable, the Adminis-
trator concluded that an exemption from
the standards was necessary for existing
reverberatory smelting furnaces, to per-
mit expansion of existing smelters at rea-
sonable costs. Consequently, the pro-
posed standards stated that any physical
changes or changes in the method of
operation of existing reverberatory
smelting furnaces, which resulted in an
increase in sulfur dioxide emissions from
these furnaces, would not cause these
furnaces to be considered "modified"
affected facilities subject to the stand-
ards. This exemption, however, applied
only where total emissions of sulfur
dioxide from the primary copper smelter
in question did not increase.
Prior to the proposal of these stand-
ards, the Administrator commissioned
the Arthur D. Little Co., Inc., to under-
take an independent assessment of both
the technical basis for the standards and
the potential impact of the standards on
the domestic primary copper smelting in-
dustry. The results of this study have
been considered together with the com-
ments submitted during the public re-
view and comment period in determining
whether the proposed standards should
be revised for promulgation.
Briefly, the Arthur D. Little study
reached the following conclusions:
(1) The proposed standards should
have no adverse impact on new primary
copper smelters processing materials con-
taining low levels of volatile impurities.
(2) The proposed standards could re-
duce the capability of new primary cop-
per smelters located in the southwest U.S.
to process materials of high impurity
content. This impact was foreseen since
the capability of flash smelting to process
materials of high impurity levels was un-
known. Although electric smelting was
considered technically capable of process-
ing these materials, the higher costs as-
sociated with electric smelting, due to the
high cost of electrical power in the south-
west, were considered sufficient to pre-
clude Its use in most cases.
This conclusion was subject, however,
to qualification. It applied only to the
southwest (Arizona, New Mexico and west
Texas) and not to other areas of the
United States (Montana, Nevada, Utah
and Washington) where primary copper
smelters currently operate; and it was
not viewed as applicable to large new ore
deposits of high impurity content which
were capable of providing the entire
charge to a new smelter. The study also
concluded it was impossible to estimate
the magnitude of this potential impact
since it was not possible to predict impur-
ity levels likely to be produced from new
oie reserves
Although considerable doubt existed as
to the need for a new smelter in the
southwest to process materials of high
impurity levels in the future (essentially
all the information and data examined
indicated such a need is not likely to
arise), the Arthur D. Little study con-
cluded it would be prudent to assume new
smelters in the southwest should have
the flexibility to process these materials.
To assume otherwise according to the
study might place constraints on possible
future plans of the American Smelting
and Refining Company.
(3) The proposed standards should
have little or no impact on the ability
of existing primary copper smelters to
expand copper production. This conclu-
sion was also subject to qualification. It
was noted that other means of expand-
ing smelter capacity might exist than the
approaches studied and that the pro-
posed standards might or might not in-
fluence the viability of these other means
of expanding capacity. It was also noted
that the study assumed existing single
absorption sulfuric acid plants could be
converted to double absorption, but that
individual smelters were not visited and
this conversion might not be possible at
some smelters.
Each of the comment letters received
by EPA contained multiple comments.
The most significant comments, the
Agency's responses to these comments
and ' the various changes made to the
proposed regulations for promulgation
in response to tlie.se comments are dis-
cussed below.
(1) Legal authority under section 111.
Four commentators indicated that the
Agency would exceed its statutory au-
thority under section 111 of the Act by
promulgating a standard of perform-
ance that could not be met by copper
reverberatory smelting furnaces, which
are extensively used at existing domestic
smelters. The commentators believe that
the "best system of emission reduction"
cited in section 111 refers to control
techniques that reduce emissions, and
not to processes that emit more easily
controlled effluent gas streams. The com-
mentators contend, therefore, that a
producer may choose the process that is
most appropriate in his view, and new
source performance standards must be
based on. the application of the best
demonstrated techniques of emission re-
duction to that process.
The legislative history of the 1970
Amendments to the Act is cited by these
commentators as supporting this inter-
pretation of section 111. Specifically
pointed out is the fact that the House-
Senate Conference Committee, which
reconciled competing House and Senate
versions of the bill, deleted language
from the Senate bill that would have
granted the Agency explicit authority to
regulate processes. This action, accord-
ing to these commentators, clearly indi-
cates a Congressional-intent not to grant
the Agency such authority
The conference bill, however, merely
replaced the phrase in the Senate bill
"latest available control technology,
processes, operating method or other
alternatives" with "best system of emis-
sion reduction which (taking into ac-
count the cost of achieving such reduc-
tion) the Administrator determines has
been adequately demonstrated." The use
of the phrase "best system of emission
reduction" appears to be inclusive of
the terms in the Senate bill. The absence
of discussion in the conference report
on this issue further suggests that no
substantive change was intended by the
substitution of the phrase "best system
of emission reduction" for the phrase
"latest available control technology,
processes, operating method or other al-
ternatives" in the Senate bill.
For some classes of sources, the dif-
ferent processes used in the production
activity significantly affect the emission
levels of the source and/or the tech-
nology that can be applied to control
the source. For this reason, the Agency
believes that the "best system of emis-
sion reduction" includes the processes
utilized and does not refer only to emis-
sion control hardware. It is clear that
adherence to existing process utilization
could serve to undermine the purpose of
section in to require maximum feasible
control of new sources. In general, there-
fore, the Agency believes that section 111
authorizes the promulgation of one
standard applicable to all processes used
by a class of sources, in order that the
standard may reflect the maximum
feasible control for that class. When the
application of a standard to a given
process would effectively ban the process,
however, a separate standard must be
prescribed for it unless some other proc-
ess'es) is available to perform the func-
tion at reasonable cost.
In determining whether the use of dif-
ferent processes would necessitate the
setting of different standards, the Agency
first determines whether or not the proc-
esses are functionally interchangeable
Factors such as whether the least pollut-
ing process can be used in various loca-
tions or with various raw materials 01
under other conditions are considered
The second important consideration ol
the Agency involves the costs of achiev-
ing the reduction called for by a standani
applicable to all processes used in ::
source category. Where a single stand
ard would effectively preclude using :
process which is much less expensive that
the permitted process, the economic im
p:\ct of the single standard must be de-
termined to be reasonable or separati
standards are set. This does not mean
however, that the cost of the alternative;
to the potentially prohibited process car
FEDERAL REGISTER, VOL 41, NO. 10THURSDAY, JANUARY 15, 1976
IV-124
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2334
RULES AND REGULATIONS
be no grater than those which would be
associated with controlling the process
under a less stringent standard.
The Administrator has determined
that the flash copper smelting process- is
available and will perform the function
of the reverberatory copper smelting
process at reasonable cost, except that
flash smelting has not yet been commer-
cially demonstrated for the processing
of feed materials with a high level of
volatile impurities. The standards pro-
mulgated herein, which do not apply to
copper reverberatory smelting furnaces
when the smelter charge contains a high
level of volatile impurities, are there-
fore authorized under section 111 of the
Act.
<2) Control of reverberatory smelting
furnaces. Two commentators represent-
ing environmental groups and one com-
mentator representing a State pollution
control agency questioned the Adminis-
trator's judgment that the use of various
sulfur dioxide scrubbing systems to con-
trol sulfur dioxide emissions from rever-
beratory smelting furnaces was unrea-
sonable, especially in view of his conclu-
sion that the use of these systems on
large steam generators was reasonable.
These commentators also pointed out
that this conclusion was based only on
an examination of the use of sulfur di-
oxide scrubbing systems and that alter-
native means of control, such as the use
of oxygen enrichment of reverberatory
furnace combustion air, or the mixing
of the gases from the reverberatory fur-
nace with the gases from roasters and
copper converters to produce a mixed
gas stream suitable for control, were not
examined.
This comment was submitted in re-
sponse to the exemption included In the
proposed standards for existing rever-
beratory smelting furnaces. As discussed
below, the amendments recently promul-
gated by the Agency to 40 CFB Part 60
clarifying the meaning of "modification"
make this exemption unnecessary. The
comment is still appropriate, however,
since the promulgated standards now In-
clude an exemption for new reverbera-
tory smelting furnaces at smelters proc-
essing materials containing high levels
of volatile impurities.
Section 111 of the Clean Air Act dic-
tates that standards of performance be
based on "* * * the best system of emis-
sion reduction which (taking into ac-
count the cost of achieving such reduc-
tion) the Administrator determines has
been adequately demonstrated." Thus,
not only must various systems of emis-
sion control be investigated to ensure
these systems are technically proven nnd
the levels to which emissions could be re-
duced through the use of these systems
identified, the co^t,-; of these systems must
be considered to ensure that standards of
performance will not impose an unrea-
sonable economic burden on each source
category for which standards are devel-
oped.
The control of gas streams containing
low concentrations of sulfur dioxide
through the use of various scrubbing sys-
tems which are currently available Is
considered by the Administrator to be
technically proven and well demon-
strated. The use of these systems on large
steam generators is considered reason-
able since electric utilities are regulated
monopolies and the costs incurred to
control sulfur dioxide emissions can be
passed forward to the consumer. Pri-
mary copper smelters, however, do not
enjoy a monopolistic position and face
direct competition from both foreign
smelters and other domestic smelters.
The costs associated with toe use of these
scrubbing systems on reverberatory
smelting furnaces at primary copper
smelters are so large, in the Administra-
tor's judgment, that they could not be
either absorbed by a copper smelter
without resulting in a significant de-
crease in profitability, passed forward to
the consumer without leading to a signif-
icant loss in sales, or passed back to the
mining operations without resulting in a
closing of some mines and a decrease in
mining activity. Consequently, the Ad-
ministrator considers the use of these
systems to control reverberatory smelt-
Ing furnaces unreasonable.
Although little discussion Is Included
In the background document supporting
the proposed standards concerning the
use of oxygen enrichment of reverbera-
tory furnace combustion air, or the mix-
ing of the gases from reverberatory fur-
naces with the gases from roasters and
copper converters, these approaches for
controlling sulfur dioxide emissions from
reverberatory smelting furnaces were ex-
amined. These investigations, however,
were not of an in-depth nature and were
not pursued to completion.
A preliminary analysis of oxygen en-
richment of reverberatory furnace com-
bustion air to produce a strong gas
stream from the reverberatory furnace
appeared to indicate that the costs asso-
ciated with this approach were unrea-
sonable. A similar analysis of the mix-
ing of the gases from a reverberatory
furnace with the gases discharged from a
fluid-bed roaster and copper converters
appeared to indicate that although the
costs associated with this approach were
reasonable, it was not possible to use
fluid-bed roasters in all cases Multi-
hearth roasters would be required where
materials of high volatile impurity levels
were processed. Although multi-hearth
roasters discharge strong gas streams (4-
5 percent sulfur dioxide), fluid bed
roasters discharge much stronger gas
streams (10-12 percent sulfur dioxide).
To determine the effect of this lower
concentration of sulfur dioxide in the
gases discharged by multi-hearth roast-
ers on the ability to mix the gases dis-
charged by reverberatory smelting fur-
naces with those discharged by roasters
and copper converters to produce a
mixed gas stream suitable for control at
reasonable costs would have required
further investigation and study.
Unfortunately, limited resources pre-
vented all avenues of Investigation from
being pursued and in view of the promis-
ing indications from the preliminary In-
vestigations into flash and electric smelt-
Ing, the Agency concentrated Its efforts
In this area. As discussed below, how-
ever, the use of these approaches to con-
trol sulfur dioxide emissions from re-
verberatory smelting furnaces are under
investigation as a means by which the
promulgated standards of performance
could be extended to cover reverberatory
smelting furnaces which process mate-
rials containing high levels of impurities.
(3) Materials of high impurity levels.
One commentator expressed his belief
that the proposed standards would pre-
vent new primary copper smelters from
processing materials containing high lev-
els of Impurities, such as arsenic, anti-
mony, lead and zinc. This commentator
does not feel flash smelting can be con-
sidered demonstrated for smelting mate-
rials containing these impurities. The
commentator also feels the domestic
smelting industry will not be able to em-
ploy electric smelting to process mate-
rials of this nature In the future, since
electric power will not be available, or
only available at a price which will pre-
vent its use by the industry.
At the tame of proposal of the stand-
ards for primary copper smelters, the Ad-
ministrator was aware that considerable
doubt existed concerning the capability
of flash smelting to process materials of
high Impuritv levels. No doubt existed,
however, with regard to the capability of
electric smelting to process these~ mate-
rials. Consequently, the standards were
proposed on the basis that where flash
smelting could not be employed to proc-
ess these materials, electric smelting
could.
As outlined above, the Arthur D. Little
study concluded that at no flash smelter
In the world has the average composition
of the total charge processed on a rou-
tine basis exceeded 0.2 weight percent
arsenic, 0.1 weight percent antimony, 4.5
weight percent lead and 5.5 weight per-
cent zinc. Thus, the capability of flash
smelting to process a charge containing
higher levels of Impurities than these has
not been adequately demonstrated. At
this time, therefore, only electric smelt-
ing preceded by multi-hearth roasting
(in addition to reverberatory smelting
preceded by multi-hearth roasting) can
be considered adequately demonstrated
(excluding costs) for processing these
materials.
Tho Arthur D. Little study also ex-
amined the projected availability and
pricing of various forms of energy
through 1980 for those areas of the
United States where primary copper
smelters now operate. Although the en-
ergy consumed by electric smelting is
approximately equal to that consumed
by reverberatory smelting (taking into
account the energy inefficiency associ-
ated with electric power generation), the
stud}' concluded that a cost penalty of
1 to 2 cents per pound of copper Is asso-
ciated with electric smelting In the
southwest U S. due to the high cost ol
electric power In tills region. This cost
penalty was considered sufficient In the
Arthur D. Little study to make the use
FEDERAL REGISTER, VOL. 41, NO. 10THURSDAY, JANUARY 15, 1976
IV-125
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RULES AND REGULATIONS
2335
of electric smelting at new primary cop-
per smelters located in the southwest
economically unattractive in most cases.
Since the basis for the proposed stand-
ards considered electric smelting as a
viable alternative should flash smelting
prove unable to process materials of high
impurity levels, the Administrator has
concluded the proposed standards should
be icvised for promulgation. Conse-
quently, the standards promulgated
herein exempt new rcverbcratory smelt-
ins furnaces at primary copper smelters
which process a total charge containing
more than 0.2 weight percent arsenic,
0.1 weight percent antimony, 4.5 weight
percent lead or 5.5 weight percent zinc.
This will permit new primary copper
smelters to be constructed to process
materials of high impurity levels without
employing electric smelting. The promul-
gated standards of performance will,
however, apply to new roasters and cop-
per converters at these smelters, since
the Administrator has concluded these
facilities can be operated to produce gas
streams containing greater than 3'.'2 Per-
cent sulfur dioxide and that the costs
associated with controlling these gas
streams are reasonable.
Although the Administrator considers
It prudent to promulgate the standards
with this exemption for new reverbera-
tory smelting furnaces, the Administra-
tor believes this exemption may not be
necessary. As pointed out in the com-
ments submitted by various environmen-
tal organizations and private citizens,
neither the use of oxygen enrichment of
reverberatory furnace combustion air,
nor the mixing of the gases from rever-
beratory furnaces with those from multi-
hearth roasters and copper converters
were investigated in depth by the Agency
in developing the proposed standards.
Either of these approaches could prove
to be reasonable for controlling sulfur
dioxide emissions from reverberatory
smelting furnaces.
Under the promulgated standards with
the exemptions provided for new rever-
beratory smelting furnaces, new primary
copper smelters could remain among the
largest point sources of sulfur dioxide
emissions within the U S. Consequently,
the Agency's program to develop stand-
ards of performance to limit sulfur diox-
ide emissions from primary copper smelt-
ers will continue. This program will
focus on the use of oxygen enrichment of
reverberatory furnace combustion air
and the mixing of the gases from rever-
beratory smelting furnaces with those
from multi-hearth roasters and copper
converters. If the Administrator con-
cludes either Or both of these approaches
can be employed to control sulfur dioxide
emissions from reverberatory smelting
furnaces at reasonable costs, the Admin-
istrator will propose that this exemption
be deleted.
(4) Copper smelter modifications. One
of the major issues associated with the
proposed regulations on modification,
notification and reconstruction (39 PR
36946) involved the "bubble concept."
The "bubble concept" refers to the trad-
Ing off of emission increases from one
existing facility undergoing a physical
or operational change at a source with
emission reductions from another exist-
ing facility at the same source. If there is
no net increase in the amount of any
air pollutant (to which a standard ap-
plies) emitted into the atmosphere by the
source as a whole, the facility which ex-
perienced an emissions increase is not
considered modified. Although the "bub-
ble concept" may be applied to existing
facilities which undergo a physical or
operational change, it may not be applied
to cover construction of new facilities
In commenting on the proposed stand-
ards of performance for primary copper
smelters, two commentators suggested
that the bubble concept be extended to
Include construction of new facilities at
existing copper smelters. These com-
mentators indicated that this could re-
sult in a substantial reduction in the
costs, while at the same time leading
to a substantial reduction in emissions
from the smelter.
To support their claims, these com-
mentators presented two hypothetical
examples of expansions at a copper
smelter that could occur through con-
struction of new facilities. Where new
facilities were controlled to meet stand-
ards of performance, emissions from the
smelter as a whole increased. Where
some new facilities were not controlled
to meet standards of performance, emis-
sions from the smelter as a whole de-
creased substantially.
These results, however, depend on spe-
cial manipulation of emissions from the
existing facilities at the smelter. In the
case where new facilities are controlled
to meet standards of performance, emis-
sions from existing facilities are not
reduced. Thus, with construction of new
facilities, emissions from the smelter as
a whole increase. In the case where some
new facilities are not controlled to meet
standards of performance, emissions
from existing facilities are reduced
through additional emission control or
production cut-back. Since emissions
from the existing facilities were assumed
to be very large initially, a reduction in
these emissions results in a net reduction
in emissions from the smelter as a whole.
These hypothetical examples, however,
appear to represent contrived situations.
In many cases, compliance with State
implementation plans to meet the Na-
tional Ambient Air Quality Standards
will require existing copper smelters to
control emissions to such a degree that
the situations portrayed in the examples
presented by' these commentators are
not likely to arise. Furthermore, a
smelter operator may petition the Ad-
ministrator for reconsideration of the
promulgated standards if he believes
they would be infeasible when applied to
his smelter.
Another commentator asked whether
conversion of an existing reverberatory
smelting furnace from firing natural gas
to firing coal would constitute a modi-
fication. This commentator pointed out
that although the conversion to firing
coal would increase sulfur dioxide emis-
sions from the smelter by 2 to 3 percent,
the costs of controlling the furnace tc
meet the standards of performance
would be prohibitive.
The primary objective of the promul-
gated standards is to control emissions
of sulfur dioxide from the copper smelt-
ing process. The data and informatior
supporting the standards consider es-
sentially only those emissions arisinp
(from the basic smelting process, not
those arising from fuel combustion. It,
is not the direct intent of these stand-
ards, therefore, to control emissions f roii:
fuel combustion per se. Consequently,
since emissions from fuel combustior
are negligible in comparison with those
from the basic smelting process, and :,
conversion of reverberatory smeltinj
furnaces to firing coal rather than nat-
ural gas will aid in efforts to conserve
natural gas resources, the standards pro-
mulgated herein include a provision ex-
empting fuel switching in reverberator;,
smelting furnaces from consideration a;;
a modification.
(5) Expansion of existing smelters,
Two commentators expressed their con-
cern that the proposed standards woulc
prevent the expansion of existing pri-
mary copper smelters, since the stand-
ards apply to modified facilities as wel'
as new facilities. These commentators
reasoned that the costs associated with
controlling emissions from each roaster
smelting furnace or copper convertc;
modified during expansion would n;
many cases make these expansions eco-
nomically unattractive.
As noted above, the Agency has pro -
posed amendments to the general provi-
sions of 40 CFR Part 60 covering modified
and reconstructed sources. Under these
provisions, standards of performance ap-
ply only where an existing facility at a
source is reconstructed; where "b. change
in an existing facility results in an in-
crease in the total emissions at a source.
and where a new facility is constructed
at a source. Thus, unless total emissions
from a primary copper smelter increase.
most alterations to existing roasters,
smelting furnaces or copper converters
which increase their emissions will not,
cause these facilities to be considered
modified and subject to standards of per-
formance.
The Administrator does not believe the
standards promulgated herein will detri
expansion of existing primary copper
smelters. As discussed earlier, the Ad-
ministrator concluded at proposal that
the cost of controlling reverberatory
smelting furnaces was unreasonable
(through the use of various sulfur dioxide
scrubbing systems currently available*,
and for this reason included an exemp-
tion in the proposed standards for ex-
isting reverberatory smelting furnaces
The prime objective of this exemption
was to unsure that existing primary cop-
per smelters could expand copper pro-
duction at reasonable costs.
Also, as discussed earlier, the Arthur
D. Little study examined this aspect of
the proposed standards and concluded
the standards would have little or no im-
pact on the ability of existing primary
copper smelters to expand production.
FEDERAL REGISTER, VOL. 41, NO. 10THURSDAY, JANUARY 15, 1976
IV-126
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RULES AND REGULATIONS
This conclusion was subject to two quali-
fications: other means of expanding
smelter capacity might exist than those
examined and the impact of the 'proposed
standards on these means of expanding
rapacity is unknown; and it was as-
-.umed that existing single absorption suU
iunc acid plants could be converted to
double absorption, but at some smelters
this might not be possible.
The Administrator does not feel these
qualifications seriously detract from the
essential conclusion that the standards
are likely to have little impact on the ex-
pansion capabilities of existing copper
smelters. The various means of expand-
ing smelter capacity examined in the Ar-
thur D. Little study represent commonly
employed techniques for increasing cop-
per production from as little as 10 to 20
percent, to as much as 50 percent at ex-
isting smelters. Consequently, the Ad-
ministrator considers the approaches
examined In the study as broadly repre-
sentative of various means of expanding
existing primary copper smelters and as
a reasonable basis from which conclu-
sions regarding the potential impact of
the standards on the expansion capabili-
ties of the domestic primary copper
smelting industry can be drawn.
The Administrator views the assump-
tion in the Arthur D. Little report that
existing single absorption sulfuric acid
plants can be converted to double absorp-
tion as a good assumption. Although at
some existing primary copper smelters
the physical plant layout might compli-
cate a conversion from single absorption
to double absorption, the remote isolated
location of most smelters provides ample
space for the construction of additional
plant facilities. Thus, while the costs for
conversion may vary from smelter to
smelter, it is unlikely that at any smelter
a conversion could not be made.
As proposed, provisions were included
In the regulations specifically stating that
physical and operating changes to exist-
ing reverberatory smelting furnaces
which resulted In an increase In sulfur
dioxide emissions would not be consid-
ered modifications, provided total emis-
sions of sulfur dioxide from the copper
smelter did not increase above levels
specified in State implementation plans.
Since proposal of the standards,
amendments to 40 CFR Part 60 to clarify
the meaning of modification under sec-
tion 111 have been proposed. These
amendments permit changes to existing
facilities within a source which increase
emissions from these facilities without
requiring compliance with standards of
performance, provided total emissions
from the source do not increase. Since
this was the objective of the provisions
included in the proposed regulations for
primary copper smelters with regard to
changes to existing reverberatory smelt-
ing furnaces, these provisions are no
longer necessary and have been deleted
from the promulgated regulations.
<6> Increased energy consumption.
Two commentators indicated that the
Agency's estimate of the impact of the
standards of performance for primary
copper, zinc and lead smelters on energy
consumption was much too low. Since
the number of smelters which will be af-
fected by the standards is relatively
small, the Agency has developed a sce-
nario on a smelter-by-smelter basis, by
which the domestic industry could in-
crease copper production by 400,000 tons
by 1980. This increase in copper produc-
tion represents a growth rate of about
3.5 percent per year and is consistent
with historical industry growth rates of
3 to 4 percent per year.
On this new basis, the energy required
to control all new primary copper, zinc
and lead smelters constructed by 1980 to
comply with both the proposed standards
and the standards promulgated herein is
the same and is estimated to be 320 mil-
lion kilowatt-hours per year. This is
equivalent to about 520,000 barrels of
number 6 fuel oil per year. Relative to
typical State implementation plan re-
quirements for primary copper, zinc and
lead smelters, the incremental energy re-
quired by these standards is 50 million
kilowatt-hours per year, which is equiva-
lent to about 80,000 barrels of number 6
fuel oil per year.
The energy required to comply with the
promulgated standards at these new
smelters by 1980 represents no more than
approximately 3.5 percent of the process
energy which would be required to oper-
ate these smelters in the absence of any
control of sulfur dioxide emissions. The
incremental amount of energy required to
meet these standards is somewhat less
than 0.5 percent of the total energy
(process plus air pollution) which would
be required to operate these new smelters
and meet typical State implementation
plan emission control requirements.
One commentator stated the Agency's
initial estimate of the increased energy
requirements associated with the pro-
posed standards was low because the
Agency did not take Into account a 3
million Btu per ton of copper concentrate
energy debit, attributed by the commen-
tator to electric smelting compared to
reverberatory smelting. The new basis
used by the Agency to estimate the im-
pact of the standards on energy con-
sumption anticipates no new electric
smelting by 1980. Consequently, any dif-
ference in the energy consumed by elec-
tric smelting compared to reverberatory
smelting will have no impact on the
amount of energy required to comply
with the standards.
The Agency's estimates of the energy
requirements associated with electric
smelting and reverberatory smelting,
which are included in the background in-
formation for the proposed standards,
are based on a review of the technical
literature and contacts with individual
.smelter operators. These estimates agree
quite favorably with those developed in
the Arthur D. Little study, which verified
the Agency's conclusion that the overall
energy requirements associated with re-
veibei'atory and electric smelting are
essentially the same. It remains, the Ad-
ministrator's conclusion, therefore, that
there is no energy debit associated with
electric smelting compared to reverbera-
tory smeltine.
Another commentator feels the
Agency's original estimates fail to take
Into account the fuel necessary to main-
tain proper operating temperatures in
sulfuric acid plants. This commentator
estimates that about 82,000 barrels of
fuel oil per year are required to heat the
gases in a double absorption sulfuric acid
plant. The commentator then assumes
the domestic non-ferrous smelting in-
dustry will expand production by 50 per-
cent in the immediate future, citing the
Arthur D. Little study for support. Since
about 30 metallurgical sulfuric acid
plants are currently in use within the
domestic smelting industry, the commen-
tator assumes this means 15 new metal-
lurgical sulfuric acid plants will be con-
structed in the future. This leads to an
estimated energy impact associated with
the standards of performance of about
l'/4 million barrels of fuel oil per year.
It should be noted, however, that the
growth projections developed in the
Arthur D. Little study are only for the
domestic copper smelting industry, and
cannot be assumed to apply to the do-
mestic zinc and lead smelting industries.
Over half the domestic zinc smelters, for
example, have shut down since 1968 and
zinc production has fallen sharply, al-
though recently plans have been an-
nounced for two new zinc smelters. In
addition, the domestic lead Industry is
widely viewed as a static Industry with
little prospect for growth in the near
future.
Furthermore, the Arthur D. Little
study does not project a 50 percent ex-
pansion of the domestic copper smelting
industry in the immediate future. By
1980, the study estimates domestic cop-
per production will have increased by 15
percent over 1974 and by 1985, domestic
copper production will have increased by
35 percent.
The Agency's growth projections for
the domestic copper smelting industry
are somewhat higher than those of the
Arthur D. Little study and forecast a 19
percent Increase in copper production by
1980 over 1974. The commentator's esti-
mate of a 50 percent expansion of the do-
mestic non-ferrous smelting Industry in
the immediate future, therefore, appears
much too high. Where the commentator
estimates that the standards of perform-
ance will affect the construction of 15
new metallurgical sulfuric acid plants,
the Agency estimates the standards will
affect the construction of 7 new acid
plants (6 In the copper industry, 1 in
the zinc industry and none in the lead
industry). In addition, the Agency esti-
mates the standards will require the con-
version of 6 existing single absorption
acid plants to double absorption (5 in
the copper industry, 1 in the zinc industry
and none in the lead industry).
As noted above, the commentator's
calculations also assume that these 15
new metallurgical acid plants do not
operate autothermally (i.e.. fuel firing
is necessary to maintain proper operat-
ing temperatures). The commentator's
estimate that a double absorption sul-
furic acid plant requires 82,000 barrels of
fuel oil per year is based on operation
of an acid plant designed to operate
autothermally at 4Vi percent sulfur di-
oxide, but which operates on gases con-
FEDERAL REGISTER. VOL. 41. NO. 10THURSDAY, JANUARY 15, 1976
IV-127
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RULES AND REGULATIONS
taining only 3',2 percent sulfur dioxide
40 percent of the time.
Using tliis same basis, the Agency cal-
culates that a sulfuric acid plant should
require less than 5,000 barrels of oil per
year. A review of these calculations with
two acid plant vendors and a private
consultant has disclosed no errors. The
Administrator must assume, therefore,
that the commentator's calculations are
in error, or assume an unrealistically low
degree of heat recovery in the acid plant
to preheat the incoming gases, or are
based on a poorly designed or poorly
operated sulfuric acid plant which fails
to achieve the degree of heat recovery
normally expected in a properly designed
and operated sulfuric acid plant.
Regardless of these calculations, how-
ever, the Administrator feels that with
good design, operation and maintenance
of the roasters, smelting furnaces, con-
certers, sulfuric acid plant and the flue
gas collection system and ductwork, the
concentration of sulfur dioxide In the
gases processed by a sulfuric acid plant
can be maintained above 3 Vi to 4 percent
sulfur dioxide. This level is typically the
autothermal point at which no fuel
need be fired to maintain proper oper-
ating temperatures in a well designed
metallurgical sulfuric acid plant. Ex-
cept for occasional start-ups, therefore,
a well designed and properly operated
metallurgical sulfuric acid plant should
operate autothermally and not require
fuel for maintaining proper operating
temperatures. Thus, it remains the Ad-
ministrator's conclusion that the impact
of the standards on Increased energy
consumption, resulting from Increased
fuel consumption to operate sulfuric acid
plants, is negligible.
(7) Emission control technology. As
three commentators correctly noted, the
proposed standards essentially require
the use of one emission control tech-
nologydouble absorption sulfuric acid
plants. These commentators feel, how-
ever, that this prevents the use of alter-
native emission control technologies such
as single absorption sulfuric acid plants
and elemental sulfur plants, and that
these are equally effective and, In the
case of elemental sulfur plants, place less
stress on the environment.
Although these commentators ac-
knowledge that double absorption sul-
furic acid plants operate at a higher ef-
ficiency than single absorption acid
plants (99.5 percent vs. 97 percent), they
feel the availability of double absorption
Dlants is lower than that of single absorp-
tion plants (90 percent vs. 92 percent).
These commentators also point out that
double absorption acid plants require
more energy to operate than single ab-
sorption plants. When the effect of these
factors on overall sulfur dioxide emis-
sions is considered, these commentators
feel there is no essential difference be-
tween double and single absorption acid
plants.
The difference in availability between
single and double absorption sulfuric
acid plants cited by these commentators
was estimated from data gathered solely
on single absorption acid plants, and Is
due essentially to only one Itemthat of
the acid coolers for the sulfuric acid pro-
duced in the absorption towers. The data
used by these commentators, however,
reflects "old technology" in this respect.
If the data are adjusted to reflect new
acid cooler technology, the availability of
single and double absorption acid plants
Is estimated to be 94 and 93.5 percent,
respectively.
Taking into account these differences
in efficiency and availability, the instal-
lation of a 1000-ton-per-day double
absorption acid plant rather than a
single absorption acid plant results in an
annual reduction in sulfur dioxide emis-
sions of about 4,500 tons. The difference
In annual availability between single and
double absorption acid plants, however,
does not influence short-term emissions.
Over short time periods the difference in
emissions between single and double
absorption acid plants is a reflection only
of their difference in operating efficiency.
Over a 24-hour period, for example, a
1000-ton-per-day single absorption acid
pant will emit about 20 tons of sulfur
dioxide compared to about 3.5 tons from
a double absorption acid plant. Conse-
quently, the difference in emission con-
trol obtained through the use of double
absorption rather than single absorption
acid plants is significant.
The Increased sulfur dioxide emissions
released 10 the atmosphere to provide the
greater energy requirements of double
absorption over single absorption acid
plants Is also minimal. For a nominal
1000-ton-per-day sulfuric acid plant, the
difference in sulfur dioxide emissions be-
tween a single absorption plant and a
double absorption plant Is about 16.5
tons per day as mentioned above. The
sulfur dioxide emissions from the com-
bustion of a 1.0 percent sulfur fuel oil to
provide the difference in energy required,
however, is of the order of magnitude
of only 200 pounds per day.
As mentioned above, these commenta-
tors also feel that elemental sulfur plants
are as effective as double absorption sul-
furic acid plants and place less stress on
the environment. Elemental sulfur
plants normally achieve emission reduc-
tion efficiencies of only about 90 percent,
which Is significantly lower than the 994-
percent normally achieved in double ab-
sorption sulfuric acid plants. Conse-
quently, the Administrator does not con-
sider elemental sulfur plants nearly as
effective as double absorption sulfuric
acid plants.
Although elemental sulfur presents no
potential water pollution problems and
can be easily stored, thus remaining a
possible future resource, the' Adminis-
trator 'does not agree that production of
elemental sulfur places less stress on the
environment than production of sulfuric
acid. At every smelter now producing sul-
furic acid, an outlet for this acid has
been found, either In copper leaching
operations to recover copper from oxide
ores, or in the traditional acid markets,
such as the production of fertilizer. Thus,
sulfuric acid, unlike elemental sulfur,
has found use as a current resource and
not required storage for use as a possible
future resource.
The Administrator believes that this
situation will also generally prevail in
the future. If sulfuric acid must be neu-
tralized at a specific smelter, however,
this can be accomplished with proper
precautions without leading to water
pollution problems, as discussed In the
background information supporting the
proposed standards.
A major drawback associated with the
production of elemental sulfur, however,
is the large amount of fuel required a?; a
reductant in the process. When compared
to sulfuric acid production in double
absorption sulfuric acid plants, ele-
mental sulfur production requires from
4 to 6 times as much energy. Conse-
quently, the Administrator is not con-
vinced that elemental sulfur production,
which releases about 20 times more sul-
fur dioxide Into the atmosphere, yet
consumes 4 to 6 times as much energy,
could be considered less stressful on the
environment than sulfuric acid produc-
tion.
PRIMARY ZINC SMELTERS
Only one major comment was sub-
mitted to-the Agency concerning the pro-
posed standards of performance for pri-
mary zinc smelters. This comment ques-
tioned whether It would be possible in
all cases to eliminate 90 percent or more
of the sulfur originally present In the
zinc concentrates during roasting.
Most primary zinc smelters employ
either the electrolytic smelting process
or the roast/sinter smelting process,
both of which require a roasting opera-
tion. The roast/sinter process, however,
requires- a sintering operation following
roasting. Sulfur not removed from the
concentrates during roasting Is removed
during sintering. Since the amount of
sulfur removed by sintering Is small, the
gases discharged from this operation
contain a low concentration of sulfur
dioxide. As discussed In the preamble to
the proposed standards, the cost of con-
trolling these emissions was judged by
the Administrator to be unreasonable.
The amount of sulfur dioxide emitted
from the sintering machine, however, de-
pends on the sulfur removal achieved In
the preceding roaster. To ensure a high
degree of sulfur removal during roastmg
which will minimize sulfur dioxide emis-
sions from the sintering machine, IJie
sulfur dioxide standard applies to any
sintering machine which eliminates mure
than 10 percent of the sulfur originally
present in the zinc concentrates. This re-
quires 90 percent or more of the sulfur
to be eliminated during roasting, which is
consistent with good operation of roast-
ers as presently practiced at the two zinc
smelters in the United States which em-
ploy the roast/sinter process.
One commentator pointed out that cal-
cium and magnesium which are present
as impurities in some zinc concentrates
could combine with sulfur during roast-
Ing to form calcium and magnesium sul-
fates. These materials would remain In
the calcine (roasted concentrate). If
these sulf ates were reduced in the sinter-
ing operation, this could lead to more
than 10 percent of the sulfur originally
present In the zinc concentrates being
FEDERAL REGISTER, VOL. 41, NO. 10THURSDAY,, JANUARY 15, 1976
IV-128
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2.%'8
RULES AND REGULATIONS
emitted from the sintering machine.
Under these conditions the sintering
machine would be required to comply
with the sulfur dioxide standard.
Although it is possible that this situa-
tion could arise, as acknowledged by the
commentator himself it does not seem
likely. Only a few zinc concentrates con-
tain enough calcium and magnesium to
carry as much as 10 percent of the sulfur
in the concentrate over into the sintering
operation, even assuming all the calcium
and magnesium present combined with
sulfur during the roasting operation.
In addition, a number of smelter opera-
tors contacted by the Agency indicated
that it is quite possible that not all the
calcium and magnesium present would
combine with sulfur to form sulfates dur-
ing roasting. It is equally possible, ac-
cording to these operators, that not all
the calcium and magnesium sulfates
formed would be reduced in the sintering
machine. Thus, even with those few con-
centrates which do contain a high level
of calcium and magnesium, the extent
to which calcium and magnesium might
contribute to high sulfur emissions from
the sintering operation is questionable.
Furthermore, these smelter operators
indicated that at most zinc smelters a
number of different zinc concentrates are
normally blended to provide a homoge-
neous charge to the roasting operation.
As pointed out by these operators, this ef-
fectively permits a smelter operator to
reduce the amount of calcium and mag-
nesium present in the charge by blending
off the high levels of calcium and mag-
nesium present in one zinc concentrate
against the low levels present in another
concentrate.
The Agency also discussed this poten-
tial problem with a number of mill oper-
ators. These operators indicated that ad-
ditional milling could be employed to re-
duce calcium and magnesium levels in
zinc concentrates. Although additional
milling would entail some additional cost
and probably result in a somewhat higher
loss of zinc to the tailings, calcium and
magnesium levels could be reduced well
below the point where formation of cal-
cium and magnesium sulfate during
roasting would be of no concern.
While one may speculate that calcium
and magnesium might lead to the forma-
tion of sulfates during roasting, which
might in turn be reduced during sinter-
ing, the extent to which this would
occur is unknown. Consequently, whether
this would prevent a primary zinc smelter
employing the roast/sinter process from
limiting emissions from sintering to no
more than 10 percent of the sulfur orig-
inally present in the zinc concentrates
is questionable. The fact remains, how-
ever, that at the two primary zinc smelt-
ers currently operating in the United
States which employ the roast,'sinter
process this has not been a problem.
Furthermore, it appears that if calcium
and magnesium were to present a prob-
lem in the future, a number of appro-
priate measures, such as additional
blending of zinc concentrates or addi-
tional milling of those concentrates con-
taining high calcium and magnesium
levels, could be employed to deal with
the situation. As a result, the standards
of performance promulgated herein for
primary zinc smelters require a sinter-
ing machine emitting more than 10 per-
cent of the sulfur originally present in
the zinc concentrates to comply with the
sulfur dioxide standard for roasters.
PRIMARY LEAD SMELTERS
No major comments were submitted to
the Agency concerning the proposed
standards of performance for primary
lead smelters. The proposed standards,
therefore, are promulgated herein with
only minor changes.
VISIBLE EMISSIONS
The opacity levels contained in the
proposed standards to limit visible emis-
sions have been reexamined to ensure
they are consistent with the provisions
promulgated by the Agency since pro-
posal of these standards for determining
compliance with visible emissions stand-
ards <39 FR 39872). These provisions
specify, in part, that the opacity of visible
emissions will be determined as a 6-
minute average value of 24 consecutive
readings taken at 15 second intervals.
Reevaluation of the visible emission data
on which the opacity levels in the pro-
posed standards were based, in terms of
6-minute averages, indicates no need to
change the opacity levels initially pro-
posed. Consequently, the standards of
performance are promulgated with the
same opacity limits on visible emissions.
TEST METHODS
The proposed standards of perform-
ance for primary copper smelters, pri-
mary zinc smelters and primary lead
smelters were accompanied by amend-
ments to Appendix AReference Meth-
ods of 40 CFR Part 60. The purpose of
the e amendments was to add to Ap-
pendix A a new test method (Method 12)
for use in determining compliance with
the proposed standards of performance.
Method 12 contained performance speci-
fications for the sulfur dioxide monitors
required in the proposed standards and
prescribed the procedures to follow in
demonstrating that a monitor met these
performance specifications.
Since proposal of these standards of
performance, the Administrator has pro-
posed amendments to Subpart AGen-
eral Provisions of 40 CFR Part 60, estab-
lishing a consistent set of definitions and
monitoring requirements applicable to
all standards of performance. These
amendments include a new appendix
(Appendix BPerformance Specifica-
tions) which contains performance spec-
ifications and procedures to follow when
demonstrating that a continuous moni-
tor meets these performance specifica-
tions. A continuous monitoring system
for measuring sulfur dioxide concentra-
tions that is evaluated in accordance
with the procedures contained in this
appendix will be satisfactory for deter-
mining compliance with the standards
promulgated herein for sulfur dioxide.
The proposed Method 12 is therefore
withdrawn to prevent an unnecessary
repetition of information in 40 CFR Part
60.
EFFECTIVE DATE
In accordance with section 111 of the
Act, these regulations prescribing stand-
ards of performance for primary copper
smelters, primary zinc smelters and pri-
mary lead smelters are effective on (date
of publication) 1975 and apply to all
affected facilities at these sources on
which construction or modification com-
menced after October 16, 1974.
Dated: December 30, 1975.
JOHN QUARLES,
Acting Administrator.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amended
as follows:
1. The table of sections is amended by
adding subparts P, Q and R as follows:
Subpart PStandards of Performance for
Primary Copper Smelters
60 160 Applicability and designation of af-
fected facility.
60.161 Definitions.
60.162 Standard for participate matter.
60 163 Standard for sulfur dioxide.
60.164 Standard for visible emissions.
60.165 Monitoring of operations.
60.166 Test methods and procedures.
Subpart QStandards of Performance for
Primary Zinc Smelters
60.170 Applicability -and designation of
affected facility.
60.171 Definitions.
60.172 Standard for particulate matter.
60 173 Standard for sulfur dioxide.
60.174 Standard for visible emissions.
60.175 Monitoring of operations.
60.176 Test methods and procedures.
Subpart RStandards of Performance for
Primary Lead Smelters
60.180 Applicability and designation of
affected facility.
60.181 Definitions.
60.182 Standard for particulate matter.
60.183 Standard for sulfur dioxide.
60.184 Standard for visible emissions.
60.185 Monitoring of operations.
60.186 Test methods and procedures.
AUTHORITY: (Sees. Ill, 114 and 301 of the
Clean Air Act as amended (42 U.S.C. 1857c-
6. 1857C-9, 1857g>.)
2. Part 60 is amended by adding sub-
parts P, Q and R as follows:
Subpart PStandards of Performance for
Primary Copper Smelters
§60.100 Applicability and designation
of afTrcIrd facility.
The provisions of this subpart are ap-
plicable to the following affected facilities
in primary copper smelters: Dryer,
roaster, smelting furnace, and copper
converter.
§(>O.H>1 n.-lillili.MK.
As used in this subpart. all terms not
defined herein shall have the meaning
given them in ^he Act and in subpart
A of this part.
(a) "Primary copper smelter" means
any installation or any intermediate
process engaged in the production of
copper from copper sulfide ore concen-
trates through the use of pyrometallurgl-
cal techniques.
FEDERAL REGISTER, VOL. 41, NO. 10THURSDAY, JANUARY 15, 1976
IV-129
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RULES AND REGULATIONS
2339
(b) "Dryer" means any facility in
which a copper sulflde ore concentrate
charge is heated in the presence of air
to eliminate a portion of the moisture
from the charge, provided less than 5
percent of the sulfur contained in the
charge is eliminated in the facility.
(c) "Roaster" means any facility in
which a copper sulfide ore concentrate
charge is heated in the presence of air
to eliminate a significant portion (5 per-
cent or more) of the sulfur contained
in the charge,
(d) "Calcine" means the solid mate-
rials produced by a roaster.
(e) "Smelting" means processing
techniques for the melting of a copper
sulflde ore concentrate or calcine charge
leading to the formation of separate lay-
ers of molten slag, molten copper, and/or
copper matte.
(f) "Smelting furnace" means any
vessel in which the smelting of copper
sulflde ore concentrates or calcines is
performed and in which the heat neces-
sary for smelting is provided by an elec-
tric current, rapid oxidation of a portion
of the sulfur contained in the concen-
trate as it passes through an oxidizing
atmosphere, or the combustion of a fossil
fuel.
(g) "Copper converter" means any
vessel to which copper matte is charged
and oxidized to copper.
(h) "Sulfuric acid plant" means any
facility producing sulfuric acid by the
contact process.
(i) "Fossil fuel" means natural gas,
petroleum, coal, and any form of solid,
liquid, or gaseous fuel derived from such
materials for the purpose of creating
useful heat.
(j) "Reverberatory smelting furnace"
means any vessel in which the smelting
of copper sulflde ore concentrates or cal-
cines is performed and in which the heat
necessary for smelting is provided pri-
marily by combustion of a fossil fuel.
(k) "Total smelter charge" means the
weight (dry basis) of all copper sulfldes
ore concentrates processed at a primary
copper smelter, plus the weight of all
other solid materials introduced into the
roasters and smelting furnaces at a pri-
mary copper smelter, except calcine, over
a one-month period.
(1) "High level of volatile impurities"
means a total smelter charge containing
more than 0.2 weight percent arsenic, 0.1
weight percent antimony, 4.5 weight per-
cent lead or 5.5 weight percent zinc, on
a dry basis.
§60.162 Standard for pnrlieiilale mat-
ter.
(a) On and after the date on which
the performance test required to be con-
ducted by § 60.8 is completed, no owner
or operator subject to the provisions of
this subpart shall cause to be discharged
into the atmosphere from any dryer any
gases which contain particulate matter
in excess of 50 mg/dscm (0.022 gr/dscf).
§ 60.163 Standard for sulfur dioxide.
(b) On and after the date on which
the performance test required to be con-
ducted by § 60.8 is completed, no owner
or operator subject to the provisions
of this subpart shall cause to be dis-
charged Into the atmosphere from any
roaster, smelting furnace, or copper con-
verter any gases which contain sulfur
dioxide in excess of 0.065 percent by
volume, except as provided in para-
graphs (b) and (c) of this section.
(b) Reverberatory smelting furnaces
shall be exempted from paragraph (a)
of this section during periods when the
total smelter charge at the primary cop-
per smelter contains a high level of
volatile impurities.
(c) A change in the fuel combusted
in a reverberatory furnace shall not be
considered a modification under this
part.
§ 60.164 Standard for visible emissions.
(a) On and after the date on which
the performance test required to be con-
ducted by § 60.8 is completed, no owner
or operator subject to the provisions of
this subpart shall cause to be discharged
into the atmosphere from any dryer any
visible emissions which exhibit greater
than 20 percent opacity.
(b) On and after the date on which
the performance test required to be con-
ducted by § 60.8 is completed, no owner
or operator subject to the provisions of
this subpart shall cause to be discharged
into the atmosphere from any affected
facility that uses a sulfuric acid to com-
ply with the standard set forth in
§ 60.163, any visible emissions which ex-
hibit greater than 20 percent opacity.
§ 60.165 Monitoring of operations.
fa) The owner or operator of any pri-
mary copper smelter subject to § 60.163
(b) shall keep a monthly record of the
total smelter charge and the weight per-
cent (dry basis) of arsenic, antimony,
lead and zinc contained in this charge.
The analytical methods and procedures
employed to determine the weight of the
monthly smelter charge and the weight
percent of arsenic, antimony, lead and
zinc shall be approved by the Adminis-
trator and shall be accurate to within
plus or minus ten percent.
(b) The owner or operator of any pri-
mary copper smelter subject to the pro-
visions of this subpart shall install and
operate:
(1) A continuous monitoring system
to monitor and record the opacity of
gases discharged into the atmosphere
from any dryer. The span of this system
shall be set at 80 to 100 percent opacity.
(2) A continuous monitoring system
to monitor and record sulfur dioxide
emissions discharged Into the atmos-
phere from any roaster, smelting furnace
or copper converter subject to § 60.163
(a). The span of this system shall be
set at a sulfur dioxide concentration of
0.20 percent by volume.
(i) The continuous monitoring system
performance evaluation required under
§ 60.13 (c) shall be completed prior to the
initial performance test required under
§ 60.8. During the performance evalua-
tion, the span of the continuous moni-
toring system may be set at a sulfur
dioxide concentration of 0.15 percent by
volume If necessary to maintain the sys-
tem output between 20 percent and 90
percent of full scale. Upon completion
of the continuous monitoring system
performance evaluation, the span of the
continuous monitoring system shaJl be
set at a sulfur dioxide concentration of
0.20 percent by volume.
(ii) For the purpose of the continuous
monitoring system performance evalua-
tion required under § 60.13(c) the ref-
erence method referred' to under the
Field Test for Accuracy (Relative) in
Performance Specification 2 of Appendix
B to this part shall be Reference Method
6. For the performance evaluation, each
concentration measurement shall be of
one hour duration. The pollutant gas
used to prepare the calibration gas mix-
tures required under paragraph 2.1, Per-
formance Specification 2 of Appendix 3,
and for calibration checks under § 60.13
(d), shall be sulfur dioxide.
(c) Six-hour average sulfur dioxide
concentrations shall be calculated and
recorded daily for the four consecutive 6-
hour periods of each operating day. Each
six-hour average shall be determined a;;
the arithmetic mean of the appropriate
six contiguous one-hour average sulfur
dioxide concentrations provided by th<:
continuous monitoring system installed
under paragraph (b) of this section.
(d) For the purpose of reports required
under § 60.7(c), periods of excess emis-.
sions that shall be reported are defined
as follows:
(D Opacity. Any six-minute period
during which the average opacity, as
measured by the continuous monitoring
system installed under paragraph (b) of
this section, exceeds the standard under
§ 60 164(a).
(2) Sulfur dioxide. Any six-hour pe-
riod, as described in paragraph (c) of
this section, during which the average
emissions of sulfur dioxide, as measured
by the continuous monitoring system in-
stalled under paragraph (b) of this sec-
tion, exceeds the standard under
§60.163.
§ 60.166 Test methods and procedures.
(a) The reference methods in Ap-
pendix A to tills part, except as provided
for in § 60.8(b), shall be used to deter-
mine compliance with the standards
prescribed in §§60.162, 60.163 and
60.164 as follows:
(1) Method 5 for the concentration of
particulate matter and the associated
moisture content.
(2) Sulfur dioxide concentrations shall
be determined using the continuous
monitoring system installed in accord-
ance with § 60.165(b). One 6-hour aver-
age period shall constitute one run. The
monitoring system drift during any n:n
shall not exceed 2 percent of span.
(b) For Method 5, Method 1 shall be
used for selecting the sampling site and
the number of traverse points, Method 2
for determining velocity and volumetric
flow rate and Method 3 for determining
the gas analysis. The sampling time for
each run shall be at least 60 minutes and
the minimum sampling volume shall l>e
0.85 dscm (30 dscf) except that smaller
times or volumes, when necessitated by
process variables or other factors, may
be approved by the Administrator.
FEOfXAt..REGISTER. VOl. 41 NO 10THURSDAY, JANUARY 15, 1976
IV-130
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2&10
RULES AND REGULATIONS
Subpart QStandards of Performance for
Primary Zinc Smelters
§ 60.170 Applicability and designation
of affected facility.
The provisions of this subpart are ap-
plicable to the following affected facili-
ties in primary zinc smelters: roaster and
sintering machine.
§ 60.171 Definitions.
As used in this subpart, all terms not
defined herein shall have the meaning
given them in the Act and In subpart A
of this part.
(a) "Primary zinc smelter" means any
installation engaged in the production, or
any Intermediate process In the produc-
tion, of zinc or zinc oxide from zinc sul-
fide ore concentrates through the use
of pyrometallurglcal techniques.
(b) "Roaster" means any facility In
which a zinc sulflde ore concentrate
charge Is heated In the presence of air
to eliminate a significant portion (more
than 10 percent) of the sulfur contained
in the charge.
(c) "Sintering machine" means any
furnace In which calcines are heated in
the presence of air to agglomerate the
calcines Into a hard porous mass called
"sinter."
(d) "Sulfuric acid plant" means any
facility producing sulfuric acid by the
contact process.
§ 60.172 Standard for paniculate mat-
ter.
(a) On and after the date on which
the performance test required to be con-
ducted by ! 60.8 Is completed, no owner
or operator subject to the provisions of
this subpart shall cause to be discharged
into the atmosphere from any sintering
machine any gases which contain par-
ticulate matter in excess of 50 mg/dscm
(0.022 gr/dscf).
§ 60.173 Standard for sulfur dioxide.
(a) On and after the date on which
the performance test required to be con-
ducted by § 60.8 is completed, no owner
or operator subject to the provisions of
tills subpart shall cause to be discharged
Into the atmosphere from any roaster
any gases which contain sulfur dioxide in
excess of 0.065 percent by volume.
(b) Any sintering machine which
sliminates more than 10 percent of the
sulfur initially contained in the zinc
sulfide ore concentrates will be consid-
ered as a roaster under paragraph (a)
of this section.
§ 60,174 Standard for visible emissions.
(a) On and after the date on which the
performance test required to be con-
ducted by i 60.8 is completed, no owner
or operator subject to the provisions of
tliis subpart shall cause to be discharged
into the atmosphere from any sintering
machine any visible emissions which ex-
hibit greater than 20 percent opacity.
(b) On and after the date on which
the performance test required to be con-
ducted by i 60.8 is completed, no owner
or operator subject to the provisions of
this subpart shall cause to be discharged
Into the atmosphere from any affected
facility that uses a sulfuric acid plant to
comply with the standard set forth in
5 60.173, any visible emissions which ex-
hibit greater than 20 percent opacity.
§ 60.175 Monitoring of operations.
(a) The owner or operator of any pri-
mary zinc smelter subject to the provi-
sions of this subpart shall install and
operate:
(1) A continuous monitoring system to
monitor and record the opacity of gases
discharged into the atmosphere from any
sintering machine. The span of this sys-
tem shall be set at 80 to 100 percent
opacity.
(2) A continuous monitoring system to
monitor and record sulfur dioxide emis-
sions discharged into the atmosphere
from any roaster subject to § 60.173. The
span of this system shall be set at a
sulfur dioxide concentration of 0.20 per-
cent by volume.
(i) The continuous monitoring system
performance evaluation required under
§ 60.13(c) shall be completed prior to the
initial performance test required under
§ 60.8. During the performance evalua-
tion, the span of the continuous monitor-
ing system may be set at a sulfur dioxide
concentration of 0.15 percent by volume
if necessary to maintain the system out-
put between 20 percent and 90 percent
of full scale. Upon completion of the con-
tinuous monitoring system performance
evaluation, the span of the continuous
monitoring system shall be set at a sulfur
dioxide concentration of 0.20 percent by
volume.
(ii) For the purpose of the continuous
monitoring system performance evalua-
tion required under § 60.13(c), the ref-
erence method referred to under the
Field Test for Accuracy (Relative) in
Performance Specification 2 of Appendix
B to this part shall be Reference Method
6. For the performance evaluation, each
concentration measurement shall be of
one hour duration. The pollutant gas
used to prepare the calibration gas mix-
tures required under paragraph 2.1, Per-
formance Specification 2 of Appendix B,
and for calibration checks under § 60.13
(d). shall be sulfur dioxide.
(b) Two-hour average sulfur dioxide
concentrations shall be calculated and
recorded daily for the twelve consecutive
2-hour periods of each operating day.
Each two-hour average shall be deter-
mined as the arithmetic mean of the ap-
propriate two contiguous one-hour aver-
age sulfur dioxide concentrations pro-
vided by the continuous monitoring sys-
tem installed under paragraph (a) of
this section.
(c) For the purpose of reports required
under § 60.7(c), periods of excess emis-
sions that shall be reported are denned
as follows:
(1) Opacity. Any six-minute period
during which the average opacity, as
measured by the continuous monitoring
system installed under paragraph (a) of
this section, exceeds the standard under
§ 60.174
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RULES AND REGULATIONS
2541
centrate charge Is generated by passing
an electric current through a portion of
the molten mass In the furnace.
(h) "Converter" means any vessel to
which lead concentrate or bullion is
charged and refined.
(i) "Sulfuric acid plant" means any
facility producing sulfuric acid by the
contact process.
§60.182 Standard for partirulnto mai-
ler.
(a) On and after the date on which
the performance test required to be con-
ducted by § 60.8 is completed, no owner
or operator subject to the provisions of
this subpart shall cause to be discharged
into the atmosphere from any blast fur- '
nace, dross reverberatory furnace, or
sintering machine discharge end any
gases which contain particulate matter
in excess of 59 mg/dscm (0.022 gr/dscf).
§ 60.183 Standard for sulfur dioxide.
(a) On and after the date on which
the performance test required to be con-
ducted by ! 60.8 is completed, no owner
or operator subject to the provisions of
this subpart shall cause to be discharged
into the atmosphere from any sintering
machine, electric smelting furnace, or
converter gases which contain sulfur di-
oxide in excess of 0.065 percent by
volume.
§ 60.181 Standard for \isihlo emissions.
(a) On and after the date on which
the performance test required to be con-
ducted by § 60.8 is completed, no owner
or operator subject to the provisions of
this subpart shall cause to be discharged
into the atmosphere from any blast fur-
nace, dross reverberatory furnace, or
sintering machine discharge end any
visible emissions which exhibit greater
than 20 percent opacity.
(b) On and after the date on which
the performance test required to be con-
ducted by § 60.8 is completed, no owner
or operator subject to the provisions of
this subpart shall cause to be discharged
into the atmosphere from any affected
facility that uses a sulfuric acid plant to
comply with the standard set forth in
§ 60.183, any visible emissions which
exhibit greater than 20 percent opacity.
§ 60.185 Monitorih£ of operation?.
(a) The owner or operator of any
primary lead smelter subject to the pro-
visions of this subpart shall install and
operate:
<1) A continuous monitoring system
to monitor and record the opacity of
gases discharged into the atmosphere
from any blast furnace, dross rever-
bevatory furnace, or sintering machine
discharge end. The span of this system
shall be set at 80 to 100 percent opacity.
(2) A continuous monitoring system
to monitor and record sulfur dioxide
emissions discharged into the atmos-
phere from any sintering machine,
electric furnace or converter subject to
§ 60.183. The span of this system shall
be set at a sulfur dioxide concentration
of 0.20 percent by volume.
(i) The continuous monitoring system
performance evaluation required under
§ 60.13(c) shall be completed prior to the
initial performance test required under
§ 60.8. During the performance evalua-
tion, the span of the continuous moni-
toring system may be set at a sulfur
dioxide concentration of 0.15 percent by
volume if necessary to maintain the sys-
tem output between 20 percent and 90
percent of full scale. Upon completion
of the continuous monitoring system
performance evaluation, the span of the
continuous monitoring system shall be
set at a sulfur dioxide concentration of
0.20 percent by volume.
(ii) For the purpose of the continuous
monitoring system performance evalua-
tion required under § 60.13(c), the refer-
ence method referred to under the Field
Test for Accuracy (Relative) in Per-
formance Specification 2 of Appendix B
to this part shall be Reference Method
6. For the performance evaluation, each
concentration measurement shall be of
one hour duration. The pollutant gases
used to prepare the calibration gas mix-
tures required under paragraph 2.1, Per-
formance Specification 2 of Appendix B,
and for calibration checks under § 60.13
(d), shall be sulfur dioxide.
(b) Two-hour average sulfur dioxide
concentrations shall be calculated and
recorded daily for the twelve consecu-
tive two-hour periods of each operating
day. Each two-hour average shall be de-
termined as the arithmetic mean of the
appropriate two contiguous one-hour
average sulfur dioxide concentrations
provided by the continuous monitoring
system installed under paragraph (a; of
this section.
(c) For the purpose of reports re-
quired under § 60.7(c), periods of excess
emissions that shall be reported are de-
fined as follows:
(1) Opacity. Any six-minute period
during which the average opacity, as
measured by the continuous monitoiing
system installed under paragraph (a) of
this section, exceeds the standard under
§ 60.184(a).
<2) Sulfur dioxide. Any two-hour pe-
riod, as described in paragraph (b) of
this section, during which the average
emissions of sulfur dioxide, as measured
by the continuous monitoring system in-
stalled under paragraph (a) of this sec-
tion, exceeds the standard under § 60.183.
§ 60.186 Tosi methods and proeeduires.
(a) The reference methods in Appen-
dix A to this part, except as provided for
in § 60.8(b), shall be used to determine
compliance with the standards pre-
scribed in §§ 60.182, 60.183 and 60.184 as
follows:
(1) Method 5 for the concentration
of particulate matter and the associated
moisture content.
(2) Sulfur dioxide concentrations shall
be determined using the continuous
monitoring system installed in accord-
ance with § 60.185(a). One 2-hour aver-
age period shall constitute one run.
ib) For Method 5, Method 1 shall be
used for selecting the sampling site and
the number of traverse points, Method 2
for determining velocity and volumetric
flow rate and Method 3 for determining
the gas analysis. The sampling time .for
each run shall be at least 60 minutes and
the minimum sampling volume shall be
0.85 dscm (30 dscf) except that smaller
times or volumes, when necessitated by
process variables or other factors, may be
approved by the Administrator.
(FR Doc.76-733 Filed l-14-76;8:45 am]
FEDERAL REGISTER, VOL. 41, NO. 10THURSDAY, JANUARY 15, 1976
IV-132
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3826
RULES AiiD REGULATIONS
2 7 Title 40Protection of Environment
CHAPTER IENVIRONMENTAL
PROTECTION AGENCY'
SUBCHAPTER CAIR PROGRAMS
IFRL 471^1]
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Primary Aluminum Industry
On October 23. 1974 (39 FR 37730),
under sections 111 and 114 of the Clean
Air Act '42 U.S.C 1857c-6, 1857c-9>, as
amended, the Administrator proposed
standards of performance for new and
modified primary aluminum reduction
plants. Interested persons participated
in the rulemaking by submitting written
comments to EPA The comments have
been carefully considered and, where de-
termined by the Administrator to be ap-
propriate, changes have been made in
the regulations as promulgated.
These regulations will not, in them-
selves, require control of emissions from
existing primary aluminum reduction
plants Such control will be required only
after EPA establishes emission guidelines
for existing plants under section lll(d)
of the Clean Air Act, which will trigger
the adoption of State emission standards
for existing plants General regulations
concerning control of existing sources
under section llHd) were proposed on
October 7, 1975 (39 FR 36102) and were
promulgated on November 17, 1975 (40
FR 53339).
The bases for the proposed standards
are presented in the first two volumes of
a background document entitled "Back-
ground Information for Standards of
Performance1 Primary Aluminum In-
dustry" Volume 1 (EPA 450.2-74-020a,
October 1974) contains the rationale for
the proposed standards and Volume 2
(EPA 450/2-74-020b, October 1974) con-
tains a summary of the supporting test
data. An inflation impact statement for
the standards and a summary of the
comments received on the proposed
standards along with the Agency re-
sponses are contained in a new Volume 3
(EPA 450/2-74-020C, November 1975) of
the background document Copies of all
three volumes of the background docu-
ments are available on request from the
Emission Standards and Engineering Di-
vision, Environmental Protection Agency,
Research Triangle Park, N.C 27711, At-
tention: Mr. Don R Goodwin.
SUMMARY OF REGULATIONS
The standards of performance promul-
gated herein limit emissions of gaseous
and particulate fluorides from new and
modified affected facilities within pri-
mary aluminum reduction plants. The
standard for fluorides limits emissions
from each potroom group within Sodcr-
berg plants to 2.0 pounds of total fluo-
rides per ton of aluminum produced ,401 M Street. SW.,
Washington, DC. 20460 I specify "Back-
ground Information for Standards of
Performance' Primary Aluminum Indus-
try Volume 3- Supplemental Informa-
tion" lEPA 45/2-74-020C) 1. The most
significant comments and changes made
to the proposed regulations are discussed
below.
(1) Designation ol Aflrcted Facility.
Several comments questioned the "ap-
plicability and designation of affected
facility" section of the proposed regu-
lations (§ 60.1901 in view of regulations
previously proposed by EPA with regard
to modification of existing plants (39
FR 36946, October 15, 19741 In 5 60 190
as proposed, the entire primary alumi-
num reduction plant was designated as
the affected facility. The commentators
argued that, as a result of this desig-
nation, addition or modification of a
single potroom at an existing plant
would subject all existing potrooms at
the plant to the standards for new
sources. The commentators argued that
this situation would unfairly restrict ex-
pansion The Agency considered these
comments and agreed that there would
be an adverse economic impact on ex-
pansion of existing plants unless the
affected facility designation were re-
vised.
To alleviate the problem, a new af-
fected facility designation has been in-
corporated in §60.190(ai The affected
facilities within primal y aluminum
plants are now each "potroom group"
and each anode bake plant within pre-
bake plants. This redesignation in turn
required splitting the fluoride standard
for prebake plants into separate stand-
ards for potroom groups and anode bake
plants (see discussion in next section).
As defined in § 60 191. the term "pot-
room group" means an uncontrolled pot-
room, or a potroom which is controlled
individually, or a group of potrooms
ducted to the same control system Under
this revised designation, addition or
modification of a potroom group at an
existing plant will not subject the entire
plant to the standards (unless the plant
consists of only one potroom group).
Similarly, addition or modification of an
anode bake plant at an exiting prebake
facility will not subject the entire pre-
bake facility to the standards. Only the
new or modified potroom group or anode
bake plant must meet the applicable
standards in such cases.
(2) Fluoride Standard. Many com-
mentators questioned the level of the
proposed standard; i.e., 2.0 Ib TF/TAP.
A number of industrial commentators
suggested that the standard be relaxed
or that it be specified in terms of a
monthly or yearly emission limit Some
commentators argued that the test data
did not support the standard and that
statistical techniques should have been
applied to the test data in order to ar-
rive at an emission standard.
Standards of performance under sec-
tion 111 are based on the best control
technology which (taking into account
control costs) has been "adequately
demonstrated." "Adequately demon-
strated" means that the Administrator
must determine, on the basis of all in-
formation available to him (including
but not limited to tests and observations
of existing plants and demonstration
projects or pilot applications) and the
exercise of sound engineering judgment,
that the control technology relied upon
in setting a standard of performance
can be made available and will be ef-
fective to enable sources to comply with
the standards In other words, test data
for existing plants are not the only bases
for standard setting. As discussed in the
background document, EPA considered
not only test data for existing plants,
but also the expected performance of
newly constructed plants Some existing
plants tested did average less than 2.0
Ib TF/TAP. Additionally, EPA believes
new plants can be specifically designed
for best control of air pollutants and,
therefore, that new plant emission con-
trol performance should exceed that of
well-controlled existing plants Finally,
relatively simple changes in current op-
erating methods (eg. cell tapping) can
produce significant reductions in emis-
sions For these reasons, EPA believes
the 2.0 Ib TF. TAP standard is both rea-
sonable and achievable A more detailed
discussion of the rationale for selecting
the 2.0 Ib TF TAP standard is contained
in Volume 1 of the background docu-
ment, and EPA's responses to specific
comments on the fluoride standard are
contained in Volume 3
As a result of the revised affected fa-
cility designation, the 2.0 Ib TF/TAP
standard for prebake plants has been
split into separate standards for potioom
groups (1 9 Ita TF/TAP) and anode bake
plants (0.1 Ib TF/TAP). The proposed
20 Ib'TF/TAP limitation for prebake
plants alwavs consisted of these two
components, but was published as a com-
FEDERAL REGISTER, VOL. 41, NO. 17MONDAY, JANUARY 26, 1976
IV-133
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RULES AND REGULATIONS
3827
bined standard to be consistent with the
original affected facility designation
(i.e, the entire primary aluminum
plant). At the time of proposal, the
Agency had not foreseen the potential
problems with modification of a two part
affected facility. Data supporting each
component of the standard as proposed
is contained in the background docu-
ment (Volumes 1 and 2). In support of
the potroom component of the standard,
for example, two existing prebake pot-
rooms tested by the Agency averaged
less than 1.9 Ib TF/TAP. Because no well
controlled anode bake plants existed at
the time of aluminum plant testing, the
components for anode bake plants was
based on a conservatively assumed con-
trol efficiency for technology demonstrat-
ed in the phosphate fertilizer industry.
Using the highest emission rate observed
at two anode bake plants which were not
controlled for fluorides and applying the
assumed control efficiency, it was pro-
jected that these plants would emit ap-
proximately 0.06 Ib TF/TAP (0.12 Ib TF/
ton of carbon anodes produced). In addi-
tion, as indicated in Volume 1 of the
background document, it may be possi-
ble to meet the standard for anode bake
plants simply by better cleaning of anode
remnants. The Agency also has estimates
of emission rates for a prebake facility
to be built in the near future. The esti-
mates indicate that the anode bake plani
at the facility will easily meet the 0.1
TF/TAP standard.
One commentator questioned why the
standard was not more stringent con-
sidering the fact that Oregon has
promulgated the following standards for
new primary aluminum plants: (a) a
monthly average of 1.3 pounds of fluoride
ion per ton of aluminum produced, and
(b) an annual average of 1.0 pound of
fluoride ion per ton of aluminum
produced.
There are several reasons why the
Agency elected not to adopt standards
equivalent to the Oregon standards. Per-
haps most important, EPA believes that
the Oregon standards would require the
installation of relatively inefficient sec-
ondary scrubbing systems at most if not
all new primary aluminum plants By
contrast, EPA's standard will require use
of secondary control systems only for
vertical stud Soderberg (VSS) plants
(which are unlikely to be built in any
event) and side-work prebake plants. A
standard requiring secondary control
systems on most if not all plants would
have a substantial adverse economic im-
pact on the aluminum industry, as is
indicated in the economic section of the
background document. Accordingly,
EPA has concluded that considerations
of cost preclude establishing a standard
comparable to the Oregon standards.
A second reason for not adopting
standards equivalent to the Oregon
standards stems from the fact that the
latter were based on test data consist-
ing of six monthly averages (calculated
by averaging from three to nine individ-
ual tests each month) from a certain
well controlled plant (which incorporates
both primary and secondary control).
Oregon applied a statistical method to
these data to derive the emission stand-
ards it adopted. As discussed in the com-
ment summary, EPA also performed a
statistical analysis of the Oregon test
data, which yielded results different
from those presented in the Oregon tech-
nical report. If the Agency's results had
been used, less stringent emission stand-
ards might have been promulgated in
Oregon.
A third consideration is that the test
methods used by Oregon were not the
same as those used by the Agency to
collect emission data in support of the
respective standards. Therefore, Ore-
gon's test data and the Agency's test
data are not directly comparable
Finally, a comment on the standard
for fluorides questioned whether or not
EPA had considered a new, potentially
non-polluting primary aluminum reduc-
tion process developed by Alcoa. The
commentator argued that if the process
had become commercially available, the
standard should be set at a level suffi-
ciently stringent to stimulate the devel-
opment of this new process. In response
to this comment, EPA has investigated
the process and has determined that it
is not yet commercially available. Alcoa
plans to test the process at a small pilot
plant which will begin production early
next year. If the pilot plant performs
successfully, it will be expanded to full
design capacity by the early 1980's. EPA
will monitor the progress of this process
and other processes under development
and will reevaluate the standards of per-
formance for the primary aluminum in-
dustry, as appropriate, in light of the
new technology.
(3) Opacity. Some of the industrial
commentators objected to the proposed
opacity standards for potrooms and
anode bake plants. They argued that
good control of total fluorides will result
in good control of particulate matter,
and therefore that the opacity standards
are unnecessary. EPA agrees that good
control of total fluorides will result in
good control of particulate matter; how-
ever, the opacity standards are intended
to serve as inexpensive enforcement tools
that will help to insure proper operation
and maintenance of the air pollution
control equipment. Under 40 CFR
60.11(d), owners and operators of af-
fected facilities are required to operate
and maintain their control equipment
properly at all times Continuous moni-
toring instruments are often required to
indicate compliance with 60.11(d), but
this is not possible in the primary
aluminum industry because continuous
total fluoride monitors are not commer-
cially available. The data presented in
the background document indicate that
the opacity standards can be easily met
at well controlled plants that are prop-
erly operated and maintained. For these
reasons, the opacity standards have been
retained in the final regulations.
EPA recognizes, however, that in un-
usual circumstances (e.g., where emis-
sions exit from an extremely wide stack)
a source might meet the mass emission
limit but fail to meet the opacity limit.
In such cases, the owner or operator of
the source may petition the Administra-
tor to establish a separate opacity stand-
ard under 40 CFR 60 ll(e) as revised on
November 12, 1974 (39 PR 39872).
<4i Control of Other Pollutants. One
commentator was concerned that EPA
did not propose standards for carbon
monoxide (CO) and sulfur dioxide (SO-)
emissions from aluminum plants. The
commentator argued that aluminum
smelters are significant sources of these
pollutants, and that although fluorides
are the most toxic aluminum plant emis-
sions, standards for all pollutants should
have been proposed. As discussed in the
preface to Volume 1 of the background
document, fluoride control was selected
as one area of emphasis to be considered
in implementing the Clean Air Act. In
turn, primary aluminum plants were
identified as major sources of fluoride
emissions and were accordingly listed as
a category of sources for which standards
of performance would be proposed. Nat-
urally, the initial investigation into
standards for the primary aluminum
industry focused on fluoride control.
However, limited testing of CO and SO.
emissions was also carried out and it was
determined (a) that although primary
aluminum plants might be a significant
source of SOj, SO., control technology had
not been demonstrated in the industry,
and (b) that CO emissions from such
plants were insignificant. For these rea-
sons, standards of performance were not
proposed for SO., and CO emissions.
It is possible that SO; control technol-
ogy used in other industries might be ap-
plicable to aluminum plants, and recent
information indicates that CO emissions
from such plants may be significant. At
present, however, EPA has insufficient
data on which to base SO2 and CO emis-
sion standards for aluminum plants. EPA
will consider the factors mentioned
above and other relevant information in
assigning priorities for future standard
setting and invites submission of perti-
nent information by any interested
parties Thus, standards for CO and SOz
emissions from primary aluminum plants
may be .set in the future.
(5) Reference Methods ISA and 13B.
These methods prescribe sampling and
analysis procedures for fluoride emis-
sions and are applicable to the testing
of phosphate fertilizer plants in addi-
tion to primary aluminum plants. The
methods were originally proposed with
the primary aluminum regulations but
have been promulgated with the stand-
ards of performance for the phosphate
fertilizer industry (published August 6,
1975, 40 FR 33152) because the fertilizer
regulations were promulgated before
those for primary aluminum. Comments
on the methods, were received from both
industries and mainly concerned pos-
sible changes in procedures and equip-
ment specifications. As discussed in the
preamble to the: phosphate fertilizer reg-
ulations, some minor changes were made
as a result of these comments.
Some commentators expressed a desire
to replace Methods 13A and 13B with
totally different methods of analysis
They felt that they should not be re-
stricted to using only those methods pub-
lished by the Agency. In response to these
FEDERAL REGISTER, VOL. 41, NO. 17MONDAY, JANUARY 26, 1976
IV-134
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RULES AMU REGULATIONS
comments, an equivalent or alternative
method may be used if approved by the
Administrator under 40 CFR 60.8 Reference Method 14. Reference
Method 14 specifies sampling equipment
and sampling procedures for measuring
fluoride emissions from roof monitors.
Most comments concerning this method
suggested changes in the prescribed
manifold system. A number of com-
mentators objected to the requirement
that stainless steel be used as the struc-
tural material for the manifold and sug-
gested that other, less expensive struc-
tural materials would work as well. Data
submitted by one aluminum manufac-
turer supported the use of aluminum for
manifold construction. The Agency re-
viewed these data and concluded that an
aluminum manifold will provide satisfac-
tory fluoride samples if the manifold is
conditioned prior to testing by passing
fluoride-laden air through the system.
By using aluminum instead of stainless
steel, the cost of installing a sampling
manifold would be substantially reduced.
Since the Agency had no data on other
possible structural materials, it was not
possible to endorse their use in the meth-
od. However, the following wording ad-
dressing this subject has been added to
the method text (§2.2.1): "Other ma-
terials of construction may be used if it
is demonstrated through comparative
testing that there is no loss of fluorides
in the system."
Some commentators also objected to
the requirement that the mean velocity
measured during fluoride sampling be
within ±10 percent of the previous 24-
hour average velocity recorded through
the system In order to reduce the num-
ber of rejected, sampling runs due to
failure to meet the above criteria, the
requirement has been amended such that
the mean sampling velocity must be
within ±20 percent of the previous 24-
hour average velocity. EPA believes that
the relaxation of this requirement will
not compromise the accuracy of the
method
(7) Economic Impact Some comments
raised questions regarding the economic
impact of the proposed regulations. The
Agency has considered these comments
and responded to them in the comment
summary cited above. As indicated pre-
viously, an analysis of the inflationary
and energy impacts of the standards ap-
pears in Volume 3 of the background
document. Copies of these documents
may be obtained as indicated previously.
Effective date In accordance with sec-
tion 111 of the Act. these regulations are
effective January 26, 1976 and apply to
sources the construction or modification
of which commenced after proposal of
the standards: i e., after October 23
1974
(It is hereby certified that the economic and
inflationary impacts of this regulation have
been carefully evaluated in accordance with
Executive Order 11821)
Dated: January 19,1976.
RUSSELL E. TRAIN,
Administrator.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations, is amended
as follows:
1. The table of sections is amended by
adding a list of sections for Subpart S
and by adding Reference Method 14 to
the list of reference methods in Appen-
dix A as follows:
Subpart SStandards of Performance for
Primary Aluminum Reduction Plants
Sec
60.190 Applicability and designation of af-
fected facility
60 191 Definitions
60 192 Standard for tluorldes
60 193 Standard for visible emissions.
60 194 Monitoring of operations
60 195 Test methods and procedures.
*****
APPENDIX AREFERENCE METHODS
*****
METHOD 14DETERMINATION OF FLUORIDE
EMISSIONS FROM POTROOM ROOF MONI-
TORS OF PRIMARY ALUMINUM PLANTS
AUTHORITY Sees 111 and 114. Clean Air
Act, as amended by sec 4(a), Pub L 91-604,
84 Stat 1678, 42 U S C 1857 C-6, C-9
2. Part 60 is amended by adding sub-
part S as follows:
Subpart SStandards of Performance for
Primary Aluminum Reduction Plants
§ 60.190 Applicability and designation
of affected faeility.
The affected facilities in primary alu-
minum reduction plants to which this
subpart applies are potroom groups and
anode bake plants
§60.191 Definitions.
As used in this subpart, all terms not
defined herein shall have the meaning
given them in the Act and in subpart A
of this part.
(a) "Primary aluminum reduction
plant" means any facility manufacturing
aluminum by electrolytic reduction.
(b) "Anode bake plant" means a facil-
ity which produces carbon anodes for use
in a primary aluminum reduction plant
(c) "Potroom" means a building unit
which houses a group of electrolytic cells
in which aluminum is produced.
(d> "Potroom group" means an uncon-
trolled potroom. a potroom which is
controlled individually, or a group of
potrooms ducted to the same control
system.
(e) "Roof monitor" means that portion
of the roof of a potroom where gases not
captured at the cell exit from the
potroom.
(f> "Aluminum equivalent" means an
amount of aluminum which can be pro-
duced from a ton of anodes produced by
an anode bake plant as determined by
§ 60.195(e).
1.
(h) "Primary control system" means
an air pollution control system designed
to remove gaseous and particulate fluo-
rides from exhaust gases which are cap-
tured at the cell.
(i) "Secondary control system" means
an air pollution control system designed
to remove gaseous and particulate fluo-
rides from gases which escape capture by
the primary control system.
§ 60.192 Standard for fluorides.
(a) On and after the date on which
the performance test required to be con-
ducted by § 60.8 is completed, no owner
or operator subject to the provisions of
this subpart shall cause to be discharged
into the atmosphere from any affected
facility any gases which contain total
fluorides in excess of:
(1) 1 kg/metric ton (2 Ib/ton) of
aluminum produced for vertical stud
Soderberg and horizontal stud Soderberg
plants;
(2) 0.95 kg/metric ton (1.9 Ib/ton) of
aluminum produced for potroom groups
at prebake plants; and
'3i 005 kg/metric ton (0.1 Ib/ton) of
aluminum equivalent for anode bake
plants.
§ 60.193 Standard for visible emissions.
(a) On and after the date on which
the performance test required to be con-
ducted by § 60 8 is completed, no owner
or operator subject to the provisions of
this subpart shall cause to be discharged
into the atmosphere:
(1) From any potroom group any
gases which exhibit 10 percent opacity or
greater, or
(2) From any anode bake plant any
gases which exhibit 20 percent opacity or
greater.
§ 60.194 Monitoring of operations.
ia) The owner or operator of any af-
fected facility subject to the provisions
of this subpart shall install, calibrate,
maintain, and operate monitoring devices
which can be used to determine daily
the weight of aluminum and anode pro-
duced The weighing devices shall have
an accuracy of ±5 percent over their
operating range
The owner or operator of any af-
fected facility shall maintain a record of
daily production rates of aluminum and
anodes, raw material feed rates, and cell
or potlme voltages.
§ 60.195 Test methods and procedures.
(a) Except as provided in §60.8(b),
reference methods specified in Appendix
A of this part shall be used to determine
compliance with the standards prescribed
in § 60.192 as follows:
< 1) For sampling emissions from
stacks-
H) Method 13A or 13B for the concen-
tration of total fluorides and the associ-
ated moisture content,
(io Method 1 for sample and velocity
traverses.
(111) Method 2 for velocity and volu-
metric flow rate, and
(iv) Method 3 for gas analysis.
(2) For sampling emissions from roof
monitors not employing stacks or pol-
lutant collection systems:
(i) Method 14 for the concentration of
total fluorides and associated moisture
content,
FEDERAL REGISTER, VOL. 41, NO. 17MONDAY, JANUARY J<, 1976
IV-135
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RULES AND REGULATIONS
3829
(ii) Method 1 for sample and velocity
traverses,
(Hi) Method 2 and Method 14 for ve-
locity and volumetric flow rate, and
riv' Method 3 for gas analysis.
(3) For sampling emissions from roof
monitors not employing stacks but
equipped with pollutant collection sys-
tems, the procedures under § 60.8(b)
shall be followed.
(b) For Method 13A or 13B, the sam-
pling time for each run shall be at least'
eight hours for any potroom sample and
at least four hours for any anode bake
plant sample, and the minimum sample
volume shall be 6.8 dscm (240 dscf) for
any potroom sample and 3.4 dscm (120
dscf) for any anode bake plant sample
except that shorter sampling times or
smaller volumes, when necessitated by
process variables or other factors, may
be approved by the Administrator.
(c) The air pollution control system
for each affected facility shall be con-
structed so that volumetric flow rates and
total fluoride emissions can be accurately
determined using applicable methods
specified under paragraph (a) of this
section.
stream In dscm/hr as
determined by Method 2 and/or
Method 14, as applicable
10-"conversion factor from mg to kg
Jlf=rate of aluminum production in
metric ton/hr as determined by
§ 60 195(d)
(C,Q.)7=product of C. and Q, for meas-
urements of primary control
system effluent gas streams.
(CiQi) i=product of C. and Q. for meas-
urements of secondary control
system or roof monitor effluent
gas streams
(g) For each run, as applicable, anode
bake plant emissions expressed in kg/
metric ton of aluminum equivalent shall
be determined using the following equa-
tion:
e.g. 10-'
Eb>= -it -
Where:
Etip anode bake plant emissions of total
fluorides in kg/metric ton of alu-
minum equivalent.
C,=concentratlon of total fluorides In
mg/dscm as determined by Method
13Aor 13B.
Q, = volumetric flow rate of the effluent
gas stream In dscm/hr as deter-
mined by Method 2.
10-t=converslon factor from mg to kg.
M* = aluminum equivalent for anodes pro-
duced by anode bake plants in
metric ton/hr as determined by
§ 60.195(e).
3. Part 60 is amended by adding Ref-
erence Method 14 to Appendix A as fol-
lows:
METHOD 14 DETERMINATION OF FLUORIDE
EMISSIONS FROM POTROOM ROOF MONITORS
OF PRIMARY ALUMINUM PLANTS
1. Principle and applicability.
1.1 Principle. Gaseous and participate
fluoride roof monitor emissions are drawn
Into a permanent sampling manifold through
several large nozzles The sample is trans-
ported from the sampling manifold to ground
level through a duct. The gas In the duct Is
sampled using Method ISA or 13BDETER-
MINATION OF TOTAL FLUORIDE EMIS-
SIONS FROM STATIONARY SOURCES. Ef-
fluent velocity and volumetric flow rate are
determined with anemometers permanently
located in the roof monitor.
1.2 Applicability This method is applica-
ble for the determination of fluoride emis-
sions from stationary sources only when
specified by the test procedures for deter-
mining compliance with new source perform-
ance standards.
2. Apparatus.
2.1.1 Anemometers. Vane or propeller
anemometers with a velocity measuring
threshold as low as 15 meters/minute and a
range up to at least 600 meters/minute. Each
anemometer shall generate an electrical sig-
nal .which can be calibrated to the velocity
measured by the anemometer. Anemometers
shall be able to withstand dusty and corro-
sive atmospheres.
One anemometer shall be installed for
every 85 meters of roof monitor length. If
the roof monitor length divided by 85 meters
Is not a whole number, round the fraction
to the nearest whole nvnber to determine
the number of anemometers needed. Use one
anemometer for any roof monitor less than
85 meters long. Permanently mount the
anemometers at the center of each equal
length along the roof monitor. One anemom-
eter shall be installed In the same section
of the roof monitor that contains the sam-
pling manifold (see section 22.1) Make a
velocity traverse of the width of the roof
monitor where an anemometer Is to be placed
This traverse may be made with any suit-
able low velocity measuring device, and shall
be made dining normal process operating
conditions Install the anemometer at a point
of average velocity along this traverse
2 1 2 Recorders. Recorders equipped with
signs) transducers for converting the elect-l-
eal signal from each anemometer to a con-
tinuous recording of air flow velocity, Or to
an Integrated measure of volumetric flow.
For the purpose of recording velocity, "con-
tinuous" shall mean one readout per 15-
minute or shorter time interval. A constant
amount of time shall elapse between read-
ings Volumetric flow rate may be determined
by an electrical count of anemometer revo-
lutions The recorders or counters shall per-
mit identification of the velocities or flow
rate measured by each individual anemom-
eter.
SAMPLE EXTRACTION
OUCT
FXHAUJT
" STACK
r
WtNIMUM
1DOCTDIA
MINIMUM
f~- HOZZLE -^
VtRTICAl OUCT
sccnow AS SHawn
7 Stm DIA
POT ROOM
EXHAUST IIOWER
Figure 14 1 Roof Morntof Sampling System
»_03S 002SDIA
fO CAllBftATIOn
HOIE
TOILQWEfl .«'"
D°
DIMENSIONS IN METERS
NOT TOSCALE
Figure 14 2 Sampling Manifold and Noizles
2.2 Roof monitor air sampling system
221 Sampling ductwork The manlfo d
system and connecting duct shall be per-
manently installed to draw an air sample
from the roof monitor to ground level. A
typical Installation of duct for drawing a
sample from a roof monitor to ground level
Is shown In Figure 14-1. A plan of a mani-
fold system that Is located In a roof monitor
Is shown in Figure 14-2. These drawings rep-
resent a typical Installation for a generalized
roof monitor. The dimensions on these flf;-
ures may be altered slightly to make the
manifold system fit Into a particular roof
monitor, but the general configuration shall
be followed. There shall be eight nozzles, each
having a diameter of 0 40 to 0.50 meters. Tt-e
length of the manifold system from the fir.st
nozzle to the eighth shall be 35 meters or
eight percent of the length of the roof moni-
tor, whichever Is greater. The duct leading
from the roof monitor manifold shall be
round with a diameter of 0.30 to 0 40 meters.
As shown in Figure 14-2, each of the sample
legs of the manifold shall have a device, such
as a blast gate or valve, to enable adjustment
of flow Into each sample nozzle.
FEDERAL REGISTER, VOL. 41, NO. 17MONDAY, JANUARY U 1976
IV-136
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3830
RULES AND REGULATIONS
Locate 1he manifold along the length of
the roof monitor so that It lies nenr the
midsertton of thp roof monitor If the design
of a particular roof monitor makes this im-
possible. Ihe manifold may he located else-
where along the roof monitor hut avoid
locating the manifold near the ends of the
roof monitor or in a section where the
aluminum reduction pot arrangement is not
tvplcal of the rest of the potroom Center the
sample noz/les In the throat of the roof
monitor (See "Figure 14- 1 ) Construct all
simple-exposed surfaces within the nozzles,
manifold and sample duel of 316 stainless
stool Aluminum may he used if -a new duct-
work system Is conditioned with fKioridc-
laden roof monitor air for a period of six
weeks prior to Initial testing Other materials
of construction may he used If it Is demon-
strated through comparative testing that
there Is no loss of fluorides in the system All
connections In the ductwork shall be leak
free
Locate two sample ports in a vertical sec-
tion of the duct between the roof monitor
and exhaust fan The sample ports shall be at
least 10 duct diameters downstream and
two diameters upstream from any flow dis-
tuibance such as a bend or contraction The
two sample ports shall he situated GO" apart
One of the sample ports shall be situated so
that the dnct can be traversed in the plane
of the nearest upstream duct bend
222 Exhaust fan An Industrial fan or
blower to be attached to the sample duct
at ground level (See Figure 14-1 ) This ex-
haust fan shall have a maximum capacity
such that a large enough volume of air can
be pulled through the ductwork to main-
tain an isokinetic sampling rate in all the
sample nozzles for all flow rates normally en-
countered in the roof monitor
The exhaust fan volumetric flow rate shall
be adjustable so that the roof monitor air
can be drawn Isoklnetically into the sample
nozzles This control of flow may be achieved
by a damper on the Inlet to the exhauster or
by any other workable method
23 Temperature measurement apparatus
2 3 1 Thermocouple Installed In the roof
monitor near the sample duct
232 Signal transducer Transducer to
change the thermocouple voltage output to
a temperature readout
233 Thermocouple wire To reach from
roof monitor to signal transducer and
recorder
234 Sampling train. Use the train de-
scribed In Methods 13A and 13BDetermi-
nation of total fluoride .emissions from sta-
tionary sources.
3. Reagents
3 1 Sampling ana, analysis Use reagents
described in Method ISA or 13BDetermi-
nation of total fluoride emissions from sta-
tionary sources.
4 Calibration
4 1 Propeller anemometer Calibrate the
anemometers so that their electrical signal
output corresponds to the velocity or volu-
metric flow they are measuring Calibrate
according to manufacturer's instructions
42 Manifold intake nozzles Adjust the ex-
haust fan to draw a volumetric flow rate
(refer to Equation 14-1) such that the en-
trance \eloclty Into each manifold nozzle
approximates the average effluent velocity In
the roof monitor Measure the velocity of the
air entering each nozzle by Inserting an S
type pilot tube into a '2 5 cm or less diameter
hole (.see Figure 14 2) located In the mani-
fold between each blast gate (or valve) and
nozzle The pitot tube tip shall be extended
Into the center of the manifold Take care
to insure that ther? is no leakage around the
pitot probe which could affect the Indicated
velocity in the manifold leg If the velocity
of air being drawn into each nozzle Is not
the same, open or close each blast gate (or
^alve) until the \elocity in each nozzle is the
sime Fasten each blast gate (or vnlve) so
that it will remain in this position and close
the pitot port holes This calibration shall be
performed when the manifold system Is in-
stalled (Note: It is recommended that this
calibration be repeated at least once a year )
5 Procedure
5 1 Roof monitor \elocity determination
5 1.1 Velocity value for setting isokinelic
flow. During the 24 hours preceding a test
run, determine the velocity indicated by the
propeller anemometer in the section of roof
monitor containing the sampling manifold.
Velocity readings shall be taken every 15
minutes or at shorter equal time intervals
Calculate the average velocity for the 24-hour
period.
512 Velocity determination during a test
run During the actual t3st run, record the
velocity or volume readings of each propeller
anemometer in the roof monitor Velocity
readings shall be taken for each anemometer
every 15 minutes or at shorter equal time
Intervals (or continuously)
5.2 Temperature recording. Record the
temperature of the roof monitor every two
hours during the test run.
5 3 Sampling
531 Preliminary air flow in duct During
the 24 hours preceding the test, turn on the
exhaust fan and draw roof monitor air
through the manifold duct to condition the
ductwork Adjust the fan to draw a volu-
metric flow through th? duct such that the
velocity of gas entering the manifold nozzles
approximates the average velocity of the air
leaving the roof monitor
532 Isokinetic sample rate, adjustment
Adjust the fan so that the volumetric flow
rate in the duct is such that air enters Into
the manifold sample nozzles at a velocity
equal to the 24-hour average velocity deter-
mined under 511 Equation 14-1 gives the
conect stream velocity which Is needed in the
duct at the sample ports in order for sample
gas to be drawn isokinetlcally Into the mani-
fold nozzles Perform a pilot traverse of the
duct al the sample ports to determine if the
correct average velocity in the duct has been
achieved Perform the pitot determination
according to Method 2 Make this determina-
tion before the start of a test run The fan
setting need not be changed during the run.
ir^L^V..) lmim'te
(Dt)- 60 sec
where1
Vd=desired velocity in duct at sample
ports, meter/sec
Dn=diameter of a roof monitor manifold
nozzle, meters.
flcf=diameter of duct at sample port,
meters
Vm=average velocity of the air stream in
the roof monitor, meters/minute, as
determined under section 511.
523 Sample train operation. Sample the
durt using the standard fluoride train and
methods described lu Methods 13A and 13B
Determination of total fluoride emissions
from stationary sources Select sample ti av-
erse points according to Method 1. If a se-
lected sampling point is less than one inch
from the stack wall, adjust the location of
that point to one Inch away from the wall.
534 Each test run .shall last eight hours
or more If a question exists concerning the
representativeness of an eight-hour test, a
longer test period up to 24 hours may be se-
lected Conduct each run during a period
when all normal operations are performed
underneath the sampling manifold, I.e. tap-
ping, anode changes, maintenance, and other
normal duties. All pots In the potroom shall
be operated In a normal manner during the
test period
535 Sample recovery. Same as Method
ISA or 13BDetermination of total fluoride
emissions from stallonary sources
5 4 Analysis, Same as Method 13A or 13B
Determination of total fluoride emissions
from stationary sources.
6 Calculations
6 1 Isokinetic sampling test. Calculate the
mean velocity measured during each sam-
pling run by the anemometer in the section
of the roof monitor coiilaining the sampling
manifold If the mean velocity recorded dur-
ing a particular test run does not fall within
±20 percent of the mean velocity established
according to 5 3 2, repeat the run.
6 2 Average velocity of roof monitor gases.
Calculate the average roof monitor velocity
using all the velocity or volumetric flow read-
ings from section 512.
6 3 Roof monitor temperature Calculate
the mean value of the temperatures recorded
In section 5 2
6 4 Concentration of fluorides in roof moni-
tor air in mg F/m This is given by Equation
13A-5 in Method 13ADetermination of
total fluoride emissions from stationary
sources
6 5 Average volumetric flow from roof is
given by Equation 14-2
__ V,,t (A} (Ma) Pm (294'K)
~(T,,, 4-273°) (760mmHg)
where
Qm average volumetric flow from rool
monitor at standard conditions on
a dry basis, mVmin.
^4-^roof monitor open area, m'-.
Vmf = average velocity of air in the roof
monitor, meters/minute from sec-
tion 6 2
Pm atmospheric pressure, mm Hg
Tr,,roof monitor temperature, °C, from
section 6 3
Ma = mole fraction of dry gas, which Is
^ , 100-100 (Bv,,)
given by M>=
B«.»=ris the proportion by volume of water
vapor in the gas stream, from
Equation 13A-3, Method 13ADe-
termination of total fluoride emis-
sions from stationary sources
[Sections 111 and 114 of the Clean Air Act, as
amended by section 4(a) of Pub. L. 91-604, 84
Stat. 1678 (42US.C. 1857C-6, c-9) ].
[FR Doc.76-2133 Filed 1-23-76:8:45 am]
FEDERAL REGISTER, VOL. 41. NO. 17MONDAY. JANUARY 26, 1976
IV-137
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28
Title 40Protection of Environment
CHAPTER IENVIRONMENTAL
PROTECTION AGENCY
RULES AND REGULATIONS 29
[FRL 483-7]
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Delegation of Authority to Washington
Local Agencies
Pursuant to s;ectlon 111 (c) of the Clean
Air Act, as amended, the Regional Ad-
ministrator of Region X, Environmental
Protection Agency (EPA), delegated to
the State of Washington Department of
Ecology on February 28, 1975, the au-
thority to Implement and enforce the
program for standards of performance
for new stationary sources (NSPS). The
delegation was announced In the FED-
ERAL REGISTER on April 1, 1975 (40 PR
14632). On April 25, 1975 (40 PR 18169)
the Assistant Administrator for Air and
Waste Management promulgated a
change to 40 CFR 60.4, Address to re-
flect the delegation to the State of
Washington.
On September 30 and October 8 and 9,
1975, the State Department of Ecology
requested EPA's concurrence In the
State's sub-delegation of the NSFS pro-
gram to four local air pollution control
agencies. After reviewing the State's re-
quest, the Regional Administrator de-
termined that the subdelegations meet
all the requirements outlined In EPA's
delegation of February 28, 1975. There-
fore, the Regional Administrator on De-
cember 5, 1975, concurred In the sub-
delegations to the four local agencies
listed below with the stipulation that all
the conditions placed on the original
delegation to the State shall also apply to
the sub-delegations to the local agencies.
EPA is today amending 40 CFR 60.4 to
reflect the State's sub-delegations.
The amended I 60.4 provides that all
reports, requests, applications, submlttals
and communications required pursuant
to Part 60 which were previously to be
sent to the Director of the State of Wash-
ington Department of Ecology (DOE)
will now be sent to the Puget Sound Air
Pollution Control Agency (PSAPCA), the
Northwest Air Pollution Authority (NW
APA), the Spokane County Air Pollution
Authority (SCAPA) or the Southwest Air
Pollution Control Authority (SAPCA) as
appropriate. The amended section Is set
forth below.
The Administrator finds good cause for
foregoing prior public notice and for
making this rulemaking effective im-
mediately in that It is an administrative
change and not one of substantive con-
tent. No additional substantive burdens
are imposed on the parties affected. The
delegations which are reflected by the
administrative amendment were effective
on September 30 to the NWAPA, October
7 to the PSAPCA and October 8 to the
SCAPA and the SAPCA, and it serves no
useful purpose to delay the technical
change of the addition of the local agency
addresses to the Code of Federal Regu-
lations.
This rulemaking is effective immedi-
ately, and is issued under the authority
of Section 111 of the Clean Air Act, as
amended. 42 U.S.C. 1857c-6.
Dated: January 24,1976.
STANLEY W. LEGRO,
Assistant Administrator
for Enforcement.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amended
as follows:
1. In 5 60.4, paragraph (b) is amended
by revising subparagraph (WW) to read
as follows:
§ 60. V AddrP-s.
* * * t »
(b) * * *
(WW) (1) Washington; Slate of Washing-
ton, Department of Ecology, Olympia, Wash-
ington 98504.
(11) Northwest Air Pollution Authority, 207
Pioneer Building, Second and Pine Streets,
Mount Vernon, Washington 98273.
(Ill) Puget Sound Air Pollution Control
Agency, 410 West Harrison Street, Seattle,
Washington 98119.
(Iv) Spokane County Air Pollution Control
Authority, North 811 Jefferson, Spokane,
Washington 99201.
(v) Southwest Air Pollution Control Au-
thortty, Suite 7601 H, NE Hnzel Dell Avenue,
Vancouver, Washington 98665,
* *
(FRDoc.76-2673 Filed l-28-76;8'45 am)
FEDERAL REGISTER, VOL. 41, NO. 20-
-THURSDAY, JANUARY 29, 1976
Title 40Protection of Environment
[FBI. 492-3]
CHAPTER 1ENVIRONMENTAL
PROTECTION AGENCY
SUBCHAPTER CAIR PROGRAMS
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Delegation of Authority to State of Oregon
Pursuant to the delegation of author-
ity for the standards of performance for
new stationary sources (NSPS) to the
State of Oregon on November 10, 197S>,
EPA is toda5r amending 40 CFR 60.4,
Address, to reflect tills delegation. A Nc-
tice announcing this delegation is pub-
lished today at 41 PR 7750 in the
FEDERAL REGISTER. The amended § 60 4
which adds the address of the State of
Oregon Department of Environmental
QuaJity to which all reports, requests,
applications, submittals, and communi-
cations pursuant to this part must be
addressed, is set forth below.
The Admin tstrator finds good cause for
foregoing pr.or public notice and for
making this rulemaking effective imme-
diately in that it is an administrative
change and not one of substantive con-
tent. No additional substantive burdens
are imposed on the parties affected. The
delegation which is reflected by this ad-
ministrative amendment was effective on
November 10, 1975 and it serves no pur-
pose to delay the technical change of
this addition of the State address to the
Code of Federal Regulations.
This rulemaking is effective immedi-
ately, and is Issued under the authority
of Section 111 of the Clean Air Act, as
amended. 42 U.S.C. 1857C-6.
Dated- February 11,1976.
STANLEY W. LEGRO,
Assistant Administrator for
Enforcement.
Part 60 of Chapter I, Title 40 of t':ie
Code of Federal Regulations is amended
as follows:
1. In § 60.4 paragraph (b) is amended
by revising subparagraph (MM) to read
as follows:
§ 60.4 Address.
*****
(b) *
(A)-(LL) * ' *
(MM)State of Oregon, Department
of Environmental Quality, 1234 SW
Morrison Street, Portland, Oregon 97205.
|FRDoc.76-4964 Piled 2-19-76:8:46 am]
FEDERAL REGISTER, VOL. 41, NO, 35-
-FRIDAY, FEBRUARY 20, 1976
IV-138
-------
RULES AND REGULATIONS
30
Title 40Protection of Environment
(FRL 494-3]
CHAPTER IENVIRONMENTAL
PROTECTION AGENCY
SUBCHAPTER CAIR PROGRAMS
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Primary Copper, Zinc, and Lead Smelters;
Correction
In FR Doc. 76-733 appearing at page
2331 in the FEDERAL REGISTER of January
15, 1976, the ninth line of paragraph (a)
in $ 60.165 is corrected to read as follows:
"total smelter charge and the weight."
Dated: February 20, 1976.
ROGER STRELON.
Assistant Administrator
lor Air and Waste Management.
|FR Doc.76-5398 Filed 2 25-76:8'45 nm\
(FRL 495-4|
PART 60STANDARDS OF PERFORMANCE
FOR NEW STATIONARY SOURCES
Delegation of Authority to Commonwealth
of Virginia
Pursuant to the delegation of authority
for the standards of performance for
new stationary sources (NSPS) to the
Commonwealth of Virginia on December
30, 1975, EPA is today amending 40 CFR
60.4, Address, to reflect this delegation.
A Notice announcing this delegation is
published today at 41 FR 8416 in the
FEDERAL REGISTER. The amended § 60.4,
which adds the address of the Virginia
State Air Pollution Control Board to
which all reports, requests, applications,
submittals, and communications to the
Administrator pursuant to this part must
also be addressed, is set forth below.
The Administrator finds good cause for
foregoing prior public notice and for
making this rulemaking effective im-
mediately in that it is ap administrative
change and not one of .substantive con-
tent). No additional substantive burdens
are imposed on the parties affected. The
delegation which is reflected by this ad-
ministrative amendment was effective on
December 30, 1975, and it &eive.s no pur-
pose to delay the technical change of this
addition of the State address to the Code
of Federal Regulations.
This rulemaking Is effective immedi-
ately, and is issued under Uie authority of
section 111 of the Clean Air Art. as
amended. 42 U.S.C. 1857c-6.
42 U.S.C. 1857C-6.
Dated: February 21, 1916
STANLEY W. Ijrx.T.o.
Assistant Administrator
for Enforcement.
Part 60 of -Chapter I, Title 40 of the
Code of Federal Regulations Is amended
as follows:
1. In § 6D.4, paragraph (b) is amended
by revising subparagraph (W) to read
as follows:
§ 60.4 Address.
'A)-(UU) * * *
(VV) Commonwealth of -Virginia. Vir-
ginia State Air Pollution Control Board,
Room 1106, Ninth Street Office Building,
Richmond, Virginia 23219.
|FR Doc.76-5504 Filed 2-25-76:8-45 am |
FEDERAL REGISTER, VOL. 41, NO. 39-
-1HURSDAY. FEBRUARY 26, 1976
(H) State of Connecticut, Department
of Environmental Protection, State Of-
fice Building, Hartford, Connecticut
06115.
« «
[PE Doc.76-7967 Filed 3-19-76; 8:45 am]
32
31
SUBCHAPTER CAIR PROGRAMS
[FRL 507-1]
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCE
Delegation of Authority to State of
Connecticut
Pursuant to the delegation of authority
for the standards of performance for new
stationary sources (NSPS) to the State
of Connecticut on December 9,1975, EPA
Is today amending 40 CFR 60.4, Address,
to reflect this delegation. A Notice an-
nouncing this delegation is published to-
day at (41 FR 11874) in the FEDERAL REG-
ISTER. The amended § 00.4, which adds
the address of the Connecticut Depart-
ment of Environmental Protection to
which all reports, requests, applications,
submittals. and communications to the
Administrator pursuant to this part must
also be addressed, is set forth below.
The Administrator finds good cause
for foregoing prior public notice and for
making this rulemaking effective imme-
diately in that It is an administrative
change and not one of substantive con-
tent. No additional substantive burdens
are Imposed on the parties affected. The
delegation which Is reflected by this ad-
ministrative amendment was effective on
December 9, 1975. and it serves no pur-
pose to delay the technical change of this
addition to the State address to the Code
of Federal Regulations.
This rulemaking is effective immedi-
ately, and is Issued under the authority
of section 111 of the Clean Air Act, as
amended.
(42 TJB.C. 1857C-8)
Dated: March 15,1976.
STAKLET W. LEGRO,
Assistant Administrator
/or Enforcement.
FEDERAL REGISTER, VOL. 41, NO. 56-
-MONDAY, MARCH 22, J976
Title 40Protection of Environment
CHAPTER [ENVIRONMENTAL
PROTECTION AGENCY
[FBL 529-3)
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCE
Delegation of Authority to State of
South Dakota
Pursuant to the delegation of author-
ity for the standards of performance for
new stationary sources (NSPS) to the
State of South Dakota on March 25, 1976,
EPA is today amending 40 CPU 60.4, Ad-
dress, to reflect this delegation. A Notice
announcing this delegation is published
today at 41 FR 17600. The amended
5 60.4, which adds the address of Depart-
ment of Environmental Protection to
which all reports, requests, applications,
submittals, and communications to the
Administrator pursuant to this part must
also be addressed, is set forth below.
The Administrator finds good cause for
foregoing prior public notice and for
making this rulemaking effective imme-
diately in that it is an administrative
change and not one of substantive con-
tent. No additional substantive "burdens
are imposed on the parties affected. The
delegation which is reflected by this ad-
ministrative amendment was effective on
March 25, 1976, and it serves no purpose
to delay the technical change of this ad-
dition of the State address to the Code of
Federal Regulations.
This rulemaking is effective immedi-
ately, and is issued under the authority
of Section 111 of the Clean Air Act, as
amended.
42 U.S.C. 1857C-6.
Date: April 20, 1976.
STANLEY W. LEGRO,
Assistant Administrator
for Enforcement.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amended
as follows:
1. In § 60.4 paragraph (b) is amended
by revising subparagraph QQ to read as
follows:
Part 60 of Chapter I, Title 40 of the § 60.4 Address.
Code of Federal Regulations is amended « «
as follows:
1. In § 60.4 paragraph (b) is amended
by revising subparagraph (H) to read as
follows:
§ 60.4 Address.
* *
(b) *
(b) * *
(A)-(Z) «
(AA)-(PP)
(QQ) State of South Dakota, Depart-
ment of Environmental Protection, Joe
Foss Building, Pierre, South Dakota
57501.
FEDERAL REGISTER, VOL 41, NO. 82-
TUESDAY, APRIl 27, 1976
IV-139
-------
18498
33
Title 40Protection of Environment
CHAPTER IENVIRONMENTAL
PROTECTION AGENCY
[PBL 509-3]
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Ferroalloy Production FacPties
On October 21, 1974 (39 FR 37470).
under section 111 of the Clean Air Act,
as amended, the Environmental Protec-
tion Agency (EPA) proposed standards of
performance for new and modified fer-
roalloy production facilities. Interested
persons participated In the rulemaking
by submitting comments to EPA. The
comments have been carefully consid-
ered, arc1 where determined by the Ad-
ministrator to be appropriate, changes
have been made to the regulations as
promulgated.
The standards limit emissions of par-
ticulate matter and carbon monoxide
from ferroalloy electric submersed arc
furnaces. The purpose of the standards is
to require effective capture and control
of emissions from the furnace and tap-
ping station by application of best sys-
tems of emission reduction. For ferro-
alloy furnaces the best system of emis-
sion reduction for participate matter Is
a well-designed hood in combination
with a fabric filter collector or venturl
scrubber. For some alloys the best system
Is an electrostatic precipitator preceded
by wet gas conditioning or a venturi
scrubber. The standard for carbon mon-
oxide reouires only that the gas stream be
flared or combusted in some other
manner.
The environmental Impact of these
standards Is beneficial since the increase
in emissions due to growth of the In-
dustry will be minimized. Also, the stand-
ards will remove the incentive for plants
to locate in areas with less stringent
regulations.
Upon evaluation of the costs asso-
ciated with the standards and their eco-
nomic impact, EPA concluded that the
costs are reasonable and should not bar
entry into the market or expansion of
facilities. Tn addition, the standards will
require at most a minimal increase )n
power consumption over that required to
comply with the restrictions of most
State regulations.
SUMMARY OF REGULATION
The promulgated standards limit par-
tlcula.te matter and carbon monoxide
emissions from the electric submerged
arc furnace and limit participate matter
emissions from dust-handling equip-
ment. Emissions of participate matter
from the control device are limited to
less than 0.45 kg/MW-hr (0.99 Ib/MW-
hr) for furnaces producing high-silicon
alloys (In general) and to less than 0.23
kg/MW-hr (0.51 Ib/MW-hr) for fur-
naces producing chrome and manganese
alloys. For both product groups, emis-
sions from the control device must be
less than 15 percent opacity. The regu-
lation requires that the collection hoods
capture all emissions generated within
the furnace and capture all tapping emis-
sions for at least 60 percent of the tap-
RULES AND REGULATIONS
ping time. The concentration of carbon
monoxide in any gas stream discharged
to the atmosphere must be less than 20
volume percent. Emissions from dust-
handling equipment may not equal or ex-
ceed 10 percent opacity. Any owner or
operator of a facility subject to this regu-
lation must continuously monitor volu-
metric flow rates through the collection
system and must continuously monitor
the opacity of emissions from the control
device.
SUMMARY OP COMMENTS
Eighteen comment letters were re-
ceived on the proposed standards of per-
formance. Copies of the comment letters
and a report which contains a summary
of the issues and EPA's responses are
available for public inspection and copy-
ing at the U.S. Environmental Protec-
tion Agency, Public Information Refer-
ence Unit (EPA Library), Room 2922,
401 M Street, S.W., Washington, D.C.
Copies of the report also may be ob-
tained upon written request froia the
EPA Public Information Center (PM-
215), 401 M Street, S.W., Washington,
D.C. 20460 (specifySupplemental In-
formation on Standards of Performance
for Ferroalloy Production Facilities). In
addition to the summary of the issues
and EPA's responses, the report contains
a reevaluation of the opacity standard
in light of revisions to Reference Method
9 which were published in the FEDERAL
REGISTER November 12, 1974 (39 FR
39872).
The bases for the proposed standards
are presented in "Background Informa-
tion for Standards of Performance: Elec-
tric Submerged Arc Furnaces for Pro-
duction of Ferroalloys" (EPA 450/2-74-
018a, b). Copies of this document are
available on request from the Emission
Standards and Engineering Division,
Environmental Protection Agency, Re-
search Trlanele Park, North Carolina
27711, Attention: Mr. Don R. Goodwin.
SIGNIFICANT COMMENTS AND CHANGES TO
THE PROPOSED REGULATION
Most of the comment letters contained
multiple comments. The more significant
comments and the differences between
the proposed and the final regulations
are discussed below. In addition to the
discussed changes, several paragraphs
were reworded and some sections were
reorganized.
(1) Mass standard. Several commen-
ters questioned the representativeness of the
data used to demonstrate the achievabll-
Ity of the^0.23 kg/MW-hr (0.51 Ib/MW-
hr) standard proposed for facilities pro-
ducing chreme and manganese alloys.
Specifically, the commenters were con-
cerned that sampling only a limited num-
ber of compartments or control devices
serving a furnace, nonisokinetic sam-
pling of some facilities, and the proce-
dures used to determine the total gas
volume flow from open fabric filter col-
lectors would Bias the data low. For these
reasons, the commenters argued that the
standard should be 0.45 kg/MW-hr (0.99
Ib/MW-hr) for all alloys. As additional
support for their position, they claimed
that control equipment vendors will not
guarantee that their equipment will
achieve 0.23 kg/MW-hr (0.51 Ib/MW-
hr). 35
Because of these comments, EPA
thoroughly reevaluated the bases for the
two mass standards of performance and
concluded that the standards are achiev-
able by best systems of emission reduc-
tion. For open ferroalloy electric sub-
merged arc furnaces, the best system of
emission reduction is a well-designed
canopy hood that minimizes the volume
of induced rir and a well-designed and
properly operated fabric filter collector
or high-energy venturi scrubber. In a
few cases, an electrostatic precipitator
preceded by a venturi scrubber or wet
gas conditioning is a bsst system. In
EPA's opinion, revising the standard up-
ward to 0.45 kg/MW-hr (0.99 Ib/MW-hr)
would allow instpirticn of systems other
than the best. Therefore, the promul-
gated standard of performance for fur-
naces producing chrome and manganese
alloys is 0.23 kg/MW-hr (0.51 Ib/MW-
hr) . The standard for furnaces produc-
ing the specified high-silicon alloys is
0.45 kg/MW-hr O.99 Ib/MW-hr). The
rationale for establishing the standards
at these levels is summarized below.
The reevaluation of the data bases for
the standards showed that the emission
test procedures ured did not significantly
bias the results. Therefore, contrary U>
the commenter's concerns, the proce-
dures did not result in emission limita-
tions lower than those achievable by best
systems of emission reduction. The de-
viations and assumntions made in the
test procedures w?re trased on considera-
tion of the particle size of the emissions,
an evaluation of the performance of the
control systems, and factors affecting the
induction of air into open fabric filter
collectors.
EPA tests, and allows testing of, a rep-
resentative number of stacks or compart-
ments in a control device because sub-
sections of a well-designed and properly
operating control device will perform
equivalently. Evaluation of the control
system and the condition of the control
device by EPA engineers at the time of
the emission test showed that sections
not tested were of equivalent design and
In operating condition equivalent to or
better than the tested sections. Thus, the
performance of the non-tested portions
of the control device are considered to be
equivalent to or better th«n the per-
formance of the sections emission tested.
In addition, the particle size of emissions
from well-controlled ferroalloy furnaces
was investigated bv EPA and was found
to consist of parti 'les of less than two
micrometers aerodynamic diameter for
all alloys. The mass and, hence, inertia
of these particles are negligible; there-
fore, they follow the motion of the gas
streahi. For emissions of this size distri-
bution, concentrations determined by
nonisokinetic sampling would not be sig-
nificantly different than those measured
by isoklnetic s"mpling.
EPA determined the total gas volume
flow rate from the open fabric filter col-
lectors by measuring the inlet volume
flow rate and the volume-of air induced
into the collector. The inlet gas volumes
FEDERAL REGISTER, VOL, 41, NO. 67TUESDAY, MAY 4, 1976
-------
RULES AND REGUTATTONS
18499
to the collectors were measured during
each run of each test; but the volume
of air Induced Into the collector was de-
termined once during the emission test.
The total gas volume flow from the col-
lector was calculated as the sum of the
inlet gas volume and the induced air vol-
ume. Although the procedures used were
not ideal, the reported gas volumes are
considered to be rersonably representa-
tive of the total gas volumes from the
facility. This conclusion is based on the
fact that the quantity of air induced
around the bags in an open collector is
primarily dependent on the open area
and the temperature of the inlet gas
stream and the ambient air. Therefore,
equivalent air volumes are drawn into the
collector under similar meteorological
and inlet gas conditions. During the pe-
riods of emission testing at the facilities,
meteorological conditions were uniform
and the volume of induced air was ex-
pected to be constant. Consequently,
measurement of the induced air volume
once during the emission test was ex-
pected to be sufficient for calculating the
total gas volume flow from the collector.
Since conducting the test in question,
EPA has gained rdditional experience
and has concluded that in general it is
preferable to measure the total gas vol-
ume flow during each run of a perform-
ance test. This conclusion, however,
does not invalidate the use of the test
data obtained by the less optimum pro-
cedure of a single .determination of in-
duced air volume. EPA evaluated pos-
sibjie variations in the amount of air in-
duced into the collector by performing
enthalpy balances using reported tem-
perature data. The Induced air volumes
were calculated assuming adiabatic mix-
Ing (no heat transfer by inlet gases to
collector) and, hence, are conservatively
high estimates. The calculated induced
air volumes did differ from the single
measured values; however, the effect on
the mass emission rate for the collectors
was not significant. EPA. therefore, con-
cluded that the use of single measure-
ments of the induced air volume did not
affect the level of the standards.
Another Issue of concern to com-
menters is the reluctance of control
equipment vendors to guarantee reduc-
tion of emissions to less than 0.23 kg/
MW-hr (0.51 lb/MW-hr>. It is EPA's
opinion that this reluctance does not
demonstrate the unachievability of the
standard. The vendors' reluctance to
guarantee this level is not surprising con-
sidering the variables which are beyond
their control. Specific?lly, they rarely
have any control over the design of the
fume collection systems for the furnace
and tapping station. Fabric filter collec-
tors tend to control the concentration of
participate matter in the effluent The
mass rate of emissions from the collec-
tor Is determined by the total volumetric
flow rate from the control device, which
is not determined by vendors. Further,
because of limited experience with emis-
sion testing to evaluate the performance
of open fabric filter collectors, vendors
cannot effectlvelr evaluate the perform-
ance of these systems over the guarantee
period. For vendors, establishment of the,
performance guarantes level is also com-
plicated by the fact that the performance
of the collector is contingent upon its
beinj properly operated and maintained.
Standards of performance are neces-
sarily based on data from a limited
number of best-controlled facilities and
on engineering- judgments regarding
performance of the control systems. For
this reason, there is a possibility of ar-
riving at different conclusions regarding
the performance capabilities of these
systems. Consequently, the question of
vendors' reluctance to guarantee their
equipment to achieve 0.23 kg/MW-hr
(0.51 lb/MW-hr> was considered along
with the results of additional recent
emission tests on fabric filter collectors.
Recognizing that the data base for the
standards was limited and that a num-
ber of well-controlled facilities had
started operation since completion of the
original study, EPA obtained additional
data to better evaluate the performance
of emission control systems of interest.
Under the authority of section 114 of
the Clean Air Act, EPA requested copies
of all emission data for well-controlled
furnaces operated by 10 ferroalloy pro-
ducers. Data were received for five well-
controlled facilities. In general, theie
facilities had close fitting water cooled
canopy hoods, and tapping fumes were
collected and sent to the control device
along with the furnace emissions.
The emission data submitted by the
industry show that properly operating
compartments bf open fabric filter col-
lectors have effluent concentrations of
less than 0.009 g/dscm (0.004 gr/dscf).
For these recently constructed facilities,
the reported mass emission rates were
less than 0.12 kg/MW-hr (0.24 Ib/Mw-
hr) for 15 MW capacity silicon metal
furnaces. Evaluation of possible errors
in the data and uncertainties in the test
procedures showed that emissions may
have been as high as 0.20 kg/MW-hr
(0.45 Ib/MW-hr) in some cases. These
emission rates were achieved by desien
of the collection hood to minimize the
quantity of induced air. The data sub-
mitted by the industry showed that gas
volumes from well-hooded large silicon
metal furnaces can be reduced to 50 per-
cent of the volumes from typically hood-
ed large silicon furnaces. Based on the
data obtained from the industry, a large
well-hooded and well-controlled silicon
metal furnace is expected to have an
emission rate of less than 0.45 kg/MW-
hr (0.991b/MW-hr).
In EPA's study of the ferroalloy In-
dustry, it was determined that emissions
from production of high-siligon alloys
would be more difficult to control than
chrome and manganese emissions due
to the finer size distribution of the par-
ticles and significantly larger gas vol-
umes from the furnace. Comparison of
the gas volumes reported by the industry
from silicon metal production with gas
volumes from typically hooded furnaces
producing chrome and manganese alloys
shows that the original conclusion Is
still valid. Due to the lower gas volumes
associated with their production, a low-
er mass emission rate is still expected for
chrome and manganese alloys. In addi-
tion, EPA emission tests in the original
study on a-number of tightly hooded
open furnaces demonstrated emissions
can be controlled to less than 0.23 kg/
MW-hr (0.51 Ib/MW-hr). Emissions
were reduced to these levels by control
of induced air volumes and by use of a
well-designed and properly operated
fabric filter collector or venturi scrub-
ber.
Just before promulgation of the
standard?, me-nbers of the Ferroalloy
Association informed EPA that future
supplies of chrome and manganese ores
v il1 be fr^er and more friable than those
in use during development of the stand-
ard. The industry representatives
claimed that use of finer ores will affect
furnace operations and prevent new fur-
naces from complying with the 0.23 kg/
MW-hr (0.51 Ib/MW-hr) standard. Al-
though the representatives submitted
statements concerning the effect of finer
ores on furnace operating conditions, no
data were provided to show the effect of
ore Fi?c -on emissions. CPA evaluated the
material submitted and concluded that
funvce operating rrob'ems associated
with use of fire ores can be contro'led by
operation and mrintenance procedure-;.
With r roper operation of- the furnace, usre
of fner onr? rhou'd not affect the achier-
ability of the standard, and relaxation
of tho 0.23 kg/MW-hr (0.51 Ib/MW-hr)'
standard is not justified. This evaluation
is discussed in detail in Chapter II of the
supplements! information document. If
and when factual information is pre-
sented to EPA which clearly demon-
strates that use of finer chrome and
manganese ores does prevent a propcr'y
operated new furnace, which Is equipped
with the best demonstrated system of
emission reduction (considering costs),
from meeting the 0.23 kg/MW-hr (0.51
Ib/MW-hr) standard, EPA will propose a
revisinn to the standard. The best system
of e"ni?
-------
18500
RULES AND REGULATIONS
device to less than 20 percent has been
revised in the regulation promulgated
herein to require that emissions be less
than 15 percent opacity in order to retain
the intended level of control.
(3) Control system capture require-
ments. Ten commenters criticized fume
capture requirements for the furnace and
tapping station control systems on two
basic points. The arguments were: <1)
EPA lacks the statutory authority -to
regulate emissions within the building,
nnd (2) the standards are not technical-
ly feasible at all times.
EPA has the statutory authority un-
der section 111 of the Act to regulate any
new stationary source which "emits or
may emit any air pollutant." EPA does
not agre.i with the opinion of the com-
menters that section 111 of the Act ex-
pressly or implicitly limits the Agency to
regulation only of pollutants which are
emitted directly into the atmosphere.
Particulate matter emissions escaping
capture by the furnace control cy~tem
ultimately will be discharged to the at-
mosphere outside of the shop; therefore,
they may be regulated under section 111
of the Act. Standards which regulate
pollutants at the point of emission inside
the building allow assessment of the con-
trol system without interference from
nonregulated sources located in the same
building. In addition, by requiring evalu-
ation of emissions before their dilution,
the standards will resuU in better con-
trol of the furnnce emissions and will
regulate affected ferroalloy fac'Ht'PS
more uniformly than would standards
limiting emissions from the shop.
EPA believes the standards on the fur-
nace and tapping station collection
hoods are achievable because the stand-
ards are based on observations of normal
operations at well-controlled facilities.
The commenters who argued that the
standards are not technically feasible at
all times cited examples of abnormal op-
erations which would preclude achiev-
ing the standards. For examnle, several
commenters cited the fact that violent
reactions due to im'ia'ances in the alloy
chemistry occasionally can generate more
emissions than the hood was designed to
capture. If the capture system is well-
designed, well-maintained, and properly
operated, only failures of the process to
operate in the normal or usual manner
would cause the capacity of the system to
be exceeded. Such operating perio-ls are
malfunctions, and, therefore, compliance
with the standards of performance
would not be determined during these
periods. Performance tests under 40 CFR
60.8(c) are conducted only during rep-
resentative conditions, and periods of
start-up, shutdown, and malfunctions
are not considered representative condi-
tions.
Five commenters discussed other op-
erating conditions which they believed
would preclude a source from complying
with the tapping station standard. These
conditions Included blowing taps, period
of poling the tarhole, and periods of re-
moval of metal and slag from the spout.
The commenters argued that blowing
taps should be exempted from the stand-
ard and the tapping station standard
should be replaced with an opacity
standard or emissions from the shop. The
comments \.ero revi:wed and EPA con-
cluded that exemption of blowing taps la
justified. The regulation promulgated
herein exempts blowing taps from the
tr.p: ing station standard and Includes.a
definition of blowing tap. EPA believes
that conditions which result in plugging
of th-3 ta^hol? and mctni in the spout are
malfunctions because they are unavoid-
able failures of the process to operate
in the normal or usual manner. Discus-
sions with experts In the ferroalloy in-
dustry, revealed that these conditions are
not predictable conditions for which a
preventative maintenance or operation
program could be established. As mal-
function?, rh~f p"viod': are not subject
to the standards, and a performance test
would not be conducted during such
periods. Therefore, the suggested revision
to the standard to exempt these periods
Is not necessary because of the existing
provisions of 40 CFR 60 8(c) and 60.11.
In EPA's judgment, both the furnace and
tapping station standards are achievable
for all normal process operations at fa-
cilities with well-designed, well-main-
tain^) a-d ^ro^pily operated emission
collection systems.
Th° promulgated regulation retains
the proposed fume capture requirements,
but the regulation has been revised to
be more enforceable than the proposed
capture requirements, which could have
been enforced only on an infrequent
basis. The regulation has been reorga-
nized to clarify that unlike the opacity
standards, the collection system capture
requirements (visible emission limita-
tions) are subject to demonstration of
compliance during the performance test.
To provide a means for routine enforce-
ment of the capture requirements, con-
tinuous monitoring of the volumetric
flow rate(s) through the collection sys-
tem Is required for each affected fur-
nace. An owner or operator may comply
with this requirement either by install-
ing a flow rate monitoring device in an
appropriate location in the exhaust duct
or by calculating the flow rate through
the system from fan operating data. Dur-
ing the performance test, the baseline
operating flow rate(s) will be established
for the affected electric submerged arc
furnace. The regulation establishes emis-
sion capture standards which are appli-
cable only during the performance test
of the affected facility. At all other times,
the operating volumetric flow rate(s)
shall be maintained at or greater than
the established baseline values for the
furnace load. Use of lower volumetric
flow rates than the established values
constitutes unacceptable operation and
maintenance of the affected facility.
These provisions of the promulgated
regulation will ensure continuous mon-
itoring of the operations of the emission
capture system and will simplify enforce-
ment of the emission capture require-
ments.
The requirements for monitoring volu-
metric flow rates will add negligible ad-
ditional costs to the total costs of
complying with the standards of per-
formance. Flow rate monitoring devices
of sufficient accuracy to meet the re-
quirements of I (»0.265(c) can be installed
for $600-$4000 depending on the flow
profile of the area being monitored and
the complexity of the monitoring device.
A suitable stiip chsrt recorder can be
installed for less than $600, The alter-
native provisions allowing calculation of
the volumetric flow rate(s) through the
control system from continuous monitor-
ing of fan operatiDns will result in no
additional costs because the Industry
presently monitors fan operations.
(4) Monitoring of operations. The
promulgated regulation requires report-
ing to the Administrator any product
changes that wiU result in a change in
the applicable standard of performance
for the affected electric submerged arc
furnace. This requirement is necessary
because electric submerged arc furnaces
may be converted to production of alloys
other than the original design alloys by
physical alterations to the furnace.
changes to the electrode spacing,
changes In the transformer capacity, and
changes in the materials charged to the
furnace. Thus, the emission rate from
the electric submerged arc furnace and
the standard of performance (which is
dependent on the alloy produced) may
change during the lifetime of the facil-
ity. Conversion of the furnace to pro-
duction of alloys with significantly dif-
ferent emission rates, such as changes
between the product grouos for the two
standards, may result in the facility ex-
ceeding the applicable standard. Conse-
quently, the reporting requirement was
added to ensure continued compliance
with the applicable standards of per-
formance. These re-orts of product
changes will afford the Administrator an
opportunity to determine whether a per-
formance test should be conducted and
will simplify enforcement of the regu-
lation. As with the requirements appli-
cable under the proposed regulation, the
performance te.ct still must be conducted
while the electric submerged arc furnace
is producing the design alloy whose emis-
sions are the most difficult to control of
the product family. Subsequent product
changes within the product family will
not cause the facility to exceed the stand-
ard.
(5) Test methods and procedures. Sec-
tion 60.266(d) of the promulgated regu-
lation requires the owner or operator to
design and construct the control device
to allow measurement of emissions and
flow rates using applicable test methods
and procedures. This provision permits
the use of open pressurized fabric filter
collectors (arid other control devices)
whose emissions cannot be measured ty
reference methods currently in Appendix
A to this part, if compliance with the
promulgated standard can be demon-
strated by an alternative procedure. EPA
has not specified a single test procedure
for emission testing of open pressurized
fabric filter collectors because of the
large variations in the design of thei>e
collectors. Test procedures can be de-
veloped on a case-by-case basis, however.
Provisions in 40 CFR 60.8(b) allow the
owner or operator upon approval by the
Administrator to use an "alternative" i>r
FEDERAL REGISTER, VOL. 41, NO. 87TUESDAY, MAY 4, 1974
IV-142
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RULES AND REGULATIONS
18501
"equivalent" test procedure to rhow com-
pliance with the. standards. EPA would
like to emphasize that development of
the "alternative" or "equivalent" test
procedure is the responsibility of any
owner or operator who elects to use a
control device not amenable to testing by
Method 5 of Appendix A to this part. The
procedures of an "alternative" test
method for demonstration of compliance
are dependent on specific design features
and condition of the collector and the
capabilities of the sampling equipment.
Consequently, procedures acceptable for
demonstration of compliance will vary
with specific situations. General guid-
ance on possitle approaches to sampling
of emissions from pre-surized fabric filter
collectors is provided in Chapter IV of
the supplemental information document.
Di e to the costs of testing, the owner
or operator should obtain EPA approval
for a specific test procedure or other
means for determining compliance be-
fore construction of a new source. Under
the provisions of § 60 6, the owner or
operator of a new facility may request
review of the acceptability of proposed
plans for construction and testing of con-
trol systems which are not amenable to
sampling by Reference Method 5. If an
acceptable "alternative" test procedure is
not developed by the owner or operator,
then total enclosure of the pressurized
fabric filter collector and testing by
Method 5 is required.
Effective date. In accordance with sec-
tion 111 of the Act. these regulations
prescribing standards of performance for
ferroalloy production facilities are effec-
tive May 4, 1976, and apply to electric
submerged arc furnaces and their asso-
ciated dust-handling equipment, the
construction or modilcation of which
was commenced after October 21, 1974.
(Sees. Ill and 114 of the Clean Air Act,
amended by Sec. 4(a) of Pub. L. 91-604, 84
Stat. 1678 (42 U.S.C. 1857C-6, 1867C-9).)
Dated: April 23,1976.
RUSSELL E. TRAIN,
Administrator.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amended
as follows:
1. The table of sections is amended by
adding subpart Z as follows:
Subpart ZStandards of Performance for Ferro-
alloy Product on Facil t.es
Sec.
60.260 Applicability and designation of
affected facility.
60.261 Definitions.
60.262 Standard for participate matter.
60.263 Standard for carbon monoxide,
60.264 Emission monitoring.
60.265 Monitoring of operations.
60.266 Test methods and procedures.
2. Part 60 is amended by adding sub-
part Z as follows:
Subpart 7Standards of Performance for
Ferroalloy Pro Juction
§ 60.260 Applicability and designation
of affected fucilitj.
The provisions of this subpart are ap-
plicable to the following affected facili-
ties: Electric submerged arc furnaces
which produce silicon metal, ferrosillcon,
calcium silicon, sllicomanganese zirco-
nium, ferrochrome silicon, silvery iron,
nich-carbon ferrochrome, charge chrome
standard ferromanganese, silimanga-
nese, ferrcmanganese silicon, or caloium
carbide; and dust-handling cquipm3nt.
§60.261 Definitions.
As used in this subpart, all terms not
defined herein shall have the meaning
given them in the Act and in subpart A
of this part.
(a) "Electric submerged arc furnace"
means any furnace wherein electrical
energy is converted to heat energy by
transmission of current between elec-
trodes partially submerged in the furnace
charge.
(b) "Furnace charge" me?ns any ma-
terial introduced into the electric.sub-
merged arc furnace and may consist of,
but is not limited to, eras, slag, carbo-
naceous mateiial, and limestone.
(c) "Product change" means any
change in the composition of ths furnace
charge that would cause the electric sub-
merged arc furnace to become subject
to a different nass standard applicable
under this subpart.
"Furnace power input" means the
resistive electrical power consumption of
an electric submerged arc furnace as
measured in kilowatts.
(k) "Dust-handling equipment" means
any equipment used to handle particu-
l:te matter collected by ttu air pollution
control device (and located at or near
such device) servine any electric sub-
merged arc furnace subject to this sub-
part.
(1) "Control device'1 means the air
pollution control equipment used to re-
move particulate matter generated by an
electric submerged arc furnace from an
effluent gas stream.
(m) "Capture system" means the
equipment (Including hoods, ducts, fans,
dampers, etc.) used to capture or trans-
port particulate matter generated by an
affected electric submerged arc furnace
to the control device.
(n) "Standard ferromanganese" means
that alloy as defined by A.S.T.M. desig-
nation A99-66.
(o) "Silicomanganese" means that
alloy as defined by A.S.T.M. designation
A483-C6.
(p) "Calcium carbide" means material
containing 70 to 85 percent calcium car-
bide by weight.
(q) "High-carbon ferrochrome" means
that alloy as defined by A.S.T.M. desig-
nation A101-66 grades HC1 through HC6.
(r) "Charge chrome" means that alloy
containing 52 to VO percent by weight
chremium, 5 to 8 percent by weight car-
ban, and 3 to 6 percent by weight silicon.
(s) "Silvery iron" m?ans any ferro-
silicon, as defined by A.S.T.M. designa-
tion 100-69, which contains less than
30 percent silicon.
(t) "Ferrochrome silicon" means that
al'oy as defined by A.S.T.M. designation
A482-6G.
(u) "Eilicomanganese zirconium"
means that alloy containing 60 to 65 per-
cent by weight silicon, 1.5 to 2.5 percent
by weight calcium, 5 to 7 percent by
weight zirconium, 0.75 to 1.25 percent by
\vci:ht aluminum, 5 to 7 percent by
weight manganese, and 2 to 3 percent by
weight barium.
(v) "Calcium silicon" means that
alloy as defined by A.S.T.M. designation
A495-G4.
(w) "Ferrosilicon" means that alloy as
defined by A S.TM. designation A100-69
grades A, B, C, D, and E which contains
5D or more percent by weight silicon.
(x) "Silicon metal" means any si'icon
alloy containing more than 96 percent
silicon by weight.
(y) "Ferromanganese silicon" means
that alloy containing 63 to 66 percent by
weight manganese, 28 to 32 percent by
weight silicon, and a maximum of 0.08
percent by weight carbon.
§ 60.262 Standard for participate mat-
ter.
(a) On and after the date on which the
performance test required to be con-
ducted by § 60.8 is completed, no owner
or operator subject to the provisions of
this subpart shall cause to be discharged
into the atmosphere from any electric
submerged arc furnace any gases which:
(1) Exit f ron. a control device and con-
tain particulate matter in excess of 0.45
kg/MW-hr (0.99 Ib/MW-hr) while sili-
con metal, ferrosilicon, calcium silicon,
or silicomanganese zirconium is being
produced.
(2) Exit from a control device and con-
tain particulate matter in excess of 0.23
kg/MW-hr (0.51 Ib/MW-hr) while high-
carbon ferrochrome, charge chrome,
standard ferromanganese, silicomanga-
nese, calcium carbide, ferrochrome sili-
con, ferromanganese silicon, or silvery
Iron is being produced.
(3) Exit from a control device and ex-
hibit 15 percent opacity or greater.
(4) Exit from an electric submerged
arc furnace and escape the capture sys-
tem and are visible without the aid of
instruments. The requirements under
this subparagraph apply only during pe-
riods when flow rates are being estab-
lished under § 60.265(d).
FEDERAL REGISTER, VOl. 41, NO. 87TUESDAY, MAY 4, 1976
IV-143
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18502
RULES AND REGULATIONS
(5) Escape- the capture system at the
tapping station and are visible without
the aid of instruments for more than 40
percent of each tapping period. There are
no limitations on visible emissions under
this subparagraph when a blowing tap
occurs. The requirements under this sub-
paragraph apply only during periods
when flow rates are being established
under § 60.265(d).
(b) On and after the date an which
the performance test required to be con-
ducted by § 60.8 is completed, no owner
or operator subject to the provisions of
thh subpart shall cause to be discharged
into the atmosphere from any dust-han-
dling equipment any gases which exhibit
10 percent opacity or greater.
§ 60.263 Standard for carbon monoxide.
(a) On and after the date on which
the performance test reouired to be con-
ducted by § 60.8 is completed, no owner
or operator subtect to the provisions of
this subpart shall cause to be discharged
into the atmosphere from any electric
submerged arc furnace any gases which
contain, on a dry basis, 20 or greater
volume percent of carbon monoxide.
Combustion of such gases under condi-
tions acceptable to the Administrator
constitutes compliance with this section.
Acceptable conditions include, but are
not limited to, flaring of gases or use of
gases as fuel for other processes.
§ 60.264 Enrssion monitoring.
fa> The owner or operator subject to
the provisions of this subpart shall In-
stall, calibrate, maintain and operate a
continuous monitoring system for meas-
urement of the opacity of emissions dis-
charged into the atmosphere from the
control device (s).
(b) For the purpose of reports re-
quired under § 60.7(c), the owner or op-
erator shall report as excess emissions
all six-minute periods 'in which the av-
erage opacity is 15 percent or great3r.
(c) The owner or operator subject to
the provisions of this subnart shall sub-
mit a written report of any product
change to the Administrator. Reports of
product changes must be postmarked
not later than 30 days after implemen-
tation of the product change.
§ 60.265 Monitaripg of operations.
(aX The owner or operator of any elec-
tric submerged arc furnace subject to the
provisions of this subpart shall main-
tain daily records of the following in-
formation:
(1) Product being produced.
CO Description of constituents of fur-
nace charge. Including the quantity, by
weight.
(3i Time and duration of each tap-
ping period and the identification of ma-
terial tapped (slag or product.)
(4) All furnace power input data ob-
tained under paragraph (b) of this sec-
tion.
(5) AS flow rate data obtained under
paragraph (c) of this section or all fan
motor power consumption and pressure
drop data obtained under paragraph (e)
of this section.
(b) The owner or operator subject to
the provisions of this subpart shall In-
stall, calibrate, maintain, and operate a
device to measure and continuously re-
cord the furnace power input. The fur-
nace power input may be measured at the
output or input side of the transformer.
The device must have an accuracy of ±5
percent over its operating range.
(c) The owner or operator subject to
the provisions of this subpart shall in-
staJl, calibrate, and maintain a monitor-
ing device that continuously measures
and records the volumetric flow rate
through each separately ducted hood of
the capture system, except as provided
under paragraph (e) of this section. The
owner or operator of an electric sub-
merged arc furnace thpf is equipped wifh
a water cooled cover which is designed
to contain and prevent escape of the
generated gas and particulate matter
shall monitor only the volumetric flow
rate through the capture system for con-
trol of emissions from the tapping sta-
tion. The owner or operator may install
the monitoring devicefs) in any appro-
priate location in the exhaust duct such
that reproducible flow rate monitoring
will result. The flow rate monitoring de-
vice must have an accuracy of ±10 per-
cent over its normal operating range and
must be calibrated according to the
manufacturer's instructions. The Ad-
ministrator may reouire the owner or
operator to demonstrate the accuracy of
the monitoring device relative to Meth-
ods 1 and 2 of Anpendix A tc this part.
(d) When performance tests are con-
ducted under the provisions of § 60.8 of
this part to demonstrate compliance
with the standards under §§60.262(a)
(4) and (5), the volumetric flow rate
through each separately ducted hood of
the capture system must be determined
using the monitoring device required
under paragraph (c) of this section. The
volumetric flow rates must be determined
for furnace power input levels at 50 and
100 percent of the nominal rated capacity
of the electric submerged arc furnace.
At all times the electric submerged arc
furnace is operated, the owner or oper-
ator shall maintain the volumetric flow
rate at or above the appropriate levels
for that furnace power input level de-
termined during the most recent per-
formance test. If emissions due to tap-
ping are captured and ducted separately
from emissions of the electric submerged
arc furnace, during each tapping period
the owner or operator shall maintain
the exhaust flow rates through the cap-
ture system over the tapping; station at
or above the levels established during
the most recent performance test. Oper-
ation at lower flow rates may be consid-
ered by the Administrator to be unac-
ceptable operation and maintenance of
the affected facility. The owner or oper-
ator may request that these flow rates be
reestablished by conducting new per-
formance tests under § 60.8 of this part.
(e) The owner or operator may as an
alternative to paragraph (c) of this sec-
tion determine trie volumetric flow rate
through each fan of the capture system
from the fan power consumption, pres-
sure drop across the'fan and the fan per-
formance curve. Only data specific to the
operation of the affected electric sub-
merged arc furnace are acceptable for
demonstration, of compliance with the
requirements of this paragraph. The
owner or operator shall maintain on file
a permanent record of the fan per-
formance curve 'prepared for a specific
temperature) and shall:
(1) Install, calibrate, maintain, ana
operate a device to continuously measure
and record the power consumption of the
fan motor fme'|si'red in kilowatts), and
(2) Install, calibrate, maintain, and
operate a device to continuously meas-
ure r>nd re-ord the pressure dron acros;s
the fan. The fan rower consumption and
pressure droo measurements must be
synchronised to allo-v real time comppr-
i^ons of the data. The monitoring de-
vices must h"ve an accuracv of ±5 per-
cent over the'r normal operating ranges.
(f) The volumetric flow rate through
each f?>n of the capture svstem must be
determined from the fan power con-
sumntlon, fan pressure drop, and fan
performance curve sneeifled under parfi-
frrarh (e) of thi; section, during anv per-
formance test required under § 60.8 of
this p^rt to demonstrate comniipnce with
the standards under §5 60.262(a) (4) and
(5). The O"ner or operator shall deter-
mire the volumetric flow rate at a repre-
sentative temperature for furnace power
input (eve's of 50 and 100 percent of the
nominal rated capacity of the electric
submerged arc furnace. At all times the
e^ctric .submerged arc furnace is op-
erated, the owner or operator shall main-
tain the fan power consumption and fpn
pressure dron at leve's such that the vol-
umetric flow rat° is at or above the levels
established during the most recent per-
formance te*t for that furnace pover in-
put level. If emissions due to tapping are
captured and ducted separately from
emissions of the electric submerged arc
furnace, during each tipping period the
owner or operator shall maintain the f an
power consumption and fan pressure
drop at levels such that the volumetric
flow rate is at or above the levels estab-
lished during the most recent perform-
ance test. Operation at lower flow rates
may be considered bv the Administrator
to be unacceptable operation and main-
tenance of the affected facility. The own-
er or operator may request tint these
flow rates be reestablished by conducting
new performance tests under $ 60.8 of
this part. The Administrator may requi re
the owner or operator ta verify the fan
performance curve by monitoring neces-
sary fan operating parameters and de-
termining the gas volume moved relative
to Methods 1 and 2 of Appendix A to this
part.
(g) ATI monitoring devices required
under paragraphs (c) and (e) of this
section are to be checked for calibration
annually In accordance with the proce-
dures under §60.13(b).
§ 60.206 Test methods and procedures.
(a) Reference methods hi Appendix A
of this part, except as provided ta 5 60.8
(b), shall be used to determine compli-
ance with the standards prescribed In
160.262 and f 60.263 as follows:
FEDERAL REGISTER, VOL 41, NO. 87TUESDAY, MAY 4, 1976
IV-L44
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RULES AND REGULATIONS
18503
(1) Method 5 for the concentration of
particulate matter and the associated
moisture content except that the heating
systems specified in paragraphs 2.1.2 and
2.1.4 of Method 5 are not to be used when
the carbon monoxide content of the gas
stream exceeds 10 percent by volume,
dry basis.
(2) Method 1 for sample and velocity
traverses.
(3) Method 2 for velocity and volumet-
ric flow rate.
(4) Method 3 for gas analysis, includ-
ing carbon monoxide.
(b) For Method 5, the sampling time
for each run is to include an integral
number of furnace cycles. The sampling
time for each run must be at least 60
minutes and the minimum sample vol-
ume must be 1.8 dscm (64 dscf) when
sampling emissions from open electric
submerged arc furnaces with wet scrub-
ber control devices, sealed electric sub-
merged arc furnaces, or semi-enolosed
electric submerged arc furnaces. When
sampling emissions from other types of
installations, the sampling time for each
run must be at leist 200 minutes and the
minimum sample volume must be 5.7
dscm (200 dscf). Shorter sampling times
or smaller sampling volumes, when ne-
cessitated by process variables or other
factors, may be approved by the Admin-
istrator.
(c) During the performance test, the
owner or operator shall record the maxi-
mum open hood area (in hoods with
segmented or otherwise nioveable sides)
under which the process is expected to
be operated and remain in compliance
with all standards. Any future operation
of the hooding system with open areas in
excess of the maximum is not permitted.
(d) The owner or operator shall con-
struct the control device so that volu-
metric flow rates and participate matter
emissions can be accurately determined
by applicable test methods and proce-
dures.
During any performance test re-
quired under § 60.8 of this part, the
owner or operator shall not allow gaseous
diluents to be added to the effluent gas
stream after the fabric in an open pres-
surized fabric filter collector unless the
total gas volume flow from the collector
is accurately determined and considered
in the determination of emissions.
(f) When compliance with § 60.263 is
to be attained by combusting the gas
stream in a flare, the location of the
sampling site for particulate matter is
to be upstream of the flare.
(g) For each run, particulate matter
emissions, expressed in kg/hr (Ib/hr),
must be determined for each exhaust
stream at which emissions are quantified
using the following equation:
where:
£= Emissions of particulate matter in
kg/hr (Ib/hr).
C.=Concentration of particulate matter In
kg/dscm (Ib/dscf) as determined by
Method 6.
Q>= Volumetric flow rate of the effluent gas
stream In dszm/hr (dscf/hr) as do-
termlned by Method 2.
(h) For Method 5, particulate matter
emissions from the affected facility, ex-
pressed in kg/MW-hr (Ib/MW-hr) must
be determined for each run using the
following equation:
N
n=l
£=
where:
E=Emissions of particulate from the af-
fected facility,' in kg/MW-hr (lb/
MW-hr).
NTotal number of exhaust streams at
which emissions are quantified.
£»=Emission of particulate matter from
\ each exhaust stream in kg/hr (lb/
hr), as determined in paragraph (g)
of this section.
p = Average furnace power input during
the sampling period, in megawatts
as determined according to § 60.263
(b).
(Sees. Ill and 114 of the Clean Air Act, as
amended by sec. 4(a) of Pub. L. 91-404, 84
Btat. 1678 (42 UJ3.C. 1857C-6, 1857C-9))
(PR Doc.76-12814 tiled 6-3-76;8:49 *"*!
KDEKAt lEOIJTEH. VOL 41. NO. 87TUESDAY, MAY 4, 197*
34
Title 40Protection of Environment
CHAPTER IENVIRONMENTAL
PROTECTION AGENCY
SUBCKAPTER CAIR PROGRAMS
(FRL 539-5]
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCE
Delegation of Authority to Commonwealth
of Massachusetts
Pursuant to the delegation of author-
ity for the standards of performance for
new stationary sources (NSPS) to the
Commonwealth of Massacluisetts on
January 23, 1976, EPA is today amending
40 CFB 60.4. "Address," to reflect this
delegation. A notice announcing this
delegation is published in the Notices
section of today's FEDERAL REGISTER. The
amended § 60.4, which adds the address
of the Massachusetts Department of En-
vironmental Quality Engineering, Divi-
sion of Air Quality Control, to which all
reports, requests, applications, submit-
tals, and communications to the Ad-
ministrator pursuant to this part must
also be addressed, is set forth below.
The Administrator finds good cause for
foregoing prior public notice and for
making this rulemaking effective im-
mediately in that it is an administra-
tive change and not one of substantive
content. No additional substantive bur-
dens are imposed on the parties affected.
The delegation which is reflected by thus
administrative amendment was effective
on January 23, 1976, and it serves no
purpose to delay the technical change
of this addition of the State address to
the Code of Federal Regulations.
This rulemaking is effective immedi-
ately, and is issued under the authority
of Section 111 of the Clean Air Act. as
amended.
42 U.S.C. 1857C-6.
Dated May 3, 1976.
STANLEY W. LEGRO,
Assistant Administrator
/or Enforcement,
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amended
as follows:
1. In § 60.4 paragraph (b) is amended
by revising subparagraph (W) to read
as follows:
§ 60.4 Ad
-------
RULES AND REGULATIONS
This rulemaking Is effective immedi-
ately, and is issued under the authority
of Section 111 of the Clean Air Act, as
amended.
42 US C. 1857c-«.
Da ted: May 3,1976.
STANLEY W. LEGRO,
Assistant Administrator
of Enforcement.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amended
as follows:
1. In § 60.4 paragraph (b) is amended
by revising subparagraph (EE) to read
as follows:
§ 60.1 Address.
*****
(b) * * *
(EE) New Hampshire Air Pollution
Control Agency, Department of Health
and Welfare, State Laboratory Building,
Hazen Drive, Concord, New Hampshire
03301.
[FR Doc.76-13821 Filed 6-12-76,8:45 am)
FEDERAL REGISTER, VOL. 41. NO. 94-
-THURSDAY, MAY 13, 1976
35 [FRL509-3J
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Ferroalloy Production Facilities
Correction
In PR Doc. 78-12814 appearing at pag«
18498 in the FEDERAL REGISTER of Tues-
day, May 4, 1976 the following correc-
tions should be made:
1. On page 18408, second column, last
paragraph designated "(1)", second line,
fourth word should read "representa-
tiveness".
2. On page 18501, first column, the sub-
part heading Immediately preceding the
text, should read "Subrjart ZStandards
of Performance for Ferroalloy Produc-
tion Facilities".
3. On page 18501, in {60.260, second
column, fourth line from the top, the
third word should read "sillcomanga-".
4. On page 18501, second column. In
960.261 (i), second line, third word
should read "evolution".
5. On page 18503, third column. In
{ «0.26«(h> th« equation should hare ap-
peared as follows:
36.
[OPP260019: FRL 645-81
FEDERAL REGISTER, VOL 41, NO. 99-
-THUSSOAY, MAY 20, 1976
Title 40Protection of Environment
[FRL 548-4]
CHAPTER IENVIRONMENTAL
PROTECTION AGENCY
SUBCHAPTER CAIR PROGRAMS
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Delegation of Authority to State of Cali-
fornia on Behalf of Ventura County and
Northern Sonoma County Air Pollution
Control Districts
Pursuant to the delegation of author-
ity for the standards of performance for
new stationary sources (NSPS) to the
State of California on behalf of the
Ventura County Air Pollution Control
District and the Northern Sonoma
County Air Pollution Control District,
dated February 2, 197G, EPA is today
amending 40 CFR 60.4, Address, to re-
flect this delegation. A Notice announcing-
this delegation is published today in
the Notice section of this issue. The
amended § GO.4 is set forth below. It adds
the addresses of the Ventura County and
Northern Sonoma County Air Pollution
Control Districts, to which must be ad-
dressed all reports, requests, applica-
tions, submittals, and communications
pursuant to this part by sources subject
to the NSPS located within these Air
Pollution Control Districts.
The Administrator finds Rood cause
for foregoing prior public notice nnd for
making this rulemakmg effective imme-
diately in that it is an administrative
change and not one of substantive con-
tent. No additional substantive burdens
are imposed on the parties affected. The
delegation which is reflected by this ad-
ministrative amendment wns effective on
Febraury 2, 1976, and it serves no pur-
poses to delay the technical change of
tills addition of the Air Pollution Con-
trol District addresses to the Code of
Federal Regulations.
Tin's rulemaking is effective imme-
diately.
(Sec. Ill of the Clean Air Act, as amended
|42U.S.C. 1857c-6j).
Dated: May 3,1976.
STANLEY W. LEGRO,
Assistant Administrator
for Enforcement.
Part 60 of'Chapter I. Title 40 of the
Code of Federal Regulations is amended
as follows:
1. Section 60.4(b) Is amended by
revising subparagraph F to read as fol-
lows:
§ 60.4 Address.
(b) * * *
F California
Bay Area Air Pollution Control District,
639 Ellis St., Sen Francisco, CA 94109.
Del Norte County Air Pollution Control
District, Courthouse, Crescent City. CA 9&5S1.
Humboldt County Air Pollution Control
District, 5600 8. Broadway, Eureka, CA 95601.
Kern County Air Pollution Control District,
1700 Flower St. (P.O. Box 097), Bakersfleld.
OA M303.
Monterey Bay Unified Air Pollution Control
District, 420 Church St. (P.O. Box 487),
Sulinas, CA 93001.
Northern Sonoma County Air Pollution
Control District, 3313 Chanate Bd., Santa-
Rosa, CA 95404.
Trinity County Air Pollution Control Dis-
trict, Box AJ. Wcaverville, CA 96093
Ventura County Air Pollution Control Dis-
trict. 025 E. Santa Clara St, Ventura, CA
93001.
FEDERAL REGISTER, VOL. 41, NO, 103-
-WEDNESDAY, MAY 26, 1976
37
Title 40Protection of Environment
[FRL, 562-8]
CHAPTER IENVIRONMENTAL
PROTECTION AGENCY
SUBCHAPTER CAIR PROGRAMS
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Delegation of Authority to State of Utah
Pursuant to the delegation of author-
ity for the standards of performance for
twelve (12) categories of new stationary
sources (NSPS) to the State of Utah on
May 13, 1976, EPA is today amending 40
CFR 60.4, Address, to reflect this delega-
tion. A Notice announcing this delega-
tion is published today In the FEDERAL
REGISTER. The amended I 60.4, which
adds the address of the Utah Air Con-
servation Committee to which all re-
ports, requests, applications, submittals,
and communications to the Administra-
tor pursuant to this part must also be
addressed, is set forth below.
The Administrator finds good cause for
foregoing prior public notice and for
making this rulemaking effective im-
mediately in that it is an administrative
change and not one of substantive con-
tent. No additional substantive burdens
are imposed on the parties affected. Th>5
delegation which is reflected by this ad -
ministrative amendment was effective on
May 13, 1976, and it serves no purpose
to delay the technical change of this
addition of the State address to the Code
of Federal Regulations.
This rulemaking is effective immedi-
ately, and is issued under the authority
of section 111 of the Clean Air Act, as
amended, 42 U.S C. 1857c-6.
Dated: June 10, 1976.
STANLEY W. LEGRO,
Assistant Administrator
for Enforcement.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amended
as follows:
1. In § 60.4 paragraph (b) Is amended
by revising subparagraph (TT) to read
as follows:
§ 60.4 AddreM.
(b)
(TT)State of Utah, Utah Air Con-
servation Committee, State Division of
Health, 44 Medical Drive, Salt Lake City,
Utah 84113.
* » t *
[FR Doc.76-17433 Piled &-14-76;8:45 am]
FEDERAL REGISTER, VOL. 41, NO. 116-
-TUE50AY, JUNE 15, 1976
IV-146
-------
RULES AND REGULATIONS
3 8 Title 40Protection of Environment
CHAPTER IENVIRONMENTAL.
PROTECTION AGENCY
SUBCHAPTER CAIR PROGRAMS
[FBL 664-«l
NEW SOURCE REVIEW
Delegation of Authority to the State of
Georgia
The amendments below Institute cer-
tain address changes for reports and ap-
plications required from operators of new
sources. EPA has delegated to the State
of Georgia authority to review new and
modified sources. The delegated author-
ity includes the reviews under 40 CFR
Part 52 for the prevention of significant
deterioration. It also includes the review
under 40 CFR Part 60 for the standards
of performance for new stationary
sources and review under 40 CPR Part
61 for national emission standards for
hazardous air pollutants.
A notice announcing the delepration of
authority is published elsewhere in the
Notices section this issue of the FEDERAL
REGISTER. These amendments provide
that all reports, requests, applications,
submittals, and communications previ-
ously required for the delegated reviews
will now be sent instead to the Envi-
ronmental Protection Division, Georgia
Department of Natural Resources, 270
Washington Street SW., Atlanta, Georgia
30334, instead of EPA's Region IV.
The Regional Administrator finds good
cause for foregoing prior public notice
and for making this rulemaking effective
immediately in that it Is an administra-
tive change and not one of substantive
content. No additional substantive bur-
dens are Imposed on the parties affected.
The delegation which Is reflected by this
administrative amendment was effective
on May 3, 1976, and it serves no pur-
pose to delay the technical change of
this addition of the State address to the
Code of Federal regulations.
This rulemaking Is effective Immedi-
ately, and Is Issued under the authority
of Sections 101, 110, 111. 112 and 301 of
the Clean Air Act, as amended 42 UJ3.C.
1857, 1857C- 5, 6, 7 and 1857&,
Dated: June 11. 1076.
JACK E. RAVAN,
Regional Administrator.
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
DELEGATION OF AUTHORITY TO THE
STATE OF GEORGIA
Part 60 of Chapter I, Title 40, Code of
Federal Regulations, Is amended as fol-
lows:
2. In § 60.4, paragraph (b) (L) is re-
vised to read as follows:
§ 60.4 Address.
(b)
(L) State of Georgia, Environmental Pro-
tection Division. Department of Natural Re-
sources, 270 Washington Street, S.W., At-
lanta. Georgia 30334.
FEDERAL REGISTER, VOL 41, NO. 120-
-MONDAY, JUNE 21, 1976
39
SUBCHAPTER CAIR PROGRAMS
[FBL 574-31
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Delegation of Authority to State of Cali-
fornia on Behalf of Fresno, Mendocino,
San Joaquin, and Sacramento County
Air Pollution Control Districts
Pursuant to the delegation of author-
ity for the standards of performance for
new stationary sources (NSPS) to the
State of California on behalf of the
Fresno County Air Pollution Control
District, the Mendocino County Air Pol-
lution Control District, the San Joaquin
County Air Pollution Control District,
and the Sacramento County Air Pollu-
tion Control District, dated March 29,
1976, EPA Is today amending 40 CFR
60.4, Address, to reflect this delegation.
A Notice announcing this delegation Is
published today in the Notice Section of
this Issue. The amended § 60.4 is set forth
below. It adds the addresses of the Fres-
no County, Mendocino County, San Joa-
quin County, and Sacramento County
Air Pollution Control Districts, to which
must be addressed all reports, requests,
applications, submittals, and communi-
cations pursuant to this part by sources
subject to the NSPS located within these
Air Pollution Control Districts.
The Administrator finds good cause for
foregoing prior public notice and for
making this rulemaking effective Imme-
diately In that It Is an administrative
chenge and not one of substantive con-
tent. No additional substantive burdens
are Imposed on the parties affected. The
delegation which Is reflected by this ad-
ministrative amendment was effective on
March 29, 1976, and it serves no purpose
to delay the technical change of this ad-
dition of the Air Pollution Control Dis-
trict addresses to the Code of Federal
Regulations.
This rulemaking is effective Immedi-
ately, and Is issued under the authority
of section 111 of the Clean Air Act, as
amended [42 UJS.C. 1857c-63.
Dated: June 15,1976.
STANLEY W. LEGRO,
Assistant Administrator
for Enforcement.
Part 60 of Chapter I, Title 40, of the
Code of Federal Regulations, Is amended
as follows:
1. In § 60.4, paragraph (b) Is amended
by revising subparagraph P to read a*
follows:
§ 60.4 Address.
(b) *
(A)-(E) * * *
(F) California:
Bay Area Air Pollution Control District, 939
Ellis St., San Francisco, CA 94109
Del Norte County Air Pollution Control Dis-
trict, Courthouse, Crescent City, CA 95531
Fresno County Air Pollution Control District,
615 S. Cedar Ave.. Fresno, CA 93703
Humboldt County Air Pollution Control Dis-
trict. 6600 S. Broadway, Eureka, CA 95501
Kern County Air Pollution Control District,
1700 Flower St. (P.O. Box 997), Bakersfleld,
CA 93302
Mendocino County Air Pollution Control
District, County Courthouse, TJklan. CA
95482
Monterey Bay Unified Air Pollution Control
District, 420 Church Sfc (P.O. Box 487),
Salinas, CA 93901
Northern Sonoma County Air Pollution Con-
trol District, 3313 Chanate Rd., Santa Rosa.
CA 95404
Sacramento County Air Pollution Control
District, 2221 Stockton Blvd., Sacramento,
CA 95827
San Joaquin County Air Pollution Control
District, 1601 E. Hazelton St. (P.O. Box
2009), Stockton, CA 95201
Trinity County Air Pollution Control Dis-
trict, Boi AJ, Weavervllle, CA 96093
Ventura County Air Pollution Control Dis-
trict, 625 E. Santa Clara St., Ventura. CA
93001
FEDERAL REGISTER, VOL. 41, NO. 132-
-THURSOAY, JULY 8, 1976
IV-147
-------
RULES AND REGULATIONS
40 Title 40 Protection of Environment
CHAPTER I ENVIRONMENTAL
PROTECTION AGENCY
[FRL 597-l|
PART 60 STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Delegation of Authority to State of Cali-
fornia on Behalf of Madera County Air
Pollution Control District
Pursuant to the delegation of authority
for the standards of performance for new
stationary sources (NSPS) to the State
of California on behalf of the Madera
County Air Pollution Control District,
dated May 12, 1976, EPA is today amend-
ing 40 CFR 60.4 Address, to reflect this
delegation. A Notice announcing this del-
egation is published in the Notices Sec-
tion of this issue of the FEDERAL REGISTER,
Environmental Protection Agency, FRL
596-8. The amended 5 60.4 is set forth be-
low. It adds the address of the Madera
County Air Pollution Control District, to
which must be addressed all reports, re-
quests, applications, submittals, and
communications pursuant to this part by
sources subject to the NSPS located
within this Air Pollution Control District.
The Administrator finds good cause for
foregoing prior public notice! and for
making this rulemaking effective immed-
iately In that It is an administrative
change and not one of substantive con-
tent. No additional substantive burdens
are imposed on the parties affected. The
delegation which is reflected by this ad-
ministrative amendment was effective on
May 12, 1976. and it serves no purpose to
delay the technical change of this addi-
tion of the Air Pollution Control District
address to the Code of Federal
Regulations.
This rulemaking is effective immedi-
ately, and is issued under the authority
of Section 111 of the Clean Air Act, as
amended I42U.S.C. 1857c-61.
Dated: July 27, 1976.
PAUL DEFALCO.
Regional Administrator,
Region IX. EPA.
Pai-t 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amended
as follows:
1. In 5 60.4 paragraph
-------
42 [FRL 698-2]
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Revision to Emission Monitoring
Requirements
On October 6, 1975 (40 PR 46250),
under section 111 of the Clean Air Act,
as amended, the Environmental Protec-
tion Agency (EPA) promulgated emis-
sion monitoring requirements and revi-
sions to the performance testing methods
In 40 CFR Part 60. The provisions of
560.13(1) allow the Administrator to
approve alternatives to monitoring pro-
cedures or requirements only upon writ-
ten application by an owner or operator
of an affected facility; monitoring equip-
ment manufacturers would not be al-
lowed to apply for approval of alternative
monitoring equipment. Since EPA did
not Intend to prevent monitoring equip-
ment manufacturers from applying for
approval of alternative monitoring
equipment, 5 60.13(1) Is being revised. As
revised, any person will be allowed to
make application to the Administrator
for approval of alternative monitoring
procedures or requirements.
This revision does not add new require-
ments, rather It provides greater flexi-
bility for approval of alternative equip-
ment and procedures. This revision is
effective (date of publication).
(Sections 111, 114, and 301 (a) of the Clean
Air Act, as amended by sec. 4(a) of Puti. L.
91-604, 84 Stat. 1678 and by sec. 16(c) (2) of
Pub. L. 91-604, 84 Stat. 1713 (42 UB.C. :867o-
6, 18570-9, and 1857g(a)).)
Dated: August 13,1976.
RUSSELL E. TRAIN,
Administrator.
In 40 CFR Part 60, Bubpart A la
amended as follows:
1. Section 60.13 is amended by revising
paragraph (1) as follows:
§60.13 Monitoring requirement*.
«
(i) After receipt and consideration of
written application, the Administrator
may approve alternatives to any moni-
toring procedures or requirements of this
part Including, but not limited to the
following:
[PR Doc.76-24058 Filed 8-19-76;8:45 *m)
FEDERAL REGISTER, VOL. 41, NO. 163
FRIDAY, AUGUST 20, 1976
43
RULES AND REGULATIONS
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
5. By revising § 60.9 to read as follows:
§ 60.9 Availability of information.
The availability to the public of in-
formation provided to, or otherwise ob-
tained by, the Administrator under this
Part shall be governed by Part 2 of this
chapter. (Information submitted volun-
tarily to the Administrator for the pur-
poses of §§ 60.5 and 60.6 is governed by
§ 2.201 through § 2.213 of this chapter
and not by § 2.301 of this chapter.)
FEDERAL REGISTER, VOL. 41, NO. 171
WEDNESDAY, SEPTEMBER 1, 1976
* 4 Title 40Protection of Environment
CHAPTER IENVIRONMENTAL
PROTECTION AGENCY
SUBCHAPTER CAIR PROGRAMS
[FRL 617-2)
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Delegation of Authority to State of Cali-
fornia on Behalf of Stanislaus County
Air Pollution Control District; Delegation
of Authority to State of California on Be-
half of Sacramento County Air Pollution
Control District; Correction
Pursuant to the delegation of author-
ity for the standards of performance for
new stationary sources (NSPS) to the
State of California on behalf of the
Stanislaus County Air Pollution Control
District, dated July 2, 1976, EPA is today
amending 40 CPR 60.4 Address, to reflect
this delegation. A notice announcing
this delegation is published today at 41
PR 40108. The amended § 60.4 is set forth
below. It adds the address of the Stanis-
laus County Air Pollution Control Dis-
trict, to which must be addressed all re-
ports, requests, applications, submittals,
and communications pursuant to this
part by sources subject to the NSPS lo-
cated within this Air Pollution Control
District.
On July 8, 1976, EPA amended 40 CPR
60.4, Address to reflect delegation of au-
thority for NSPS to the State of Cali-
fornia on behalf of the Sacramento
County Air Pollution Control District.
By letter of July 30, 1976, Colin T. Green-
law, M.D., Sacramento County Air Pol-
lution Control Officer, notified EPA that
the address published at 41 FR. 27967
was incorrect. Therefore, EPA is today
also amending 40 CFR 60.4, Address to
reflect the correct address for theNSac-
ramento County Air Pollution Control
District.
The Administrator finds good cause
for foregoing prior public notice and for
making this rulemaking effective im-
mediately in that it Is an administrative
change and not one of substantive con-
tent. No additional substantive burdens
are Imposed on the parties affected. The
delegations which are reflected by this
administrative amendment were effec-
tive on July 2, 1976 and March 29, 1976,
and It serves no purpose to delay the
technical change of these additions of the
Air Pollution Control Districts addresses
to the Code of Federal Regulations.
This rulemaking Is effective Immedi-
ately, and Is Issued under the authority of
Section 111 of the Clean Air Act, as
amended (42 U.S.C. 1857c-«)
Dated: September 8, 1976.
L. RUSSELL FREEMAN,
Acting Regional Administrator,
Region IX, EPA.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations Is amended
as follows;
1. In { 60.4 paragraph (b) (f ) is re-
vised to read as follows:
§ 60.4 Address.
(b)
(F) California;
Bay Area Air Pollution Control District, 939
Ellis St., San Francisco, CA 94109
Del Norte County Air Pollution Control Dis-
trict, Courthouse, Crescent City, CA 95531
Fresno County Air Pollution Control District,
615 S. Cedar Avenue, Fresno, CA 93702
Humboldt County Air Pollution Control Dis-
trict, 6600 S. Broadway, Eureka, CA 95601
Kern County Air Pollution Control District,
1700 Flower St. (P.O. Box 997), Bakers-
field, CA 93302
Madera County Air Pollution Control Dis-
trict, 135 W. Yosemlte Avenue, Madera, CA
93637
Mendoclno County Air Pollution Control Dis-
trict, County Courthouse, Uklah, CA 95482
Monterey Bay Unified Air Pollution Control
District, 420 Church St. (P.O. Box 487),
Salinas, CA 93901
Northern Sonoma County Air Pollution Con-
trol District, 3313 Chanate Rd., Santa
Rosa, CA 95404
Sacramento County Air Pollution Control
District, 3701 Branch Center Road, Sacra-
mento, CA 95827
San Joaquln County Ah- Pollution Control
District, 1601 E. Hazelton St. (P.O. Box
2009) . Stockton, CA 95201
Stanislaus County Air Pollution Control Dis-
trict, 820 Scenic Drive. Modesto, CA 95350
Trinity County Air Pollution Control Dis-
trict. Box AJ, Weavervllle, CA 96093
Ventura County Air Pollution Control Dis-
trict, 626 E. Santa Clara St., Ventura, CA
93001
IFR Doc.76-27175 Filed 9-16-76;8:45 am]
FEDERAL REGISTER, VOL. 41, NO. 182
FRIDAY, SEPTEMBER 17, 197*
IV-149
-------
RULES AND REGULATIONS
45
Title 4OProtection of Environment
CHAPTER IENVIRONMENTAL
46
Title 40Protection of Environment
PROTECTION AGENCY
(FBI. 819-1]
SUBCHAPTER CAIR PROGRAMS
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
PART 61NATIONAL EMISSION STAND-
ARDS FOR HAZARDOUS AIR POLLUTANTS
Reports and Applications From Operators
of New Sources; Address Changes
DELEGATION OF AUTHORITY TO THE STATE
OF ALABAMA
The amendments below institute cer-
tain address changes for reports and ap-
plications required from operators of new-
sources. EPA has delegated to the State
of Alabama authority to review new and
modified sources. The delegated author-
ity includes the review under 40 CFR Part
60 for the standards of performance for
new stationary sources and review under
40 CFR Part 61 for national emission
standards for hazardous air pollutants.
A notice announcing the delegation of
authority is published elsewhere in this
issue of the FEDERAL REGISTER. These
amendments provide that all reports, re-
quests, applications, submittals, and
communications previously reuired for
the delegated reviews will now be sent
instead to the Air Pollution Control Divi-
sion, Alabama Air Pollution Control
Commission, 645 South McDonough
Street, Montgomery, Alabama 36104, in-
stead of EPA's Region IV.
The Regional Administrator finds good
cause for foregoing prior public notice
and for making this rulemaking effective
Immediately in that it is an administra-
tive change and not one of substantive
content. No additional substantive bur-
dens are imposed on the parties affected.
The delegation which is reflected by this
administrative amendment was effective
on August 5, 1976, and it serves no pur-
pose to delay the technical change of
this addition of the State adoress to the
Code of Federal Regulations.
This rulemaking Is effective immedi-
ately, and is Issued under the authority
of sections 111, 112, and 301 of the Clean
Air Act, as amended 42 U.S.C. 1857,
1857C-5, 6, 7 and 1857g.
Dated: September 9,1976.
JACK E. LAV AM,
Regional Administrator.
Part 60 of Chapter I, Title 40, Code of
Federal Regulations, Is amended as fol-
lows:
1. In 5 60.4. paragraph (b) Is amended
by revising subparagraph (B) to read a»
follows:
§ 60.4 Addre**.
CHAPTER IENVIRONMENTAL
PROTECTION AGENCY
SUBCHAPTER CAIR PROGRAMS
[FRL 623-7]
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Delegation of Authority to the State of
Indiana
Pursuant to the delegation of authority
to implement the standards of perform-
ance for new stationary sources (NSPS)
to the State of Indiana on April 21, 1976,
EPA Is today amending 40 CFR 60.4,
Address, to reflect this delegation. A
notice announcing this delegation is pub-
lished Thursday, September 30, 1976 (41
FR 43237). The amended §60.4, which
adds the address of the Indiana Air Pol-
lution Control Board to that list of ad-
dresses to which all reports, requests, ap-
plications, submittals, and communica-
tions to the Administrator pursuant to
this part must be sent, is set forth below.
The Administrator finds good cause for
foregoing prior notice and for making
this rulemaking effective immediately in
that it is an administrative change and
not one of substantive content. No addi-
tional substantive burdens are imposed
on the parlies affected. The delegation
which is reflected by this administrative
amendment was effective on April 21,
1976. and it serves no purpose to delay
the technical change of this addition of
the State address to the Code of Fed-
eral Regulations.
This rulemaking is effective immedi-
ately.
(Sec 111 of the Clean Air Act, as amended,
42U.SC. 1857C-6.)
Dated: September 22, 1976.
GEORGE R. ALEXANDER, Jr.,
Regional Administrator.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amended
as follows:
1. In § 60 4, paragraph (b) is amended
by revising subparagraph P, to read as
follows:
§60.1 Address.
*****
(b) * '
(A)-(O) *
(P) State of Indiana. Indiana Air Pollu-
tion Control Board, 1330 West Michigan
Street, Indianapolis, Indiana 4620C.
*****
IFR Doc 76-28507 Filed 9-29-76,8:45 am]
FEDERAL REGISTER, VOL. 4!, NO. 191
THURSDAY, SEPTEMBER 30, 1976
4 / Title 40Protection of Environment
CHAPTER IENVIRONMENTAL
PROTECTION AGENCY
SUBCHAPTER CAIR PROGRAMS
[FRL 629-8]
PART 60STANDARDS OF PERFORM-
ANCE FOR STATIONARY SOURCES
PART 61NATIONAL EMISSION STAND-
ARDS FOR HAZARDOUS AIR POLLU-
TANTS
Delegation of Authority to State of
North Dakota
Pursuant to the delegation of author-
ity for the standards of performance for
new sources (NSPS) and national emis-
sion standards for hazardous air pol-
lutants (NESHAPS) to the State of
North Dakota on August 30. 1976, EPA
is today amending respectively 40 CFR.
60.4 and 61.04 Address, to reflect this-
delegation. A notice announcing this del-
egation L" published today in the notices
section The amended §§ 60.4 and 61.04
which add the address of the North Da-
kota State Department of Health to
which nil reports, requests, applications,
submiti als, and communications to tho
Administrator pursuant to these parts
must also be addressed, are set forth
below.
The Administrator finds good cause for
foregoing prior public notice and for
making this rulemaking effective Imme-
diately in that it is an administrate
change and not one of substantive con-
tent. No additional substantive burdens
are imposed on the parties affected. The
delegation which is reflected by this ad-
ministrative amendment was effective on
August 30, 1976, and it serves no purpose
to delay the technical change of this
addition to the State address to the Code
of Federal Regulations.
This rulemaking Is effective immedi-
ately, and is issued under the authority
of sections 111 and 112 of the Clean Air
Act, as amended, (42 U.S.C. 1857c~6 and,
-7).
Dated: October 1.1976.
JOHN A. GREEN,
Regional Administrator.
Parts 60 and 61 of Chapter I, Title 40
of the Code of Federal Regulations are
respectively amended as follows:
1. In § 60.4, paragraph (b) is amended
by revising subparagraph (JJ) to read.
as follows:
§ 60.1 Addrc<-».
(b)
(A)-(Z)
(AA)-(U) »
(JJ)State of North Dakota, State De-
partment of Health, State Capitol, Bismarck.
North Dakota 58501.
(b) '
(B) State of Alabama. Air Pollution Con-
trol Division. Air Pollution Control Commto-
slon. 648 8. McDonough Street, Montgomery.
Alabama 30104.
FEDERAL REGISTER, VOL 41, NO. 1IJ
MONDAY, SEPTEMBER 20, 197*
FEDERAL REGISTER, VOL. 41, NO. 199
WEDNESDAY, OCTOBER 13, T976
IV-150
-------
48
Title 40Protection of Environment
CHAPTER IENVIRONMENTAL
PROTECTION AGENCY
SUBCHAPTER CAIR PROGRAMS
[PRL 638-4]
PART 60STANDARDS OF PERFORM- '
ANCE FOR NEW STATIONARY SOURCES
Delegation of Authority to State of Cali-
fornia On Behalf of Santa Barbara
County Air Pollution Control District
Pursuant to the delegation of author-
ity for the standards of performance for
new stationary sources (NSPS) to the
State of California on behalf of the
Santa Barbara County Air Pollution
Control District, dated September 17,
1976, EPA is today amending 40 CPR
60.4 Address, to reflect this delegation.
A Notice announcing this delegation is
published in the Notices section of this
issue of the FEDERAL REGISTER. The
amended § 60.4 is set forth below. It adds
the address of the Santa Barbara
County Air Pollution Control District, to
which must be addressed all reports, re-
quests, applications, submittals, and
communications pursuant to this part
by sources subject to the NSPS located
within this Air Pollution Control
District.
The Administrator finds good cause
for foregoing prior public notice and for
making this rulemaking effective imme-
diately in that it is an administrative
change and not one of substantive con-
tent. No additional substantive burdens
are imposed on the parties affected. The
delegation which is reflected this admin-
istrative amendment was effective on
September 17. 1976 and It serves no pur-
pose to delay the technical change on
this addition of the Air Pollution Control
District's address to the Code of Federal
Regulations.
This rulemaking is effective immedi-
ately, and is issued under the authority
of section 111 of the Clean Air Act, as
amended (42 U.S.C. 1857C-6).
Dated: October 20, 1976.
PAUL DE FALCO, Jr.,
Regional Administrator,
EPA, Region IX.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amended
as follows:
1. In §60.4 paragraph (b) (3) is
amended by revising subparagraph F to
read as follows:
§ 60.4 Addrr«.
(b)
(3)
(A)-(E)
FCALIFORNIA
RULES AND REGULATIONS
Humboldt County Air Pollution Control
District, 5600 8. Broadway, Eureka, CA 95501.
Kern County Air Pollution Control Dis-
trict, 1700 Flower St. (PO. Box 997), Bakers-
fleld, CA 93302.
Madera County Air Pollution Control Dis-
trict, 135 W. Yosemite Avenue, Madera, CA
93637.
Mendoclno County Air Pollution Control
District, County Courthouse, Ukloh, CA
96482.
Monterey Bay Unified Atr Pollution Con-
trol District, 420 Church St. (P.O. Box 487),
Salinas, CA 93901.
Northern Sonoma County Air Pollution
Control District, 3313 Chanate Bd., Santa
Rosa. CA 95404.
Sacramento County Air Pollution Control
District. 3701 Branch Center Road, Sacra-
mento, CA 95827
San Joaquln County Air Pollution Control
District, 1601 E. Hazelton St. (P.O. Box 2009).
Stockton, CA 95201
Santa Barbara County Air Pollution Con-
trol District, 4440 Calle Real, Santa Barbara,
Cf 93110
Stanislaus County Air Pollution Control
District, 820 Scenic Drive, Modesto, CA 95350.
Trinity County Air Pollution Control Dis-
trict. Box AJ, Weavervllle, CA 96093.
Ventura County Air Pollution Control Dis-
trict. 625 E Santa Clara St., Ventura, CA
93001
(FR Doc.76-32104 Filed H-2~76;8:45 am)
FEDERAL REGISTER, VOl. 41, NO. 213
WEDNESDAY, NOVEMBER 3, 1976
49
Title 40Protection of Environment
Bay Area Air Pollution Control District,
939 Ellis St, San Francisco. CA 94109
Del Norte County Air Pollution Control
District, Courthouse, Crescent City, CA 95531
Fresno County Air Pollution Control Dis-
trict, 515 S. Cedar Avenue, Fresno, CA 93702.
CHAPTER IENVIRONMENTAL
PROTECTION AGENCY
SUBCHAPTER CAIR PROGRAMS
[FRL 639-3]
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Amendments to Subpart D
Standards of performance for fossil
fuel-fired steam generators of more than
73 megawatts (250 million Btu per hour)
heat input rate are provided under Sub-
part D of 40 CFR Part 60. Subpart D is
amended herein to revise the application
of the standards of performance for fa-
cilities burning wood residues In combi-
nation with fossil fuel.
Subpart D contains standards for par-
ticulate matter, sulfur dioxide, nitrogen
oxides, and visible emissions from steam
generators. These standards, except for
the one applicable to visible emissions,
are based on heat input. For sulfur di-
oxide, there are separate standards for
liquid fossil fuel-fired and solid fossil
fuel-fired facilities with provisions for a
prorated standard when combinations of
different fossil fuels are fired. There is
no sulfur dioxide standard for gaseous
fossil fuel-fired facilities since they emit
negligible amounts of sulfur dioxide.
To date, there have been two ways for
a source owner or operator to comply
with the sulfur dioxide standard: (1) By
firing low sulfur fossil fuels or (2) by
using flue gas desulfurlzation systems.
Complying with the standard by firing
low sulfur fossil fuel requires an ade-
quate supply of fuel with a sulfur con-
tent low enough to meet the standard.
However, it would be possible for the
owner or operator to fire, for example, a
relatively high sulfur fossil fuel with a
very low sulfur fossil fuel (e.g. natural
gas) to obtain a fuel mixture which
would meet the standard. The low sulfur
fuel adds to the heat input but not to
the sulfur dioxide emissions and, thereby,
has an overall fuel sulfur reduction ef-
fect. In the past, the application of Sub-
part D permitted the heat content of
fossil fuels but not wood residue to be
used in determining compliance with the
standards for particulate matter, sulfur
dioxide and nitrogen oxides; the amend-
ment made herein will allow the heat
content of wood residue to be used for
determining compliance with the stand-
ards. The amendment does not change
the scope of applicability of Subpart D;
all steam generating units constructed
after August 17. 1971, and capable of fir-
ing fossil fuel at a heat input rate of
more than 73 megawatts (250 million Btu
per hour) are subject to Subpart D.
RATIONALE FOR THE AMENDMENTS
Wood residue, which includes bark,
sawdust, chips, etc., is not a fossil fuel
and thus hns not been allowed for use as
a dilution agent in complying with the
sulfur dioxide standard for steam gener-
ators. Several companies have requested
that EPA revise Subpart D to permit
blending of wood residue with high sulfur
fossil fuels This would enable them to
obtain a fuel mixture low enough in sul-
fur to comply with the sulfur dioxide
standard. Since Subpart D allows the
blending of high and low sulfur fossil
fuels, EPA has concluded that it is rea-
sonable to extend application of this
principle to wood residue which, although
not a fossil fuel, does have low sulfur
content
Several companies have expressed in-
terest in constructing steam generators
which continuously fire wood residue in
combinntion with fossil fuel. New facili-
ties will comply with the standards for
less cost than at present because they,
will be able to use wood residue, a valu-
able source of energy, as an alternative to
expense low sulfur fossil fuels. Also,
using wood residue as a fuel supplement
instead of low sulfur fossil fuels will re-
IV-151
-------
RULES AND REGULATIONS
suit in substantial savings in the con-
sumption of scarce natural gas and oil
resources, and will relieve what would
otherwise be a substantial solid waste
disposal problem. Consumption of energy
and raw material resources will be re-
duced further by minimizing the need
for flue gas desulfurization systems at
new facilities. There will be no adverse
environmental impact; neither sulfur di-
oxide nor nitrogen oxides emissions will
increase as a result of this action. Con-
sidering the beneficial, environmental,
energy, and economic impacts, it is rea-
sonable to permit wood residue to be fired
as a low sulfur fuel to aid in compliance
with the standards for fossil fuel-fired
steam generators.
In making this amendment, EPA rec-
ognizes that affected facilities which
burn substantially more wood residue
than fossil fuel may have difficulty com-
plying with the 43 nanogram per joule
standard for particulate matter (0.1
pound per million Btu). There is not
sufficient information available at this
time to determine what level of particu-
late matter emissions is achievable; how-
ever, EPA is continuing to gather Infor-
mation on this question. If EPA deter-
mines that the particulate matter stand-
ard is not achievable, appropriate
changes will be made to the standard.
Any change would be proposed for pub-
lic comment; however, in the interim,
owners and operators will be subject to
the 43 nanogram per joule standard.
'F' FACTOR DETERMINATION
New facilities firing wood residue in
combination with fossil fuel will be sub-
ject to the emission and fuel monitoring
requirements of § 60.45 (as revised on
October 6, 1975, 40 FR 46250). The T'
factors listed in § 60.45(f) (4), which are
used for converting continuous monitor-
ing data and performance test data into
units of the standard, presently apply
only to fossil fuels. Therefore, 'F' fac-
tors for bark and wood residue have been
added to § 60.45(f) (4). Any owner or op-
erator who elects to calculate his own
'F' factor must obtain approval of the
Administrator.
INTERNATIONAL SYSTEM OF UNITS
In accordance with the objective to
Implement national use of the metric sys-
tem, EPA presents numerical values in
both metric units and English units in
its regulations and technical publica-
tions. In an effort to simplify use of the
metric units of measurements. EPA now
uses the International System of Units
(SI) as set forth in a publication by the
American Society for Testing and Ma-
terials entitled "Standard ton Metric
Practice" (Designation: E 380-76). The
following amendments to Subpart D re-
flect the use of SI units.
MISCELLANEOUS
Since these amendments are expected
to have limited applicability, no environ-
mental impact statement is required for
this rulemaking pursuant to section Kb)
of the "Procedures for the Voluntary
Preparation of Environmental Impact
Statements" (39 FR 37419).
This action is effective on November 22,
1976. The Agency finds that good cause
exists for not Duhhshing this action as a
notice of proposed rulemaking and for
making it effective immediately upon
publication because:
1. The action is expected to have lim-
ited applicability.
2. The action will remove an existing
restriction on operations without In-
creasing emissions and will have benefi-
cial environmental, energy, and eco-
nomic effects.
3. The action is not technically con-
troversial and does not alter the overall
substantive content of Subpart D.
4. Immediate effectiveness of the action
will enable affected parties to proceed
promptly and with certainty in conduct-
ing their affairs.
(Sees, ill, 114 and 301 (a) of the Clean Air
Act, as amended by section 4(a) of Pub.L.
91-604, 84 Stat 1678, and by section 16(c) (2)
of PubL. 91-604, 84 Stat. 1713 (42 U.8.C.
1857C-6, 1857C-9, 1857g(a)).)
Date: November 15,1976.
JOHN QUARLES,
Acting Administrator.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amended
as follows:
1. Section 60.40 is amended by revising
the designation of affected facility and
by substituting the International System
(SI) of Units as forows:
§ 60.40 Applicability and designation of
affected facility.
(a) The affected facilities to which the
provisions of this subpart apply are:
(1) Each fossil fuel-fired steam gener-
ating unit of more than 73 megawatts
heat input rate (250 million Btu per
hour).
(2) Each fossil fuel and wood residue-
fired steam generating unit capable of
firing fossil fuel at a heat input rate of
more than 73 megawatts (250 million Btu
per hour).
(b) Any change to an existing fossil
fuel-fired steam generating unit to ac-
commodate the use of combustible mate-
rials, other than fossil fuels as defined in
this subpart, shall not bring that unit
under the applicability of this subpart.
2. Section 60.41 is amended by adding
paragraphs (d) and (e) as follows:
§ 60.41 Definitions.
* *
(d) "Fossil fuel and wood residue-fired
steam generating unit" means a furnace
or boiler used in the process of burning
fossil fuel and wood residue for the pur-
pose of producing steam by heat transfer.
(e) "Wood residue" means bark, saw-
dust, slabs, chips, shavings, mill trim,
and other wood products derived from
wood processing and forest management
operations.
3. Section 60.42 is amended by revising
paragraph (a) (1) and by substituting SI
units in paragraph (a) (1) as follows:
§ 60.42 -Standard for paniculate mailer,
(a) * * *
(1) Contain particulate matter in ex-
cess of 43 nanograms per joule heat in-
put (0.10 Ib per million Btu) derived
from fossil fuel or fossil fuel and wood
residue.
*****
4. Section 60.43 is amended by revising
paragraphs (a)(l) and (a)(2), by sub-
stituting SI units in paragraphs (a)(l)
and (a) (2), arid by revising the formulei
in paragraph (b) as follows:
§ 60.43 Standard for gulfur dioxide.
(a) * * *
(1) 340 nanograms per joule heat In-
put (0 80 Ib per million Btu) derived
from liquid fos,sil fuel or liquid fossil fuel
and wood residue.
(2) 520 nanograms per joule heat in-
put (1.2 Ib per million Btu) derived from
solid fossil fuel or solid fossil fuel and
wood residue.
(b) When different fossil fuels are
burned simultaneously in any combina-
tion, the applicable standard (In ng/J)
shall be determined by proratlon using
the following formula:
y(340)+z(520)
y+z
PS8
where:
PSpoz is the prorated standard for sulfur
dioxide when burning different fuels
simultaneously, in nanograma per
joulo heat input derived from all
fossil fuels fired or from all fossil fuels
and wood residue fired,
y is the percentage of total heat input
derived from liquid fossil fuel, and
z is the percentage of total heat input
derived from solid fossil fuel.
* * *
5. Section 60.44 is amended by revising
paragraphs (a)(l), (a) (2), and (a) (3);
by substituting SI units In paragraphs
(aid), (a) (2), and (a) (3); and by re-
vising paragraph (b) as follows:
§ 60.44 Standard for nitrogen oxides.
(a) *
(1)86 nanograms per joule heat input
(0.20 Ib per million Btu) derived from
gaseous fossil fuel or gaseous fossil fuel
and wood residue.
(2) 13Q nanograms per joule heat In-
put (0.30 Ib per million Btu) derived
from liquid fossil fuel or liquid fossil fuel
and wood residue.
(3) 300 nanograms per joule heat In-
put (0.70 Ib per million Btu) derived
from solid fossil fuel or solid fossil fuel
and wood residue (except lignite or a
solid fossil fuel containing 25 percent,
by weight, or more of coal refuse).
(b) When different fossil fuels are
burned simultaneously in any combina-
tion, the applicable standards (in ng/J)
shall be determined by proration. Com-
pliance shall be determined by using toe
following formula:
FEDERAL »?0ISTH, VOL. 41, NO. 226MONDAY, NOVEMBER 22, 1976
IV-152
-------
RULES AND REGULATIONS
x (86)+y(l30)+t(300)
PSNO,=
where:
PSNO, is the prorated standard for nitro-
gen oxides when burning different
fuels simultaneously, in nanograms
per joule beat input derived from all
fossil fuels fired or from all fossil fuels
and wood residue fired,
x is the percentage of total heat input
derived from gaseous fossil fuel,
y is the percentage of total heat input
derived from liquid fossil fuel, and
i is the percentage of total heat input
derived from solid fossil fuel (except
lignite or a solid fossil fuel containing
25 percent, by weight, or more of coal
refuse).
When lignite or a solid fossil fuel con-
taining 25 percent, by weight, or more
of coal refuse is burned in combination
with gaseous, liquid, other solid fossil
fuel, or wood residue, the standard for
nitrogen oxides does not apply.
6. Section 60.45 is amended by sub-
stituting SI units In paragraphs (e),
(f)(l), (f>(2), (f)(4)(i), (f)(4)Ui), (f)
(4) (ill), (f)(4)(iv), (f)(5), and (f) (5)
(U), by adding paragraphs (f)(4)(v)
and (f) (5) (iii), and by revising para-
graph (f) (6) as follows:
§ 60.45 Emission and fuel monitoring.
* * *
(e) An owner or operator required to
install continuous monitoring systems
under paragraphs (b) and (c) of this
section shall for each pollutant moni-
tored use the applicable conversion pro-
cedure for the purpose of converting
continuous monitoring data into units of
the applicable standards (nanograms
per joule, pounds per million Btu) as
follows:
(f) *
(1) E=pollutant emissions, ng/J (lb/
million Btu).
(2) C=pollutant concentration, ng/
dscm (Ib/dscf), determined by multiply-
ing the average concentration (ppm) for
each one-hour period by 4.15x10' M ng/
dscm per ppm (2.59x10"' M Ib/dscf
per ppm) where M=pollutant molecu-
lar weight, g/g-mole (lb/lb-mole>. M=
64.07 for sulfur dioxide and 46.01 for ni-
trogen oxides.
*****
(4) * * *
(1) For anthracite coal as classified
according to A.S.T.M. D 388-66, F=
2.723x10-' dscm/J (10,140 dscf/million
Btu) and Fc=0.532xlO-7 scm CO,/J
(1,980 scf COs/mulion Btu).
(ii) For subbituminous and bituminous
coal as classified according to A.S.T.M. D
388-66, F=2.637X10-7 dscm/J (9,820
dscf/million Btu) and FC=0.486X1Q-7
scm COi/J (1,810 scf CO2/million Btu).
(iii) For liquid fossil fuels including
crude, residual, and distillate oils,
F=2.476xlO-'1 dscm/J (9,220 dscf/mil-
lion Btu) and Fc=0.384 scm COi/J
(1,430 scf CO2/million Btu).
(iv) For gaseous fossil fuels, F=2.347
X10-7 dscm/J 8,740 dscf/million Btu).
For natural gas, propane, and butane
fuels, FC=0.279X10-7 scm COi/J (1,040
scf COj/mlllion Btu) for natural gas,
0.322 XIO"7 scm COa/J (1,200 scf CO3/
million Btu") for propane, and 0.338 X10"7
scm COz/J (1,260 scf COa/million Btu)
for butane.
(v) For bark F= 1.076 dscm/J (9,575
dscf/million Btu) and Fc=0.217 dscm/J
(1,927 dscf/million Btu). For wood resi-
due other than bark F= 1.038 dscm/J
(9.233 dscf/million Btu) and Fc=0.207
dscm/J (1,842 dscf/million Btu).
(5) The owner or operator may use the
following equation to determine an F
factor (dscm/J or dscf/million Btu) on
a dry basis (if it is desired to calculate F
on a wet basis, consult the Administra-
tor) or Fc factor (scm COi/J, or scf COa/
million Btu) on either basis in lieu of the
F or Fc factors specified in paragraph
(f)(4) of this section:
, 227.0(%g)+95.7(%C)+35.4(%5)+8.6(%AT)-28.5(%0)
~ GCV
(SI units)
10«t3.64(y0tf)+1.53(%C)+0.57(%S)-r-0.14(%N)-0.46(%Q)l
GCV
(English units)
_20.0(%C)
e~ GCV
(SI units)
=321X10i(%C)
GCV
(English units)
(i)
(ii) GCV is the gross calorific value
(kJ/kg, Btu/lb) of the fuel combusted,
determined by the A.S.T.M. test methods
D 2015-66(72) for solid fuels and D 1826-
64(70) for gaseous fuels as applicable.
(iii) For affected facilities which fire
both fossil fuels and nonfossil fuels, the
F or Fc value shall be subject to the
Administrator's approval.
(6) For affected facilities firing com-
binations of fossil fuels or fossil fuels and
wood residue, the F or F. factors deter-
mined by paragraphs (f ) (4) or (f ) (5) of
this section shall be prorated in accord-
ance with the applicable formula as fol-
lows:
or Fe='
where :
Jfi = the fraction of total heat input
derived from each type of fuel
(e.g. natural gas. bituminous
coal, wood residue, etc.)
Fi or (F,) i =the applicable F or Fc factor for
each fuel type determined in
accordance with paragraphs
(f) (4) and (f) (6) of this
section.
rarrthe number of fuels being
burned In combination.
*****
7. Section 60.46 is amended by sub-
stituting SI units in paragraphs (b) and
(f ) and paragraph (g) is revised as fol-
lows:
§ 60.46 Test methods and procedures.
*****
For Method 5. Method 1 shall be
used to select the 'sampling site and the
number of traverse sampling points. The
sampling time for each run shall be at
least 60 minutes and the minimum
sampling volume shall be 0.85 dscm (30
dscf) except that smaller sampling times
or volumes, when necessitated by process
variables or other factors, may be ap-
proved by the Administrator. The probe
and filter holder heating systems in the
sampling train shall be set to provide a
gas temperature no greater than 433 K
(320°F).
*****
(f) For each run using the methods
specified by paragraphs (a) (3), (a) (4),
and
-------
rate by a material balance over the steam
generation system.
(Sections 111, 114, and 301 (a) of the Clean
Al Act as amended by section 4(a) of Pub L.
91-604, 84 Stat. 1678 and by section 15(c> (2)
of Pub. L. 91-604, 84 Stat. 1713 (42 U.S.C.
1857C-6, 1857C-9, 1857g(a)).
|FR Doc.76-33966 Filed 11-19-76:8:45 am)
f (tie 40Protection of Environment
CHAPTER IENVIRONMENTAL
PROTECTION AGENCY
[FRL 639-2]
PART 60STANDARDS Of PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Amendments to Reference Methods 13A
and 133
On August 8, 1975 (40 FR 33151), the
Environmental Protection Agency (EPA)
Promulgated Reference Methods 13A and
13B in Appendix A to 40 CFR Part 60.
Methods 13A and 13B prescribe testing
and analysis procedures for fluoride
emissions from stationary sources. After
promulgation of the methods, EPA con-
tinued to evaluate them and as a result
has determined the need for certain
amendments to improve the accuracy
and precision of the methods.
Methods 13A and 13B require assembly
of the fluoride sampling train so that
the filter is located either between the
third and fourth impingers or in an
optional location between the probe and
first impinger. They also specify that a
fritted glass disc be used to support the
filter. Since promulgation of the meth-
ods, EPA has found that when a glass
frit filter support is used in the optional
filter location, some of the fluoride
sample is retained on the glass. Although
no tests have been performed, it is be-
lieved that fluoride retention may also
occur if a sintered metal frit filter sup-
port is used. However, in tests performed
using a 20 mesh stainless steel screen
as a filter support no fluoride retention
was noted. Therefore, to eliminate the
possibility of fluoride retention, sections
5.1.5 and 7.1.3 of Methods 13A and 13B
are being revised to require the use of
a 20 mesh stainless steel screen filter
support if the filter is located between
the probe and first impinger. If the filter
is located in the normal position between
the third and fourth Impingers, the glass
frit filter support may still be used.
In addition to the changes to sections
5.1.5 and 7.1.3. a few corrections are also
being made. The amendments promul-
gated herein are effective on November
29, 1976. EPA finds that good cause exists
for not publishing this action as a notice
of proposed rulemaking and for making
it effective immediately upon publication
because:
RULES AND REGULATIONS
1. The action is intended to Improve
the accuracy and precision of Methods
13 A and 13B and does not alter the
overall substantive content of the meth-
ods or the stringency of standards of
performance for fluoride emissions.
2. The amended methods may be used
immediately in source testing for fluoride
emissions.
Dated: November 17,1976.
JOHN QUARLES,
Acting Administrator.
In Part 60 of Chapter I. Title 40 of the
Code of Federal Regulations, Appendix
A is amended as follows:
1. Reference Method 13A is amended
as follows:
(a) In section 3., the phrase "300
pg/Ilter" is corrected to read "300 rag/
liter" and the parenthetical phrase "(see
section 7.3.6)" is corrected to read "(see
section 7.3.4)".
(b) Section 5.1.5 is revised to read as
follows:
S.I.6 Filter holderIf located between the
probe and first Impinger, borosllleate glass
with & 20 mesh stainless steel screen alter
support and a slllcone rubber gasket; neither
a glass frit filter support nor a sintered metal
filter support may be used If the fllter U In
front of the Impingers. If located between
the third and fourth Impingers, borosllleate
glass with a glass frit fllter support and a
slllcone rubber gasket. Other materials of
construction may be used with approval from
the Administrator, e g., If probe liner Is stain-
less steel, then fllter holder may be stainless
steel. The holder design shall provide a posi-
tive seal against leakage from the outside or
around the filter.
(c) Section 7.1.3 is amended by re-
vising the first two sentences of the sixth
paragraph to read as follows:
7 1.3 Preparation of collection train.
Assemble the train aa shown In Figure
13A-1 with the filter between the third and
fourth Impingers. Alternatively, the fllter
may be placed between the probe and first
Impinger If a 20 mesh stainless steel screen
Is used for the fllter support.
(d) In section 7.3.4, the reference in
the first paragraph to "section 7.3.6" Is
corrected to read "section 7.3.5".
2. Reference Method 13B Is amended
as follows:
(a) In the third line of section 3, the
phrase "300^g/liter" is corrected to read
"300 mg/liter".
(b) Section 5.1.5 is revised to read as
follows:
5 1.5 Filter holder
-------
RULES AND REGULATIONS
51
Title 40Protection of Environment
CHAPTER IENVIRONMENTAL
PROTECTION AGENCY
52
SUSCHAFTER CAIR PROGRAMS
[FRL65I-5]
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Delegation of Authority to Pima County
Health Department On Behalf of Pima
County Air Pollution Control District
Pursuant to the delegation of author-
ity for the standards of performance for
new stationary sources (NSPS> to t!\e
Pima County Health Department on be-
half of the Pima County Air Pollution
Control District, dated October 7, 1976,
EPA Is today amending 40 CFR 60.4
Address, to reflect this delegation A
document announcing this delegation
is published today at 41 FR in the Notices
section of this issue. The amended
§ 60.4 is set forth below. It adds the ad-
dress of the Pima County Air Pollution
Control District, to which must be ad-
dressed all reports, requests, applications,
submittals, and communications pursu-
ant to this part by sources subject to the
NSPS located within this Air Pollution
Control District.
The Administrator finds good cause for
foregoing prior public notice and for
making this rulemaking effective Imme-
diately in that it Is an administrative
change and not one of substantive con-
tent. No additional substantive burdens
are imposed on the parties affected. The
delegation which is reflected by this ad-
ministrative amendment was effective on
October 7, 1976 and It serves no purpose
to delay the technical change on this
addition of the Air Pollutioa Control
District's address to the Code of Federal
Regulations.
This rulemaking is effective immedi-
ately, and Is issued under the authority
of Section 111 of the Clean Air Act. as
amended (42 U.S.C. 1867C-6).
Dated: November 19, 1976
Pv. L. O'COtlNELL.
Acting Regional Administrator.
Environmental Protection
Agency, Region IX.
Part 60 of Chapter I,- Title 40 of the
Code of Federal Regulations is amended
as follows:
1. In § 60.4 paragraph (b) Is amended
by adding subparagraph D to read as
follows:
§ 60.1 Address.
(3) * * *
(A)-(C)
DArizona
Pima County Air Pollution Control Dis-
trict, 151 West Congre
FRIDAY, D6<":M3£1 3, 1976
[PRL 657-3J
PART 60 STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Delegation of Authority to State of Califor-
nia on Behalf of San Diego County Air
Pollution Control District
Pursuant to the delegation of authority
for the standards of performance for
new stationary sources (NSPS) to the
State of California on behalf of the San
Diego County Air Pollution Control Dis-
trict, dated November 8, 1976. EPA is
today amending 40 CFR 60.4 Address, to
reflect this delegation. A Notice announc-
ing this delegation is published in the
Notices section of this issue, under EPA
(PR Doc. 76-36929 at page 54798)., The
amended 5 60.4 is set forth below. It adds
the address of the San Diego County Air
Pollution Control District, to which must
be addressed all reports, requests, appli-
cations, submittals, and communications
pursuant to this part bv sources subject
to the NSPS located within this Air Pol-
lution Control District.
The Administrator finds good cause
for foregoing prior public notice and for
making this rulemaking effective Imme-
diately In that It is an administrative
change and not one of substantive con-
tent. No additional substantive burdens
are imposed on the parties affected. The
delegation which is reflected in this ad-
ministrative amendment was effective on
November 8. 1976 and it serves no pur-
pose to delay the technical change on
this addition of the Air Pollution Control
District's address to the Code of Federal
Regulations.
This rulemaking is effective immedi-
ately, and is Issued under the authority
of section 111 of the Clean Air Act, as
amended (42 U.S.C. 1857c-6).
Dated: November 26. 1976.
Monterey Bay Unified Air Pollution Control
District, 420 Church Street (P.O. Box 487)
Salinas, CA 03901.
Northern Sonoma County Air Pollution
Control District, 3313 Chanate Road, Santa
Rosa, CA 95404.
Sacramento County Air Pollution Control
District, 3701 Branch Center Road, Sacra'
mento, CA 95827.
San Diego County Air Pollution Control
District, DIM Ohesapeak* Drive, San Diego.
CA 93133.
San Joaquiu County Air Pollution Control
District, 1601 E. Hazelton Street (P.O. Box
2000) Stockton, CA 95201.
Santa Barbara County Air Pollution Con-
trol District, 4440 Calle Real, Santa Barbara
CA 93110 .
Stanlslt-.ua County Air Pollution Control
District, 820 Scenic Drive, Modesto, CA 96350.
Trinity Couuty Air Pollution Control Dis-
trict, Box AJ, Weaverviile, CA 96093.
Ventura County Air Pollution Control Dis-
trict, 626 E. Santa Clara Street, Ventura, CA
93001.
* * * *
|FB Doc,.76 36025 Filed 12-14-76,8:45 am|
KDUAL ftEOICTM. VOl. 41, NO. 242
WEDNESDAY, DECEMBER 15, 1976
SHELIA M.
Acting Regional Administrator.
Environmental Protection
Agency, Region IX.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amended
as follows:
1. In § 60.4 paragraph (b) la amended
by revising subparagraph P to read as
follows :
§ 60.4 Ad * *
-------
53 [FHL 661-6)
PART 60STANDARDS OF PERFORM
ANCE FOR NEW STATIONARY SOURCES
Delegation of Authority to the State of Ohio
Pursuant to the delegation of authority
to Implement the standards of per-
i.". evince for new stationaiy sources
VSPS> to the- State of Ohio on August 4.
I'.1!''! HPA is U'dny amending 40 CFR
104 Address to relied this delegation.
A Notice announcing this delegation is
; ,ib';:-iK'd in tlie Notices section of this
i^Mie of the FEDERAL REGISTEK is amended
by revising subparagraph KK, to read
as follows:
§ 60. i Ad«Irr«.
*****
ib) * * *
* * *
(Al-(HH) '
(II) North Carolina Em irontnental Mun-
agement Commission. Department ot Natural
and Economic Resources, Division of Envi-
ronmental Management, P.O. Box 27887, Ra-
leigh, North Carolina 27611. Attention: Air
Quality .Section.
SUBCHAPTER CAIR PROGRAMS
IFRL664-3]
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Delegation of Authority to Slate of
Nebraska
Pursuant to the delegation of author-
ity for the Standards of Performance
for New Stationary Sources , to
the State of Nebraska on November 24.
1975. the Environmental Protection
Agency (EPA) is today amending 40 CFR
60.4, [Address.], to reflect this delega-
tion. A notice announcing this delegation
Is published (December 30. 1976), in the
FEDERAL REGISTER. Effective immediately
all requests, reports, applications, sub-
mittals, and other communications con-
cerning the 12 source categories of the
17-156
-------
NSPS which were promulgated Decem-
ber 23, 1971, and March 8. 1974, shall
be sent to Nebraska Department of En-
vironmental Control (DEC), P.O. Box
94653, State House Station, Lincoln,
Nebraska 68509. However, reports re-
quired pursuant to 40 CFR 60.7(a5 shall
be sent to EPA, Region VII, 1735 Balti-
more, Kansas City, Missouri 64108, as
well as to the State.
The Regional Administrator finds good
cause for forgoing prior public notice
and making this rulemaking effective
immediately in that it is an administra-
tive change and not one of substantive
content. No additional substantive bur-
dens are imposed on the parties affected.
This delegation, which is reflected by this
administrative amendment, was effective
on November 24, 1975, and it serves no
purpose to delay the technical change of
this addition of the State address to the
Code of Federal Regulations.
This rulemaking is effective imme-
diately, and is issued under the author-
ity of Section 111 of the Clean Air Act,
as amended.
(42 U.S.C. 1857C-6.)
Dated: December 20,1976.
JEROME H. SVORE,
Regional Administrator.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amended
as follows:
1. In § 60.4 paragraph (b) is amended
by revising subparagraph (CO to read
as follows:
§ 60.4 Address.
*****
(b) * ' *
(A)-(BB) * * *
(CO Nebraska Department of Envi-
ronmental Control, P.O. Box 94653, State
House Station, Lincoln, Nebraska 68509.
IFRDoc.76-38234 Filed 12-29-76,8:45 am]
IFBL 664-6)
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Delegation of Authority to the State of
Iowa
Pursuant to the delegation of author-
ity for New Source Performance Stand-
ards (NSPS) to the State of Iowa on
June 6, 1975, the Envii onmental Protec-
tion Agency is today amending 40 CFR
60.4, [Address.] to reflect this delegation.
A. notice announcing this delegation is
published (December 30, 1976), in the
FEDERAL REGISTER.
The amended § 60 4 provides that all
reports, requests, applications, submit-
tals, and other communications required
for the 11 source categories of the NSPS,
which were delegated to the State, shall
be sent to the Iowa Department of Envi-
ronmental Quality (DEQ), 3920 Delaware
Avenue, P O. Box 3326. Des Moines. Iowa
50316. However, reports required pur-
suant to 40 CFR 60.7'a) shall be sent to
EPA, Region VII, 1735 Baltimore, Kan-
sas City, Missouri 64108, as well as to the
State.
RULES AND REGULATIONS
The Regional Administrator finds good
rau.se to forgo prior public notice and
make this rulemaking effective immedi-
ately in that it is an administrative
change and not one of substantive con-
tent. The delegation was effective June 6,
1975, and it serves no purpose to delay
the technical change of the addition of
the State address to the Code of Federal
Regulations.
This rulemaking is effective immedi-
ately and is issued under the authority
of Section 111 of the Clean Air Act, as
amended.
(42 USC. 1857C-G.)
Dated: December 20, 1976.
JEROME H. SVORE.
Regional Administrator.
Part 60 of Chapter 1, Title 40 of the
Code of Federal Regulations is amended
as follows:
1. In § 60 4, paragraph
-------
RULES AND REGULATIONS
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
DELEGATION OF AUTHORITY TO THE STATE
OF SOUTH CAROLINA
2. Part 60 of Chapter I, Title 40, Code
of Federal Regulations, is amended by
revising subparagraph *
(A)-(OO) ' ' '
(PP) State ol South Carolina, Oilier of
Environmental Quality Control, Department
of Health and Environmental Control, 2GOO
Bull Street, Columbia, South Carolina 29201.
Title 40Protection of Environment
CHAPTER IENVIRONMENTAL
PROTECTION AGENCY
SUBCHAPTER CAIR PROGRAMS
[FRL 673-6)
NEW SOURCE REVIEW
Delegation of Authority to the State of
South Carolina
The amendments below institute cer-
tain address changes for reports and ap-
pllcafUons required from operators of new
sources. EPA has delegated to the State
of South Carolina authority to review
new and modified sources. The delegated
authority includes the reviews under 40
CFR Part 52 for the prevention of sig-
nificant deterioration. It also includes
the review under 40 CFR Part 60 for the
standards of performance for new sta-
tionary sources and review under 40 CFR
Part Cl for national emission standards
for hazardous air pollutants.
A notice announcing the delegation of
authority is published elsewhere in the
notices section of this Issue of the FED-
F.HAI. REGISTER. These amendments pro-
vide that all reports, requests, applica-
tions, submittnls, and communications
previously required for the delegated
reviews will now be sent to the Office of
Environmental Quality Control, Depart-
partment of Health and Environmental
Control, 2600 Bull Street, Columbia,
South Carolina 29201, instead of EPA's
Region IV.
The Regional Administrator finds
good cause for foregoing prior public
notice and for making this rulemaking
effective immediately In that It Is an ad-
ministrative change and not one of sub-
stantive comV'i't. No additional substan-
tive burdens we imposed on the parties
affected. The delegation which is reflect-
ed by this administrative amendment
was effective on October 19, and It
serves no purpose to delay the technical
change of this addition of the State ad-
dress to the Code of Federal Regula-
tions.
This rulemaking is effective immedi-
ately, and is issued under the authority
of sections 101, 110, 111, 112, and 301
of the Clean Air Act, as amended, 42
U.S.C. 1857c-5, 6, 7 and 1857g.
Dated: January 11, 1977.
JOHN A. LITTLE,
Acting Regional Administrator.
FEDERAL REGISTER, VOL 42, NO. 15-MONDAY, JANUARY 24, 1977
NOTICES
ENVIRONMENTAL PROTECTION
AGENCY
|FBL 675-4]
AIR PROGRAMSSTANDARDS OF PER-
FORMANCE FOR NEW STATIONARY
SOURCES
Receipt of Application and Approval of
Alternative Performance Test Method
On January 26, 1976 (41 FR 3826), the
Environmental Protection Agency (EPA)
promulgated standards of performance'
for new primary aluminum reduction
plants under 40 CFR Part 60. The stand
ards limit air emissions of gaseous and
particulate fluorides from new and modi-
fied primary aluminum reduction plants.
The owners or operators of affected fa-
cilities are required to determine com-
pliance with these standards by conduct-
ing a performance test as specified in Ap-
pendix AReference Methods, Method
13A or 13B, "Determination of Total
Fluoride Emissions from Stationary
Sources" published in the FEDERAL REG-
ISTER August 6, 1975 (40 FR 33157). As
provided in 40 CFR 60.8(b), (2) and (3),
the Administrator may approve the use
of an equivalent test method or may ap-
prove the use of an alternative method
if the method has been shown to be ade-
quate for the determination of compli-
ance with the standard. Method 13A
specified that total fluorides be deter-
mined by the EPADNS Zirconium Lake
colormetric method, and Method 133
specified that this determination be made
by the specific Ion electrode method.
On September 3, 1976. EPA received
written application for approval of equiv-
alency for a third analytical technique
from Kaiser Aluminum and Chemical
Corporation, Oakland, California. Specil-
Ically, the application requested approv-
al of ASTM Method D 3270-73T, "Ten-
tative Method of Analysis for Fluoride
Content of the Atmosphere and Plant
Tissues," 1974 Annual Book of ASTM
StandardsPart 26.
Specific guidelines for the determina-
tion of method equivalency have not been
established by EPA. However, EPA has
completed a technical review of the ap-
plication and has determined that tiie
ASTM method will produce results ad-
equate for the determination of compli-
ance with the standards of performance
for new primary aluminum plants.
Therefore, EPA approves the ASTM
method as an alternative to the analyt-
ical procedures specified in paragraph
7.3 "Analysis" of Method 13A or 13B for
aluminum plants, pursuant to 40 CFR
60.8
-------
Tllli! 40-Prolcclion of environment
CHAPTER ILNVIRONMENTAL
PROTECTION AGENCY
IFIiL (ion-4 |
PART 60STANDARDS OF PERFORMANCE
FOR NEW STATIONARY SOURCES
Revisions to Emission Monitoring
Requirements and to Reference Methods
On October 6, 1975 (40 PR 46250),
under sections 111, 114, and 301 of the
Clean Air Act, as amended, the Envi-
ronmental Protection Agency (EPA)
promulgated emission monitoring re-
quirements and revisions to the perform-
ance testing Reference Methods in 40
CFR Part 60. Since that time, EPA has
determined that there is a need for a
number of revisions to clarify the re-
quirements. Each of the revisions being
made in 40 CPR Part 60 are discussed
as follows:
1. Section 60.13. Paragraph (c) (3) has
been rewritten to clarify that not only
new monitoring systems but also up-
graded monitoring systems must comply
with applicable performance specifica-
tions.
Paragraph (e) (1) is revised to provide
that data recording is not required more
frequently than once every six minutes
(rather than the previously required ten
seconds) for continuous monitoring sys-
tems measuring the opacity of emissions.
Since reportsi of excess emissions are
based upon review of six-minute aver-
ages, more frequent data recording is
not required in order to satisfy these
monitoring requirements.
2. Section 60.45. Paragraphs (a)
through 'e) have been reorganized for
clarification. In addition, restrictions on
use of continuous monitoring systems for
measuring oxygen on a wet basis have
been removed. Prior to this revision, only
dry basis oxygen monitoring equipment
was acceptable. Procedures for use of wet
basis oxygen monitoring equipment have
been approved by EPA and were pub-
lished in the FEDERAL REGISTER as an al-
ternative procedure (41 FR 44838).
Also deleted from § 60.45 are restric-
tions on the location of a carbon dioxide
(CO.) continuous monitoring system
downstream of wet scrubber flue gas de-
sulfunzation equipment At the time the
regulations were / promulgated (Octo-
ber G. 1975), EPA thoiiKht that limestone
scrubbers were operated under condi-
tions that, could cause significant gen-
eration or absorption of CO by the
scrubbing solution which would cause
errors in the monitoring results EPA in-
vestigated this potential problem and
concluded that lime or limestone scrub-
bers under typical conditions of opera-
tion do not significantly alter the con-
centration of CO. in the flue gas and
would not 'introduce significant errors
into thr monitoring result s. Lime scrub-
bers operate at a pH level between 7 and
8 which will maximize SO absorption
and minimize CO. absorption. Thus, the
effect of CO_ loss on the emission results
is expected to be minimal The exact
amount of CO loss, if any. during the
scrubber operation has not been deter -
RULES AND REGULATIONS
mined f.liifo It 1;> dciii'iidenl, upon the
tipiTallni; (.ondlUun:, lor a p;irtl< ular la-
cihty Although each percent of CO_- ab-
sorption will result in a positive bias of
7.1 percent (at a stack concentration of
14 percent CO.) in the final emission
results, i.e. the indicated results may be
higher than actual stack concentrations,
the actual bias is expected to be very
small since the amount of CO; absorp-
tion will be much less than one percent.
In flue gases from limestone scrubbers,
there exists a possibility of the addition
of CO, from the scrubbing reaction to
the CO2 from the fuel combustion. Every
two molecules of SO, reacting with the
limestone will produce a molecule of CO,.
Limestone scrubbers are typically oper-
ated at an approximate temperature of
50° C under acidic conditions. At these
operating conditions the amount of CO,
generated in a 90 percent efficiency
scrubber is 1350 ppm or 0.135 percent
CO,. This will introduce a negative bias
of 1 to 1.5 percent for a CO: level of 8 to
15 percent This amount of potential
error compares favorably with systems
previously approved Therefore. EPA is
removing the restrictions which limited
the installation of carbon dioxide con-
tinuous monitoring svstems to a location
upstream of the scrubber.
Several other revisions are being made
to paragraphs (a), 'b), (c), and 'e) of
Subnart D which imnrove the clarity or
further define the intent of the regula-
tions. Paragraph (d) has been reserved
for later addition of fuel monitoring pro-
visions.
3. Performance Specification 1. Para-
graph 6.2 has been rewritten to clarify
requirements that must be met by con-
tinuous opacity monitor manufacturers.
Manufacturers must certify that at least
one analyzer from each month's produc-
tion was tested and meets all applicable
requirements. If any requirements are
not met, the production for the month
must be resampled according to mi'itarv
standard 10SD (MIL-STD-105D1 and re-
tested Previously the regulation re-
quired that each unit of nroduct'on had
to be tested Copies of MIT,-STD-10SD
may be purchased from the Superintend-
ent of Documents. US. Government
Printing Office. Washinrton DC. ?0402.
4. Performance Specification 2, Figure
2-3 of Performance Specification 2 has
been corrected to properly define the
term "mean differences." The corrections
in the operations now conform with the
statistical definitions of the specifica-
tions.
5. General. These amendments pro-
vide optional monitoring procedures that
may be selected by an owner or operator
of a facility affected by the monitoring
requirements of 40 CFR Part 60. Certain
editorial clarifications arc also included.
Proposal of these amendments is not
necessary because the chances are either
interpretative in nature, or represent
minor changes in instrumentation test-
ing and data recording, or allow a wider
selection of equipment to be used These
changes will have no effect upon the
number of emission sources that must be
monitored or the quality of the resultant
cml'i.'ilon data. The channes ixro consist-
ent with recent determinations of the
Admir.i.strator with respect to use of al-
ternative continuous monitoring systems.
G. Effective date. These revisions be-
come effective March 2, 1977.
(Kccs 111, 114. 301(a). Clean Air Act. as
amended, Pub. L. 91-G04, 84 Stat. 1678 (42
U.SC. 1857C-6. 1857C-9, 1857g(a)).)
NOTE.The Environmental Protection
Agency has determined that this document
does not contain a major proposal requiring
preparation of an Inflation Impact State-
ment under Executive Order 11821 and OMB
Circular A-107.
Dated: January 19, 1977.
JOHN QUARLES,
Acting Administrator.
In 40 CFR Part 60 Subpart A, Subpart
D, and Appendix B are amended as fol-
lows:
Subpart AGeneral Provisions
1. Section 60.13 is amended by revis-
ing paragraphs (c) (3) and (e)(l) as
follows:
§ 60.13 Monitoring requirements.
(C) * « *
(3) All continuous monitoring systems
referenced by paragraph (c) (2) of this
section shall be upgraded or replaced < if
necessai'y) with new continuous moni-
toring systems, and the new or improved
systems shall be demonstrated to com-
ply with applicable performance speci-
fications under paragraph (c) (1) of this
section on or before September 11, 1979.
*****
(e) * * *
(1) All continuous monitoring sys-
tems referenced by paragraphs (c) (1)
and (c) (2) of this section for measuring
opacity of emissions shall complete a
minimum of one cycle of sampling and
analyzing for each successive ten-second
period and one cycle of data recording
for each successive six-minute period.
*****
Subpart DStandards of Performance for
Fossil Fuel-Fired Steam Generators
2. Section 60.45 is amended by revising
paragraphs (a), (b), (c),and (e) and by
reserving paragraph (d) as follows:
§ 60.45 Emission aiitl fuel monitoring.
'a) Each owner or operator shall in-
stall, calibrate, maintain, and operate
continuous monitoring systems for meas-
uring the opacity of emissions, sulfur
dioxide emissions, nitrogen oxides emis-
sions, and either oxygen or carbon di-
oxide except a.s provided in paragraph
of this section.
(b) Certain of the continuous moni-
toring system requirements under para-
graph i a) of this section do not apply
to owners or operators under the follow-
ing conditions:
11) For a fossil fuel-fired steam gen-
erator that burns only gaseous fossil
fuel, continuous monitoring systems for
measuring the opacity of emissions and
sulfur dioxide emissions are not re-
quired.
FEDERAL REGISTER, VOL. 42, NO. 20MONDAY, JANUARY 31, 1977
IV-159
-------
RULES AND REGULATIONS
(2) For a fossil fuel-fired steam gen-
erator that docs not use a flue gas de-
sulfurization device, a continuous moni-
toring system for measuring sulfur di-
oxide emissions is not required if the
owner or operator monitors sulfur di-
oxide emissions by fuel sampling and
analysis under paragraph (d) of this
section.
(3) Notwithstanding § 60.13(Tot, in-
stallation of a continuous monitoring
system for nitrogen oxides may be de-
layed'until after the initial performance
tests under § 60.8 have been conducted.
If the owner or operator demonstrates
during the performance test that emis-
sions of nitrogen oxides are less than 70
percent of the applicable standards in
§ 60.44, a continuous monitoring system
for measuring nitrogen oxides emissions'
is not required. If the initial performance
test results show that nitrogen oxide
emissions are greater than 70 percent of
the applicable standard,! the owner or
operator shall install a continuous moni-
toring system for nitrogen oxides within
one year after the date of the initial per-
formance tests under § 60.8 and comply
with all other applicable monitoring re-
quirements under this part.
(4) If an owner or operator does not
install any continuous monitoring sys-
tems for sulfur oxides and nitrogen ox-
ides, as provided under paragraphs (b)
(1) and (b) (3) or paragraphs (b) (2)
and (b) (3) of this section a continuous
monitoring system for measuring either
oxygen or carbon dioxide is not required.
(c) For performance evaluations un-
der 560.13(c) and calibration checks
under §60.13(d>, the following proce-
dures shall be used:
(1) Reference Methods 6 or 7, as ap-
plicable, shall be used for conducting
performance evaluations of sulfur diox-
ide and nitrogen oxides continuous mon-
itoring systems.
(2) Sulfur dioxide or nitric oxide, as
applicable, shall be used for preparing
calibration gas mixtures under Perform-
ance Specification 2 of Appendix B to
this part.
(3) For affected facilities burning fos-
sil fuel(s), the span value for a continu-
ous monitoring system measuring the
opacity of emissions shall be 80, 90, or
100 percent and for a continuous moni-
toring system measuring sulfur oxides or
nitrogen oxides the span value shall be
determined as follows:
|In parti per million)
Fossil lael Spnn value (or
sulfur dioxide
Gas (i)
Liquid _. .. 1,000
Solid 1 600
Combinations.. l,000|H-l,500z
1 Not applicable.
where:
Span value for
nitrogen oxides
500
600
600
500(i+f)-H,OOOz
(4) All span values computed under
paragraph (c) (3) of this section for
burning combinations of fossil fuels shall
be rounded to the nearest 500 ppm.
(5) For a fossil fuel-fired steam gen-
erator that simultaneously burns fossil
fuel and nonfossil fuel, the span value
of all continuous monitoring systems
shall be subject to the Administrator's
approval.
(d) [Reserved]
(e) For any continuous monitoring
system installed under paragraph (a) of
this section, the following conversion
procedures shall be used to convert the
continuous monitoring data into units of
the applicable standards (ng/J, Ib/mil-
lion Btu):
(1) When a continuous monitoring
system for measuring oxygen is selected,
the measurement of the pollutant con-
centration and oxygen concentration
shall each be on a consistent basis (wet
or dry). Alternative procedures ap-
proved by the Administrator shall be
used when measurements are on a wet
basis. When measurements are on a dry
basis, the following conversion procedure
shall be used:
r 20.9 I
L 20.9-percent Oj
where:
E, C, F, and %0, are determined under para-
graph (f) of this section.
(2) When a continuous monitoring
system for measuring carbon dioxide is
selected, the measurement of the pol-
lutant concentration and carbon dioxide
concentration shall each be on a con-
sistent basis (wet or dry) and the fol-
lowing conversion procedure shall be
used:
T 100
E=CFC
Lpercent C0;
where:
E, C, Fc and %CCX are determined under
paragraph (f) of this section.
APPENDIX BPERFORMANCE
SPECIFICATIONS
3. Performance Specification 1 is
amended by revising paragraph 6.2 as
follows:
62 Conformance with the requirement
of section 6.1 may be demonstrated by the
owner or operator of the affected facility by
testing each analyzer or by obtaining a cer-
tificate of conlormance from the Instrument
manufacturer. The certificate must certify
that at least one analyzer from each month's
production was tested and satisfactorily met
all applicable requirements. The certificate
must state that the first analyzer randomly
sampled met all requirements of paragraph
6 of this specification. If uny of the require-
ments were not met, the certificate must
show that the entire month's analyzer pro-
duction was resampled according to the mili-
tary standard 105D sampling procedure
(MTL-STD-105D) Inspection level II; was re-
tested for each of the applicable require-
ments under paragraph 6 of this specifica-
tion; and was determined to be acceptable
under MIL-STD-105D procedures. The certifi-
cate of conformance must show the results
of each test performed for the analyzers
sampled during the month the analyzer be-
ing Installed was produced.
4. Performance Specification 2 is
amended by revising Figure 2-3 as
follows:
Test
No.
1
1
3
4
5
e
7
e
9
lean
fit
)Sl (
kccur
£x(
Date
and
Time
Reference Method Samples
SO,
Sampfe 1
(PP»)
NO
Sample 1
(ppn)
1
l
reference r
value (S02
onfldence 1
ethod
ntervals
NO ; NO
SampTe 2 ! Sampfe 3
(ppm) | (pptn)
|
NO Sample
Average
(ppm)
1
!
Analyzer 1-Hour
Average (ppm)*
soz NOX
I
Mean reference method
test value (NCJ
ppm (SO,) t
lean of the "ifffrences » 95, conndence~1nterv«l ,^ .
at<" " " Mean reference method value .,..-_
lain and report method used to determine Integrated averages
V
Difference
(pp»)
S02 m>
Mean of
* tlie differences
. ppm
* iso2
"V
» (NOX)
x the fraction of total heat Input derived
from gaseous fossil fuel, and
y-=the fraction of total heat Input derived
from liquid fossil fuel, and
z=the fraction of total heat Input derived
from solid fossil fuel.
Figure 2-3. Accuracy Determination (S02 and NO^)
(Sees. 111. 114, 301 (a), Clean Air Act. as amended. Pub. L. Sl-604, 84 Stat. 1878 (42 U.S.C.
1857C-6, 1857-9. 1857g(a))).
[PR Doo.77-2744 Ittled 1-38-77:8:45 am)
FEDERAL REGISTER, VOL. 42, NO. 20MONDAY, JANUARY 31, 1977
IV- 160
-------
NSPS which were promulgated Decem-
ber 23, 1971, and March 8, 1974, shall
be sent to Nebraska Department of En-
vironmental Control (DEC), P.O. Box
94653, State House Station, Lincoln,
Nebraska 68509. However, reports re-
quired pursuant to 40 CFR 60.7(a5 shall
be sent to EPA, Region VII, 1735 Balti-
more, Kansas City, Missouri 64108, as
well as to the State.
The Regional Administrator finds good
cause for forgoing prior public notice
and making this rulemaking effective
immediately in that it is an administra-
tive change and not one of substantive
content. No additional substantive bur-
dens are imposed on the parties affected.
This delegation, which is reflected by this
administrative amendment, was effective
on November 24. 1975, and it serves no
purpose to delay the technical change of
this addition of the State address to the
Code of Federal Regulations.
This rulemaking is effective imme-
diately, and is issued under the author-
ity of Section 111 of the Clean Air Act,
as amended.
(42 U.S.C. 1857C-6.)
Dated: December 20,1976.
JEROME H. SVORE,
Regional Administrator.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amended
as follows:
1. In § 60.4 paragraph (b) is amended
by revising subparagraph (CO to read
as follows:
§ 60.4 Address.
* * *
(b) * * *
(A)-(BB) * * *
(CO Nebraska Department of Envi-
ronmental Control, P.O. Box 94653, State
House Station, Lincoln, Nebraska 68509.
|PB Doc.76-38234 Filed 12-29-76,8:45 am]
IFBL 664-6]
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Delegation of Authority to the State of
Iowa
Pursuant to the delegation of author-
ity for New Source Performance Stand-
ards (NSPS) to the State of Iowa on
June 6, 1975, the Environmental Protec-
tion Agency is today amending 40 CFR
60.4, [Address.] to reflect this delegation.
A. notice announcing this delegation is
published (December 30, 1976), in the
FEDERAL REGISTER.
The amended § 60.4 provides that all
reports, requests, applications, submit-
tals, and other communications required
for the 11 source categories of the NSPS,
which were delegated to the State, shall
be sent to the Iowa Department of Envi-
ronmental Quality (DEQ>. 3920 Delaware
Avenue, P O. Box 3326. Des Moines. Iowa
50316. However, reports required pur-
suant to 40 CFR 60.7fa) shall be sent to
EPA, Region VII, 1735 Baltimore, Kan-
sas City, Missouri 64108, as well as to the
State.
RULES AND REGULATIONS
The Regional Administrator finds good
cause to forgo prior public notice and
make this rulemaking effective immedi-
ately in that it is an administrative
change and not one of substantive con-
tent. The delegation was effective June 6,
1975, and it serves no purpose to delay
the technical change of the addition of
the State address to the Code of Federal
Regulations.
This rulemaking is effective immedi-
ately and is issued under the authority
of Section 111 of the Clean Air Act, as
amended.
(42U.S.C. 1857C-G.)
Dated: December 20, 1976.
JEROME H. SVORE.
Regional Administrator.
Part 60 of Chapter 1, Title 40 of the
Code of Federal Regulations is amended
as follows:
1. In 8 60.4, paragraph (b) is amended
by revising subparagraph Q, to read as
follows:
§ 60.4 Address.
*****
(b) * * *
(A)-(P) * * *
(Q) State of Iowa, Department of
Environmental Quality, 3920 Delaware,
P.O. Box 3326, Des Moines, Iowa 50316.
*****
[FBDoc.76-38741 Filed 12-?9-76;8:45 am]
HDEKAL KOISTU. VOL 41, NO. 252
THURSDAY. DECEMBEt 30, 1976
55
Title 40Protection of Environment
CHAPTER IENVIRONMENTAL
PROTECTION AGENCY
SUBCHAPTER CAll) PROGRAMS
[FRL 608-1]
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCE
Delegation of Authority to State of Vermont
Pursuant to the delegation of author-
ity for the Standards of Performance for
New Stationary Sources (NSPS) to the
State of Vermont on September 3, 1976,
FPA is today amending 40 OFR 60.4,
Address, to reflect this delegation. A no-
tice announcing this delegation is pub-
lished today in the FEDERAL REGISTER.
(See FR Doc. 77-546 appearing in the
Notices section of this issue). The
amended $ 60.4, which adds the address
of the Vermont .Agency of Environ-
mental Protection to which all reports,
requests, applications, submittals, and
communications to the Administrator
pursuant to this part must also be ad-
dressed, is set forth below.
The Administrator finds good cause
for foregoing prior public notice and for
making this rulemaking effective im-
mediately in that it is an administrative
change and not one of substantive con-
tent. No additional substantive burdens
are imposed on the parties affected. The
delegation which is reflected by this ad-
ministrative amendment was effective on
September 3, 1976, and it serves no pur-
pose to delay the technical change of
this addition to the State address to the
Code of Federal Regulations.
This rulemaking is effective imme-
diately, and is issued under the authority
of Section 111 of the Clean Air Act, as
amended. 42 U.S.C. 1857c-6.
Dated: December 17, 1976.
JOHN A. S. MCGLENNON,
Regional Administrator.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amended.
as follows:
1. In 8 60.4 paragraph (b) is amended
by revising subparagraph (UU) to read
as follows:
§ 60. t Address.
*****
-------
RULES AND REGULATIONS
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
DELEGATION OF AUTHORITY TO THE STATE
OP SOUTH CAROLINA
2. Part 60 of Chapter I, Title 40, Code
of Federal Regulations, Is amended by
revising subparagraph
-------
v*x
l^ftV m^
-------
"
-------
litlo 10Proler.tlon of fnvironiwnt
CHAPTER ItNVIRONMENTAL
PROTECTION AGENCY
(FliL (SCO 4 I
PART 60STANDARDS OF PERFORMANCE
FOR NEW STATIONARY SOURCES
Revisions to Emission Monitoring
Requirements and to Reference Methods
On October 6, 1975 (40 FH 46250),
under sections 111, 114, and 301 of the
Clean Air Act, as amended, the Envi-
ronmental Protection Agency (EPA)
promulgated emission monitoring re-
quirements and revisions to the perform-
ance testing Reference Methods in 40
CFR Part 60. Since that time, EPA has
determined that there is a need for a
number of revisions to clarify the re-
quirements. Each of the revisions being
made in 40 CFR Part 60 are discussed
as follows:
1. Section 60.13. Paragraph (c) (3) has
been rewritten to clarify that not only
new monitoring systems but also up-
graded monitoring systems must comply
with applicable performance specifica-
tions.
Paragraph (e) (1) is revised to provide
that data recording is not required more
frequently than once every six minutes
(rather than the previously required ten
seconds) for continuous monitoring sys-
tems measuring the opacity of emissions.
Since reportsi of excess emissions are
based upon review of six-minute aver-
ages, more frequent data recording is
not required in order to satisfy these
monitoring requirements
2. Section 60.45. Paragraphs (a>
through 'el have been reorganized for
clarification. In addition, restrictions on
use of continuous monitoring systems for
measuring oxygen on a wet basis have
been removed. Prior to this revision, only
dry basis oxygen monitoring equipment
was acceptable. Procedures for use of wet
basis oxygen monitoring equipment have
been approved by EPA and were pub-
lished in the FEDERAL REGISTER as an al-
ternative procedure (41 FR 44838).
Also deleted from 5 60.45 are restric-
tions on the location of a carbon dioxide
-------
RULES AND PECULATIONS
(2) For a fossil fuel-flrcd steam gen-
erator that docs not use a flue gas cie-
sulfurization device, a continuous moni-
toring system for measuring sulfur di-
oxide emissions is not required if the
owner or operator monitors sulfur di-
oxide emissions by fuel sampling and
analysis under paragraph (d) of this
section.
(3) Notwithstanding 560.13Cb), in-
stallation of a continuous monitoring
system for nitrogen oxides may be de-
layed'until after the initial performance
tests under I 60.8 have been conducted.
If the owner or operator demonstrates
during the performance test that emis-
sions of nitrogen oxides are less than 70
percent of the applicable standards in
§ 60.44, a continuous monitoring system
for measuring nitrogen oxides emissions
is not required. If the initial performance
test results show that nitrogen oxide
emissions are greater than 70 percent of
the applicable standard, the owner or
operator shall install a continuous moni-
toring system for nitrogen oxides within
one year after the date of the initial per-
formance tests under § 60.8 and comply
with all other applicable monitoring re-
quirements under this part.
(4) If an owner or operator does not
install any continuous monitoring sys-
tems for sulfur oxides and nitrogen ox-
Ides, as provided under paragraphs (b)
(1) and (b)(3) or paragraphs (b) (2)
and (b) (3) of this section a continuous
monitoring system for measuring either
oxygen or carbon dioxide is not required.
(c) For performance evaluations un-
der 8 60.13(c) and calibration checks
under 560.13(d), the following proce-
dures shall be used:
(1) Reference Methods 6 or 7, as ap-
plicable, shall be used for conducting
performance evaluations of sulfur diox-
ide and nitrogen oxides continuous mon-
itoring systems.
(2) Sulfur dioxide or nitric oxide, as
applicable, shall be used for preparing
calibration gas mixtures under Perform-
ance Specification 2 of Appendix B to
this part.
(3) For affected facilities burning fos-
sil fuel(s), the span value for a continu-
ous monitoring system measuring the
opacity of emissions shall be 80, 90, or
100 percent and for a continuous moni-
toring system measuring sulfur oxides or
nitrogen oxides the span value shall be
determined as follows:
|In part* per million)
Fossil fuel Span value (or
sulfur dioxide
Ota (i)
Liquid 1,000
Solid 1 600
Combinations.. 1,000|/+ 1,500?
i Not applicable.
where:
Span value for
nitrogen oxides
500
600
500
500(i+v)+l,000z
(4) All span values computed under
paragraph (c) (3) of this section for
burning combinations of fossil fuels shall
be rounded to the nearest 500 ppm.
(5) For a fossil fuel-fired steam gen-
erator that simultaneously burns fossil
fuel and nonfossil fuel, the span value
of all continuous monitoring systems
shall be subject to the Administrator's
approval.
(d) [Reserved]
(e) For any continuous monitoring
system installed under paragraph (a) of
this section, the following conversion
procedures shall be used to convert the
continuous monitoring data into units of
the applicable standards (ng/J, Ib/mil-
lion Btu):
(1) When a continuous monitoring
system for measuring oxygen is selected,
the measurement of the pollutant con-
centration and oxygen concentration
shall each be on a consistent basis (wet
or dry). Alternative procedures ap-
proved by the Administrator shall be
used when measurements are on a wet
basis. When measurements are on a dry
basis, the following conversion procedure
shall be used:
r 20.9 "I
L 20.9-percent OjJ
where:
E, C, F, and %0., are determined under para-
graph (f) of this section.
(2) When a continuous monitoring
system for measuring carbon dioxide is
selected, the measurement of the pol-
lutant concentration and carbon dioxide
concentration shall each be on a con-
sistent basis (wet or dry) and the fol-
lowing conversion procedure shall be
used:
E=Cf f 10° 1
" L Percent CO2J
where:
E, C, Fc and %C(X are determined under
paragraph (f) of this section.
APPENDIX BPERFORMANCE
SPECIFICATIONS
3. Performance Specification 1 is
amended by revising paragraph 6.2 as
follows:
6. ...
6.2 Coraformance with the requirements
of section 6.1 may be demonstrated by the
owner or operator of the affected facility by
testing each analyzer or by obtaining a cer-
tificate of conformance from the Instrument
manufacturer. The certificate must certify
that at least one analyzer from each month's
production was tested and satisfactorily met
all applicable requirements. The certificate
must state that the first analyzer randomly
sampled met all requirements of paragraph
6 of this specification. If any of the require-
ments were not met, the certificate must
show that the entire month's analyzer pro-
duction was resampled according to the mili-
tary standard 105D sampling procedure
(MIL-STD-105D) Inspection level II; was re-
tested for each of the applicable require-
ments under paragraph 6 of this specifica-
tion; and was determined to be acceptable
under MIL-STD-105D procedures. The certifi-
cate of conformance must show the results
of each test performed for the analyzers
sampled during the month the analyzer be-
ing Installed was produced.
4. Performance Specification 2 is
amended by revising Figure 2-3 as
follows:
Test
No.
1
?
3
4
Date
and
Time
Reference Method Samples
SO-
Sample 1
(Ppm)
NO
Sample 1
(ppm)
I
1 i
5 ,
6 1
7
8
9
lean
est
)5J
ICCU
> E»|
reference B
value (S02
onfldence
let hod
ntervals
NO NO
Sample 2 Sample 3
(ppm) i (ppm)
i
NO Sample
Average
(ppm)
1
1
|
Analyzer 1-Hour
Average (ppm)«
so2 «ox
Mean reference method
test value (NO )
POT (SO,) »
Difference
s4PI">itox
Mean of
< the differences
ppm
Mean of the "ifffrences + g5j conffdence'lnterv*! , _ . len
ac<" ' " Mean reference method value «.««_
lain and report method used to determine Integrated averages
i-"2
NO,)
I (NOX)
xthe fraction of total heat Input derived
from gaseous fossil fuel, and
y the fraction of total heat Input derived
from liquid fossil fuel, and
z=the fraction of total heat Input derived
from solid fossil fuel.
Figure 2-3. Accuracy Determination (S02 and NOX)
(Sees. Ill, 114, 301 (a), Clean Air Act, as amended. Pub. L. 91-1304, 84 Stat. 1678 (42 U.8.C.
18S7C-6, 1867-9, 18S7g(a))).
[PB Doc.77-2744 Mled l-28-77;8;45 am]
FEDERAL REGISTER, VOL. 42, NO. 20MONDAY, JANUARY 31, 1977
IV- 160
-------
RULES AND REGULATIONS
58
[FRL 682-4]
59
PART 60 STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES-
Delegation of Authority to City of
Philadelphia
Pursuant to the delegation of author-
ity for the standards of performance
for new stationary sources (NSPS) to
the City of Philadelphia on Septem-
ber 30, 1976, EPA is today amending
40 CFR 60.4, Address, to reflect this
delegation. For a notice announcing
this delegation, see FR Doc 77-3712
published in the Notices section of to-
day's FEDERAL REGISTER. The amended
§ 60.4, which adds the address of the
Philadelphia Department of Public
Health, Air Management Services, to
which all reports, requests, applications.
submittals, and communications to the
Administrator pursuant to this part
must also be addressed, is set forth be-
low.
The Administrator finds good cause
for foregoing prior public notice and for
making this rulemaking effective im-
mediately in that it is an administrative
change and not one of substantive con-
tent No additional substantive burdens
are imposed on the parties affected. The
delegation which is reflected by this Ad-
ministrative amendment was effective on
September 30. 1976, and it serves no
purpose to delay the technical change
of this address to the Code of Federal
Regulations.
This rulemaking is effective imme-
diately, and is issued under the author-
ity of section 111 of the Clean Air Act,
as amended, 42 U.S.C. 1857c-6.
Dated: January 25, 1977.
A. R. MORRIS,
Acting Regional Administrator.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amended
as follows :
1. In fj 60.4, paragraph (b) is amended
by revising subparagraph (NN) to read
as follows :
§60. 1 Adilrct-.
(A)-(MM) *
(NN)(a) City of Philadelphia: Philadelphia
Department ot Public Health, Air Man-
agement Services, 801 Arch Street, Phila-
delphia. Pennsylvania 19107.
* * *- * *
(FR Doc.77-3709 Filed 2-3-77;8:45 am]
FEDERAL REGISTER, VOL. 42, NO. 24
FRIDAY, FEBRUARY 4, 1977
PART 0STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Region V Address; Correction
Section 60.4 paragraph (a) Is corrected
by changing Region V (Illinois, Indiana,
Minnesota, Michigan, Ohio, Wisconsin),
1 North Wacker Drive. Chicago, Illinois
60606 to Region V (Illinois, Indiana,
Minnesota, Michigan, Ohio, Wisconsin),
230 South Dearborn /Street, Chicago, n-
Unods 60604.
Da ted: March 21,1977.
GEORGE R. ALEXANDER, Jr.,
Regional Administrator.
(TO Doc.77-9406 Filed 8-29-77:8:45 am]
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Delegation of Authority to the State of
Wisconsin
Pursuant to the delegation of author-
ity for the standards of performance for
new stationary sources (NSPS) to the
State of Wisconsin on September 28,
1976, EPA Is today amending 40 CFR
60.4, Address, to reflect this delegation.
A Notice announcing this delegation is
published today, March 30, 1977, at 42
PR 16845 in this FEDERAL REGISTER. Hie
amended § 60.4, which adds the address
of the Wisconsin Department of Natural
Resources to which all reports, requests,
applications, submittals, and communi-
cations to the Administrator pursuant to
this part must also be addressed, is set
forth below.
The Administrator finds good cause for
foregoing prior public notice and for
making this rulemaking effective Im-
mediately in that it Is an administrative
change and not one of substantive con-
tent. No additional substantive burdens
are imposed on the parties affected. The
delegation which is reflected by this ad-
ministrative amendment was effective on
September 28,1976 and it serves no pur-
pose to delay the technical change of this
addition of the State address to the Code
of Federal Regulations.
This rulemaking is effective immedi-
ately, and is issued under the authority
of section 111 of the Clean Air Act, as
amended. 42 U.S.C. 1857c-6.
Da ted: March 21,1977.
GEORGE R. ALEXANDER, Jr.,
Regional Administrator.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amended
as follows:
1. In { 60.4 paragraph (b) is amended
by revising subparagraph (YY), to read
as follows:
§ 60.4 Address.
*****
(b)
(A)-
(YY) Wisconsin
Wisconsin Department of Natural Resources,
P.O. Box 7031. Madison, Wisconsin 63707.
[FR Doc.77-9404 Filed 3-29-77:8:45 am)
FEDERAL tEClSTER, VOL. 42, NO. 61WEDNESDAY, MARCH 30, W7
IV-161
-------
60
Title 40Protection of Environment
CHAPTER IENVIRONMENTAL
PROTECTION AGENCY
[PEL 716-8]
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Compliance With Standards and
Maintenance Requirements
AGENCY: Environmental Protection
Agency.
ACTION: Final rule.
SUMMARY: This action amends the
general provisions of the standards of
performance to allow methods other
than Reference Method 9 to be used as a
means of measuring plume opacity. The
Environmental Protection Agency (EPA)
Is Investigating a remote sensing laser
radar system of measuring plume opacity
and believes It could be considered as an
alternative method to Reference Method
8. This amendment would aHow EPA to
propose such «ystems as alternative
methods In the future.
EFFECTIVE DATE: June 22, 1977.
FOR FURTHER INFORMATION CON-
TACT:
Don R. Goodwin, Emission Standards
and Engineering Division, Environ-
mental Protection Agency, Research
Triangle Park, North Carolina 27711,
telephone no. 919-688-8146, ext. 271.
SUPPLEMENTARY INFORMATION:
As originally expressed, 40 CFR 60.11(b)
permitted the use of Reference Method 9
exclusively for determining whether a
ource compiled with an applicable
opacity standard. By this action, EPA
mends {60.1Kb) so that alternative
methods approved by the Administrator
may be used to determine opacity.
When 560.1Kb) was originally pro-
mulgated, the visible emissions (Method
») technique of determining plume
opacity with trained visible emission ob-
servers was the only expedient and accu-
rate method available to enforcement
personnel. Recently, EPA funded the de-
velopment of a remote sensing laser ra-
dar system (LJDAR) that appears to pro-
duce results adequate for determination
of compliance with opacity standards.
EPA Is currently evaluating the equip-
ment and Is considering proposing Its
use as an alternative techniaue of meas-
uring plume opacity.
This amendment will allow EPA to
consider use of the LIDAR method of
determining plume opacity and, If ap-
propriate, to approve this method for en-
forcement of opacity regulations. If this
method appears to be a suitable alterna-
tive to Method 9, it will be proposed In
the FEDERAL REGISTER for public com-
ment. After considering comments, EPA
will determine if the new method will be
an acceptable means of determining
paclty compliance.
(Bees. 111. 114, 301 (a), Clean Air Act, sec. 4(a)
of Pub. L. 91-604, 84 Stat. 1683; sec. 4 (a) of
Pub. L. 91-604, 84 Stat. 1687; me. 3 of Pub. L.
Ho. 90-148, 81 Stat. 804 (43 VS.C. 1857C-6.
1867c-« and 1857g(a) ).)
RULES AND REGULATIONS
Kam.Economic Impact Analysis: The
Environmental Protection Agency has deter-
mined that this action does not contain a
major proposal requiring preparation of an
Economic Impact Analysis under Executive
Orders 11821 and 11948 and OMB Circular
A-1O7.
Dated: May 10, 1977.
DOUGLAS M, COSTLE,
Administrator.
Part 60 of Chapter L Title 40 of the
Code of Federal Regulations is amended
0 follows:
L Section 60.11 Is amended by revising
paragraph (b) as follows:
| 60.11 Compliance with standards and
maintenance requirements.
« «
Cb) Compliance with opacity stand-
ard* «n thte part shall be determined by
conducting observations in accordance
with Reference Method 9 in Appendix A
of this part or any alternative method
that Is approved by the Administrator.
Opacity readings of portions of plumes
which contain condensed, uncombined
water vapor shall not be used for pur-
poses of determining compliance with
opacity standards. The results of con-
tinuous monitoring by transmissometer
which Indicate that the opacity at the
time visual observations were made was
not in excess of the standard are proba-
tive but not conclusive evidence of the
actual opacity of an emission, provided
that the source shall meet the burden of
proving that the Instrument used meets
(at the time of the alleged violation)
Performance Specification 1 hi Appendix
B of this part, has been properly main-
tained and (at the time of the alleged
violation) calibrated, and that the
resulting data have not been tampered
with in any way.
(Sees. Ill, 114, 301 (a), Clean Air Act, Sec. 4
(a) of Pub. L. 91-604, 84 Stat. 1683; sec. 4(a)
of Pub. L. 91-604, 84 Stat. 1687; sec. 2 of Pub.
L. No. 90-148 81 Btat. 604 (42 DB.C. 1857C-6.
18S7C-8, 1867g(a)).)
[PR Doc.77-14582 Piled &-20-77;8:45 am]
61
Title 40Protection of Environment
CHAPTER 1ENVIRONMENTAL PROTEC-
TION AGENCY
[FBL 742-6]
PART 6OSTANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Petroleum Refinery Ruld Catalytic Cracking
Unit Catalyst Regenerators
AGENCY: Environmental Protection
Agency.
ACTION: Final rule.
SUMMARY: This rule revises the stand-
ard which limits the opacity of omissions
from new, modified, or reconstructed
petroleum refinery fluid catalytic crack-
Ing unit catalyst regenerators to 30 per-
cent, except for one six-minute period In
any one hour. The revision is being made
to make the standard consistent with a
revision to the test method for opacity.
The standard implements the Clean Air
Act and Is intended to require the proper
operation and maintenance of fluid cata-
lytic cracking unit catalyst regenerators.
EFFECTIVE DATE: June 24, 1976.
ADDRESSES: Copies of the comment
letters and a report which contains a
summary of the issues and EPA's re-
sponses are available for public inspec-
tion and copyljng at the U.S. Environ-
mental Protection Agency, Public Infor-
mation Reference Unit (EPA Library),
Room 2922, 401 M Street SW., Washing-
ton, D.C. Copies of the report also may
be obtained upon written request from
the EPA Public Information Center
(PM-215), Washington, D.C. 20460
(specify Comment SummaryPetroleum
Refinery Fluid Catalytic Cracking
Units).
FOR FURTHER INFORMATION CON-
TACT:
Don R. Goodwin, Emission Standards
and Engineering Division, Environ-
mental Protection Agency, Research
Triangle Park, North Carolina 27711,
telephone number 919-688-8146, ex-
tension 271.
SUPPLEMENTARY INFORMATION:
BACKGROUND
On June 29, 1973, the U.S. Court of
Appeals for the District of Columbia
Circuit remanded to EPA the standards
of performance for Portland cement
plants (.Portland Cement Association v.
Ruckelshaus, 486 F. 2d 375). One of the
issues remanded was the use of opacity
standards. On November 12, 1974, EPA
responded to the remand (39 FR
39872) and on May 22, 1975, the Court
affirmed the use of opacity standards
(513F.2d506).
In the remand response, EPA recon-
sidered the use of opacity standards and
concluded that they are a reliable, in-
expensive, and useful means of ensuring
that control equipment is properly main-
tained and operated at all times. EPA
also made revisions to the general pro-
FEDHAl K6ISTER, VOL 4t, NO. »*-^iONDAY, MAY 13, 1*77
IV-162
-------
RULES AND REGULATIONS
visions of 40 CPR Part 60 and to the
Reference Method 9.
EPA reevaluated the opacity standard
for petroleum refinery fluid catalytic
cracking unit catalyst regenerators in
light of the revisions to Reference
Method 9, and proposed a revision to
tills standard on August 30,1976 (41 PR
36600). The revision is not the result of
a revaluation of the technical, economic
and environmental basis for the stand-
ard. Consequently, the revised opacity
standard will be neither more nor less
stringent than the previous standard,
and will be consistent with the mass
emission standard (1.0 kg/1000 kg of
coke burnoff)
SUMMARY or COMMENTS AKD EPA's
RESPONSES
EPA received six letters commenting
on the proposed revision (three from in-
dustry and three from State and local
governments). Two commenters pointed
out that the basis for the original opac-
ity standard assumed new fluid catalytic
cracking units would be of 65,000 barrels
per day capacity, but the proposed re-
vision assumed new fluid catalytic crack-
ing units would be of less than 50,000
barrels per day capacity. Two other com-
menters pointed out that Jlie original
standard allowed one three-minute ex-
ception from the opacity standard of
performance to accommodate soot-
blowing in the carbon monoxide boiler
and that the proposed change to six-
minute averages did not justify adding
an additional exception.
A review of the basis for the original
opacity standard indicates the com-
menters are correct. Large, new or modi-
fied fluid catalytic cracking units will
more likely be in the range of 65,000
barrels per day capacity, and one ex-
ception per hour more accurately reflects
the one three-minute exception allowed
under the previous test method. The ef-
fect of increased capacity on the opacity
of particulate mass emissions was dis-
cussed both in the FEDERAL REGISTER no-
tice proposing revision of the opacity
standard and in the background infor-
mation document supporting the revi-
sion. Considering the effect on opacity of
the greater capacity of a 65,000-barrel-
per-day fluid catalytic cracking unit
compared tor a 50,000-barrel-per-day
unit leads to the conclusion that the
opacity standard should not be revised
to 25 percent, but should remain at 30
percent opacity. Accordingly, the revised
opacity standard is promulgated as 30
percent opacity with one six-minute ex-
ception period per hour.
One comment concerned 8 60.11 (e) of
the General Provisions and questioned
whether in its present form it adequately
accounts for the problems of petroleum
refinery fluid catalytic cracking units.
Section 60.life) provides relief for those
individual sources where, because of op-
erating variables, opacity readings are
abnormally high and cause it to exceed
the standard, even though it is in com-
pliance with the mass emission stand-
ard. The mechanism for relief is that
opacity readings may be taken during
initial start-up mass emission testing
and a special opacity standard assigned
to the source.
Petroleum refinery fluid catalytic
cracking units operate continuously for
periods of two years or more; and over
such long periods, mass and opacity
emissions gradually increase. For this
reason, the mass and opacity standards
were set on the basis of levels achievable
at the end of the run. It is to be ex-
pected, therefore, that at the beginning
of the run, both mass and opacity emis-
sions from such units will be well below
the standard, even in some cases where
opacity readings are abnormally high
given the mass emissions. In such cases,
an Individualized opacity standard based
on beginning-of-run readings would not
necessarily prevent the facility which
still meets the mass emissions standard
at the end of the run from falling an
end-of-run opacity test. To alleviate this
problem. EPA is adding a new i 60.106
(e) to the petroleum refinery standard
which, in conjunction with 55 60.11 (e)
(2), fe)(3), and (e) (4) of the General
Provisions, will permit determination of
an individualized opacity standard for
a fluid catalytic cracking unit during
any performance test and not just the
initial performance test. This will ensure
that a properly operated and maintained
source will not be found in violation of
the opacity standard, while in compli-
ance with the applicable mass emission
standard.
The proposed amendment to 5 60.102
(a) (2) specified that opacity readings
of Dortions of plumes which contain
condensed, uncomblned water vapor are
not to be used for determining compli-
ance with opacity standards. Since this
provision has been added to 5 60.1Kb)
of the General Provisions, It is not neces-
sary to repeat it hi Subpart J for petro-
leum refineries.
MISCELLANEOUS
The opacity standard, as modified, ap-
plies to all affected faculties for which
construction or modification was com-.
menced after June 11, 1973, the date the
standard was proposed.
This revision is promulgated under the
authority of sections 111, 114, and 301 (a)
of the Clean Air Act, as amended by
Public Law 91-604, 84 Statute 1683, 1687
(42 U.S.C. 1857c-6, 1857c-9) and Public
Law 90-148, 81 Statute 504 (42 U.S.C.
1857g(a)).
NOTE.The Environmental Protection
Agency has determined that this document
does not contain a major proposal requiring
preparation of an Economic Impact State-
ment under Executive Orders 11821 and
11949, end OMB Circular R^107.
Dated: June 24,1977.65
DOUGLAS M. COSTLE,
Administrator.
Part 60, Chapter I of Title 40 of the
Code of Federal Regulations is amended
as follows:
1. Section 60.102(a)(2) is revised to
read as follows:
§ 60.102 Standard for particulate matter.
(a) * *
(2) Gases exhibiting greater than 30
percent opacity, except for one six-min-
ute average opacity reading In any one
hour.
*****
(Sec. Ill, Pub. L. 91-604, 84 Stat. 1683 (42
0.S.C. 1857C-6); sec. 301 (a), Pub. L. 90-148,
81 Stat. 604 (42 U.S.C. 1857g(a)).)
2. Section 60.105 (e) (1) is revised to
read as follows:
§ 60.105 Emission monitoring.
(e)
(1) Opacity. All hourly periods which
contain two or more six-minute periods
during which the average opacity as
measured by the continuous monitoring
system exceeds 30 percent.
*****
3. Section 60.106(e) is addea to read as
follows:
§ 60.106 Test methods and procedures.
* *
(e) An owner or operator of an af-
fected facility may request the Adminis-
trator to determine opacity of emissions
from the affected facility during any per-
formance test covered under | 60.8. In
such event the provisions of §§ 60.11 (e)
(2), (e) (3), and (e) (4) shall apply.
(Sec. Ill, 114, Pub. L. 91-604, 84 Stat. 1683,
1687 (42 U.S.C. 2857C-6, 1857c-8) sec. 301 (a)
Pub. L. 90-148, 81 Stat. 604 (42 U.S.C 1857g
()))
[PB Doc.77-18129 Filed 6-23-77;8:45 am]
FEDERAL REGISTER, VOL. 42, NO. 122FRIDAY, JUNE 24, 1977
IV-163
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W* [PRL 753_aj
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Units and Abbreviations
AGENCY: Environmental Protection
Agency
ACTION: Final rule
SUMMARY: This action revises the Gen-
eral Provisions by reorganizing the units
and abbreviations and adding the Inter-
national System of Units (SI). Until re-
cently, EPA did not have a preferred sys-
tem of measurement to be used in its
regulations. Now the Agency is using SI
units in all regulations issued under this
part. This necessitates that SI units be
added to the General Provisions to pro-
vide a complete listing of abbreviations
used..
EFFECTIVE DATE: August 18, 1977.
FOR FURTHER INFORMATION CON-
TACT:
Don R. Goodwin, Emission Standards
and Engineering Division, Environ-
mental Protection Agency, Research
Triangle Park, North Carolina 27711,
telephone no. 919-541-5271.
SUPPLEMENTARY INFORMATION:
BACKGROUND
Section 3 of Pub. L. 94-168, the Metric
Conversion Act of 1975, declares that
the policy of the United States shall be
to coordinate and plan the increasing
use of the metric system in the United
States. On December 10, 1970, a notice
was published in the FEDERAL REGISTER
(41 FR 54018) that set forth the inter-
pretation and modification of the Inter-
national System of Units (SI) for the
United States. EPA incorporates SI units
in all regulations issued under 40 CFR
Part 60 and provides common equivalents
in parentheses where desirable. Use of
SI unite requires this revision of the ab-
breviations section (§ 60.3) of the Gen-
eral Provisions of 40 CFR Part 80.
RxmnicB DOCUMENTS
An explanation of the International
Systems of Units was presented in the
FEDERAL REGISTER notice mentioned
above (41 FR 54018). The Environmental
Protection Agency is using the Standard
for Metric Practice (E 380-76) published
by the American Society for Testing and
Materials (A.S.TM.) as its basic refer-
ence. This document may be obtained by
sending S4.00 to A.S.T.M., 1916 Race
Street, Philadelphia, Pennsylvania 19103.
MISCELLANEOUS
As this revision has no regulatory Im-
pact, but only defines units and abbrevl-
ULES AND REGULATIONS
ations used in this part, opportunity for
public participation was judged unnec-
essary.
(Sections III and 301 (a) of the Clean All
Act; sec. 4(a) of Pub. L. 91-604. 84 Stat. 1683;
sec. a of Pub. L. 90-148, 81 Stat. 504 (42 U.S.C.
1857C-6, 1857g(a)).)
NOTE.The Environmental Protection
Agency has determined that this document
does not contain a major proposal requiring
preparation of an Economic Impact Analysis
under Executive Orders 11821 and 11949 and
OMB Circular A-107.
Dated: July 8,1977.
DOUGLAS M. COSTLE,
Administrator.
40 CFR Part 60 is amended by revis-
ing § 60.3 to read as follows:
§ 60.3 Units and abbreviations.
Used in this part are abbreviations and
symbols of units of measure. These are
defined as follows:
(a) System Intel-rational (SI) units
of measure:
Aampere
ggram
Hihertz
JJoule
Kdegree Kelvin
kgkilogram
mmeter
ofcubic meter
mgmilligram10-n gram
mm.millimeter10-» meter
Mgmegagram10* gram
molmole
Nnewton
ngnanogram10-' gram
nmnanometer10-° meter
Papascal
second
Tvolt
Wwatt
aohm
«gmicrogram10-" gram
(b) Other units of measure:
BtuBritish thermal unit
*Cdegree Celsius (centigrade)
calcalorie
cfmcubic feet per minute
cu ftcuMc feet
dcfdry cuWc feet
dcmdry cubic meter
dacfdry cubic feet at standard conditions
dacmdry cubic meter at standard condi-
tions
eqequivalent
Pdegree Fahrenheit
itfeet
galgallon
mlmllllllter
mol. wt.molecular weight
ppbparts per billion
ppmparts per million
pslapounds per square Inch absolute
pslgpounds per square Incto gage
Rdegree Ranttne
scfcubic feet at standard condition*
scfhcubic feet per hour at standard condi-
tions
scmcubic meter at standard condition*
secsecond
sq ftsquare feet
8tdat standard conditions
(c) Chemical nomenclature:
OdBcadmium sulflde
COcarbon monoxide
CO,carbon dioxide
HCIhydrochloric acid
Hgmercury
H,Owater
ILShydrogen sulflde
H.SO,sulfuric acid
Nznitrogen
NOnitric oxide-
NO.nitrogen dioxide
NO1nitrogen oxides
O,oxygen
8O2sulfur dioxide
SO,sulfur trioxlde
SO.sulfur oxides
(d) Miscellaneous:
A.S.T.M.J-Amerloftn Society for Testing and
Materials
(Sections III and 301 (a) at the dean Air
Act; sec. 4 (a) of Pub. L. 91-604, 84 Stat. 1683;
sec. 2 of Pub. L. 90-148.81 Stat. 604 (43 0J3.C.
1867C-6,1857g(a)Jt.)
[FB DOC.77-20M7 Filed 7-18-77:8:45 am)
g-eqgram equl-**)ent
orhour
lo-^-inch
k1,000
Iliter
1pmliter per minute
Ibpound
meqmiUtequivalcnt
mlnminute
nDHAL IfdSTEl, VOL 49, NO. 138TUESDAY. JUtY 1*. t*77
IV-164
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63 [PEL 762-2]
PART 60STANDARDS OF PERFORM
ANCE FOR NEW STATIONARY SOURCES
Delegation of Authority to the State of New
Jersey
AGKNCY: Environmental Protection
Agency.
ACTION: Final Rule.
SUMMARY: A notice announcing EPA's
delegation of authority for the New
Source Performance Standards to the
State of New Jersey is published at page
37387 of today's FEDERAL REGISTER. In
order to reflect this delegation, this docu-
ment amends EPA regulations to require
the submission of all notices, reports, and
other communications called for by the
delegated regulations to the State of New
Jersey rather than to EPA.
EFFECTIVE DATE: July 21,1977.
FOR FURTHER INFORMATION CON-
TACT:
J. Kevin Healy, Attorney, U.S. Envi-
ronmental Protection Agency, Region
H, General Enforcement Branch, En-
forcement Division, 26 Federal Plaza,
New York, New York 10007, 212-264-
1196).
SUPPLEMENTARY INFORMATION:
On May 9, 1977 EPA delegated author-
ity to the State of New Jersey to imple-
ment and enforce the New Source Per-
formance Standards. A full account of
the background to this action and of the
exact terms of the delegation appear in
the Notice of Delegation which is also
published in today's FEDERAL REGISTER.
This rulemaking is effective immedi-
ately, since the Administrator has found
good cause to forego prior public notice.
This addition of the State of New Jersey
address to the Code of Federal Regula-
tions is a technical change and imposes
no additional substantive burden on the
parties affected.
Dated: July 18, 1977.
BARBARA BLUM,
Acting Administrator.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amended
under authority of Section 111 of the
Clean Air Act (42 U.S.C. 1857c-6), as
follows:
(1) In § 60.4 paragraph (b) is amended
by revising subparagraph (FF) to read
as follows:
§ 60.4 Address.
*****
(b) * *
(FF)State of New Jersey: New Jersey De-
partment of Environmental Protection,
John Fitch Plaza, P.O. Box 2807, Trenton.
New Jersey 08625.
|FR Doc.77-21020 Filed 7-20-77:8:48 am]
RULES AND REGULATIONS
64
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Applicability Dates
AGENCY: Environmental Protection
Agency.
ACTION: Final rule.
SUMMARY: This action incorporates
into the regulations the dates on which
the standards of performance are applic-
able. The dates were not a part of the
regulations at the time of their promul-
gation and considerable confusion exists
over when the standards apply. This ac-
tion removes the confusion and makes
future enforcement of the standards
easier.
EFFECTIVE DATE: August 24,1977.
FOR FURTHER INFORMATION CON-
TACT:
Don. R. Goodwin, Emission Standards
and Engineering Division, Environ-
mental Protection Agency, Research
Triangle Park, North Carolina 27711,
telephone 919-541-5271.
SUPPLEMENTARY INFORMATION:
Section 111 of the Clean Air Act provides
that "new source" under that section
means "any stationary source, the con-
struction or modification of which is
commenced after the publication of reg-
ulations (or, if earlier, proposed regula-
tions) prescribing a standard of perform-
ance which will be applicable to such
source." Thus, for standards of perform-
ance under section 111, the proposal date
(or, in the event there was no proposal,
the promulgation date) of a standard
constitutes its applicability date. While
this information is contained in the "Ap-
plicability" section (5 60.2) of the Gen-
eral Provisions, the Agency has not, until
now, incorporated in the regulations the
specific applicability date(s) for each
standard.
The absence of these dates from the
various regulations has led to some con-
fusion. The most frequent mistake is for
the applicability date to be confused with
the effective date. The effective date is
the day on which the regulation becomes
law (usually the day the final regulation
is published in the FEDERAL REGISTER).
The effective date has customarily been
noted in the preamble to the final regu-
lation when it appears in the FEDERAL
REGISTER. A regulation, then, usually be-
comes effective upon promulgation and
applies to sources constructed or modi-
fied after the proposal date.
In view of past confusion and the
growing number of regulations, includ-
ing revisions and amendments, the
Agency has decided to hereafter incor-
porate the applicability date(s) under
the "Applicability and designation of af-
fected faculty" section of each subpart.
This action should serve to clarify which
facilities are affected by these regula-
tions. This amendment provides clarifi-
cation of the applicability dates only for
the standards promulgated to date. An
applicability statement will be added to
regulations under proposal and to future
regulations at the time of promulgation.
MISCELLANEOUS
As this action has no regulatory Im-
pact, but only sets forth applicability
dates for the purpose of clarification,
public participation was judged un-
necessary.
(Sees. Ill and 301 (a) of the Clean Air Act;
sec. 4(e) of Pub. L. 91-604, 84 Stat. 1683; sec.
3 of Pub. L. 90-148. 81 Stat. 604 (42 U.S.C.
1857C-6. 1857g(»)).)
Nom.The Environmental Protection
Agency has determined that this document
does not contain a major proposal requiring
preparation of an Economic Impact Analysis
under Executive Orders 11821 and 11949 and
OMB Circular A-107.
Dated: July 18,1977.
BARBARA BLUM,
Acting Administrator.
40 CFR Part 60 is amended by revising
Subparts D through AA as follows:
Subpart DStandards of Performance for
Fossil-Fuel-Fired Steam Generators
1. Section 60.40 is revised as follows:
§ 60.40 Applicability and designation of
affected facility.
(a) The affected facilities to which the
provisions of this subpart apply are:
(1) Each fossil-fuel-fired steam gen-
erating unit of more than 73 megawatts
heat input rate (250 million Btu per
hour).
(2) Each fossil-fuel and wood-residue-
fired steam generating unit capable of
firing fossil fuel at a heat input rate of
more than 73 megawatts (250 million
Btu per hour).
(b) Any change to an existing fossll-
fuel-flred steam generating unit to
accommodate the use of combustible
materials, other than fossil fuels as
defined in this subpart, shall not bring
that unit under the applicability of this
subpart.
(c) Any facility under paragraph (a)
of this section that commences con-
struction or modification after August
17, 1971, is subject to the requirements
of this subpart.
Subpart EStandards of Performance for
Incinerators
2. Section 60.50 is revised as follows:
§ 60.50 Applicability and designation of
affected facility.
(a) The provisions of this subpart are
applicable to each incinerator of more
than 45 metric tons per day charging
rate (50 tons/day), which is the affected
facility.
KDHAl MOISTEt, VOL. 45, NO. 140
THURSDAY, JIKY 11, 1977
IV-165
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RULES AND REGULATIONS
(b) Any facility tinder paragraph (a)
of this section that commences construc-
tion or modification after August 17,
1971, is subject to the requirements of
this subpart.
Subpart FStandards of Performance for
Portland Cement Plants
3. Section 60.60 is revised as follows:
§ 60.60 Applicability and designation of
affected facility.
(a) The provisions of this subpart are
applicable to the following affected fa-
cilities in Portland cement plants: kiln,
clinker cooler, raw mill system, finish
mill system, raw mill dryer, raw material
storage, clinker storage, finished product
storage, conveyor transfer points, bag-
ging and bulk loading and unloading sys-
tems.
(b) Any facility under paragraph (a)
of this section that commences construc-
tion or modification after August 17,
1971, is subject to the requirements of
this subpart.
Subpart GStandards of Performance for
Nitric Acid Plants
4. Section 60.70 is revised as follows:
§ 60.70 Applicability and designation of
affected facility.
(a) The provisions of this subpart are
applicable to each nitric acid production
unit, which is the affected facility.
(b) Any facility under paragraph (a)
of this section that commences construc-
tion or modification after August 17,
1971, is subject to the requirements of
this subpart.
Subpart HStandards of Performance for
Sulfuric Acid Plants
5. Section 60.80 is revised as follows:
§ 60.80 Applicability and designation of
affected facility.
(a) The provisions of this subpart are
applicable to each sulfuric acid produc-
tion unit, which is the affected facility.
(b) Any facility under paragraph (a)
of this section that commences construc-
tion or modification after August 17,
1971, is subject to the requirements of
this subpart.
Subpart IStandards of Performance for
Asphalt Concrete Plants
- 6. Section 60.90 is revised as follows:
§ 60.90 Applicability and designation of
affected facility.
(a) The affected facility to which the
provisions of this subpart apply is each
asphalt concrete plant. For the purpose
of this subpart, an asphalt concrete plant
is comprised only of any combination of
the following: dryers; systems for
screening, handling, storing, and weigh-
ing hot aggregate; systems for loading,
transferring, and storing mineral filler;
systems for mixing asphalt concrete;
and the loading, transfer, and storage
systems associated with emission con-
trol systems.
Subpart JStandards of Performance for
Petroleum Refineries
7. Section 60.100 is revised as follows:
§60.100 Applicability and designation
of affected facility.
(a) The provisions of this subpart are
applicable to the following affected fa-
cilities in petroleum refineries: fluid
catalytic cracking unit catalyst regen-
erators, fluid catalytic cracking unit
incinerator-waste heat boilers, and fuel
gas combustion devices.
(b) Any facility under paragraph (a)
of this section that commences construc-
tion or modification after June 11. 1873,
is subject to the requirements of this
subpart.
Subpart KStandards of Performance for
Storage Vessels for Petroleum Liquids
8. Section 60.110 is revised as follows:
§60.110 Applicability and designation
of affected facility.
(a) Except as provided in 5 60.110(b),
the affected facility to which this sub-
part applies Is each storage vessel for
petroleum liquids which has a storage
capacity greater than 151,412 liters
(40,000 gallons).
(b) This subpart does not apply to
storage vessels for petroleum or conden-
sate stored, processed, and/or treated at
a drilling and production facility prior
to custody transfer.
(c) Subject to the requiremente of
this subpart is any facility under para-
graph (a) of this section which:
(1) Has a capacity greater than
151.412 liters (40,000 gallons), but not
exceeding 245,000 liters (65,000 gallons,
and commences construction or modifi-
cation after March 8,1974.
(2) Has a capacity greater than
245,000 liter (65,000 gallons), and com-
mences construction or modification
after June 11.1973.
Subpart LStandards of Performance for
Secondary Lead Smelters
9. Section 60.120 is revised as follows:
160.120 Applicability and designation
of affected facility.
(a) The provisions of this subpart are
applicable to the following affected fa-
cilities in secondary lead smelters: pot
furnaces of more than 250 kg (550 Ib)
charging capacity, blast (cupola) fur-
naces, and reverberatory furnaces.
(b) Any facility under paragraph (a)
of this section that commences con-
struction or modification after June 11,
1973, is subject to the requirements of
this subpart.
Subpart MStandards of Performance for
Secondary Brass and Bronze Ingot Pro-
duction Plants
10. Section 60.130 is revised as fol-
lows:
§60.130 Applicability and designation
of affected facility.
(a) The provisions of this subpart are
applicable to the following affected fa-
cilities in secondary brass or bronze In-
got production plants: reverberatory
and electric furnaces of 1,000 kg (2,205
Ib) or greater production capacity and
blast (cupola.) furnaces of 250 kg/hr
(550 Ib/hr) or greater production ca-
pacity.
(b) Any faculty under paragraph (a)
of this section that commences construc-
tion or modification after June 11, 1973,
is subject to the requirements of this
subpart.
Subpart NStandards of Performance for
Iron and Steel Plants
11. Section 60.140 is revised as follows:
§ 60.140 Applicability and designation
of affected facility.
(a) The affected facility to which the
provisions of this subpart apply is each
basic oxygen process furnace.
(b) Any facility under paragraph (a)
of this section that commences construc-
tion or modification after June 11, 1973,
is subject to the requirements of this
subpart.
Subpart OStandards of Performance for
Sewage Treatment Plants
12. Section 60.150 is revised as follows:
§ 60.150 Applicability and designation
of affected facility.
(a) The affected facility to which the
provisions of this subpart apply is each
incinerator which burns the sludge pro-
duced by municipal sewage treatment
facilities.
(b) Any facility under paragraph (a)
of this section that commences construc-
tion or modification after June 11, 1973,
is subject to the requirements of this
subpart.
Subpart PStandards of Performance for
Primary Copper Smelters
13. Section 80.160 is revised as follows:
§ 60.160 Applicability and designation
of affected facility.
(a) The provisions of this subpart are
aplicable to the following affected facili-
ties in primary copper smelters: dryer,
roaster, smelting furnace, and copper
converter.
(b) Any facility under paragraph (a)
of this section that commences construc-
tion or modification after October 16.
1974, is subject to the requirements of
this subpart.
Subpart QStandards of Performance for
Primary Zinc Smelters
14. Section 60.170 is revised as follows:
§60.170 Applicability and designation
of affected facility.
(a) The provisions of this subpart are
applicable to the following affected facili-
ties in primary zinc smelters: roaster and
sintering machine.
(b) Any facility under paragraph (a)
of this section that commences construc-
tion or modification after October 18,
1974, is subject to the requirements of
thii subpart.
HDttAl ttOISTIt, VOL 42. NO. 147MONDAY, JULY 15,
IV-166
-------
KULES AND REGULATIONS
Subpart RStandards of Performance for
Primary Laad Smelter*
15. Section 60.180 Is revised as follows:
§60.180 Applicability and designation
of affected facility.
(a) The provisions of this subpart are
applicable to the following affected
facilities in primary lead smelters: sin-
tering machine, sintering machine dis-
charge end, blast furnace, dross rever-
beratory furnace, electric smelting fur-
nace, and converter.
(b) Any facility under paragraph (a)
of this section that commences con-
struction or modification after October
16, 1974, is subject to the requirements
of this subpart.
Subpart SStandards of Performance for
Primary Aluminum Reduction Plants
16. Section 60.190 is revised as fol-
lows:
§ 60.190 Applicability and de§ignation
of affected facility.
(a) The affected facilities in primary
aluminum reduction plants to which
this subpart applies are potroom groups
and anode bake plants.
(b) Any facility under paragraph (a)
of this section that commences con-
struction or modification after October
23, 1974, is subject to the requirements
of this subpart.
Subpart TStandards of Performance for
the Phosphate Fertilizer Industry: Wet-
Process Phosphoric Acid Plants
17. Section 60.200 is revised as fol-
lows:
§60.200 Applicability and designation
of affected facility.
(a) The affected facility to which the
provisions of this subpart apply is each
wet-process phosphoric acid plant. For
the purpose of this subpart, the affected
facility includes any combination of:
reactors, filters, evaporators, and hot-
wells.
(b) Any facility under paragraph (a)
of this section that commences con-
struction or modification after October
22, 1974, is subject to the requirements
of this subpart.
Subpart UStandards of Performance for
the Phosphate Fertilizer Industry: Super-
phosphoric Acid Plants
18. Section 60.210 is revised as fol-
lows:
§ 60.210 Applicability and designation
of affected facility..
(a) The affected facility to which the
provisions of this subpart apply is each
super-phosphoric acid plant. For the
purpose of this subpart, the affected
facility includes any combination of:
evaporators, hotwells, acid sumps, and
cooling tanks.
(b) Any facility under paragraph (a)
of this section that commences con-
struction or modification after October
22, 1974, is subject to the requirements
of this subpart
Subpart VStandards of Performance for
the Phosphate Fertilizer Industry: Diam-
Fnanium Phosphate Plants
19. Section 60.220 is revised as fol-
lows:
§ 60.220 Applicability and designation
of affected facility.
(a) The affected facility to which the
provisions of this subpart apply is each
granular diammonium phosphate plant.
For the purpose of this subpart, the af-
fected facility includes any combination
of: reactors, granulators, dryers, coolers,
screens, and mills.
(b) Any facility under paragraph (a)
of this section that commences construc-
tion or modification after October 22,
1974, is subject to the requirements of
this subpart.
Subpart WStandards of Performance for
the Phosphate Fertilizer Industry: Triple
Superphosphate Plants
20. Section 60.230 is revised as follows:
§ 60.230 Applicability and designation
of affected facility.
(a) The affected facility to which the
provisions of this subpart apply is each
triple superphosphate plant. For the pur-
pose of this subpart, the affected facility
includes any combination of: mixers,
curing belts (dens), reactors, granula-
tors, dryers, cookers, screens, mills, and
facilities which store run-of-pile triple
superphosphate.
(b) Any facility under paragraph (a)
of this section that commences construc-
tion or modification after October 22,
1974, is subject to the requirements of
this subpart.
Subpart XStandards of Performance for
the Phosphate Fertilizer Industry: Gran-
ular Triple Superphosphate Storage
Facilities
21. Section 60.240 is revised as follows:
§ 60.240 Applicability and designation
of affected facility.
(a) The affected facility to which the
provisions of this subpart apply is each
granular triple superphosphate storage
facility. For the purpose of this subpart,
the affected facility includes any combi-
nation of: storage or curing piles, con-
veyors, elevators, screens, and mills.
(b) Any facility under paragraph (a)
of this section that commences construc-
tion or modification after October 22,
1974, is subject to the requirements of
this subpart.
Subpart YStandards of Performance for
Coal Preparation Plants
22. Section 60.250 is revised as follows:
§ 60.250 Applicability and designation
of affected facility.
(a) The provisions of this subpart are
applicable to any of the following af-
fected facilities in coal preparation
plants which process more than 200 tons
per day: thermal dryers, pneumatic coal-
cleaning equipment (air tables), coal
processing and conveying equipment (in-
cluding breakers and crushers), coal
storage systems, and coal transfer end
loading systems.
(to) Any facility under paragraph (a)
of this section ttiat commences construc-
tion or modification after October 21,
1974, is subject to the requiremente of
this subpart.
Subpart ZStandards of Performance for
Ferroalloy Production Facilities
23. Section 60.260 Is revised as follows:
§ 60.260 Applicability and designation
of affected facility.
(a) The provisions of this subpart are
applicable to the following affected fa-
cilities: electric submerged arc furnaces
which produce silicon metal, f errosilicon,
calcium silicon, silicomanganese zircon-
ium, ferrochrome silicon, silvery
iron, high-carbon ferrochrome, charge
chrome, standard ferromanganese, sili-
comanganese, ferromanganese silicon, or
calcium carbide; and dust-handling
equipment.
(b) Any facility under paragraph (a)
of this section that commences construc-
tion or modification after October 21,
1974, is subject to the requiremente of
this subpart.
Subpart AAStandards of Performance for
Steel Plants: Electric Arc Furnaces
24. Section 60.270 is revised as follows:
§ 60.270 Applicability and designation
of affected facility.
(a) The provisions of this subpart are
applicable to the following affected fa-
cilities in steel plants: electric arc fur-
naces and dust-handling equipment.
(b) Any facility under paragraph (a)
of this section that commences construc-
tion or modification after October 24,
1974, is subject to the requirements of
this subpart.
(Sees. Ill and 801 (a). Clean Air Act as
amended (42 UB.C. 1857c-«, 1857g(a)).)
[PR Doc.77-31230 Filed 7-23-77:8:46 am)
FEDERAL REGISTER. VOL 42, NO. 142MONDAY, JULY 25, 1977
IV-167
-------
65
Title 40Protection of the Environment
CHAPTER IENVIRONMENTAL
PROTECTION AGENCY
[FHL 742-6]
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Petroleum Refinery Fluid Catalytic Cracking
Unit Catalyst Regenerators
Correction
In FR Doc. 77-18129, appearing at
page 32426, in Part VI of the issue of Fri-
day, June 24, 1977, the EFFECTIVE
DATE should be changed to read "June
24,1977"
[FBL-752-2]
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Units and Abbreviations
Correction
In FR Doc. 77-20557, appearing on
page 37000 in the issue for Tuesday,
July 19, 1977, in the second column.
{ 60.3 (a) should be changed so that the
last abbreviation reads as follows:
"»gmlcrogram10-« gram".
RULES AND REGULATIONS
66
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Petroleum Refinery Fluid Catalytic Cracking
Unit Catalyst Regenerators; Correction
AGENCY: Environmental Protection
Agency.
ACTION: Correction.
SUMMARY: This document corrects the
final rule that appeared at page 32425 in
the FEDERAL REGISTER of Friday, June 24,
1977 (FR Doc. 77-18129).
EFFECTIVE DATE: August 4,1977.
FOR FURTHER INFORMATION CON-
TACT:
Don R. Goodwin, Emission Standards
and Engineering Division, Environ-
mental Protection Agency, Research
Triangle Park, North Carolina 27711,
telephone 919-541-5271.
Dated: July 29,1977.
ERIC O. STORK,
Acting Assistant Administrator
for Air and Waste Management.
In FR Doc. 77-18129 appearing on
page 32425 in the FEDERAL REGISTER of
Friday, June 24, 1977, §§ 60.102(a) (2)
and 60.105(e> (1) on page 32427 are cor-
rected as follows:
1. In § 60.102(a) (2), the word "period"
is added in the fourth line immediately
following the words "in any one-hour."
2. In § 60.105(e) (1), "hourly period" in
the first line is corrected to read "one-
hour periods."
(Sec. Ill, 114, 301 (a) of the Clean Air Act aa
amended [42 O.S.C. 1857C-6. 1B57C-9, 1857g
[PR Doc.77-22357 Filed 8-3-77;8:45 am]
FEDERAL REGISTER, VOL. 42,
NO. 150THURSDAY, AUGUST 4, 1977
FEDERAL REGISTER, VOL. 4J,
NO. 144WEDNISDAY, JULY J7, 1977
67
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Amendments to Subpart D; Correction
AGENCY: Environmental Protection
Agency.
ACTION: Correction.
SUMMARY: This document corrects the
final rule that appeared at page 51397 in
the FEDIKAL RIGISTKH of Monday, No-
vember 22, 1976 (FR Doc. 76-33968).
EFFECTIVE DATE: August 15, 1977.
FOR FURTHER INFORMATION CON-
TACT:
Don R. Goodwin, Emission Standards
and Engineering Division, Environ-
mental Protection Agency, Research
Triangle Park, N.C. 27711, Telephone
No. 919-541-5271.
Dated August 8. 1977.
EDWARD F. TUERK,
Acting Assistant Administrator,
tor Air and Waste Management.
In FR Doc. 76-33966, §§ 60.45(1) (4.)
and 60.45(f) (5) on page 51399 are cor-
rected as follows:
§ 60.45 [Amended]
1. In 5 60.45U) (4) (iii) "F,=0.384 som
CCs/J" in the fourth line is corrected to
read "F,=0.384X10-' scm CO./J."
2. In J60.45(f)(4)(lT) a ten paren-
thesis is inserted in the second line be-
tween "dscm/J" and "8,740."
3. S 60.45(f) (4) (v) is corrected to read
as follows:
§ 60.45 Emission and fuel monitoring.
* * *
(f) * *
(4) ...
(v) For bark F=2.589X10-* dscm/J
(9,640 dscf/million Btu) and Fc=0.500
XIO'7 scm CO,/J (1,860 scf CO2/million
Btu). For wood residue other than bark
F=2.492XIO-'dscm/J (9,280dscf/million
Btu) and Fc=0.494XIO-' scm
(1,840 scf CCVmillion Btu).
4. In $ 60.45(1) (5) the F factor and P.
factor equations in SI units are corrected
to read as follows:
»_.«-. [227.2 (pet. H)+95.5 (pet. Q+35.6 (pot. S)+8.7 (pet. N)-28.7 (pet. O)]
GCV
2.0X10-* (pet. C)
c~ GCV
(See. 111. 114. 301 (a) of the Clean Air Act
a* amended (43 UB.C. 1857C-6. 18»7c-«,
1867g(a)).)
I FR Doc.77-23402 Filed 8-13-TT;8:45 ami
FEDERAL REGISTER, VOL. 42,
NO. 157MONDAY, AUGUST 19/1977
IV-168
-------
68
RULES AND REGULATIONS
Title 40Protection of Environment
CHAPTER (-^ENVIRONMENTAL
PROTECTION AGENCY
[FRL 776-t]
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
PART 61NATIONAL EMISSION STAND-
ARDS FOR HAZARDOUS AIR POLLUTANTS
Authority Citations; Revision
AGENCY: Environmental Protection
Agency.
ACTION: Final rule.
SUMMARY: This action revises the au-
thority citations for Standards of Per-
formance for New Stationary Sources
and National Emission Standards for
Hazardous Air Pollutants. The revision
adopts a method recommended by the
FEDERAL REGISTER for identifying which
sections are enacted under which statu-
tory authority, making the citations
more useful to the reader.
EFFECTIVE DATE: August 17, 1977.
FOR FURTHER INFORMATION CON-
TACT:
Don R. Goodwin, Emission Standards
and Engineering Division, Environ-
mental Protection Agency, Research
Triangle Park, N.C. 27711, telephone
919-541-5271.
SUPPLEMENTARY INFORMATION:
This action is being taken in accordance
with the requirements of 1 CFR 21.43
and is authorized under section 301 (a)
of the Clean Air Act, as amended, 42
U.S.C. 1857g(a). Because the amend-
ments are clerical in nature and affect
no substantive rights or requirements,
the Administrator finds it unnecessary
to propose and invite public comment.
Dated: August 12,1977.
DOUGLAS M. COSTUE,
Administrator.
Parts 60 and «1 of Chapter I. Title 4t
of the Code of Federal Regulations are
revised as follows:
1. The authority citation following the
table of sections in Part 60 I* revised to
read as follows:
AUTHORITY: Sec. Ill, 301 (a) of the Cleaa
Air Act w amended (43 U.S.C. 1857C-6, 1M7(
(a)), unlen otherwise noted.
2. Following §! 60.10 and 60.24(g) the
following authority citation is added:
(Sec. 116 of the Clean Air Act a* amende*
(43 U.S.C. 1857d-l).)
3. Following §160.7, 60.8, 60.», 80.11.
60.13, 60.45, 60.46, 60.53, 60.54, 60.63,
60.64, 60.73, 60.74, 60.84, 60.85, 60.03,
60.105, 60.106, 60.113, 60.123, 60.133.
60.144, 60.153, 60.154, 60.165, 60.166,
60.175, 60.176, 60.185, 60.186, 60.194.
60.195, 60.203, 60.204, 60.213, 60.214,
60.223, 60.224, 60.233, 60.234, 60.243.
60.244, 60.253, 60.254, 60.264, 60.265.
60.266, 60.273, 60.274, 60.275 and Ap-
pendices A, B, C, and D, the following
authority citation is added:
(Sec. 114 of the Clean Air Act as *m*n**4
(43 0.S.C. 1857C-9).).
4. The authority citation following the
table of sections in Part 61 is, revised to
read as follows:
AUTHORITY: Sec. 113, 301 (a) of the Clean
Air Act as amended (42 U.3.C. 1857C-7, 18*7g
(a)), unless otherwise noted.
5. Following I 61.16, the following au-
thority citation is added:
(Sec. 116 of the Clean Air Act a* amende*
(43 U.S.C. 1857d-l).)
6. Following !f 61.09, 61.10, 61.12.
61.13, 61.14, 61.15, 61.24, 61.33, 61.34.
61.43, 61.44, 61.53. 61.54, 61.55, 61.67.
61.68, 61.69, 61.70, 61.71, and Appendices
A and B, the following authority citation
i- added:
(Sec. 114 of the Clean Air Act as amended
(43 UJS.C. 1857C-9).)
[FR Doc.77-23837 Filed 8-16-77;8:4» an)
FEDERAL REGISTER, VOL. 42, NO. 159WEDNESDAY, AUGUST 17, 1*77
IV-169
-------
RULES AND REGULATIONS
69
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Revision to Reference Methods 1-8
AGENCY: Environmental Protection
Agency.
ACTION: Final Rule.
SUMMARY: This rule revises Reference
Methods 1 through 8. the detailed re-
quirements used to measure emissions
from affected facilities to determine
whether they are in compliance with a
standard of performance. The methods
were originally promulgated December
23, 1971, and since that time several re-
visions became apparent which would
clarify, correct and improve the meth-
ods. These revisions make the methods
easier to use, and improve their accuracy
and reliability.
EFFECTIVE DATE: September 19, 1977.
ADDRESSES: Copies of the comment
letters are available for public inspection
and copying at the U.S. Environmental
Protection Agency, Public Information
Reference Unit (EPA Library), Room
2922, 401 M Street, S.W., Washington.
D.C. 20460. A summary of the comments
and EPA's responses may be obtained
upon written request from the EPA Pub-
lic Information Center (PM-215), 401
M Street, S.W., Washington, D.C. 20460
(specify "Public Comment Summary:
Revisions to Reference Methods 1-8 In
Appendix A of Standards of Performance
for New Stationary Sources").
FOR FURTHER INFORMATION CON-
TACT:
Don R. Goodwin, Emission Standards
and Engineering Division, Environ-
mental Protection Agency, Research
Triangle Park, North Carolina 27711,
telephone No. 919-541-5271.
SUPPLEMENTARY INFORMATION:
The amendments were proposed on June
8, 1976 (40 FR 23060). A total of 55 com-
ment letters were received during the
comment period34 from industry, 15
from governmental agencies, and 6 from
other interested parties. They contained
numerous suggestions which were incor-
porated in the final revisions.
Changes common to all eight of the
reference methods are: (1) the clarifica-
tion of procedures and equipment spec-
ifications resulting from the comments,
(2> the addition of guidelines for al-
ternative procedures and equipment to
make prior approval of the Administra-
tor unnecessary and (3) the addition of
an introduction to each reference meth-
od discussing the general use of the
method and delineating the procedure
for using alternative methods and equip-
ment.
Specific changes to the methods are:
METHOD 1
1. The provision for the use of more
than two traverse diameters, when spec-
ified by the Administrator, has been
deleted. If one traverse diameter is In a
plane containing the greatest expected
concentration variation, the intended
purpose of the deleted paragraph will be
fulfilled.
2. Based on recent data from Fluidyne
(Particulate Sampling Strategies for
Large Power Plants Including Nonuni-
form Flow, EPA-600/2-76-170, June
1976) and Entropy Environmentalists
(Determination of the Optimum Number
of Traverse Points: An Analysis of
Method 1 Criteria (draft), Contract No.
68-01-3172), the number of traverse
points for velocity measurements has
been reduced and the 2:1 length to width
ratio requirement for cross-sectional lay-
out of rectangular ducts has been re-
placed by a "balanced matrix" scheme.
3. Guidelines for sampling in stacks
containing cyclonic flow and stacks
smaller than about 0.31 meter in diam-
eter or 0.071 m* in cross-sectional area
will be published at a later date.
4. Clarification has been made as to
when a check for cyclonic flow is neces-
sary; also, the suggested procedure for
determination of unacceptable flow con-
ditions has been revised.
METHOD 2
1. The calibration of certain pitot tubes
has been made optional. Appropriate con-
struction and application guidelines have
been included.
2. A detailed calibration procedure for
temperature gauges has been included.
3. A leak check procedure for pitot
lines has been included.
METHOD 3
1. The applicability of the method has
been confined to fossil-fuel combustion
processes and to other processes where it
has been determined that components
other than O2, CO2, CO, and N2 are not
present in concentrations sufficient to
affect the final results.
2. Based on recent research informa-
tion (Particulate Sampling Strategies for
Large Power Plants Including Nonuni-
form Flow, EPA-600/2-76-170, June
1976), the requirement for proportional
sampling has been dropped and replaced
with the requirement for constant rate
sampling. Proportional and constant rate
sampling have been found to give essen-
tially the same result.
3. The "three consecutive" require-
ment has been replaced by "any three"
for the determination of molecular
weight, CO, and O2.
4. The equation for excess air has been
revised to account for the presence of CO.
5. A clearer distinction has been made
between molecular weight determination
and emission rate correction factor
determination.
6. Single point, integrated sampling
has been included.
METHOD 4
1. The sampling time of 1 hour has
been changed to a total sampling time
which will span the length of time the
pollutant emission rate is being deter-
mined or such time as specified in an
applicable subpart of the standards.
2. The requirement for proportional
sampling has been dropped and replaced
with the requirement for constant rate
sampling.
3. The leak check before the test run
has been made optional; the leak check
after the run remains mandatory.
METHOD 5
1. The following alternatives have
been included in the method:
a. The use of metal probe liners.
b. The use of other materials of con-
struction for filter holders and probe
liner parts.
c. The use of polyethylene wash bot-
tles and sample storage containers.
d. The use of desiccants other than
silica gel or calcium sulfate, when
appropriate.
e. The use of stopcock grease other
than silicone grease, when appropriate.
f. The drying of filters and probe-filter
catches at elevated temperatures, when
appropriate.
g. The combining of the filter and
probe washes into one container.
2. The leak check prior to a test run
has been made optional. The post-test
leak check remains mandatory. A meth-
od for correcting sample volume for ex-
cessive leakage rates has been included.
3. Detailed leak check and calibration
procedures for1 the metering system have
been included,
METHOD- 6
1. Possible interfering agents of the
method have been delineated.
2. The options of: (a) using a Method
8 impinger system, or (b) determining
SOj simultaneously with particulate
matter, have been included in the
method.
3. Based on recent research data, the
requirement i'or proportional sampling
has been dropped and replaced with the
requirement for constant rate sampling.
4. Tests have shown that isopropanol
obtained from commercial sources oc-
casionally hasi peroxide impurities that
will cause erroneously low SO. measure-
ments. Therefore, a test for detecting
peroxides in isopropanol has been in-
cluded in the method.
5. The leak check before the test run
has been made optional; the leak check
after the run remains mandatory.
6. A detailed calibration procedure for
the metering system has been included
in the method.
METHOD 7
1. For variable wave length spectro-
photometers, a scanning procedure for
determining the point of maximum ab-
sorbance has been incorporated as an
option.
METHOD 8
1. Known interfering compounds have
been listed to avoid misapplication of
the method.
2. The determination of filterable
particulate matter (including acid mist)
simultaneously with SO, and SO2 has
been allowed where applicable.
3. Since occassionally some commer-
cially available quantities of isopropanol
FEDERAL REGISTER, VOL. 42, NO. 160THU«..i>AY, AUGUST 18, 1977
IV-170
-------
RULES AND REGULATIONS
have peroxide impurities that wffl cause
erroneously high sulfuric acid mist meas-
urements, a test for peroxides to Isopro-
panol has been Included in the method.
4. The gravimetric technique for mois-
ture content (rather than volumetric)
has been specified because a mixture of
Isopropyl alcohol and water will have a
volume less than the sum of the volumes
of its content.
5. A closer correspondence has been
made between similar parts of Methods
8 and 5.
MISCELLANEOUS
Several commenter? questioned the
meaning of the term "subject to the ap-
proval of the Administrator" in relation
to using alternate test methods and pro-
cedures. As denned In I 60.2 of subpart
A, the "Administrator" includes any au-
thorized representative of the Adminis-
trator of the Environmental Protection
Agency. Authorized representatives are
EPA officials in EPA Regional Offices or
State, local, and regional governmental
officials who have been delegated the re-
sponsibility of enforcing regulations un-
der 40 CFR 60. These officials hi consulta-
tion with other staff members familiar
with technical aspects of source testing
will render decisions regarding accept-
able alternate test procedures.
In accordance with section 117 of the
Act, publication of these methods was
preceded by consultation with appropri-
ate advisory committees, Independent
experts, and Federal departments and
agencies.
(Sees. Ill, 114 and 301 (a) of the Clean Air
Act, «ec. 4(») at Pub. U No. 01-604, 84 Stat.
1683; sec. *(a) of Pub. L. No. 91-604, 64 Stat.
1687; sec. 2 oT Pub. L. No. 90-148, 81 Stat. 5.) shall be calculated from the
following equation, to determine the upstream and
downstream distances.
!>.=
ZLW
L+W
RMIAl MCISTH, VOL 42, NO. 160THUISDAY, AUGUST 18, 1977
IV-171
-------
RULES AND REGULATIONS
50
C/) ,-
2?
6
Q.
LU
> 30
oc
0.5
DUCT DIAMETERS UPSTREAM FROM FLOW DISTURBANCE (DISTANCE A)
1.0 1.5 2.0
2.5
I
I
O
oc
20
5 10
\
T
A
_
1
J
L
3
rl
4
'DISTURBANCE
MEASUREMENT
?-- SITE
DISTURBANCE
* FROM POINT OF ANY TYPE OF
DISTURBANCE (BEND, EXPANSION. CONTRACTION, ETC.)
3456789
DUCT DIAMETERS DOWNSTREAM FROM FLOW DISTURBANCE (DISTANCE B)
Figure 1-1. Minimum number of traverse points for paniculate traverses.
10
where £= length and »'= width.
2.2 Determining the Number of Traverse Points.
2.2.1 Paniculate Traverses. When the eight- and
two-diameter criterion can be met, the minimum number
of traverse points shall be: (1) twelve, (or circular or
rectangular stacks with diameters (or equivalent di-
ameters) greater than 0.61 meter (24 in.); (2) eight, for
circular stacks with diameters between 0.30 and 0.61
meter (12-24 in.); (3) nine, for rectangular stacks with
equivalent diameters between 0.30 and 0.61 meter (12-24
in.).
When the eight- and two-diameter criterion cannot be
met, the minimum number of traverse points is deter-
mined from Figure 1-1. Before referring to the figure,
however, determine the distances from the chosen meas-
urement site to the nearest upstream and downstream
disturbances, and divide each distance by the stack
diameter or equivalent diameter, to determine the
distance in terms of the number of duct diameters. Then,
determine from Figure 1-1 the minimum number of
traverse points that corresponds: (1) to the number of
duct diameters upstream; and (2) to the number of
diameters downstream. Select the higher of the two
minimum numbers of traverse points, or a greater value,
so that for circular stacks tbe number is a multiple of 4,
and for rectangular stacks, the number is one Bf those
shown in Table 1-1.
TART.I 1-1. Crou-sccttonal hioat for rectangular i/acki
Ma-
trix
Number oftrascrgc point*:
12..
!«..
20-..
26..
30..
38..
42..
49-.
out
313
4X3
4x4
5x4
5x5
6x5
7rf
7x7
FCDERAL REGISTER, VOL. 42, NO. 160THURSDAY, AUGUST 18, 1977
IV-172
-------
50
0.5
RULES AND REGULATIONS
DUCT DIAMETERS UPSTREAM FROM FLOW DISTURBANCE (DISTANCE A)
1.0 1.6 2.0
25
I
I
40
O
a.
LU
CO
cc
30
LU
00
13
Z
-20
I
^'DISTURBANCE
MEASUREMENT
f- >- SITE
2 10
DISTURBANCE
I
;34 567 89 10
DUCT DIAMETERS DOWNSTREAM FROM FLOW DISTURBANCE (DISTANCE R)
Figure 1-2. Minimum number of traverse points for velocity (nonparticulate) traverses.
2.2.2 Velocity (Non-Particulate) Traverses. When
Telocity or volumetric flow rale is to be determined (but
not particulate mailer), the same procedure as that for
paniculate traverses (Section 2.2.1) is followed, eicept
that Figure 1-2 may be used instead of Figure 1-1.
2.3 Cross-Sectional Layout and Location ol Traverse
Points.
2.3.1 Circular Slacks. Locate the traverse points on
two perpendicular diameters adcording to Table 1-2 and
Hie example shown in Figure 1-3. Any equation (for
examples, see Citations '2 and 3 in the Bibliography) that,
gives the same values as those in Table 1-2 may be used
in lieu of Table 1-2.
For particulale traverses, one of the diameters must be
in a plane containing the greatest expected concentration
variation, e.g., after bends, one diameler shall bo in the
plane of the bend. This requirement becomes less critical
as the distance from the disturbance increases; therefore,
wilier diameter locations may be used, subject U> approval
of the Administrator.
In addition, for stacks having diameters greater lhan
0.61 m (24 in.) no Iraverse points shall be located witlnn
2.5 centimeters (1.00 In.) of the stack walls; and for stack
diameters equal to or loss than 0.61 m (24 in.), no tra\erse
points shall be located within 1.3cm (0.50 in.) of the stack
walls. To meet these ciiteria, observe the procedures
given below.
2.3.1.1 Slacks With Diameters Greater Than 0.61 m
(24 in.). When any of the traverse points as located m
Section 2.3.1 fall witlnn 2.6cm (1.00m.) of the stack walls,
relocate them away fiom the stack walls to. (1) a distance
of 2.5 cm (1.00 in.), or (2) a distance equal to the nozzle
inside diameter, whichever is larger. These relocated
Iraverse points (on each end of a diameter) shall be the.
"adjusted" traverse points.
Vt henever two successive traverse points are combined
to form a single adjusted traverse point, treat the ad-
justed point as two separate traverse points, both in the
sampling lor velocity nieasureinentl procedure, and in
recoidmg the data.
TOERAL REGISTER. VOL. 42, NO. 160THURSDAY, AUGUST It, 1977
IV-173
-------
RULES AND REGULATIONS
TRAVERSE
POINT
1
2
3
4
5
6
DISTANCE,
% of diameter
4.4
14.7
29 .5
70.5
85.3
95.6
0) In stecb harlag tangential Inlets or other duct con-
fliromtlou which tend to Induce swirling; in these
instances, the presence or absence of cyclonic flow at
the sampling location must be determined. The following
techniques are acceptable for this determination.
Figure 1-3. Example showing circular stack cross section divided into
12 equal areas, with location of traverse points indicated.
Table 1-2. LOCATION OF TRAVERSE POINTS IN CIRCULAR STACKS
(Percent of stack diameter from inside wall to traverse point)
Traverse
point
number
on a
diameter
1
2
3
-------
RULES AND REGULATIONS
1.90-2.54 cm*
(0.75 -1.0 in.)
r^MTJM>.'.U«flJ.gV'irEy
i 7.62 era (3 in.)*
TEMPERATURE SENSOR
SUGGESTED (INTERFERENCE FREE)
PITOT TUBE THERMOCOUPLE SPACING
Figure 2-1. Type S pilot tube manometer assembly.
2.1 Type 8 Pilot Tube. The Type 8 phot tub*
(Figure 2-1) shall be made of metal tubing (e.g., stain-
lees steel). It is recommended that the external tubing
diameter (dimension D,, Figure 2-2b) be between 0.48
and 0.95 centimeters (fit and H inch). There shall be
an equal distance from the base of each leg of the pitot
tube to its face-opening plane (dimensions PA and Pe,
Figure 2-2h); It is recommended that this distance be
between 1.05 and 1.50 times the eiternal tubing diameter.
The face openings of the pitot tube shall, preferably, be
aligned as shown in Figure 2-2; however, slight misalign-
ments of the openings are permissible (see Figure 2-3).
The Type 8 pitot tube snail have a known coefficient,
determined as outlined in Section 4. An identification
Dumber shall be assigned to the pitot tube; this number
shall be permanently marked or engraved on the body
f the tube.
HOISTH, VOL. 43, NO. I «0THURSDAY, AUGUST II, 1977
IV-175
-------
RULES AND REGULATIONS
TRANSVERSE
TUBE AXIS
V
FACE
OPENING
PLANES
(a)
A SIDE PLANE
LONGITUDINAL
TUBE AXIS *~
)
\
Dt
t
A
B
PA
PB
NOTE:
1.05Dt< P<1.50Dt
B-SIDE PLANE
(b)
A ORB
e-3-
(c)
Figure 2-2. Properly constructed Type S pitot tube, shown
in: (a) end view; face opening planes perpendicular to trans-
verse axis; (b) top view; face opening planes parallel to lon-
gitudinal axis; (c) side view; both legs of equal length and
centerlines coincident, when viewed from both sides. Basel-
line coefficient values of 0.84 may be assigned to pitot tubes
coristructed this way.
FEDEML UGISTEK, VOL 43, NO. l«THUtSDAY, AU60ST ft,
IV-176
-------
TRANSVERSE
TUBE AXIS
RULES AND REGULATIONS
I w I
LONGITUDINAL
TUBE AXIS
M
(g)
Figure 2-3. Types of face-opening misalignment that can result from field use or im-
proper construction of Type S pilot tubes. These will not affect the baseline value
of Cp(s) so long as ai and a2 < 10°, fa and fa < 5°. z < 0.32 cm (1/8 in.) and w <
0.08 cm (1/32 in.) (citation 11 in Section 6).
KDERAL RBCISTH, VOL. 42, NO. 160THURSDAY, AUGUST 18, 1977
IV-177
-------
RULES AND REGULATIONS
A standard pilot tube may be used instead o'& Type:8,
provided that it meets the ,p«-ilications of Sections 27
and 4 >; note, however, that the static and Impact
pn-s-iire holes of standard pilot tubes are susceptible to
phmcmg in particulatc-laden eos streams. 1 hen-fore
whenever a standard pilot tube is used to perform a
tr.u-.-rse. adequate proof must lie furimhed that the
opi-nincs of the pilot tube have nol plumed up during the
n ucis,. period this ean be done by taking a velocity
, !, Ap reading at the final li averse point, c ean ing out
t'». .Vipul and static holes of the standardI pi ot tube by
luek-purcing" with pressurized air. and then taking
another A;> reading If the Ap readings made before and
after the air puree are the same < -5 p,-r«-n )tlu traverse
i. acceptable. Otherwise, reject the run Note that if Ap
at The final traverse point is unsuitably ow another
P nut may be selected If "back-purging at regular
nterv. Is ,s partof the procedure, then comparative Ap
n.ulmss shall be taken, as above, for the last two back
purees at which suitably high Ap readings are observed.
>1 Differential Pressure Gauge An inclined manom-
eter or equivalent device is used Most sampling trains
are equipped with a 10-in. (water column) mcluied-
verticTmimrlmV having 0 01-m. n,O divisions on he
0- to 1-in. inclined scale, and 0.1-m. H.O'divisions on the
1- to 10-m. vertical wale. This type of manometer (or
other gauge of equivalent sensitivity) is satisfactory for
the measurement of Ap values as low as 1.3 mm 0.05 in )
H,O However a differential pressure gauge of greater
SrStivity shall be used (subject to the approval of the
Administrator), if any of the following "found to be
true: (1) the arithmetic average of all Ap readings at the
traverse points in the stack is less than 13 mm_(006 in)
H,O- (2) for traverses of 12 or more points, more than 10
percent of the individual Ap readings are below 1.3 mm
(0.05 m.) HK); (3) for traverses of fewer than 12 pointo,
more than one Ap reading is below 1.3mni (OOBm.)HsO
Citation 18 in Section 6 describes commercially available
instrumentation for the measurement ol low-range gas
'iTa'rfalternative to criteria (1) through (3) above, the
following calculation may be performed to determine the
necessity of using a more sensitive differential pressure
gauge.
T=
!C VAP".
where:
Ap,=Individual velocity bead reading at a traverse
point, mm HiO (in. H.O).
n=Total number of traverse points.
A'=0.13 mm HiO when metric units are used and
0.005 in HiO when English units are used.
If T is greater than 1.05, the velocity head data are
unacceptable and a more sensitive differential pressure
gauge must be used.
NOTE.If differential pressure gauges other than
inclined manometers are used (e.g., magnehelic gauges),
their calibration must be checked after each teafseries.
To check the calibration of a differential pressure gauge,
compare Ap readings of the gauge with those of a gauge-
oil manometer at a minimum of three points, approxi-
mately represenling the range of Ap values in the stack.
If, at each point, the values of Ap as read by the differen-
tial pressure gauge and gauge-oil manometer agree to
within i percent, the differenlial pressure gauge shall be
considered to be in proper calibration. Otherwise, the
test series shall either be voided, or procedures to adjust
the measured Ap values and final results shall be used,
subject to Ihe approval of the Adminislralar.
2.3 Temperature Gauge. A thermocouple, liquid-
filled bulb thermometer, bimetallic thermometer, mer-
'Ury-in-glass thermometer, or other gauge capable of
measuring temperature to within 1.5 percenl of the mini-
num absolute stack temperature shall be used. The
lUUm aDSOlUm SUU;K briuinua^Luo ouuu * ~u*.. ,.___
temperature gauge shall be attached to the pilot tube
such that the sensor tip doas not touch any metal; th»
gauge shall be in an interference-free arrangement with
respect to the pitot tube face openings (see Figure 2-1
and also Figure 2-7 in Section 4). Alternate positions may
be used if the pitot tube-temperature gauge system U
calibrated according to the procedure of Section 4. Pro-
vided that a difference of not more than 1 percent In th»
average velocity measurement is introduced, the tern-
perature gauge need not be attached to the pilot tube:
tins alternative is subject to the approval of the
Administrator.
2.4 Pressure Probe and Gauge. A piezometer tube and
mercury- or water-tilled (J-tube manometer capable of
measuring stack pressure to within 2.5 mm (0.1 in.) Fig
is used. The static tap of a standard type pilot tube or
one leg of a T>pe X pilot tube with the face opening
pl.ines posiiioned parallel to the gas flow may also be
used as the pressure probe.
2.5 Harometor. A mercury, aneroid, or other barom-
eter capable of measuring atmospheric pressure to
within 2.5 mm Hg (0.1 In. Ilg) may be used. In many
cases, the barometric reading may be obtained from a
nearby national weather service station, in which case
the station value (which is the absolute barometric
pressure) shall be requested and an adjustment for
elevation differences between the weather station and
Hie sampling point shall be applied at a rate of minus
2 5 mm (0.1 in.) Ilg per 30-meter (100 foot) elevation
Increase, or vice-versa for elevation decrease.
2.6 Gas Density Determination Equipment. Method
3 equipment, If needed (see Section 3.6), to determine
the stack gas dry molecular weight, and Reference
Method 4 or Method 5 equipment for moisture content
determination; other methods may be used subject to
approval of the Administrator.
2.7 Calibration Pilot Tube- When calibration of the
Type 8 pltot tube is necessary (see Section 4), a standard
pitot tube is used as a reference. The standard pltot
tube shall, preferably, have a known coefficient, obtained
either (1) directly from the National Bureau of Stand-
ards, Route 270, Quince Orchard Road, Uaithersburg,
Maryland, or C2) by calibration against another standard
pitot tube with an N BS-traceable coefficient. Alter-
natively, a standard pitot tube designed according to
the criteria given in 2.7.1 through 2.7.5 below and illus-
trated In Figure 2-4 (see also Citations 7, 8, and 17 in
Seclion 6) may be used. Pilot tubes designed according
to these specifications will have baseline coethcients of
about O.eo±0.01.
2.7.1 Hemispherical (shown in Figure2-4), ellipsoidal,
or conical tip.
2 7.2 A minimum of six diameters straight run (based
upon D, the external diameter of the tube) between the
tip and the stallc pnsssure holes.
2.7.3 A nnnimun of eight diameters straight run
between the static pressure holes and the cenlorhne of
the exlernal tube, fo1 lowing the 90 degree bend.
274 Static pressure holes of equal size (approximately
0.1 />), equally spaced ma piezometer ring configuration.
2.7.5 Ninety degree bend, with cuived or niltercd
junction.
2 8 Differential Pressure Gauge for Type 8 Pitot
Tube Calibration. An inclined manometer or equivalent
is used. If the single-velocity calibration technique is
employed (see Seclion 4.1.2.3), the cahbralion differen-
tial pressure gauge shall be readable to the nearesl 0.13
mm HzO (0.005 in. HiO). For multivelocity calibrations,
the gauge shall be readable to the nearest 0.13 mm hjO
(0.005 in HiO) for Ap values between 1.3 and 25 mm HiO
(0.05 and 1.0 In. HiO), and to the nearest 1.3 mm HjO
(0.05 in. HjO) for Ap values above 25 mm HiO (1.0 In,
HiO). A special, more sensitive gauge will be required
to read Ap values below 1.3 mm HiO [0.05 In. HiO)
(see Citation 18 in Section 6).
(J*
en
CURVED OR
MITEREO JUNCTION
STATIC
HOLES
HEMISPHERICAL
TIP
Figure 2-4. Standard pitot tube design specifications.
3.1 Set up the apparatus as shown in Figure 2-1.
Capillary tubing or surge tanks installed between the
manometer and pitot tube may be used to dampen Ap
fluctuations. It is recommended, but not required, that
a pretest leak-check be conducted, as follows: (1) blow
through the pitot Impact opening until at least 7.6 cm
(3 in.) HiO velocity pressure registers on the manometer;
then, close off the impact opening. The pressure shall
remain stable for at least 15 seconds; (2) do the same for
the static pressure side, except using suction to obtain
the minimum ot 7.8 em (3 in.) HtO. Other leak-cheek
procedures, subject to the approval of the Administrator,
may be used. :
3.2 Level and zero the manometer. Because the ma
nometer level and zero may drift due to vibrations and
temperature changes, make periodic checks during the
traverse. Record all necessary data as shown in the
example data sheet (Figure 2-5).
3.3 Measure the velocity head and temperature at the
traverse points specified by Method 1. Ensure that the
proper differential pressure gauge is being used for the
range of Ap values encountered (see Section 2.2). If it ta
necessary to change to a more sensitive gauge, do so, and
remeasure the Ap and temperature readings at each tra-
verse point. Conduct a post-test leak-check (mandatory),
as described In Section 3.1 above, to validate the traverse
run.
3.4 Measure the static pressure in the stack. On*
reading is usually adequate.
3.5 Determine the atmospheric pressure.
FEDERAL REGISTER, VOL 4J, NO. 160THURSDAY, AUGUST If, 1977
IV-178
-------
RULES AND REGULATIONS
PI ANT
I1ATF RIINWn
STACK DIAME
BAROMETRIC
CROSS SECTIO
OPERATORS
PITOT TUBE I.I
AVG. COEF
LAST DATE
Traverse
Pt.No.
TER OR DIMENSION
PRESSURE, mm Hg(i
NALAREA m2(ft2)
5 m(in ) l
n HD)
i wn
PiriFWT P- =
r.AIIRRATFn
Vel. Hd..Ap
mm (in.) H£0
Stack Temperature
tj,«C(°F)
Avenge
T$,«K(OR)
SCHEMATIC OF STACK
CROSS SECTION
mm Hg (in.Hg)
^r
Figure 2-5. Velcx:ity traverse data.
KGISTEK, VOl. 47, NO. 160TOUtSDAT, AUGUST It, 1*77
IV-179
-------
RULES AND REGULATIONS
:!fl Determine tlie stack gas dry molecular weight.
For combustion processes or processes that emit essen-
lially COj, Oi, CO, and.Nt, use Method 3. For processes
emitting essentially air, an analysis need not be con-
ducted; use a dry molecular weight o( 29.0. For other
piocesses, other methods, subject to the approval of the
Administrator, must be used.
.! 7 Obtain the moisture content from Reference
Method 4 (or equivalent) or from Method 5.
.18 Dcteiimne the eross-seotional area of the stack
"i duct at the sampling location Whenever possible,
physically measure the stack dimensions lather than
UMitg blueprints.
4 1 Type, 3 Pitot Tube. Before its initial use, care- '
fully examine the Type S pitot tube in top, side, and
end views to verify that the face openings of the tube
me, aligned within the specifications illustrated in Figure
2-2 or 2-3. The pitot tube shall not be used if it fails to
meet these alignment specifications.
After verifying the face opening alignment, measure
Mid record the following dimensions of the pito> tube:
(a) the external tubing diameter (dimension D,, Figure
2-2b); and (b) the base-to-opening plane distances
(dimensions PA and Pa, Figure 2-2b). If D, is between
0.48 and 0 95 cm (W« and H in.) and if PA and Pa are
equal and between 1.05 and 1.50 Si, there are two possible
options: (1) the pitot tube may be calibrated according
to the procedure outlined in Sections 4.12 through
4.1.5 below, or (2) a baseline (isolated tube) coefficient
value of 0 84 may bo assigned to the pitot tube. Note,
however, that if the pitot tube is part of an assembly,
calibration may still be required, despite knowledge
of the baseline coefficient value (see Section 4.1 1).
If Dt, P<, and Ps are outside the specified limits, the
pilot tube must be calibrated as outlined in 4 1 2 through
4.1 5 below.
4 1.1 Typo S Pitot Tube Assemblies. During sample
and velocity traverses, the isolated Type S pitot tube is
not always used; in many instances, the pitot tube is
used in combination with other source-sampling compon-
ents (thermocouple, sampling probe, nozzle) as part of
an "assembly." The presence of other sampling compo-
nents can sometimes affect the baseline value of the Type
S pitot tube coefficient (Citation 9 in Section 6); therefore
an assigned (or otherwise known) baseline coefficient
TYPES PITOT TUBE
value may or may not be valid for a given assembly. The
baseline and assembly coefficient values will be identical
only when the relative placement of the components m
the assembly is such that aerodynamic interference
effects are eliminated. Figures '2-6 through 2-8 illustrate
interference-free component arrangements for Type S
pitot tubes having external tubing diameters between
0 48 and 0.9/5 cm (Me and H in.). Type S pilot tube assem-
blies that fail to meet any or all of the specifications of
Figures 2-6 through 2-8 shall be calibrated according to
the procedure outlined in Sections 4 1.2 through 4 1 5
below, and prior to calibration, the values ot the inter-
component spacings (pitot-nozzle, pilot-thermocouple,
pitol-probe sheath) shall be measured and recorded.
NOTE.Do not use any Type S pitot tube assembly
which is constructed such that the impact pressure open-
ing plane of the pi tot tube is below the entry plane of the
nozzle (see Figure 2-6b).
4.1 2 Calibration Setup. If the Type S pitot tube is to
be calibrated, one leg of the tube shall be permanently
marked A, and the other, J. Calibration shall be done in
a flow system having the following essential design
features:
I
em (3/4 in.) FOR On - 1.3 cm (1/2 in.)
SAMPLING NOZZLE
A. BOTTOM VIEW; SHOWING MINIMUM PITOT NOZZLE SEPARATION.
SAMPLING
PROBE
\
SAMPLING
NOZZLE
/STATIC PRESSURE
OPENING PLANE
IMPACT PRESSURE
OPENING PLANE
T
TYPES
PITOT TUBE
NOZZLE ENTRY
PLANE
SIDE VIEW; TO PREVENT PITOT TUBE
FROM INTERFERING WITH GAS FLOW
STREAMLINES APPROACHING THE
NOZZLE. THE IMPACT PRESSURE
OPENING PLANE OF THE PITOT TUBE
SHALL BE EVEN WITH OR ABOVE THE
NOZZLE ENTRY PLANE.
Figure 2-6. Proper pitot tube sampling nozzle configuration to present
aerodynamic interference; buttonhook - type nozzle; centers of nozzle
and pitot opening aligned; Dt between 0.48 and 0.95 cm (3/16 and
3/8 in.).
FEDERAL REGISTER, VOL 42, NO. 160THURSDAY. AUGUST 18, 1977
IV-180
-------
RULES AND REGULATIONS
THERMOCOUPLE
TYPE S PITOT TUBE
SAMPLE PROBE
I
THERMOCOUPLE
2 > 5.81 em j
(2 in.)
TYPE SPITOT TUBE
SAMPLE PROBE
Figure 2-7. Proper thermocouple placement to prevent interference;
Dt between 0.48 and 0.95 cm (3/16 and 3/8 in.).
TYPE SPITOT TUBE
I Ml 111
SAMPLE PROBE
*
Y>7.62cm(3inJ
Figure 2-8. Minimum pitot-sample probe separation needed to prevent interference;
Dt between 0.48 and 0.95 cm (3/16 and 3/8 in.).
4.1.2 1 The flowing gas stream must be confined to a
duct of definite cross-sectional area, either circular or
rectangular. For circular cross-sections, the minimum
duct diameter shall be 30.5 cm (12 in.); for rectangular
cross-sections, the width (shorter side) shall be at least
254cm (10 in.).
4.1 2.1 The cross-sectional area of the calibration duct
must be constant over a distance of 10 or more duct
diameters. For a rectangular cross-section, use an eqmva-
lent diameter, calculated from the following equation,
to determine the number of duct diameters:
2LW
Equation 2-1
where:
J>. = Equivalent diameter
L=Length
If'-Width
To ensure the presence of stable, fully developed flow
patterns at the calibration site, or "lesl seclion," Hie
site must be located at least eight diameters downstream
and two diameters upslream from the nearest disturb-
ances.
NOTE.The eight- and two-diameter criteria are not
absolute; other lest section locations may be used (sub-
ject to approval of the Adminislrator), provided that the
flow at the test site is stable and demonstrably parallel
to the duct axis.
4.1.2.3 The flow system shall have the capacity to
generate a test-section velocity around 915 m/min (3,000
ft/min). This velocity must be constant with time to
guarantee steady flow during calibration. Note that
Type S pilot tube coefficients obtained by single-velocity
calibration at 915 m/min (3,000 ft/min) will generally be
valid to within ±3 percent for the measurement of
velocities above 305 m/min (1,000 ft/min) and to within
±5 to 6 percent for the measurement of velocities be-
tween 180 and 305 m/min (600 and 1,000 ft/min). If a
more precise correlation between C9 and velocity is
desired, the flow system shall have the capacity to
generate at least four distinct, time-invariant tesl-section
velocities covering the velocity range from 180 to 1,525
m/inin (600 to 5,000 ft/mm), and calibration data shall
be taken at regular velocity intervals over this range
(see Citations 9 and 14 in Section 6 (or details).
4.1.2.4 Two entry ports, one each for the standard
and Type 6 pilot tubes, shall be cut in the test section;
the standard pilot entry port shall be located slightly
downstream of the Type S port, so that the standard
and Type S impact openings will lie in the same cross-
sectional plane during calibration. To facilitate align-
ment of the pilot tubes during calibration, it is advisable
that the test section be constructed of plexiglas or some
other transparent material.
4.1.3 Calibration Procedure. Note that this procedure
is a general one and must not be used without first
referring to the special considerations presented in Sec-
tion 4.1.5. Note also that this procedure applies only to
single-velocity calibration. To obtain calibration data
for the A and B sides of the Type S pitot lube, proceed
as follows:
4.1.3.1 Make sure that the manometer is properly
filled and that the oil is free from contamination and is of
the proper density. Inspect and leak-check all pitol lines;
repair or replace if necessary.
4.1.3.2 Level and zero the manometer. Turn on the
fan and allow the flow to stabilize. Seal the Type S euti >
port.
4.1.3.3 Ensure that the manometer is level and zeroed.
Position the standard pilot tube at the calibration point
(determined as out lined in Sction 4.1.5.1), and align tha
tube so that its tip is pointed directly into the flow. Par-
ticular care should be taken m aligning the tube to avoid
yaw and pitch angles. Make sure that (he entry poil
surrounding tlie tube is properly scaled.
4.1.3.4 Read ApiI(i and record its value in a data table
similar to the one shown in Figure 2-9. Remove the
standard pilot tube from the duct and disconnect it fiom
the manometer. Seal the standard entry i>oit.
4.1.3,5 Connect the Type S pilot tube to the manom-
eter. Open the Type S entry poit Chock the manom-
eter level and zero. Insert and align the Type S pitot tube
so thai Us A side impact opening is at the same point as
was the standard pitot tube and is pointed directly m(o
the How. Make sure that lue entry port surrounding the
tube is properly sealed.
4.1.3.6 Read A p. and enter its value in the data table.
Remove the Type S pitot tube fiom the duct and dis-
connect it from the manometer.
4.1.3.7 Repeat steps 4.1.3.3 through 4.1.3.6 above until
three pairs of Ap readings have been obtained.
4.1.3.8 Repeat steps 4.1.3.3 through 4.1.3.7 above for
theB side of the Type S pitot tube.
4.1.3.9 Perform calculations, as- described in Section
4.1.4 below.
4.1.4 Calculations.
4.1.4.1 For each of the sii pairs of Ap readings (i.e.,
three from side A and three from side B) obtained m
Section 4.1.3 above, calculate the value of Ihe Type S
pilol lube coelhciont as follow >.
IfDEtAl VMI5IM, VOL 41, NO. «*0YHWSDAT, AUGUST II, 19*7
IV-181
-------
RULES AND REGULATIONS
PITOT TUBE IDENTIFICATION NUMBER:
CALIBRATED BYf.
.DATE:.
RUN NO.
1
2
3
"A" SIDE CALIBRATION
Apstd
cm HzO '
(in.HzO)
AP(S)
em H20
(in. H20)
Cp (SIDE A)
Cp(s)
DEVIATION
Cp{s) Cp(A)
RUN NO.
1
I
3
"B" SIDE CALIBRATION
APstd
crnHjO
(in. HaO)
AP(S)
cmH20
(in. H20)
Cp (SIDE B)
Cp(s)
DEVIATION
Cp(s)-Cp(B)
AVERAGE DEVIATION * a (A ORB)
S|Cp($)-Cp(AORB}]
MUSTBE<0.01
| Cp (SIDE A)-Cp (SIDE B) J-4-MUST BE <0.01
Figure 2-9. Pitot tube calibration data.
vbere:
Equation 2-2
according to the criteria of Sections 2.7.1 to
2.7.5 of this method.
Velocity head measured by the standard pilot
tube, cm HiO (in. HiO)
Ap.=Velocity head measured by the Type S pitot
tube, cm H,O (in. HiO)
4.1.4.2 Calculate C, (side A), the mean A-dde cost-
ficlent, ftnd
cftlculftte tt
coefficient is unknown and the tube Is designed Tallies,
4 1.4.3 Calculate the deviation of each of the three A-
side values ot c, to from C, (sideA), and the deviation od
cax-h D-side value of CV.j from c, (side B). Use the fol-
lowing equation:
Deviation =CV.)-CP(A or B)
Equation 2-3
4144 Calculate
-------
RULES AND REGULATIONS
ESTIMATED
SHEATH
BLOCKAGE
ElxW "[
UCTAREAJ
x 100
Figure 2-10. Projected-area models for typical pitot tube assemblies.
4.1.6 Field Use and Recalibration.
4.1.6.1 Field Use.
4.1.6.1.1 When a Type S pitot tube (isolated tube or
assembly) is used in the field, the appropriate coefficient
value (whether assigned or obtained by calibration) shall
be used to perform velocity calculations. For calibrated
Type S pitot tubes, the A side coefficient shall be used
when the A side of the tube faces the flow, and the B side
coefficient shall be used when the B side faces the flow;
alternatively, the arithmetic average of the A and B side
coefficient values may be used, inespective of which side
laces the flow
4 1 6.1.2 When a probe assembly Is used to sample a
small duct (12 to 36 in. in diameter), the probe sheath
sometimes blocks a significant part of the duct cross-
section, causing a reduction in the effective value of
~f w. Consult Citation 9 in Section 6 for details Con-
ventional pilot-sampling probe assemblies are not
recommended for use in ducts having inside diameters
smaller than 12 inches (Citation 16 in Section G).
4.1 6 2 Recallbration
4.1 6 2 1 Isolated Pitot Tubes After each field use, the
pitot tube shall be carefully reexammed in top, side, and
end views. 11 the pitot face openings are still aligned
within the specifications illustrated in Figure 2-2 or 2-3,
It can be assumed that the baseline coefficient of the pitot
tube has not changed. If, however, the tube has been
damaged to the extent that it no longer meets the specifi-
cations of Figure 2-2 or 2-3, the damage shall either be
repaired to restore proper alignment of the face openings
or the tube shall be discarded.
4.1.6.2.2 Pitot Tube Assemblies. After each field use,
check the face opening alignment of the pitot tube, as
in Section 4.1.6.2.1; also, remeasure the mtercomponent
spacings of the assembly. If the intercomponent spacings
have not changed and the face opening alignment is
acceptable, it can be assumed that the coeflicipnt of the
assembly has not changed. If the face opening alignment
is no longer within the specifications of Figures 2-2 or
8-8, either repair the damage or replace the pitot tube
(calibrating the new assembly, if necessary). If the intor-
oomponent spacings have changed, restore the original
spacings or recalibrate the assembly.
4.2 Standard pitot tube (If applicable). If a standard
pilot tube Is used for the velocity traverse, the tube shall
be constructed according to the criteria of Section 2,7 and
shall be assigned a baseline coefficient value of 0.99. If
the standard pitot tube Is used as part of an assembly.
the tube shall be in an interference-free arrangement
(subject to the approval of the Administrator).
4.3 Temperature Gauges. After each field use, cali-
brate dial thermometers, liquid-filled bulb thermom-
eters, thermocouple-potentiometer systems, and other
gauges at a temperature within 10 percent of the average
absolute stack temperature. For temperatures up to
405° C (761° F), use an ASTM mercury-ln-glass reference
thermometer, or equivalent, as a reference; alternatively,
either a reference thermocouple and potentiometer
(calibrated by NBS) or thermometric fixed points, e.g.,
ice bath and boiling water (corrected for barometric
pressure) may be used. For temperatures above 405° C
(761° F), use an NBS-cahbrated reference thermocouple-
potentiometer system or an alternate reference, subject
to the approval of the Administrator.
If, during calibration, the absolute temperatures meas-
ured with the gauge being calibrated and the reference
gauge agree within 1 5 percent, the temperature data
taken in the field shall be considered valid Otherwise,
the pollutant emission test shall either be considered
invalid or adjustments (if appropriate) of the test results
shall be made, subject to the approval of the Administra-
tor.
4 4 Barometer. Calibrate the barometer used against
a mercury barometer.
5. Calculation*
Carry out calculations, retaining at least one extra
decimal figure beyond thai of the acquired data Round
off figures after final calculation.
5 1 Nomenclature
A = Cross-sectional area of stack, m! (ft').
BM,= Water vapor in the gas stream (from Method f> or
Reference Method 4), proportion by volume.
CP = Pitot tube coefficient, dimensionless.
K, = Pitot tube constant,
U Q7
sec (°K)(mmH2O)
for the metric system and
R, .Q ft_ r(lbAb-mole)(in.Hg)T
80 sec |_ (°K)(in.II,0) J
for the English system.
A/i=Molecular weight of stack gas, dry basis (see
Section 3.6) g/g-mole (Ib/lb-mole).
if, = Molecular weight of stack gas, wet basis, g/g-
mole (Ib/lb-mole).
=Md (1 Bip.)+18.0 Bit* Equation 2-5
-Pb«r=Barometric pressure at measurement site, mui
Hg (in Hg)
P,= Stack static pressure, mm Hg (in Hg).
Pf=Absolute stack gas pressure, mm Hg (in. Hg).
=Pb.r+P, Equation 2-6
P.id = Standard absolute pressure, 760 mm Hg (29 92
in Hg)
Qld = Dry volumetric stack gas flow rate corrected to
standard conditions, dscm/hr (dscf,tir).
r,=Stack temperature, °C (°F).
:r. = Absolul<> stack temperature, °K (°R).
=273+t. for metnc
=460-H, for English
Equation 2-7
Equation 2-8
r,tj = Standard absolute tomperaflfre, 293 °K (528° R)
p, = Average stack gas velocity, m/sec (ft/sec)
Ap=Velocity head of stack gas, mm H|O (in. HjO).
3,600= Conversion factor, spc/lir
18.0= Molecular weight of water, g/g-mole Gb-lb-
mole).
5.2 Average stack gas velocity.
Equation 2-0
5.3 Average stack gas dry volumetric flow rate
Equation 2-10
6. Bibliography
1. Mark, L. 8. Mechanical Engineers' Handbook. New
York McGraw-Hill Book Co., Ine. 1951.
2. Perry, J. H Chemical Engineers' Handbook. New
York. McGraw-Hill Book Co., Inc. 1960.
FEDERAL IBGtSTEIt, VOL 42, NO. 160^THURSDAY, AUGUST 18, 1977
IV-183
-------
RULES AND REGULATIONS
3. Slugeliara, R. T., W. F. TotM, and W. 8. Smith.
flignifiouica of Errors in Si nek Sampling Measurements.
U.S. Environmental Protection Agency, Research
Tnaniile Park, N.C. (Presented at the Animal Meeting of
the Air 1'ollution Control Association, St. Louis, Mo.,
June 14-19. 1070.)
4 Standard Method for Sampling Slacks tor Paniculate
Matter. In: 1971 Book o( ASTM Standards, Part 23.
Philadelphia, Pa. IU71. ASTM Designation D-2W8-71.
r>. \Ynnard, J. K. Elementary Fluid Mechanics. New
Ymk. John Wiley and Sons, Inc. 1947.
ti. Hind MetersTheir Theory and Application.
\mciiran Society of Mechanical Engineers, New York,
N V l'ivi.
7 ASH RAE Handbook of Fundamentals. l'>72. p. 208.
X Annual Book of ASTM Standards. I'.iri 'Jfl. l'J74. p.
(jix.
9. Vollaro, R. F. Guidelines for Type S 1'itot Tube
Calibration. U.S. Environmental Pioieetiou Agency,
He.seaich Tiaugle Paik, N.C. (Presented at 1st Annual
Meeting, Source Evaluation LSociety, Dayton, Ohio,
September 18, 1975.)
10. Vollaro, R. F. A Type S Pilot Tube Calibration
Study. U.S. Environmental Protection Agency, Emis-
sion Measurement Branch, Research Triangle Park,
N.C. July 1974.
11. Vollaro, R. F. The Effects of Impact Opening
Misalignment on the Value of the Type S Pitot Tube
Coefficient. U.S. Environmental Protection Agency,
Emission Measurement BraJich, Reseaich Triangle
Park, N.C. October 1978.
12. Vollaro, R. F. Establishment of a Baseline Coeffi-
cient Value for Properly Constructed Typo S Pitot
Tubes. U.S. Environmental Protection Agency, Emis-
sion Measurement Branch, Research Triangle Park,
N.C. November 1976.
13. Vollaro, R. F. An Evaluation of Single-Velocity
Calibration Techniques as a Means of Determining Type
S 1'itot Tube Coefficients. U.S. Environmental Protec-
tion Agency, Emission Measurement Branch, Research
Triangle Park, N.C. August 1975.
14. Vollaro, R. F. The Use of Type S Pilot Tubes for
the Measurement of Low Velocities. U.S Environmental
Protection Agency, Emission Measurement Branch,
Research Triangle Park, N.C. Novemtar 1976.
15. Smith, Marvin L. Velocity Calibration of EPA
Type Source Sampling Probe. United Technologies
Corporation, Pratt and Whitney Aircraft Division,
East Hartford, Conn. 1975.
16. Vollaro, R. F. Recommended Procedure for Sample
Traverses in Ducts Smaller than 12 Inches in Diameter.
U.S. Environmental Prelection Agency, Emission
Measurement Branch, Research Triangle Park, N.C.
November 1976.
17. Ower, E. and H. C_Panlhurst. The Measurement
of Air Flow, 4th Ed., London, Pergamon Press. 1968.
18. Vollaro, R. F. A survey of Commercially Available
Instrumentation for the Measurement of Low-Range
Gas Velocities. U.S. Environmental Protection Agency,
Emission Measurement Branch, Research Triangle
Park, N.C. November 1976. (Unpublished Paper)
19. Gnyp, A. W., C. C. St. Pierre, D. S. Smith, D.
Mozzon, and J. Steiner. An Experimental Investigation
of the Effect of Pitot Tube-Sampling Probe Conngura-
1ions on the Magnitude of the S Type Pitot Tube Co-
efncient for Commoicially Available Source Sampling
Probes. Prepared by the University of Windsor for th«
Ministry of the Environment, Toronto, Canada. Feb-
ruary 1975.
METHOD 3 OAS ANALYSIS FOR CARBON DIOXIDB,
OXYGEN, EXCESS AIR, AND DRY MOT.KCULAR WKIOHT
1. Principle and Applicability
1.1 Principle. A gas sample is extracted from a stack,
by one of the following methods: (1) single-point, grab
>,im|>lm«j (2) single-point, integrated sampling; or (S)
multi-point, integrated sampling. The gas sample is
analyzed for percent carbon dioxide (COj), percent oxy-
gen (O;), and, if nece^ary, ix'reont carbon monoxide
(CO). If a dry molecular weight determination is to be
made, either an Orsat or a Fynte ' analyzer may be used
for the analysis; for excess air or emission rate correction
factor determination, au Orsat analyzer must be used.
1.2 Applicability. This method is applicable for de-
termining COz and Oj concentrations, excess air, and
dry molecular weight of a sample from a gas stream of a
fossil-fuel combustion process. The method may also be
applicable to other processes where it has been determined
that compounds other than COj, Oi, CO, and nitrogen
(Ni) are not present in concentrations sufficient to
affect the results.
Other methods, as well as modifications to the proce-
dure described herein, are also applicable for some or all
of the above determinations. Examples of specific meth-
ods and modifications include: (I) a multi-point samp-
ling method using an Orsat analyzer to analyse indi-
vidual grab samples obtained at each point; (2) a method
using COz or Oj and stoichiometrlc calculations to deter-
mine dry molecular weight and excess air; (3) assigning a
value of 30.0 for dry molecular weight, in lieu of actual
measurements, for processes burning natural gas, coal, or
oil. These methods and modifications may be used, but
are subject to the approval of the Administrator.
2. Apparatus
As an alternative to the sampling apparatus and sys-
tems described herein, other sampling systems (e.g.,
liquid displacement) may be used provided such systems
are capable of obtaining a representative sample and
maintaining a constant sampling rate, and are otherwise
capable of yielding acceptable results. Use of sucb
systems is subject to the approval of the Administrator.
2.1 Grab Sampling (Figure 3-1).
'2.1.1 Probe. The probe should be made of stainless
steel or borosuicote glass tubing and should be equipped
with an m-stack or out-stack fitter to remove particulate
matter (a plug of glass wool is satisfactory for this pur-
pose). Any other material inert to Oi, COi, CO, and Ni
and resistant to temperature at sampling conditions may
be used for the probe; examples of such material are
aluminum, copper, quartz glass and Teflon.
2.1.2 Pump. A one-way squeeze bulb, or equivalent,
is used to transport the gas sample to the analyior,
2.2 Integrated Sampling (Figure 3-2).
2.2.1 Probe. A probe such as that described in Section
2.1.1 is suitable.
1 Mention of trade names or specific products does not
constitute endorsement by the Environmental Protec-
tion Agency.
FEDERAL REGISTER, VOL 42, NO. 140THURSDAY. AUGUST If, 1*77
IV-184
-------
RULES AND REGULATIONS
PROBE
FLEXIBLE TUBING
FILTER (GLASS WOOL)
SQUEEZE BULB
TO ANALYZER
Figure 3-1. Grab-sampling train.
RATE METER
AIR-COOLED
CONDENSER
PROBE
\
FILTER
(GLASS WOOL)
QUICK DISCONNECT
J\
RIGID CONTAINER
Figure 3-2. Integrated gas-sampling train.
FEDERAL REGISTER, VOL 4S, NO. 160THURSDAY, AUGUST 18, W7
IV-185
-------
RULES AND 1EGULATIONS
"22 Condenser An air-cooled or water-cooled con-
ilenser, or other condenser that will not remove Ot,
< Oi CO and Ni, may be used to remove eicess moisture
whic'h would interfere with the operation of the pump
and flow meter. ,. ,
2 2 3 Valve. A noodle valve is used to adjust sample
pns flow rate.
224 Pump. A leak-tree, diaphragm-type pump, or
f mivalent is used to transport sample1 gas to the flexible
I le Install a small surge tank between the pump and
rate meter to eliminate the pulsation ejlcct of the dia-
1'hraem pump on the rotameter.
225 Rate Meter. The rotamoter, or equivalent rate
meter, used should be eapable of measuring How rate
to within ±2 percent of the selected flow rate A flow
1.1 te range of M> to 1000 em1 nun is suircosted.
226 KleiiMo Bag Anj leak-fiee plastic ie g , Tcdbr,
M>lar Teflon) or plastic-coated aluminum (e g , alumi-
i'!zed M;Url bag, or equivalent, having a capacity
i (insistent with the selected flow rate and time length
uf the te«t run, may bo used A capaaly in the range of
W to W lifers is suggested
To leak-check the bae, connect it to a water nanometer
»'id pressurize the bag to 5 to 10cm H:O (2 to 4 in H;O).
Allow to stand for 10 minutes Any displacement in the
water manometer indicates a leak An alternative leak-
check method is to prossume the bag to 5 to 10 em H:O
(2 to 4 in. H:O) and allow to stand overnight. A deflated
Lag indicates a leak.
2 2.7 Pressure Gauge A water-filled U-tuhe manom-
eter, or equivalent, of about 28 cm (12 in ) is used for
the flexible bag leak-check.
228 Vacuum Gauge A mercury manometer, or
equivalent, of at least 760 mm Hg (30 in. Hg) is used for
the sampling tram leak-check.
2 3 Analysis. For Orsat and Fyrite analyzer main-
tenance and operation procedures, follow the instructions
recommended by the manufacturer, unless otherwise
specified herein.
231 Dry Molecular Weight Determination. An Orsat
analyzer or Fyrite type combustion gas analyzer may be
"232 Emission Rate Correction Factor or Excess Air
Ijetermmation. An Orsat analyzer must be used. For
low COi (less than 4.0 percent) or high Oi (greater than
150 percent) concentrations, the measuring burette of
the Orsat must have at least 0 1 percent subdivisions.
3 Dry Molecular Weight Determination
Any of the three sampling and analytical procedures
described below may be used for determining the dry
molecular weight.
3.1 Single-Point, Grab Sampling and Analytical
311 The sampling point in the duct shall either be
at the centroid of the cross section or at a point no closer
to the walls than 1 00m (3.3/t), unless otherwise specified
by the Administrator.
312 Set up the equipment as shown In ligure s-i,
making sure all connections ahead of the analyzer are
light and leak-tree. If an Orsat analyzer is used, it is
recommended that the analyzer be leaked-checked by
following the procedure in Section 5; however, the leak-
check is optional.
313 Place the probe in the stack, with the tip of the
probe positioned at the sampling point; purge the sampl-
ing line Draw a sample into the analyzer and imme-
diately analyze it for percent COiand percent O:. Deter-
mine the percentage of the gas that Is Ni and CO by
subtracting the sum of the percent CO] and percent Oi
from 100 percent. Calculate the dry molecular weight as
indicated in Section 6.3.
314 Repeat the sampling, analysis, and calculation
procedures, until the dry molecular weights of any three
grab samples difler from their mean by no more than
0 3 ft/g-mole (0.3 IbAb-mole). Average these three molec-
ular weights, and report the results to the nearest
Olg/g-mole (IbAb-mole).
3.2 Single-Point, Integrated Sampling and Analytical
sTl "The sampling point in the duct shall be located
as specified in Section 3.1.1.
322 Leak-check (optional) the flexible bag as In
Section 2 2.6. Set up the equipment as shown in Figure
J-2 Just prior te sampling, leak-check (optional) the
train by placing a vacuum gauge at the condenser inlet,
pulling a vacuum of at least 2.50 mm Hg (10 m. Hg),
iiluggmg the outlet at the quick disconnect, and then
turning off the pump. The vacuum should remain stable
(or at least 0 5 minute. Evacuate the flexible bag. C onnect
the probe and place it in the stack, with the tip of the
probe positioned at the sampling point; purge the sampl-
ing line. Next, connect the hag and make sure that all
connections are tight and leak fiee.
323 Sample at a constant rate. The sampling run
should be simultaneous with, and for the same total
length of time as, the pollutant emission rate determma-
1 ,on Collection of at least 30 liters (1.00 ft3) of sample gas
is recommended, however, smaller volumes may be
collected, if desned .
324 obtain one integrated flue gas sample during
each pollutant emission late determination Within 8
hours after the sample is taken, analyze it for percent
CO2 and percent Oj using either an Orsat analyzer or a
Fyute-type combustion gas analyzer. If an Orsat ana-
lyzer is used, it is recommended that the Oisat leak-
< heck described in Section 5 be performed before this
determination; however, the check is optional. Deter-
mine the percentage of the gas that is Nj and CO by sub-
tracting the sum of the percent CO: and percent Oi
from UK) percent. Calculate the dry molecular weight M
indicated in Section 0.3.
3.JJ Repeat the analysis and calculation procedures
until the individual dry molecular weights for any three
analyses differ from their mean by no more than 0 3
g'g-mole (0 3 IbAb-mole). Average these three molecular
weights, and report the results to the nearest 0.1 g/g-mole
(O.llb/lb-mole).
3 3 Multi-Point, Integiatcd Sampling and Analytical
Procedure.
33.1 Unless otherwise specified by the Adminis-
trator, a minimum of eight traverse points shall be used
for circular stacks having diameters less then 0.61 m
(24 in.), a minimum of nine shall he used for rectangular
stacks having equivalent diameters less than 0.61 m
(24 in.), and a minimum of twelve traverse points shall
be used for all other cases. The traverse points shall be
located according to Method 1. The use of fewer points
is subject to approval of the Administrator.
J 3.2 Follow the procedures outlined in Sections 3.2 2
through 3.J.5, except for the following: traverse all sam-
pling points and sample at each point for an equal length
of tune Record sampling data as shown in Figure 3-3.
4. Emiition Rate Correction Factor or Exeat An Dtter-
initiation
NOTE.A Fyrite type combustion gas analyzer is not
acceptable for eicesi air or emission rate correction (actor
determination, unless approved by the Administrator.
If both percent COj and percent Oi are measured, the
analytical results of any of the three procedures given
below may also be used for calculating the dry molecular
weight.
Each of the three procedures below shall be used only
when specified in an applicable subpart of the standards.
The use of these procedures for other purposes must have
spec i lie piior appro pal of the Administrator.
4 1 Single-Point, Grab Sampling and Analjtioal
Procedure.
4 1.1 The sampling point in the duct shall either be
at the centroid of the cross-seeuon or at a point no okwr
to the walls than 1 COm (,3.3ft), unless otherwise --'pecuied
by the. Administrator.
4.1.2 Set up the equipment as shown in Figure 31,
making sure all connections ahead of the analyzer ate
tight and leak-free. Leak-check the Orsat analyzer ac-
cording lo the procedure described in Section 5. This
leak-check is mandatory.
TIME
TRAVERSE
PT.
AVERAGE
Q
1pm
% DEV.a
(MUST BE < 10%)
Figure 3 3. Sampling rate data.
4.1.3 Place the probe in the stack, with the tip of the
probe positioned at the sampling point; purge the sam-
pling line. Draw a sample into the analyzer. For emission
rate correction factor determination, Immediately ana-
lyze the sample, as outlined in Sections 4.1.4 and 4.1.5,
for percent COi or percent Oz. If excess air is desired,
proceed as follows: (1) immediately analyze the sample,
as In Sections 4.1.4 and 4.1.5, for percent COi, Oi, and
CO; (2) determine the percentage of the gas that is Ni
by subtracting the sum of the percent COj, percent Oj,
and percent CO from 100 percent; and (3) calculate
percent excess air as outlined in Section 6.2.
414 To ensure complete absorption of the COj, Oj,
or if applicable, CO, make repeated passes through each
absorbing solution until two consecutive readings are
the same. Several passes (three or four) should be made
between readings. (If constant readings cannot be
obtained after three consecutive readings, replace the
absorbing solution.)
4.1.5 After the analysis is completed, leak-check
(mandatory) the Orsat analyzer once again, as described
in Section 5. For the results of the analysis to be valid,
the Orsat analyzer must pass this leak test before and
after the analysis. NOTE.Since this single-point, grab
sampling and analytical procedure is noi nially conducted
in conjunction with a single-point, grab sampling and
analytical procedure for a pollutant, only one analysis
is ordinarily conducted. Therefore, great caie must be
taken to obtain a valid sample and analysis. Although
in most cases only CO? or Oi is required, it is recom-
mended that both COj and Oj be measured, and that
Citation 5 m the Bibliography be used to validate the
analytical data.
4 2 Single-Point, InteguUed Sampling ami Analytical
Piocedure
4.2.1 The sampling point in the duct shall be located
as specified in Section 4.1.1.
4.2.2 Leak-check (mandatory) the flexible bag as in
Section 2.2,b. Set up the equipment as shown in Figure
3-2. Just prior to sampling, leak-check (mandatory) the
train by placing a vacuum gauge at the condenser inlet,
pulling a vacuum of at least 250 mm Hg (10 in. Hg),
plugging the outlet at the quick disconnect, and then
turning off the pump. The vacuum shall remain stable
for at least 0..5 minute. Evacuate th» flexible bag. Con-
nect the probe and place it m the stack, with the tip of the
probe positioned at the sampling point; purge the sam-
pling line. Neit, connect the bag and make sure that
all connections are tight and leak free.
4.2.3 Sample at a constant rate, or as specified by the
Administrator. The sampling run must be simultaneous
with, and for the same total length of time as, the pollut-
ant emission rats determination. Collect at least 30
liters U 00 ft!) of sample gas Smaller volumes may be
collected, subject to approval of the Administrator.
4.2.4 Obtain one integrated flue gas sample during
each pollutant emission rate determination. For emission
rate coirection factor determination, analyze the sample
within 4 hours after it is taken for peicent CO«. or percent
Oj (as outlined in Sections 4.2.5 thiough 4.2.7). The
Orsat analyzer must be leak-checked (see Section 5)
before the analysis. If excess air is desired, proceed as
follows: (1) within 4 hours after the sample is taken,
analyze it (as m Sections 4.2.5 through 4.2.7; for percent
CO?. O«, and CO: (2) determine the peicentage of the
gas that is N; by subtracting the sum of the percent COi,
peicent O?, and peicent CO from 100 percent; i3) cal-
culate percent excess air, as outlined in bection 6 2.
4 2.5 To ensure complete absorption of the CO), Oi,
or if applicable, CO, make repeated passes through each
absorbing solution until two consecutive readings are the
same. Several passes (three or four) should be made be-
tween readings. ('It constant readings cannot be obtained
after three consec utive readings, replace the absorbing
solution.)
4.2.6 Repeat the analysis until the following criteria
are met:
4.2.6.f For pe-cent COi, repeat the analytical pro-
cedure until the results of any three analyses difler by no
more than (a) 0.3 percent by volume when COi Is greater
than 4.0 percent or fb) 0.2 percent by volume when COi
is less than or equal to 4.0 percent. Average the three ac-
ceptable values of percent COi and report the results to
the nearest 0.1 percent.
4.2.6.2 For percent Oj, repeat the analytical procedure
until the results of any three analyses difler by no more
FEDERAL REGISTER VOL 42, NO. 160THURSDAY, AUGUST 1«, 1977
IV-186
-------
RULES AND REGULATIONS
than (a) 0.3 percent by volume when Oi Is less than 15.0
percent or (b) 0.2 percent by volume when Oi is greater
than 15.0 percent. Average the three acceptable values ot
percent Oi and report the results to the nearest 0.1
percent.
4.2.6.3 For percent CO, repeat the analytical proce-
dure until the results of any three analyses differ by no
more than 0.3 percent. Average the three acceptable
values of percent CO and report the results to the nearest
0.1 percent.
4.2.7 After the analysis is completed, leak-check
(mandatory) the Orsat analyzer once again, as described
in Sections. For the results of the analysis to be valid, the
Orsat analyzer must pass this leak test before and after
the analysis. Note: Although in most instances only COi
or Oi is required, it is recommended that both COj and
Oi be measured, and that Citation 5 in the Bibliography
b« used to validate the analytical data.
4.3 Multi-Point, Integrated Sampling and Analytical
Procedure.
4.3.1 Both the minimum number of sampling points
and the sampling point location shall be as specified in
Section 3.3.1 of this method. The use of fewer points than
specified w Jobject to the approval of the Administrator.
4.3.2 Follow the procedures outlined in Sections 4.2.2
through 4.2.7, except for the following; Traverse all
sampling points and sample at each point for an equal
length of time. Record sampling data as shown in Figure
3-3.
6. Leak-Check Procedure for Orsat Analyzers
Moving an Orsat analyzer frequently causes it to leak.
Therefore, an Orsat analyzer should be thoroughly leak-
checked on site before the flue gas sample is introduced
into it. The procedure for leak-checking an Orsat analyzer
is:
5.1.1 Bring the liquid level in each pipette up to the
reference mark on the capillary tubing and then close the
pipette stopcock.
5.1.2 Raise the leveling bulb sufficiently to bring the
confining liquid meniscus onto the graduated portion of
the burette and then close the manifold stopcock.
5.1.3 Record the meniscus position.
5.1.4 Observe the meniscus in the burette and the
liquid level in the pipette for movement over the next 4
minutes.
5.1.5 For the Orsat analyzer to pass the leak-check,
two conditions must be met.
5.1.5.1 The liquid level in each pipette must not fall
below the bottom of the capillary tubing during this
4-minute interval.
S.I.5.2 The meniscus in the burette must not change
by more than 0.2 ml during this 4-minuteinterval.
5.1.6 If the analyzer fails the leak-check procedure, all
rubber connections and stopcocks should be checked
until the cause of the leak is identified. Leaking stopcocks
must be disassembled, cleaned, and regressed. Leaking
rubber connections must be replaced. After the analyzer
is reassembled, the leak-check procedure roust be
repeated.
(. Calculation
8.1 Nomenclature.
M <= Dry molecular weight, g/g-mole (Ib/lb-mole).
%EA=Percent excess air.
%CO2=PercentCOiby volume (dry basis).
%Oj= Percent O:by volume (dry basis).
%CO=Percent CO by volume (dry basis).
%N2=Percent Nj by volume (dry basis).
0.264= Ratio of Os to Nz in air, v/v.
0.280=Molecular weight of Ni or CO, divided by 100.
0.320=Molecular weight of Oi divided by 100.
0.440=Molecular weight of COi divided by 100.
6.2 Percent Excess Air Calculate the percent excess
air (if applicable), by substituting the appropriate
values of percent ();, CO, and NT2 (obtained from Section
4 1 3 or 4 2 4) into Equation 3-1
%Oj-0.5%CO
100
"L.0.264 %N2(%02-0.5 %CO) J
Equation 3-1
NOTE.The equation above assumes that ambient
air is used as the source of Ch and that the luel does not
contain appreciable amounts of N: (as do coke oven or
blast furnace gases). For those cases when appreciable
amounts of Ni are present (coal, oil, and natural gas
do not contain appreciable amounts of NO or when
oxygen enrichment is used, alternate methods, subject
to approval of the Administrator, are required.
6.3 Dry Molecular Weight Use Equation 3-2 to
calculate the dry molecular weight of the stack gas
Equation 3-2
NOTE The above equation does not aonsider argon
in air (about 09 percent, molecular weight of 377).
A negative error of about 04 percent is introduced.
The tester may opt to include argon in the analysis using
procedures subject to appioval of the Administrator.
7. Bibliography
1. AHshuller, A. P. Storage of Gases and Vapors in
Plastic Bags. International Journal of Air and Water
Pollution, ff. 75-81. 1963.
2. Conner, William D. and J. S. Nader. Air Sampling
Plastic Bags. Journal of the American Industrial Hy-
giene Association. $5 291-297. 1964.
3. Burrell Manual for Gas Analysts, Seventh edition.
Burrell Corporation, 2223 Fifth Avenue, Pittsburgh,
Pa. 15219. 1951
4. Mitchell, W J. and M. R, Midgett. Field Reliability
of the Orsat Analyzer. Journal of Air Pollution Control
Association 26.491-495, May 1976.
5 Shigehara, R. T., R. M. Neulicht, and W. S. Smith.
Validating Orsat Analysis Data from Fossil Fuel-Fired
Units. Stack Sampling News. *j(2):21-26. August, 1976,
METHOD 4 DETERMINATION or MOISTURE CONTENT
IN STACK GASES
1. Principle and Applicability
1.1 Principle. A gas sample is extracted at a constant
rate from the source, moisture is removed from the sam-
ple stream and determined either volumetrically or
gravimetrically.
1.2 Applicability. This method is applicable for
determining the moisture content ol stack gas.
Two procedures arc given. The first is a reference
method, for accurate determinations of moisture content
(such as are needed to calculate emission data). The
second vs an approximation method, which provides
estimates of peicent moisture to aid in setting isokmetic
sampling rates pnor to a pollutant emission measure-
ment run. The approximation method described herein
is only a suggested approach, alternative means for
approximating the moisture content, e g , drying tubes,
wet bulb-dry bulb techniques, condensation technique's,
stoichiometnc calculations, previous experience, etc.,
are also acceptable
The reference method is often conducted simultane-
ously with a pollutant emission measurement run, when
it is, calculation of peicent isokmetic, pollutant emission
rate, etc., for the run shall be based upon the results of
the reference method or its equivalent; these calculations
shall not be based upon the lesults of the approximation
method, unless the approximation method is shown, to
the satisfaction of the Administrator, U.S. Environmen-
tal Protection Agency, to be capable of yielding results
within 1 percent H?O of the reference method
NOTE The reference method may yield questionable
results when applied to satin ated gas streams or to
streams that contain water droplets Therefore, when
these conditions exist or are suspected, a second deter-
mination of the moisture content shall be made simul-
taneously with the reference method, as follows Assume
that the gas stream is saturated Attach a temperature
senior {capable of measuring to ±1° C (2° F)j to the
reference method probe. Measure the stack gas tempera-
ture at each traverse point (see Section 221) during the
reference method traverse, calculate the average stack
gas temperature. Next, determine the moisture percent-
age, either by: (1) using a psychrometnc chart and
making appropriate corrections if sta
-------
RUIE5 AND REGULATIONS
FILTER
(EITHER IN STACK
OR OUT OF STACK)
STACK
WALL
CONDENSER-ICE BATH SYSTEM INCLUDING
SILICA GEL TUBEy
AIR-TIGHT
PUMP
Figure 4-1. Moisture sampling train-reference method.
2.1.1 Probe. The probe is constructed of stainless
teel or glass tubing, sufficiently heated to prevent
water condensation, and is equipped with a filter, either
ln-«tack (e.g., a plug of glass wool inserted into the end
of the probe) or heated out-stack (e.g., as described In
Method 5), to remove paniculate matter.
When stack conditions permit, other metals or plastic
tubing may be used for the probe, subject to the approval
of the Administrator.
2.1.2 Condenser. The condenser consists of four
Smpingers connected in series with ground glass, leak-
free fittings or any similarly leak-free non-contaminating
fittings. The first, third, and fourth impmgers shall be
of the Greenburg-Smith design, modified by replacing
the tip with a 1.3 centimeter (1A inch) ID glass tube
extending to about 1.3 cm (M in-) from the bottom of
the flask. The second impinger shall be of the Greenburg-
Smith design with the standard tip. Modifications (e.g.,
using flexible connections between the impmgers, using
materials other than glass, or using flexible vacuum lines
to connect the filter holder to the condenser) may be
used, subject to the approval of the Administrator.
The first two impmgers shall contain known volumes
f water, the third shall be empty, and the fourth shall
contain a known weight of 6- to 16-mesh indicating type
nliea gel, or equivalent desiccant. If the silica gel has
been previously used, dry at 175° C (350° F) for 2 hours.
New silica gel may be used as received. A thermometer,
capable of measuring temperature to within 1° C (2° F),
shall be placed at the outlet of the fourth impinger, for
monitoring purposes.
Alternatively, any system may be used (subject to
the approval of the Administrator) that cools the sample
gas stream and allows measurement of both the water
that has been condensed and the moisture leaving the
condenser, each to within 1 ml or 1 g. Acceptable means
are to measure the condensed water, either gravi-
metrically or volumetrically, and to measure the mois-
ture leaving the condenser by: (1) monitoring the
temperature and pressure at the exit of the condenser
ud using Dalton's law of partial pressures, or (2) passing
the sample gas "stream through a tared silica gel (or
equivalent desiccant) trap, witb exit gases kept below
20° C (68° F), and determining the weight gain.
IT means other than silica gel are used to determine the
amount of moisture leaving the condenser it is recom-
mended that silica gel (or equivalent) still be used be-
tween the condenser system and pump, to prevent
moisture condensation In the pump and metering
devices and to avoid the need to make corrections for
moisture in the metered volume.
21.3 Cooling System. An ice bath container and
crushed ice (or equivalent) are used to aid in condensing
moisture.
2.1.4 Metering System. This system includes a vac-
uum gauge, leal-free pump, thermometers capable of
measuring temperature to within 3° C (5.4° F), dry gas
meter capable of measuring volume to within 2 percent,
and related equipment as shown in Figure 4-1. Other
metering systems, capable of maintaining a constant
sampling rate and determining sample gas volume, may
be used, subjectrto the approval ol the Administrator.
2,1.5 Barometer. Mercury, aneroid, or other barom-
eter capable of measuring atmospheric pressure to within
2.8 mm Hg (0.1 in. Hg) may be used. In many cases, the
barometric reading may be obtained from a nearby
national weather service station, in which case the sta-
tion value (which is the absolute barometric pressure)
shall be requested and an adjustment for elevation
differences between the weather station and the sam-
pling point shall be applied at a rate of minus 2.6 mm Hg
(0.1 in. Hg) per 30 m (100 ft) elevation increase or vice
versa for elevaiion d«crease.
2.1.6 Graduated Cylinder and,'or Balance. These
items are used to measure condensed water and moisture
caught in the silica gel to within 1 ml or 0.5 g. Graduated
cylinders shall have subdivisions no greater than 2 ml.
Most laboratory balances are capable of weighing to the
nearest 0.8 g or less. These balances are suitable for
use here.
2.2 Procedure. The following procedure is written for
a condenser system (such as the impinger system de-
scribed in Section 2.1.2) incorporating volumetric analy-
sis to measure the condensed moisture, and silica gel and
gravimetric analysis to measure the moisture leaving the
condenser.
2.2.1 Unless otherwise specified by the Administrator,
a minimum of eight traverse points shall be used for
circular stacks having diameters less than 0.61 m (24 in.),
a minimum of nine points shall be used for rectangular
stacks having equivalent diameters less than 0.61 m
(24 in.), and a minimum of twelve travers points shall
be used in all other cases. The traverse points shall be
located according to Method 1. The use of fewer points
is subject to the approval of the Administrator. Select »
suitable probe and probe length such that all traverse
points can be sampled. Consider sampling from opposite
sides of the stack (four total sampling ports) for large
stacks, to permit use of shelter probe lengths. Mark the
probe with heat resistant tape or by some other method
to denote the proper distanfe into the stack or duct for
each sampling point. Place known volumes of water in
the first two impiugers. Weigh and record the weight oS
the silica gel to the nearest 0.5 g, and transfer the silica
gel to the fourth impinger; alternatively, the «ihcagel
may first be transferred to the impinger, and the weight
of the silica gel plus impinger recorded.
2.2.2 Select a total sampling time such that a mini-
mum total gas volume of 0.60 scm (21 scf) wiil be col-
lected, at a rate no greater than 0.021 mj/mm (0.75 cfm).
When both moistuie content and pollutant emission rat*
are to be determined, the moisture determination shall
he simultaneous with, and for the same total length of
time as. the pollutant emission rate run, unless otherwise
specified in an applicable subpart of the standards.
2.2.3 Set up the sampling train as shown in Figure
4-1. Turn on the probe heater and (if applicable) the
filter heating system to temperatures of about 120° C
(248° F), to prevent water condensation ahead ol ttw
condenser; allow time for the temperatures to stabilize.
place crushed ice In the Ice batb container. It is recom-
mended, but not required, that a leak check be don*, m
follows: Disconnect the probe from tbe first impinger or
FEDERAL REGISTEK, VOL. 41, NO. 160THUtSOAY, AUGUST U, 1977
IV-188
-------
RULES AND REGULATIONS
(if applicable) from the filter holder. Plug the Inlet to the
first impmger (or filter bolder) and pull a 380 mm (15 in.)
Hg vacuum; a lower vacuum may be used, provided that
it is not exceeded during the test. A leakage rate in
excess of 4 percent ol the average sampling rate or 0.00057
mVmin (0.02 cfm), whichever is less, is unacceptable.
Following the i eak check, reconnect the probe to the
samplHig train.
2.2 4 Dialing the sampling run, maintain a sampling
rate within 10 percent ot constant rate, or as specified by
the Administrator. For each run, record the data re-
quired on the example data sheet shown in Figure 4^2.
Be sure to record the dry gas meter reading at the begin-
ning and end of each sampling time increment and when-
PLANT .
! OCATION.
OPERATOR
DATE___
RUN NO
AMBIENT TEMPERATURE
IAROMETRIC PRESSURE.
FBOBE IENGTH m(ft) <
ever sampling is halted. Take other appropriate readings
at each sample point, at least once during each time
increment.
2.2.5 To begin sampling, position the probe tip at the
first traverse point. Immediately start the pump and
adjust the flow to the desired rate. Traverse the cross
section, sampling at each traverse point for an equal
length of time. Add more ice and, if necessary, salt to
maintain a temperature of leas than 20° C (68° F) at the
silica gel outlet.
2.2.6 After collecting the sample, disconnect the probe
from the filter holder (or from the first impmger) and con-
duct a leak check (mandatory) as described in Section
2.2.J. Record the leak rate. If the leakage rate exceeds the
allowable rate, the tester shall either reject the test re-
sults or shall correct the sample volume as in Section 6 3
of Method 5. Next, measure the volume of the moisture
condensed to the nearest ml. Determine the increase in
weight of the silica gel (or silica gel plus impinger) to the
nearest 0.5 g. Record this information (see example data
abeet. Figure 4-3) and calculate the moisture percentage,
as described in 2.3 below.
2.3 Calculations. Carry out the following calculations,
retaining at least one extra decimal figure beyond that of
the acquired data. Bound off figures after final calcula-
tion.
SCHEMATIC OF STACK CROSS SECTION
TRAVERSE POINT
NUMBER
TOTAL
SAMPLING
TIME
(6). mi*.
AVERAGE
STACK .
TEMPERATURE
«C<»F)
PRESSURE
DIFFERENTIAL
ACROSS
ORIFICE METER
(AH).
mmfinj HjO
METER
READING
GAS SAMPLE
VOLUME
1*1 (ft1)
AV«
«i»
Figure 4-2. Field moisture determination-reference method.
PCMtAt teOttTM, VOL 42, NO. 160THUtSDAY, AUGUST 1«, 1*77
IV-189
-------
RULES AND REGULATIONS
FINAL
INITIAL
DIFFERENCE
IMPINGER
VOLUME,
ml
SILICA GEL
WEIGHT.
8
.
Figure 4 3. Analyticjl data reference method.
2 3.1 Nomenclature.
n,,,= Proportion of \\(uet \,tpor, bj \olnnio, in
the gas stream.
M» = Molecular weight of watiT, 18.0 g/g-mole
(18.0\b/lb-mole).
P,, = Absolute pressure (for this method, same
as barometric pressure) at the dry pas meter,
mm Hg (in. Hg).
f,td~ Standard absolute pressure, 7m) mm Hg
(29.92m. Hg).
7J = Ideal gas constant, 0.06236 (mm Hg) (m8)/
(g-mole) (°K) for metric units and 21.85 (in.
Hg) (ft')/(lb-mole) (°R) for English units.
T, = Absolute temperature at meter. °K (°R).
'7',,j=Stamlard absolute tempeiature, 293° K
(528° R).
Vm Dry gas volume measured by dry gas meter,
dem (dcf).
&Vm = Incremental dry gas volume measured by
diy gas meter at each tiaverse point, dcm
(dcf).
V»,(,id> = Dry gas volume measured by the dry gas
meter, corrected to standard conditions,
dscm (dscf).
= Volume of water vapor condensed corrected
to standard conditions, scm (scf).
V»ii{i( Volume of water vapor collected in silica
gel corrected to standard conditions, scm
(scf).
Vf= Final volume of condenser water, ml.
F,=Imtial volume, if any, of condenser water,
ml.
W, = Final weight of silica gel or silica gel plus
impmger, g.
lf,=Initial weight of silica gel or silica gel plus
impmger, g.
y=Dry gas meter calibration factor.
p.=Density of water, 0.9982 g/nil (0.002201
Ib/ml).
232 Volume of water vapor condensed.
V., (.
Kqu.ition 4 1
Where:
Jfi=0.001333 m3,'uil for metric units
=0.04707 ft'/ml for English units
233 Volume of water vapor collected in silica gel.
V
where:
£"1=0.001338 m'/g for metric units
=0.04718 ft'/g tor English units
2.3.4 Barnple gas volume.
Equation 42
\vhne
7u=0 386h "K/inm HR fur indue mills
= 17 04 "Rill llg for English units
NOTEIf the post-test K>k lAtc (Sectiun -' -' fi) ex-
ceeds the allowable rate, coiiect the VA'W of t'm in
Ki|ii»iii>n 4-3, as dcsruhed m Seetion (\ 1 n( Mel hod 3.
2 ! '> Moisture Content
Kquntlun 4-4
\"orrIn saturated 01 moisture droplet-laden gas
htreams, two calculations of the moisture content of the
stack gas shall be made, one using a value based upon
the saturated conditions (see Section 1 2), and another
based upon the results of the impinger analysis. The
lower of these two values of B,,. shall be considered cor-
rect
2 3 i> Venlication of constant sampling late. For each
time inclement, determine the AV*. Calculate the
average If the value for any time in< lenient differs from
the aveiage by more than 10 percent, ri'jw t the results
and repeat the run.
3 Approiniialion Method
The approximation method described below is pie-
sented only as a suggested method (see Section 12).
3 1 Apparatus.
31,1 Fiobe Stainless steel or glass tubing, sufliciently
heated to prevent water condensation and equipped
with a tilter (either in-staek or heated out-stack) to re-
move paniculate matter A plug of glass wool, taierted
into the end of the probe, is a satisfactory filter.
3.1 2 Impmgers. Two midget impingets, each with
30 ml capacity, or equivalent
3 1.3 lee Bath. Container and ice, to aid in condens-
ing moibture in impingers.
3.1.4 Drying Tube. Tube packed with new or re-
geneiated 6- to 16-mesh indicating-type silica gel (or
equivalent dosiceaiit), to dry the sample gas and to pro-
tect the meter and pump.
3.1.5 Valve. Needle valve, to legulate the sample gas
flow late.
3.1.6 Pump. Leak-free, diaphragm type, or equiva-
lent, to pull the gas sample through the tram.
3.1.7 Volume meter. Dry gas meter, sufficiently ac-
curate to measure the sample volume within 2%, and
calibrated over the range of flow rates and conditions
actually encountered duiing sampling.
3.1.8 Kate Meter. Rotameter, to measure the flow
range from 0 to 31 pm (0 to 0.11 cfm).
.) 1.9 Graduated Cylinder. 25 ml.
3.1.10 Barometer. Mercury, aneioid, or other barom-
eter, as described in Section 2.1.5 above.
3.1.11 Vacuum Gauge. At least 760 mm Hg (30 in.
Hg) gauge, to be used lor the sampling leak cheek.
3.2 Procedure.
3.2.1 Place exactly 5 ml distilled water in each im-
pinger. Assemble the apparatus without the probe as
shown in Figure 4-4. Leak check the train by placing a
vacuum gauge at the inlet to the first impinger and
drawing a vacuum ot at least 250 mm Hg (10 in. Hg),
plugging the outlet of the rotameter, and then turning
otf the pump. The vacuum shall remain constant for at
east one minute. Carefully release the vacuum g'auge
Ibefore unplugging the rotameter end.
FEDERAL REGISTER, VOL. 42, NO. 160THURSDAY, AUGUST 18, 1977
IV-190
-------
HEATED PROBE
RUIES AND REGULATIONS
SILICA GEL TUBE RATE METER.
MIDGET IMPIIMGERS
PUMP
Figure 4-4. Moisture-sampling train - approximation method.
LOCATION.
TEST
COMMENTS
DATE
OPERATOR
BAROMETRIC PRESSURE
CLOCK TIME
GAS VOLUME THROUGH
METER, (Vm),
m3 (ft3)
RATE METER SETTING
nvVmin. (ft3/min.)
METER TEMPERATURE.
°C(°F)
Figure 4-5. Field moisture determination approximation method.
RDCKAL UUIUtR, VOL 42, NO. 1 tO1HUISDAT, AUOUST It, MTT
IV-191
-------
RULES AND REGULATIONS
332 Connect the probe, insert it into the stack, and
sample at a constant rate of21pm (0.071 dm). Continue
sampling until the dry gas meter registers about 30
liters (1.1 ft») or until visible liquid droplets are carried
over from the first impinger to the second. Record
temperature, pressure, and dry gas meter readings as
required by Figure 4^5.
3.2.3 After collecting the sample, combine the con-
tents of the two impingers and measure the volume to the
nearest 0.5 ml.
3.3 Calculations. The calculation method presented is
designed to estimate the moisture in the stack gas;
therefore, other data, which are only necessary for ac-
curate moisture determinations, are not collected. The
following equations adequately estimate the moisture
content, for the purpose of determining isokinetic sam-
pling rate settings.
3.3.1 Nomenclature.
B««=Approiimate proportion, by volume, of
water vapor in the gas stream leaving the
second impinger, 0.025.
B.,=Water vapor in the gas stream, proportion by
volume.
M.=Molecular weight of water, 18.0 g/g-mole
(IS.OlbAb-mole)
P»=Absolute pressure (for this method, same as
barometric pressure) at the dry gas meter.
P,u"Standard absolute pressure, 760 mm Hg
(29 92 in. Hg).
A-Ideal gas constant, 0.06236 (mm Hg) (m>)/
(g-mole) (°K) for metric units and 21.85
(in. Hg) (ft»)/lb-mole) (°B) for English
units.
T.=Absolute temperature at meter, "K (°R)
T,,j=Standard absolute temperature, 293° K
(528° B)
V/=Final volume of impinger contents, ml.
K=Initial volume of impinger contents, ml.
V»=Dry gas volume measured by dry gas meter,
dcm (dcf).
V.(,u)=Dry gas volume measured by dry gas meter,
corrected to standard conditions, dscm
(dscf).
V.,i.u)=Volume of water vapor condensed, corrected
to standard conditions, son (set).
»=Density of water, 0.9982 g/ml (0.002201 Ib/ml).
3.3,2 Volume of water vapor collected.
Equation 4-5
where:
K]-0.0013S3 ro'/ml for metric units
=0.04707 ft'/ml for English units.
3.3.3 Gas volume.
^(iW)=y»(^
-K,
vmpm
Equation 4-4
where:
Jft-0.3858 °E/mm Hg for metric units
-17.64 °R/in. Hg for English units
3.3.4 Approximate moisture content.
v..
v,.
-v-+V
'weT- rn(It
4. Coitoroiion
Equation 4-7
4.1 For the reference method, calibrate equipment as
specified in the followir.., sections of Method 6: Section 5.3
(metering system); Section 5.5 (temperature gauges):
aud Section 5.7 (barometer). The recommended leak
check of the metering system (Section 5.6 of Method 5)
also applies to the reference method. For the approxima-
tion method, use the procedures outlined in Section 5.1.1
of Method 6 to calibrate the metering system, and the
procedure of Method 5, Section 5.7 to calibrate the
barometer.
5. BiWiojropAf
\. Air Pollution Engineering Manual (Second Edition).
Danielson, J. A. (ed.). TJ.S. Environmental Protection
Agency, Office of Air Quality Planning and Standards.
Research Triangle Park, N.C. Publication No. AP-40.
1973.
2. Devorkin, Howard, et al. Air Pollution Source Test-
ing Manual. Air Pollution Control District, Los Angeles,
Calif. November, 1963.
3. Methods for Determination of Velocity, Volume,
Dust and Mist Content of Gases. Western Precipitation
Division of Joy Manufacturing Co., Los Angeles, Calif.
Bulletin WP-50.1968.
METHOD 5 DETERMINATION or r ARTICULATE EMISSIONS
FROM STATIONARY SOURCES
1. Principle and Applicability
1.1 Principle. Participate matter is withdrawn iso-
kinetically from the source and collected on a glass
fiber filter maintained at a temperature in the range of
120±H- C (248±2S° F) or such other temperature as
specified by an applicable subpart of the standards or
approved by the Administrator, U.S. Environmental
Protection Agency, for a particular application. The
paniculate mass, which includes any material that
condenses at or above the filtration temperature, if
determined gravimetrically after removal of uncombined
water.
1.2 Applicability. This method is applicable for the
determination of paniculate emissions from stationary
sources.
2. Appertain
2.1 Sampling Train. A schematic of the sampling
train used in this method is shown in Figure 5-1. Com-
plete construction details are given in APTD-0581
(Citation 2 in Section 7); commercial models of this
train are also available. For changes from APTD-0581
and for allowable modifications of the train shown in
Figure 5-1, see the following subsections.
The operating and maintenance procedures for the
sampling train are described in AFTD-0576 (Citation 3
in Section 7). Since correct usage is important in obtain-
ing valid results, all users should read APTD-0576 and
adopt the operating and maintenance procedures out-
lined in it, unless otherwise specified herein. The sam-
pling train consists of the following components:
MORAL UmSTM. VOW «S. NO, 1MTHUiSDAY, AUGUST It. 1977
IV-192
-------
RULES AND REGULATIONS
PITOTTUBE
MPERATURESENSOR
- PROBE
TEMPERATURE
SENSOR
IMPINGER TRAIN OPTIONAL, MAY BE REPLACED
BY AN EQUIVALENT CONDENSER
HEATED AREA THERMOMETER
THERMOMETER
PROBE /fl STACK
-jC_LtWALL
REVERSE-TYPE
PITOT TUBE
PITOT MANOMETER IMPINGERS ICE BATH
BY-PASS VALVE
ORIFICE ' " '
CHECK
VALVE
VACUUM
LINE
VACUUM
GAUGE
THERMOMETERS
DRY GAS METER
AIRTIGHT
PUMP
Figure 5 1. Paniculate-sampling train.
2.1.1 Probe Noizle. Stainless steel (316) or glass with
ih&rp, tapered leading edge. The angle of taper shall
be <30° and the taper shall be on the outside to preserve
constant internal diameter. The proble nozzle shall be
of the button-hook or elbow design, unless otherwise
specified by the Administrator. If made of stainless
steel, the nozzle shall be constructed from seamless tub-
ing; other materials of construction may be used, subject
to the approval of the Administrator.
A range of nozzle sizes suitable for isokinetic sampling
should be available, e.g., 0.32 to 1.27 cm (H to M in.)
or larger if higher volume sampling trains are used
inside diameter (ID) nozzles in increments of 0.16 cm
(H6 in.). Each nozzle shall be calibrated according to
the procedures outlined in Section 5.
2.1.2 Probe Liner. Borosihcate or quartt glass tubing
with a heating system capable of maintaining a gas tem-
perature at the eiit end during sampling of 120±14° C
(24g±25° F), or such other temperature as specified by
an applicable subpart of the standards or approved by
the Administrator for a particular application. (The
tester may opt to operate the equipment at a temperature
lower than that specified.) Since the actual temperature
at the outlet of the probe is not usually monitored during
sampling, probes constructed according to APTD-0681
and utilizing the calibration curves of APTD-0576 (or
calibrated according to the procedure outlined in
APTD-0576) will be considered acceptable.
Either borosilic: te or quartz glass probe liners may be
used for stack temperatures up to about 480° C ,900° F)
quartz liners shall be used lor .emperalures between 480
«nd 900° C (900 and 1,650° F) Both types ol liners may
be used at higher temperatures than specified for short
periods of time, subject to the approval of the Adminis-
trator. The softening temperature for borosilicate is
820° C (1,508° F), and tor quartz it is 1,501 ° C (2,732° F)
Whenever practical, every effort should be made to use
borosi lie-ate or quarti glass probe liners. Alternatively,
metal liners (e.g., 316 stainless steel, Incoloy 825,' or other
corrosion resistant metals) made of seamless tubing ma;
be used, subject u> the approval of the Administrator.
2.1.3 Pilot Tube. Type 8, as described in Section 2.1
of Method 2, or other device approved by the Adminis-
trator The pilot tube shall be attached to the probe (as
«hown in Figure 5-1) to allow constant monitoring of the
tack gas velocity The impact (high pressure) opening
1 Meniioo ol trade names or specific products does not
constitute endorsement by the Environmental Protec-
tion Agency.
plane of the pi tot tube shall be even with or above the
nozzle entry plane (see Method 2, Figure 2-6b) during
sampling. The Type S pilot tube assembly shall have a
known coefficient, determined as outlined in Section 4 of
Method 2.
2.1.4 Differential Pressure Gauge. Inclined manom-
eter or equivalent deve> (two), as oscribed in Section
2.2 ol Method 2. One manometer s'mll be'used .or velocity
head (Ap) readings, and the other, for orifice differential
pressure readings
2.1.5 Filter Holder. Borosilicate glass, with a glass
frit filter support and a silicone rubber gasket. Other
materials of construction (e.g., stainless steel, Teflon,
Viton) may be used, subject to approval of the Ad-
ministrator. The holder design shall provide a positive
seal against leakage irom the outside or around the filter.
The holder shall be attached immediately at the outlet
of the probe (or cyclone, II used).
2.1.6 Filter Heating System. Any heating system
capable of maintaining a temperature around the filter
holder during sampling o. 120±14° C (248±2.r,° F), or
such other temperature as specified by an applicable
subpart of the standards or approved by the Adminis-
trator for a particular application. Alternatively, the
tester may opt to operate the equipment at a temperature
lower than that specified. A temperature gauge capable
of measuring temperature to within 3" C (5.4° F) shall
be installed so that the temperature around the filter
bolder can be regulated and monitored during sampling.
Heating systems other than the one shown in APTD-
0581 may be used.
2.1.7 Condenser. The following system shall be used
to determine the stack gas moisture content: Four
impingers connected in series with leak-free ground
glass fillings or any similar leak-free non-contaminating
fittings. The first, third, and fourth impingers shall be
ol the Greenburg-Smith design, modilied by replacing
the Up with 1.3 cm (M in.) 1L) glass tube extending to
about 1..1 cm (>4 in.) from the bottom ol the flask. Tbe
second impingcr shall be of the Greenburg-Sniith design
with the standard tip. Modifications (e.g., using flexible
connections between the Impmgrrs, using materials
other than glass, or using flex! ble vacuum lines to connect
the filter holder to the oondonscr) may be used, subject
to the approval of the Administrator. The first and
second Impingers shall contain known quantities of
water (Section 4.1.3), the third shall be empty, and. the
fourth shall contain a known weight of silica gel, or
equivalent desiccant. A thermometer, capable of measur-
ing temperature to within 1° C (2° F) shall be placed
at the outlet of the fourth implnger for monitoring
purposes.
Alternatively, any system that cools the sample gas
stream and allows measurement of the water condensed
and moisture leaving the condenser, each to within
1 ml or 1 g may be used, subject to the approval of the
Administrator. Acceptable means are to measure the
condensed water either gravimetncally or volumetncally
and to measure the moisture leaving the condenser by:
(1) monitoring the temperature and pressure at the
exit of the condenser and using Dalton s law of partial
pressures; or (2) passing the sample gas stream through
a tared silica gel (or equivalent desiccant) trap with
exit gases kept below 20° C (68° F) and determining
the weight gain.
If means other than silica gel are used to determine
the amount of moisture leaving the condenser, it 19
recommended that silica gel (or equivalent) still be
used between the condenser system and pump to prevent
moisture condensation in the pump and metering devices
and to avoid the need to make corrections for moisture in
the metercd volume.
NOTE.If a determination of the particulate matter
collected in the impingers is desired in addition to mois-
ture content, the impinger system described above shall
be used, without modification. Individual States or
control agencies requiring this information shall be
contacted as to the sample recovery and analysis of the
Impinger contents.
2.1.8 Metering Systom. Vacuum gauge, teak-free
pump, thermometers capable of measuring temperature
to within 3° C (5.4° F), dry gas meter capable of measuring
volume to within 2 percent, and related equipment, as
shown in Figure 5-1. Other metering systems capable of
maintaining sampling rates within 10 percent of iso-
kinetic and of determining sample volumes to within '2
percent may be used, subject to the approval of the
Administrator. When the metering system is used m
conjunction with a pilot tube, the system shall enable
checks ol isokinetic ralos.
Sampling trains utilizing metering systems designed for
higher flow rates than that described in APTD-05S1 or
APTD-OS7G may be used provided that the specifica-
tions 01 this method are met.
2.1.9 Barometer. Mercury, aneroid, or other barometor
capable of measuring almospheric pressure lo within
2.5 mm Hg (0.1 in. llg). In many cases, the baromclno
reading may be obtained from a nearby national weather
service station, In which case the station value (which u
FEDERAL tEGTSTER,'YOU «, NO. T60THUflDAr, AUORttT 18/T977
IV-193
-------
RULES AND REGULATIONS
i h^ absolute Imiomolric pressure) shall be requested and
m adjustment for elevation ditlcrfnces between the
\M-athcr station and sampling point shall be applied at a
r.itc of ilium" 2.5 mm 13g (D.I in. Ilg) per 30 m (100 It)
It'vaMon nuTL'juse or vice versa for elevation decrease.
a 1 10 (!fts Density Determination Equipment.
Temperature sensor and pressure gauge, as described
in Sections 2 3 and 2.4 of Method 2, and gas analyzer,
if necessary, as described in Method 3 The temperature
j-nsor i-liall, preferably, be permanently attached to
the pilot tube or sampling probe in a fixed configuration,
such that the tip of the sensor extends beyond the leading
cdue of Hie probe sheath and does not touch any metal.
Alternatively, the sensor may be attached just prior
to use in the Held Note, however, that if the temperature
-en.-or is attached in the iield, the sensor must be placed
in an inteifcrencc-free arrangement with respect to the
Type S pilot tube openings (see Method 2, Figure 2-7).
As a second alternative, if a ditlerenee of not more than
1 percent in the average velocity measurement is to be
introduced, the temperature gauge need not be attached
to th_e probe or pilot tube. (This alternative is subject
to the approval of the Administrator.)
2 2 Sample Recovery. The following items are
needed.
2 2.1 Probe-Liner and Probe-Nozzle Brushes. Nylon
bristle brushes with stainless steel wire handles. The
probe brush shall have extensions (at least as long as
the probe) of stainless steel. Nylon, Teflon, or similarly
inert material The brushes shall be properly sized and
shaped to brush out the probe liner and nozzle
222 Wash BottlesTwo. Glass wash bottles are
recommended; polyethylene wash bottles may be used
at the option of the tester It is recommended that acetone
not be stored in polyethylene bottles for longer than a
month.
2 2.3 Glass Sample Storage Containers. Chemically
resistant, borosilicate glass bottles, for acetone washes,
.500 ml or 1000 ml. Screw cap liners shall either be rubber-
backed Teflon or shall be constructed so as to be leak-free
and resistant to chemical attack by acetone. (Narrow
mouth glass bottles have been found to be less prone to
leakage.) Alternatively, polyethylene bottles may be
used.
224 Petri Dishes. For filter samples, glass or poU-
ethylene, unless otherwise specified by the Admin-
istrator.
225 Graduated Cylinder and/or Balance To meas-
ure condensed water to within 1 ml or 1 g. Graduated
> ylinders shall have subdivisions no greater than 2 ml.
Most laboratory balances are capable of weighing to the
nearest 0.5 g or less. Any of these balances is suitable for
use here and in Section 2 3.4.
226 Plastic Storage Containers. Air-tight containers
to store silica gel.
2 2.7 Funnel and Rubber Policeman. To aid in
transfer of silica gel to container1 not necessary if silica
gel is weigbed in the field.
2 2.8 Funnel. Glass or polyethlene, to aid in sample
recovery.
2.3 Analysis. For analysis, the following equipment is
needed.
2.3.1 Glass Weighing Dishes.
232 Desiccator.
2.3.3 Analytical Balance. To measure to within 0.1
mg.
2.3.4 Balance. To measure to within 0.5 g.
2.35 Beakers. 250 ml.
2 3.6 Hygrometer. To measure the relative humidity
of the laboratory environment.
2.3.7 Temperature Gauge. To measure the tempera-
tan of the laboratory environment.
3. Reagent!
3.1 Sampling. The reagents used in sampling are as
follows:
3.1.1 Filters. Gloss fiber filters, without organic
binder, exhibiting at least 99.95 percent elficiency (<0.05
percent penetration) on 0.3-micron dioctyl phthalale
smoke particles. The filter efficiency test shall be con-
ducted in accordance with ASTM standard method D
2986-71. Test data from the supplier's quality control
program are sufficient for this purpose.
3.1.2. Silica Gel. Indicating type, 6 to 16 mesh. If
previously used, dry at 175° C (350* F) lor 2 hours. New
silica gel may be used as received. Alternatively, other
types of desiccants (equivalent or better) may be used,
subject to the approval of the Administrator.
3.1.3 Water. When analysis of the material caught in
the impingers is required, distilled water shall be used.
Run blanks prior to field use to eliminate a high blank
on test samples.
3.1.4 Crushed Ice.
3.1.5 Stopcock Grease. Acetone-insoluble, heat-stable
^ilicone grease. This is not necessary if screw-on con-
nectors with Teflon sleeves, or similar, are used. Alterna-
tively, other types of stopeock grease may be used, sub-
ject to the approval of the Administrator.
3.2 Sample Recovery. Acetonereagent grade, <0.001
percent residue, in glass bottlesis required. Acetone
from metal containers generally has a high residue blank
and should not be used. Sometimes, suppliers transfer
acetone to glass bottles from metal containers; thus,
acetone blanks shall be run prior to Held use and only
acetone with low blank values (<0.001 percent) shall be
used. In no case shall a blank value of greater than 0.001
percent of the weight of acetone used be subtracted from
the sample weight.
3.3 Analysis. Two reagents are required for the analy-
sis:
3.3.1 Acetone. Same as 3.2.
3.3.3 Desiccant. Anhydrous calcium sulfate, Indicat-
ing type. Alternatively, other types of desiccants may be
used, subject to the approval of the Administrator.
4. Proctdwe
4.1 Sampling. The complexity of this method is such
that, in order to obtain reliable results", testers should be
trained and experienced with the test procedures.
4.1.1 Pretest Preparation. All the components shall
be maintained and calibrated according to the procedure
described in APTD-0578, unless otherwise specified
herein.
Weigh several 200 to 300g poitions of silica gel in air-tight
containers to the nearest 0.5 g. Record the total weight of
the silica gel plus container, on each container. As an
alternative, the silica gel need not be preweighed, but
may be weighed directly in its impingor or sampling
holder just prior to train assembly.
Check filters visually against light for irregularities and
flaws or pinhole leaks. Label filters of the proper diameter
on the back side near the edge using numbering machine
ink. As an alternative, label the shipping containers
(glass or plastic petn dishes) and keep the tutors in these
containers at all times except duiing sampling and
Desiccate the filters at 20±5.6° C (68±10° F) and
ambient pressure for at least 24 hours and weigh at in-
tervals of at least 6 hours to a constant weight, i.e.,
<0.5 nig change from previous weighing; record results
to the nearest 0.1 mg. During each weighing the filter
must not be exposed to the laboratory atmosphere lor a
period greater than 2 minutes and a relative humidity
above 50 percent. Alternatively (unless otherwise speci-
fied by the Administrator), the tillers may be oven
dried at 105° C (220° F) for 2 to 3 hours, desiccated for 2
hours, and weighed. Procedures other than those de-
scribed, which account for relative humidity effects, may
be used, subject to the approval of the Administrator.
4.1.2 Preliminary Determinations. Select the sam-
pling site and the minimum number of sampling points
according to Method 1 or as specified by the Administra-
tor. Determine the stack pressure, temperature, and the
range of velocity heads using Method 2; it is recommended
that a leak-cheek of the pilot lines (see Method 2, Sec-
tion 3.1) be performed. Determine the moisture content
using Approximation Method 4 or its allernalivea for
the purpose of making isotinetic sampling rate sellings.
Determine the stack gas dry molecular weighl, as des-
cribed in Method 2, Seclion 3.6; if mtegraled Method 3
sampling is used for molecular weight determination, the
integrated bag sample shall be taken simultaneously
with, and for the same total length of time as, the par-
ticulale sample run.
Select a nozzle size based on the range of velocity heads,
such lhat it is not necessary to change the nozzle size in
order to maintain isokinetic sampling rates. During the
run, do not change the nozzle size. Ensure that the
proper differential pressure gauge is chosen for the range
of velocity heads encountered (see Section 2.2 of Method
2).
Select a suitable probe liner and probe length such that
all traverse points can be sampled. For large stacks,
consider sampling from opposite sides of the stack to
reduce the length of probes.
Select a total sampling time greater than or equal to
the minimum total sampling time specified in the test
procedures for the specific industry such that (1) the
sampling time per point is not less than 2 min (or some
greater time interval as specified by the Administrator),
and (2) the sample volume taken (corrected to standard
conditions) will exceed the required minimum total gas
sample volume. The latter is based on an approximate
average sampling rate.
It is recommended that the number of minutes sam-
pled at each point be an integer or an integer plus one-
half minute, in order to avoid timekeeping errors.
In some circumstances, e.g., batch cycles, it may be
necessary to sample for shorter times at the traverse
points and to obtain smaller gas sample volumes. In
these cases, the Administrator's approval must first
be obtained.
4 1.3 Preparation of Collection Train. During prep-
aration and assembly of the sampling train, keep all
openings where contamination can occur covered until
just prior to assembly or until sampling is about to begin.
Place 100 ml of water in each of the first two impingers,
leave the third impinger empty, and transfer approxi-
mately 200 to 300 g of preweighed silica gel from its
container to the fourth impinger. More silica gel may b«
used, but care should be taken to ensure that it Is not
entrained and carried out from the impinger during
sampling Place the container in a clean place for later
use in the sample recovery. Alternatively, the weight of -
the silica gel plus impinger may be determined to the
nearest 0 5 g and recorded.
Using a tweeter or clean disposable surgical gloves,
place a labeled (identified) and weighed filter m the
filter holder. Be sure that the filter is properly centered
and the gasket properly placed so as to prevent the
sample gas stream from circumventing the filter. Check
the filter for tears after assembly is completed.
When class liners are used, install the selected noule
using a Viton A O-rlnj Then stack temperatures are
less than 260° C (600° F) and an asbestos string gasket
when temperatures we higher. Bee APTD-4676 tor
details Other «)ime< ting systems using either .Hi, Main
lew steel or Teflon leirules may be used. When met*!
Siners are used, install the nozzle as above or by a ieak-
free direct mechanical connection. Mark the probe with
heat resistant tape or by some other method to denote
the proper distance into the stack or duct for each sam-
pling point.
Set up the train a;i in Figure 5-1, using (if necessary)
a very light coat of silicone grease on all ground glass
joints, greasing only the outer portion (see APTD-0570)
to avoid possibility of contamination by the silicon?
grease. Subject to the approval of the Administrator, a
glass cyilone may be used between the probe and filter
holder when the total patticulate catch is exported to
exceed 100 ing ov when water droplets are pri^t'iit in the
stack gas.
Place crushed ice around the impingers.
4.1.4 Leak-Check Procedures.
4.1.4.1 Pretest Leak-Check. A pretest Irak-check is
recommended, but not required. If the tester opts to
conduct the pretest leak-check, the following procedure
shall be used.
After the sampling train has been assembled, turn on
and set the filter and probe heating systems at the desired
operating temperatures. Allow time for the temperatures
to stabilize. If a Viton A O-ring or other leak-free connec-
tion is used in assembling the probe nozzle to the probe
liner, leak-check the train at the sampling site by plug-
ging the nozzle and pulling a 380 nun Ilg (IS in. Hg)
vacuum.
NOTE.A lower vacuum may be used, provided that
it is not exceeded during the test.
If an asbestos string is used, do not connect the probe
to the train during the leak-check. Instead, leak-clieck
the train by first plugging the inlet to the filter holder
(cyclone, if applicable) and pulling a 380mm Hg (15 in.
Hg) vacuum (see Note immediately above). Then con-
nect the probe to the train and leak-check at about 25
mm Hg (1 m. Hg) vacuum, alternatively, the probe may
be leak-checked with the rest of the sampling tram, in
one step, at 380 mm Hg (15 in. Hg) vacuum. Leakage
rates in excess of 4 percent of the average sampling rate
or 0.00057 m'.'min (0.02 cfm), whichever is less, are
unacceptable.
The following leak-check instniclions for the sampling
ttain described in APTD-0576 and APTD-0581 may be
helpful. Start the pump with bypass valve fully open
and coarse adjust valve completely closed. Partially
open the coarse adjust valve and slowly close the bypass
valve until the desired vacuum is reached. Do not reverse
direction of bypass valve; this will cause water to back
up into the filter holder. If the desired vacuum is ex-
ceeded, either leak-check at this higher vacuum or end
the leak check as shown below and start over.
When the leak-check is completed, first slowly remove
the plug from the inlet to the probe, liher holder, or
cyclone (if applicable) and immediately turn oft the
vaccum pump. This prevents the water in the impingers
from being foiced backward into the filter holder and
silica gel from being entrained backward into the third
impinger.
4.1.4.2 Leak-Cheeks During Sample Run. If, during
the sampling run, a component (e.g., filter assembly
or impinger) change becomes necessary, a leak-check
shall be conducted immediately before the change is
made. The leak-check shall be done according to the
procedure outlined in Section 4.1.4.1 above, except that
It shall be done at a vacuum equal to or greater than the
maximum value recorded up to that point in the test.
If the leakage rate is found to be no greater than 0.00057
m'/min (0.02 cfm) or 4 percent of the average sampling
rate (whichever is less), the results are acceptable, and
no correction will need to be applied to the total volume
of dry gas metered; if, however, a higher leakage rate
is obtained, the tester shall either record the leakage
rate and plan to correct the sample volume as shown in
Section 6.3 of this method, or shall void the sampling
run.
Immediately after component changes, leak-checks
are optional; if such leak-checks are done, the procedure
outlined in Section 4.1.4.1 above shall be used.
4.1.4.3 Post-test Leak-Check. A leak-check is manda-
tory at the conclusion of each sampling run. The leak-
check shall be done in accordance with the procedures
outlined in Section 4.1 4.1, except that it shall be con-
ducted at a vacuum equal to or greater than the maxi-
mum value reached during the sampling run. If the
leakage rate is found to be no greater than 0.00057 m»,'min
(0.02 cfm) or 4 percent of the average sampling rate
(whichever is less), the results are acceptable, and no
correction need be applied to the total volume of dry gas
metered. If, however, a higher leakage rate is obtained,
the tester shall either record the leakage rate and correct
the sample volume as shown in Section 6.3 of this method,
or shall void the sampling run.
4.1.5 Particulate Train Operation. During th»
sampling run, maintain an isokinetic sampling rate
(within 10 percent of true isokinetic unless otherwise
specified by the Administrator) and a temperature
around the filter of 120±140 C (248±25° F), or such other
temperature as specified by an applicable subpart of th«
standards or approved by the Administrator.
For each run, record the data required on a data sheet
such as the one shown in Figure 6-2. Be sure to record the
initial dry gas meter reading. Record the dry gas meter
readings at the beginning and end of each sampling time
increment, when changes in flow rate* an made, Defer*
and after each leak check, and when sampling it halted)
FEDERAL REGISTER, VOL 42. NO. 160THURSDAY, AUGUST II, 1977
IV-194
-------
RULES AND REGULATIONS
Take other readings required by Figure 5^2 at least once
at each sample point during each time increment and
additional readings when significant changes (20 percent
variation in velocity head readings) necessitate addi-
tional adjustments in flow rate. Level and tero the
manometer. Because the manometer level and rero may
drift due to vibrations and temperature changes, make
ptnodic checks during the traverse.
Clean the portholes prior to the teat ran la minimi**
the chance of sampling deposited material. To begin
sampling, remove the nozile eap, verify that the filter
and probe heating systems are up to temperature, «nd
that the pilot tube and probe are properly positioned.
Position the no&zle at the first traverse point with the tip
pointing directly into the gas stream. Immediately start
the pump and adjust the flow to isokinetic conditions.
Nomographs are available, which aid in the rapid adjust-
of the iaoklnetlc sampling rate without excessive
computations. These nomographs are designed for use
when the Type B pltot tube coefficient is 0.85±0.02, and
the «tack gas equivalent density (dry molecular weight)
is equal to 29±4. APTD-0576 details the procedure for
using the nomographs. If Cf and Mt are outside the
above stated ranges do not use the nomographs unless
appropriate steps (see Citation 7 in Section 7) are taken
to compensate for the deviations.
PLANT.
LOCATION.
OPERATOR,.
DATE
RUN NO. _
SAMPLE BOX NO..
METEflBOXNO._
METERAHg
C FACTOR
AMBIENT TEMPERATURE.
BAROMETRIC PRESSURE.
ASSUMED MOISTURE,* _
PROBE LENGTH.m (ft)
PITOT TUBE COEFFICIENT, Cf.
SCHEMATIC OF STACK CROSS SECTION
NOZZLE IpENTIFICATION NO
AVERAGE CALIBRATED NOZZLE DIAMETER, cm (in.).
PROBE HEATER SETTING
LEAK RATE. m3/min.(cfm)
PROBE LINER MATERIAL
STATIC PRESSURE, mm Kg (in. Kg),.
FILTER NO
TRAVERSE POINT
NUMBER
TOTAL
SAMPLING
TIME
(01, min.
AVERAGE
VACUUM
mm Hg
(in. Hg)
STACK
TEMPERATURE
from the w,i". sample container
labeled "acetone blank.'1
Inspect the train prior to and during ch^as-emhlv ami
note any abnormal condition- 1ri-.it the samples a»
lollows:
Container A'o. /. Carefully remove the filler from th*>
filter holder and place it in its identified petri dish con-
tainer. lTse a pair of tweezers and/or clean disposable
surgical gloves to handle the filler If it is neccss.iry to
fold the hlter, do so sucli that the paniculate cake i»
inside the fold. Carefully transfer to the petri dish any
particulate matter and/or filter fibers which adhere to
the filter holder gasket, by using a dry nylon brisllo
brush and/or a sharp-edged blade. Seal the container.
Ccmioinrr No. t. Taking care to see that dust on the
outside of the probe or other exterior surfaces does not
get into the sample, quantitatively recover particulate
matter or any condensato from the probe nozzle, probe
KDiRAL «GIST«, VOL. 42, NO. 160THURSDAY, AUGUSt 18, 19T7
IV-195
-------
RULES AND REGULATIONS
fntmg, probe litu r. and front half o/ Iho filter holder by
»:u,hmg those components »illi acetone and placing tli«
».ish in a glass container. Distilled water may b« iwd
instead of acetone when approved by the Administrator
-.ind shall be used when specified by the Administrator;
in these caws, save a water blank and follow the Admin-
istrator's directions on anal} MS. Perform Ui« acetone
rinses as follows-
Caivfulh : iiuiM- ihe piot*' no/vli and clean the inside
Miifoce l-y inline with .IM-IOM.' fmin a wa>h bodle and
bru*lini|r'»>:ii ' i'\lou !>'>Mle biush. Hiush iiiuil the
sttMone ]HM> turn's no vMi'le ptn iicles. after which
make a Uul rinse of ihc i Mite Mr (.it ? \viill acetone.
Plant.
1 1
(1 r.MM- ;'v i' Mile p.]::* of the Swapelok
r-j ui'M .ti ctone ri i -.- .i!.if \\ i\ until no vi-ihle
ri m.iin.
lone by tilling and
L< - lone into us upper
be netted with acc-
Jiain fionl the lower end into the
A funnel 'class 01 poljcthjh'iie) may
raiisferrmg hi|tud whiles to the cou-
:1 1-1- r« main.
in-*- IN*' prolie li >< r w
11'^ ] ht- piutv- \\ Illlc S|ll
-ii ih.n .ill inside suita
. I.i i the a
li- i'oi>t..m
lo aid in
Follow the ru.rtone rinse with a piobe bi
Hold the pioue in an lucluicd puMiion. squirt at el one-
inio Ilic upper end as ihe piobe biu.^h is being pushed
»nh a twisting action through the piobc hold a sample
'onliinuT underneath the lowei end of the piobe, and
i .Men any acetone and participate matter -which is
brushed from the probe. Run the biu-.li iluongh the
probe three times- or more until no vi-ihle p.wictilate
matter is carried out with the at clone or until none
remains in Ihe probe linci on \i--u:il insjiection. With
«tainless steel or other met.il probes, run the brush
throuph in tlie above pn^iubed mannei at least sn
times since mcial piol'cs li.i\c -.mail devices in \vblch
particulate matte' can be em rapped. Kinse tbe brush
with acetone, and qtiantn.itiveli, collect these wftslungs
in the sample coniamci. Mn-i the biushiug, make a
final acetone rinse of the prol>e as descnbed above.
It is recommended that two people be used to clean
the probe to minimize sample losses. Between sampling
nm=, keep brushes clean and protected from contamina-
tion.
After ensuring that all joints have been wiped clean
of siiicone grease, clean the inside of the front half of the
lilter holder by rubbing the surfaces with a nylon bristle
brush and rinsing with acetone. Bins* each smface
three times or more if needed to remove visible pailicii-
late. Make a final rinse of tlie brus-h and niter holder.
Carefully rinse out the glass cyi lone, also lit applicable).
After all acetone -washings and paniculate matter have
been collected in the sample container, tighten the lid
on tbe sample container so that acetone will not leak
out when it is shipped to the laboratory. Mark the
height of the fluid level to determine whether or not
leakage occurred during transport. Label the container
to clearly identify its contents.
Container A'o. 3 Note the color of the indkating silica
gel to determine if it has been completely «pem and make
a notation of its condition Transfer the silica gel from
the fourth impinger to its original container and seal.
A funnel may make it easier to pour t be silii a gel wit hoi it
spilling A rubber policeman may be used as an aid in
removing the silica gel from the impinger. It is not
necessary to remove the Miiall amount of dust particles
that may adhere to the impmger wall and are difficult
to remove Since the pain in weight is to be used for
moisture calculations, do not use any water or other
liquids to transfer the - ,
1 g/ml
Figure 5-3. Analytical data.
ffDEIAL UGISTH. VOt, 42. NO, 160THUtSDAY. AUGUST II, 1977
IV-196
-------
RULES AND REGULATIONS
Alternatively, the sample may be oven dried at 105° C
(220° F) tor 2 to 3 hours, cooled in the desiccator, and
weighed to a constant weight, unless otherwise specified
by the Administrator. The tester may also opt to oven
dry the sample at 106 ° C (220 ° F) for 2 to 3 hours, weigh
the sample, and use this weight as a final weight.
Container No.t. Note the level ofliquid in the container
»nd confirm on the analysis sheet whether or not leakage
occurred during transport. If a noticeable amount of
leakage has occurred, either void the sample or use
methods, subject to the approval of the Administrator,
to correct the final results. Measure the liquid in this
container either volumetrically to ±1 ml or gravi-
metncally to ±0.5 g. Transfer the contents to a tared
250-ml beaker and evaporate to dryness at ambient
temperature and pressure. Desiccate for 24 hours and
weigh to 8 constant weight. .Report the results to the
nearest 0.1 mg.
Container No. S Weigh the spent silica gel (or silica gel
plus impinger) to the nearest 0.5 g using a balance. This
.
step may be conducted in the field.
'Acetone Blank" Container. Measure acetone in this
container either volumetricaily or gravimetrically.
Transfer the acetone to a tared 250-ml beaker and evap-
orate to dryness at ambient temperature and pressure.
Desiccate for 24 hours and weigh to a contsant weight.
Report the results to the nearest 0.1 mg.
NOTE. At the option of the tester, the contents of
Container No. 2 as well as the acetone blank container
may be evaporated at temperatures higher than ambi-
ent. If evaporation is done at an elevated temperature,
the temperature must be below the boiling point of the
solvent; also, to prevent "bumping," the evaporation
process must be closely supervised, and the contents of
the beaker must be swirled occasionally to maintain an
even temperature. Use extreme care, as acetone is highly
flammable and has a low flash point.
6. Calibration
Maintain a laboratory log of all calibrations.
5.1 Probe Nozzle. Probe nozzles shall be calibrated
before their initial use in the field. Dsing a micrometer,
measure the inside diameter of the nozzle to the nearest
0.025 mm (0.001 in.). Make three separate measurements
using different diameters each time, and obtain the aver-
age of the measurements. The difference between the high
and low numbers shall not exceed 0.1 mm (0.004 in.).
When nozzles become nicked, dented, or corroded, they
shall be reshaped, sharpened, and recalibrated before
use. Each nozzle shall be permanently and uniquely
identified.
5.2 Pilot Tube. The Type S pitot tube assembly shall
be calibrated according to the procedure outlined in
Section 4 of Method 2.
5.3 Metering System. Before its initial use in the field,
the metering system shall be calibrated according to the
procedure outlined in APTD-0376. Instead of physically
adjusting the dry gas meter dial readings to correspond
to the wet test meter readings, calibration factors may be
used tomathematically correct the gas meter dial readings
to the proper values. Before calibrating the metering sys-
tem, it is suggested that a leak-check be conducted.
For metering systems having diaphragm pumps, the
normal leak-check procedure will not detect leakages
within the pump. For these cases the following leak-
check procedure is suggested, make a 10-mmute calibra-
tion run at 0.00057 m Vmin (0.02 cfm); at the end of the
run, take the difference of the measured wet test meter
and dry gas meter volumes; divide the difference by 10,
to get the leak rate. The leak rate should not exceed
0.00057 m '/min (0.02 cfm).
After each field use, the calibration of the metering
system shall be checked by performing three calibration
runs at a single, intermediate orifice setting (based on
the previous field test), with the vacuum set at the
maximum value reached during the test series. To
adjust the vacuum, insert a valve between the wet test
meter and the inlet of the metering system. Calculate
the average value of the calibration factor. If the calibra-
tion has changed by more than 5 percent, recalibrate
the meter over the full range of orifice settings, as out-
lined in APTD-0576.
Alternative procedures, e.g., using the orifice meter
coefficients, may be used, subject to the approval of the
Administrator.
NOT!.If the dry gas metro coefficient values obtained
before and after a test series differ by more than 5 percent,
the test series shall either be voided, or calculations for
the test series shall be performed using whichever meter
coefficient value (I.e., before or after) gives the lower
value of total sample voluma
6.4 Probe Heater Calibration. The probe heating
system shall be calibrated before its initial use in the
field according to the procedure outlined in APTD-Q576.
Probes constructed according to APTD-0581 need not
be calibrated if the calibration curves in APTD-0576
are used.
5.5 Temperature Gauges. Use the procedure in
Section 4.3 of Method 2 to calibrate in-stack temperature
gauges. Dial thermometers, such as are used for the dry
gas meter and condenser outlet, shall be calibrated
against mercury-in-glass thermometers.
5.6 Leak Check of Metering System Shown !n Figure
5-1. That portion of the sampling train from the pump
to the orifice meter should be leak checked prior to initial
use and after e ach shipment. Leakage after the pump will
result in less volume being recorded than is actually
sampled. The following procedure is suggested (see
Figure 5-4): Close the main valve on the meter box.
Insert a one-hole rubber stopper with rubber tubing
attached into the orifice exhjjost pipe. Disconnect and
vent the low side of the orifice manometer. Close off the
low side orifice tap. Pressurize the system to 13 to 18 cm
(5 to 7 in.) water column by blowing into the rubber
tubing. Pinch oft the tubing and observe the manometer
for one minute. A loss of pressure on the manometer
indicates a leak in the meter box; leaks, if present, must
be corrected.
5.7 Barometer. Calibrate against a mercury barom-
eter.
6. Calculations
Carry out calculations, retaining at least one extra
decimal figure beyond that of the acquired data. Round
off figures after the final calculation. Other forms of the
equations may be used as long as they give equivalent
results.
RUBBER
TUBING
RUBBER
STOPPER
ORIFICE
VACUUM
GAUGE
BLOW INTO TUBING
UNTIL MANOMETER
READS 5 TO 7 INCHES
WATER COLUMN
ORIFICE
MANOMETER
Figure 5-4. Leak check of meter box.
t, 1 Nomenclature
A, Cross-sectional area of nozzle, m> (ft1).
£ Water vapor In the gas stream, proportion
by volume.
C, Acetone blank residue concentrations, mg/g.
. ft Concentration of particulate matter in stack
gaj, dry basis, corrected to standard condi-
tions, g/dscm (g/dscf).
7 Percent of isokinetic sampling.
L. = Maximum acceptable leakage rate for either a
pretest leak check or for a leak check follow-
ing a component change; equal to 0.00057
m'/min (0.02 cfm) or 4 percent of the average
sampling rate, whichever is less.
Li Individual leakage rate observed during the
leak check conducted prior to the r'(«b"
component change ((=1, 2, 3 .... M),
m!/min (cfm).
L, Leakage rate observed during the post-test
leak check, m'/min (cfm).
m. -Total amount of particulate matter collected,
mg.
M, -Molecular weight of water, 18.0 g/g-mole
(18.0 Ib/IlHnoIe).
M. -Mass of residue of acetone alter evaporation,
xng.
£Vu Barometric pressure at the sampling site,
mm Hg (in. Hg).
P. Abgolutestack gaspressure.mmHg (in.Hg).
Put -Standard absolute pressure, 760 mm fig
R Ideal gas constant, 0.06238 mm Hg-m»/°K!-«-
mole (21.85 in. Hg-ft«/°R-lb-mole).
Tm Absolute average dry gas meter temperature
(see Figure 5-2), °K ("R).
T, Absolute average stack gas temperature (see
Figure 5-2), °K (°R).
T.td -Standard absolute temperature, 293° K
(528° R).
V, Volume of acetone blank, ml.
V, » Volume of acetone used in wash, ml.
Vi«=Total volume of liquid collected in impingers
and silica gel (see Figure 5-3), ml.
V. Volume of gas sample as measured by dry gas
meter, dcm (dcf).
V»t,«)=Volume of gas sample measured by the dry
gas meter, corrected to standard conditions,
dscm (dscf):
V.(,«) =Volume of water vapor in the gas sample,
corrected to standard conditions, scm (set).
Stack gas velocity, calculated by Method 2,
Equation 2-0, using data obtained from
Method 5, in/sec (ftfcec).
Weight of residue In acetone wash, mg.
Drj gas meter calibration factor.
Average pressure differential across the orifice
meter (see Figure 5-2), mm HjO (In. HtO).
Density of acetone, mg/ml (see label on
bottle).
Density of water, 0.9982 g/ml (0.002201
Ib/ml).
Total sampling time, min.
V."= S
y=
AH=
#;=Samph'ng time interval, from the beginning
of a run until the first component-change,
min.
0,-Sampling time interval, between two suc-
cessive component changes, beginning with
the interval between the first and second
changes, min.
4,=Sampling time interval, from the final (n'M
component change until the end of the
sampling run, mm.
13.6=8pecific gravity of mercury.
60=Sec/mui.
100=Con version to percent.
6.2 Average dry gas meter temperature and average
orifice pressure drop. See data sheet (Figure 5-2).
t.S Dry Qas Volume. Correct the sample volume
measured by the dry gas meter to standard conditions
(20° C, 760 mm Hg or 68° F, 29.92 in. Hg) by using
Equation 5-1.
rP +a*n
V _r Y(T'»\ ""M3.6
K"("d>-v"rV?W I ~~P^~\
T.
Equation 6-1
HOMAl UOISTHt, VOL. 42. NO. 160THUISDAY, AUGUST It, \9T7
IV-197
-------
RULES AND REGULATIONS
m,«='o .IS-** "K,mm Hg tor metric unit*
- 17.64 R,'in. Hg for English units
No«. Equation 5-1 oan b« used u written unless
the leaks** «t« observed during any of the mandatory
leak checks (i.e., the post-test leak check or leak checks
conducted prior to component changes) exceeds i.. II
A, or In exceeds £., Equation 5-1 must be modified as
follows;
(a) Case T. No component changes made during
sampling nin. In this case, replace l'« m Equation 5-1
with the expression;
Vm-(L. -!.)]
(b) Case II. One or more component changes made
during the sampling run. In this case, replace V. in
Equation 3-1 by the expression:
NOTIIn saturated or water droplet-laden IM
streams, two calculations of the moisture content of the
stack gas shall be made, one from the Impinger analysis
(Equation 5-3), and a second from the assumption of
saturated conditions. The lower of the two value* of
£». shall be considered correct. The procedure far deter-
mining the moisture content based upon assumption of
saturated conditions is given in the Note of Section 1.2
of Method 4 For the purposes of this method, the average
stack gas temperature from Figure 5-2 may be used to
make this determination, provided that the accuracy of
the in-stack temperature sensor is ± 1° C (2° f).
6 6 Acetone Blank Concentration.
6 7 Acetone Wash Blank.
Equation 5-4
1-2
mod substitute only for those leakage rates (£, or L,)
Equation 5-5
6.8 Total ParticuJate Weight. Determine the total
paniculate catch from the sum of the weight* obtained
from containers 1 and 2 less the acetone blank (see Figure
5-3). NOTE. Refer to Section 4.1.5 to assist in calculation
of results involving two or more* filter assemblies or two
or more sampling trains.
6 9 Paniculate Concentration.
hich
6.4
V
'here:
#1=
6.5"
exceed /...
Volume of water vapor.
0.001333 m'/'ml for metric unite
0.04707 ft»/ml for English units.
Moistnre Content.
p ^» ("tcfl
Equation 5-2
\-KjVlc
From
"ft"
g,ft«
g/lt»
6.11
Equation 5-3 6.11.
60 00, P..
.4-ll.
October, 1974.
1.1 Principle. A gas sample is extracted from the
sampling point in the stack. The sulfuric acicl mist
^including sulfur trioxide) and the sulfur dioxide are
separated. The sulfur dioxide fraction is measured by
the barium-thorin titratioiJ method.
1.2 Applicability. This method is applicable for the
determination of sulfur dioxide emissions from stationary
sources. The minimum detectable limit of the method
has been determined to be 3.4 milligrams (mg) of 8Oi/m'
(2.12X10"' Ib'ft1). Although no upper limit has been
established, testa have shown that concentrations as
lugh as 80,000 mg/m' of SOi can be collected efficiently
m iwo midgcl impmgcrs, each containing 15 milliliters
of 3 percent hydrogen peroxide, at a rate of 1.0 1pm for
20 minutes. Based on theoretical calculations, the upper
concentration limit m a 20-hter sample is about 93,300
mg/m3.
Possible interferents are free ammonia, water-soluble
canons, and fluorides. The cations and fluorides are
removed by glass wool niters and an isopropanol bu bbler,
and hence do not alTect the SO- analysis. When samples
ar« being taken from a gas stream with high concentra-
tions of very fine metallic fumes (such as in inlets to
control devices), a high-efficiency glass fiber niter must
be used in place, of the glass wool plug (i.e., the one in
the probe) to remove the cation interferents.
Free ammonia interferes by reacting with SOi to form
particulate sulite and by reacting with the indicator.
If free ammonia is present (this can be determined by
knowledge of the process and noticing white partioulau
matter in the probe and isopropanol bubbler), alterna-
tive methods, subject to the approval of the Administra-
tor, U.S. Environmental Protection Agency, are
required.
2. Apparatui
FEDERAL REGISTER. VOL 42, NO. 16O-THURSOAY, AUGUST It,
IV-198
-------
RULES AND REGULATIONS
PROBE (END PACKED
WITH QUARTZ OR
PYREX WOOL)
STACK WALL
MIDGET IMPINGERS
THERMOMETER
MIDGET BUBBLER
GLASS WOOL
SILICA GEL
DRYING TUBE
ICE BATH
THERMOMETER
PUMP
Figure 6-1. S02 sampling train.
SURGE TANK
2.1 Sampling. The sampling train It shown in Figure
8-1, and component parts are discussed below. The
tester has the option of substituting sampling equip-
ment described in Method 8 in place of the midget 1m-
plnger equipment of Method 6. However, the Method 8
train must be modified to include a heated filter between
the probe and isopropanol Implnger, and the operation
of the sampling train and sample analysis must be at
toe flow rates and solution volumes denned in Method 8.
The tester also has the option of determining 8O>
simultaneously with paniculate matter and moisture
determinations by (1) replacing the water in a Method 5
Implnger system with 3 percent perioxide solution, or
(2) by replacing the Method $ water impinger system
with a Method 8 isopropanol-filter-peroxtde system. The
analysis for SOi must be consistent with the procedure
In Method g.
2.1.1 Probe. Borosilicate glass, or stainless steel (other
materials of construction may be used, subject to the
approval of the Administrator), approximately ft-mm
inside diameter, with a heating system to prevent water
condensation and a filter (either in-slack or heated out-
stack) to remove particulate matter, including sulhiric
acid mist. A plug of class wool is a satisfactory filter.
2.1.2 Bubbler and Impingers. One midget bubbler,
with medium-coarse glass frit and borosilicate or quarts
glass wool packed in top (see Figure &-1) to prevent
snlfuric acid mist carryover, and three 30-ml midget
impingers. The bubbler and midget impingers must be
connected in series with leak-free glass connectors. Sili-
cone Breast may be used, if necessary, to prevent leakage.
At the option of the tester, a midget impinger may be
used in place of the midget bubbler.
Other collection absorbers and flow rates may be used,
but are subject to the approval of the Administrator.
Also, collection efficiency must be shown to be at least
99 percent for each test run and must be documented in
the report. If the efficiency is found to b« acceptable after
a series of three tests, further documentation is not
required. To conduct the efficiency test, an extra ab-
sorber must be added and analyted separately. This
extra absorber must not contain more than 1 percent of
the total 80..
2.1.3 Glass Wool. Borosilicate or quarts.
2.1.4 Stopcock Orease. Acetone-insoluble, heat-
stable slllcone grease may be used, if necessary.
2.1.6 Temperature Gauge. Dial thermometer, or
equivalent, to measure temperature of gas leaving im-
pinger train to within 1" C (2* F.)
2.1.6 Drying Tube. Tube packed with 6- to 18-mesh
Indicating type silica gel, or equivalent, to dry the fas
ample and to protect the meter and pump. If the slliac
eel has been used previously, dry at 175* C (350° F) lor
2 hours. New silica gel may be used as received. Alterna-
tively, other types of deslccants (equivalent or better)
may be used, subject to approval of the Administrator.
2.1.7 Value. Needle value, to-ogulate sample gas flow
rate.
2.1.8 Pump. Leak-free diaphragm pump, or equiv-
alent, to pull gas through the train. Install a small tank
between the pump and rate meter to eliminate the
pulsation effect of the diaphragm pump on the rotameter.
2.1.9 Rate Meter. Rotameter, or equivalent, capable
of measuring flow rate to within 2 percent of the selected
flow rate of about 1000 co/min.
2.1.10 Volume Meter. Dry gas meter, sufficiently
accurate to measure the sample volume within 2 percent,
calibrated at the selected flow rate and conditions
actually encountered during sampling, and equipped
with a temperature gauge (dial thermometer, or equiv-
alent) capable of measuring temperature to within
3CC (S.4=F)T
2.1.11 Barometer. Mercury, amerold, or other barom-
eter capable of measuring atmospheric pressure to within
2.6 mm Hg (0.1 In. Hg). In many cases, the barometric
reading may be obtained from a nearby national weather
service station, In which case the station value (which
is the absolute barometric pressure) shall be requested
and an adjustment for elevation differences between
the weather station and sampling point shall be applied
at a rate of minus 2.5 mm Hg (0.1 in. Hg) per 30 m (100 ft)
elevation increase or vice versa for elevation decrease.
2.1.12 Vacuum Gauge. At least 760 mm Hg (30 in.
Hg) gauge, to be used for leak check of the sampling
train.
2.2 Sample Recovery.
2.2.1 Wash bottles. Polyethylene or glass, MO ml,
two.
2.2.2 Storage Bottles. Polyethylene, 100 ml, to store
Implnger samples (one per sample).
2.3 Analysis.
2.3.1 Pipettes. Volumetric type, 5-ml, 20-ml (one per
sample), and 25-ml sizes.
2.8.2 Volumetric Flasks. 100-ml site (one per sample)
and 100-ml site.
2.3.3 Burettes. 5- and 60-ml sites.
2.8.4 Erlenmeyer Flasks. 250 mi-site (one for each
ample, blank, and standard).
2.3.5 Dropping Bottle. 125-ml site, to add indicator.
2.3.8 Graduated Cylinder. 100-ml site.
2.3.7 Spectrophotometer. To measure abeorbance at
S52 nanometers.
8. Reagent*
Unless otherwise Indicated, all reagents must conform
to the specifications established by the Committee on
Analytical Reagents of the American Chemical Society.
Where such specifications are not available, use the best
available grade.
3.1 Sampling.
3.1.1 WaterTDeionited, distilled to conform to ASTM
specification Dl 183-74, Type 3. At the option of the
analyst, the KMnO< test for oxidliable organic matter
may be omitted when high concentrations of organic
matter are not expected to De present.
3.1.2 Isopropanol, 80 percent. Mix 80 ml of isopropanol
with 20 ml of deionited, distilled water. Check each lot of
isopropanol for peroxide impurities as follows: shake 10
ml of isopropanol with 10 ml of freshly prepared 10
percent potassium iodide solution. Prepare a blank by
similarly treating 10ml of distilled water. After 1 minute,
read the absorbance at 362 nanometers on a Spectro-
photometer. If absorbance exceeds 0.1, reject alcohol for
use.
Peroxides may be removed from Isopropanol by redis-
tilling or by passage through a column of activated
alumina; however, reagent grade Isopropanol with
suitably low peroxide levels may be obtained from com-
mercial sources. Rejection of contaminated lots may,
therefore, be a more efficient procedure.
3.1.8 Hydrogen Peroxide, 8 Percent. Dilute SO percent
hydrogen peroxide 1:9 (v/v) with deioniied, distilled
water (80 ml is needed per sample). Prepare fresh daily
3.1.4 Potassium Iodide Solution, 10 Percent. Dissolve
10.0 grams KI in deioniied, distilled water and dilute to
100 ml. Prepare when needed.
3.2 Sample Recovery.
8.2.1 Water. Deionited, distilled, as in 3.1.1.
8.2.2 Isopropanol. 80 Percent. Mix 80 ml of isopropanol
with 20 ml of deioniied, distilled water.
8.3 Analysis.
8.3.1 Water. Deionited, distilled, as In 3.1.1.
8.3.2 Isopropanol, 100 percent.
8.8.3 Tborin Indicator. l-(o-«rsonophenylaio)-2-
naphtho)-3,641sulfonlc Mid, disodium salt, or equiva-
lent. Dissolve 0.20 g in 100 ml of deioniied, dlstiUed
water.
3.8.4 Barium Perchlorate Solution, 0.0100 N Dis-
solve l.M I of barium perchlorate trihydrat* (Ba(ClOi)r
SHiO] in 200 ml distilled water and dilute to 1 liter with
sopropanol. Alternatively, 1.22 g of (BaClr2HtO] may
be used instead of the perchlorate. Standardize as in
Section 5.5.
KDERAl MOUTH, VOL 43, NO. 1*0THURSDAY, AUGUST II, 1977
IV-199
-------
RULES AND REGULATIONS
3.3 5 Sulfuric Acid Standard, 0 0100 N. Purchase or
standardize to *0.0002 N against 0 0100 N NaOH which
has previously been standardized against potassium
acid phthalate (primary standard grade)
4 Procedure.
4.1 Sampling.
411 Preparation of collection train. Measure 15 ml of
80 percent isopropanol into the midget bubbler and 15
ml of 3 percent hydrogen peroxide into each of the first
two midget impingers Leave the final midget impinger
dry Assemble the train as shown in Figure fr-l Adjust
probe heater to a temperature sufficient to prevent water
condensation. Place crushed ice and water around the
impingers
4 1 2 Leak-check procedure A leak check prior to the
sampling run is optional, however, a leak check after the
sampling run is mandatory The leak-check procedure is
as follows:
With the probe disconnected, place a vacuum gauge at
the inlet to the bubbler and pull a vacuum of 250 mm
(10 in } Eg; plug or pinch otf the outlet of the flow meter,
and then turn off the pump The vacuum shall remain
stable for at least 30 seconds Carefully release the
vacuum gauge before releasing the flow meter end to
prevent back flow of the impinger fluid
Other leak check procedures may be used, subject to
the approval of the Administrator, U S Environmental
Protection Agency The procedure used in Method 5 is
not suitable for diaphragm pumps
413 Sample collection Record the initial dry gas
meter reading and barometric pressure. To begin sam-
pling, position the tip of the probe at the sampling point,
connect the probe to the bubbler, and start the pump
Adjust the sample flow to a constant rate of ap-
proximately 1 0 liter'min as indicated by the rotameter.
Maintain this constant rate (*10 percent) during the
entire sampling run. Take readings (dry gas meter,
temperatures at dry gas meter and at impinger outlet
and rate meter) at least every 5 minutes. Add more ice
during the run to keep the temperature of the gases
leaving the last impinger at 20° C (68° F) or less. At the
conclusion of each run, turn off the pump, remove probe
from the stack, and record the final readings. Conduct a
leak check as in Section 4.1.2. (This leak check is manda-
tory.) If a leak is found, void the test run. Drain the ice
bath, and purge the remaining part of the train by draw-
ing clean ambient air through the system for 15 minutes
at the sampling rate.
Clean ambient air can be provided by passing air
through a charcoal filter or through an extra midget
impinger with 15 ml of 3 percent HiOi. The tester may
opt to simply use ambient air, without purification.
4.2 Sample Recovery. Disconnect the impingers after
purging. Discard the contents of the midget bubbler. Pour
the contents of the midget impingers into a leak-free
polyethylene bottle for shipment. Rinse the three midget
impingers and the connecting tubes with deionized,
distilled water, and add the washings to the same storage
container. Mark the fluid level. Seal and identify the
sample container.
4.3 Sample Analysis. Note level of liquid in container,
and confirm whether any sample was lost during ship-
ment; note this on analytical data sheet. If a noticeable
amount of leakage has occurred, eitber void tbe sample
or use methods, subject to the approval of the Adminis-
trator, to correct the final results.
Transfer the contents of the storage container to a
100-ml volumetric flask and dilute to exactly 100 ml
with deionized, distilled water. Pipette a 20-ml aliquot of
this solution into a 250-ml Erlenmeyer flask, add 80 ml
oflOO percent isopropanol and two to four drops of thorin
indicator, and titrate to a pink endpoint using 0.0100 N
barium perchlorate. Repeat and average the titration
volumes. Run a blank with each series of samples. Repli-
cate titrations must agree within 1 percent or 0.2 ml,
whichever is larger.
(NOTE.Protect the 0.0100 N barium perchlorate
solution from evaporation at all times.)
5. Calibration
5.1 Metering System.
5.1.1 Initial Calibration. Before its initial use in the
field, first leak check the metering system (drying tube,
needle valve, pump, rotameter, and dry gas meter) as
follows: place a vacuum gauge at the inlet to the drying
tube and pull a vacuum of 250 mm (10 in.) Hg; plug or
pinch off the outlet or the flow meter, and then turn off
the pump. The vacuum shall remain stable for at least
30 seconds. Carefully release the vacuum gauge before
releasing the flow meter end.
Next, calibrate the metering system (at the sampling
flow rate specified by the method) as follows: connect
an appropriately sized wet test meter (e.g., 1 liter per
revolution) to the inlet of the drying tube. Make three
independent calibration runs, using at least five revolu-
tions of the dry gas meter per run. Calculate the calibra-
tion factor, Y (wet test meter calibration volume divided
by the dry gas meter volume, both volumes adjusted to
the same reference temperature and pressure), for each
ran, and average the results. If any Y value deviates by
more than 2 percent from the average, the metering
system is unacceptable for use. Otherwise, use the aver-
age as the calibration factor for subsequent test runs.
5.1.2 Post-Test Calibration Check. After each field
test series, conduct a calibration check as in Section 5.1.1
above, except for the following variations: (a) the leak
check is not to be conducted, (b) three, or more revolu-
tions of the dry gas meter may be used, and (c) only two
independent runs need be made. If the calibration factor
does not deviate by more than 5 percent from the initial
calibration factor (determined in Section 5.1.1), then the
dry gas meter volumes obtained during the test series
are acceptable. If the calibration factor deviates by more
than 5 percent, recalibrate the metering system as in
Section 5.1.1, and for the calculations, use the calibration
factor (initial or recalibration) that yields the lower gas
volume for each test run.
5.2 Thermometers. Calibrate against mercury-ln-
glass thermometers.
5.3 Rotameter. The rotameter need not be calibrated
but should be cleaned and maintained according to the
manufacturer's instruction.
5.4 Barometer. Calibrate against a mercury barom-
eter.
5.5 Barium Perchlorate Solution. Standardize the
barium perchlorate solution against 25 ml of standard
sulfuric acid to which 100 ml of 100 percent isopropanol
has been added.
6. Calculation!
Carry out calculations, retaining at least one extra
decimal figure beyond that of the acquired data. Round
off figures after final calculation.
6.1 Nomenclature.
C«,-Concentration of sulfur dioxide, dry basis
' corrected to standard conditions, mg/dscm
. (Ib/dscf).
.V=Normality of barium perchlorate tltrant,
milllequivalents/ml.
Pb«r=Barometrlc pressure at the exit orifice of the
dry gas meter, mm Hg (In. Hg).
P.td- Standard absolute pressure, 760 mm Hg
(29.92 in. Hg).
T«Average dry gas meter absolute temperature,
°K (°R).
T,td°° Standard absolute temperature, 293° K
(528° R).
V.Volume of sample aliquot titrated, ml.
V»-Dry gas volume as measured by the dry gas
meter, dcm (dcf).
V,(.tj)=Dry gas volume measured by the dry gas
meter, corrected to standard conditions,
dscm (dscf).
Vw.li,Total volume of solution In which the sulfur
dioxide sample is contained, 100 ml.
V,= Volume of barium perchlorate titrant used
for the sample, ml (average of replicate
titrations).
V,i=Volume of barium perchlorate tltrant used
for the blank, ml.
Y= Dry gas meter calibration factor.
32.03=Equivalent weight of sulfur dioxide.
6.2 Dry sample gas volume, corrected to standard
conditions. ._.._. -- _
jf V '" ' b»r
A,r T^
Equation 9-1
where:
Jfi-0.3858 °K/mm Hg for metric units.
-17.84 °R/in. Hg for English units.
6.3 Sulfur dioxide concentration.
-K,
(V,-V,t)
Equation 6-2
where'
Kt-32 03 mg/meq. for metric units.
-7.061X10-S Ib/meq. for English units.
7.
1. Atmospheric Emissions from Sulfuric Acid Manu-
facturing Processes. U.S. DHEW, PHS. Division of Air
Pollution Public Health Service Publication No.
999-AP-U. Cincinnati, Ohio. 1965.
2. Corbett, P. F. The Determination of SO) and SO]
In Flue Oases. Journal of the Institute of Fuel. 14: 237-
s! Matty, R. E. and E. K. Diehl. Measuring Flue-Gas
SOi and SOi. Power. 101: 94-97. November 1957.
4. Patton, W.F. and J. A. Brink, Jr. New Equipment
and Techniques for Sampling Chemical Process Oases.
J. Air Pollution Control Association. IS: 162. 1963.
5. Rom, J. J. Maintenance, Calibration, and Operation
of Isokinetic Source-Sampling Equipment. Office of
Air Programs, Environmental Protection Agency.
Research Triangle Park, N.C. APTD-0576. March 1972.
6. Hamil, H. F. and D. E. Camann. Collaborative
Study of Method for the Determination of Sulfur Dioxide
Emissions from Stationary Sources (Fossil-Fuel Fired
Steam Generators). Environmental Protection Agency,
Research Triangle Park, N.C. EPA-650/4-74-024.
December 1973.
7. Annual Book of ASTM Standards. Part 31; Water,
Atmospheric Analysis. American Society for Testing
and Materials. Philadelphia, Ps. 1974. pp. 40-42.
8. Knoll, J. E. and M. R. Midgett. The Application of
EPA Method 6 to High Sulfur Dioxide Concentrations.
Environmental Protection Agency. Research Triangle
Park, N.C. EPA-600/4-76-038. July 1976.
METHOD 7DETERMINATION or NITBOQEN OXIDE
EMISSIONS FROM STATIONARY SOUECM
1. Principle and AppHcabatti
1.1 Principle. A grab sample Is collected in an evacu-
ated flask containing a dilute sulfuric acid-hydrogen
peroxide absorbing solution, and the nitrogen oxides,
except nitrous oxide, are measured colorimetericaUy
using the phenoldisulfonlc acid (PDS) procedure.
1.2 Applicability. This method is applicable to the
measurement of nitrogen oxides emitted from stationary
sources. The range of the method has been determined
to be 2 to 400 milligrams NO, (as NOt) per dry standard
cubic meter, without having to dilute the sample.
2. Apparatut
2.1 Sampling (see Figure 7-1). Other grab sampling
systems or equipment, capable of measuring sample
volume to within ±2.0 percent and collecting a sufficient
sample volume to allow analytical reproducibllity to
within ±5 percent, will be considered acceptable alter-
natives, subject to approval of the Administrator, U.S.
Environmental Protection Agency. The following
equipment is used In sampling:
2.1.1 Probe. Borosilicate glass tubing, sufficiently
heated to prevent water condensation and equipped
with an in-stack or out-stack filter to remove particulate
matter (a plug of glass wool is satisfactory for this
purpose). Stainless steel or Teflon' tubing may also be
used for the probe. Heating Is not necessary if the probe
remains dry during the purging period.
> Mention of trade names or specific products does not
constitute endorsement by the Environmental Pro-
tection Agency.
FEDERAl REGISTER, VOL. 42, NO. 160THURSDAY, AUGUST 18, 1977
IV-200
-------
RULES AND REGULATIONS
PROBE
\
EVACUATE
PURGE
\^S
FLASK VALVEx ff} SAMPLE
FILTER
GROUND-GLASS SOCKET
§ NO. 12/5
110 mm
3-WAY STOPCOCK:
T-BORE. i PYREX.
2-nvnBORE. 8-mmOO
FLASK
FLASK SHIELLX. .
SQUEEZE BULB
IMP VALVE
PUMP
THERMOMETER
GROUND-GLASS CONE
STANDARD TAPER.
§ SLEEVE NO. 24/40
210 mm
GROUND-GLASS
SOCKET. § NO. 12/5
PYREX
FOAM ENCASEMENT
BOILING FLASK -
2-LITER. BOUND-BOTTOM, SHORT NECK.
WITH I SLEEVE NO. 24/40
Figure 7-1. Sampling train, flask valve, and flask.
2.1.2 Collection Flask. Two-liter borosilicate, round
bottom flask, with short neck and 24/40 standard taper
opening, protected against implosion or breakage.
2.1.3 Flask Valve. T-bore stopcock connected to a
24/40 standard taper joint.
2.1.4 Temperature Gauge. Dial-type thermometer, or
other temperature gauge, capable of measuring 1° C
(2° F) intervals from -5 to 50° C (25 to 125" F).
2.1.5 Vacuum Line. Tubing capable of withstanding
a vacuum of 75 mm Hg (3 in. Hg) absolute pressure, with
"T" connection and T-bore stopcock.
2.1.6 Vacuum Gauge. U-tube manometer, 1 meter
(36 iu.), with 1-mm (0.1-in.) divisions, or other gauge
capable of measuring pressure to within ±2.5 mm Hg
(0.10 in. Hg).
2.1.7 Pump. Capable of evacuating the collection
flask to a pressure equal to or less than 75 mm Hg (3 in.
Hg) absolute.
2.1.8 Squeeze Bulb. One-way.
2.1.9 Volumetnc Pipette. 25 ml.
2.1.10 Stopcock and Ground Joint Grease. A high-
vacuum, high-temperature chlorofluorocarbon grease is
required. Halocarbon 25-58 has been found to be effective.
2.1.11 Barometer. Mercury, aneroid, or other barom-
eter capable of measuring atmospheric pressure to within
2.5 mm Hg (0.1 in. Hg). In many cases, the barometric
reading may be obtained from a nearby national weather
ervice station, in which case the station value (which Is
the absolute barometric pressure) shall be requested and
an adjustment for elevation differences between the
weather station and sampling point shall be applied at a
rate of minus 2.5 mm Hg (0.1 in. Hg) per 30 m (100 ft)
elevation increase, or vice versa for elevation decrease.
2.2 Sample Recovery. The following equipment Is
required for sample recovery
2.2 1 Graduated Cylinder. 50 m! with 1-ml divisions.
2.2.2 Storage Containers. Leak free polyethylene
bottles.
2.2.3 Wash Bottle. Polyethylene or glass
2.2.4 Glass Stirring Rod.
2.2.5 Test Paper for Indicating pH. To cover the pH
range of 7 to 14.
2.3 Analysis. For the analysis, the following equip-
ment is needed.
2.3.1 Volumetric Pipettes. Two 1 ml, two 2 ml, one
3 ml, one 4 ml, two 10 ml, and one 25 ml for each sample
and standard.
2.3.2 Porcelain Evaporating Dishes. 175- to 250-ml
capacity with lip for pouring, one for each sample and
each standard. The Coors No. 45006 (shallow-form, 195
ml) has been found to be satisfactory. Alternatively,
polymethyl pentene beakers (Nalge No. 1203,150ml), or
glass beakers (150 ml) may be used. When glass beakers
are used, etching of the beakers may cause solid matter
to be present in the analytical steo. the solids should be
removed by filtration (see Section 4.3).
2.3.3 Steam Bath Low-temperature ovens or thermo-
statically controlled hot plates kept below 70° C (160° F)
are acceptable alternatives
2.3 4 Dropping Pipette or Dropper. Three required.
2.3.5 Polyethylene Policeman. One for each sample
and each standard.
2.3.6 Graduated Cylinder. 100ml with 1-ml divisions.
2.3.7 Volumetric Flasks. 50 ml (one for each sample),
100 ml (one for each sample and each standard, and one
for the working standard KNOi solution), and 1000 ml
(one).
2.3.8 Spectrophotometer. To measure absorbance at
410 nm.
2.3.0 Graduated Pipette. 10 ml with 0.1-ml divisions.
2.3.10 Test Paper lor Indicating pH. To cover the
pH range of 7 to 14.
2.3.11 Analytical Balance. To measure to within 0.1
mg.
3. Reagent*
Unless otherwise indicated, it is intended that all
reagents conform to the specifications established by the
Committee on Analytical Reagents of the American
Chemical Society, where such specifications are avail
able; otherwise, use the best available grade.
3.1 Sampling To prepare the absorbing solution,
cautiously add 2.8 ml concentrated HiSOi to 1 liter of
deionlzcd, distilled water. Mix well and add 6 ml of 3
percent hydrogen peroxide, freshly prepared from 30
percent hydrogen peroxide solution. The absorbing
solution should be used within 1 week of its preparation.
Do not expose to extreme heat or direct sunlight
3.2 Sample Recovery. Two reagents are required for
sample recovery:
3.2.1 Sodium Hydroxide (IN). Dissolve 40 g NaOH
in deionned, distilled water and dilute to 1 liter.
3.2.2 Water. Deiomied. distilled to conform to ASTM
specification D1193-74, Type 3. At the option of the
analyst, the KMNO/ test for oiidizable organic matter
may be omitted when high concentrations of organic
matter are not expected to be present
3.3 Analysis. For the analysis, the following reagents
are required'
3.3.1 Fuming Sulfuric Acid. 15 to 18 percent by weight
free sulfur tnoxide. HANDLE WITH CAUTION.
3.3.2 Phenol. White solid.
3.3.3 Sulfuric Acid. Concentrated, 95 percent mini-
mum assay. HANDLE WITH CAUTION.
3.3.4 Potassium Nitrate. Dried at 105 to 110° C (220
to 230° F) for a minimum of 2 hours Just prior to prepara-
tion of standard solution.
33.5 Standard KNOj Solution. Dissolve exactly
2.198 g of dried potassium nitrate (KNOi) in deiomzed,
distilled water and dilute to 1 liter with deiomzed,
distilled water in a 1,000-ml volumetric flask.
3.3.6 Working Standard KNOj Solution Dilute 10
ml of the standard solution to 100 ml with dcionized
distilled water. One mllhliter of the working standard
solution is equivalent to 100/ig nitrogen dioxide (NOj).
3.3.7 Water. Deionized, distilled as in Section 3.2 2.
3.38 Phenoldisulfonic Acid Solution Dissolve 25 g
of pure white phenol in 150 ml concentrated sulfuric
acid on a steam bath Cool, add 75 ml fuming sulfuric
acid, and heat at 100° C (212° F) for 2 hours Store in
a dark, stoppered bottle.
4. Procedure*
41 Sampling.
411 Pipette 25 ml of absorbing solution into a sample
flask, retaining a sufficient quantity for use in preparing
the calibration standards Insert the flask valve stopper
into the flask with the valve in the "purge" position
Assemble the sampling train as shown in Figure 7-1
and place the probe at the sampling point Make sure
that all fittings are tight and leak-free, and that all
ground glass joints have been properly greasi-d with a
high-vacuum, high-temperature chloroiliiorocarhon-
based stopcock grease Turn the flask valve and the
pump valve to their "evacuate" positions Evacuate'
the flask to 75 mm Hg (3 in. Hg) absolute pressure, or
less Evacuation to a pressure approaching the vapor
pressure of water at the existing temperature is desirable
Turn the pump valve to its "vent" position and turn
ofl the pump Check for leakage by observing the ma-
nometer for any pressure fluctuation (Any variation
FEDERAL REGISTER, VOL. 42, NO. 160THURSDAY, AUGUST 18, 1977
IV-201
-------
RULES AND REGULATIONS
greater than 10 mm Hg (0.4 in Hg) over a period of
1 minute is not acceptable, and the flask is not to be
used until the leakage problem is corrected. Pressure
in the flask is not to exceed 75 mm Hg (3 in. Hg) absolute
ftt the time sampling is commenced ) Record the volume
of the flask and valve (V/), the flask temperature (T,),
and the barometric pressure Turn the flask valve
counterclockwise to its "purge" position and do the
same with the pump valve. Purge the probe and the
vacuum tube using the squeeze bulb. If condensation
occurs in the probe and the flask valve area, heat the
probe and purge until the condensation disappears.
Srext, turn the pump valve to its "vent" position. Turn
the flask valve clockwise to its "evacuate" position and
record the difference in the mercury levels in the manom-
eter. The absolute internal pressure in the flask (Pi)
is equal to the barometric pressure less the manometer
reading. Immediately turn the flask valve to the "sam-
ple" position and permit the gas to enter the flask until
pressures in the flask and sample line (i e , duct, stack)
are equal. This will usually require about 15 seconds;
a longer period indicates a "plug" in the probe, which
must be corrected before sampling is continued. After
collecting the sample, turn the flask valve to its "purge"
position and disconnect the flask from the sampling
train. Shake the flask for at least 5 minutes.
4.1.2 If the gas being sampled contains insufficient
oxygen for the conversion of NO to NOj (e.g., an ap-
plicable subpart of the standard may require taking a
sample of a calibration gas mixture of NO in Nj), then
oxygen shall be introduced into the flask to permit this
conversion. Oxygen may be introduced into the flask
by one of three methods; (1) Before evacuating the
sampling flask, flush with pure cylinder oxygen, then
evacuate flask to 75 mm Hg (3 in. Hg) absolute pressure
or less, or (2) inject oxygen into the flask after sampling;
or (3) terminate sampling with a minimum of 50 mm
Hg (2 in Hg) vacuum remaining in the flask, record
this final pressure, and then vent the flask to the at-
mosphere until the flask pressure is almost equal to
atmospheric pressure.
4.2 Sample Recovery. Let the flask set for a minimum
of 16 hours and then shake the contents for 2 minutes
Connect the flask to a mercury filled U-tube manometer.
Open the valve from the flask to the manometer and
record the flask temperature (TV), the barometric
pressure, and the difference between the mercury levels
n the manometer. The absolute internal pressure in
the flask (P/) is the barometric pressure less the man-
ometer reading Transfer the contents of the flask to a
leak-free polyethylene bottle. Rinse the flask twice
with 5-ml portions of deionized, distilled water and add
the rinse water to the bottle Adjust the pH to between
9 and 12 by adding sodium hydroxide (1 N), dropwise
(about 25 to 35 drops). Check the pH by dipping a
stirring rod into the solution and then touching the rod
to the pH test paper Remove as little material as possible
during this step. Mark the height of the liquid level so
that the container can be checked for leakage after
transport. Label the container to clearly identify its
contents. Seal the container for shipping.
4.3 Analysis. Note the level of the liquid in container
and confirm whether or not any sample was lost during
shipment; note this on the analytical data sheet. If a
noticeable amount of leakage has occurred, either void
the sample or use methods, subject to the approval of
the Administrator, to correct the final results. Immedi-
ately prior to analysis, transfer the contents of the
shipping container to a 50-ml volumetric flask, and
rinse the container twice with 5-ml portions of deionized,
distilled water. Add the rinse water to the flask and
dilute to the mark with deionized, distilled water; mix
thoroughly. Pipette a 25-ml aliquot into the procelain
evaporating dish. Return any unused portion of the
sample to the polyethylene storage bottle. Evaporate
the 25-ml aliquot to dryness on a steam bath and allow
to cool. Add 2 ml phenoldisulfonic acid solution to the
dried residue and triturate thoroughly with a poylethyl-
ene policeman. Make sure the solution contacts all the
residue. Add 1 ml deionized, distilled water and four
drops.of concentrated sulfuric acid. Heat the solution
on a steam bath for 3 minutes with occasional stirring.
Allow the solution to cool, add 20 ml deionized, distilled
water, mix well by stirring, and add concentrated am-
monium hydroxide, dropwise, with constant stirring,
until the pH is 10 (as determined by pH paper). If the
sample contains solids, these must be removed by
filtration (centrifugation is an acceptable alternative,
subject to the approval of the Administrator), as follows.
filter through Whatman No. 41 filter paper into a 100-ml
volumetric flask; rinse the evaporating dish with three
5-ml portions of deionized, distilled water; filter these
three rinses. Wash the filter with at least three 15-ml
portions of deionized, distilled water. Add the filter
washings to the contents of the volumetric flask and
dilute to the mark with deionized, distilled water. If
solids are absent, the solution can be transferred directly
to the 100-ml volumetric flask and diluted to the mark
with deionized, distilled water. Mix the contents of the
flask thoroughly, and measure the absorbance at the
optimum wavelength used for the standards (Section
5.2.1), using the blank solution as a zero reference. Dilute
the sample and the blank with equal volumes of deion-
ized, distilled water if the absorbance exceeds At, the
absorbance of the 400 *ig NOj standard (see Section 5.2.2).
5 Calibration
5 1 Flask Volume. The volume of the collection flask-
flask valve combination must be known prior to sam-
pling. Assemble the flask and flask valve and fill with
water, to the stopcock Measure the volume of water to
±10 ml Record this volume on the flask.
6 2 Spectrophotometer Calibration.
8 2.1 Optimum Wavelength Determination. For both
flied and variable wavelength spectrophotometers,
calibrate against standard certified wavelength of 410
nm, every 6 months. Alternatively, for vanable wave
length spectrophotometers, scan the spectrum between
400 and 415 nm using a 200 jig NOi standard solution (see
Section 5.2 2). If a peak does not occur, the spectropho-
tometer is probably malfunctioning, and should be re-
paired. When a peak is obtained within the 400 to 418 nm
range, the wavelength at which this peak occurs shall be
the optimum wavelength for the measurement of ab-
sorbance for both the standards and samples.
5 2.2 Determination of Spectrophotometer Calibra-
tion Factor K, Add 0 0, 1 0, 2 0, 3.0. and 4.0 ml of the
KNOi working standard solution (1 ml = 100Mg NOj) to
a series of five porcelain evaporating dishes. To each, add
25 ml of absorbing solution. 10 ml deionized, distilled
water, and sodium hydroxide (IN), dropwise, until the
pH is between 9 and 12 (aboutr25 to 35 drops each).
Beginning with the evaporation step, follow the analy-
sis procedure of Section 4.3, until the solution has been
transferred to the 100 ml volumetric flask and diluted to
the mark Measure the absorbance of each solution, at the
optimum wavelength, as determined in Section 521.
This calibration procedure must be repeated on each day
that samples are analyzed Calculate the Spectrophotom-
eter calibration factor as follows:
Kc=100
Equation 7-1
where:
Jfc=Calibratlon factor
Xi= Absorbance of the 100-jig NOj standard
/4i=Absorbance of the 200-pg NOs standard
Aj= Absorbance of the 300-yg NOj standard
X<=Absorbance of the 400-pg NO: standard
5.3 Barometer. Calibrate against a mercury barom-
eter.
5.4 Temperature Gauge. Calibrate dial thermometers
against mercury-in-glass thermometers.
5.5 Vacuum Gauge. Calibrate mechanical gauges, If
used, against a mercury manometer such as that speci-
fied in 2.1.6.
5.6 Analytical Balance. Calibrate against standard
weights.
6. Calculation!
Carry out the calculations, retaining at least one extra
decimal, figure beyond that of the acquired data. Round
off figures after final calculations.
6.1 Nomenclature.
A= Absorbance of sample.
C=Concentration of NO. as N.0>, dry basis, cor-
rected to standard conditions, mg/dscm
(Ib/dscf).
F=Dilution factor (ie, 25/5, 25/10, etc., required
only if sample dilution was needed to reduce
the absorbance into the range of calibration).
/f«=Spectrophotometer calibration factor.
TO = Mass of NO, as NOi in gas sample, jig.
PI= Final absolute pressure of flask, mm Hg (in. Hg).
P> = Initial absolute pressure of flask, mm Hg (in.
Hg).
P.id "Standard absolute pressure, 760 mm Hg (29.92 in.
He).
7"/=Final absolute temperature of flask ,°K (°R).
7\ = Initial absolute temperature of flask, °K (°R).
T.m=Standard absolute temperature, 293° K (528° R)
V',, = Sample volume at standard conditions (dry
basis), ml.
V/= Volume of flask and valve, ml.
V«=Volume of absorbing solution, 25 ml
2=60/25, the aliquot factor. (If other than a 25-ml
aliquot was used for analysis, the correspond-
ing factor must be substituted) .
6.2 Sample volume, dry basis, corrected to standard
conditions.
6.4 Sample concentration, dry basis, corrected to
standard conditions,
where:
, = 0.3858
°K
mm Hg
Equation 7-2
for metric units
= 17.64-
°R
for English units
in. Hg
0.3 Total tig NO; per sample.
m=2KeAF
Equation 7-3
NOTE.If other than a 25-ml aliquot is used for analy-
sis, the factor 2 must he replaced by a corresponding
factor.
TO
1 T~
* te
Equation 7-4
where:
KI= 103 / =- for metric units
=6.243X10-' -!5 for English units
6
7. Bibliography
1. Standard Methods of Chemical Analysis. 6th ed.
New York, D. Vna Nostrand Co., Inc. 1962. Vol. 1,
p. 329-330.
2. Standard Method of Test for Oxides of Nitrogen in
Gaseous Combustion Products (Phenoldisulfonic Acid
Procedure). In: 1968 Book of ASTM Standards, Part 26.
Philadelphia, Pa. 1968. ASTM Designation D-1608-60,
p. 725-729.
3. Jacob, M. B. The Chemical Analysis of Air Pollut-
ants. New York. Interscience Publishers, Inc. 1960.
Vol. 10, p. 351-356.
4. Beatty, R. L., L. B. Berger, and H. H. Schrenk.
Determination of Oxides of Nitrogen by the Phenoldisul-
lonic Acid Method. Bureau of Mines, U.S. Dept. of
Interior. R. I. 3687. February 1943.
5. Hamil, H. F. and D. E. Camann. Collaborative
Study of Method for the Determination of Nitrogen
Oxide Emissions from Stationary Sources (Fossil Fuel-
Fired Steam Generators). Southwest Research Institute
report for Environmental Protection Agency. Research
Triangle Park, N.C. October 5, 1973.
6. Hamil, H. F. and K. E. Thomas. Collaborative
Study of Method for the Drtermination of Nitrogen
Oxide Emissions from Stationary Sources (Nitric Acid
Plants). Southwest Research Institute report for En-
vironmental Protection Agency. Research Triangle
Park, N.C. May 8, 1974.
METHOD 8 DETERMINATION o? SULFUHIC Aero MIST
AND SULFUR DIOXIDE EMISSIONS FROM STATIONARY
SOURCES
1. Principle and Applicability
1.1 Principle. A gas sample is extracted isokinetically
from the stack. The sulfuric acid mist (including sulfur
trioxide) and the sulfur dioxide are separated, and both
fractions are measured separately by the barium-thorm
titration method.
1.2 Applicability. This method is applicable for the
determination of sulfuric acid mist (including sulfur
trioxide, and in the absence of other paniculate matter)
and sulfur dioxide emissions from stationary sources.
Collaborative tests have shown that the minimum
detectable limits of the method are 0.05 milligrams/cubic
meter (0.03X 10-' pounds/cubic foot) for sulfur trioxide
and 1.2 mg/m3 (0.74 10-' Ib/ft*) for sulfur dioxide. No
upper limits have been established. Based on theoretical
calculations for 200 milliliters of 3 percent hydrogen
peroxide solution, the upper concentration limit for
sulfur dioxide in a 1.0 m3 (35.3 ft3) gas sample is about
12,500 mg/m» (7.7X10-* lb/ft»). The upper limit can be
extended by increasing the quantity of peroxide solution
in the impingers.
Possible interfering agents of this method are fluorides,
free ammonia, and dimethyl aniline. If any of these
interfering agents are present (this can be determined by
knowledge of the process), alternative methods, subject
to the approval of the Administrator, are required.
Filterable paniculate matter may be determined along
with SOj and SOj (subject to the approval of the Ad-
ministrator): howevei, the procedure used for paniculate
matter must be consistent with the specifications and
procedures given in Method 5.
2. Apparatus
2.1 Sampling. A schematic of the sampling train
used in this method is shown in Figure 8-1; ft Is similar
to the Method 5 train except that the filter position is
different and the flltei holder does not have to be heated.
Commercial models of this train are available. For those
who desire to build their own, however, complete con-
struction details are described In APTD-OJ81. Changes
from the APTD-0581 document and allowable modi-
fications to Figure 8-1 are discussed In the following
subsections.
The operating and maintenance procedures for the
sampling train are described in APTD-0576. Since correct
usage is important in obtaining valid results, all users
should read the APTD-0576 document and adopt the
operating and maintenance procedures outlined in it,
unless otherwise specified herein. Further details and
guidelines on operation and maintenance arc given in
Method 5 and should be read and followed whenever
they are applicable.
2.1.1 Probe Nozzle. Same as Method 5, Section 2.1.1.
2.1.2 Probe Liner. Borosilicate or quartz glass, with a
heating system to prevent visible condensation during
sampling. Do not use metal probe liners.
2.1.3 Pitot Tube. Same as Method 5, Section 2.1.3.
FEDERAL REGISTER, VOL. 42, NO. 160THURSDAY, AUGUST 1$, 1977
IV--2Q2
-------
RULES AND REGULATIONS
TEMPERATURE SENSOR
PROBE
THERMOMETER
PROBE
7
REVERSE TYPE
PITOT TUBE
PITOTTUBE
TEMPERATURE SENSOR
FILTER HOLDER
CHECK
VALVE
VACUUM
LINE
VACUUM
GAUGE
MAIN VALVE
DRY TEST METER
Figure 8-1. Sulfuric acid mist sampling train.
2.1.4 Differential Pressure Gauge. Same as Method 5,
Section 2.1.4.
2.1.5 Filter Holder. Borosllicate glass, with a glass
frit filter support and a silicone rubber gasket. Other
gasket materials, e.g.. Teflon or Viton, may be used sub-
ject to the approval of the Administrator. The holder
design shall provide a positive seal against leakage from
the outside or around the filter. The filter holder shall
be placed between the first and second Impingers. Note:
Do not heat the filter holder.
2.1.6 ImpingersFour, as shown In Figure 8-1. The
first and third shall be of the Oreenburg-Smith design
with standard tips. The second and fourth shall be of
the Oreenburg-Smlth design, modified by replacing the
Insert with an approximately 13 millimeter (0.5 in.) ID
glass tube, having an unconstricted tip located 13 mm
(0.5 in.) from the bottom of the flask. Similar collection
systems, which have been approved by the Adminis-
trator, may be used.
2.1.7 Metering System. Same as Method 5, Section
2.1.8.
2.1.8 Barometer. Same as Method 5. Section 2.1.9
2.1.9 Gas Density Determination Equipment. Same
as Method 5, Section 2.1.10.
2.1.10 Temperature Gauge. Thermometer, or equiva-
lent, to measure the temperature of the gas leaving the
Impinger train to within 1° C (2° F).
2.2 Sample Recovery.
2J.1 Wash Bottles. Polyethylene or glass, 500 ml
(two).
2.2.2 Graduated Cylinders. 260 ml, 1 liter (Volu-
metric flasks may also be used.)
in£?-*i 5toiye Bo"1"-Leak-frM polyethylene bottles,
1000 ml size (two tor each sampling run).
2.2.4 Trip Balance. SOOgram capacity, to measure to
±0.5 g (necessary only if a moisture content analysis is
to be done).
2.3 Analysis.
2.3.1 Pipettes. Volumetric 25 ml, 100 ml.
2.3.2 Burrette. 60 ml.
2.3.3 Erlenmeyer Flask. 250 ml. (one for each sample
blank and standard).
2.3.4 Graduated Cylinder. 100 ml.
2.3.5 Trip Balance. 600 g capacity, to measure to
ab0.5g.
2.3.6 Dropping Bottle. To add indicator solution,
125-mlsUe.
a.Rcaicnti
^Unless otherwise Indicated, all reagents are to conform
to the specifications established by the Committee on
Analytical Reagents of the American Chemical Society,
where such specifications are available. Otherwise, use
the best available grade.
3.1 Sampling.
3.1.1 Filters. Same as Method 5, Section 3.1.1.
3.1.2 Silica Gel. Same as Method 5, Section 3.1.2.
3.1.3 Water. Deionited, distilled to conform to A8TM
specification D1193-74, Type 3. At the option of the
analyst, the KMnO< test for oxidizable organic matter
may be omitted when high concentrations of organic
matter are not expected to be present.
1.1.4 Isopropanol. 80 Percent. Mix 800 ml of Isopro-
panol with 200 ml of delonked, distilled water.
Now.Experience has shown that only A.C.B. grade
Uopropanol is satisfactory. Tests have shown that
Isopropaool obtained from commercial sources ocea-
canonally has peroxide impurities that will cause er-
roneously high snlfnric acid mist measurement. Use
the following test for detecting peroxides in each lot of
isopropanol: Shake 10 ml of the Isopropanol with 10 ml
of freshly prepared 10 percent potassium iodide solution.
Prepare a blank by similarly treating 10 ml of distilled
water. After 1 minute, read the absorbance on a spectro-
photometer at 352 nanometers. If the absorbance exceeds
5.1, the isopropanol shall not be used. Peroxides may be
removed from isopropanol by redistilling, or by passage
thiough a column of activated alumina. However, re-
agent-grade Isopropanol with suitably low peroxide levels
Is readily available from commercial sources; therefore,
rejection of contaminated lots may be more efficient
than following the peroxide removal procedure.
3.1.5 Hydrogen Peroxide, 3 Percent. Dilute 100 ml
of 30 percent hydrogen peroxide to 1 liter with deionized,
distilled water. Prepare fresh daily.
3.1.6 Crushed Ice.
3.2 Sample Recovery.
3.2.1 Water. Same as 3.1.3.
3.2.2 Isopropanol, 80 Percent. Same as 3.1.4.
3.3 Analysis.
3J.I Water. Same as 3.1.3.
3.3.2 Isopropanol, 100 Percent.
3.3.3 Thorin Indicator. l-(o-arsonophenylaio)-2-naph-
thol-3, 6-dtsulfonic acid, disodium salt, or equivalent.
Dissolve 0.20 g in 100 ml of deionited, distilled water.
3.3.4 Barium Perchlorate (0.0100 Normal). Dissolve
1.95 got barium perchlorate trihydrate (Ba(ClOi)i-SHiO)
In 200 ml deionited, distilled water, and dilute to 1 liter
with Isopropanol; 1.22 g of barium chloride dihydrate
(BaClf2HiO) may be used Instead of the barium per-
chlorate. Standardize with sulfurlc acid as in Section 5.2.
This solution must be protected against evaporation at
all times.
KDERAL UGISTER, VOL 42, NO. l«0THUISDAY, AUGUST II, 1977
IV-203
-------
RULES AND REGULATIONS
3.3.5 Sulfuric Acid Standard (0 0100 N). Purchase or
standardize to ±0.0002 N against 00100 N NaOH that
has previously been standardized against primary
standard potassium acid phthalate.
4. Procedure
4.1 Sampling.
4 1 1 Pretest Preparation. Follow the procedure out-
lined in Method 5, Section 4.1.1; filters should be in-
spected, but need not be desiccated, weighed, or identi-
lied. If the effluent gas can be considered dry, I.e., mois-
ture free,, the silica gel need not be weighed.
412 Preliminary Determinations. Follow the pro-
cedure outlined in Method 5, Section 4.1.2.
4 1 3 Preparation of Collection Train. Follow the pro-
cedure outlined in Method 5, Section 4.1.3 (eicept for
the second paragraph and other obviously inapplicable
parts) and use Figure 8-1 instead of Figure 5-1. Replace
the second paragraph with: Place 100 ml of 80 percent
isopropanol in the first impinger, 100 ml of 3 percent
hydrogen peronde in both the second and third im-
P'
bl;
lingers; retain a portion of each reagent for use as a
'lank solution. Place about 200 g of silica gel in the fourth
impinger.
NOTE.If moisture content is to be determined by
plus container) must also be determined to the nearest
0.5 g and recorded.
4.1.4 Pretest Leak-Check Procedure. Follow the
basic procedure outlined in Method 5, Section 4.1.4.1,
noting that the probe heater shall be adjusted to the
minimum temperature required to prevent condensa-
tion, and also that verbage such as, ' ' plugging the
inlet to the niter holder ," shall be replaced by,
" * plugging the inlet to the first impinger * * *."
The pretest leak-check is optional.
4.1.5 Train Operation. Follow the basic procedures
outlined in Method 5, Section 4.1.5, in conjunction with
the following special instructions. Data shall be recorded
on a sheet similar to the one In Figure 8-2. The sampling
rate shall not exceed 0.030 rn'/mln (1.0 cfm) during the
run. Periodically during the test, observe the connecting
line between the probe and first Impinger for signs of
condensation. If it does occur, adjust the probe heater
setting upward to the minimum temperature required
to prevent condensation. If component changes become
necessary during a run, a leak-check shall be done Im-
mediately before each change, according to the procedure
outlined In Section 4.1.4.2 of Method 5 (with appropriate
modifications, as mentioned in Section 4.1.4 of this
method); record all leak rates. If the leakage rate(s)
exceed the specified rate, the tester shall either void the
run or shall plan to correct the sample volume as out-
lined in Section 6.3 of Method 5. Immediately after com-
ponent changes, leak-checks are optional. If these
leak-checks are done, the procedure outlined in Section
4.1.4.1 of Method 5 (with appropriate modifications)
shall be used.
PLANT.
LOCATION
OPERATOR
DATE
RUN NO
SAMPLE BOX NO..
METER BOX NO. _
METER A Hg
C FACTOR
PITOT TUBE COEFFICIENT, Cp.
STATIC PRESSURE, mm HI (in. HI)
AMBIENT TEMPERATURE
BAROMETRIC PRESSURE
ASSUMED MOISTURE, X
PROBE LENGTH, m (ft)
SCHEMATIC OF STACK CROSS SECTION
NOZZLE IDENTIFICATION NO
AVERAGE CALIBRATED NOZZLE DIAMETER, cm (in.).
PROBE HEATER SETTING
LEAK RATE, m3/min,(cfm)
PROBE LINER MATERIAL
FILTER NO.
TRAVERSE POINT
NUMBEF.
TOTAL
SAMPLING
TIME
Wl.min.
AVERAGE
VACUUM
mm H|
(in. H|)
STACK
TEMPERATURE
-------
RULES AND REGULATIONS
values. Replicate titrations most agree within 1 percent
or 0.2 ml, whichever is greater.
4.3.2 Container No. 2. Thoroughly mix the solution
In the container holding the contents of the second and
third impingers. Pipette a 10- ml aliquot of sample Into a
250-ml Erlenmeyer flask. Add ml of isopropanol, 2 to
4 drops of thorln indicator, and titrate to a pink endpoint
using 0.0100 N barium perchlorate. Repeat the titration
with a second aliquot of sample and average the titration
values. Replicate titrations must agree within 1 percent
or 0.2 ml whichever is greater.
4.3.3 Blanks. Prepare blanks by adding 2 to 4 drops
of thorin indicator to 100 ml of 80 percent isopropanol.
Titrate the blanks in the same manner as the samples.
5. Calibration
4.1 Calibrate equipment using the procedures speci-
fied In the following sections of Method 5: Section 5.3
(metering system); Section 5.5 (temperature gauges);
Section 5.7 (barometer). Note that the recommended
leak-check of the metering system, described in Section
6.8 of Method 5, also applies to this method.
5.2 Standardise the barium perchlorate solution with
35 ml of standard sulfurlc acid, to which 100 ml of 100
percent Isopropanol has been added.
t. OOeulatiOM
Note. Carry out calculations retaining at least one
extra decimal figure beyond that of the acquired data.
Round off figures after final calculation-
t.l Nomenclature.
A, Cross-sectional area of notile, m' (ft1).
B^-Water vapor In the gas stream, proportion
by volume.
CHiSOi-Sulfuric acid (Including BOi) concentration,
g/dscm (lb/dscf).
CSOiSuifur dioxide concentration, g/dscm (lb/
dscf).
/-Percent of isokinetic sampling.
AT Normality of barium perchlorate titrant, g
equivalents/liter.
Pbmr Barometric pressure at the sampling site,
mmHg (in. Hg).
P.-Absolute stack gas pressure, mm Hg (In.
Pstd
Hg).
ndard
-Standard absolute pressure, 760 mm Hg
(29.92 in. Hg).
7".-Average absolute dry gas meter temperature
.
Vi,-Total volume of liquid collected In impingers
and silica gel, ml.
V.-Volume of gas sample as measured by dry
gas meter, Ocm (del).
V.(std)Volume of gas sample measured by the dry
gas meter corrected to standard conditions,
dscm (dscf).
»4Average stack gas velocity, calculated by
Method 2, Equation 2-9, using data obtained
from Method 8, m/sec (ft/sec).
Vsoln- Total volume of solution in which the
tulfurir acid or sulfur dioxide sample is
contained, 250 ml or 1,000 ml, respectively.
ViVolume of barium perchlorate titrant used
for the sample, ml.
VitVolume of barium perchlorate titrant used
for the blank, ml.
yDry gas meter calibration factor.
AHAverage pressure drop across orifice meter,
mm (in.) HiO.
6Total sampling time, mm.
U.6**8peclfic gravity of mercury.
60-sec/min.
100Conversion to percent.
6.2 Average dry gas meter temperature and average
orifice pressure drop. See data sheet (Figure 8-2).
«.3 Dry Qas Volume. Correct the sample volume
measured by the dry gas meter to standard conditions
(20° C and 760 nun Hg or 68° F and 29.92 in, Hg) by using
Equation 8-1.
(.id) -
.pb.r+(Ajr/i3.6)
Equation 8-1
where:
jTi^o.3858 «K/mm Hg for metric units.
-17.64 °R/m. Hg for English units.
NOTE.If the leak rate observed during any manda-
tory leak-checks exceeds the specified acceptable rate,
the tester shall either correct the value of V. in Equation
1-1 (as described in Section 64 of Method 4), or shall
invalidate the test run.
6.4 Volume of Water Vapor and Moisture Conteit.
Calculate the volume of water vapor using Equation
5-2 of Method 5; the weight of water collected in the
implngers and silica gel can be directly converted to
mffliliters (the specific gravity of water Is 1 g/ml). Cal-
culate the moisture content of the stack gas, using Equa-
tion 5-3 of Method 5. The "Note" in Section 6.5 of Method
5 also applies to this method. Note that if the effluent gas
stream can be considered dry, the volume of water vapor
and moisture content need not be calculated.
6.5 Sulfuric acid mist (including SOi) concentration.
N(V.-V»)
V«<.td>
Equation 8-2
where:
#1=0.04904 g/millieqnivalent for metric units.
-1.081X10-
-------
70
Title 40Protection of Environment
CHAPTER IENVIRONMENTAL
PROTECTION AGENCY
[FKL 784-7]
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
PART 61NATIONAL EMISSION STAND-
ARDS FOR HAZARDOUS AIR POLLUTANTS
Delegation of Authority; New Source
Review; State of Montana
AGENCY: Environmental Protection
Agency.
ACTION: Final rule.
SUMMARY: This rule will change the
address to which reports and applica-
tions must be sent by operators of new
sources in the State of Montana. The
address change is the result of delegation
of authority to the State of Montana for
New Source Performance Standards (40
CFR Part 60) and National Emissions
Standards for Hazardous Air Pollutants
(40 CFR Part 61).
ADDRESS: Any questions or comments
should be sent to Director, Enforcement
Division, Environmental Protection
Agency, 1860 Lincoln Street, Denver,
Colo. 80295.
FOR FURTHER INFORMATION CON-
TACT:
RULES AND REGULATIONS
Act. as amended, 42 U.S.C. 1857, 1857C-5,
6,7 and 1857g.
Dated: August 17,1977.
JOHN A. GREEN,
Regional Administrator.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amended
as follows:
1.' In | 60.4 paragraph (b) is amended
by revising subparagraph (BB) to read
as follows:
§ 60.4 Address.
*
(b) * *
(BB) State of Montana, Department of
Health and Environmental Services, Cogswell
Building. Helena, Mont. 69601.
*
Part 61 of Chapter I, Title 40 of the
Code of Federal Regulations is amended
as follows:
2. In { 61.04 paragraph (b) is amended
by revising subparagraph (BB) to read
as follows:
§ 61.04 Address.
*
(b)
(BB) State of Montana, Department of
Health and Environmental Sciences, Cogs-
well Building, Helena, Mont. 59601.
Mr. Trwin L. Dickstein, 303-837-3868. l*B Doc.77-26827 Filed 9-2-77;8:45 am]
SUPPLEMENTARY INFORMATION:
The amendments below institute certain
address changes for reports and appli-
cations required from operators of new
sources. EPA has delegated to the State
of Montana authority to review new and
modified sources. The delegated author-
ity includes the review under 40 CFR
Part 60 for the standards of performance
for new stationary sources and review
under 40 CFR Part 61 for national emis-
sion standards for hazardous air
pollutants.
A Notice announcing the delegation of
authority is published today in the FED-
ERAL REGISTER (42 PR. 44573). The amend-
ments provide that all reports, requests,
applications, submlttals, and communi-
cations previously required for the dele-
gated reviews will now be sent to the
Montana Department of Health and En-
vironmental Sciences Instead of EPA's
Region vm.
The Regional Administrator finds good
cause for foregoing prior public notice
and for making this rulemaking effective
immediately in that it is an adminis-
trative change and not one of substan-
tive content. No additional substantive
burdens are imposed on the parties af-
fected. The delegation which is reflected
by this administrative amendment was
effective on May 18, 1977, and it serves
no purpose to delay the technical change
of this addition of the State address to
the Code of Federal Regulations.
This rulemaking is effective immedi-
ately, and is issued under the authority
of sections 111 and 112 of the Clean Air
FEDERAL REGISTER, VOL. 42. NO. 172
TUESDAY, SEPTEMBER 6, 1977
71
Titte 40Protection of Environment
CHAPTER IENVIRONMENTAL
PROTECTION AGENCY
SUBCHAPTER CAIR PROGRAMS
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Applicability Dates; Correction
AGENCY: Environmental Protection
Agency.
ACTION: Correction.
SUMMARY: This document correcw
the final rule that appeared at page
37935 in the FEDERAL REGISTER of Mon-
day. July 25, 1977 (FR Doc. 77-21230).
EFFECTIVE DATE: September 7, 1977.
FOR FURTHER INFORMATION CON-
TACT:
Don R. Goodwin, Emission Standards
and Engineering Division, Environ
mental Protection Agency, Research
Triangle Park, N.C. 27711, telephone
No. 919-541-5271.
Dated: August 31,1977.
EDWARD F. TDERK,
Acting Assistant Administrator,
for Air and Waste Management.
In FR Doc. 77-21230 appearing at page
37935 in the FEDERAL REGISTER of Mon-
day, July 25, 1977, the following correc-
tions are made to §§ 60.250(b) and 60.270
(b) on page 37938:
1. The applicability date in i 60.250(b)
is corrected to October 24,1974.
2. The applicability date in § 60.270 (b)
is corrected to October 21,1974.
(Sec. Ill, 301 (a) of the Clean Air Act as
amended (42 D.S.C. 1857C-6, 1857g(a)).)
[PR Doc.77-26023 Filed 9-6-77;8:45 am]
FEDERAL REGISTER, VOL 42, NO. 173
WEDNESDAY, SEPTEMBER 7, 1977
IV-206
-------
72
Tttte 40Protection of Environment
CHAPTER IENVIRONMENTAL
PROTECTION AGENCY
(PRL 7BO-4J
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Delegation of Authority to State of
Wyoming
AGENCY: Environmental Protection
Agency.
ACTION: Final rule.
SUMMARY: This rule will change the
address to which reports and applica-
tions must be sent by owners and opera-
ton of new and modified sources in the
State of Wyoming. The address change
Is the result of delegation of authority
to the State of Wyoming for New Source
Performance Standards (40 CFR Part
60).
ADDRESS: Any questions or comments
should be sent to Director, Enforcement
Division, Environmental Protection
Agency, 1860 Lincoln Street, Denver,
Colo. 80295.
FOR FURTHER INFORMATION CON-
TACT:
Mr. Irwin L. Dickstein, 303-837-3868.
SUPPLEMENTARY INFORMATION:
The amendments below institute cer-
tain address changes for reports and
applications required from operators of
new and modified sources, EPA has del-
egated to the State of Wyoming au-
thority to review new and modified
aources. The delegated authority in-
cludes the review under 40 CFR Part 60
for the standards of performance for
new stationary sources.
A notice announcing the delegation of
authority Is published today in the FED-
ERAL REGISTER (Notices Section). The
amendments now provide that all re-
ports, requests, applications, submittals,
and communications previously required
for the delegated reviews will now be sent
to the Air Quality Division of the Wyo-
ming Department of Environmental
Quality instead of EPA's Region Vm.
The Regional Administrator finds good
cause for foregoing prior public notice
and for making this rulemaking effective
Immediately in that it is an administra-
tive change and not one of substantive
content. No additional substantive bur-
dens are imposed on the parties affected.
The delegation which is reflected by this
administrative amendment was effective
on August 2, 1977, and it serves no pur-
pose to delay the technical change of
this addition of the State address to the
Code of Federal Regulations.
(Sec. Ill," Clean Air Act, as amended (42
TJ.S.C. 1857, 18570-6, 6, 7. 1857g).
Dated: August 25.1977.
JOHN A. GREEN,
Regional Administrator.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amended
as follows:
1. In § 60.4 paragraph (b) is amended
by revising subparagraph (ZZ) to read
RULES AND REGULATIONS
as follows:
§ 60.4 Address.
*****
(b) '
(ZZ) State of Wyoming, Air Quality Dl-
vUlon of the Department of Environmental
Quality, Hathaway Building, Cheyenne, Wyo.
83002.
* »
JPB Doc.77-26905 Filed 9-14-77;8:45 am]
FEDERAL REGISTER, VOL. 42, NO. 179
THURSDAY, SEPTEMBER 15, 1977
IV-207
-------
RULES AND REGULATIONS
73
Title 40Protection of Environment
[PRL 770-7]
CHAPTER [ENVIRONMENTAL
PROTECTION AGENCY
SUBCHAPTER CAIR PROGRAMS
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Emission Guideline for Sulfuric Acid Mist
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Final rule.
SUMMARY: This action establishes
emission guidelines and times for com-
pliance for control of sulfuric acid mist
emissions from existing sulfuric acid
plants. Standards of performance have
been issued for emissions of sulfuric acid
mist, a designated pollutant, from new,
modified, and reconstructed sulfuric acid
plants. The Clean Air Act requires States
to control emissions of designated pollut-
ants from existing sources, and this
rulemaking initiates the States' action
and provides them guidelines for what
will be acceptable by EPA.
DATES: State plans providing for the
control of sulfuric acid mist from exist-
ing plants are due for submission to the
Administrator on July 18, 1978. The Ad-
ministrator has four months from the
date required for submission of the plans,
or until November 18, 1978, to take ac-
tion to approve or disapprove the plan
or portions of it.
ADDRESSES: Copies of the final guide-
line document are available by writing
to the EPA Public Information Center
(PM-215), 401 M Street SW., Washing-
ton, D.C. 20460. "Final Guidance Docu-
ment: Control of Sulfuric Acid Mist
Emissions From Existing Sulfuric Acid
Production Units," June 1977, should be
specified when requesting the document.
A summary of the comments and EPA's
responses may be obtained at the same
address. Copies of the comment letters
responding to the proposed rulemaking
published in the FEDERAL REGISTER on
November 4, 1976 (41 FR 48706) are
available for public inspection and copy-
ing at the U.S. Environmental Protection
Agency, Public Information Reference
Unit (EPA Library), Room 2922, 401 M
Street SW., Washington, D.C. 20460.
FOR FURTHER INFORMATION CON-
TACT:
Don R. Goodwin, Emission Standards
and Engineering Division, Environ-
mental Protection Agency, Research
Triangle Park, N.C. 27711; telephone:
919-541-5271.
SUPPLEMENTARY INFORMATION:
On November 4, 1976 (41 FR 48706) EPA
proposed an emission guideline for sul-
furic acid mist emissions from existing
sulfuric acid plants and announced the
availability or a draft guideline docu-
ment for public comment. A discussion
of the background and comments re-
ceived follows:
BACKGROUND
Section lll(d) of the Clean Air Act
requires that "designated" pollutants
controlled under standards of perform-
ance for new stationary sources by sec-
tion lll(b) of the Act must also be con-
trolled at exsiting sources in the same
source category. New source standards of
performance for sulfuric acid mist were
promulgated December 23, 1971 (36 FR
24876). Sulfuric acid mist is considered
a designated pollutant; therefore, it
must be controlled under the provisions
of section lll(d).
As a step toward implementing the re-
quirements of section lll(d), Subpart B
of Part 60, entitled "State Plans for the
Control of Certain Pollutants From Ex-
isting Facilities," was published on No-
vember 17, 1975 (40 FR 53340).
Subpart B provides that once a stand-
ard of performance for the control of a
designated pollutant from a .new source
category is promulgated, the Administra-
tor will then publish a draft emission
guideline and guideline document ap-
plicable to the control of the same pollut-
ant from designated (existing) facilities.
For health-related pollutants, the emis-
sion guideline will be proposed and sub-
sequently be promulgated while emission
guidelines for welfare-related pollutants
will appear only in the applicable guide-
line document. Sulfuric acid mist is con-
sidered a health-related pollutant; there-
fore, the proposed emission guideline and
the announcement that the draft guide-
line document was available for public
inspection and comment appeared in the
FEDERAL REGISTER November 4,1976.
Subpart B also provides nine months
for the States to develop and submit
plans for control of the designated pol-
lutant from the date that the notice of
availability of a final guideline is pub-
lished; thus, the States will have nine
months from this date to develop their
plans for the control of sulfuric acid
mist at designated facilities within the
State.
Another provision of Subpart B is that
which provides the Administrator the
option of either approving or disapprov-
ing the State submitted plan or portions
of it within four months after the date
required for submission. If the plan or
a portion of it is disapproved, the Ad-
ministrator is required to promulgate a
new plan or a replacement of the inade-
quate portions of the plan. These and re-
lated provisions of Subpart B are essen-
tially patterned after section 110 of the
Act and 40 CFR Part 51 which sets forth
the requirements for adoption and sub-
mit 'al of State implementation plans
under section 110 of the Act.
COMMENTS AND RESPONSES
During the 60-day comment period
following the publication of the proposed
emission guidelines on November 4,1976,
eleven comment letters were received;
four from State pollution control agen-
cies, five from industry and two from
other government agencies. None of the
comments warranted a change in the
emission guideline nor did any com-
ments justify any significant changes in
the guideline document.
One commenter believed that sulfuric
acid mist is included within the defini-
tion of sulfur oxides as contained in the
Air Quality Criteria for Sulfur Oxides:
therefore, it Is subject to control as a cri-
teria pollutant under State implemen-
tation plans, section 110 of the Clean
Act, and not as a designated pollutant
under section lll(d) of the Act. EPA
does not agree with this comment. Sul-
furic acid mist is only one of a number of
related compounds noted in the criteria
document defining sulfur oxides. Sulfuric
acid mist is not listed and regulated in
and of itsel*. In addition, although some
designated pollutants controlled under
section lll(d) may occur in particulate
a? well as gaseous form and thus may
be controlled to some degree under State
implementation plan regulations requir-
ing control of particulate matter, specific
rather than incidental control of such
pollutants is required under section
lll(d).
Several commenters were concerned
that the emission guideline was not based
on the health and welfare effects of sul-
furic acid mist or on such other factors
as plant site location and the hazard of
cumulative impacts where emissions
from other sources interacted. Another
commenter noted that since the toxico-
logical effects of exposure to sulfuric acid
mist are a function of concentration and
time, a daily maximum time-weighted
average concentration limitation should
be considered.
These comments appear to be based on
a misunderstanding of the intent and
purpose of section lll(d) of the Act. In
the preamble to the section lll(d) pro-
cedural regulation (40 FR 53340), it is
stated that section lll(d) requires emis-
sion controls based on the general prin-
ciple of the application of the best ade-
quately demonstrated control technology,
considering costs, rather than controls
based directly on health or welfare effects
or on other factors such as those men-
tioned in the comments. Section lll(b)
(1)(A) of the Act requires the Admin-
istrator to list categories of sources once
it is determined that they may con-
tribute to the endangerment of public
health or welfare. While this is a pre-
requisite for the development of stand-
ards under section lll(d), the emission
guideline is technology-based rather
than tied specifically to protection of
health or welfare. The States, in devel-
oping regulations for the control of sul-
furic acid mist, have the prerogative
under 40 CFR 60.24 (f) and (g) to de-
velop standards which may be based on
health or welfare considerations or on
any other relevant factors.
Some of the comments addressed the
stringency of the emission guideline. One
commenter considered the emission
guideline inflexible to the point where its
application will be too stringent in some
areas and inadequate in others. Another
commenter thought the guideline docu-
ment indicated that facilities using ele-
mental sulfur as feedstock can meet more
rigid emission standards and that the
KDERAl REGISTER, VOL. 42, NO. 201TUESDAY, OCTOBER 18, 1977
IV-208
-------
RULES AND REGULATIONS
emission guidelines should include more
stringent standards for these facilities.
EPA has provided a great deal of
flexibility in developing emission stand-
ards for the control of designated pollut-
ants under Subpart B of Part 60. Specifi-
cally, 40 CFR 60.24(b) provides that
nothing under Subpart B precludes any
State from adopting or enforcing more
stringent emission standards than those
specified in the guideline document. On
the other hand, 40 CFR Part 60.24 (f)
provides that States, "on a case-by-case
basis for particular designated facilities,
or classes of facilities * * * may provide
for the application of less stringent emis-
sion standards than those otherwise re-
quired * * *" provided certain conditions
are demonstrated by the State. The con-
ditions include unreasonable cost of con-
trol resulting from plant age, location or
basic process design, physical impossi-
bility of installing necessary control
equipment, and other factors specific to
the facility that make the application of
a less stringent standard significantly
more reasonable. To include more strin-
gent standards for facilities using ele-
mental sulfur as feedstock would cause
an unacceptable economic burden for
those sources which have already in-
stalled efficient emission control equip-
ment to meet a State regulation. To re-
quire these sources to retrofit additional
emission control equipment to meet a
more stringent standard would be in-
equitable.
MISCELLANEOUS
NOTE.The Environmental Protection
Agency has determined that this document
does not contain a major proposal requiring
preparation of an Economic Impact Analysis
under Executive Order 11821 and 11049 and
OMB Circular A-107.
Dated: September 22, 1977.
DOUGLAS M. COSTLE,
Administrator.
Part 60 of Chapter I of Title 40 of the
Code of Federal Regulations is amended
by adding Subpart C as follows:
Subpart CEmission Guidelines and
Compliance Times
Sec.
60.30 Scope.
60.31 Definitions
60.32 Designated facilities.
60.33 Emission guidelines.
60.34 Compliance times.
AUTHORITY: Sections lll(d), 301 (a) of the
Clean Air Act as amended (42 U.S.C. 1857C-6
and 1857g(a)), and additional authority as
noted below.
Subpart CEmission Guidelines and
Compliance Times
§ 60.30 Scope.
This subpart contains emission guide-
lines and compliance times for the con-
trol of certain designated pollutants from
certain designated facilities in accord-
ance with section lll(d) of the Act and
Subpart B.
§ 60.31 Definitions.
Terms used but not defined in this
subpart have the meaning given them
in the Act and in Subparts A and B of
this part.
§ 60.32 Designated facilities.
(a) Sulfuric acid production units.
The designated facility to which §§ 60.33
(a) and 60.34(a) apply is each existing
"sulfuric acid production unit" as de-
fined in § 60.81 (a) of Subpart H.
§ 60.33 Emission guidelines.
(a) Sulfuric acid production units.
The emission guideline for designated
facilities is 0.25 gram sulfuric acid mist
(as measured by Reference Method 8, of
Appendix A) per kilogram of sulfuric
acid produced (0.5 Ib/ton), the produ«-
tion being expressed as 100 percent
§ 60.34 Compliance times.
(a) Sulfuric acid production units.
Planning, awarding of contracts, and
installation of equipment capable of
attaining the level of the emission guide-
line established under § 60.33 (a) can be
accomplished within 17 months after the
effective date of a State emission stand-
ard for sulfuric acid mist.
[FR Doc.77-30466 Filed 10-17-77;8:46 amj
FEDERAL REGISTER, VOL. 41, NO. 201
TUESDAY, OCTOBER 18, 1977
74 [FRL 793-4]
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Amendments to General Provisions and
Copper Smelter Standards
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Final rule.
SUMMARY: This rule clarifies that ex-
cess emissions during periods of startup,
shutdown, and malfunction are not con-
sidered a violation of a standard. This
rule also clarifies that excess emissions
for no more than 1.5 percent of the time
during a quarter will not be considered
indicative of a potential violation of the
new source performance standard for
primary copper smelters provided the af-
fected facility and the air pollution con-
trol equipment are maintained and op-
erated consistent with good air pollution
control practice.
EFFECTIVE DATE: November 1, 1977.
FOR FURTHER INFORMATION CON-
TACT:
Don R. Goodwin, Emission Standards
and Engineering Division, Environ-
mental Protection Agency, Research
Triangle Park, North Carolina 27711.
SUPPLEMENTARY INFORMATION:
BACKGROUND
EPA promulgated standards of per-
formance for primary copper, rinc and
lead smelters on January 15, 1976. On
March 5, 1976, Kennecott Copper Cor-
poration filed a petition with the United
States Court of Appeals for the District
of Columbia Circuit requesting that EPA
reconsider the standards for copper
smelters. EPA proposed to make two
clarifying amendments to the standards,
and Kennecott agreed to withdraw its
court challenge providing these amend-
ments were made. The amendments
being made are in response to the follow-
ing two issues raised in the Kennecott
court appeal:
(1) The standards of performance fail
to provide for excessive emissions during
periods of startup, shutdown, and mal-
function.
(2) The standards of performance
prescribe averaging times too short to ac-
commodate the normal fluctuations in
sulfur dioxide emissions inherent in
smelting operations.
EXCESS EMISSIONS DURING STARTUP,
SHUTDOWN AND MALFUNCTION
For all sources covered under 40 CFR
Part 60, compliance with numerical emis-
sion limits must be determined through
performance tests. 40 CFR 60.8(c) ex-
empts periods of startup, shutdown, and
malfunction from performance tests. By
implication this means compliance with
numerical emission limits cannot be de-
termined during periods of startup, shut-
down, and malfunction. EPA and Kenne-
cott have agreed that for clarification
IV-209
-------
RULES AND REGULATIONS
purposes this should be specifically stated
In the regulation. Therefore, an amend-
ment to this effect Is being made in 40
CPR 60.8(c).
This exemption from compliance with
numerical emission limits during startup,
shutdown and malfunction, however,
does not exempt the owner or operator
from compliance with the requirements
of 40 CPR 60.11 (d) which says: "At all
times, Including periods of startup, shut-
down, and malfunction, owners and op-
erators shall, to the extent practicable,
maintain and operate any affected fa-
cility including associated air pollution
control equipment in a manner con-
sistent with good air pollution control
practice for minimizing emissions."
AVERAGING TIMES
Kennecott alleged that a six-hour
averaging time is not long enough to
average out periods of excessive emis-
sions of sulfur dioxide which normally
occur at smelters equipped with best con-
trol technology. According to Kennecott,
the six-hour averaging period simply
does not mask emission variations caused
by normal fluctuations in gas strengths
and volumes.
A performance test to determine com-
pliance with the numerical emission
limit included in the standard of per-
formance consists of the arithmetic
average of three consecutive six-hour
emission tests. EPA's analysis of the
emission data presented In the back-
ground document ("Background Infor-
mation for New Source Performance
Standards: Primary Copper, Zinc, and
Lead Smelters," October 1974) support-
ing the standards of performance for
copper smelters indicates that the pos-
sibility of a performance test exceeding
the standard of performance under nor-
mal conditions is extremely low, less than
0.15 percent. This same analysis, how-
ever, indicates that the possibility of
emissions averaged over a single six-
hour period exceeding the numerical
emission limit included in the standard
of performance during normal operation
is about 1.5 percent. To reconcile this
situation with the excess emission re-
porting requirements, which currently
require all six-hour periods in excess of
the level of the sulfur dioxide standard
to be reported as excess emissions, 40
CFR 60.165 is being amended to provide
that if emissions exceed the level of the
standard for no more than 1.5 percent
of the six-hour averaging periods during
a quarter, they will not be considered
indicative of potential violation of 40
CPR 60.1Kd); i.e., indicative of improper
maintenance or operation. This exemp-
tion applies, however, only if the owner
or operator maintains and operates the
affected facility and air pollution con-
trol equipment in a manner consistent
with good air pollution control practice
for minimizing emissions during these
periods. This ensures that the control
equipment will be operated and emis-
sions will be minimized during this time.
Excess emissions during periods of start-
up, shutdown, and malfunction are not
considered part of the 1.5 percent.
MISCELLANEOUS
The Administrator finds that good
cause exists for omitting prior notice and
public comment on these amendments
and for making them immediately effec-
tive because they simply clarify the exist-
ing regulations and impose no additional
substantive requirements.
NOTS.The EPA has determined that thU
document does not contain a major proposal
requiring preparation of an Economic Impact
Statement under Executive Orders 11821 and
11949, and OMB Circular Rr-107.
Dated: October 25, 1977.
DOUGLAS M. COSTLE,
Administrator.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amended
as follows:
1. In § 60.8, paragraph (c) is amended
to read as follows:
§ 60.8 Performance tests.
*****
(c) Performance tests shall be con-
ducted under such conditions as the Ad-
ministrator shall specify to the plant
operator based on representative per-
formance of the affected facility. The
owner or operator shall make available
to the Administrator such records as may
be necessary to determine the conditions
of the performance tests. Operations
during periods of startup, shutdown, and
malfunction shall not constitute repre-
sentative conditions for the purpose of a
performance test nor shall emissions in
excess of the level of the applicable emis-
sion limit during periods of 'startup,
shutdown, and malfunction be con-
sidered a violation of the applicable
emission limit unless otherwise specified
In the applicable standard.
2. In §60.165, paragraph (d)(2) is
amended to read as follows:
§ 60.165 Monitoring of operation*.
*****
(d) * * »
(2) Sulfur dioxide. All six-hour periods
during which the average emissions of
sulfur dioxide, as measured by the con-
tinuous monitoring system installed
under § 60.163, exceed the level of the
standard. The Administrator will not
consider emissions in excess of the level
of the standard for less than or equal to
1.5 percent of the six-hour periods dur-
ing the quarter as indicative of a poten-
tial violation of § 60.1 l(d) provided the
affected facility, including air pollution
control equipment, is maintained and
operated in a manner consistent with
good air pollution control practice for
minimizing emissions during these pe-
riods. Emissions in excess of the level of
the standard during periods of startup,
shutdown, and malfunction are not to be
included within the 1.5 percent.
(Sees. Ill, 114, and 301(a) of the Clean Air
Act as amended (42 U.S.C. 1857C-6 1857C-9
1857g(a».)
|PB Doc.77-31508 Filed 10-31-77;8:45 am]
FEDERAL REGISTER, VOL. 42, NO. 210
TUESDAY, NOVEMIIR 1, 1977
IV-210
-------
RULES AND REGULATIONS
75 (PRL 781-7]
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Amendment to Subpart O: Sewage Sludge
Incinerators
AGENCY: Environmental Protection
Agency.
ACTION: Final rule.
SUMMARY: This rule revises the ap-
plicability of the standard of perform-
ance for sewage sludge incinerators to
cover any incinerator that burns wastes
containing more than 10 percent sewage
sludge (dry basis) produced by munici-
pal sewage treatment plants, or charges
more than 1000 kg (2205 Ib) per day
municipal sewage sludge (dry basis). The
State of Alaska requested that EPA re-
vise the standard because incinerators
small enough to meet the needs of small
communities in Alaska and comply with
the particulate matter standard are too
costly, and land disposal is not feasible
in areas with permafrost and high water
tables. The intended effect of the revi-
sion is to exempt from the standard
small incinerators for the combined dis-
posal of municipal wastes and sewage
sludge when land disposal, which is
normally a cheaper and preferable alter-
native, is infeasible due to permafrost,
high water tables, or other conditions.
DATES: This amendment is effective
November 10, 1977, as required by
i 11Kb) (1) (B) of the Clean Air" Act as
amended.
FOR FURTHER INFORMATION CON-
TACT:
Don R. Goodwin, Emission Standards
and Engineering Division, Environ-
mental Protection Agency, Research
Triangle Park, North Carolina 27711,
telephone 919-541-5271.
SUPPLEMENTARY INFORMATION:
On January 26, 1977 (42 PR 4863), EPA
published a proposed amendment to
Subpart 0 of 40 CFR Part 60. An error
in that proposal necessitated a correc-
tion notice that was published on Feb-
ruary 18, 1977 (42 FR 10019). The pro-
posed amendment exempted any sewage
sludge incinerator located at a municipal
waste treatment plant having a dry
sludge capacity below 140 kg/hr (300
Ib/hr), and where it would not be
feasible to dispose of the sludge by land
application or in a sanitary landfill be-
cause of freezing conditions. Prompting
this amendment was a request by the
State of Alaska which noted (1) the
limited availability of small sludge in-
cinerators which can meet the particu-
late matter standard, and (2) the dif-
ficulty of using landfills as an alternative
means of sewage sludge disposal in some
Alaskan communities because of perma-
frost conditions.
During the comment period on that
proposal, four comment letters were re-
ceived. Copies of these letters and a sum-
mary of the comments with EPA's
responses are available for public in-
spection and copying at the EPA Public
Information Reference Unit, Room 2922
(EPA Library), 401 M Street SW., Wash-
ington, D.C. In addition, copies of the
comment summary and Agency re-
sponses may be obtained upon written
request from the Public Information
Center (PM-215), Environmental Pro-
tection Agency, 401 M Street SW.,
Washington. D.C. 20460 (specify Public
Comment Summary: Amendment to
Standards of performance for Sewage
Treatment Plants).
One commenter requested that indus-
trial sludge incineration also be ex-
empted by this revision. Only incinera-
tors which burn sludge produced by mu-
nicipal sewage treatment plants are cov-
ered by Subpart O. Incineration of in-
dustrial sludges are not covered because
they may involve special metal, toxic and
radioactive waste problems which were
not addressed by the original study for
developing the standard.
Three other commenters questioned
the applicability of the proposed amend-
ment. One questioned the need for the
proposed exemption, arguing that small
incinerators with control devices suffi-
cient to meet the existing particulate
emission standard of 0.65 g/kg dry sludge
input are commercially available and
should be used. Two others recommended
wording to broaden the proposed exemp-
tion. They suggested that the amend-
ment as proposed is too restrictive, con-
sidering the or. ditioi ' faced by small
communities ir Alaska One noted that
high water-table levels severely limit
land disposal of sludge in many areas.
The other n.arle a sun: ar comment but
attributed the problerr to high rainfall
as well.
Based upon these comments, EPA re-
evaluated the need for the proposed ex-
emption. EPA recognizes that at least
one type of incinerator (the fluidized-
bed type) can be constructed in size cat-
egories of less than 140 kg/hr (300 Ib/hr)
and with emission control equipment ca-
pable of achieving the existing standard.
However, separate sludge disposal by an
incinerator dedicated exclusively to sew-
age sludge is unduly costly for a small
community. This conclusion is based on
data contained in two EPA publications:
A Guide to the Selection of Cost-Effec-
tive Wastewater Treatment Systems
(EPA-430/9-75-002), and Municipal
Sludge Management: EPA Construction
Grants ProgramAn Overview of the
Sludge Management Situation (EPA-
430/9-76-009). Sludge incineration costs,
especially those for operation and main-
tenance, were compared for sewage
treatment plants of 1 and 10 million gal-
lons per day (mgd) capacity. Costs for a
1 mgd plant (about 1000 kg of dry sludge
per day) were 100 to 300 percent higher
than those for a 10 mgd facility. A small,
remote community which already incin-
erates its other municipal wastes would
bear the heaviest burden if forced to in-
cinerate its sewage sludge separately.
In most instances, neither municipal
waste nor sewage sludge incinerators are
constructed because land disposal is a
more cost-effective alternative. The co-
Incineration of sewage sludge with solid
waste should be a cost-effective and
energy-efficient disposal alternative
whenever land disposal options are not
reasonably available. Since high water
table levels, high annual precipitation,
freezing conditions, and other factor*
limit or preclude the land application or
sanitary landfilling of sludge, EPA has
decided to broaden the exemption. Only
freezing conditions were considered in
the proposed exemption. However, an ex-
emption based on these additional fac-
tors would be difficult to enforce due to
climatic variability.
In order to make the exemption suffi-
ciently broad and readily enforceable,
EPA has decided to exempt incinerators
that burn not more than 1000 kg per day
of sewage sludge from municipal sewage
treatment plants provided that the sew-
age sludge (dry basis) does not comprise,
by weight, more than 10 percent of the
total waste burned. The exemption pro-
vides relief only when sewage sludge is
co-incinerated with municipal wastes,
since any Incinerator combusting more
than 10 percent sewage sludge is affected
by the emission standard regardless of
the amount of sludge combusted. This
approach, Is based principally on the eco-
nomics of sewage waste disposal and ap-
plies to any small community faced with
very difficult land disposal conditions. It
allows disposal of small quantities of
sewage sludge in incinerators primarily
combusting municipal refuse.
Currently, sludge incineration for
small communities is 50 to 100 percent
more costly per ton of dry sludge than
land application or sanitary landfilling.
Even though EPA is proposing criteria
for landfill design and operation, the
costs of incineration are expected to re-
main significantly higher. Thus, it is ex-
pected that this exemption will not cause
a shift to incineration, but will only pro-
IV-211
-------
vide relief in areas where land disposal
is either infeasible or very costly.
The purpose of the amendment is to
relieve small communities (<9,000 pop-
ulation) of the burden of constructing
separate incinerators for municipal
wastes and sewage sludge in areas where
land disposal Is not feasible. Co-incinera-
tion of sewage sludge with solid wastes
is less costly than separate sludge in-
cineration and provides an energy bene-
fit in lower auxiliary fuel consumption.
Without this amendment, any co-incin-
eration facility would have been consid-
ered a sludge incinerator under Subpart
0.
Since sludge Incineration costs decline
as the quantities disposed of Increase.
this amendment limits the exemption to
co-incineration units burning not more
than 1000 kg (2205 Ib) dry sludge per
day. At an average generation rate of
0.11 kg (0.2.5 Ib) dry sludge per person
per day, the 1000 kg limit represents a
population of approximately 9,000 per-
sons. The 10 percent sludge allowance in
such co-incineration is based on the fact
that an average community generates
about 14 times as much solid waste per
person as dry sludge. Thus the 10 percent
allowance should easily permit a small
community to co-incinerate all its sludge
and solid waste in one facility.
This amendment does not affect the
applicability of the National Emission
Standard for Mercury under 40 CFR Part
61. However, significant mercury wastes
are usually not found in sewage sludge
from small communities, but are more
commonly found in metropolitan wastes
from industrial activity.
It should be noted that standards of
performance for new sources established
under section 111 of the Clean Air Act
reflect emission limits achievable with
the best adequately demonstrated sys-
tems of emission reduction considering
the cost of such systems. State Imple-
mentation plans (SIPs) approved or pro-
mulgated under section 110 of the Act,
on the other hand, must provide for
the attainment and maintenance of na-
tional ambient air 'quality standards
(NAAQS) designed to protect public
health and welfare. For that purpose
SIPs must in some cases require greater
emission reductions than those required
by standards of performance for new
sources.
States are free under section 116 of
the Act to establish even more stringent
emission limits than those necessary to
attain or maintain the NAAQS under
section 110 or those for new sources es-
tablished under section 111. Thus, new
sources may In some na-?es be subject
to limitations more stri,,jrnt than EFA's
standards of performa. e under sert'.on
111, and prospective owners and opera-
tors of new sources sh< ,-\i be aware of
this possibility In planing for such
facilities.
NOTE.The "Environmental Protection
Agency has determined that this document
does not contain a malor prooosal requiring
preparation of an Economic Impact Analysis
RULES AND REGULATIONS
under Executive Order* 11821 and 11949 and
OMB Circular A-107.
Dated: November 3,1977.
DOUGLAS M. COSTLE,
Administrator.
In 40 CFR Part 60, Subpart O Is
amended by revising § 60.150 and { 60.-
153 as follows:
§ 60.150 Applicability and designation
of affected facility.
(a) The affected facility is each in-
cinerator that combusts wastes contain-
ing more than 10 percent sewage sludge
(dry basis) produced by municipal sew-
age treatment plants, or each incinerator
that charges more than 1000 kg (2205
Ib) per day municipal sewage sludge (dry
basis).
(b) Any facility under paragraph (a)
of this section that commences construc-
tion or modification after June 11, 1973,
is subject to the requirements of this
subpart.
§60.153 Monitoring of operations.
(a) The owner or operator of any
sludge incinerator subject to the provi-
sions of this subpart shall:
(1) Install, calibrate, maintain, and
operate a flow measuring device which
can be used to determine either the mass
or volume of sludge charged to the in-
cinerator. The flow measuring device
shall have 'an accuracy of ±5 percent
over its operating range.
(2) Provide access to the sludge
charged so that a well mixed representa-
tive grab sample of the sludge can be ob-
tained.
(3) Install, calibrate, maintain, and
operate a weighing device for determin-
ing the mass of any municipal solid
waste charged to the incinerator when
sewage sludge and municipal solid waste
are incinerated together. The weighing
device shall have an accuracy of ±5 per-
cent over its operating range.
(Sections 111, 114, 301 (») of the Clean Air
Act as amended [42 D.S.C. 1857C-6, 1857c-9,
1887g(a)].)
(PE Doc.77-32667 Filed ll-9-77;8'45 am)
FEDERAL REGISTER, VOL. 42, NO. 217
THURSDAY, NOVEMBER 10, 1977
76
Title 40Protection of Environment
CHAPTER IENVIRONMENTAL
PROTECTION AGENCY
SUBCHAPTER CAIR PROGRAMS
[FRL 803-8]
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Opacity Provisions for Fossil-Fuel-Fired
Steam Generators
AGENCY: Environmental Protection
Agency (EPA).'
ACTION: Final rule.
SUMMARY: This rule revises the format
of the opacity standard and establishes
reporting requirements for excess emis-
sions of opacity for fossil-fuel-fired
steam generators. This action is needed
to make the standard and reporting re-
quirements conform to changes in the
Reference Method for determining opac-
ity which were promulgated on Novem-
ber 12, 1974, (39 FR 39872). The in-
tended effect, is to limit opacity of emis-
sions in order to insure proper operation
and maintenance of facilities subject to
standards of performance.
EFFECTIVE DATE: This rule is effective
on December 5, 1977.
ADDRESSES: A summary of the public
comments received on the September 10,
1975 (40 FR 42028), proposed rule with
EPA's responses is available for public
inspection and copying at the EPA Pub-
lic Information Reference Unit (EPA
Library), room 2922, 401 M Street SW.,
Washington, D.C. 20460. In addition,
copies of the comment summary may be
obtained by writing to the EPA Public
Information Center (PM-215), Washing-
ton, D.C. 20460 (specify: "Public Com-
ment Summary: Steam Generator Opac-
ity Exception (40 FR 42028)").
FOR FURTHER INFORMATION CON-
TACT:
Don R. Goodwin, Director, Emission
Standards and Engineering Division
(MD-13), Environmental Protection
Agency, Research Triangle Park, N.C.
27711, telephone: 919-541-5271.
SUPPLEMENTARY INFORMATION:
The standards of performance for fossil-
fuel-fired steam generators as promul-
gated under Subpart D of Part 60 in De-
cember 23, 1971, (36 FR 24876) allow
emissions up to 20 percent opacity, ex-
cept 40 percent is allowed for two minutes
in any hour. On October 15, 1973, (38
FR 28564) a provision was added to Sub-
part D which required reporting as'excess
emissions all hourly periods during
which there were three or more one-
minute periods when average opacity
exceeds 20 percent. Changes to the opa-
city provisions of Subpart A, General
Provisions, and to Reference Method 9,
Visual Determination of the Opacity of
Emissions from Stationary Sources, were
promulgated on November 12, 1974 (39
IV-212
-------
RULES AND REGULATIONS
PR 39872). Among these changes is a
requirement that opacity be determined
by averaging 24 readings taken at 15-
second intervals. Because of this change,
the Agency reassessed the opacity stand-
ard originally promulgated under Sub-
part D, and on September 10, 1975, pro-
posed amendments to the opacity stand-
ard and reporting requirements. Specifi-
cally, these amendments would have de-
leted the permissible exemption that
are not equipped with hot side precipita-
tors, but again the deletion would have
little effect and would needlessly compli-
cate the regulation.
Section 60.42(a) (2) is amended by ex-
pressing the two-minute 40 percent
opacity exception in terms of a six-min-
ute 27 percent average opacity (a
weighted average of two minutes at 40
percent opacity and four minutes at 20
percent opacity) for consistency with
Reference Method 9. This change does
not alter the stringency of the standard.
In addition, S 60.45(g) (1) which was re-
served on October 6, 1975, (40 PR 46250)
pending resolution of the opacity ex-
ception, is added to require reporting as
excess emissions any six-minute period
during which the average opacity of
emissions exceeds 20 percent opacity, ex-
cept for the one permissible six-minute
period per hour of up to 27 percent
opacity.
NOTE.The Environmental Protection
Agency has determined that this document
does not contain a major proposal requiring
preparation of an Economic Impact Analysis
under Executive Orders 11821 and 11949 and
OMB Circular A-107.
Dated: November 23,1977.
DOUGLAS M. COSTLE,
Administrator.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amended
as follows:
1. Section 60.42(2> Is revised as
follows:
§ 60.42 Standard for paniculate niatlrr.
(a) '
(2) Exhibit greater than 20 percent
opacity except for one six-minute pe-
riod per hour of not more than 27 per-
cent opacity.
(Sec. Ill, 301(a), Clean Air Act as am'ended
(42U.S.C. 7411, 7601).)
2. Section 60.45(g) (1) is added as fol-
lows:
§ 60.45 Emission and furl inoniloriiiir.
0 * * * *
(g) ' *
(1) Opacity. Excess emissions are de-
fined as any six-minute period during
which the average opacity of emissions
exceeds 20 percent opacity, except that
one six-minute average per hour of up
to 27 percent opacity need not be re-
ported.
(Sec. 111. 114, 301(a). Clean Air Act M
mended (42 UB.C.' 7411,7414, 7601).)
|PR DOC.77-34641 Filed 12-2-77,8:45 am)
KDERAL REGISTER, VOL. 41, NO. 131
MONDAY, OECEMMR 5, 1977
IV-213
-------
77
PART 60STAN HARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Delegation of Authority to the
Commonwealth of Puerto Rico
AGENCY: Environmental Protection
Agency.
ACTION: Final rule.
SUMMARY: A notice announcing EPA's
delegation of authority for the New
Source Performance Standards to the
Commonwealth of Puerto Rico is pub-
lished at page 62196 of today's FEDERAL
REGISTER. In order to reflect this delega-
tion, this document amends EPA regula-
tions to require the submission of all no-
tices, reports, and other communications
called for by the delegated regulations
to the Commonwealth of Puerto Rico
as well as to EPA.
EFFECTIVE DATE: December 9, 1977.
FOR FURTHER INFORMATION CON-
TACT:
J. Kevin Healy, Attorney, U.S. Envi-
ronmental Protection Agency, Region
n, General Enforcement Branch, En-
forcement Division, 26 Federal Plaza.
New York, N.Y. 10007, 212-264-1196.
SUPPLEMENTARY INFORMATION:
By letter dated "January 13, 1977 EPA
delegated authority to the Common-
wealth of Puerto Rico to implement and
enforce the New Source Performance
Standards. The Commonwealth accepted
this delegation by letter dated October
17,1977. A fujl account of the background
to this action and of the exact terms
of the delegation appears in the Notice
of Delegation which is also published
in today's FEDERAL REGISTER.
This rulemaking Is effective immedi-
ately, since the Administrator has found
good cause to forgo prior public notice.
This addition of the Commonwealth
of Puerto Rico address to the Code of
Federal Regulations Is a technical change
and imposes no additional substantive
burden on the parties affected.
Dated: November 22, 1977.
ECKARDT C. BECK.
Regional Administrator.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amended
as follows:
(1) In § 60.4 paragraph (b) is amended
by revising subparagraph (BBB) to read
as follows:
§ 60.4 Address.
*****
(b) * ' '
(AAA) ' *
(BBB)Commonwealth of Puerto Rico:
Commonwealth of Puerto Rico Environmen-
tal Quality Board. P.O. Box 11785, Santurce.
P.R. 00910.
[PR Doc.77-35162 Piled 12-8-77:8.45 »m|
KOfRAL REOISTtt, VOt. 42, NO. 237
FftlDAr. DECEMBER », 1*77
RULES AND REGULATIONS
78
Title 40Protection of Environment
CHAPTER IENVIRONMENTAL
PROTECTION AGENCY
[PRL 838-3)
AIR POLLUTION
Delegation of Authority to the State of
Minnesota for Prevention of Significant
Deterioration; Inspections, Monitoring
and Entry; Standards of Performance for
New Stationary Sources; and National
Emission Standards for Hazardous Air
Pollutants
AGENCY: Environmental Protection
Agency.
ACTION: Final rule.
SUMMARY: The amendment below in-
stitutes an address change for the imple-
mentation of technical and administra-
tive review and enforcement of Preven-
tion of Significant Deterioration provi-
sions; Inspections, Monitoring and Entry
provisions; Standards of Performance
for New Stationary Sources; and Nation-
al Emission Standards for Hazardous
Air Pollutants. The notice announcing
the delegation of authority Is published
elsewhere in this issue of the FEDERAL
REGISTER.
EKb'ECTiVE DATE: October 6, 1977.
ADDRESSES: This amendment provides
that all reports, requests, applications,
and communications required for the
delegated authority will no longer be
sent to the US. Environmental Protec-
tion Agency, Region V Office, but will be
sent Instead to: Minnesota Pollution
Control Agency, Division of Air Quality,
1935 West County Road B-2, Rosevllle,
Minn. 55113.
FOR FURTHER INFORMATION, CON-
TACT:
Joel Morbito, Air Programs Branch,
U.S. Environmental Protection Agency,
Region V, 230 South Dearborn St.,
Chicago, m. 60604, 312-353-2205.
SUPPLEMENTARY INFORMATION:
The Regional Administrator finds good
cause for forgoing prior public notice
and for making this rulemaking effective
immediately in that it is an adminis-
trative change and not one of substantive
content. No additional substantive bur-
dens are imposed on the parties affected.
The delegations which are granted by
this administrative amendment were
effective October 6, 1977, and it serves
no purpose to delay the technical
change of this addition of the State ad-
dress to the Code of Federal Regulations.
This rulemaking is effective immediately
and is Issued under authority of sections
101, 110, 111, 112, 114, 160-169 of the
Clean Air Act, as amended (42 UJ3.C.
7401, 7410, 7411, 7412, 7414-7470-79.
7491). Accordingly, 40 CFR Parts 52, 60
and 61 are amended as follows:
PART 52APPROVAL AND PROMULGA-
TION OF IMPLEMENTATION PLANS
Subpart YMinnesota
1. Section 52.1224 is amended by add-
ing a new paragraph (b) (5) as follows:
| 52.1224 General requirements.
* * »
(b)
(5) Authority of the Regional Admin-
istrator to make available information
and data was delegated to the Minnesota
Pollution Control Agency effective Octo-
ber 6, 1977.
2. Section 52.1234 is amended by add-
ing a new paragraph (c) as follows:
§ 52.1234 Significant deterioration of
air quality.
«!»
(c) All applications and other Infor-
mation required pursuant to ( 62.21 from
sources located in the State of Minnesota
shall be submitted to the Minnesota Pol-
lution Control Agency, Division of Air
Quality, 1935 West County Road B-2,
Rosevllle, Minn. 55113.
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY SOURCES
Subpart AGeneral Provisions
1. Section 60.4 is amended by adding
a new paragraph (b) (7) as follows:
§ 60.4 Address.
(b)
(T) Minnesota Pollution Control Agency,
DlvUlon of Air Quality, 1936 West County
Road B-2, Rosevllle, Minn. 8*113.
WOISTH, VOL 41, NO. 1
TUESDAY, JANUARY », 1*7*
IV-214
-------
79
PART 60STANDARDS Of KRFORMANCf
FOR NEW STATIONARY SOURCES
Revision of Rtfarcnc* Method 11
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Final rule.
SUMMARY: This action revises refer-
ence method 11, the method for deter-
mining the hydrogen sulfide content
of fuel gas streams. The revision is
made because EPA found that inter-
ferences resulting from the presence
of mercaptans in some refinery fuel
gases can lead to erroneous test data
when the current method is used. This
revision eliminates the problem of
mercaptan Interference and insures
the accuracy of the test data.
EFFECTIVE DATE: January 10. 1978.
ADDRESSES: Copies of the comment
letters responding to the proposed re-
vision published in the FEDERAL REGIS-
TER on May 23, 1977 (42 FR 26222),
and a summary of the comments with
EPA's responses are available for
public inspection and copying at the
U.S. Environmental Protection
Agency, Public Information Reference
Unit (EPA Library), Room 2922, 401 M
Street SW., Washington, D.C. 20460. A
copy of the summary of comments and
EPA's responses may be obtained by
writing the Emission Standards and
Engineering Division (MD-13), Envi-
ronmental Protection Agency, Re-
search Triangle Park, N.C. 27711.
When requesting this document,
"Comments and Responses Summary:
Revision of Reference Method 11,"
should be specified.
FOR FURTHER INFORMATION
CONTACT:
Don R. Goodwin, Director, Emission
Standards and Engineering Division,
Environmental Protection Agency,
Research Triangle Park, N.C. 27711,
telephone 919-541-5271.
SUPPLEMENTARY INFORMATION:
On March 8, 1974, the Environmental
Protection Agency promulgated stan-
dards of performance limiting emis-
sions of sulfur dioxide from new, modi-
fied, and reconstructed fuel gas com-
bustion devices at petroleum refiner-
ies. At the same time, reference
method 11 was promulgated as the
performance test method for measur-
ing H.S in the fuel gases. It was found
after the promulgation of method 11
that interference resulting from the
presence of mercaptans in some refin-
ery fuel gases can lead to erroneous
test results in those cases where mer-
captans were present in significant
concentrations.
RULES AND REGULATIONS
Following studies of the problems
related to reference method 11, it was
decided to revise the method and the
revision was proposed in the FEDERAL
REGISTER on May 23, 1977. The major
change in the proposed revision from
the-original promulgation was a sub-
stitution of a new absorbing solution
that is essentially free from mercap-
tan interference. New sections were
sJso added which described the range
and sensitivity, interferences, and pre-
cision and accuracy of the revision.
There were seven comments, received
concerning the proposed revision. Five
were received from industry, one from
a local environmental control agency
and one from a research'laboratory.
None of the comments warranted any
significant changes of the proposed re-
vision. The final revision differs from
the revision proposed on May 23, 1977,
in only one respect: Phenylarsine
oxide standard solution has been in-
cluded as an acceptable titrant in lieu
of sodium thiosulf ate.
The effective date of this regulation
is January 10, 1978, because section
lll(bXlXB) of the Clean Air Act pro-
vides that standards of performance or
revisions of them become effective
upon promulgation.
NOTE.The Environmental Protection
Agency has determined that this document
does not contain a major proposal requiring
preparation of an economic impact analysis
under Executive Orders 11821 and 11949
and OMB Circular A-107.
Dated: December 29, 1977.
DOUGLAS M. COSTLE,
Administrator.
Part 60 of Chapter I of Title 40 of
the Code of Federal Regulations is
amended by revising Method 11 of Ap-
pendix AReference Methods as fol-
lows:
APPENDIX A.REFERENCE METHODS
METHOD 11DETERMINATION OF HYDROGEN
SULFIDE CONTENT OF FUEL CAS STREAMS IM
PETROLEUM REFINERIES
1. Principle and applicability. 1.1 Princi-
ple. Hydrogen sulfide (H,S) is collected from
a source in a series of midget impingers and
absorbed in pH 3.0 cadmium sulfate (CdSO.)
solution to form cadmium sulfide (CdS).
The latter compound is then measured iodo-
metrically. An impinger containing hydro-
gen peroxide is included to remove SO, as
an interfering species. This method is a revi-
sion of the H,S method originally published
in the FEDERAL REGISTER. Volume 39, No. 47,
dated Friday, March 8, 1974.
1.2 Applicability. This method is applica-
ble for the determination of the hydrogen
sulfide content of fuel gas streams at petro-
leum refineries.
2. Range and sensitivity. The lower limit
of detection is approximately 8 mg/rn' (6
ppm). The maximum of the range is 740
mg/m' (520 ppm).
3. Interferences. Any compound that re-
duces iodine or oxidizes iodide ion will Inter-
fere in this procedure, provide it is collected
in the cadmium sulfate impingers. Sulfur
dioxide in concentrations of up to 2,600 mg/
m1 is eliminated by the hydrogen peroxide
solution. Thiols precipitate with hydrogen
sulfide. In the absence of HjS, only co-traces
of thiols are collected. When methane- and
ethane-thiols at a total level of 300 mg/m'
are present in addition to H,S, the results
vary from 2 percent low at an HiS concen-
tration of 400 mg/ms to 14 percent high at
an H,S concentration of 100 mg/m'. Carbon
oxysulfide at a concentration of 20 percent
does not interfere. Certain carbonyl-con-
taining compounds react with iodine and
produce recurring end points. However, ac-
etaldehyde and acetone at concentrations of
1 and 3 percent, respectively, do not inter-
fere.
Entrained hydrogen peroxide produces a
negative interference equivalent to 100 per-
cent of that of an equimolar quantity of hy-
drogen sulfide. Avoid the ejection of hydro-
gen peroxide into the cadmium sulfate im-
pingers.
4. Precision and accuracy. Collaborative
testing has shown the within-laboratory co-
efficient of variation to be 2.2 percent and
the overall coefficient of variation to be S
percent. The method bias was shown to be
4.8 percent when only H.S was present. In
the presence of the interferences cited in
section 3, the bias was positive at low H.S
concentrations and negative at higher con-
centrations. At 230 mg H,S/m', the level of
the compliance standard, the bias was +2.7
percent. Thiols had no effect on the preci-
sion.
5. Apparatus.
5.1 Sampling apparatus.
5.1.1 Sampling line. Six to 7 mm
-------
RULES AND REGULATIONS
6.1.8 Flow meter. Rotameter or equiv-
alent, to measure flow rates In the range
from 0.5 to 2 llters/min (1 to 4 cfh).
5.1.9 Graduated cylinder, 25 ml size.
5.1.10 Barometer. Mercury, aneroid, or
other barometer capable of measuring at-
mospheric pressure to within 2.5 mm Hg
(0.1 in. Hg). In many cases, the barometric
reading may be obtained Irofti a nearby Na-
tional Weather Service station, in which
cue, the station value (which is the abso-
lute barometric pressure) shall be requested
and an adjustment for elevation differences
between the weather station and the sam-
pling point shall be applied at a rate of
minus 2.5 mm Hg (0.1 in. Hg) per 30 m (100
ft) elevation increase or vice-versa for eleva-
tion decrease.
5.1.11 U-tube manometer. 0-30 cm water
column. For leak check procedure.
6.1.12 Rubber squeeze bulb. To pressur-
ise train for leak check.
5.1.13 Tee, pinchclamp, and connecting
tubing. For leak check.
6.1.14 Pump. Diaphragm pump, or equiv-
alent Insert a small surge tank between the
pump and rate meter to eliminate the pulsa-
tion effect of the diaphragm pump on the
rotameter. The pump is used for the air
purge at the end of the sample run; the
pump is not ordinarily used during sam-
pling, because fuel gas streams are usually
sufficiently pressurized to force sample gas
through the train at the required flow rate.
The pump need not be leak-free unless it is
used for sampling.
6,1.15 Needle valve or critical orifice. To
set air purge flow to 1 liter/min.
5.1.16 Tube packed with active carbon.
To filter air during purge.
6.1.17 Volumetric flask. One 1,000 ml.
6.1.18 Volumetric pipette. One 15 ml.
5.1.19 Pressure-reduction regulator. De-
pending on the sampling stream pressure, a
pressure-reduction regulator may be needed
to reduce the pressure of the gas stream en-
tering the Teflon sample line to a safe level.
6.1.20 Cold trap. If condensed water or
mine is present in the sample stream, a
corrosion-resistant cold trap shall be used
Immediately after the sample tap. The trap
shall not be operated below 0' C (32° F) to
avoid condensation of C> or C, hydrocar-
bons.
6.3 Sample recovery.
5.2.1 Sample container. Iodine flask,
(lass-stoppered: 500 ml size.
5.2.2 Pipette. 50 ml volumetric type.
5.2.3 Graduated cylinders. One each 25
and 250 ml.
6.2.4 Flasks. 125 ml, Erlenmeyer.
6.2.5 Wash bottle.
5.2.6 Volumetric flasks. Three 1,000 ml.
5.3 Analysis.
6.3.1 Flask. 500 ml glass-stoppered iodine
flask.
5.3.2 Burette. 50 ml.
6.3.3 Flask. 125 ml, Erlenmeyer.
6.3.4 Pipettes, volumetric. One 25 ml; two
each 50 and 100 ml.
5.3.5 Volumetric flasks. One 1.000 ml;
two 500 ml.
6.3.6 Graduated cylinders. One each 10
and 100 ml.
8. Reagents. Unless otherwise indicated, it
Is Intended that all reagents conform to the
specifications established by the Committee
on Analytical Reagents of the American
Chemical Society, where such specifications
are available. Otherwise, use best available
grade.
8.1 Sampling.
6.1.1 Cadmium sulfate absorbing solu-
tion. Dissolve 41 g of 3CdSO. 8H.O and 15
ml of 0.1 M sulfuric acid in a 1-liter volumet-
ric flask that contains approximately V« liter
of deionized distilled water. Dilute to
volume with deionized water. Mix thorough-
ly. pH should be 3±0.1. Add 10 drops of
Dow-Coming Antitoam B. Shake well before
use. If Antifoam B is not used, the alternate
acidified Iodine extraction procedure (sec-
tion 7.2.2) must be used.
8.1.2 ^Hydrogen peroxide, 3 percent.
Dilute 30 percent hydrogen peroxide to 3
percent as needed. Prepare fresh daily.
6.1.3 Water. Deionized, distilled to con-
form to ASTM specifications D1193-72,
Type 3. At the option of the analyst, the
KMnO, test for oxidizable organic matter
may be omitted when high concentrations
of organic matter are not expected to be
present.
6.2 Sample recovery.
8.2.1 Hydrochloric acid solution (HC1),
3M. Add 240 ml of concentrated HC1 (specif-
ic gravity 1.19) to 500 ml of deionized, dis-
tilled water in a 1-liter volumetric flask.
Dilute to 1 liter with deionized water. Mix
thoroughly.
6.2.2 Iodine solution 0.1 N. Dissolve 24 g
of potassium iodl'de (KI) in 30 ml of deion-
ized, distilled water. Add 12.7 g of resub-
limed iodine (I,) to the potassium Iodide so-
lution. Shake the mixture until the iodine is
completely dissolved. If possible, let the so-
lution stand overnight in the dark. Slowly
dilute the solution to 1 liter with deionized,
distilled water, with swirling. Filter the so-
lution if it Is cloudy. Store solution in a
brown-glass reagent bottle.
6.2.3 Standard iodine solution, 0.01 N. Pi-
pette 100.0 ml of the 0.1 N iodine solution
into a 1-liter volumetric flask and dilute to
volume with deionized, distilled water. Stan-
dardize daily as in section 8.1.1. This solu-
tion must be protected from light. Reagent
bottles and flasks must be kept tightly stop-
pered.
6.3 Analysis.
6.3.1 Sodium thiosulfate solution, stan-
dard 0.1 N. Dissolve 24.8 g of sodium thio-
sulfate pentahydrate (Na&O, 5H,O) or 15.8
t of anhydrous sodium thiosulfate (Na*S,O>>
in 1 liter of deionized, distilled water and
add 0.01 g of anhydrous sodium carbonate
(Na,CO,> and 0.4 ml of chloroform (CHC1.)
to stabilize. Mix thoroughly by shaking or
by aerating with nitrogen for approximately
15 minutes and store in a glass-stoppered,
reagent bottle. Standardize as In section
8.1.2.
6.3.2 Sodium thiosulfate solution, stan-
dard 0.01 N. Pipette 50.0 ml of the standard
0.1 N thiosulfate solution into a volumetric
flask and dilute to 500 ml with distilled
water.
NOTE.A 0.01 N phenylarsine oxide solu-
tion may be prepared Instead of 0.01 N thio-
sulfate (see section 6.3.3).
6.3.3 Phenylarsine oxide solution, stan-
dard 0.01 N. Dissolve 1.80 g of phenylarsine
oxide (C.H>AsD) In 150 ml of 0.3 N sodium
hydroxide. After settling, decant 140 ml of
this solution into 800 ml of distilled water.
Bring the solution to pH 6-7 with 6N hydro-
chloric acid and dilute to 1 liter. Standard-
ize as in section 8.1.3.
6.3.4 Starch indicator solution. Suspend
10 g of soluble starch in 100 ml of deionized,
distilled water and add 15 g of potassium
hydroxide (KOH) pellets. Stir until dis-
solved, dilute with 900 ml of deionized dis-
tilled water and let stand'for 1 hour. Neu-
tralize the alkali with concentrated hydro-
chloric acid, using an indicator paper similar
to Alkacid test ribbon, then add 2 ml of gla-
cial acetic acid as a preservative.
NOTE.Test starch indicator solution for
decomposition by titrating, with 0.01 N
iodine solution, 4 ml of starch solution in
200 ml of distilled water that contains 1 g
potassium iodide. If more than 4 drops of
the 0.01 N iodine solution are required to
obtain the blue color, a fresh solution must
be prepared.
7. procedure.
7.1 Sampling.
7.1.1 Assemble the sampling train as
shown in figure 11-1, connecting the five
midget impingers in series. Place 15 ml of 3
percent hydrogen peroxide solution in the
first impinger. Leave the second impinger
empty. Place 15 ml of the cadmium sulfate
absorbing solution in the third, fourth, and
fifth impingers. Place the impinger assem-
bly in an ice bath container and place
crushed ice around the impingers. Add more
Ice during the run, if needed.
7.1.2 Connect the rubber bulb and mano-
meter to first impinger, as shown in figure
11-1. Close the petcock on the dry gas meter
outlet. Pressurize the train to 25-cm water
pressure with the bulb and close off tubing
connected to rubber bulb. The train must
hold a 25-cm water pressure with not more
than a 1-cm drop in pressure In a 1-minute
Interval. Stopcock grease is acceptable for
sealing ground glass joints.
NOTE.This leak check procedure is op-
tional at the beginning of the sample run,
but is mandatory at the conclusion. Note
also that if the pump is used for sampling, it
is recommended (but not required) that the
pump be leak-checked separately, using a
method consistent with the leak-check pro-
cedure for diaphragm pumps outlined in
section 4.1.2 of reference method 6, 40 CFR
Part 60, Appendix A.
7.1.3 Purge the connecting line between
the sampling valve and first impinger, by
disconnecting the line from the first im-
pinger, opening the sampling valve, and al-
lowing process gas to flow through the line
for a minute or two. Then, close the sam-
pling valve and reconnect the line to the im-
pinger train. Open the petcock on the dry
gas meter outlet. Record the initial dry gas
meter reading.
7.1.4 Open the sampling valve and then
adjust the valve to obtain a rate of approxi-
mately 1 liter/min. Maintain a constant
(±10 percent) flow rate during the test.
Record the meter temperature.
7.1.5 Sample for at least 10 min. At the
end of the sampling time, close the sam-
pling valve and record the final volume and
temperature readings. Conduct a leak check
as described in Section 7.1.2 above.
7.1.6 Disconnect the impinger train from
the sampling line. Connect the charcoal
tube and the pump, as shown In figure 11-1.
Purge the train (at a rate of 1 liter/mm)
with clean ambient air fpr 15 minutes to
ensure that all H.S is removed from the hy-
drogen peroxide. For sample recovery, cap
the open ends and remove the irnpmger
train to a clean area that is awt- from
sources of heat. The area should he well
lighted, but not exposed to direct sunlight.
7.2 Sample recovery.
7.2.1 Discard the contents of the hydro-
gen peroxide impinger. Carefully rinse the
contents of the third, fourth, and fifth im-
pingers into a 500 ml iodine flask.
IV-216
-------
RULES AND REGULATIONS
DRY OAS METER RATE METER
VALVE
(FOR AIR PURGE)
PUMP
Figure 11-1. H2S sampling tram.
NOTE.The Impingers normally have only
a thin film of cadmium sulfide remaining
after a water rinse. If Antifoam B was not
used or if significant quantities of yellow
cadmium sulfide remain in the impingers,
the alternate recovery procedure described
below must be used.
7.2.2 Pipette exactly 50 ml of 0.01 N
iodine solution into a 125 ml Erlenmeyer
flask. Add 10 ml of 3 M HC1 to the solution.
Quantitatively rinse the acidified iodine
into the iodine flask. Stopper the flask im-
mediately and shake briefly.
7.2.2 (Alternate). Extract the remaining
cadmium sulfide from the third, fourth, and
fifth impingers using the acidified iodine so-
lution. Immediately after pouring the acidi-
fied iodine into an impinger, stopper it and
shake for a few moments, then transfer the
liquid to the iodine flask. Do not transfer
any rinse portion from one Impinger to an-
other; transfer it directly to the iodine flask.
Once the acidified iodine solution has been
poured into any glassware containing cadmi-
um sulfide, the container must be tightly
stoppered at all times except when adding
more solution, and this must be done as
quickly and carefully as possible. After
adding any acidified iodine solution to the
iodine flask, allow a few minutes for absorp-
tion of the H,S before adding any further
rinses. Repeat the iodine extraction until all
cadmium sulfide is removed from the im-
pingers. Extract that part of the connecting
glassware that contains visible cadmium sul-
fide.
Quantitatively rinse all of the iodine from
the impingers, connectors, and the beaker
into the iodine flask using deionized, dis-
tilled water. Stopper the flask and shake
briefly.
7.2.3 Allow the iodine flask to stand
about 30 minutes in the dark for absorption
of the H,S into the iodine, then complete
the titration analysis as in section 7.3.
NOTE.Caution! Iodine evaporates from
acidified iodine solutions. Samples to which
acidified iodine have been added may not be
stored, but must be analyzed in the time
schedule stated in section 7.2.3.
7.2.4 Prepare a blank by adding 45 ml of
cadmium sulfate absorbing solution to an
iodine flask. Pipette exactly 50 ml of 0.01 N
iodine solution into a 125-ml Erlenmeyer
flask. Add 10 ml Of 3 M Ha. Follow the
same impinger extracting and quantitative
rinsing procedure carried out in sample
analysis. Stopper the flask, shake briefly,
let stand 30 minutes In the dark, and titrate
with the samples.
NOTE.The blank must be handled by ex-
actly the same procedure as that used for
the samples.
7.3 Analysis.
NOTE.Titration analyses should be con-
ducted at the sample-cleanup area in order
to prevent loss of iodine from the sample.
Titration should never be made in direct
sunlight.
7.3.1 Using 0.01 N sodium thiosulfate so-
lution (or 0.01 N phenylarsine oxide, If ap-
plicable), rapidly titrate each sample in an
iodine flask using gentle mixing, until solu-
tion is light yellow. Add 4 ml of starch indi-
cator solution and continue titrating slowly
until the blue color just disappears. Record
VTT, the volume of sodium thiosulfate solu-
tion used, or VAT. the volume of phenylar-
sine oxide solution used (ml).
7.3.2 Titrate the blanks in the game
manner as the samples. Run blanks each
day until replicate values agree within 0.05
ml. Average the replicate titration values
which agree within 0.05 ml.
8. Calibration and standards.
8.1 Standardizations.
8.1.1 Standardize the 0.01 N iodine solu-
tion daily as follows: Pipette 25 ml of the
iodine solution into a 125 ml Erlenmeyer
flask. Add 2 ml of 3 M HC1. Titrate rapidly
with standard 0.01 N thiosulfate solution or
with 0.01 N phenylarsine oxide until the so-
lution is light yellow, using gentle mixing.
Add four drops of starch indicator solution
and continue titrating slowly until the blue
color just disappears. Record VT, the volume
of thiosulfate solution used, or V«, the
volume of phenylarsine oxide solution used
(ml). Repeat until replicate values agree
within 0.05 ml. Average the replicate titra-
tion values which agree within 0.05 ml and
calculate the exact normality of the iodine
solution using equation 9.3. Repeat the
standardization daily.
8.1.2 Standardize the 0.1 N thiosulfate
solution as follows: Oven-dry potassium di-
chromate (K,Cr,O,) at 180 to 200° C (360 to
390° P). Weigh to the nearest milligram, 2 g
of potassium dichromate. Transfer the di-
chromate to a 500 ml volumetric flask, dis-
solve in deionized, distilled water and dilute
to exactly 500 ml. In a 500 ml iodine flask,
dissolve approximately 3 g of potassium
iodide (KI) in 45 ml of deionized, distilled
water, then add 10 ml of 3 M hydrochloric
acid solution. Pipette 50 ml of the dichro-
mate solution into this mixture. Gently
swirl the solution once and allow it to stand
in the dark for 5 minutes. Dilute the solu-
tion with 100 to 200 ml of deionized distilled
water, washing down the sides of the flask
with part of the water. Titrate with 0.1 N
thiosulfate until the solution is light yellow.
Add 4 ml of starch indicator and continue ti-
trating slowly to a green end point. Record
V,, the volume of thiosulfate solution used
(ml). Repeat until replicate analyses agree
within 0.05 ml. Calculate the normality
using equation 9.1. Repeat the standardiza-
tion each week, or after each test series,
whichever time is shorter.
8.1.3 Standardize the 0.01 N Phenylar-
sine oxide (if applicable) as follows: oven
dry potassium dichromate . Weigh to the near-
est milligram, 2 g of the K,Cr,O,; transfer
the dichromate to a 500 ml volumetric flask,
dissolve in deionized, distilled water, and
dilute to exactly 500 ml. In a 500 ml iodine
flask, dissolve approximately 0.3 g of potas-
sium iodide (KI) in 45 ml of deionized, dis-
tilled water, add 10 ml of 3M hydrochloric
acid. Pipette 5 ml of the K,Cr,O, solution
Into the iodine flask. Gently swirl the con-
tents of the flask once and allow to stand In
the dark for 5 minutes. Dilute the solution
with 100 to 200 ml of deionized. distilled
water, washing down the sides of the flask
with part of the water. Titrate with 0.01 N
phenylarsine oxide until the solution U
light yellow. Add 4 ml of starch indicator
and continue titrating slowly to a green end
point. Record VA, the volume of phenylar-
sine oxide used (ml). Repeat until replicate
analyses agree within 0.05 ml. Calculate the
normality using equation 9.2. Repeat the
standardization each week or after each test
series, whichever time is shorter.
IV-217
-------
RULES AND REGULATIONS
8.2 Sampling train calibration. Calibrate
the sampling train components as follows:
8.2.1 Dry gas meter.
8.2.1.1 Initial calibration. The dry gas
meter shall be calibrated before Its Initial
use in the field. Proceed as follows: First, as-
semble the following components in series:
Drying tube, needle valve, pump, rotameter,
and dry gas meter. Then, leak-check the
system as follows: Place a vacuum gauge (at
least 760 mm Hg) at the inlet to the drying
tube and pull a vacuum of 250 mm (10 in.)
Hg; plug or pinch off the outlet of the flow
meter, and then turn off the pump. The
vacuum shall remain stable for at least 30
seconds. Carefully release the vacuum
gauge before releasing the flow meter end.
Next, calibrate the dry gas meter (at the
sampling flow rate specified by the method)
as follows: Connect an appropriately sized
wet test meter (e.g., 1 liter per revolution) to
the inlet of the drying tube. Make three in-
dependent calibration runs, using at least
five revolutions of the dry gas meter per
run. Calculate the calibration factor, Y (wet
test meter calibration volume divided by the
dry gas meter volume, both volumes adjust-
ed to the same reference temperature and
pressure), for each run, and average the re-
sults. If any Y value deviates by more than 2
percent from the average, the dry gas meter
is unacceptable for use. Otherwise, use the
average as the calibration factor for subse-
quent test runs.
8.2.1.2 Post-test calibration check. After
each field test series, conduct a calibration
check as in section 8.2.1.1. above, except tor
the following variations: (a) The leak check
Is not to be conducted, (b) three or more
revolutions of the dry gas meter may be
used, and (3) only two independent runs
need be made. If the calibration factor does
not deviate by more than 5 percent from
the initial calibration factor (determined in
section 8.2.1.1.), then the dry gas meter vol-
umes obtained during the test series are ac-
ceptable. If the calibration factor deviates
by more than 5 percent, recalibrate the dry
gas meter as in section 8.2.1.1, and for the
calculations, use the calibration factor (ini-
tial or recalibration) that yields the lower
gas volume for each test run.
8.2.2 Thermometers. Calibrate against
mercury-ln-glass thermometers.
8.2.3 Rotameter. The rotameter need not
be calibrated, but should be cleaned and
maintained according to the manufacturer's
Instruction.
8.2.4 Barometer. Calibrate against a mer-
cury barometer.
9. Calculations. Carry out calculations re-
taining at least one extra decimal figure
beyond that of the acquired data. Round off
results only after the final calculation.
9.1 Normality of the Standard (-0.1 N)
Thiosulfate Solution.
N,=2.039 W/V,
where:
W=Weight of K.Cr.O, used, g.
V,=Volume of NswS.O, solution used, ml.
N,=Normality of standard thiosulfate solu-
tion, g-eq/liter.
2.039=Conversion factor
(6 eq. I,/mole K,Cr,O,) (1,000 ml/liter)/=
(294.2 g K,Cr,O,/mole) (10 aliquot factor)
9.2 Normality of Standard Phenylarsine
Oxide Solution (if applicable).
NA=0.2039 W/VA
where:
W= Weight of K,Cr,O, used, g.
V»= Volume of C.HSA,O used, ml.
NA=Normality of standard phenylarsine
oxide solution, g = eq/liter.
0.2039 = Conversion factor
<6 eq. I,/mole K.Cr.O,) (1,000 ml/liter)/
(249.2 g K,Cr,O,/mole) (100 aliquot
factor)
9.3 Normality of Standard Iodine Solu-
tion.
where:
N,= Normality of standard Iodine solution,
g-eq/liter.
V,=Volume of standard iodine solution
used, ml.
NT = Normality of standard (~0.01 N) thio-
sulfate solution: assumed to be 0.1 N,. g-
eq/liter.
VT=Volume of thiosulfate solution used, ml.
NOTE. If phenylarsine oxide is used
Intead of thiosulfate, replace NT and VT in
Equation 9.3 with N» and V^, respectively
(see sections 8.1.1 and 8.1.3).
9.4 Dry Gas Volume. Correct the sample
volume measured by the dry gas meter to
Standard conditions (20* C) and 760 mm Hg.
where:
VBi.,ji = Volume at standard conditions of gas
sample through the dry gas meter, stan-
dard liters.
Vm = Volume of gas sample through the dry
gas meter (meter conditions), liters.
T.ui = Absolute temperature at standard con-
ditions, 293" K.
Tm = Average dry gas meter temperature, 'K.
Pb.,= Barometric pressure at the sampling
site, mm Hg.
P.ul=Absolute pressure at standard condi-
tions, 760 mm Hg.
Y=Dry gas meter calibration factor.
9.5 Concentration of H,S. Calculate the
concentration of H,S in the gas stream at
standard conditions using the following
equation:
CH« = Kt(V1TN,-VTrNT) sample-
(V.TN.-VTTNy) blank]/Vm,.,d)
where (metric units):
CH» = Concentration of HiS at standard con-
ditions. mg/dscm.
K = Conversion factor= 17.04x10'
(34.07 g/mole H.S) (1,000 liters/m') (1.000
mg/g)/ = (l,000 ml/liter) (2HJS eq/mole)
Vrr= Volume of standard Iodine solu-
tion =50.0 ml.
Ni = Normality of standard iodine solution,
g-eq/liter.
VTT= Volume of standard (-0.01 N) sodium
thiosulfate solution, ml.
NT = Normahty of standard sodium thiosul-
fate solution, g-eq/liter.
V«(.uii=Dry gas volume at standard condi-
tions, liters.
NoTE.-»If phenylarsine oxide Is used In-
stead of thiosulfate, replace N, and V,-, in
Equation 9.5 with NA and V»T. respectively
(see Sections 7.3.1 and 8.1.3).
10. Stability. The absorbing solution is
stable for at least 1 month. Sample recovery
and analysis should begin within 1 hour of
sampling to minimize oxidation of the acidi-
fied cadmium sulfide. Once iodine has been
added to the sample, the remainder of the
analysis procedure must be completed ac-
cording to sections 7.2.2 through 7.3.2.
11. Bibliography.
11.1 Determination of Hydrogen Sulfide,
Ammoniacal Cadmium Chloride Method.
API Method 772-54. In: Manual on Disposal
of Refinery Wastes, Vol. V: Sampling and
Analysis of Waste Gases and Particulate
Matter, American Petroleum Institute,
Washington, D.C., 1954.
11.2 Tentative Method of Determination
of Hydrogen Sulfide and Mercaptan Sulfur
In Natural Gas, Natural Gas Processors As-
sociation, Tulsa, Okla.. NGPA Publication
No. 2265-65, 1965.
11.3 Knoll, J. E.. and M. R. Midgett. De-
termination of Hydrogen Sulfide in Refin-
ery Fuel Gases, Environmental Monitoring
Series, Office of Research and Develop-
ment, USEPA, Research Triangle Park, N.C.
27711, EPA 600/4-77-007.
11.4 Scheill, G. W., and M. C. Sharp.
Standardization of Method 11 at a Petro-
leum Refinery, Midwest Research Institute
Draft Report for USEPA. Office of Re-
search and Development. Research Triangle
Park, N.C. 27711, EPA Contract No. 68-02-
1098, August 1976, EPA 600/4-77-088a
(Volume 1) and EPA 600/4-77-088b (Volume
2).
(Sees. 111. 114, 301, Clean Air Act as
amended (42 U.S.C. 7411, 7414, 7601).)
tFR Doc. 78-482 Filed 1-9-78; 8:45 am]
FEDERAL REGISTER, VOL 43, NO. 6
TUESDAY, JANUARY 10, 1978
IV-218
-------
80
Title 409rotection of Environment
CHAPTER IENVIRONMENTAL PROTECTION
AGENCY
SUKHAPTEt CAIR PROGRAMS
[PRL 846-7]
NEW.SOURCE REVIEW
Delegation of Aufhorify to the Commonwealth
of Kentucky
AGENCY: Environmental Protection
Agency.
ACTION: Final rule.
SUMMARY: The amendments below
institute certain address changes for
reports and applications required from
operators of new sources. EPA has del-
egated to the Commonwealth of Ken-
tucky authority to review new and
modified sources. The delegated au-
thority includes the reviews under 40
CPR Part 52 for the prevention of sig-
nificant deterioration. It also includes
the review under 40 CPR Part 60 for
the standards of performance for new
stationary sources and reviewed under
40 CFR Part 61 for national emission
standards for hazardous air pollutants.
A notice announcing the delegation of
authority was published in the Notices
section of a previous issue of the FED-
ERAL REGISTER. These amendments
provide that all reports, requests, ap-
plications, submittals, and communica-
tions previously required for the dele-
gated reviews will now be sent to the
Division of Air Pollution Control, De-
partment for Natural Resources and
Environmental Protection, West
Frankfort Office Complex, U.S. 127,
Frankfort, Ky. 40601, instead of EPA's
Region IV.
EFFECTIVE DATE: January 25, 1978.
FOR FURTHER INFORMATION,
CONTACT:
John Eagles, Air Programs Branch,
Environmental Protection Agency,
Region IV, 345 Courtland Street
NE., Atlanta. Oa. 30308, phone 404-
881-2864.
SUPPLEMENTARY INFORMATION:
The Regional Administrator finds
good cause for foregoing prior public
notice and for making this rulemaking
effective immediately in that it is an
administrative change and not one of
substantive content. No additional
substantive burdens are imposed on
the parties affected. The delegation
which is reflected by this administra-
tive amendment was effective on April
12, 1977, and it serves no purpose to
delay the technical change of this ad-
dition of the state address to the Code
of Federal Regulations.
(Sees. 101. 110. Ill, 112, 301. Clean Air Act.
as amended. (42 0.S.C. 7401. 7410. 7411.
7412.7601).)
Dated: January 10,1978.
JOHN C. WHITE,
Regional Administrator.
RULES AND REGULATIONS
PART 52APPROVAL AND PROMULGATION
OF IMPLEMENTATION PLANS
Part 52 of Chapter I, Title 40, Code
of Federal Regulations, is amended as
follows:
Subpurt SKentucky
1. Section 52.920(0 is amended by
adding a new paragraph (cXll) as fol-
lows:
§ 52.920 Identification of plan.
(c)
(11) Letters requesting delegation of
Federal authority for the administra-
tive and technical portions of the Pre-
vention of Significant Deterioration
program were submitted on May 5 and
July 13, 1976 by the Secretary of the
Department for Natural Resources
and Environmental Protection.
2. Section 52.931 is amended by
adding a new paragraph (c) as follows:
§52.931 Significant deterioration of air
quality.
(c) All applications and other infor-
mation required pursuant to §52.21
from sources located in the Common-
wealth of Kentucky shall be submitted
to the Division of Air Pollution Con-
trol, Department for Natural Re-
sources and Environmental Protection,
West Frankfort Office Complex, U.S.
127, Frankfort, Ky. 40601, instead of
the EPA Region FV office.
PART 60STANDARDS OF PERFORMANCE
FOR NEW STATIONARY SOURCES
Part 60 of Chapter I, Title 40, Code
of Federal Regulations, is amended as
follows:
3. In §60.4, paragraph (bXS) is
added as follows:
§60.4 Address.
(S) Division of Air Pollution Control, De-
partment for Natural Resources and Envi-
ronmental Protection, U.S. 127. Frankfort,
Ky. 40601.
PART 61NATIONAL EMISSION STANDARDS
FOR HAZARDOUS AIR POLLUTANTS
Part 61 of Chapter I, Title 40. Code
of Federal Regulations, is amended as
follows:
4. In §61.04, paragraph
-------
81
Title 40Protection of Environment
CHAPTER IENVIRONMENTAL PROTECTION
AGENCY
SUBCHAPm CAll PROGRAMS
CFRL 856-1]
PART 60STANDARDS OF PERFORMANCE
FOR NEW STATIONARY SOURCES
Delegation of Authority to State of Delaware
AGENCY: Environmental Protection
Agency.
ACTION: Final rule.
SUMMARY: This document amends
regulations concerning air programs to
reflect delegation to the State of Dela-
ware of authority to implement and
enforce certain Standards of Perfor-
mance for New Stationary Sources.
EFFECTIVE DATE: February 16,
1978.
FOR FURTHER INFORMATION
CONTACT:
Stephen R. Wassersug, Director, En-
forcement Division, Environmental
Protection Agency, Region III, 6th
and Walnut Streets, Philadelphia,
Pa. 19106, 215-597-4171.
SUPPLEMENTARY INFORMATION:
I. BACKGROUND
On September 7, 1977, the State of
Delaware requested delegation of au-
thority to implement and enforce cer-
tain Standards of Performance for
New Stationary Sources. The request
was reviewed and on September 30,
1977 a letter was sent to Pierre S.
DuPont IV, Governor, State of Dela-
ware, approving the delegation and
outlining its conditions. The approval
letter specified that if Governor
DuPont or any other representatives
had any objections to the conditions
of delegation they were to respond
within ten (10) days after receipt of
the letter. As of this date, no objec-
tions have been received.
II. REGULATIONS AJTECTED BY THIS
DOCUMENT
Pursuant to the delegation of au-
thority for certain Standards of Per-
formance for New Stationary Sources
to the State of Delaware, EPA is today
amending 40 CFR 60.4, Address, to re-
flect this delegation. A Notice an-
nouncing this delegation (was) pub-
lished on February 15, 1978, In the
FEDERAL REGISTER. The amended
§60.4, which adds the address of the
Delaware Department of Natural Re-
sources and Environmental Control, to
which all reports, requests, applica-
tions, submittals, and communications
to the Administrator pursuant to this
part must also be addressed, is set
forth below.
RULES AND REGULATIONS
III. GENERAL
The Administrator finds good cause
for foregoing prior public notice and
for making this rulemaking effective
immediately in that it is an adminis-
trative change and not one of substan-
tive content. No additional substantive
burdens are imposed on the parties af-
fected. The delegation which is reflect-
ed by this administrative amendment
was effective on September 30, 1977,
and it serves no purpose to delay the
technical change of this address to the
Code of Federal Regulations.
This rulemaking is effective immedi-
ately, and is issued under the author-
ity of Section 111 of the Clean Air Act,
as amended, 42 U.S.C. 1857c-6.
Dated: January 31,1978.
JACK J. SCHRAMM,
Regional Administrator.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amend-
ed as follows:
1. In § 60.4, paragraph (b) is amend-
ed by revising subparagraph (I) to
read as follows:
f 60.4 Address.
(b)
(A)-(H) *
(I) State of Delaware (for fossil fuel-fired
steam generators; incinerators; nitric acid
plants; asphalt concrete plants; storage ves-
sels for petroleum liquids; and sewage treat-
ment plants only): Delaware Department of
Natural Resources and Environmental Con-
trol, Edward Tatnall Building, Dover, Del
19901.
[PR Doc. 78-4268 Filed 2-15-78; 8:45 am]
FEDERAL REGISTER, VOL 43, NO. 13
THURSDAY, FEMUARY, U, 1971
IV-220
-------
MIUS AND REGULATIONS
82
Title 40Prelection of Hi* Environment
CHAPTER IENVIRONMENTAL PROTECTION
AGENCY
SUBCHAPTER C-AIR PROGRAMS
tFRL 833-1]
PART 60STANDARDS OF PERFORMANCE
FOR NEW STATIONARY SOURCES
Kraft Pulp Mills
AGENCY: Environmental Protection
Agency.
ACTION: Final rule.
SUMMARY: The standards limit emis-
sions of total reduced sulfur (TRS)
and particulate matter from new,
modified, and reconstructed kraft pulp
mills. The standards implement the
Clean Air Act and are based on the
Administrator's determination that
emissions from kraft pulp mills con-
tribute significantly to air pollution.
The intended effect of these standards
is to require new, modified, and recon-
structed kraft pulp mills to use the
best demonstrated system of continu-
ous emission reduction.
EFFECTIVE DATE: February 23,
1978.
ADDRESSES: The Standards Support
and Environmental Impact Statement
(SSEIS) may be obtained from the
U.S. EPA Library (MD-35), Research
Triangle Park, N.C. 27711 (specify
"Standards Support and Environmen-
tal Impact Statement, Volume 2: Pro-
mulgated Standards of Performance
for Kraft Pulp Mills" (EPA-450/2-76-
014b)). Copies of all comment letters
received from interested persons par-
ticipating in this rulemaking are avail-
able for inspection and copying during
normal business hours at EPA's Public
Information Reference Unit, Room
2922 (EPA Library), 401 M Street SW.,
Washington, D.C.
FOR FURTHER INFORMATION
CONTACT:
Don R. Goodwin, Emission Stan-
dards and Engineering Division, En-
vironmental Protection Agency, Re-
search Triangle Park, N.C. 27711,
telephone No. 919-541-5271.
SUPPLEMENTARY INFORMATION:
On September 24, 1976 (41 FR 42012),
standards of performance were pro-
posed for new, modified, and recon-
structed kraft pulp mills under section
111 of the Clean Air Act, as amended.
The significant comments that were
received during the public comment
period have been carefully reviewed
and considered and, where determined
by the Administrator to be appropri-
ate, changes have been included in
this notice of final rulemaking.
THE STANDARDS
The standards limit emissions of par-
ticulate matter from three affected fa-
cilities at kraft pulp mills. The limits
are: 0.10 gram per dry standard cubic
meter (g/dscm) at 8 percent oxygen
for recovery furnaces, 0.10 gram per
kilogram of black liquor solids (dry
weight) (g/kg BLS) for smelt dissolv-
ing tanks, 0.15 g/dscm at 10 percent
oxygen for lime kilns when burning
gas, and 0.30 r/dscm at 10 percent
oxygen for lime kilns when burning
oil. Visible emissions from recovery
furnaces are limited to 35 percent
opacity.
The standards also limit emissions of
TRS from eight affected facilities at
kraft pulp mills. The limits are: 5 parts
per million (ppm) by volume at 10 per-
cent oxygen from the digester sys-
tems, multiple-effect evaporator sys-
tems, brown stock washer systems,
black liquor oxidation systems, and
condensate stripper systems; 5 ppm by
volume at 8 percent oxygen from
straight kraft recovery furnaces, 8
ppm by volume at 10 percent oxygen
from lime kilns; and 25 ppm by volume
at 8 percent oxygen from cross recov-
ery furnaces, which are defined as fur-
naces burning at least 7 percent neu-
tral sulfite semi-chemical (NSSC)
liquor and having a green liquor sulfi-
dity of at least 28 percent. In addition.
TRS emissions from smelt dissolving
tanks are limited to 0.0084 g/kg BLS.
The proposed TRS standard for the
lime kiln has been changed, a separate
TRS standard for cross recovery fur-
naces has been developed, and the pro-
posed format of the standards for
smelt dissolving tanks, digesters, mul-
tiple-effect evaporators, brown stock
washers, black liquor oxidation and
condensate strippers have been
changed. The TRS, particulate matter
and opacity standards for the other fa-
cilities, however, are essentially the
same as those proposed.
It should be noted that standards of
performance for new sources estab-
lished under section 111 of the Clean
Air Act reflect emission limits achiev-
able with the best adequately demon-
strated technological system of con-
tinuous emission reduction considering
the cost of achieving such emission re-
ductions and any nonair quality
health, environmental, and energy im-
pacts. State implementation plans
(SIP's) approved or promulgated
under section 110 of the Act, on the
other hand, must provide for the at-
tainment and maintenance of national
ambient air quality standards
(NAAQS) designed to protect public
health and welfare. For that purpose
SIP's must in some cases require
greater emission reductions than those
required by standards of performance
for new sources. Section 173(2) of the
Clean Air Act, as amended in 1977, re-
quires, among other things, that a new
or modified source constructed in an
area which exceeds the NAAQS must
reduce emissions to the level which re-
flects the "lowest achievable emission
rate" for such category of source,
unless the owner or operator demon-
strates that the source cannot achieve
such an emission rate. In no event can
the emission rate exceed any applica-
ble standard of performance.
A similar situation may arise when a
major emitting facility is to be con-
structed in a geographic area which
falls under the prevention of signifi-
cant deterioration of air quality provi-
sions of the Act (Part C). These provi-
sions require, among other things,
that major emitting facilities to be
constructed in such areas are to be
subject to best available control tech-
nology. The term "best available con-
trol technology" (BACT) means "an
emission limitation based on the maxi-
mum degree of reduction of each pol-
lutant subject to regulation under this
Act emitted from or which results
from any major emitting facility,
which the permitting authority, on a
case-by-case basis, taking into account
energy, environmental, and economic
impacts and other costs, determines it
achievable for such facility through
application of production processes
and available methods, systems, and
techniques, including fuel cleaning or
treatment or innovative fuel combus-
tion techniques for control of each
such pollutant. In no event shall appli-
cation of 'best available control tech-
nology' result in emissions of any pol-
lutants which will exceed the emis-
sions allowed by any applicable stan-
dard established pursuant to section
111 or 112 of this Act."
Standards of performance should
not be viewed as the ultimate in
achievable emission control and
should not preclude the imposition of
a more stringent emission standard,
where appropriate. For example, cost
of achivement may be an important
factor in determining standards of per-
formance applicable to all areas of the
country (clean as well as dirty). Costs
must be accorded far less weight in de-
termining the "lowest achievable emis-
sion rate" for new or modified sources
locating in areas violating statutorily-
mandated health and welfare stan-
dards. Although there may be emis-
sion control technology available that
can reduce emissions below those
levels required to comply with stan-
dards of performance, this technology
might not be selected as the basis of
standards of performance due to costs
associated with its use. This in no way
should preclude its use in situations
where cost is a lesser consideration,
such as determination of the "lowest
achievable emission rate."
In addition. States are free under
section 116 of the Act to establish even
more stringent emission limits than
FEDERAL REGISTER, VOL 43, NO. J7THURSDAY, KMUARY 23, 1971
IV-221
-------
RULES AND REGULATIONS
those established under section 111 or
those necessary to attain or maintain
the NAAQS under section 110. Thus,
new sources may in some cases be sub-
ject to limitations more stringent than
Standards of performance under sec-
tion 111, and prospective owners and
operators of new sources should be
aware of this possibility In planning
for such facilities.
ENVIRONMENTAL AND ECONOMIC IMPACT
The promulgated standards will
reduce partlculate emissions about 50
percent below requirements of the
Average existing State regulations.
TRS emissions will be reduced by
About 80 percent below requirements
of the average existing State regula-
tions, and this reduction will prevent
Odor problems from arising at most
new kraft pulp mills. The secondary
environmental Impacts of the promul-
gated standard will be slight increases
to water demand and wastewater
treatment requirements. The energy
Impact of the promulgated standards
will be small, increasing national
energy consumption in 1980 by the
equivalent of only 1.4 million barrels
per year of No. 6 oil. The economic
impact will be small with fifth-year
Annualized costs being estimated at
133 million.
PUBLIC PARTICIPATION
Prior to proposal of the standards,
Interested parties were advised by
public notice in the FEDERAL REGISTER
of a meeting of the National Air Pollu-
tion Control Techniques Advisory
Committee. In addition, copies of the
proposed standards and the Standards
Support and Environmental Impact
Statement (SSEIS) were dlstrublted to
members of the kraft pulp industry
And several environmental groups at
the time of proposal. The public com-
ment period extended from September
M, 1976, to March 14,1977, and result-
ed In 42 comment letters with 28 of
these letters coming from the indus-
try, 12 from various regulatory agen-
cies, and two from U.S. citizens. Sever-
al comments resulted in changes to
the proposed standards. A detailed dis-
cussion of the comments and changes
Which resulted is presented in Volume
S of the SSEIS. A summary is present-
ed here.
SIGNIFICANT COMMENTS AND CHANGES
MADE IN THE PROPOSED REGULATIONS
Most of the comment letters re-
ceived contained multiple comments.
The most significant comments and
Changes made to the proposed regula-
tions are discussed below.
IMPACTS OF THE PROPOSED STANDARDS
Several commenters expressed con-
cern about the increased energy con-
umption which would result from
compliance with proposed standards.
These commenters felt that this would
conflict with the Department of Ener-
gy's goal to reduce total energy con-
sumption in the pulp and paper indus-
try by 14 percent. This factor was con-
sidered in the analysis of the energy
Impact associated with the standards
and is discussed in the SSEIS. Al-
though the standards will increase the
difficulty of attaining this energy re-
duction goal, the 4.3 percent increase
in energy usage that will be required
by new, modified, or reconstructed by
kraft pulp mills to comply with the
standards is considered reasonable in
comparison to the benefits which will
result from the corresponding reduc-
tion in TRS and participate matter
emissions.
EMISSION CONTROL TECHNOLOGY
Most of the comments received re-
garding emission control technology
concerned the application of this tech-
nology to either lime kilns or recovery
furnaces. A few comments, however,
expressed concern with the use of the
oxygen correction factor included in
the proposed standards for both lime
kilns and recovery furnaces. These
commenters pointed out that adjust-
ing the concentration of particulate
matter and TRS emissions to 10 per-
cent oxygen for lime kilns and 8 per-
cent oxygen for recovery furnaces
only when the oxygen concentration
exceeded these values effectively
placed more stringent standards on
the most energy-efficient operators.
To ensure that the standard Is equita-
ble for all operators, these com-
menters suggested that the measured
particulate matter and TRS concen-
trations should always be adjusted to
10 percent oxygen for the lime kiln
and 8 percent oxygen for the recovery
furnace.
These comments are valid. Requir-
ing a lime kiln or recovery furnace
with a low oxygen concentration to
meet the same emission concentration
as a lime kiln or recovery furnace with
a high oxygen concentration would ef-
fectively place a more stringent emis-
sion limit on the kiln or furnace with
the low oxygen concentration. Conse-
quently, the promulgated standards
require correction of particulate
matter and TRS concentrations to 10
percent or 8 percent oxygen, as. appro-
priate, in all cases.
Lime Kilns. Numerous comments
were received on the emission control
technology for lime kilns. The main
points questioned by the commenters
were: (a) Whether caustic scrubbing is
effective in reducing TRS emissions
from lime kilns; (b) whether an over-
design of the mud washing facilities at
lime kiln E was responsible for the
lower TRS emissions observed at this
lime kiln; and (c) the adequacy of the
data base used in developing the TRS
standard.
The effectiveness of caustic scrub-
bing is substantiated by comparison of
TRS emissions during brief periods
when caustic was not being added to
the scrubber at lime kiln E, with TRS
emissions during normal operation at
lime kiln E when caustic is being
added to the scrubber. These observa-
tions clearly indicate that TRS emis-
sions would be higher if caustic was
not used in the scrubber. The ability
of caustic scrubbing to reduce TRS
emissions is also substantiated by the
experience at another kraft pulp mill
which was able to reduce TRS emis-
sions from its lime kiln from 40-50
ppm to about 20 ppm merely by
adding caustic to the scrubber. These
factors, coupled with the emission
data showing higher TRS emissions
from those lime kilns which employed
only efficient mud washing and good
lime kiln process control, clearly show
that caustic scrubbing reduces TRS
emissions.
The mud washing facilities at lime
kiln E are larger than those at other
kraft pulp mills of equivalent pulp ca-
pacity. This "overdeslgn" resulted
from initial plans of the company to
process lime mud from waste water
treatment. These waste water treat-
ment plans were later abandoned.
Since the quality or efficiency of mud
washing has been shown to be a sig-
nificant factor in reducing TRS emis-
sions from lime kilns, the larger mud
washing facilities at lime kiln E un-
doubtedly contributed to the low TRS
emissions observed at this kiln. With
the data available, however, it is not
possible to separate the relative contri-
bution of these mud washing facilities
to the low TRS emissions observed
from the relative contributions of
good process operation of the lime kiln
and caustic scrubbing.
Comments questioning the adequacy
of the data base used in developing
the standards for lime kilns were
mainly directed toward the following
points: the TRS standard was based on
only one lime kiln; sampling losses
which may have occurred during test-
ing were not taken into account; and
no lime kiln met both the TRS stan-
dard and the particulate standard.
As mentioned above, the TRS stan-
dard is based upon the emission con-
trol system installed at lime kiln E
(i.e., efficient mud washing, good lime
kiln process operation, and caustic
scrubbing). While it is true that no
other lime kiln in the United States is
currently achieving the TRS emission
levels observed at lime kiln E, there is
no other lime kiln in the United States
which is using the same emission con-
trol system that is employed at this fa-
cility. As discussed in the SSEIS. an
analysis of the various parameters in-
fluencing TRS emissions from lime
kilns indicates that this system of
emission reduction could be applied to
VOL Or NO. VTHURSDAY, FEMUARY 23, 197V
IV-222
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RULES AND REGULATIONS
11 new, modified, or reconstructed
Uaw kilns and achieve the same reduc-
tion in emissions as observed at lime
kiln E. Section 111 of the Clean Air
Act requires that "standards of perfor-
mance reflect the degree of emission
reduction achievable through the ap-
plication of the best system of con-
tinuous emission reduction which
(taking into consideration the cost of
achieving such emission reduction, and
any nonair quality health and environ-
mental Impact and energy require-
ments) the Administrator determines
ha* been adequately demonstrated for
that category of sources." Litigation of
standards of performance has resulted
m clarification of the term "adequate-
ly demonstrated." In Portland Cement
Association v. Ruckelshaus (486 F. 2d
175, D.C. Circuit. 1973). the standards
of performance were viewed by the
Court as "technology-forcing." Thus,
while a system of emission reduction
must be available for use to be consid-
ered adequately demonstrated, it does
not have to be in routine use. Howev-
er, to order to ensure that the numeri-
cal emission limit selected was consis-
tent with proper operation and main-
tenance of the emission control system
on lime kiln E, continuous monitoring
data was examined. This analysis indi-
cated that an emission source test of
nme kiln E would have found TRS
emission above 5 ppm greater than 5
percent of the time. This analysis also
Indicated, however, that it was very
unlikely that an emission source test
of lime kiln E would have found TRS
emissions above 8 ppm. Thus, it ap-
peared that the S ppm TRS numerical
emission limit - included in the pro-
posed standard for lime kilns was too
stringent. Accordingly, the numerical
emission limit included in the promul-
gated TRS standard for lime kilns has
been 'revised to 8 ppm. As discussed
later in this preamble, consistent with
this change in the numerical emission
limit, the excess emissions allowance
included within the emission monitor-
ing requirements has been eliminated.
This does not reflect a change in the
basts for the standard. The standard is
still based on the best system of emis-
sion reduction, considering costs, for
controlling TRS emissions from lime
kilns (i.e., efficient mud washing, good
lime kiln process operation, and caus-
tic scrubbing). This system, or one
equivalent to it, will still be required
to comply with the standard.
Since proposal of the standards,
sample losses of up to 20 percent
during emission source testing have
been confirmed. Although these losses
were not considered in selecting the
numerical emission limit Included in
the proposed TRS emission standard,
they have been considered in selecting
the numerical emission limit Included
in the promulgated standard. Also,
since the amount of sample loss that
occurs within the TRS emission mea-
surement system during source testing
can be determined, procedures have
been added to Reference Method 16
requiring determination of these losses
during each source test and adjust-
ment of the emission data obtained to
take these losses into account.
With regard to the ability of a lime
kiln to comply with both the TRS
emission standard and the particulate
emission standard simultaneously,
caustic scrubbing will tend to Increase
particulate emissions due to release of
sodium fume from the scrubbing
liquor. Compared to the concentration
of particulate matter permitted in the
gases discharged to the atmosphere,
however, the potential contribution of
sodium fume from caustic scrubbing is
quite small. Consequently, with proper
operation and maintenance, sodium
fume due to caustic scrubbing will not
cause particulate emissions from a
lime kiln to exceed the numerical
emission limit included in the promul-
gated standard.
Recovery Furnace. A number of com-
ments were received regarding both
the proposed TRS emission standard
and the proposed particulate emission
standard for recovery furnaces. Basi-
cally, the major issue was whether a
cross recovery furnace could comply
with the S ppm TRS standard or
whether a separate standard was nec-
essary-
Review of the data and information
submitted with these comments indi-
cates that the operation of cross recov-
ery furnaces is substantially different
from that of straight kraft recovery
furnaces. The sulfidity of the black
liquor burned in cross recovery fur-
naces and the heat content of the
liquor, "both of which are significant
factors influencing TRS emissions, are
considerably different from the levels
found in straight kraft recovery fur-
naces.
Analysis of the data indicated that
TRS emissions were generally less
than 26 ppm, with only occasional ex-
cursions exceeding this level. Conse-
quently, the promulgated TRS emis-
sion standard has been revised to in-
clude a separate TRS numerical emis-
sion limit of 25 ppm for cross recovery
furnaces.
Smelt Dissolving Tank. Numerous
comments were received concerning
the format of the proposed TRS and
particulate emission standards for
smelt dissolving tanks. These com-
ments pointed out that standards in
terms of emissions per unit of air-dried
pulp were inequitable for kraft pulp
mills which produced low-yield pulps
since both TRS and particulate emis-
sions from the smelt dissolving tanks
are proportional to the tons of black
liquor solids fed Into the tanks. The
black liquor solids produced per ton of
air-dried pulp, however, can vary sub-
stantially from mill to mill. A standard
in terms of emissions per unit of air-
dried pulp, therefore, requires greater
control of emissions at krait pulp mills
which use low-yield pulps (higher
solids-to-pulp ratio).
Review of these comments does
indeed indicate that the format of the
proposed standards was inequitable.
The format of the promulgated stan-
dards, therefore, has been revised to
emissions per unit of black liquor
solids fed to the smelt dissolving
tanks. Since the percent solids and
black liquor flow rate to the recovery
furnace is routinely monitored at kraft
pulp mills, the weight of black liquor
solids corresponding to a particular
emissions period will be easy to deter-
mine.
Brown Stock Washers. Several com-
ments expressed concern about com-
bustion of the high volume-low TRS
concentration gases discharged from
brown stock washers and black liquor
oxidation facilities in recovery fur-
naces without facing a serious risk of
explosions. As discussed in the SSEIS,
information obtained from two kraft
pulp mill operators indicates that this
practice is both safe and reliable when
it is accompanied by careful engineer-
ing and operating practices. Danger of
an explosion occurring is essentially
eliminated by introducing the gases
high in the furnace. Since some older
furnaces do not have the capability to
accept large volumes of gases at
higher combustion ports, this practice
may not be safe for some existing fur-
naces. In addition, the costs associated
with altering these furnaces to accept
these gases are frequently prohibitive.
Consequently, the promulgated stan-
dards include an exemption for new,
modified, or reconstructed brown
stock washers and black liquor oxida-
tion facilities within existing kraft
pulp mills where combustion of these
gases in an existing facility is not fea-
sible from a safety or economic stand-
point.
CONTINUOUS MONITORING
Numerous comments were received
concerning the proposed continuous
monitoring requirements. Generally,
these comments questioned the re-
quirement to install TRS monitors in
light of the absence of performance
specifications for these monitors.
At the time of proposal of the stan-
dards, both EPA and the kraft pulp
mill industry were engaged in develop-
ing performance specifications for
TRS continuous emission monitoring
systems. It was expected that this
work would lead to performance speci-
fications for these monitoring systems
by the time the standards of perfor-
mance were promulgated. Unfortu-
nately, this is not the case. In a joint
EPA/Industry effort, the compatibility
of various TRS emission monitoring
MORAL RtGBTEt. VOL 43, NO. 37THURSDAY, FEBRUARY M, 197t
IV-223
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RULES AND REGULATIONS
methods with Reference Method 16,
which is the performance test method
to determine TRS emissions, is still
under study. There is little doubt but
that these TRS emission monitoring
systems will be shown to be compati-
ble with Reference Method 16, and
that performance specifications for
these systems will be developed. Con-
sequently, the promulgated standards
include TRS continuous emission mon-
itoring requirements. These require-
ments, however, will not become effec-
tive until performance specifications
for TRS continuous emission monitor-
ing systems have been developed. To
accommodate this situation, not only
for the promulgated standards for
kraft pulp mills, but also for standards
of performance that may be developed
in the future that may also face this
situation, section 60.13 of the General
Provisions for subpart 60 is amended
to provide that continuous monitoring
systems need not be installed until
performance specifications for these
systems are promulgated under Ap-
pendix B to subpart 60. This will
ensure that all facilities which are cov-
ered by standards of performance will
eventually install continuous emission
monitoring systems where required.
EXCESS EMISSIONS
Numerous comments were received
which were concerned with the excess
emission allowances and the reporting
requirements for excess emissions. In
general, these comments reflected a
lack of understanding with regard to
the concept of excess emissions. Con-
sequently, a brief review of this con-
cept is appropriate.
Standards of performance have two
major objectives. The first is installa-
tion of the best system of emission re-
duction, considering costs; and the
second is continued proper operation
and maintenance of the system
throughout its useful life. Since the
numerical emission limit included in
standards of performance is selected
to reflect the performance of the best
system of emission reduction under
conditions of proper operation and
maintenance, the performance test,
under 40 CFR 60.8 represents the abil-
ity of the source to meet these objec-
tives. Performance tests, however, are
often time consuming and complex. As
a result, while the performance test is
an excellent mechanism for achieving
these objectives, it is rather cumber-
some and inconvenient for routinely
achieving these objectives. Therefore,
the Agency believes that continuous
monitors must play an important role
In meeting these objectives.
Excess emissions are defined as emis-
sions exceeding the numerical emis-
sion limit included in a standard of
performance. Continuous emission
monitoring, therefore, identifies peri-
ods of excess emissions and when com-
bined with the requirement that these
periods be reported to EPA, it provides
the Agency with a useful mechanism
for achieving the previously men-
tioned objectives.
Continuous emission monitoring,
however, will identify all periods of
excess emissions, including those
which are not the result of improper
operation and maintenance. Excess
emissions due to start-ups, shutdowns,
and malfunctions, for example, are un-
avoidable or beyond the control of an
owner or operator and cannot be at-
tributed to improper operation and
maintenance. Similarly, excess emis-
sions as a result of some inherent vari-
ability or fluctation within a process
which influences emissions cannot be
attributed to improper operation and
maintenance, unless these floatations
could be controlled by more carefully
attending to those process operating
parameters during routine operation
which have, little effect on operation
of the process, but which may have a
significant effect on emissions.
To quantify the potential for excess
emissions due to inherent variability
in a process, continuous monitoring
data are used whenever possible to cal-
culate an excess emission allowance.
For TRS emissions at kraft pulp mills.
this allowance is defined as follows. If
a calendar quarter is divided into dis-
crete contiguous 12-hour time periods,
the excess emission allowance is ex-
pressed as the percentage of these
time periods. Excess emissions may
occur as the result of unavoidable vari-
ability within the kraft pulping pro-
cess. Thus, the excess emissions
allowance represents the potential for
excess emissions under conditions of
proper operation and maintenance in
the absence of start-ups, shutdowns
and malfunctions, and is used as a
guideline or screening mechanism for
interpreting the data generated by the
excess emission reporting require-
ments.
Although the excess emission report-
ing requirements provide a mechanism
for achieving the objective of proper
operation and maintenance of the best
system of emission reduction, this
mechanism is not necessarily a direct
indicator of improper operation and
maintenance. Consequently, excess
emission reports must be reviewed and
interpreted for proper decisionmaking.
In general, the comments received
concerning the excess emission report-
ing requirements questioned: (1) The
adequacy of the TRS excess emission
allowance for lime kilns and (2) the
lack of a TRS excess emission
allowance for recovery furnaces.
With regard to the adequacy of the
TRS excess emissions allowance for
lime kilns, a revaluation of the TRS
emission data from lime kiln E led the
Agency to the conclusion that, for a
TRS emission limit of 5 ppm, an
excess emission allowance of 6 percent
was appropriate. However, a similar
analysis also indicates that an excess
emission allowance is not appropriate
at a TRS emission level of 8 ppm. Ac-
cordingly, the excess emission report-
ing requirements included in the pro-
mulgated standard for lime kilns con-
tains no excess emission allowance.
This does not represent a change in
the basis of the standard. The stand-
ard will still require installation of the
best system of emission reduction, con-
sidering costs (i.e., efficient mud wash-
ing, good lime kiln process operation,
and caustic scrubbing; or an alterna-
tive system equivalent to the perfor-
mance of this system).
With regard to the lack of a TRS
excess emission allowance for recovery
furnaces, at the time of proposal of
the standards, no TRS continuous
emission monitoring data were avail-
able from a well-controlled and well
operated recovery furnace which could
be used to determine an excess emis-
sion allowance. Several months of
TRS continuous emission monitoring
data, however, were submitted with
the comments received from the oper-
ator of recovery furnace D concerning
this point.
A review of the data indicates that,
while some of the excursions of TRS
emissions above 5 ppm reflected either
improper operation and maintenance,
or start-ups, shutdowns, or malfunc-
tions, most of these excursions reflect-
ed unavoidable normal variability in
the operation of a kraft pulp mill re-
covery furnace. Discounting those ex-
cursions in emissions from the data
which were due to improper operation
and maintenance, or start-ups, shut-
downs, or malfunctions indicates that
an excess emission allowance of 1 per-
cent is appropriate for all recovery
furnaces.
Including an excess emissions
allowance in the promulgated stan-
dards for recovery furnaces, but not
for lime kilns, is a reversal of the pro-
posed requirements. Including such an
allowance for recovery furnaces but
not for lime kilns, however, is consis-
tent with the nature of the different
emission control systems which were
selected as the bases for these stan-
dards. The emission control system
upon which the TRS standard for re-
covery furnaces is based consists of
black liquor oxidation and good pro-
cess operation of the recovery furnace
for direct recovery furnaces, and good
process operation alone for indirect re-
covery furnaces. Neither of these emis-
sion control systems are particularly
well suited to controlling fluctuations
in the kraft pulping process. Thus,
fluctuations in the process tend to
pass through the emission control
system and show up as fluctuations in
TRS emissions.
The emission control system upon
which the TRS standard for lime kilns
FEDERAL MOISTEt, VOL 43, NO. 37THUtSDAY, KMUAKY 23, 1971
IV-224
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RULES AND REGULATIONS
is based consists of efficient mud
washing, good process operation of the
lime kiln, and caustic scrubbing of the
gases discharged from the lime kiln.
As with the emission control system
upon which the standard for recovery
furnaces is based, the first two emis-
sion control techniques (i.e., mud
washing and good process operation)
are not particularly well suited to con-
trolling fluctuations in the kraft pulp-
ing process. The third emission control
technique, however, caustic scrubbing,
is an "add-on" emission control tech-
nique that can be designed to accom-
modate fluctuations in TRS emissions
and minimize or essentially eliminate
these fluctuations.
EMISSION TESTING
A few comments were received
which questioned the validity of the
results obtained by Reference Method
16, due to sample losses and sulfur
dioxide (SO,) interference.
With regard to the validity of the re-
sults obtained by Reference Method
16, as mentioned earlier, during the
emission testing program, it was not
widely known that sample losses could
occur within the TRS emission mea-
surement system. Since proposal of
the standards, however, sample losses
of up to 20 percent during emission
source testing have been confirmed.
Although these losses were not consid-
ered in selecting the numerical emis-
sion limits included in the proposed
TRS emission standards, they have
been considered in selecting the nu-
merical emission limit included in the
promulgated standards. Also, since the
amount of sample loss that occurs
within the TRS emission measure-
ment system during source testing can
be determined, procedures have been
added to Reference Method 16 requir-
ing determination of these losses
during each source test and adjust-
ment of the emission data obtained to
take these losses into account. This
will ensure that the TRS emission
data obtained during a performance
test are accurate.
It has also been confirmed that high
concentrations of SOa will interfere
with the determination of TRS emis-
sions to some extent. At this point,
however, it is not known what SO,
concentration levels will result in a sig-
nificant loss of accuracy in determin-
ing TRS emissions. The ability of a ci-
trate scrubber to selectively remove
SO, prior to measurement of TRS
emissions is now being tested. In addi-
tion, various chromatographic col-
umns might exist which would effec-
tively resolve this problem. As soon as
an appropriate technique is developed
to overcome this problem, Reference
Method 16 will be amended.
This problem of SO, interference
will not present major difficulties to
the use of Reference Method 16. Rela-
tively high SO. concentration levels
were observed in only one EPA emis-
sion source test. Accordingly, high SO.
concentration levels are probably not
a frequent occurrence within kraft
pulp mills. More importantly, howev-
er, high SO. concentrations only inter-
fere with the determination of methyl
mercaptan In the emission measure-
ment system outlined in Reference
Method 16. Since methyl mercaptan is
usually only a small contributor to
total TRS emissions, neglecting
methyl mercaptan where this interfer-
ence occurs should not seriously affect
the determination of TRS emissions.
Consequently, Reference Method 16
can be used to enforce the promulgat-
ed standards without major difficul-
ties.
Miscellaneous: The effective date of
this regulation is February 24, 1976.
Section lll(bXlXB) of the Clean Air
Act provides that standards of perfor-
mance or revisions of them become ef-
fective upon promulgation and apply
to affected facilities, construction or
modification of which was commenced
after ihe date of proposal (September
24, 1976).
NOTE.An economic assessment has been
prepared as required under section 317 of
the Act. This also satisfies the requirements
of Executive Orders 11821 and OMB Circu-
lar A-107.
Dated: February 10, 1978.
BARBARA BLUM,
Acting Administrator.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amend-
ed as follows:
Subpart AGeneral Provident
1. Section 60.13 is amended to clarify
the provisions in paragraph (a) by re-
vising paragraph (a) to read as follows:
§60.13 Monitoring requirements.
(a) For the purposes of this section,
all continuous monitoring systems re-
quired under applicable subparts shall
be subject to the provisions of this sec-
tion upon promulgation of perfor-
mance specifications for continuous
monitoring system under Appendix B
to this part, unless:
(1) The continuous monitoring
system is subject to the provisions of
paragraphs (c)(2) and (c)(3) of this
section, or
(2) otherwise specified in an applica-
ble subpart or by the Administrator.
2. Part 60 is amended by adding sub-
part BB as follows:
SobBart »»Standard* el Performance for Kraft Pulp
Mlllt
Sec.
60.280 Applicability and designation of af-
fected facility.
60.281 Definitions.
60.282 Standard for partlculate matter.
60.283 Standard for total reduced sulfur
(TRS).
60.284 Monitoring of emissions and oper-
ations.
60.285 Test methods and procedures.
AUTHORITY: Sees. 111. 301(a) of the Clean
Air Act, as amended [42 U.S.C. 7411,
7601(a>], and additional authority as noted
below.
Subpart B8Standards of Performance for
Kraft Pulp Mill.
60.280 Applicability and designation of af-
fected facility.
(a) The provisions of this subpart
are applicable to the following affect-
ed facilities in kraft pulp mills: digest-
er system, brown stock washer system,
multiple-effect evaporator system,
black liquor oxidation system, recov-
ery furnace, smelt dissolving tank,
lime kiln, and condensate stripper
system. In pulp mills where kraft
pulping is combined with neutral sul-
fite semichemical pulping, the provi-
sions of this subpart are applicable
when any portion of the material
charged to an affected facility is pro-
duced by the kraft pulping operation.
(b) Any facility under paragraph (a)
of this section that commences con-
struction or modification after Sep-
tember 24, 1976, is subject to the re-
quirements of this subpart.
§ 60.281 Definitions.
As used in this subpart, all terms not
defined herein shall have the same
meaning given them In the Act and in
Subpart A.
(a) "Kraft pulp mill" means any sta-
tionary source which produces pulp
from wood by cooking (digesting)
wood chips in a water solution of
sodium hydroxide and sodium sulfide
(white liquor) at high temperature
and pressure. Regeneration "of the
cooking chemicals through a recovery
process is also considered part of the
kraft pulp mill.
(b) "Neutral sulfite semichemical
pulping operation" means any oper-
ation in which pulp is produced from
wood by cooking (digesting) wood
chips in a solution of sodium sulfite
and sodium bicarbonate, followed by
mechanical defibrating (grinding).
(c) "Total reduced sulfur (TRS)"
means the sum of the sulfur com-
pounds hydrogen sulfide, methyl mer-
captan, dimethyl sulfide, and dimethyl
disulfide, that are released during the
kraft pulping operation and measured
by Reference Method 16.
(d) "Digester system" means each
continuous digester or each batch di-
gester used for the cooking of wood in
white liquor, and associated flash
tank(s), below tank(s), chip steamer(s),
and condenser(s).
(e) "Brown stock washer system"
means brown stock washers and associ-
ated knotters, vacuum pumps, and fil-
FEDERAL REGISTER, VOL. 43, NO. 37THURSDAY, FEBRUARY 33, 197*
IV-225
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RULES AND REGULATIONS
trate tanks used to wash the pulp fol-
lowing the digester system.
(f) "Multiple-effect evaporator
system" means the multiple-effect
evaporators and associated
condenser(s) and hotwell(s) used to
concentrate the spent cooking liquid
that is separated from the pulp (black
liquor).
(g) "Black liquor oxidation system"
means the vessels used to oxidize, with
air or oxygen, the black liquor, and as-
sociated storage tank(s).
(h) "Recovery furnace" means either
a straight kraft recovery furnace or a
cross recovery furnace, and includes
the direct-contact evaporator for a
direct-contact furnace.
(i) "Straight kraft recovery furnace"
means a furnace used to recover
chemicals consisting primarily of
sodium and sulfur compounds by
burning black liquor which on a quar-
terly basis contains 7 weight percent
or less of the total pulp solids from
the neutral sulfite semichemical pro-
cess or has green liquor sulfidlty of 28
percent or less.
(j) "Cross recovery furnace" means a
furnace used to recover chemicals con-
sisting primarily of sodium and sulfur
compounds by burning black liquor
which on a quarterly basis contains
more than 7 weight percent of the
total pulp solids from the neutral sul-
fite semichemical process and has a
green liquor sulfidity of more than 28
percent.
(k) "Black liquor solids" means the
dry" weight of the solids which enter
the recovery furnace in the black
liquor.
(1) "Green liquor sulfidity" means
the sulfidity of the liquor which leaves
the smelt dissolving tank.
(m) "Smelt dissolving tank" means a
vessel used for dissolving the smelt
collected from the recovery furnace.
(n) "Lime kiln" means a unit used to
calcine lime mud, which consists pri-
marily of calcium carbonate, into
quicklime, which is calcium oxide.
(o) "Condensate stripper system"
means a column, and associated con-
densers, used to strip, with air or
steam, TRS compounds from conden-
sate streams from various processes
within a kraft pulp mill.
§ 60.282 Standard for particulate matter.
(a) On and after the date on which
the performance test required to be
conducted by §60.8 is completed, no
owner or operator subject to the provi-
sions of this subpart shall cause to be
discharged into the atmosphere:
(1) From any recovery furnace any
gases which:
(i) Contain particulate matter In
excess of 0.10 g/dscm (0.044 gr/dscf)
corrected to 8 percent oxygen.
(ii) Exhibit 35 percent opacity or
greater.
(2) Prom any smelt dissolving tank
any gases which contain particulate
matter in excess of 0.1 g/kg black
liquor solids (dry weight)[0.2 Ib/ton
black liquor solids (dry weight)].
(3) Prom any lime kiln any gases
which contain particulate matter in
excess of:
(i) 0.15 g/dscm (0.067 gr/dscf) cor-
rected to 10 percent oxygen, when gas-
eous fossil fuel is burned.
(ii) 0.30 g/dscm (0.13 gr/dscf) cor-
rected to 10 percent oxygen, when
liquid fossil fuel is burned.
§60.283 Standard for total reduced sulfur
(TRS).
(a) On and after the date on which
the performance test required to be
conducted by §60.8 is completed, no
owner or operator subject to the provi-
sions of this subpart shall cause to be
discharged into the atmosphere:
(1) From any digester system, brown
stock washer system, multiple-effect
evaporator system, black liquor oxida-
tion system, or condensate stripper
system any gases which contain TRS
in excess of 5 ppm by volume on a dry
basis, corrected to 10 percent oxygen,
unless the following conditions are
met:
(i) The gases are combusted in a lime
kiln subject to the provisions of para-
graph (a)(5) of this section; or
(ii) The gases are combusted in a re-
covery furnace subject to the provi-
sions of paragraphs (a)(2) or (a)(3) of
this section; or
(iii) The gases are combusted with
other waste gases in an incinerator or
other device, or combusted in a lime
kiln or recovery furnace not subject to
the provisions of this subpart, and are
subjected to a minimum temperature
of 1200° F. for at least 0.5 second; or
(iv) It has been demonstrated to the
Administrator's satisfaction by the
owrter or operator that incinerating
the exhaust gases from a new, modi-
fied, or reconstructed black liquor oxi-
dation system or brown stock washer
system in an existing facility is tech-
nologically or economically not feasi-
ble. Any exempt system will become
subject to the provisions of this sub-
part if the facility is changed so that
the gases can be incinerated.
(2) From any straight kraft recovery
furnace any gases which contain TRS
in excess of 5 ppm by volume on a dry
basis, corrected to 8 percent oxygen.
(3) From any cross recovery furnace
any gases which contain TRS in excess
of 25 ppm by volume on a dry basis,
corrected to 8 percent oxygen.
(4) From any smelt dissolving tank
any gases which contain TRS in excess
of 0.0084 g/kg black liquor solids (dry
weight) [0.0168 Ib/ton liquor solids
(dry weight)].
(5) From any lime kiln any gases
which contain TRS in excess of 8 ppm
by volume on a dry basis, corrected to
10 percent oxygen.
§ 60,284 Monitoring of emissions and op-
erations.
(a) Any owner or operator subject to
the provisions of this subpart shall in-
stall, calibrate, maintain, and operate
the following continuous monitoring
systems:
(DA continuous monitoring system
to monitor and record the opacity of
the gases discharged into the atmos-
phere from any recovery furnace. The
span of this system shall be set at 70
percent opacity.
(2) Continuous monitoring systems
to monitor and record the concentra-
tion of TRS emissions on a dry basis
and the percent of oxygen by volume
on a dry basis in the gases discharged
into the atmosphere from any lime
kiln, recovery furnace, digester
system, brown stock washer system,
multiple-effect evaporator system,
black liquor oxidation system, or con-
densate stripper system, except where
the provisions of §60.283(aXl) (iii) or
(iv) apply. These systems shall be lo-
cated downstream of the contrjol
device(s) and the span(s) of these con-
tinuous monitoring system(s) shall be
set:
(i) At a TRS concentration of 30
ppm for the TRS continuous monitor-
ing system, except that for any cross
recovery furnace the span shall be set
at 50 ppm.
(ii) At 20 percent oxygen for the
continuous oxygen monitoring system.
(b) Any owner or operator subject to
the provision;; of this subpart shall in-
stall, calibrate, maintain, and operate
the following continuous monitoring
devices:
(DA monitoring device which mea-
sures the combustion temperature at
the point of incineration of effluent
gases which are emitted from any di-
gester system, brown stock washer
system, multiple-effect evaporator
system, black liquor oxidation system,
or condensate stripper system where
the provisions of §60.283(a)(l)(iii)
apply. The monitoring device is to be
certified by the manufacturer to be ac-
curate within ±1 percent of the tem-
perature being measured.
(2) For any lime kiln or smelt dis-
solving tank using a scrubber emission
control device:
(i) A monitoring device for the con-
tinuous measurement of the pressure
loss of the gas stream through the
control equipment. The monitoring
device is to be certified by the manu-
facturer to be accurate to within a
gage pressure of ±500 pascals (ca. ±2
inches water gage pressure).
(ii) A monitoring device for the con-
tinuous measurement of the scrubbing
liquid supply pressure to the control
equipment. The monitoring device is
to be certified by the manufacturer to
be accurate within ±15 percent of
design scrubbing liquid supply pres-
sure. The pressure sensor or tap is to
RDEKAl RfOISTEK, VOL 43, NO. VTHUXSDAY, FtMUARY 23,
IV-226
-------
RULES AND REGULATIONS
be located close to the scrubber liquid
discharge point. The Administrator
may be consulted for approval of alter-
native locations.
(c) Any owner or operator subject to
the provisions of this subpart shall,
except where the provisions of
§60.283(a)(l)(iv) or §60.283(a)(4)
apply.
(1) Calculate and record on a daily
basis 12-hour average TRS concentra-
tions for the two consecutive periods
of each operating day. Each 12-hour
average shall be determined as the
arithmetic mean of the appropriate 12
contiguous 1-hour average total re-
duced sulfur concentrations provided
by each continuous monitoring system
Installed under paragraph (a)(2) of
this section.
(2) Calculate and record on a daily
basis 12-hour average oxygen concen-
trations for the two consecutive peri-
ods of each operating day for the re-
covery furnace and lime kiln. These
12-hour averages shall correspond to
the 12-hour average TRS concentra-
tions under paragraph (c)(l) of this
section and shall be determined as an
arithmetic mean of the appropriate 12
contiguous 1-hour average oxygen con-
centrations provided by each continu-
ous monitoring system Installed under
paragraph (a)(2) of this section.
(3) Correct all 12-hour average TRS
concentrations to 10 volume percent
oxygen, except that all 12-hour aver-
age TRS concentration from a recov-
ery furnace shall be corrected to '8
volume percent using the following
equation:
X (21 - X/21 - Y)
where:
for
Cm = the concentration corrected
oxygen.
Cm-1=the concentration uncorrected for
oxygen.
JT=the volumetric oxygen concentration in
percentage to be corrected to (8 percent
for recovery furnaces and 10 percent for
lime kilns, incinerators, or other de-
vices).
y=the measured 12-hour average volumet-
ric oxygen concentration.
(d) For the purpose of reports re-
quired under § 60.7(c), any owner or
operator subject to the provisions of
this subpart shall report periods of
excess emissions as follows:
(1) For emissions from any recovery
furnace periods of excess emissions
are:
(i) All 12-hour averages of TRS con-
centrations above 5 ppm by volume for
straight kraft recovery furnaces and
above 25 ppm by volume for cross re-
covery furnaces.
(ii) All 6-minute average opacities
that exceed 35 percent.
(2) For emissions from any lime kiln,
periods of excess emissions are all 12-
hour average TRS concentration
above 8 ppm by volume.
(3) For emissions from any digester
system, brown stock washer system,
multiple-effect evaporator system,
black liquor oxidation system, or con-
densate stripper system periods of
excess emissions are:
(i) All 12-hour average TRS concen-
trations above 5 ppm by volume unless
the provisions of § 60.283(aXl) (i), (ii),
or (iv) apply; or
(ii) All periods In excess of 5 minutes
and their duration during which the
combustion temperature at the point
of incineration is less than 1200° F.
where the provisions of
f 60.283(a)(l)(ii) apply.
(e) The Administrator will not con-
sider periods of excess emissions re-
ported under paragraph (d) of this sec-
tion to be indicative of a violation of
§ 60.11(d) provided that:
(1) The percent of the total number
of possible contiguous periods of
excess emissions in a quarter (exclud-
ing periods of startup, "Shutdown, or
malfunction and periods when the fa-
cility is not operating) during which
excess emissions occur does not
exceed:
(i) One percent for TRS emissions
from recovery furnaces.
(ii) Six percent for average opacities
from recovery furnaces.
(2) The Administrator determines
that the affected facility, including air
pollution control equipment, is main-
tained and operated in a manner
which is consistent with good air pol-
lution control practice for minimizing
emissions during periods of excess
emissions.
§ 60.285 Test methods and procedures.
(a) Reference methods in Appendix
A of this part, except as provided
under § 60.8(b), shall be used to deter-
mine compliance with §60.282(a) as
follows:
(1) Method 5 for the concentration
of participate matter and the associat-
ed moisture content,
(2) Method 1 for sample and velocity
traverses,
(3) When determining compliance
with § 60.282(a)(2), Method 2 for veloc-
ity and volumetric flow rate, ,
(4) Method 3 for gas analysis, and
(5) Method 9 for visible emissions.
(b) For Method 5, the sampling time
for each run shall be at least 60 min-
utes and the sampling rate shall be at
least 0.85 dscm/hr (0.53 dscf/min)
except that shorter sampling times,
when necessitated by process variables
or other factors, may be approved by
the Administrator. Water shall be
used as the cleanup solvent instead of
acetone in the sample recovery proce-
dure outlined in Method 5.
(c) Method 17 (in-stack filtration)
may be used as an alternate method
for Method 5 for determining compli-
ance with |60.282(a)(l)(i): Provided,
That a constant value of 0.009 g/dscm
(0.004 gr/dscf) is added to the results
of Method 17 and the stack tempera-
ture is no greater than 205° C (ca. 400°
F). Water shall be used as the cleanup
solvent Instead of acetone in the
sample recovery procedure outlined in
Method 17.
(d) For the purpose of determining
compliance with §60.283(a) (1), (2),
(3), (4). and (5), the following refer-
ence methods shall be used:
(1) Method 16 for the concentration
of TRS,
(2) Method 3 for gas analysis, and
(3) When determining compliance
with §60.283(aX4), use the results of
Method 2, Method 16, and the black
liquor solids feed rate in the following
equation to determine the TRS emis-
sion rate.
,E =
Where:
£ = mass of TRS emitted per unity of black
liquor solids (g/kg) (Ib/ton)
Cm, = average concentration of hydrogen
sulfide CH*S) during the test period,
PPM.
CM.SH = average concentration of methyl
mercaptan (MeSH) during the rtest
period, PPM.
CMIS = average concentration of dimethyl
sulfide (DMS) during the test period,
PPM.
CDMM = average concentration of dimethyl
disulfide (DMDS) during the test period,
PPM.
Fm> = 0.001417 g/m' PPM for metric units
= 0.08844 lb/ff PPM for English units
fn.su = 0.00200 g/m' PPM for metric units
= 0.1248 lb/ft' PPM for English units
Ftms = 0.002583 g/m' PPM for metric units
= 0.1612 lb/ff PPM for English units
Fam* = 0.003917 g/m' PPM for metric units
= 0.2445 lb/ft« PPM for English units
Q«, = dry volumetric stack gas flow rate cor-
rected to standard conditions, dscm/hr
(dscf/hr)
BLS = black liquor solids feed rate, kg/hr
(Ib/hr)
(4) When determining whether a
furnace is straight kraft recovery fur-
nace or a cross recovery furnace,
TAPPI Method T.624 shall be used to
determine sodium sulfide, sodium hy-
droxide and sodium carbonate. These
"determinations shall be made three
times daily from the green liquor and
the daily average values shall be con-
verted to sodium oxide (Na^O) and
substituted into the following equa-
tion to determine the green liquor sul-
fidity:
GLS = 100 C».,VCN.,8 + CN.OH + CN.,co,
Where:
GLS = percent green liquor sulfidity
CV.M = average concentration of No* ex-
pressed as NthO (mg/1)
CH,OH = average concentration of NaOH
expressed as Na,O (mg/1)
CiuiCO, = average concentration of Na,CO,
expressed as Na,O (mg/1)
(e) All concentrations of particulate
matter and TRS required to be mea-
sured by this section from lime kilns
or incinerators shall be corrected 10
volume percent oxygen and those con-
centrations from recovery furnaces
FEDERAL REGISTER, VOL 43, NO. 17THURSDAY, FEBRUARY 73, 1978
IV-227
-------
RULES AND REGULATIONS
shall be corrected to 8 volume percent
oxygen. These corrections shall be
made in the manner specified in
$60.284(0(3).
APPENDIX AREFERENCE METHODS
(3) Method 16 and Method 17 are
added to Appendix A as follows:
METHOD 16. SEMICONTINUOUS DETERMINATION
OF SULFUR EMISSIONS FROM STATIONARY
SOURCES
Introduction
The method described below uses the
principle of gas chromatographic separation
and flame photometric detection. Since
there are many systems or sets of operating
conditions that represent usable methods of
determining sulfur emissions, all systems
which employ this principle, but differ only
in details of equipment and operation, may
be used as alternative methods, provided
that the criteria set below are met.
1. Principle and Applicability.
1.1 Principle. A gas sample is extracted
from the emission source and diluted with
clean dry air. An aliquot of the diluted
sample is then analyzed for hydrogen sul-
fide (H.S), methyl mercaptan (MeSH), di-
methyl sulfide (DMS) and dimethyl disul-
fide (DMDS) by gas chromatographic (GO
separation and flame photometric detection
(FPD). These four compounds are known
collectively as total reduced sulfur (TRS).
1.2 Applicability. This method is applica-
ble for determination of TRS compounds
from recovery furnaces, lime kilns, and
smelt dissolving tanks at kraft pulp mills.
2. Range and Sensitivity.
2.1 Range. Coupled with a gas chromato-
graphic system utilizing a ten milliliter
sample size, the maximum limit of the FPD
for each sulfur compound is approximately
1 ppm. This limit is expanded by dilution of
the sample gas before analysis. Kraft mill
gas samples are normally diluted tenfold
(9:1). resulting in an upper limit of about 10
ppm for each compound.
For sources with emission levels between
10 and 100 ppm, the measuring range can be
best extended by reducing the sample size
to 1 milliliter.
2.2 Using the sample size, the minimum
detectable concentration is approximately
50 ppb.
3. Interferences.
3.1 Moisture Condensation. Moisture
condensation in the sample delivery system,
the analytical column, or the FPD burner
block can cause losses or interferences. This
potential is eliminated by heating the
sample line, and by conditioning the sample
with dry dilution air to lower its dew point
below the operating temperature of the
OC/FPD analytical system prior to analysis.
3.2 Carbon Monoxide and Carbon Diox-
ide. CO and CO, have substantial desensitiz-
ing effect on the flame photometric detec-
tor even after 9:1 dilution. Acceptable sys-
tems must demonstrate that they have
eliminated this interference by some proce-
dure such as elutlng these compounds
before any of the compounds to be mea-
sured. Compliance with this requirement
can be demonstrated by submitting chroma-
tograms of calibration gases with and with-
out CO, in the diluent gas. The CO, level
should be approximately 10 percent for the
case with CO, present. The two chromato-
graphs should show agreement within the
precision limits of Section 4.1.
3.3 Particulate Matter. Particulate
matter in gas samples can cause Interfer-
ence by eventual clogging of the analytical
system. This interference must be eliminat-
ed by use of a probe filter.
3.4 Sulfur Dioxide. SO, is not a specific
interf erent but may be present in such large
amounts that it cannot be effectively sepa-
rated from other compounds of interest.
The procedure must be designed to elimi-
nate this problem either by the choice of
separation columns or by removal of SO,
from the sample.
Compliance with this section can be dem-
onstrated by submitting chromatographs of
calibration gases with SO, present in the
same quantities expected from the emission
source to be tested. Acceptable systems
shall show baseline separation with the am-
plifier attenuation set so that the reduced
sulfur compound of concern is at least 50
percent of full scale. Base line separation is
defined as a return to zero ± percent in the
interval between peaks.
4. Precision and Accuracy.
4.1 GC/FPD and Dilution System Cali-
bration Precision. A series of three consecu-
tive Injections of the same calibration gas,
at any dilution, shall produce results which
do not vary by more than ±3 percent from
the mean of the three injections.
4.2 OC/FPD and Dilution System Cali-
bration Drift. The calibration drift deter-
mined from the mean of three injections
made at the beginning and end of any 8-
hour period shall not exceed ± percent.
4.3 System Calibration Accuracy. The
complete system must quantitatively trans-
port and analyze with an accuracy of 20 per-
cent. A correction factor Is developed to
adjust calibration accuracy to 100 percent.
5. Apparatus (See Figure 16-1).
6.1.1 Probe. The probe must be made of
inert material such as stainless steel or
glass. It should be designed to incorporate a
filter and to allow calibration gas to enter
the probe at or near the sample entry point.
Any portion of the probe not exposed to the
stack gas must be heated to prevent mois-
ture condensation.
5.1.2 Sample Line. The sample line must
be made of Teflon,' no greater than 1.3 cm
(V4> inside diameter. All parts from the
probe to the dilution system must be ther-
mostatically heated to 120* C.
5.1.3 Sample Pump. The sample pump
shall be a leak] ess Teflon-coated diaphragm
type or equivalent. If the pump is upstream
of the dilution system, the pump head must
be heated to 120' C.
5.2 Dilution System. The dilution system
must be constructed such that all sample
contacts are made of inert materials (e.g.,
stainless steel or Teflon). It must be heated
to 120* C. and be capable of approximately a
9:1 dilution of the sample.
5.3 Gas Chromatograph. The gas chro-
matograph must have at least the following
components:
5.3.1 Oven. Capable of maintaining the
separation column at the proper operating
temperature ±1' C.
5.3.2 Temperature Gauge. To monitor
column oven, detector, and exhaust tem-
perature ±1' C.
5.3.3 Flow System. Gas metering system
to measure sample, fuel, combustion gas,
and carrier gas flows.
'Mention of trade names or specific prod-
ucts does not constitute endorsement by the
Environmental Protection Agency.
5.3.4 Flame Photometric Detector.
5.3.4.1 Electrometer. Capable of full scale
amplification of linear ranges of 10~' to 10"'
amperes full scale.
5.3.4.2 Power Supply. Capable of deliver-
ing up to 750 volts.
5.3.4.3 Recorder. Compatible with the
output voltage range of the electrometer.
5.4 Gas Chromatograph Columns. The
column system must be demonstrated to be
capble of resolving the four major reduced
sulfur compounds: H*S, MeSH, DMS, and
DMDS. It must also demonstrate freedom
from known Interferences.
To demonstrate that adequate resolution
has been achieved, the tester must submit a
Chromatograph of a calibration gas contain-
ing all four of the TRS compounds in the
concentration range of the applicable stan-
dard. Adequate resolution will be defined as
base line separation of adjacent peaks when
the amplifier attenuation is set so that the
smaller peak is at least 50 percent of full
scale. Base line separation Is defined in Sec-
tion 3.4. Systems not meeting this criteria
may be considered alternate methods sub-
ject to the approval of the Administrator.
5.5. Calibration System. The calibration
system must contain the following compo-
nents.
5.5.1 Tube Chamber. Chamber of glass or
Teflon of sufficient dimensions to house
permeation tubes.
5.5.2 Flow System. To measure air flow
over permeation tubes at ±2 percent. Each
flowmeter shall be calibrated after a com-
plete test series with a wet test meter. If the
flow measuring device differs from the wet
test meter by 5 percent, the completed test
shall be discarded. Alternatively, the tester
may elect to use the flow data that would
yield the lowest flow measurement. Calibra-
tion with a wet test meter before a test is
optional.
5.5.3 Constant Temperature Bath. Device
capable of maintaining the permeation
tubes at the calibration temperature within
±0.1' C.
5.5.4 Temperature Gauge. Thermometer
or equivalent to monitor bath temperature
within ±1' C.
6. Reagents.
6.1 Fuel. Hydrogen (H,) prepurlfied
grade or better.
6.2 Combustion Gas. Oxygen (O,) or air,
research purity or better.
6.3 Carrier Gas. Prepurlfied grade or
better.
6.4 Diluent. Air containing less than 50
ppb total sulfur compounds and less than 10
ppm each of moisture and total hydrocar-
bons. This gas must be heated prior to
mixing with the sample to avoid water con-
densation at the point of contact.
6.5 Calibration Gases. Permeation tubes,
one each of H.S, MeSH. DMS, and DMDS,
agravlmetrically calibrated and certified at
some convenient operating temperature.
These tubes consist of hermetically sealed
FEP Teflon tubing in which a liquified gas-
eous substance Is enclosed. The enclosed gas
permeates through the tubing wall at a con-
stant rate. When the temperature is con-
stant, calibration gases Governing a wide
range of known concentrations can be gen-
erated by varying and accurately measuring
the flow rate of diluent gas passing over the
tubes. These calibration gases are used to
calibrate the GC/FPD system and the dilu-
tion system.
7. Pretest Procedures. The following proce-
dures are optional but would be helpful in
preventing any problem which might occur
later and invalidate the entire test.
FEDERAL REGISTER, VOL 43, NO. 37THURSDAY, FEBRUARY 23, 1978
IV-228
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RULES 'AND REGULATIONS
7.1 After the complete measurement
system has been set up at the site and
deemed to be operational, the following pro-
cedures should be completed before sam-
pling is initiated.
7.1.1 Leak Test. Appropriate leak test
procedures should be employed to verify the
integrity of all components, sample lines,
and connections. The following leak test
procedure is suggested: For components up-
stream of the sample pump, attach the
probe end of the sample line to a ma- no-
meter or vacuum gauge, start the pump and
pull greater than 50 nun (2 in.) Hg vacuum,
close off the pump outlet, and then stop the
pump and ascertain that there is no leak for
1 minute. For components after the pump,
apply a slight positive pressure and check
for leaks by applying a liquid (detergent in
water, for example) at each joint. Bubbling
indicates the presence of a leak.
7.1.2 System Performance. Since the
complete system Is calibrated following each
test, the precise calibration of each compo-
nent is not critical. However, these compo-
nents should be verified to be operating
properly. This verification can be performed
by observing the response of flowmeters or
of the GC output to changes in flow rates or
calibration gas concentrations and ascer-
taining the response to be within predicted
limits. In any component, or if the complete
system falls to respond in a normal and pre-
dictable manner, the source of the discrep-
ancy should be identified and corrected
before proceeding.
8. Calibration. Prior to any sampling run,
calibrate the system using the following
procedures. (If more than one run is per-
formed during any 24-hour period, a calibra-
tion need not be performed prior to the
second and any subsequent runs. The cali-
bration must, however, be verified as pre-
scribed in Section 10, after the last run
made within the 24-hour period.)
8.1 General Considerations. This section
outlines steps to be followed for use of the
GC/FPD and the dilution system. The pro-
cedure does not include detailed instruc-
tions because the operation of these systems
Is complex, and it requires a understanding
of the individual system being used. Each
system should include a written operating
manual describing in detail the operating
procedures associated with each component
in the measurement system. In addition, the
operator should be familiar with the operat-
ing principles of the components; particular-
ly the GC/FPD. The citations in the Bib-
liography at the end of this method are rec-
ommended for review for this purpose.
8.2 Calibration Procedure. Insert the per-
meation tubes into the tube chamber.
Check the bath temperature to assure
agreement with the calibration temperature
of the tubes within ±0.1* C. Allow 24 hours
for the tubes to equilibrate. Alternatively
equilibration may be verified by Injecting
samples of calibration gas at 1-hour Inter-
vals. The permeation tubes can be assumed
to have reached equilibrium when consecu-
tive hourly samples agree within the preci-
sion limits of Section 4.1.
Vary the amount of air flowing over the
tubes to produce the desired concentrations
for calibrating the analytical and dilution
systems. The air flow across the tubes must
at all times exceed the flow requirement of
the analytical systems. The concentration In
parts per million generated by a tube con-
taining a specific permeant can be calculat-
ed as follows: p
c - KRC
Equation 16-1
where:
C= Concentration of penneant produced in
ppm.
Pr=Permeation rate of the tube in ftg/min.
M=Molecular weight of the permeant (g/g-
mole).
L=Flow rate, 1/min, of air over permeant @
20' C, 760 mm Hg.
K=Oas constant at 20* C and 760 mm
Hg=24.04 1/gmole.
8.3 Calibration of analysis system. Gen-
erate a series of three or more known con-
centrations spanning the linear range of the
FPD (approximately 0.05 to 1.0 ppm) for
each of the four major sulfur compounds.
Bypassing the dilution system, inject these
standards into the GC/FPD analyzers and
monitor the responses. Three Injects for
each concentration must yield the precision
described in Section 4.1. Failure to attain
this precision is an Indication of a problem
In the calibration or analytical system. Any
such problem must be identified and cor-
rected before proceeding.
8.4 Calibration Curves. Plot the OC/FPD
response in current (amperes) versus their
causative concentrations in ppm on log-log
coordinate graph paper for each sulfur com-
pound. Alternatively, a least squares equa-
tion may be generated from the calibration
data.
8.5 Calibration of Dilution System. Gen-
erate a known concentration of hydrogen
sulfide using the permeation tube system.
Adjust the flow rate of diluent air for the
first dilution stage so that the desired level
of dilution is approximated. Inject the dilut-
ed calibration gas Into the GC/FPD system
and monitor Its response. Three injections
for each dilution must yield the precision
described in Section 4.1. Failure to attain
this precision in this step Is an indication of
a problem in the dilution system. Any such
problem must be Identified and corrected
before proceeding. Using the calibration
data for H.S (developed under 8.3) deter-
mine the diluted calibration gas concentra-
tion in ppm. Then calculate the dilution
factor as the ratio of the calibration gas
concentration before dilution to the diluted
calibration gas concentration determined
under this paragraph. Repeat this proce-
dure for each stage of dilution required. Al-
ternatively, the GC/FPD system may be
calibrated by generating a series of three or
more concentrations of each sulfur com-
pound and diluting these samples before in-
jecting them into the GC/FPD system. This
data will then serve as the calibration data
for the unknown samples and a separate de-
termination of the dilution factor will not
be necessary. However, the precision re-
quirements of Section 4.1 are still applica-
ble.
9. Sampling and Analysis Procedure.
9.1 Sampling. Insert the sampling probe
into the test port making certain that no di-
lution air enters the stack through the port.
Begin sampling and dilute the sample ap-
proximtely 9:1 using the dilution system.
Note that the precise dilution factor is that
which is determined in paragraph 8.5. Con-
dition the entire system with sample for a
minimum of 15 minutes prior to commenc-
ing analysis.
9.2 Analysis. Aliquots of diluted sample
are injected into the GC/FPD analyzer for
analysis.
9.2.1 Sample Run. A sample run is com-
posed of 16 individual analyses (injects) per-
formed over a period of not less than 3
hours or more than 6 hours.
9.2.2 Observation for Clogging of Probe.
If reductions in sample concentrations are
observed during a sample run that cannot
be explained by process conditions, the sam-
pling must be interrupted to determine If
the sample probe is clogged with particulate
matter. If the probe is found to be clogged,
the test must be stopped and the results up
to that point discarded. Testing may resume
after cleaning the probe or replacing it with
a clean one. After each run, the sample
probe must be inspected and, if necessary,
dismantled and cleaned.
10. Post-Test Procedures.
10.1 Sample Line Loss. A known concen-
tration of hydrogen sulfide at the level of
the applicable standard, ±20 percent, must
be Introduced Into the sampling system at
the opening of the probe in sufficient quan-
tities to Insure that there is an excess of
sample which must be vented to the atmo-
sphere. The sample must be transported
through the entire sampling system to the
measurement system in the normal manner.
The resulting measured concentration
should be compared to the known value to
determine the sampling system loss. A sam-
pling system loss of more than 20 percent U
unacceptable. Sampling losses of 0-20 per-
cent must be corrected for by dividing the
resulting sample concentration by the frac-
tion of recovery. The known gas sample may
be generated using permeation tubes. Alter-
natively, cylinders of hydrogen sulfide
mixed in air may be used provided they are
traceable to permeation tubes. The optional
pretest procedures provide a good guideline
for determining if there are leaks in the
sampling system.
10.2 Recalibration. After each run, or
after a series of runs made within a 24-hour
period, perform a partial recalibration using
the procedures In Section 8. Only HiS (or
other permeant) need be used to recalibrate
the GC/FPD analysis system (8.3) and the
dilution system (8.5).
10.3 Determination of Calibration Drift.
Compare the calibration curves obtained
prior to the runs, to the calibration curves
obtained under paragraph 10.1. The calibra-
tion drift should not exceed the limits set
forth in paragraph 4.2. If the drift exceeds
this limit, the intervening run or runs
should be considered not valid. The tester,
however, may instead have the option of
choosing the calibration data set which
would give the highest sample values.
11. Calculations.
11.1 Determine the concentrations of
each reduced sulfur compound detected di-
rectly from the calibration curves. Alterna-
tively, the concentrations may be calculated
using the equation for the least square line.
11.2 Calculation of TRS. Total reduced
sulfur will be determined for each anaylsb
made by summing the concentrations of
each reduced sulfur compound resolved
during a given analysis.
TRS=2 (H.S. MeSH, DMS, 2DMDS)d
Equation 16-2
where:
TRS=Total reduced sulfur In ppm, wet
basis.
HiS=Hydrogen sulfide. ppm.
MeSH=Methyl mercaptan, ppm.
DMS=Dimethyl sulfide, ppm.
DMDS=Dimethyl disulfide, ppm.
d-= Dilution factor, dimensionless.
FfDEftAL HKHSTtt, VOL 41, NO. 17THUKSDAY, FEMUAIY 23. 1971
IV-229
-------
RULES AND REGULATIONS
11.3 Average TRS. The average TRS will
be determined as follows:
Average TRS=
Average TRS=Average total reduced suflur
in ppm, dry basis.
TRS,=Total reduced sulfur in ppm as deter-
mined by Equation 16-2.
N-Number of samples.
B«.=Fraction of volume of water vapor in
the gas stream as determined by method
4Determination of Moisture in Stack
Gases (36 PR 24887).
11.4 Average concentration of Individual
reduced sulfur compounds.
Equation 16-3
where:
Si=Concentration of any reduced sulfur
compound from the ith sample injec-
tion, ppm.
C = Average concentration of any one of the
reduced sulfur compounds for the entire
run, ppm.
N=Number of injections in any run period.
12. Example System. Described below Is a
system utilized by EPA in gathering NSPS
data. This system does not now reflect all
the latest developments in equipment and
column technology, but it does represent
one system that has been demonstrated to
work.
12.1 Apparatus.
12.1.1 Sampling System.
12.1.1.1 Probe. Figure 16-1 illustrates the
probe used in lime kilns and other sources
where significant amounts of partlculate
matter are present, the probe is designed
with the deflector shield placed between the
sample and the gas inlet holes and the glass
wool plugs to reduce clogging of the filter
and possible adsorption of sample gas. The
exposed portion of the probe between the
sampling port and the sample line is heated
with heating tape.
12.1.1.2 Sample Line Vi« inch Inside diam-
eter Tetton tubing, heated to 120' C. This
temperature is controlled by a thermostatic
heater.
12.1.1.3 Sample Pump. Leakless Teflon
coated diaphragm type or equivalent. The
pump head Is heated to 120* C by enclosing
It in the sample dilution box (12.2.4 below).
12.1.2 Dilution System. A schematic dia-
gram of the dynamic dilution system is
given in Figure 16-2. The dilution system is
constructed such that all sample contacts
are made of inert materials. The dilution
system which is heated to 120* C must be ca-
pable of a minimum of 9:1 dilution of
sample. Equipment used in the dilution
system is listed below:
12.1.2.1 Dilution Pump. Model A-1SO
Kohmyhr Teflon positive displacement
type, nonadjustable ISO cc/min. ±2.0 per-
cent, or equivalent, per dilution stage. A 9:1
dilution of sample is accomplished by com-
bining 150 cc of sample with 1,350 cc of
clean dry air as shown in Figure 16-2.
12.1.2.2 Valves. Three-way Teflon sole-
noid or manual type.
12.1.2.3 Tubing. Teflon tubing and fit-
tings are used throughout from the sample
probe to the GC/FPD to present an inert
surface for sample gas,
12.1.2.4 Box. Insulated "box, heated and
maintained at 120* C, of sufficient dimen-
sions to house dilution apparatus.
12.1.2.5 Flowmeters. Rotameters or
equivalent to measure flow from 0 to 1500
ml/mln ±1 percent per dilution stage.
12.1.3 Gas Chromatograph Columns.
Two types of columns are used for separa-
tion of low and high molecular weight
sulfur compounds:
12.1.3.1 Low Molecular Weight Sulfur
Compounds Column (GC/FPD-1).
12.1.3.1 Separation Column. 11 m by 2.16
mm (36 ft by 0.085 In) inside diameter
Teflon tubing packed with 30/60 mesh
Teflon coated with 5 percent polyphenyl
ether and 0.05 percent orthophosphoric
acid, or equivalent (see Figure 16-3).
12.1.3.1.2 Stripper or Precolumn. 0.6 m
by 2.16 mm (2 ft by 0.085 In) Inside diameter
Teflon tubing packed as in 5.3.1.
12.1.3.1.3 Sample Valve. Teflon 10-port
gas sampling valve, equipped with a 10 ml
sample loop, actuated by compressed air
(Figure 16-3).
12.1.3.1.4 Oven. For containing sample
valve, stripper column and separation
column. The oven should be capable of
maintaining an elevated temperature rang-
ing from ambient to 100' C, constant within
±rc.
12.1.3.1.5 Temperature Monitor. Thermo-
couple pyrometer to measure column oven,
detector, and exhaust temperature ±1* C.
12.1.3.1.6 Flow System. Gas metering
system to measure sample flow, hydrogen
flow, and oxygen flow (and nitrogen carrier
gas flow).
12.1.3.1.7 Detector. Flame photometric
detector.
12.1.3.1.8 Electrometer. Capable of full
scale amplification of linear ranges of 10~>
to 10~< amperes full scale.
12.1.3.1.9 Power Supply. Capable of deli-
vering up to 750 volts.
12.1.3.1.10 Recorder. Compatible with
the output voltage range of the electrom-
eter.
12.1.3.2 High Molecular Weight Com-
pounds Column (OC/FPD-11).
12.1.3.2.1. Separation Column. 3.05 m by
2.16 mm (10 ft by 0.0885 in) inside diameter
Teflon tubing packed with 30/60 mesh
Teflon coated with 10 percent Triton X-305,
or equivalent.
12.1.3.2.2 Sample Valve. Teflon 6-port gas
sampling valve equipped with a 10 ml
sample loop, actuated by compressed air
(Figure 16-3).
12.1.3.2.3 Other Components. All compo-
nents same as in 12.1.3.1.4 to 12.1.3.1.10.
12.1.4 Calibration. Permeation tube
system (figure 16-4).
12.1.4.1 Tube Chamber. Glass chamber
of sufficient dimensions to house perme-
ation tubes.
12.1.4.2 Mass Flowmeters. Two mass
flowmeters in the range 0-3 1/min. and 0-10
1/min. to measure air flow over permeation
tubes at ±2 percent. These flowmeters shall
be cross-calibrated at the beginning of each
test. Using a convenient flow rate in the
measuring range of both flowmeters, set
and monitor the flow rate of gas over the
permeation tubes. Injection of calibration
gas generated at this flow rate as measured
by one flowmeter followed by Injection of
calibration gas at the same flow rate as mea-
sured by the other flowmeter should agree
within the specified precision limits. If they
do not, then there is a problem with the
mass flow measurement. Each mass flow-
meter shall be calibrated prior to the first
test with a wet test meter and thereafter, at
least once each year.
12.1.4.3 Constant Temperature Bath. Ca-
pable of maintaining permeation tubes at
certification temperature of 30* C. within
±0.1' C.
12.2 Reagents
12.2.1 Fuel. Hydrogen (H,) prepurlfied
grade or better.
12.2.2. Combustion Gas. Oxygen (O,) re-
search purity or better.
12.2.3 Carrier Gas. Nitrogen (N>> prepurl-
fied grade or better.
12.2.4 Diluent. Air containing less than
50 ppb total sulfur compounds and less than
10 ppm each of moisture and total hydro-
carbons, and filtered using MSA filters
46727 and 79030, or equivalent. Removal of
sulfur compounds can be verified by inject-
ing dilution air only, described in Section
8.3.
12.2.5 Compressed Air. 60 pslg for GC
valve actuation.
12.2.6 Calibrated Gases. Permeation
tubes gravimetrically calibrated and certi-
fied at 30.0' C.
12.3 Operating Parameters.
12.3.1 Low-Molecular Weight Sulfur
Compounds. The operating parameters for
the GC/FPD system used for low molecular
weight compounds are as follows: nitrogen
carrier gas flow rate of 50 cc/min, exhaust
temperature of 110' C, detector temperature
of 105' C, oven temperature of 40' C, hydro-
gen flow rate of 80 cc/min. oxygen flow rate
of 20 cc/min, and sample flow rate between
20 and 80 cc/min.
12.3.2 High-Molecular "Weight Sulfur
Compounds. The operating parameters for
the GC/FPD system for high molecular
weight compounds are the same as in 12.3.1
except: oven temperature of 70* C, and ni-
trogen carrier gas flow of 100 cc/min.
12.4 Analysis Procedure.
12.4.1 Analysis. Aliquots of diluted
sample are injected simultaneously into
both GC/FPD analyzers for analysis. OC/
FPD-I is used to measure the low-molecular
weight reduced sulfur compounds. The low
molecular weight compounds Include hydro-
gen sulfide, methyl mercaptan, and di-
methyl sulflde. GC/FPD-II Is used to re-
solve the high-molecular weight compound.
The high-molecular weight compound is di-
methyl disulfide.
12.4.1.1 Analysis of Low-Molecular
Weight Sulfur Compounds. The sample
valve Is actuated for 3 minutes In which
time an aliquot of diluted sample is injected
into the stripper column and analytical
column. The valve Is then deactivated for
approximately 12 minutes In which time.
the analytical column continues to be fore-
flushed, the stripper column is backflushed,
and the sample loop is refilled. Monitor the
responses. The elutlon time for each com-
pound will be determined during calibra-
tion.
12.4.1.2 Analysis of High-Molecular
Weight Sulfur Compounds. The procedure
is essentially the same as above except that
no stripper column is needed.
13. Bibliography.
13.1 O'Keeffe, A. E. and G. C. Ortman.
"Primary Standards for Trace Gas Analy-
KDf HAL IKMSTtt, VOL 41, NO. >7TNUtSOAY, HMUARY S3,
IV-230
-------
IULES AND REGULATIONS
ill." Analytical Chemical Journal, 38,760 Compounds Related to Kraft Mill Activi- 13.5 Grimley, K. W., W. S. Smith, and R.
(1966). ties." Presented at the 12th Conference on M. Martin. "The Use of a Dynamic Dilution
13.2 Stevens, R. K., A. E. O'Keeffe, and Methods in Air Pollution and Industrial Hy- System in the Conditioning of Stack Oases
O. C. Oilman. "Absolute Calibration of a gtene Studies, University of Southern Cali- for Automated Analysis by a Mobile Sam-
Flame Photometric Detector to Volatile fornia, Los Angeles, CA. April 6-8, 1971. pling Van." Presented at the 63rd Annual
Sulfur Compounds at Sub Part-Per-MUlion ., n-.,..,., n w R <= Sprpnius and APCA Meeting in St. Louis, Mo. June 14-19,
Levels." Environmental Science and Tech- A13'4 Devonald, R. H., R. S. berenlus^ ana ^^
oology, 3:7 (July, 1969). A- D- Mclntyre. "Evaluation of the Flame 13 6 General Reference. Standard Meth-
13.3 Mulick, J. D., R. K. Stevens, and R. Photometric Detector for Analysis of Sulfur o^ of chemical Analysis Volume III A and
Baumgardner. "An Analytical System De- Compounds." Pulp and Paper Magazine of B Instrumental Methods. Sixth Edition.
icned to Measure Multiple Malodorous Canada, 73,3 (March. 1972). Van Nostrand Reinhold Co.
FEDERAL REGISTER, VOL 43, NO. VTHURSDAY, KMUAftY 23, 1978
IV-231
-------
RULES AND REGULATIONS
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IV-232
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RULES AND REGULATIONS
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FEDESAl REGISTER, VOL. 43, NO. 37 -THURSDAY, FFBP.UARY 23, 1978
IV-234
-------
RULES AND REGULATIONS
TO INSTRUMENTS
AND
DILUTION SYSTEM
CONSTANT
TEMPERATURE
BATH
THERMOMETER
FLOWMETER
DRIER
DILUENT
A0'g
NITROGEN
STIRRER
GLASS
CHAMBER
PERMEATION
TUBE
Figure 16-4. Apparatus for field calibration.
FEDERAL REGISTER, VOL. 43, NO. 37-THURSDAY, FEBRUARY 23, 1978
IV-235
-------
RULES AND REGULATIONS
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FEDERAL REGISTER, VOL. 43, NO. 37THURSDAY, FEBRUARY 73, 1978
IV-236
-------
METHOD 17. DETERMINATION OF PARTICOLATE
EMISSIONS FROM STATIONARY SOURCES (IN-
STACK FILTRATION METHOD)
Introduction
Particulate matter is not an absolute
quantity; rather, it is a function of tempera-
ture and pressure. Therefore, to prevent
variability in particulate matter emission
regulations and/or associated test methods,
the temperature and pressure at which par-
ticulate matter is to be measured must be
carefully defined. Of the two variables (i.e.,
temperature and pressure), temperature has
the greater effect upon the amount of par-
ticulate matter in an effluent gas stream; in
most stationary source categories, the effect
of pressure appears to be negligible.
In method 5, 250' P is established as a
nominal reference temperature. Thus,
where Method 5 is specified m an applicable
subpart of the standards, particulate matter
is defined with respect to temperature. In
order to maintain a collection temperature
of 250° F, Method 5 employs a heated glass
RULES AND REGULATIONS
sample probe and a heated filter holder.
This equipment is somewhat cumbersome
and requires care in its operation. There-
fore, where particulate matter concentra-
tions (over the normal range of temperature
associated with a specified source category)
are known to be independent of tempera-
ture, it is desirable to eliminate the glass
probe and heating systems, and sample at
stack temperature.
This method describes an in-stack sam-
pling system and sampling procedures for
use in such cases. It is intended to be used
only when specified by an applicable sub-
part of the standards, and only within the
applicable temperature limits (if specified),
or when otherwise approved by the Admin-
istrator.
1. Principle and Applicability.
1.1 Principle. Particulate matter is with-
drawn isokinetically from the source and
collected on a glass fiber filter maintained
at stack temperature. The particulate mass
is determined gravimetrically after removal
of uncombined water.
1.2 Applicability. This method applies to
the determination of particulate emissions
from stationary sources for determining
compliance with new source performance
standards, only when specifically provided
for in an applicable subpart of the stan-
dards. This method is not applicable to
stacks that contain liquid droplets or are
saturated with water vapor. In addition, this
method shall not be used as written if the
projected cross-sectional area of the probe
extension-filter holder assembly covers
more than 5 percent of the stack cross-sec-
tional area (see Section 4.1.2).
2. Apparatus.
2.1 Sampling Tram. A schematic of the
sampling train used in this method is shown
in Figure 17-1. Construction details for
many, but not all, of the train components
are given in APTD-0581 (Citation 2 in Sec-
tion 7); for changes from the APTD-0581
document and for allowable modifications
to Figure 17-1, consult with the Administra-
tor.
FEDERAL REGISTER, VOL 43, NO. 37THURSDAY, FEBRUARY 23, 197S
IV-237
-------
RULES AND REGULATIONS
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FEDERAL REGISTER, VOL. 43, NO. 37THURSDAY, FEBRUARY 23, 1978
IV-238
-------
RULES AND REGULATIONS
The operating and maintenance proce-
dures for many of the sampling train com-
ponents are described in APTD-0576 (Cita-
tion 3 In Section 7). Since correct usage is
Important In obtaining valid results, all
users should read the APTD-0576 document
and adopt the operating and maintenance
procedures outlined in it, unless otherwise
specified herein. The sampling train con-
sists of the following components:
2.1.1 Probe Nozzle. Stainless steel (316)
or glass, with sharp, tapered leading edge.
The angle of taper shall be 030° and the
taper shall be on the outside to preserve a
constant internal diameter. The probe
nozzle shall be of the button-hook or elbow
design, unless otherwise specified by the Ad-
ministrator. If made of stainless steel, the
nozzle shall be constructed from seamless
tubing. Other materials of construction may
be used subject to the approval of the Ad-
ministrator.
A range of sizes suitable for isokinetic
sampling should be available, e.g., 0.32 to
1.27 cm (Vi to V4 in)«r larger if higher
volume sampling trains are usedinside di-
ameter (ID) nozzles in increments of 0.16 cm
(Vi« in). Each nozzle shall be calibrated ac-
cording to the procedures outlined in Sec-
tion 5.1.
2.1.2 Filter Holder. The in-stack filter
holder shall be constructed of borosilicate
or quartz glass, or stainless steel; if a gasket
is used, it shall be made of silicone rubber,
Teflon, or stainless steel. Other holder and
gasket materials may be used subject to the
approval of the Administrator. The filter
holder shall be designed to provide a posi-
tive seal against leakage from the outside or
around the filter.
2.1.3 Probe Extension. Any suitable rigid
probe extension may be used after the filter
holder.
2.1.4 Pilot Tube. Type S, as described in
Section 2.1 of Method 2, or other device ap-
proved by the Administrator; the pilot tube
shall be attached to the probe extension to
allow constant monitoring of the stack gas
velocity (see Figure 17-1). The impact (high
pressure) opening plane of the pilol tube
shall be even wilh or above the nozzle entry
plane during sampling (see Method 2,
Figure 2-6b). It is recommended: (1) that
the pilot tube have a known baseline coeffi-
cienl, determined as outlined in Section 4 of
Method 2; and (2) lhat this known coeffi-
cient be preserved by placing the pilot lube
in an interference-free arrangement with re-
spect lo Ihe sampling nozzle, filter holder,
and lemperature sensor (see Figure 17-1).
Nole lhat the 1.9 cm (0.75 in) free-space be-
Iween Ihe nozzle and pilot tube shown in
Figure 17-1, is based on a 1.3 cm (0.5 in) ID
nozzle. If the sampling train is designed for
sampling at higher flow rates than lhat de-
scribed in APTD-0581, Ihus necessilatmg
Ihe use of larger sized nozzles, the free-
space shall be 1.9 cm (0.75 in) with Ihe larg-
est sized nozzle in place.
Source-sampling assemblies that do not
meet the minimum spacing requirements of
Figure 17-1 (or the equivalent of these re-
quirements, e.g., Figure 2-7 of Method 2)
may be used; however, the pilot lube coeffi-
cients of such assemblies shall be deter-
mined by calibration, using methods subject
to the approval of the Administrator.
2.1.5 Differential Pressure Gauge. In-
clined manomeler or equivalent device
(two), as described in Section 2.2 of Method
2. One manometer shall be used for velocity
head (Ap) readings, and the other, for ori-
fice differential pressure readings.
2.1.6 Condenser. It is recommended that
the impinger system described in Method 5
be used to determine the moisture content
of the stack gas. Alternatively, any system
that allows measurement of both the water
condensed and the moisture leaving the con-
denser, each to wilhin 1 ml or 1 g, may be
used. The moisture leaving the condenser
can be measured either by: (1) monitoring
the temperature and pressure at the exit of
the condenser and using Dalton's law of
partial pressures; or (2) passing Ihe sample
gas stream through a silica gel trap with
exit gases kept below 20' C (68* F) and de-
termining the weight gain.
Flexible tubing may be used between the
probe extension and condenser. If means
other than silica gel are used lo delermine
the amount of moisture leaving the con-
denser, it is recommended thai silica gel still
be used belween Ihe condenser system and
pump to prevent moisture condensation in
the pump and metering devices and to avoid
the need lo make correclions for moisture
in Ihe melered volume.
2.1.7 Melering System. Vacuum gauge,
leak-free pump, thermomelers capable of
measuring temperalure lo wilhin 3' C (5.4*
F), dry gas meler capable of measuring
volume to within 2 percent, and related
equipment, as shown in Figure 17-1. Other
metering systems capable of maintaining
sampling rales within 10 percent of isokine-
tic and of determining sample volumes to
within 2 percenl may be used, subjecl lo the
approval of Ihe Administrator. When the
metering system is used in conjunction with
a pilot tube, the system shall enable checks
of isokinetic rates.
Sampling trains utilizing melering sys-
tems designed for higher flow rales than
thai described in APTD-0581 or APTD-0576
may be used provided lhal the specifica-
tions of this method are met.
2.1.8 Barometer. Mercury, aneroid, or
other barometer capable of measuring at-
mospheric pressure to within 2.5 mm Hg
(0.1 in. Hg). In many cases, the barometric
reading may be obtained from a nearby na-
tional weather service station, in which case
the stalion value (which is Ihe absolute
barometric pressure) shall be requested and
an adjustment for elevation differences be-
tween the wealher slation and sampling
point shall be applied at a rate of minus 2.5
mm Hg (0.1 in. Hg) per 30 m (100 ft) eleva-
tion increase or vice versa for elevation de-
crease.
2.1.9 Gas Density Determinalion Equip-
ment. Temperature sensor and pressure
gauge, as described in Sections 2.3 and 2.4 of
Method 2, and gas analyzer, if necessary, as
described in Method 3.
The temperature sensor shall be attached
to either the pilot tube or to the probe ex-
tension, in a fixed configuration. If the tem-
perature sensor is attached in the field; the
sensor shall be placed in an interference-
free arrangement with respect lo Ihe Type
S pilot lube openings (as shown in Figure
17-1 or in Figure 2-7 of Melhod 2). Allerna-
livelj, the temperalure sensor need not be
attached to either the probe extension or
pitol lube during sampling, provided lhal a
difference of not more than 1 percent in the
average velocity measurement is introduced.
This alternative is subject to the approval
of the Administrator.
2.2 Sample Recovery.
2.2.1 Probe Nozzle Brush. Nylon bristle
brush with stainless steel wire handle. The
brush shall be properly sized and shaped to
brush oul Ihe probe nozzle.
2.2.2 Wash BottlesTwo. Glass wash
bottles are recommended; polyethylene
wash bottles may be used at Ihe option of
the tester. It is recommended that acetone
not be stored in polyethylene bottles for
longer than a month.
2.2.3 Glass Sample Storage Containers.
Chemically resistant, borosilicate glass bot-
tles, for acetone washes, 500 ml or 1000 ml.
Screw cap liners shall eilher be rubber-
backed Teflon or shall be conslrucled so as
to be leak-free and resislanl to chemical
attack by acetone. (Narrow mouth glass bot-
tles have been found to be less prone lo
leakage.) Alternalively, polyelhylene bottles
may be used.
2.2.4 Petri Dishes. For filler samples;
glass or polyethylene, unless otherwise
specified by the Administrator.
2.2.5 Graduated Cylinder and/or Bal-
ance. To measure condensed water to within
1 ml or 1 g. Graduated cylinders shall have
subdivisions no greater than 2 ml. Most lab-
oratory balances are capable of weighing to
the nearesl 0.5 g or less. Any of Ihese bal-
ances is suitable for use here and in Seclion
2.3.4.
2.2.6 Plastic Storage Containers. Air
tight containers lo store silica gel.
2.2.7 Funnel and Rubber Policeman. To
aid in Iransfer of silica gel to conlainer; not
necessary if silica gel is weighed in Ihe field.
2.2.8 Funnel. Glass or polyethylene, lo
aid in sample recovery.
2.3 Analysis.
2.3.1 Glass Weighing Dishes.
2.3.2 Desiccator.
2.3.3 Analytical Balance. To measure to
wilhin 0.1 mg.
2.3.4 Balance. To measure lo wilhin 0.5
mg.
2.3.5 Beakers. 250 ml.
2.3.6 Hygrometer. To measure the rela-
tive humidity of the laboratory environ-
ment.
2.3.7 Temperature Gauge. To measure
the lemperature of Ihe laboratory environ-
ment.
3. Reagents.
3.1 Sampling.
3.1.1 Filters. The in-stack filters shall be
glass mats or thimble fiber filters, without
organic binders, and shall exhibit at least
99.95 percenl efficiency (00.05 percent pene-
tralion) on 0.3 micron dioctyl phthalate
smoke particles. The filter efficiency tests
shall be conducted in accordance with
ASTM standard method D 2986-71. Test
data from the supplier's quality control pro-
gram are sufficient for this purpose.
3.1.2 Silica Gel. Indicating type, 6- to 16-
mesh. If previously used, dry at 175° C (350*
F) for 2 hours. New silica gel may be used as
received. Alternatively, other types of desic-
cants (equivalent or better) may be used.
subject to the approval of the Administra-
tor.
3.1.3 Crushed Ice.
3.1.4 Stopcock Grease. Acetone-insoluble,
heat-stable silicone grease. This is not nec-
essary if screw-on connectors with Teflon
sleeves, or similar, are used. Alternatively.
olher lypes of stopcock grease may be used,
subject to Ihe approval of Ihe Adminislra-
tor.
3.2 Sample Recovery. Acetone, reagent
grade, 00.001 percent residue, in glass bot-
tles. Acetone from metal containers general-
ly has a high residue blank and should not
be used. Sometimes, suppliers transfer ac-
etone to glass bottles from metal containers.
Thus, acetone blanks shall be run prior to
field use and only acetone with low blank
FEDERAL REGISTER, VOL. 43, NO. 37THURSDAY, FEBRUARY 23, 1978
IV-239
-------
RULES AND REGULATIONS
values (00.001 percent) shall be used. In no
case shall a blank value of greater than
0.001 percent of the weight of acetone used
be subtracted from the sample weight.
3.3 Analysis.
3.3.1 Acetone. Same as 3.2.
3.3.2 Desiccant. Anhydrous calcium sul-
fate, indicating type. Alternatively, other
types of desiccants may be used, subject to
the approval of the Administrator.
4. Procedure.
4.1 Sampling. The complexity of this
method is such that, in order to obtain reli-
able results, testers should be trained and
experienced with the test procedures.
4.1.1 Pretest Preparation. All compo-
nents shall be maintained and calibrated ac-
cording to the procedure described In
APTD-0576, unless otherwise specified
herein.
Weigh several 200 to 300 g portions of
silica gel in air-tight containers to the near-
est 0.5 g. Record the total weight of the
silica gel plus container, on each container.
As an alternative, the silica gel need not be
preweighed, but may be weighed directly In
its impinger or sampling holder just prior to
train assembly.
Check filters visually against light for ir-
regularities and flaws or pinhole leaks.
Label filters of the proper size on the back
side near the edge using numbering ma-
chine ink. As an alternative, label the ship-
ping containers (glass or plastic petrl dishes)
and keep the filters in these containers at
all times except during sampling and weigh-
ing.
Desiccate the filters at 20±5.6° C <68±10'
P) and ambient pressure for at least 24
hours and weigh at intervals of at least 6
hours to a constant weight, i.e., 00.5 mg
change from previous weighing; record re-
sults to the nearest 0.1 mg. During each
weighing the filter must not be exposed to
the laboratory atmosphere for a period
greater than 2 minutes and a relative hu-
midity above 50 percent. Alternatively
(unless otherwise specified by the Adminis-
trator), the filters may be oven dried at 105°
C (220° F) for 2 to 3 hours, desiccated for 2
hours, and weighed. Procedures other than
those described, which account for relative
humidity effects, may be used, subject to
the approval of the Administrator.
4.1.2 Preliminary Determinations. Select
the sampling site and the minimum number
of sampling points according to Method 1 or
as specified by the Administrator. Make a
projected-area model of the probe exten-
sion-filter holder assembly, with the pilot
tube face openings positioned along the cen-
terline of the stack, as shown in Figure 17-2.
Calculate the estimated cross-section block-
age, as shown in Figure 17-2. If the blockage
exceeds 5 percent of the duct cross sectional
area, the tester has the following options:
(Da suitable out-of-stack filtration method
may be used instead of in-stack filtration; or
(2) a special in-stack arrangement, in which
the sampling and velocity measurement
sites are separate, may be used; for details
concerning this approach, consult with the
Administrator (see also Citation 10 in Sec-
tion 7). Determine the stack pressure, tem-
perature, and the range of velocity heads
using Method 2; it is recommended that a
leak-check of the pilot lines (see Method 2,
Section 3.1) be performed. Determine the
moisture' content using Approximation
Method 4 or its alternatives for the purpose
of making isokinetic sampling rate settings.
Determine the stack gas dry molecular
weight, as described in Method 2, Section
3.6; If integrated Method 3 sampling is used
for molecular weight determination, the in-
tegrated bag sample shall be taken simulta-
neously with, and for the same total length
of time'as, the particular sample run.
FfDERAl RKMSTtR, VOL 43, NO. 37THURSDAY, REMUARY 23, 1978
IV-240
-------
RULES AND REGULATIONS
STACK
WALL
IN STACK FILTER
PROBE EXTENSION
ASSEMBLY
ESTIMATED
BLOCKAGE
fsHADED AREA]
L DUCT AREAJ
X 100
Figure 17-2. Projected-area model of cross-section blockage (approximate average for
a sample traverse) caused by an in-stack filter holder-probe extension assembly.
FEDERAL REGISTER, VOl. 43, NO. 37THURSDAY, KMUARY S3, 1978
IV-241
-------
RULES AND REGULATIONS
Select a nozzle size based on the range of
velocity heads, such that it is not necessary
to change the nozzle size in order to main-
tain isokinetic sampling rates. During the
run, do not change the nozzle size. Ensure
that the proper differential pressure gauge
is chosen for the range of velocity heads en-
countered (see Section 2.2 of Method 2).
Select a probe extension length such that
all traverse points can be sampled. For large
stacks, consider sampling from opposite
sides of the stack to reduce the length of
probes.
Select a total sampling time greater than
or equal to the minimum total sampling
time specified in the test procedures for the
specific industry such that (1) the sampling
time per point is not less than 2 minutes (or
some greater time interval if specified by
the Administrator), and (2) the sample
volume taken (corrected to standard condi-
tions) will exceed the required minimum
total gas sample volume. The latter is based
on an approximate average sampling rate.
It is recommended that the number of
minutes sampled at each point be an integer
or an integer plus one-half minute, in order
to avoid timekeeping errors.
In some circumstances, e.g., batch cycles,
it may be necessary to sample for shorter
times at the traverse points and to obtain
smaller gas sample volumes. In these cases,
the Administrator's approval must first be
obtained.
4.1.3 Preparation of Collection Train.
During preparation and assembly of the
sampling train, keep all openings where con-
tamination can occur covered until just
prior to assembly or until sampling is about
to begin.
If impingers are used to condense stack
gas moisture, prepare them as follows: place
100 ml of water in each of the first two im-
pingers, leave the third impinger empty,
and transfer approximately 200 to 300 g of
preweighed silica gel from its container to
the fourth impinger. More silica gel may be
used, but care should be taken to ensure
that it is not entrained and carried out from
the impinger during sampling. Place the
container in a clean place for later use in
the sample recovery. Alternatively, the
weight of the silica gel plus impinger may
be determined to the nearest 0.5 g and re-
corded.
If some means other than impingers is
used to condense moisture, prepare the con-
denser (and, if appropnate, silica gel for
condenser outlet) for use.
Using a tweezer or clean disposable surgi-
cal gloves, place a labeled (identified) and
weighed filter in the filter holder. Be sure
that the filter is properly centered and the
gasket properly placed so as not to allow the
sample gas stream to circumvent the filter.
Check filter for tears after assembly is com-
pleted. Mark the probe extension with heat
resistant tape or by some other method to
denote the proper distance into the stack or
duct for each sampling point.
Assemble the train as in Figure 17-1, using
a very light coat of silicone grease on all
ground glass joints and greasing only the
outer portion (see APTD-0576) to avoid pos-
sibility of contamination by the silicone
grease. Place crushed Ice around the im-
pingers.
4.1.4 Leak Check Procedures.
4.1.4.1 Pretest Leak-Check. A pretest
leak-check is recommended, but not re-
quired. If the tester opts to conduct the pre-
test leak-check, the following procedure
shall be used.
After the sampling train has been assem-
bled, plug the inlet to the probe nozzle with
a material that will be able to withstand the
stack temperature. Insert the filter holder
into the stack and wait approximately 5
minutes (or longer, if necessary) to allow
the system to come to equilibrium with the
temperature of the stack gas stream. Turn
on the pump and draw a vacuum of at least
380 .mm Hg (15 in. Hg); note that a lower
vacuum may be used, provided that it Is not
exceeded during the test. Determine the
leakage rate. A leakage rate In excess of 4
percent of the average sampling rate or
0.00057 m'/min. (0.02 cfm), whichever is
less, is unacceptable.
The following leak-check Instructions for
the sampling train described in APTD-0576
and APTD-0581 may be helpful. Start the
pump with by-pass valve fully open and
coarse adjust valve completely closed. Par-
tially open the coarse adjust valve and
slowly -close the by-pass valve until the de-
sired vacuum Is reached. Do not reverse di-
rection of by-pass valve. If the desired
vacuum is exceeded, either leak-check at
this higher vacuum or end the leak-check as
shown below and start over.
When the leak-check is completed, first
slowly remove the plug from the inlet to the
probe nozzle and immediately turn off the
vacuum pump. This prevents water from
being forced backward and keeps silica gel
from being entrained backward.
4.1.4.2 Leak-Checks During Sample Run.
If, during the sampling run, a component
(e.g., filter assembly or impinger) change be-
comes necessary, a leak-check shall be con-
ducted immediately before the change is
made. The leak-check shall be done accord-
Ing to the procedure outlined in Section
4.1.4.1 above, except that it shall be done at
a vacuum equal to or greater than the maxi-
mum value recorded up to that point in the
test. If the leakage rate is found to be no
greater than 0.00057 m'/min (0.02 cfm) or 4
percent of the average sampling rate
(whichever is less), the results are accept-
able, and no correction will need to be ap-
plied to the total volume of dry gas metered;
if, however, a higher leakage rate Is ob-
tained, the tester shall either record the
leakage rate and plan to -correct the sample
volume as shown in Section 6.3 of this
method, or shall void the sampling run.
Immediately after component changes,
teak-checks are optional; if such leak-checks
are done, the procedure outlined in Section
4.1.4.1 above shall be used.
4.1.4.3 Post-Test LeaK-Check. A leak-
check is mandatory at the conclusion of
each sampling run. The leak-check shall be
done in accordance with the procedures out-
lined in Section 4.1.4.1, except that it shall
be conducted at a vacuum equal to or great-
er than the maximum value reached during
the sampling run. If the leakage rate is
found to be no greater than 0.00057 m'/min
(0.02 cfm) or 4 percent of the average sam-
pling rate (whichever is less), the results are
acceptable, and no correction need be ap-
plied to the total volume of dry gas metered.
If, however, a higher leakage rate is ob-
tained, the tester shall either record the
leakage rate and correct the sample volume
as shown in Section 6.3 of this method, or
shall void the sampling run.
4.1.5 Paniculate Tram Operation.
During the sampling run, maintain a sam-
pling rate such that sampling is within 10
percent of true isokinetic, unless otherwise
specified by the Administrator.
For each run, record the data required on
the example data sheet shown in Figure 17-
3. Be sure to record the initial dry gas meter
reading. Record the dry gas meter readings
at the beginning and end of each sampling
time Increment, when changes in flow rates
are made, before and after each leak check,
and when sampling is halted. Take other
readings required by Figure 17-3 at least
once at each sample point during each time
increment and additional readings when sig-
nificant changes (20 percent variation in ve-
locity head readings) necessitate additional
adjustments in flow rate. Level and zero the
manometer. Because the manometer level
and zero may drift due to vibrations and
temperature changes, make periodic checks
during the traverse.
FEDERAL REGISTER, VOL. 43, NO. 37THURSDAY, FEBRUARY 23, 1978
IV-242
-------
RULES AND REGULATIONS
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FEDERAL REGISTER, VOL. 43, NO. 37THURSDAY, FEBRUARY 23, 1978
IV-243
-------
RULES AND REGULATIONS
Clean the portholes prior to the test run
to minimize the chance of sampling the de-
posited material. To begin sampling, remove
the nozzle cap and verify that the pitot tube
and probe extension are properly posi-
tioned. Position the nozzle at the first tra-
verse point with the tip pointing directly
Into the gas stream. Immediately start the
pump and adjust the flow to isokinetic con-
ditions. Nomographs are available, which
aid in the rapid adjustment to the isokinetic
sampling rate without excessive computa-
tions. These nomographs are designed for
use when the Type S pitot tube coefficient
is 0.85 ±0.02, and the stack gas equivalent
density (dry molecular weight) is equal to
29 ±4. APTD-0576 details the procedure for
using the nomographs. If C» and M« are out-
side the above stated ranges, do not use the
nomographs unless appropriate steps (see
Citation 7 in Section 7) are taken to com-
pensate for the deviations.
When the stack is under significant nega-
tive pressure (height of impinger stem),
take care to close the coarse adjust valve
before inserting the probe extension assem-
bly into the stack to prevent water from
being forced backward. If necessary, the
pump may be turned on with the coarse
adjust valve closed.
When the probe is in position, block off
the openings around the probe and porthole
to prevent unrepresentative dilution of the
gas stream.
Traverse the stack cross section, as re-
quired by Method 1 or as specified by the
Administrator, being careful not to bump
the probe nozzle into the stack walls when
sampling near the walls or when removing
or inserting the probe extension through
the portholes, to minimize chance of ex-
tracting deposited material.
During the test run, take appropriate
steps (e.g., adding crushed ice to the im-
pinger ice bath) to maintain a temperature
of less than 20° C (68* F) at the condenser
outlet; this will prevent excessive moisture
losses. Also, periodically check the level and
zero of the manometer.
If the pressure drop across the filter be-
comes too high, making isokinetic sampling
difficult to maintain, the filter may be re-
placed in the midst of a sample run. It is
recommended that another complete filter
holder assembly be used rather than at-
tempting to change the filter itself. Before a
new filter holder is installed, conduct a leak
check, as outlined in Section 4.1.4.2. The
total particulate weight shall include the
summation of all filter assembly catches.
A single train shall be used for the entire
sample run, except in cases where simulta-
neous sampling is required in two or more
separate ducts or at two or more different
locations within the same duct, or, in cases
where equipment failure necessitates a
change of trains. In all other situations, the
use of two or more trains will be subject to
the approval of the Administrator. Note
that when two or more trains are used, a
separate analysis of the collected particu-
late from each train shall be performed,
unless identical nozzle sizes were used on all
trains, in which case the particulate catches
from the individual trains may be combined
and a single analysis performed.
At the end of the sample run, turn off the
pump, remove the probe extension assembly
from the stack, and record the final dry gas
meter reading. Perform a leak-check, as out-
lined in Section 4.1.4.3. Also, leak-check the
pitot lines as described in Section 3.1 of
Method 2; the lines must pass this leak-
check, in order to validate the velocity head
data.
4.1.6 Calculation of Percent Isokinetic.
Calculate percent isokinetic (see Section
6.11) to determine whether another test run
should be made. If there is difficulty in
maintaining isokinetic rates due to source
conditions, consult with the Administrator
for possible variance on the isokinetic rates.
4.2 Sample Recovery. Proper cleanup
procedure begins as soon as the probe ex-
tension assembly is removed from the stack
at the end of the sampling period. Allow the
assembly to cool.
When the assembly can be safely handled,
wipe off all external particulate matter near
the tip of the probe nozzle and place a cap
over it to prevent losing or gaining particu-
late matter. Do not cap off the probe tip
tightly while the sampling ,train is cooling
down as this would create a vacuum in the
filter holder, forcing condenser water back-
ward.
Before moving th« sample train to the
cleanup site, disconnect the filter holder-
probe nozzle assembly from the probe ex-
tension; cap the open inlet of the probe ex-
tension. Be careful not to lose any conden-
sate, if present. Remove the umbilical cord
from the condenser outlet and cap the
outlet. If a flexible line is used between the
first impinger (or condenser) and the probe
extension, disconnect the line at the probe
extension and let any condensed water or
liquid drain into the impingers or condens-
er. Disconnect the probe extension from the
condenser; cap the probe extension outlet.
After wiping off the silicone grease, cap off
the condenser inlet. Ground glass stoppers,
plastic caps, or serum caps (whichever are
appropriate) may be used to close these
openings.
Transfer both the filter holder-probe
nozzle assembly and the condenser to the
cleanup area. This area should be clean and
protected from the wind so that the chances
of contaminating or losing the sample will
be minimized.
Save a portion of the acetone used for
cleanup as a blank. Take 200 ml of this ac-
etone directly from the wash bottle being
used and place it in a glass sample container
labeled "acetone blank."
Inspect the train prior to and during dis-
assembly and note any abnormal conditions.
Treat the samples as follows:
Container No. 1. Carefully remove the
filter from the filter holder and place it in
its identified petri dish container. Use a pair
of tweezers and/or clean disposable surgical
gloves to handle the filter. If it is necessary
to fold the filter, do so such that the partic-
ulate cake is inside the fold. Carefully trans-
fer to the petri dish any particulate matter
and/or filter fibers which adhere to the
filter holder gasket, by using a dry Nylon
bristle brush and/or a sharp-edged blade.
Seal the container.
Container No. 2. Taking care to see that
dust on the outside of the probe nozzle or
other exterior surfaces does not get into the
sample, quantitatively recover particulate
matter or any condensate from the probe
nozzle, fitting, and front half of the filter
holder by washing these components with
acetone and placing the wash to a glass con-
tainer. Distilled water may be used instead
of acetone when approved by the Adminis-
trator and shall be used when specified by
the Administrator; in these cases, save a
water blank and follow Administrator's di-
rections on analysis. Perform the acetone
rinses as follows:
Carefully remove the probe nozzle and
clean the inside surface by rinsing with ac-
etone from a wash bottle and brushing with
a Nylon bristle brush. Brush until acetone
rinse shows no visible particles, after which
make a final rinse of the inside surface with
acetone.
Brush and rinse with acetone the inside
parts of the fitting in a similar way until no
visible particles remain. A funnel (glass or
polyethylene) may be used to aid in trans-
ferring liquid washes to the container. Rinse
the brush with acetone and quantitatively
collect these washings in the sample con-
tainer. Between sampling runs, keep
brushes clean and protected from contami-
nation.
After ensuring that all joints are wiped
clean of silicone grease (if applicable), clean
the inside of the front half of the filter
holder by rubbing the surfaces with a Nylon
bristle brush and rinsing with acetone.
Rinse each surface three times or more if
needed to remove visible particulate. Make
final rinse of the brush and filter holder.
After all acetone washings and particulate
matter are collected in the sample contain-
er, tighten the lid on the sample container
so that acetone will not leak out when it is
shipped to the laboratory. Mark the height
of the fluid level to determine whether or
not leakage occurred during transport.
Label the container to clearly identify its
contents.
Container No. 3. if silica gel is used in the
condenser system for mositure content de-
termination, note the color of the gel to de-
termine if it has been completely spent;
make a notation of its condition. Transfer
the silica gel back to its original container
and seal. A funnel may make it easier to
pour the silica gel without spilling, and a
rubber policeman may be used as an aid in
removing the silica gel. It is not necessary to
remove the small amount of dust particles
that may adhere to the walls and are diffi-
cult to remove. Since the gain in weight is to
be used for moisture calculations, do not use
any water or other liquids to transfer the
silica gel. If a balance is available in the
field, follow the procedure for Container
No. 3 under "Analysis."
Condenser Water. Treat the condenser or
impinger water as follows: make a notation
of any color or film in the liquid catch. Mea-
sure the liquid volume to within ±1 ml by
using a graduated cylinder or, if a balance is
available, determine the liquid weight to
within ±0.5 g. Record the total volume or
weight of liquid present. This information is
required to calculate the moisture content
of the effluent gas. Discard the liquid after
measuring and recording the volume or
weight.
4.3 Analysis. Record the data required on
the example sheet shown in Figure 17-4.
Handle each sample container as follows:
Container No. 1. Leave the contents in the
shipping container or transfer the filter and
any loose particulate from the sample con-
tainer to a tared glass weighing dish. Desic-
cate for 24 hours in a desiccator containing
anhydrous calcium sulfate. Weigh to a con-
stant weight and report the results to the
nearest 0.1 mg. For purposes of this Section,
4.3, the term "constant weight" means a dif-
ference of no more than 0.5 mg or 1 percent
of total weight less tare weight, whichever is
greater, between two consecutive weighings.
with no less than 6 hours of desiccation
time between weighings.
Alternatively, the sample may be oven
dried at the average stack temperature or
FEDERAL REGISTER, VOL. 43, NO. 37THURSDAY, FEBRUARY 23, 1978
IV-244
-------
RULES AND REGULATIONS
105° C (220° F), whichever is less, for 2 to 3 tied by the Administrator. The tester may whichever is less, for 2 to 3 hours, weigh the
hours, cooled in the desiccator, and weighed also opt to oven dry the sample at the aver- sample, and use this weight as a final
to a constant weight, unless otherwise speci- age stack temperature or 105° C (220* P), weight.
Plant.
Date.
Run No..
Filter No.
Amount liquid lost during transport
Acetone blank volume, ml
Acetone wash volume, ml
Acetone black concentration, mg/mg (equation 174)
Acetone wash blank, mg (equation 17-5)
CONTAINER
NUMBER
1
2
TOTAL
WEIGHT OF PARTICULATE COLLECTED.
mg
FINAL WEIGHT
Z^x^
TARE WEIGHT
^x^
Less acetone blank
Weight of parti cut ate matter
WEIGHT GAIN
FINAL
INITIAL
LIQUID COLLECTED
TOTAL VOLUME COLLECTED
VOLUME OF LIQUID
WATER COLLECTED
IMPINGER
VOLUME.
ml
SILICA GEL
WEIGHT,
9
g* ml
* CONVERT WEIGHT OF WATER TO VOLUME BY DIVIDING TOTAL WEIGHT
INCREASE BY DENSITY OF WATER (1g/ml).
INCREASE- 9 ^ VOLUME WATER, ml
1 g/ml
Figure 17-4. Analytical data.
FEDERAL REGISTER, VOL. 43, NO. 37THURSDAY, FEBRUARY 33, 1978
IV-245
-------
RULES AND REGULATIONS
Container No. 2. Note the level of liquid in
the container and confirm on the analysis
sheet whether or not leakage occurred
during transport. If a noticeable amount of
leakage has occurred, either void the sample
or use methods, subject to the approval of
the Administrator, to correct the final re-
sults. Measure the liquid in this container
either volumetrically to ±1 ml or gravime-
trically to ±0.5 g. Transfer the contents to a
tared 250-ml beaker and evaporate to dry-
ness at ambient temperature and pressure.
Desiccate for 24 hours and weigh to a con-
stant weight. Report the results to the near-
est 0.1 mg.
Container No. 3. This step may be con-
ducted in the field. Weigh the spent silica
gel (or silica gel plus impinger) to the near-
est 0.5 g using a balance.
"Acetone Blank" Container. Measure ac-
etone in this container either volumetrically
or gravimetrically. Transfer the acetone to a
tared 250-ml beaker and evaporate to dry-
ness at ambient temperature and pressure.
Desiccate for 24 hours and weigh to a con-
stant weight. Report the results to the near-
est 0.1 mg.
NOTE.At the option of the tester, the
contents of Container No. 2 as well as the
acetone blank container may be evaporated
at temperatures higher than ambient. If
evaporation is done at an elevated tempera-
ture, the temperature must be below the
boiling point of the solvent; also, to prevent
"bumping," the evaporation process must be
closely supervised, and the contents of the
beaker must be swirled occasionally to
maintain an even temperature. Use extreme
care, as acetone is highly flammable and
has a low flash point.
5. Calibration. Maintain a laboratory log
of all calibrations.
5.1 Probe Nozzle. Probe nozzles shall be
calibrated before their initial use in the
field. Using a micrometer, measure the
inside diameter of the nozzle to the nearest
0.025 mm (0.001 in.). Make three separate
measurements using different diameters
each time, and obtain the average of the
measurements. The difference between the
high and low numbers shall not exceed 0.1
mm (0.004 in.). When nozzles become
nicked, dented, or corroded, they shall be
reshaped, sharpened, and recalibrated
before use. Each nozzle shall be permanent-
ly and uniquely identified.
5.2 Pitot Tube. If the pitot tube is placed
in an Interference-free arrangement with re-
spect to the other probe assembly compo-
nents, its baseline (isolated tube) coefficient
shall be determined as outlined in Section 4
of Method 2. If the probe assembly is not in-
terference-free, the pitot tube assembly co-
efficient shall be determined by calibration,
using methods subject to the approval of
the Administrator.
5.3 Metering System. Before its initial
use in the field, the metering system shall
be calibrated According to the procedure
outlined in APTD-0576. Instead of physical-
ly adjusting the dry gas meter dial readings
to correspond to the wet test meter read-
ings, calibration factors may be used to
mathematically correct the gas meter dial
readings to the proper values.
Before calibrating the metering system, it
is suggested that a leak-check be conducted.
For metering systems having diaphragm
pumps, the normal leak-check procedure
will not detect leakages within the pump.
For these cases the following leak-check
procedure is suggested: make a 10-minute
calibration run at 0.00057 m'/rain (0.02
cfm); at the end of the run, take the differ-
ence of the measured wet test meter and
dry gas meter volumes; divide the difference
by 10, to get the leak rate. The leak rate
should not exceed 0.00057 m'/mln (0.02
cfm).
After each field use, the calibration of the
metering system shall be checked by per-
forming three calibration runs at a single,
intermediate orifice setting (based on the
previous field test), with the vacuum set at
the maximum value reached during the test
series. To adjust the vacuum, insert a valve
between the wet test meter and the inlet of
the metering system. Calculate the average
value of the calibration factor. If the cali-
bration has changed by more than 5 per-
cent, recalibrate the meter over the full
range of orifice settings, as outlined in
APTD-0576.
Alternative procedures, e.g., using the ori-
fice meter coefficients, may be used, subject
to the approval of the Administrator.
NOTE.If the dry gas meter coefficient
values obtained before and after a test
series differ by more than 5 percent, the
test series shall either be voided, or calcula-
tions for the test series shall be performed
using whichever meter coefficient value
(i.e., before or after) gives the lower value of
total sample volume.
5.4 Temperature Gauges. Use the proce-
dure in Section 4.3 of Method 2 to calibrate
in-stack temperature gauges. Dial thermom-
eters, such as are used for the dry gas meter
and condenser outlet, shall be calibrated
against mercury-in-glass thermometers.
5.5 Leak Check of Metering System
Shown in Figure 17-1. That portion of the
sampling train from the pump to the orifice
meter should be leak checked prior to initial
use and after each shipment. Leakage after
the pump will result in less volume being re-
corded than is actually sampled. The follow-
ing procedure is suggested (see Figure 17-5).
Close the main valve on the meter box.
Insert a one-hole rubber stopper with
rubber tubing attached into the orifice ex-
haust pipe. Disconnect and vent the low side
of the orifice manometer. Close off the low
side orifice tap. Pressurize the system to 13
to 18 cm (5 to 1 in.) water column by blow-
ing into the rubber tubing. Pinch off the
tubing and observe the manometer for one
minute. A loss of pressure on the mano-
meter indicates a leak in the meter box;
leaks, if present, must be corrected.
FEDERAL REGISTER, VOL. 43, NO. 37THURSDAY, FEBRUARY 23, 1978
IV-246
-------
RULES AND REGULATIONS
x
o
.Q
t.
0)
4-*
O)
E
.
I
o
0>
_l
in
o>
.1
u.
FEDERAL REGISTER, VOL. 43, NO. 37THURSDAY, FEBRUARY 23, 1978
IV-247
-------
RULES AND REGULATIONS
5.6 Barometer. Calibrate against a mer-
cury barometer.
6. Calculations. Carry out calculations, re-
taining at least one extra decimal figure
beyond that of the acquired data. Round off
figures after the final calculation. Other
forms of the equations may be used as long
as they give equivalent results.
6.1 Nomenclature.
A*=Cross-sectional area of nozzle, m* (ft1).
Bw,=Wn'ter t'ai/»i in the gas stream, propor-
tion by volume.
C.=Acetone blank residue concentration.
mg/g.
c.=Concentration of participate matter in
stack gas, dry basis, corrtv.v»d to stan-
dard condition*, g/dscm (g/dst{).
I« Percent of isokinetic sampling
L.= Maximum acc..-tnl>le leakage rate for
either a pretest leak «heck or for a leak
.check following a compo^t change;
tequ&l to 0.00057 m'/mlr (0 02 cfm) Or 4
= Volume of gas sample measured by
the dry gas meter, corrected to standard
conditions, dscm (dscf).
V^,un = Volume of water vapor in the gas
sample, corrected to standard condi-
tions, scm (scf).
v.=Stack gas velocity, calculated by Method
2, Equation 2-9, using data obtained
from Method 17, m/sec (ft/sec).
W.=Weight of residue in acetone wash, mg.
Y = Dry gas meter calibration coefficient.
AH = Average pressure differential across
the orifice meter (see Figure 17-3), mm
H,O (in. H,O).
p. = Density of acetone, mg/ml (see label on
bottle).
=,=Density of water, 0.9982 g/ml (0.002201
Ib/ml).
6=Total sampling time, min.
6, = Sampling time interval, from the begin-
ning of a run until the first component
change, min.
9,=Sampling time interval, between two
successive component changes, begin-
ning with the interval between the first
and second changes, min.
«,=Sampling time Interval, from the final
-------
1. Addendum to Specifications for Inciner-
ator Testing at Federal Facilities. PHS.
NCAPC. December 6, 1967.
2. Martin. Robert M., Construction Details
of Isokinetic Source-Sampling Equipment.
Environmental Protection Agency. Re-
search Triangle Park, N.C. APTD-0581.
April, 1971.
3. Rom, Jerome J., Maintenance, Calibra-
tion, and Operation of Isokinetic Source-
Sampling Equipment. Environmental Pro-
tection Agency. Research Triangle Park,
N.C. APTD-0576. March. 1972.
4. Smith, W. S., R. T. Shigehara, and W.
F. Todd. A Method of Interpreting Stack
Sampling Data. Paper Presented at the 63rd
Annual Meeting of the Air Pollution Con-
trol Association, St. Louis, Mo. June 14-19,
1970.
5. Smith. W. S., et al.. Stack Gas Sampling
Improved and Simplified with New Equip-
ment. APCA Paper No. 87-119. 1967.
6. Specifications for Incinerator Testing at
Federal Facilities. PHS. NCAPC. 1967.
7. Shigehara, R. T., Adjustments in the
EPA Nomograph for Different Pilot Tube
Coefficients and Dry Molecular Weights.
Stack Sampling News 2:4-11. October, 1974.
8. Vollaro, R. P., A Survey of Commercial-
ly Available Instrumentation for the Mea-
surement of Low-Range Gas Velocities. U.S.
Environmental Protection Agency, Emission
Measurement Branch. Research Triangle
Park, N.C. November, 1976 (unpublished
paper).
9. Annual Book of ASTM Standards. Part
36. Gaseous Fuels; Coal and Coke; Atmo-
spheric Analysis. American Society for Test-
Ing and Materials. Philadelphia, Pa. 1974.
pp. 617-622.
10. Vollaro, R. P., Recommended Proce
dure for Sample Traverses in Ducts Smaller
than 12 Inches in Diameter f.o. environ-
mental Protection Armey. Emission Mea-
surement Branch. Research Triangle Park,
N.C. November, 1^76.
[PR Doc. 78-t795 Filed 2-22-78; 8:45 am]
FEDERAL REGISTER, VOL. 43, NO. 37
THURSDAY, FEBRUARY 23, 1978
RULES AND REGULATIONS
3
Title 40 Protection of Environment
CFRL 848-2]
CHAPTER I ENVIRONMENTAL
PROTECTION AGENCY
PART 60 STANDARDS OF PERFOR-
MANCE FOR NEW STATIONARY
SOURCES
PART 61 NATIONAL EMISSION
STANDARDS FOR HAZARDOUS AIR
POLLUTANTS
Revision of Authority Citations
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Final rule.
SUMMARY: This action abends the
authority dilations for Standards of
Performance for New Stationary
Sources and National Emission Stan-
tards for Hazardous Pollutants. The
amendment adopts the redesignation
of classification numbers as changed
in the 1977 amendments to the Clean
Air Act. As amended, the Act formerly
classified to 42 U.S.C. 1857 et seq. has
been transferred and is now classified
to 42 U.S.C. 7401 et seq.
: March 3, 1978.
INFORMATION
FOR FURTHER
CONTACT:
Don R. Goodwin, Emission Stan-
dards and Engineering Division, En-
vironmental Protection Agency, Re-
search Triangle Park. N.C. 27711
telephone 919-541-5271.
SUPPLEMENTARY INFORMATION:
This action is being taken in accor-
dance with the requirements of 1 CFR
21.43 and is authorized under section
301(a) of the Clean Air Act, as amend-
ed, 42 U.S.C. 7601(a). Because the
amendments are clerical in nature and
affect no substantive rights or require-
ments, the Administrator finds it un-
necessary to propose and invite public
comment.
Dated: February 24, 1978.
DOUGLAS M. Costu:,
Administrator.
Parts 60 and 61 of Chapter I. Title
40 of the Code of Federal Regulations
are revised as follows:
1. The authority citation following
the table of sections in Part 60 is re-
vised to read as follows:
AUTHORITY: Sec. Ill, 301(a) of the Clean
Air Act as amended (42 D.S.C. 7411,
7601(a)>, unless otherwise noted.
§§ 60.10 and 60.24 [Amended]
2. Following §§ 60.10 and 60.24(g) the
following authority citation is added:
(Sec. 116 of the Clean Air Act ac amended
(42 U.S.C. 7416)).
§§ 60.7, 60.8, 60.9,
60.46, 60.53,
60.73, 60.74,
60.105, 60.106,
60.144, 60.153,
60.175,60.176,
60.195,60.203,
60.223, 60.224,
60.244, 60.253,
60.266, 60.273
Appendices A,
ed]
3. The following authority citation is
added to the above sections and ap-
pendices:
(Sec. 114, Clean Air Act Is amended (42
U.S.C. 7414)).
60.11, 60.13, 60.45,
60.54, 60.63, 60.64.
60.84. 60.85, 60.93,
60.113,60.123,60.133.
60.154,60.165,60.166,
60.185,60.186,60.194,
60.204,60.213.60.214.
60.233, 60.234, 60.243.
60.254, 60.264, 60.265,
, 60.274, 60.275, and
B, C, and D [Amend-
ttDERAL REGISTER, VOL. 43, NO. 43
FRIDAY, MARCH 3, 1971
IV-249
-------
84
PART 60 STANDARDS OF PERFOR-
MANCE FOR NEW STATIONARY
SOURCES
Lignite-Fired Steam Generators
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Final rule.
SUMMARY: This final rule estab-
lishes standards of performance for
new or modified lignite-fired steam
generators with heat input rates great-
er than 73 megawatts (250 million Btu
per hour) and limits emissions of ni-
trogen oxides to 260 ng/J of heat
input except that 340 ng/J of heat
input is allowed from cyclone-fired
units which are fired with lignite
mined in North Dakota, South
Dakota, or Montana. Steam gener-
ators contribute significantly to air
pollution, and the intended effect of
this final rule is to require new steam
generators which burn lignite to use
the best control system for reducing
emissions of nitrogen oxides.
EFFECTIVE DATE: March 7,1978.
ADDRESSES: The "Standards Sup-
port and Environmental Impact State-
ment (SSEIS), Volume 2: Promulgated
Standards of Performance for Lignite-
Fired Steam Generators" (EPA-450/2-
76-030b) may be obtained by writing
the U.S. EPA Library (MD-35), Re-
search Triangle Park, N.C. 27711.
Volume 1 of the SSEIS, "Proposed
Standards of Performance for Lignite-
Fired Steam Generators" (EPA-450/2-
76~030a), is also available at the same
address. Please specify both the title
and EPA number of the document de-
sired. These documents and all public
comments may be inspected at the
Public Information Reference Unit
(EPA Library), Room 2922, 401 M
Street SW., Washington, D.C.
FOR FURTHER INFORMATION
CONTACT:
RULES AND REGULATIONS
Don R. Goodwin, Director, Emission
Standards and Engineering Division
(MD-13), Environmental Protection
Agency, Research Triapgle Park,
N.C. 27711, telephone 919-541-5271.
SUPPLEMENTARY INFORMATION:
On December 23, 1971 (36 FR 24877),
EPA established under Subpart D of
40 CFR Part 60 standards of perfor-
mance for new steam generators with
heat input rates greater than 73
megawatts (250 million Btu per hour).
Steam generators which burn llgnitie
were exempted from the emission
standards for nitrogen oxides (NO,)
because too little operating experience
was available to adequately character-
ize NO, emissions. (Lignite-fired steam
generators were not exempted from
the standards for sulfur oxides and
particulate matter, however.) Since
1971, EPA has gathered additional in-
formation on lignite-fired facilities,
and on December 22, 1976 (41 FR
55791), the Agency proposed to amend
Subpart D by establishing a standard
of performance of 260 nanograms per
joule (ng/J) of heat input (0.6 pound
per million Btu) for NO, emissions
from new lignite-fired steam gener-
ators. Supporting information for the
proposed standard was published in
Volume 1 of the SSEIS for lignite-
fired steam generators. After review-
ing issues raised during the public
comment period which followed the
proposal, EPA decided to promulgate
standards which will permit the limit-
ed use of cyclone-fired facilities to
burn lignite mined in North Dakota,
South Dakota, and .Montana (which
causes severe fouling and slagging in
pulverized-fired units). Supporting in-
formation for these final standards of
performance appears in Volume 2 of
the SSEIS.
FINAL STANDARDS
NO, emissions from lignite-fired
steam generators are limited to 260
ng/J of heat in put (0.6 lb/10« Btu)
except that 340 ng/J (0.8 lb/10* Btu)
is allowed from cyclone-fired steam
generators burning lignite mined In
North Dakota, South Dakota, and
Montana. Both standards apply only
to boilers which burn lignite, with
heat input rates greater than 73
megawatts (250 million Btu per hour),
and for which construction or modifi-
cation began after December 21, 1976.
RATIONALE FOR FINAL STANDARDS
The NO, standard originally pro-
posed by EPA, 260 ng/J, may have
prevented the use of cyclone-fired
boilers, since it has not been demon-
strated that emisisons from these
units can be consistently controlled to
levels below 260 ng/J. During the
public comment period, several com-
menters argued that the utilization of
cyclone-fired boilers is necessary to
overcome the serious fouling and slag-
ging problems which develop when-
ever the sodium content of the lignite
burned exceeds about 5 percent, by
weight. These high sodium content re-
serves are believed to be widespread,
especially in North Dakota, and the
utilities claim that their low sodium
content reserves are being rapidly de-
pleted. The commenters said that cy-
clones have inherently lower fouling
end slagging rates than other large
boiler designs because much less ash is
carried through the boiler convective
passes. In addition, they contended
that in the Dakotas there has actually
been very little operating experience
with pulverized-fired boilers, the alter-
native to large cyclones, and it is
doubtful that these units can burn
high sodium lignite without experienc-
ing severe problems. Thus, the com-
menters concluded that the proposed
standard might restrict the use of
valuable resources of high sodium lig-
nite fuel by prohibiting the utilization
of cyclone-fired boilers. The com-
menters also argued that the proposed
standard would place an economic
burden on the electirc power utilities
which burn lignite by limiting compe-
titve bidding for new boilers.
EPA agrees that at present there is
too little operating experience with
pulverized- or cyclone-fired boilers to
be able to predict their reliability
when burning high sodium lignite.
Furthermore, the Agency does not
want to establish a standard which
might inhibit future efforts to find a
successful way to burn this trouble-
some fuel. Consequently, EPA has es-
tablished a separate nitrogen oxides
emission standard of 340 ng/J (0.8 lb/
10 Btu) for new cyclone-fired boilers
which burn North Dakota, South
Dakota, or Montana lignite. This stan-
dard will permit the limited utlization
of cyclone-fired boilers and assure the
continued use of our country's abun-
dant resources of lignite. Lignite
mined in Texas, the only other known
major lignite formation, generally has
low sodium content and has been suc-
cessfully burned in pulverized-fired
units for years. The standard is sup-
ported by emission test data and other
information contained in Volume I of
the SSEIS. Nitrogen oxides emissions
from pulverized-fired boilers will be
limited to 260 ng/J (0.6 lb/10' Btu). as
originally proposed.
. Cyclone-fired boilers could account
for 10 to 20 percent of all new lignite-
fired steam generators, based on EPA
estimates of lignite consumption for
the year 1980. EPA estimates that NO,
emissions from new cyclone-fired boil-
ers may be reduced by as much as 20
percent as a result of the standard.
The combined effect of both standards
will be to reduce total NO, emissions
from all new boilers which burn lignite
by about 25 percent.
IV-250
-------
ftULES AND REGULATIONS
It should be noted that standards of
performance for new sources estab-
lished under-section 111 of the Clean
Air Act reflect the degree of emission
limitation achievable through applica-
tion of the best adequately demon-
strated technological system of con-
tinuous emission reduction (taking
into consideration the cost of achiev-
ing such emission reduction, any non-
air quality health and environmental
impact and energy requirements).
State implementation plans (SIPs) ap-
proved or promulgated under section
110 of the Act, on the other hand,
must provide for the attainment and
maintenance of national ambient air
quality standards (NAAQS) designed
to protect public health and welfare.
For that purpose, SIPs must in some
cases require greater emission reduc-
tions than those required by standards
of performance for new sources. Sec-
tion 173 of the Act requires, among
other things, that a new or modified
source constructed in an area which
exceeds the NAAQS must reduce emis-
sions to the level which reflects the
"lowest achievable emission rate" for
such category of source as defined in
section 171(3), unless the owner or op-
erator demonstrates that the source
cannot achieve such an emission rate.
In no event can the emission rate
exceed any applicable standard of per-
formance.
A similar situation may arise when a
major emitting facility is to be con-
structed in a geographic area which
falls under the prevention of signifi-
cant deterioration of air quality provi-
sions of the Act (Part C). These provi-
sions require, among other things,
that major emitting facilities to be
constructed in such areas are to be
subject to best available control tech-
nology. The term "best available con-
trol technology"
-------
RULES AND REGULATIONS
which burn high sodium content lig-
nite to justify eliminating cyclones
from the market. Consequently, the
Agency has decided to establish a sep-
arate NO. emission standard for cy-
clones burning Dakota lignite which
permits their use.
Another issue raised during the com-
ment period concerned the potentially
high NO, emissions which could occur
when Texas lignite with a high nitro-
gen content is burned. It was argued
that these emissions could exceed the
standard even If the best system of
emission reduction were employed. In
support of this contention, a com-
menter submitted data which Indicate
that the fuel-nitrogen content of
Texas lignites ranges well above ex-
pected values. EPA has determined,
however, that these data were accu-
mulated around the turn of the cen-
tury and are inconsistent with present-
day values. Information from the
Bureau of Economic Geology at the
University of Texas and the Texas
Railroad Commission indicates that
Texas lignite nitrogen contents are
typically low and should not cause
NO, emissions from a well controlled
plant to exceed the standard.
These and all other comments are
discussed in detail in Volume 2, Chap-
ter 2 of the SSEIS.
The effective date of this regulation
is (date of publication), because sec-
tion HKbXlKB) of the Clean Air Act
provides that standards of perfor-
mance or revisions thereof become ef-
fective upon promulgation.
NOTE.The Environmental Protection
Agency has determined that this document
does not contain a major proposal requiring
preparation of an Economic Impact Analy-
sis under Executive Orders 11821 and 11949
and OMB Circular A-107.
Dated: March 2,1978.
DOUGLAS M. COSTLE,
Administrator.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amend-
ed by revising Subparts A and D as fol-
lows:
Subparl AGeneral Provisions
1. Section 60.2 is amended by substi-
tuting the International System of
Units (SI) in paragraph (1) as follows:
{60.2 Definitions.
(1) "Standard conditions" means a
temperature of 293 K (68° F) and a
pressure of 101.3 kilopascals (29.92 in
Hg).
Subport DStandards of Performance
for Fossil Fuel-Fired Steam Generators
2. Section 60.40 is amended by revis-
ing paragraph (c) and by adding para-
graph (d) as follows:
S 60.40 Applicability and designation of
affected facility.
(c) Except as provided in paragraph
(d) of this section, any facility under
paragraph (a) of this section that com-
menced construction or modification
after August 17, 1971, is subject to the
requirements of this subpart.
(d) The requirements of
§§60.44(a)(4), (a)(5), (b), and (d), and
60.45(f)(4Xvi) are applicable to lignite-
fired steam generating units that com-
menced construction or modification
after December 22,1976.
3. Section 60.41 is amended by
adding paragraph (f) as follows:
fi 60.41 Definitions.
(f) "Coal" means all solid fuels clas-
sified as anthracite, bituminous, subbi-
tuminous, or lignite by the American
Society for Testing Material. Designa-
tion D 388-66.
4. Section 60.44 is amended by
adding paragraphs (a)(4) and (a)(5), by
revising paragraph (b), and by adding
paragraphs (c) and (d) as follows:
§ 60.44 Standard for nitrogen oxides.
(a) * *
(4) 260 nanograms per joule heat
input (0.60 Ib per million Btu) derived
from lignite or lignite and wood resi-
due (except as provided under para-
graph (a)(5) of this section).
(5) 340 nanograms per joule heat
input (0.80 Ib per million Btu) derived
from lignite which is mined in North
Dakota, South Dakota, or Montana
and which is burned in a cyclone-fired
unit.
(b) Except as provided under para-
graphs (c) and (d) of this section,
when different fossil fuels are burned
simultaneously in any combination,
the applicable standard (in ng/J) is de-
termined by proration using the fol-
lowing formula:
where:
PS*0l=ls the prorated standard for nitro-
gen oxides when burning different
fuels simultaneously, in nanograms
per joule heat input derived from all
fossil fuels fired or from all fossil fuels
and wood residue fired;
tc=is the percentage of total heat input
derived from lignite;
x<=is the percentage of total heat input
derived from gaseous fossil fuel;
V=ls the percentage of total heat input
derived from liquid fossil fuel; and
«=is the percentage of total heat input de-
rived from solid fossil fuel (except lig-
nite).
(c) When a fossil fuel containing at
least 25 percent, by weight, of coal
refuse is burned in combination with
gaseous, liquid, or other solid fossil
fuel or wood residue, the standard for
nitrogen oxides does not apply.
(d) Cyclone-fired units which burn
fuels containing at least 25 percent of
lignite that is mined in North Dakota,
South Dakota, or Montana remain
subject to paragraph (a)(5) of this sec-
tion regardless of the types of fuel
combusted in combination with that
lignite.
(Sections 111 and 301(a) of the Clean Air
Act, as amended (42 U.S.C. 7411, and 7601).)
5. Section 60.45 is amended by
adding paragraph (f)(4)(vi) as follows:
{ 60.45 Emission and fuel monitoring.
(f) *
(4)
(vi) For lignite coal as classified ac-
cording to A.S.T.M. D 388-66,
F= 2.659 xlO-T dscm/J (9900 dscf/mil-
lion Btu) and Fc=0.516xlO-' scm CO,/
J (1920 scf COa/million Btu).
(Sections 111, 114, and 301(a) of the Clean
Air Act, as amended (42 U.S.C. 7411, 7414,
and 7601).)
[FR Doc. 78-5975 Piled 3-6-78; 8:45 am]
FEDERAL REGISTER, VOL 43, NO. 45
TUESDAY, MARCH 7, 1978
IV-252
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HOLES AND REGULATIONS
85
Title 40Protection of Environment
CHAPTER IENVIRONMENTAL
PROTECTION AGENCY
SWCHAPTER CAK PROGRAMS
tPRL 836-2]
PART 60STANDARDS OF PERFOR-
MANCE FOR NEW STATIONARY
SOURCES
Ume Manufacturing Plants
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Final rule.
SUMMARY: This rule establishes
standards of performance which limit
emissions of particulate matter from
new, modified, and reconstructed lime
manufacturing plants. The standards
implement the Clean Air Act and are
based on the Administrator's determi-
nation that lime manufacturing plant
emissions contribute significantly to
air pollution. The intended effect of
setting these standards is to require,
new, modified, and reconstructed lime
manufacturing plants to use the best
demonstrated system of continuous
emission reduction.
EFFECTIVE DATE: March 7, 1978.
ADDRESSES: A support document
entitled, "Standard Support and Envi-
ronmental Impact Statement, Volume
II: Promulgated Standards of Perfor-
mance for Lime Manufacturing
Plants" (EPA-4SO/2-77-007b), October
1977, has been prepared and is avail-
able. This document includes sum-
mary economic and environmental
impact statements as well as EPA's re-
sponses to the comments on the pro-
posed standards. Also available is the
supporting volume for the proposed
standards entitled, "Standard Support
and Environmental Impact Statement,
Volume I: Proposed Standards of Per-
formance for Lime Manufacturing
Plants" (EPA-450/2-77-007a), April
1977. Copies of these documents can
be ordered by'addressing a request to
the EPA Library (MD-35), Research
Triangle Park, N.C. 27711. The title
and number for each or both of the
documents should be specified when
ordering. These documents as well as
copies of the comment letters respond-
ing to the proposed rulemaking pub-
lished in the FEDERAL REGISTER on
May 3, 1977 (42 FR 22506) are avail-
able for public inspection and copying
at the U.S. Environmental Protection
Agency, Public Information Reference
Unit (EPA Library), Room 2922, 401 M
Street SW., Washington, D.C. 20460.
FOR FURTHER, INFORMATION
CONTACT:
Don R. Goodwin, Director, Emission
Standards and Engineering Division
(MD-13), Environmental Protection
Agency, Research Triangle Park.
N.C. 27711, telephone 919-541-5271.
SUPPLEMENTARY INFORMATION:
There are two minor changes in the
standards from those proposed on
May 3, 1977. The first of these is the
specific exclusion of lime production
units at kraft pulp mills [§60.340(b)].
Emission standards for kraft pulp
mills were proposed In the FEDERAL
REGISTER on September 24, 1976,
which cover emissions from the lime
production unite at these mills.
The second change is the addition of
§60.344(c) (Test methods and proce-
dures). The addition recommends a
testing technique which would more
accurately test exhaust gases from hy-
drators In those cases where high
moisture content is a problem.
During the 60-day comment period
following publication of the proposed
emission standards in the FEDERAL
REGISTER on May 3, 1977, 23 comment
letters were received, 10 from indus-
try, 7 from State or local pollution
control agencies, and 6 from other gov-
ernment agencies. In addition, on June
16, 1977, a public meeting was held at
the EPA facility at Research Triangle
Park, N.C., that provided an opportu-
nity for oral presentations and com-
ments on the standards. None of the
comments warranted a change of the
emission standards nor did any com-
ments justify any significant changes
in the standards support document.
Major comments focused on three
areas: (1) criticism of the testing pro-
cedures and the supporting emission
data, (2) the opacity standard, and (3)
the requirement for continuous moni-
toring. These and other comments are
summarized and addressed in Volume
II of the standards support document.
The most significant of the three
areas of comments was the question-
ing of the testing procedures and the
data base. More specifically, it was as-
serted that when data were gathered
upon which to base the standard, stan-
dard testing procedures were not fol-
lowed in every case, which consequent-
ly biased the data. A careful review of
the procedures and the resulting data
revealed that, although there were
minor miscalculations, the errors did
not affect the emission standards that
were set.
The opacity standard (10 percent),
was questioned because it was thought
to be too stringent and in a range
where observer error would result in
unfair violation decisions. A review of
the opacity data indicated that of the
1,056 six-minute averages of opacity,
less than one percent exceeded the
visible emission level of 10 percent,
thus EPA considers the 10 percent
opacity standard reasonable. As for
observer error, as indicated in the in-
troduction to Reference Method 9
(Part 60, Appendix A), the accuracy of
the method and any potential error
must be taken into account when de-
termining possible violations of the
standards.
Some commenters questioned the re-
quirement for continuous monitoring
of multiple stack baghouses, believing
it to be unnecessary and excessively
expensive to place a monitor on each
stack. In establishing the continuous
monitoring requirement, it was not
the intention of EPA that emission
monitors be installed at each stack at
a multiple stack baghouse. The pro-
posed regulation has been revised to
reflect this intent. It Is believed that
in most cases one monitor, or two in
certain situations, can be installed to
simultaneously monitor emissions
from several stacks. With such a moni-
toring system, the plant must demon-
strate that representative emissions
are monitored on a continuous basis.
It should be noted that standards of
performance for new sources estab-
lished under section 111 of the Clean
Air Act reflect the degree of emission
limitation achievable through applica-
tion of the best adequately demon-
strated technological system of con-
tinuous emission reduction (taking
into consideration the cost of achiev-
ing such emission reduction, any
nonatr quality health and environmen-
tal impact and energy requirements).
State implementation plans (SIPs) ap-
proved or promulgated under section
110 of the Act, on the other hand,
must provide for the attainment and
maintenance of national ambient air
quality standards (NAAQS) designed
to protect public health and welfare.
For that purpose, SIPs must in some
cases require greater emission reduc-
tions than those required by standards
of performance for new sources. Sec-
tion 173 of the Act requires, among
other things, that a new or modified
source constructed in an area which
exceeds the NAAQS must reduce emis-
sions to the level which reflects the
"lowest achievable emission rate" for
such category of source. In no event
can the emission rate exceed any ap-
plicable standard of performance.
A similar situation may arise when a
major emitting facility is to be con-
structed in a geographic area which
falls under the prevention of signifi-
cant deterioration of air quality provi-
sions of the Act (part C). These provi-
sions require, among other things,
that major emitting facilities to be
constructed in such areas are to be
subject to best available control tech-
nology for all pollutants regulated
under the Act. The term "best avail-
able control technology" (BACT), as
defined In section 169(3), means "an
emission limitation based on the maxi-
mum degree of reduction of each pol-
lutant subject to regulation under this
Act emitted from or which results
FEDERAL REGKTER, VOL 43, NO. 45TUESDAY, MARCH 7, 19TS
IV-253
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tULES AND REGULATIONS
from any major emitting facility,
which the permitting authority, on a
case-by-case basis, taking into account
energy, environmental, and economic
Impacts and other costs, determines is
achievable for such facility through
application of production processes
and available methods, systems, and
techniques, including fuel cleaning or
treatment or innovative fuel combus-
tion techniques for control- of each
ucb pollutant. In no event shall appli-
cation of 'best available control tech-
nology' result in emissions of any pol-
lutants which will exceed the emis-
sions allowed by any applicable stan-
dard established pursuant to section
111 or 112 of this Act."
Standards of performance should
not be viewed as the ultimate in
achievable emission control and
should not preclude the imposition of
a more stringent emission standard,
where appropriate. For example while
cost of achievement may be an impor-
tant factor in determining standards
of performance applicable to.all areas
of the country (clean as well as dirty),
statutorily, costs do not play such a
role in determining the "lowest achiev-
able emission rate" for new or modi-
fied sources locating in areas violating
statutorily-mandated health and wel-
fare standards. Although there may be
emission control technology available
that can reduce emissions below those
levels required to comply with stan-
dards of performance, this technology
might not be selected as the basis of
standards of performance due to costs
associated with its use. This in no way
should preclude its use in situations
where cost is a lesser consideration,
such as determination of the "lowest
achievable emission rate."
In addition, States are free under
section 116 of the Act to establish even
more stringent emission limits than
those established under section 111 or
those necessary to attain or maintain
the NAAQS under section 110. Thus,
new sources may in some cases be sub-
ject to limitations more stringent than
EPA's standards of performance under
section 111, and prospective owners
and operators of new sources should
be aware of this possibility in planning
for such facilities.
MISCELLANEOUS: The effective
date of this regulation is March 7,
1978. Section UKbXlXB) of the Clean
Air Act provides that standards of per-
formance or revisions of them become
effective upon promulgation and apply
to affected facilities, construction or
modification of .which was commenced
after the date of proposal (May 3,
1977).
NOTE.The Environmental Protection
Agency has determined that this document
does not contain m major proposal requiring
an Economic Impact Analysis under Execu-
tive Orders 11821 and 11949 and OMB Cir-
cular A-107.
Dated: March 1,1978.
DOUGLAS M. COSTLE,
Administrator.
Part 60 of Chapter I of Title 40 of
the Code of Regulations is amended as
follows:
1. By adding subpart HH as follows:
Subpart HHStandards of Perfor-
mance for lime Manufacturing
- Plants
Sec.
60.340 Applicability and designation of af-
fected facility.
60.341 Definitions.
60.342 Standard for particulate matter.
60.343 Monitoring of emissions and oper-
ations.
60.344 Test methods and procedures.
AUTHORITY: Sec. Ill and 301(a) of the
Clean Air Act, as amended (42 U.S.C. 7411,
7601), and additional authority as noted
below.
§60.340 Applicability and designation of
affected facility.
(a) The provisions of this subpart
are applicable to the following affect-
ed facilities used in the manufacture
of lime: rotary lime kilns and lime hy-
drators.
(b) The provisions of this subpart
are not applicable to facilities used in
the manufacture of lime at kraft pulp
mills.
(c) Any facility under paragraph (a)
of this section that commences con-
struction or modification after May 3,
1977, is subject to the requirements of
this part.
§ 60.341 Definitions.
As used in this subpart, all terms not
defined herein shall have the same
meaning given them in the Act and in
subpart A of this part.
(a) "Lime manufacturing plant" in-
cludes any plant which produces a
lime product from limestone by calci-
nation. Hydration of the lime product
is also considered to be part of the
source.
(b) "Lime product" means the prod-
uct of the calcination process includ-
ing, but not limited to, calcitic lime,
dolomitic lime, and dead-burned dolo-
mite.
(c) "Rotary lime kiln" means a unit
with an inclined rotating drum which
is used to produce a lime product from
limestone by calcination.
(d) "Lime hydrator" means a unit
used to produce hydrated lime prod-
uct.
{ 60.342 Standard for particulate matter.
(a) On and after the date on which
the performance test required to be
conducted by $60.8 is completed, no
owner or operator subject to the provi-
sions of this subpart shalTcause to be
discharged into the atmosphere:
(1) Prom any rotary lime kiln any
gases which:
(i) Contain particulate matter in
excess of 0.15 kilogram per megagram
of limestone feed (0.30 Ib/ton).
(ii) Exhibit 10 percent opacity or
greater.
(2) Prom any lime hydrator any
gases which contain particulate matter
in excess of 0.075 kilogram per mega-
gram of lime feed (0.15 Ib/ton).
§ 60.343 Monitoring of emissions and op-
erations.
(a) The owner or operator subject to
the provisions of this subpart shall in-
stall, calibrate, maintain, and operate
a continuous monitoring system,
except as provided in paragraph (b) of
this section, to monitor and record the
opacity of a representative portion of
the gases discharged into the atmos-
phere from any rotary lime kiln. The
span of this system shall be set at 40
percent opacity.
(b) The owner or operator of any
rotary lime kiln using a wet scrubbing
emission control device subject to the
provisions of this subpart shall not be
required to monitor the opacity of the
gases discharged as required in para-
graph (a) of this section, but shall in-
stall, calibrate, maintain, and operate
the following continuous monitoring
devices:
(DA monitoring device for the con-
tinuous measurement of the pressure
loss of the gas stream through the
scrubber. The monitoring device must
be accurate within ±250 pascals (one
inch of water).
(2) A monitoring device for the con-
tinuous measurement of the scrubbing
liquid supply pressure to the control
device. The monitoring device must be
accurate within ±5 percent of design
scrubbing liquid supply pressure.
(c) The owner or operator of any
lime hydrator using a wet scrubbing
emission control device subject to the
provisions of this subpart shall install,
calibrate, maintain, and operate the
following continuous monitoring de-
vices:
(DA monitoring device for the con-
tinuous measuring of the scrubbing
liquid flow rate. The monitoring
device must be accurate within ±5 per-
cent of design scrubbing liquid flow
rate.
(2) A monitoring device for the con-
tinuous measurement of the electric
current, in amperes, used by the scrub-
ber. The monitoring device must be ac-
curate within ±10 percent over its
normal operating range.
(d) For the purpose of conducting a
performance test under §60.8, the
owner or operator of any lime manu-
facturing plant subject to the provi-
sions of this subpart shall install, cali-
brate, maintain, and operate a device
for measuring the mass rate of lime-
stone feed to any affected rotary lime
FEDEftAl EQISTEft, VOL 43, NO. 4STUESDAY, MAICH 7, 1971
IV-254
-------
IULES AND REGULATIONS
kiln and the mass rate of lime feed to
any affected lime hydrator. The mea-
suring device used must be accurate to
within ±5 percent of the mass rate
over its operating range.
(e) For the purpose of reports-re-
quired under |60.7(c), periods of
excess emissions that shall be reported
are defined as all six-minute periods
during which the average opacity of
the plume from any lime kiln subject
to paragraph (a) of this subpart is 10
percent or greater.
(Sec. 114 of the Clean Air Act, as amended
(42 U.S.C. 7414).)
S 60.344 Test methods and procedures.
(a) Reference methods in Appendix
A of this part, except as provided
under J60.8(b), shall be used to deter-
mine compliance with §60.322(a) as
follows:
(1) Method 5 for the measurement
of particulate matter,
(2) Method 1 for sample and velocity
traverses,
(3) Method 2 for velocity and volu-
metric flow rate,
(4) Method 3 for gas analysis,
(5) Method 4 for stack gas moisture.
and
(6) Method 9 for visible emissions.
(b) For Method 5, the sampling time
for each run shall be at least 60 min-
utes and the sampling rate shall be at
least 0.85 std m'/h, dry basis (0.53
dscf/min), except that shorter sam-
pling times, when necessitated by pro-
cess variables or other factors, may be
approved by the Administrator.
(c) Because of the high moisture
content (40 to 85 percent by volume)
of the exhaust gases from hydrators,
the Method 5 sample train may be
modified to include a calibrated orifice
Immediately following the sample
nozzle when testing lime hydrators. In
this configuration, the sampling rate
necessary for maintaining isokinetic
conditions can be directly related to
exhaust gas velocity without a correc-
tion for moisture content. Extra care
should be exercised when cleaning the
sample train with the orifice in this
position following the test runs.
(Sec. 114 of the Clean Air Act, as amended
(42 UJB.C, 7414).)
[PR Doc. 78-6974 Filed 3-4-78; 8:45 ami
fBMftAl UOBTOt. VOC 4*. NO. 45
1UHQAY, MARCH 7,
86
Title 40Protection of Environment
CHAPTER IENVIRONMENTAL
PROTECTION AGENCY
SUBCHAPTER CAIR PROGRAMS
[FRL 836-1]
PART 60STANDARDS OF PERFOR-
MANCE FOR NEW STATIONARY
SOURCES
Petroleum Refinery Clous Sulfur
Recovery Plants
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Final rule.
SUMMARY: This rule establishes
standards of performance which will
limit emissions of sulfur dioxide (SO.)
and reduced sulfur compounds from
new, modified, and reconstructed pe-
troleum refinery Claus sulfur recovery
plants. The standards implement the
Clean Air Act and are based on the
Administrator's determination that
emissions from petroleum refinery
Claus sulfur recovery plants contrib-
ute significantly to air pollution. The
intended effect of the standards is to
require new, modified, and recon-
structed petroleum refinery Claus
sulfur recovery plants to use the best
technological system of continuous
emission reduction.
EFFECTIVE DATE: March 15, 1978.
ADDRESSES: Copies of the standard
support documents are available on re-
quest from the U.S. EPA Library
(MD-35), Research Triangle Park,
N.C. 27711. The requestor should
specify "Standards Support and Envi-
ronmental Impact Statement, Volume
I. Proposed Standards of Performance
for Petroleum Refinery Sulfur Recov-
ery Plants" (EPA-450/2-76-016a) and/
or "Standards Support and Environ-
mental Impact Statement, Volume II:
Promulgated Standards of Perfor-
mance for Petroleum Refinery Sulfur
Recovery Plants" (EPA-450/2-76-
016b). Comment letters responding to
the proposed rules published in the
FEDERAL REGISTER on October 4, 1976
(41 FR 43866), are available for public
inspection and copying at the U.S. En-
vironmental Protection Agency, Public
Information Reference Unit (EPA Li-
brary), Room 2922, 401 M Street SW.,
Washington, D.C.
FOR FURTHER INFORMATION
CONTACT:
Don R. Goodwin, Emission Stan-
dards and Engineering Division
(MD-13), Environmental Protection
Agency, Research Triangle Park,
N.C. 27711, telephone number 919-
541-5271.
SUPPLEMENTARY INFORMATION:
SUMMARY
On October 4, 1976 (41 FR 43866).
EPA proposed standards of perfor-
mance for new petroleum refinery
Claus sulfur recovery plants under sec-
tion 111 of the Clean Air Act, as
amended. The promulgated standards
are essentially the same as those pro-
posed, although an exemption for
small petroleum refineries has been in-
cluded in the promulgated standards.
The standards are based on the use of
tail gas scrubbing systems which have
been determined to be the best tech-
nological system of continuous emis-
sion reduction, taking into consider-
ation the cost of achieving such emis-
sion reduction, any nonair quality,
health, and environmental impact and
energy requirements. Compliance with
these standards will increase the over-
all sulfur recovery efficiency of a typi-
cal refinery Claus sulfur recovery
plant to about 99.9 percent, compared
to a recovery efficiency of about 94
percent for an uncontrolled refinery
Claus sulfur recovery plant, or a recov-
ery efficiency of about 99 percent for a
Claus sulfur recovery plant complying
with typical State emission control
regulations for these plants.
The promulgated standards will
apply to: (1 )"any Claus sulfur recovery
plant with a sulfur production capac-
ity of more than 20 long tons per day
(LTD) which is associated with a small
petroleum refinery (i.e., a petroleum
refinery having a crude oil processing
capacity of 50,000 barrels per stream
day (BSD) or less which is owned or
controled by a refiner whose total
combined crude oil processing capacity
is 137,500 BSD or less) and (2) any size
Claus sulfur recovery plant associated
with a large petroleum refinery. Spe-
cifically, the standards limit the con-
centration of sulfur dioxide (SO,) in
the gases discharged into the atmo-
sphere to 0.025 percent by volume at
zero percent oxygen on a dry basis.
Where the emission control system in-
stalled to comply with these standards
discharges residual emissions of hy-
drogen sulfide (HiS), carbonyl sulfide
(COS), and carbon disulfide (CS,), the
standards limit the concentration of
H»5 and the total concentration of
H,S, COS and CS, (calculated as SO,)
in the gases discharged into the atmo-
sphere to 0.0010 percent and 0.030 per-
cent by volume at zero percent oxygen
on a dry basis, respectively.
Compliance with these standards
will reduce nationwide sulfur dioxide
emissions by some 55,000 tons per year
by 1980. This reduction will be
achieved without any significant ad-
verse impact on other aspects of envi-
ronmental quality, such as solid waste
disposal, water pollution, or noise.
This reduction in emissions will also
be accompanied by a reduction in the
IV-255
-------
RULES AND REGULATIONS
growth of nation! energy consumption
equivalent to about 90,000 barrels of
fuel oil per year by 1980.
The economic impact of the promul-
gated standards is reasonable. They
will result in an increase in the annual
operating costs of the petroleum refin-
ing industry by some $16 million per
year in 1980. An individual refiner who
installs alternative II controls will
need to increase his prices from 0.1 to
1 percent to maintain his profitability.
It should be noted that standards of
performance for new sources estab-
lished under section 111 of the Act re-
flect the degree of emission limitation
achievable through application of the
best adequately demonstrated techno-
logical system of continuous emission
reduction (talcing into consideration
the cost of achieving such emission re-
duction, any nonair quality health and
environmental impact and energy re-
quirements). State implementation
plans (SIPs) approved or promulgated
under section 110 of the Act, on the
other hand, must provide 'for the at-
tainment and maintenance of national
ambient air quality standards
(NAAQS) designed to protect public
health and welfare. For that purpose,
SIPs must in some cases require great-
er emission reduction than those re-
quired by standards of performance
for new sources. Section 173(2) of the
Act requires, among other things, that
a new or modified source constructed
in an area which exceeds the NAAQS
must reduce emissions to the level
which reflects the "lowest achievable
emission rate" for such category of
source, unless the owner or operator
demonstrates that the source cannot
achieve such an emission rate. In no
event can the emission rate exceed any
applicable standard of performance.
A similar situation may arise when a
major emitting facility is to be con-
structed in a geographic area which
falls under the prevention of signifi-
cant deterioration of air quality provi-
sions of the Act (part C). These provi-
sions require, among other things,
that major emitting facilities to be
constructed in such areas are to be
subject to the best available control
technology. The term "best available
control technology" (BACT) means
"an emission limitation based on the
maximum degree of reduction of each
pollutant subject to regulation under
this Act emitted from or which results
from any major emitting facility,
which the permitting authority, on a
case-by-case basis, taking into account
energy, environmental, and economic
impacts and other costs, determines is
achievable for such facility through
application of production processes
and available methods, systems, and
techniques, including fuel cleaning or
treatment or innovative fuel combus-
tion techniques for control of each
such pollutant. In no event shall appli-
cation of 'best available control tech-
nology' result in emissions of any pol-
lutants which will exceed the emis-
sions allowed by any applicable stan-
dard established pursuant to section
111 or 112 of this Act."
Standards of performance should
not be viewed as the ultimate in
achievable emission control and
should not preclude the imposition of
a more stringent emission standard,
where appropriate. For example, while
cost of achievement may be an impor-
tant factor in determining standards
of performance applicable to all areas
of the country (clean as well as dirty),
costs must be accorded far less weight
in determining the "lowest achievable
emission rate" for new or modified
sources locating in areas violating sta-
tutorily-mandated health and welfare
standards. Although there may be
emission control technology available
that can reduce emissions below those
levels required to comply with stan-
dards of performance, this technology
might not be selected as the basis of
standards of performance due to costs
associated with its use. This in no way
should preclude its use in situations
where cost is a lesser consideration,
such as determination of the "lowest
achievable emission rate."
In addition, States are free under
section 116 of the Act to establish even
more stringent emission limits than
those established under section 111 or
those necessary to attain or maintain
the NAAQS under section 110. Thus,
new sources may in some cases be sub-
ject to limitations more stringent than
standards of performance under sec-
tion 111, and prospective owners and
operators of new sources should be
aware of this possibility in planning
for such facilities.
PUBLIC PARTICIPATION
Prior to proposal of the standards,
interested parties were advised by
public notice in the FEDERAL REGISTER
of a meeting of the National Air Pollu-
tion Control Techniques Advisory
Committee to discuss the standards
recommended for proposal. This meet-
ing was open to the public and each
person attending was given ample op-
portunity to comment on the stan-
dards recommended for proposal. The
standards were proposed on October 4,
1976, and copies of the proposed stan-
dards and the Standards Support and
Environmental Impact Statement
(SSEIS) were distributed to members
of the petroleum refining industry and
several environmental groups at this
time. The public comment period ex-
tended from October 4, 1976, to De-
cember 3, 1976.
Twenty-two comment letters were
received on the proposed standards of
performance. These comments have
been carefully considered and, where
determined to be appropriate by the
Administrator, changes have been
made in the standards which were pro-
posed.
MAJOR COMMENTS
Comments on the proposed stan-
dards were received from several oil in-
dustry representatives, State and local
air pollution control agencies, a vendor
of emission source testing equipment,
and several Federal agencies. These
comments covered four major areas:
the costs of implementing the stan-
dards, the ability of emission control
technology to meet the standards, the
environmental impacts of the stan-
dards, and the energy impacts of the
standards.
COSTS
The major comments concerning
costs were that the costs of the emis-
sion control systems required to meet
the standards were underestimated,
that these costs were excessive; and
that small sulfur recovery plants, or
small petroleum refineries should be
exempt from the standard.
The basic cost data used to develop
the cost estimates were obtained from
pretroleum refinery sources. No specif-
ic data or information was provided in
the public comments, however, which"
would indicate that these costs are sig-
nificantly in error.
In the preamble to the proposed
standards, comments were specifically
invited concerning the impact of the
standards on the small refiner. After
considering these comments, EPA has
concluded that some relief from the
standards is appropriate. The major
factor involved in this decision was a
consideration of the cost effectiveness
of the standards on large and small re-
finers. The incremental cost per incre-
mental unit of sulfur emissions that
must be controlled to meet the stan-
dards is substantially greater for the
small refiner than for the large refin-
er. Furthermore, the impact of these
costs on the small refiner is more
severe than the impact on the large re-
finer, because the small refiner cannot
readily pass on the cost of emission
control equipment. Consequently, as
discussed in volume II of the Stan-
dards Support and Environmental
Impact Statement (SSEIS), the pro-
mulgated standards include a lower
size cutoff for small petroleum refiner-
ies and Claus sulfur recovery plants.
Claus sulfur recovery plants with a
sulfur production capacity of 20 long
tons per day or less associated with a
petroleum refinery with a crude oil
processing capacity of 50,000 BSD or
less, which is owned or controlled by a
refiner whose total combined crude oil
processing capacity is 137,500 BSD or
less, are exempt from the standards.
This definition of a small petroleum
refinery is consistent with that includ-
ed in section 211 of the Clean Air Act,
as amended.
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tULES AND REGULATIONS
EMISSION CONTROL TECHNOLOGY
A major concern of many com-
menters was the limited amount of
source test data used in support of the
numerical emission limits included in
the standards and the fact that some
of these data were collected at refiner-
ies where the emission control system
was operating below design capacity.
Also, some commenters questioned the
ability of the alternative II emission
control systems to continuously oper-
ate at a 99.9 percent control efficiency
because of the adverse impact of Claus
sulfur recovery plant fluctuations and
COa-rich waste gas streams.
In arriving at the numerical emis-
sions limits included in the standards,
source test data collected by a local
agency at times when the emission
control systems were operating at
normal capacities, information from
vendors of emission control equip-
ment, published literature on emission
control technology, and contractor re-
ports on the performance of emission
control technology were considered, in
addition to the data collected during
EPA's source tests. Based on the infor-
mation and data from these sources
and the lack of any new information
and data submitted by the com-
menters, no change in the emission
limits of the standards is warranted.
Furthermore, the numerical emission
limits in the standards contain an ade-
quate safety margin to allow for in-
creased emissions due to Clause sulfur
recovery plant fluctuations.
With repect to the potential adverse
impact of high CO3 gas streams, this is
not likely to impair the overall emis-
sion control system efficiency since
high COj gas streams are seldom
found in the gases treated in refinery
Claus sulfur recovery plants.
ENVIRONMENTAL IMPACT
Several commenters felt that the as-
sessment of the environmental impact
of the standards was, in some cases,
biased and not always clear. One of
these commenters suggested that a
thorough environmental impact state-
ment should be prepared to clarify the
Impacts of the standards.
Litigation involving standards of
performance has established that
preparation of a formal environmental
Impact statement under the National
Environmental Policy Act is not neces-
sary for actions under section 111 of
the Clean Air Act. While a formal en-
vironmental impact statement is not
prepared, the beneficial as well as the
adverse Impacts of standards of per-
formance are considered. The promul-
gated standards will significantly
reduce emissions of sulfur from petro-
leum refineries without resulting in
any significant adverse environmental,
energy, or economic impacts.
Other commenters felt that stan-
dards based on 99 percent control (al-
ternative I) would be essentially as en-
vironmentally beneficial as standards
based on 99.9 percent control and
would be less costly to the public. This
argument was based on the premise
that most State regulations do not re-
quire control of Claus sulfur plant
emissions at the 99 percent level as
claimed in volume I of the SSEIS.
Hence, standards based on alternative
I would significantly reduce national
sulfur emissions from refinery Claus
sulfur recovery plants.
A review of State regulations for
controlling emissions from refinery
sulfur recovery plants has shown that
the majority of the States with the
largest petroleum refining capacities
require 99 percent control of emissions
from new and existing sulfur recovery
plants. Since refinery sulfur recovery
plant growth will likely occur in these
States, the conclusion that standards
based on 99 percent control would
have little or no beneficial impact is
essentially correct.
ENERGY IMPACT
Several commenters questioned the
conclusion that compliance with stan-
dards based on alternative II could
lead to an energy savings, compared to
standards based on alternative I. A
review of the information and data
available confirms this conclusion. In
any case, the important consideration
is whether the energy impact of the
standards is reasonable. No informa-
tion was submitted which would indi-
cate that the energy impact of the
standards is unreasonable.
OTHER CONSIDERATIONS
At proposal comments were request-
ed relative to EPA's decision to regu-
late reduced sulfur compound emis-
sions, which are designated pollutants,
without implementing section lll(d)
of the Clean Air Act at this time. The
one commenter who responded to this
issue was in agreement with this deci-
sion.
As discussed in both the preamble to
the proposed standards and volumes I
and II of the SSEIS, petroleum refin-
ery Claus sulfur recovery plants are
sources of SO2 emissions, not reduced
sulfur compound emissions. One of
the emission control technologies for
reducing SOj emissions, however, first
converts these emissions to reduced
sulfur compounds and then controls
these compounds. Consequently, this
technology may discharge residual
emissions of reduced sulfur com-
pounds to the atmosphere.
Currently, there are about 30 refin-
ery Claus sulfur recovery plants in the
United States which have installed re-
duction emission control systems to
reduce SOj emissions. A review of
these plants indicates that these emis-
sion control systems are well designed
and well maintained and operated.
Emissions of reduced sulfur com-
pounds are less than 0.050 percent
(i.e., 500 ppm), which is only slightly
higher than the numerical emission
limit included in the promulgated
standard. Thus, there is little to gain
at this time by requiring States to de-
velop regulations limiting emissions
from these sources. Consequently, sec-
tion lll(d) will not be implemented
until resources permit, taking into
consideration other requirements of
the Clean Air Act, as amended, which
EPA must implement.
Several commenters were concerned
that Reference Method 15 might not
be practical for use in a refinery envi-
ronment. The basis for most of these
objections was that the commenters
thought this method was being pro-
posed as a continuous monitoring
method. However, Reference Method
15 was not proposed for use as a con-
tinuous monitoring method. Perfor-
mance specifications for continuous
monitors for reduced sulfur com-
pounds have not been developed and
therefore such monitors are not re-
quired to be installed until perfor-
mance specifications for these moni-
tors are proposed and promulgated
under Appendix B of 40 CFR Part 60.
Reference Method 15 has been re-
vised to allow greater flexibility in op-
erating details and equipment choice.
The user is now permitted to design
his own sampling and analysis system
as long as he preserves the operating
principle of gas chromatography with
flame photometric detection and
meets the design and performance cri-
teria.
MISCELLANEOUS
The effective date of this regulation
is March 15, 1978. Section HKbXlXB)
of the Clean Air Act provides that
standards of performance or revisions
of them become effective upon pro-
mulgation and apply to affected facili-
ties, construction or modification of
which was commenced after the date
of proposal (October 4,1976).
ECONOMIC IMPACT ASSESSMENT: An econom-
ic assessment has been prepared as required
under section 317 of the Act. This also satis-
fies the requirements of Executive Orders
11821 and 11949 and OMB Circular A-107.
Dated: March 1, 1978.
DOUGLAS M. COSTLE,
Administrator.
1. Section 60.100 is amended as fol-
lows:
§ 60.100 Applicability and designation of
affected facility.
(a) The provisions of this subpart
are applicable to the following affect-
ed facilities In petroleum refineries:
fluid catalytic cracking unit catalyst
regenerators, fuel gas combustion de-
vices, and all Claus sulfur recovery
plants except Claus plants of 20 long
IV-257
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RULES AND REGULATIONS
tons per day (LTD) or less associated
with a small petroleum refinery. The
Claus sulfur recovery plant need not
be physically located within the
boundaries of a petroleum refinery to
be an affected facility, provided it pro-
cesses gases produced within a petro-
leum refinery.
(b) Any fluid catalytic cracking unit
catalyst regenerator of fuel gas com-
bustion device under paragraph (a) of
this section which commences con-
struction or modification after June
11, 1973, or any Claus sulfur recovery
plant under paragraph (a) of this sec-
tion which commences construction or
modification after October 4, 1976, is
subject to the requirements of this
part.
(Sees. Ill and 301(a). Clean Air Act, as
amended (42 U.S.C. 7411, 7601 (a)), and ad-
ditional authority as noted below.)
2. Section 60.101 is amended as fol-
lows:
§ 60.101 Definitions.
(i) "Claus sulfur recovery plant"
means a process unit which recovers
sulfur from hydrogen sulfide by a
vapor-phase catalytic reaction of
sulfur dioxide and hydrogen sulfide.
(j) "Oxidation control system"
means an emission control system
which reduces emissions from sulfur
recovery plants by converting these
emissions to sulfur dioxide.
(k) "Reduction control system"
means an emission control system
which reduces emissions from sulfur
recovery plants by converting these
emissions to hydrogen sulfide.
(1) "Reduced sulfur compounds"
mean hydrogen sulfide (HzS), carbonyl
sulfide (COS) and carbon disulfide
(CS2).
(m) "Small petroleum refinery"
means a petroleum refinery which has
a crude oil processing capacity of
50,000 barrels per stream day or less,
and which is owned or controlled by a
refinery with a total combined crude
oil processing capacity of 137,500 bar-
rels per stream day or less.
3. Section 60.102 is amended by re-
vising paragraph (a) introductory text
and paragraph (b) as follows:
§ 60.102 Standard for participate matter.
(a) On and after the date on which
the performance test required to be
conducted by § 60.8 is completed, no
owner or operator subject to the provi-
sions of this subpart shall discharge or
cause the discharge into the atmos-
phere from any fluid catalytic crack-
ing unit catalyst regenerator:
(!)*
(2)* *
(b) Where the gases discharged by
the fluid catalytic cracking unit cata-
lyst regenerator pass through an in-
cinerator or waste heat boiler in which
auxiliary or supplemental liquid or
sold fossil fuel is burned, particulate
matter in excess of that permitted by
paragraph (a)(l) of this section may
be emitted to the atmosphere, except
that the incremental rate of particu-
late matter emissions shall not exceed
43.0 g/MJ (0.10 Ib/million Btu) of
heat input attributable to such liquid
or solid fossil fuel.
4. Section 60.104 is amended as fol-
lows:
§ 60.104 Standard for sulfur dioxide.
(a) On and after the date on which
the performance test required to be
conducted by § 60.8 is completed, no
owner or operator subject to the provi-
sions of this subpart shall:
(1) Burn in any fuel gas combustion
device any fuel gas which contains hy-
drogen sulfide in excess of 230 mg/
dscm (0.10 gr/dscf), except that the
gases resulting from the combustion of
fuel gas may be treated to control
sulfur dioxide emissions provided the
owner or operator demonstrates to the
satisfaction of the Administrator that
this is as effective in preventing sulfur
dioxide emissions to the atmosphere
as restricting the H» concentration in
the fuel gas to 230 mg/dscm or less.
The combustion in a flare of process
upset gas, or fuel gas which is released
to the flare as a result of relief valve
leakage, is ' exempt from this para-
graph.
(2) Discharge or cause the discharge
of any gases into the atmosphere from
any Claus sulfur recovery plant con-
taining in excess of:
(i) 0.025 percent by volume of sulfur
dioxide at zero percent oxygen on a
dry basis if emissions are controlled by
an oxidation control system, or a re-
duction control system followed by in-
cineration, or
(ii) 0.030 percent by volume of re-
duced sulfur compounds and 0.0010
percent by volume of hydrogen sulfide
calculated as sulfur dioxide at zero
percent oxygen on a dry basis if emis-
sions are controlled by a reduction
control system not followed by incin-
eration.
(b) [Reserved]
5. Section 60.105 is amended as fol-
lows:
§ 60.105 Emission monitoring.
(a)* *
(2) An instrument for continuously
monitoring and recording the concen-
tration of carbon monoxide in gases
discharged into the atmosphere from
fluid catalytic cracking unit catalyst
regenerators. The span of this con-
tinuous monitoring system shall be
1,000 ppm.
(3)*
(4) An instrument for continuously
monitoring and recording concentra-
tions of hydrogen sulfide in fuel gases
burned in any fuel gas combustion
device, if compliance with
§60.104(a)(l) is achieved by removing
HaS from the fuel gas before it is
burned; fuel gas combustion devices
having a common source of fuel gas
may be monitored at one location, if
monitoring at this location accurately
represents the concentration of H2S in
the fuel gas burned. The span of this
continuous monitoring system shall be
300 ppm.
(5) An instrument for continuously
monitoring and recording concentra-
tions of SO2 in the gases discharged
into the atmosphere from any Claus
sulfur recovery plant if compliance
with § 60.104(a)(2) is achieved through
the use of an oxidation control system
or a reduction control system followed
by incineration. The span of this con-
tinuous monitoring system shall be
sent at 500 ppm.
(6) An instrument(s) for continuous-
ly monitoring and recording the con-
centration of H2S and reduced sulfur
compounds in the gases discharged
into the atmosphere from any Claus
sulfur recovery plant if compliance
with § 60.104(aK2) is achieved through
the use of a reduction control system
not followed by incineration. The
span(s) of this continuous monitoring
system(s) shall be set at 20 ppm for
monitoring and recording the concen-
tration of H2S and 600 ppm for moni-
toring and recording the concentration
of reduced sulfur compounds.
(e)* * *
(1) * * *
(2) Carbon monoxide. All hourly pe-
riods during which the average carbon
monoxide concentration in the gases
discharged into the atmosphere from
any fluid catalytic cracking unit cata-
lyst regenerator subject to §60.103 ex-
ceeds 0.050 percent by volume.
(3) Sulfur dioxide, (i) Any three-
hour period during which the average
concentration of H2S in any fuel gas
combusted in any fuel gas combustion
device subject to § 60.104(a)(l) exceeds
230 mg/dscm (0.10 gr/dscf), if compli-
ance is achieved by removing H2S from
the fuel gas before it is burned; or any
three-hour period during which the
average concentration of SOa in the
gases discharged into the atmosphere
from any fuel gas combustion device
subject to §60.104(a)(l) exceeds the
level specified in §60.104(a)(l), if com-
pliance is achieved by removing SOi
from the combusted fuel gases.
(ii) Any twelve-hour period during
which the average concentration of
SOa in the gases discharged into the
atmosphere from any Claus sulfur re-
covery plant subject to §60.104(a)(2)
exceeds 250 ppm at zero percent
oxygen on a dry basis If compliance
with §60.104(b) is achieved through
the use of an oxidation control system
IV-258
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RULES AND REGULATIONS
or a reduction control system followed
by incineration; or any twelve-hour
period during which the average con-
centration of H2S, or reduced sulfur
compounds in the gases discharged
into the atmosphere of any Claus
sulfur plant subject to § 60.104(a)(2)
(b) exceeds 10 ppm or 300 ppm, respec-
tively, at zero percent oxygen and on a
dry basis if compliance is achieved
through the use of a reduction control
system not followed by incineration.
6. Section 60.106 is amended as fol-
lows:
§ 60.106 Test methods and procedures.
(c) For the purpose of determining
compliance with § 60.104(a)(l),
Method 11 shall be used to determine
the concentration of H2S and Method
6 shall be used to determine the con-
centration of SO,.
(1) If Method 11 is used, the gases
sampled shall be introduced into the
sampling train at approximately atmo-
spheric pressure. Where refinery fuel
gas lines are operating at pressures
substantially above atmosphere, this
may be accomplished with a flow con-
trol valve. If the line pressure is high
enough to operate the sampling train
without a vacuum pump, the pump
may be eliminated from the sampling
train. The sample shall be drawn from
a point near the centroid of the fuel
gas line. The minimum sampling time
shall be 10 minutes and the minimum
sampling volume 0.01 dscm (0.35 dscf)
for each sample. The arithmetic aver-
age of two samples of equal sampling
time shall constitute one run. Samples
shall be taken at approximately 1-
hour intervals. For most fuel gases,
sample times exceeding 20 minutes
may result in depletion of the collect-
ing solution, although fuel gases con-
taining low concentrations of hydro-
gen sulfide may necessitate sampling
for longer periods of time.
(2) If Method 6 is used, Method 1
shall be used for velocity traverses and
Method 2 for determining velocity and
volumetric flow rate. The sampling
site for determining SO, concentration
by Method 6 shall be the same as for
determining volumetric flow rate by
Method 2. The sampling point in the
duct for determining SO, concentra-
tion by Method 6 shall be at the cen-
troid of the cross section if the cross
sectional area is less than 5 m! (54 ft2)
or at a point no closer to the walls
than 1 m (39 inches) if the cross sec-
tional area is 5 m* or more and the
centroid is more than one meter from
the wall. The sample shall be extract-
ed at a rate proportional to the gas ve-
locity at the sampling point. The mini-
mum sampling time shall be 10 min-
utes and the minimum sampling
volume 0.01 dscm (0.35 dscf) for each
sample. The arithmetic average of two
samples of equal sampling time shall
constitute one run. Samples shall be
taken at approximately 1-hour inter-
vals.
(d) For the purpose of determining
compliance with §60.104(a)(2),
Method 6 shall be used to determine
the concentration of SO, and Method
15 shall be used to determine the con-
centration of HaS and reduced sulfur
compounds.
(1) If Method 6 is used, the proce-
dure outlined in paragraph (c)(2) of
this section shall be followed except
that each run shall span a minimum
of four consecutive hours of continu-
ous sampling. A number of separate
samples may be taken for each run,
provided the total sampling time of
these samples adds up to a minimum
of four consecutive hours. Where more
than one sample is used, the average
SO, concentration for the run shall be
calculated as the time weighted aver-
age of the SOj concentration for each
sample according to the formula:
Where:
C« = SOi concentration for the run.
N- Number of samples.
Cs, = SC>2 concentration for sample t.
ts, = Continuous sampling time of sample t.
T= Total continuous sampling time of all
N samples.
(2) If Method 15 is used, each run
shall consist of 16 samples taken over
a minimum of three hours. The sam-
pling point shall be at the centroid of
the cross section of the duct if the
cross sectional area is less than 5 m2
(54 ft2) or at a point no closer to the
walls than 1 m (39 inches) if the cross
sectional area is 5 m2 or more and the
centroid is more than 1 meter from
the wall. To insure minimum residence
time for the sample inside the sample
lines, the sampling rate shall be at
least 3 liters/minute (0.1 ftVmin). The
SO2 equivalent for each run shall be
calculated as the arithmetic average of
the SO2 equivalent of each sample
during the run. Reference Method 4
shall be used to determine the mois-
ture content of the gases. The sam-
pling point for Method 4 shall be adja-
cent to the sampling point for Method
15. The sample shall be extracted at a
rate proportional to the gas velocity at
the sampling point. Each run shall
span a minimum of four consecutive
hours of continuous sampling. A
number of separate samples may be
taken for each run provided the total
sampling time of these samples adds
up to a minimum of four consecutive
hours. Where more than one sample is
used, the average moisture content for
the run shall be calculated as the time
weighted average of the moisture con-
tent of each sample according to the
formula:
J3u.= Proportion by volume of water vapor
in the gas stream for the run.
A'=Number of samples.
Bn Proportion by volume of water vapor
in the gas stream for the sample £
&, = Continuous sampling time for sample
t.
7"=Total continuous sampling time of all
N samples.
(Sec. 114 of the Clean Air Act, as amended
[42U.S.C. 74141).
APPENDIX AREFERENCE METHODS
7. Appendix A is amended by adding
a new reference method as follows:
METHOD 15. DETERMINATION OF HYDROGEN
SULFIDE. CARBONYL SULFIDE, AND CARBON
DISULFIDE EMISSIONS PROM STATIONARY
SOURCES
INTRODUCTION
The method described below uses the
principle of gas chromatographic separation
and flame photometric detection (FPD).
Since there are many systems or sets of op-
erating conditions that represent usable
methods of determining sulfur emissions, all
systems which employ this principle, but
differ only In details of equipment and oper-
ation, may be used as alternative methods,
provided that the criteria set below are met.
1. Principle and applicability
1.1 Principle. A gas sample Is extracted
from the emission source and diluted with
clean dry air. An aliquot of the diluted
sample is then analyzed for hydrogen sul-
fide (H,S), carbonyl sulfide (COS), and
carbon disulfide (CSj) by gas chromatogra-
phic (GO separation and flame photomet-
ric detection (FPD).
1.2 Applicability. This method is. applica-
ble for determination of the above sulfur
compounds from tall gas control units of
sulfur recovery plants.
2. Range and sensitivity
2.1 Range. Coupled with a gas chromto-
graphic system utilizing a 1-milliliter sample
size, the maximum limit of the FPD for
each sulfur compound is approximately 10
ppm. It may be necessary to dilute gas sam-
ples from sulfur recovery plants hundred-
fold (99:1) resulting In an upper limit of
about 1000 ppm for each compound.
2.2 The minimum detectable concentra-
tion of the FPD is also dependent on sample
size and would be about 0.5 ppm for a 1 ml
sample.
3. Interferences
3.1 Moisture Condensation. Moisture con-
densation in the sample delivery system, the
analytical column, or the FPD burner block
can cause losses or Interferences. This po-
tential Is eliminated by heating the sample
line, and by conditioning the sample with
dry dilution air to lower its dew point below
the operating temperature of the OC/FPD
analytical system prior to analysis.
3.2 Carbon Monoxide and Carbon Dioxide.
CO and CO, have substantial desensitizing
IV-259
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RULES AND REGULATIONS
effects on the flame photometric detector
even after 9.1 dilution (Acceptable systems
must demonstrate that they have eliminat-
ed this interference by some procedure such
as eluding CO and CO, before any of the
sulfur compounds to be measured.) Compli-
ance with this requirement can be demon-
strated by submitting chromatograms of
calibration gases with and without CO, in
the diluent gas. The CO, level should be ap-
proximately 10 percent for the case with
CO, present. The two chromatographs
should show agreement within the precision
limits of section 4.1.
3 3 Elemental Sulfur. The condensation of
sulfur vapor in the sampling line can lead to
eventual coating and even blockage of the
sample line. This problem can be eliminated
along with the moisture problem by heating
the sample line.
4. Precision
4 1 Calibration Precision, A series of three
consecutive injections of the same calibra-
tion gas. at any dilution, shall produce re-
sults which do not vary by more than ±13
percent from the mean of the three injec-
tions.
4.2 Calibration Drift. The calibration drift
determined from the mean of three injec-
tions made at the beginning and end of any
8-hour period shall not exceed ±5 percent.
5. Apparatus
5.1.1 Probe. The probe must be made of
inert material such as stainless steel or
glass. It should be designed to incorporate a
filter and to allow calibration gas to enter
the probe at or near the sample entry point.
Any portion of the probe not exposed to the
stack gas must be heated to prevent mois-
ture condensation.
5.1.2 The sample line must be made of
Teflon,' no greater than 1.3 cm (Vz in) inside
diameter. All parts from the probe to the di-
lution system must be thermostatically
heated to 120° C.
5.1.3 Sample Pump. The sample pump
shall be a leakless Teflon coated diaphragm
type or equivalent. If the pump is upstream
of the dilution system, the pump head must
be heated to 120' C.
5.2 Dilution System. The dilution system
must be constructed such that all sample
contacts are made of inert material (e.g.
stainless steel or Teflon). It must be heated
to 120° C and be capable of approximately a
9:1 dilution of the sample.
5.3 Gas Chromatograph. The gas chroma-
tograph must have at least the following
components'.
5.3.1 Oven. Capable of maintaining the
separation column at the proper operating
temperature ±1' C.
5.3.2 Temperature Gauge. To monitor
column oven, detector, and exhaust tem-
perature ±1° C.
5.3.3 Flow System. Gas metering system to
measure sample, fuel, combustion gas, and
carrier gas flows.
5.3.4 Flame Photometric Detector.
5.3.4.1 Electrometer. Capable of full scale
amplification of linear ranges of 10"'to 10"'
amperes full scale.
5.3.4.2 Power Supply. Capable of deliver-
ing up to 750 volts.
5.3 4.3 Recorder. Compatible with the
output voltage range of the electrometer.
'Mention of trade names or specific prod-
ucts does not constitute an endorsement by
the Environmental Protection Agency.
5.4 Gas Chromatograph Columns. The
column system must be demonstrated to be
capable of resolving three major reduced
sulfur compounds: H,S, COS, and CS,.
To demonstrate that adequate resolution
has been achieved the tester must submit a
Chromatograph of a calibration gas contain-
ing all three reduced sulfur compounds in
the concentration range of the applicable
standard. Adequate resolution will be de-
fined as base line separation of adjacent
peaks when the amplifier attenuation is set
so that the smaller peak is at least 50 per-
cent of full scale. Base line separation is de-
fined as a return to zero ±5 percent in the
Interval between peaks. Systems not meet-
Ing this criteria may be considered alternate
methods subject to the approval of the Ad-
ministrator.
5.5.1 Calibration System. The calibration
system must contain the following compo-
nents.
5.5.2 Flow System. To measure air flow
over permeation tubes at ±2 percent. Each
flowmeter shall be calibrated after a com-
plete test series with a wet test meter. If the
flow measuring device differs from the wet
test meter by 5 percent, the completed test
shall be discarded. Alternatively, the tester
may elect to use the flow data that would
yield the lowest flow measurement. Calibra-
tion with a wet test meter before a test is
optional.
5.5.3 Constant Temperature Bath. Device
capable of maintaining the permeation
tubes at the calibration temperature within
±1.1° C.
5.5.4 Temperature Gauge. Thermometer
or equivalent to monitor bath temperature
within ±1° C.
6. Reagents
6.1 Fuel. Hydrogen
-------
RULES AND REGULATIONS
M = Molecular weight of the permeant: g/
g-mole.
L=Flow rate, 1/min. of air over permeant
@ 20°C, 760 mm Hg.
K = Gas constant at 20'C and 760 mm
Hg = 24.04 1/gmole.
8.3 Calibration of analysis system. Gener-
ate a series of three or more known concen-
trations spanning the linear range of the
PPD (approximately 0.05 to 1.0 ppm) for
each of the four major sulfur compounds.
Bypassing the dilution system, inject these
standards in to the GC/FPD analyzers and
monitor the responses. Three injects for
each concentration must yield the precision
described in section 4.1. Failure to attain
this precision is an indication of a problem
in the calibration or analytical system. Any
such problem must be identified and cor-
rected before proceeding.
8.4 Calibration Curves. Plot the GC/FPD
response in current (amperes) versus their
causative concentrations in ppm on log-log
coordinate graph paper for each sulfur com-
pound. Alternatively, a least squares equa-
tion may be generated from the calibration
data.
8.5 Calibration of Dilution System. Gener-
ate a know concentration of hydrogen sul-
fied using the permeation tube system.
Adjust the flow rate of diluent air for the
first dilution stage so that the desired level
of dilution is approximated. Inject the dilut-
ed calibration gas into the GC/FPD system
and monitor its response. Three injections
for each dilution must yield the precision
described In section 4.1. Failure to attain
this precision in this step is an indication of
a problem in the dilution system. Any such
problem must be identified and corrected
before proceeding. Using the calibration
data for H.S (developed under 8.3) deter-
mine the diluted calibration gas concentra-
tion in ppm. Then calculate the dilution
factor as the ratio of the calibration gas
concentration before dilution to the diluted
calibration gas concentration determined
under this paragraph. Repeat this proce-
dure for each stage of dilution required. Al-
ternatively, the GC/FPD system may be
calibrated by generating a series of three or
more concentrations of each sulfur com-
pound and diluting these samples before in-
jecting them into the GC/FPD system. This
data will then serve as the calibration data
for the unknown samples and a separate de-
termination of the dilution factor will not
be necessary. However, the precision re-
quirements of section 4.1 are still applicable.
9. Sampling and Analysis Procedure
9.1 Sampling. Insert the sampling probe
Into the test port making certain that no di-
lution air enters the stack through the port.
Begin sampling and dilute the sample ap-
proximately 9:1 using the dilution system.
Note that the precise dilution factor is that
which is determined in paragraph 8.5. Con-
dition the entire system with sample for a
minimum of 15 minutes prior to commenc-
ing analysis.
9.2 Analysis. Aliquots of diluted sample
are injected into the GC/FPD analyzer for
analysis.
9.2.1 Sample Run. A sample run is com-
posed of 16 individual analyses (injects) per-
formed over a period of not less than 3
hours or more than 6 hours.
9.2.2 Observation for Clogging of Probe. If
reductions in sample concentrations are ob-
served during a sample run that cannot be
explained by process conditions, the sam-
pling must be interrupted to determine if
the sample probe is clogged with particulate
matter. If the probe is found to be clogged,
the test must be stopped and the results up
to that point discarded. Testing may resume
after cleaning the probe or replacing it with
a clean one. After each run, the sample
probe must be inspected and, if necessary,
dismantled and cleaned.
10. Post-Test Procedures
10 1 Sample Line Loss. A known concen-
tration of hydrogen sulfide at the level of
the applicable standard, ±20 percent, must
be introduced into the sampling system at
the opening of the probe in sufficient quan-
tities to ensure that there is an excess of
sample which must be vented to the atmo-
sphere. The sample must be transported
through the entire sampling system to the
measurement system in the normal manner.
The resulting measured concentration
should be compared to the known value to
determine the sampling system loss. A sam-
pling system loss of more than 20 percent is
unacceptable. Sampling losses of 0-20 per-
cent must be corrected by dividing the re-
sulting sample concentration by the frac-
tion of recovery. The known gas sample may
be generated using permeation tubes. Alter-
natively, cylinders of hydrogen sulfide
mixed in air may be used provided they are
traceable to permeation tubes. The optional
pretest procedures provide a good guideline
for determining if there are leaks in the
sampling system.
10.2 Recalibration. After each run, or
after a series of runs made within a 24-hour
period, perform a partial recalibration using
the procedures in section 8. Only H.S (or
other permeant) need be used to recalibrate
the GC/FPD analysis system (8.3) and the
dilution system (8.5).
10 3 Determination of Calibration Drift.
Compare the calibration curves obtained
prior to the runs, to the calibration curves
obtained under paragraph 10.1. The calibra-
tion drift should not exceed the limits set
forth in paragraph 4.2. If the drift exceeds
this limit, the intervening run or runs
should be considered not valid. The tester,
however, may instead have the option of
choosing the calibration data set which
would give the highest sample values.
11. Calculations
11.1 Determine the concentrations of each
reduced sulfur compound detected directly
from the calibration curves. Alternatively,
the concentrations may be calculated using
the equation for the least squares line.
11.2 Calculation of SO, Equivalent. SO,
equivalent will be determined for each anal-
ysis made by summing the concentrations of
each reduced sulfur compound resolved
during the given analysis.
SO, equivalent = 2(H,S. COS, 2 CS,)d
Equation 15-2
where
SO, equivalent = The sum of the concen-
tration of each of the measured com-
pounds (COS, H*S, CS,) expressed as
sulfur dioxide in ppm.
H,S = Hydrogen sulfide, ppm.
COS = Carbonyl sulfide, ppm.
CS,=Carbon disulfide, ppm.
d=Dilution factor, dimensionless.
11.3 Average SO, equivalent will be deter-
mined as follows:
Average SO. equivalen
N
I 5
i = 1
equtv.
Tn - Bwo)
Equation 15-3
where:
Average SO, equivalent, = Average SO,
equivalent in ppm, dry basis.
Average SO, equivalent, = SO, in ppm as
determined by Equation 15-2.
N = Number of analyses performed.
Bwo = Fraction of volume of water vapor
in the gas stream as determined by
Method 4Determination of Moisture
in Stack Gases (36 FR 24887).
12. Example System
Described below is a system utilized by
EPA in gathering NSPS data. This system
does not now reflect all the latest develop-
ments in equipment and column technology,
but it does represent one system that has
been demonstrated to work.
12.1 Apparatus.
12.1.1 Sample System.
12.1.1.1 Probe. Stainless steel tubing, 6.35
mm (V4 in.) outside diameter, packed with
glass wool.
12.1.1.2 Sample Line, ^n inch inside diam-
eter TeHon tubing heated to 120' C. This
temperature is controlled by a thermostatic
heater.
12.1.1.3 Sample Pump. Leakless Teflon
coated diaphragm type or equivalent. The
pump head is heated to 120' C by enclosing
it in the sample dilution box (12.2.4 below).
12.1.2 Dilution System. A schematic dia-
gram of the dynamic dilution system is
given in Figure 15-2. The dilution system is
constructed such that all sample contacts
are made of inert materials. The dilution
system which is heated to 120° C must be ca-
pable of a minimum of 9:1 dilution of
sample. Equipment used in the dilution
system is listed below:
12.1.2.1 Dilution Pump. Model A-150 Koh-
myhr Teflon positive displacement type,
nonadjustable 150 cc/min. ±2.0 percent, or
equivalent, per dilution stage. A 9:1 dilution
of sample is accomplished by combining 150
cc of sample with 1350 cc of clean dry air as
shown in Figure 15-2.
12.1.2.2 Valves. Three-way Teflon solenoid
or manual type.
12.1.2.3 Tubing. Teflon tubing and fittings
are used throughout from the sample probe
to the GC/FPD to present an inert surface
for sample gas.
12.1.2.4 Box. Insulated box, heated and
maintained at 120° C, of sufficient dimen-
sions to house dilution apparatus.
12.1.2.5 Flowmeters. Rotameters or equiv-
alent to measure flow from 0 to 1500 ml/
rain. ± 1 percent per dilution stage.
12.1.3.0 Gas Chromatograph.
12.1.3.1 Column1.83 m (6 ft.) length of
Tenon tubing, 2.16 mm (0.085 in.) inside di-
ameter, packed with deactivated silica gel,
or equivalent.
12.1.3.2 Sample Valve. Tenon six port gas
sampling valve, equipped with a 1 ml sample
loop, actuated by compressed air (Figure 15-
1).
12.1.3.3 Oven. For containing sample
valve, stripper column and separation
column. The oven should be capable of
maintaining an elevated temperature rang-
ing from ambient to 100° C, constant within
±rc.
IV-261
-------
RULES AND REGULATIONS
12.1.34 Temperature Monitor Thermo-
couple pyrometer to measure column oven.
detector, and exhaust temperature ±T C.
12.1.3.5 Flow System. Gas metering
system to measure sample flow, hydrogen
flow, oxygen flow and nitrogen carrier gas
flow.
12.1.3.6 Detector. Flame photometric de-
tector.
12.1.3.7 Electrometer. Capable of full scale
amplification of linear ranges of 10~'to 10~4
amperes full scale.
12.1.3.8 Power Supply. Capable of deliver-
ing up to 750 volts.
12.1.3.9 Recorder. Compatible with the
output voltage range of the electrometer.
12.1.4 Calibration. Permeation tube
system (Figure 15-3).
12.1.4.1 Tube Chamber. Glass chamber of
sufficient dimensions to house permeation
tubes.
12.1.4.2 Mass Flowmeters. Two mass flow-
meters in the range 0-3 1/min. and 0-10 I/
min. to measure air flow over permeation
tubes at ±2 percent. These flowmeters shall
be cross-calibrated at the beginning of each
test. Using a convenient flow rate in the
measuring range of both flowmeters, set
and monitor the flow rate of gas over the
permeation tubes. Injection of calibration
gas generated at this now rate as measured
by one flowmeter followed by injection of
calibration gas at the same flow rate as mea-
sured by the other flowmeter should agree
within the specified precision limits. If they
do not, then there is a problem with the
mass flow measurement. Each mass flow-
meter shall be calibrated prior to the first
test with a wet test meter and thereafter at
least once each year.
12.1.4.3 Constant Temperature Bath. Ca-
pable of maintaining permeation
-------
RULES AND REGULATIONS
tkm notice. In addition to the errors in
the methods themselves, two typo-
graphical errors were discovered in the
preamble. On page 41754, under
"Method 7," the phrase "variable wave
length" is corrected to read "single
and double-beam." On page 41755,
under "Method 8," the word "content"
(in point No. 4) is corrected to read
"components."
NOTB.The Environmental Protection
Agency has determined that this document
does not contain a major proposal requiring
preparation of an Economic Impact Analy-
tic.
Dated: March 13, 1878.
DAVID A, HAWKINS,
Assistant Administrator
for Air and Waste Management,
Part 60 of Chapter I. Title 40 of the
Code of Federal Regulations is amend-
ed as follows:
APPENDIX AREFERENCE METHODS
In Method 1 of Appendix A, Sections
2.3.1, 2.3.2, and 2.4 and Table 1-1 are
amended as follows:
1. In Section 2.3.1, the word "adcord-
ing" in the second line is corrected to
read "according."
2. In Section 2.3.2, insert after the
first paragraph the following:
If the tester desires to use more than the
minimum number of traverse points,
expand the "minimum number of traverse
point*" matrix (see Table 1-1) by adding the
extra traverse points along one or the other
or both legs of the matrix; the final matrix
need not be balanced. For example, if a 4x3
"minimum number of points" matrix were
expanded to W points, the final matrix
could be 9x4 or 12x3, and would not neces-
sarily have to be 6x6. After constructing the
final matrix, divide the stack cross-section
into as many equal rectangular, elemental
areas as traverse points, and locate a tra-
verse point at the centroid of each equal
area
3. In Section 2.4, the word "travrse"
in the fifteenth line of the second
paragraph is corrected to read "tra-
verse."
4. In Table 1-1, more the words
"Number of traverse points" to the
left, so that they are centered above
the numbers listed to the left-hand
column.
In Method 2 of Appendix A, Sections
2.1, 2.2, 2,4, 3.2, 4.1, 4.1.2, 4.1.4.1.
4.1.5.2. and 6 are amended as follows;
1. In Section 2.1, "±" is inserted in
front of the "5 percent" in the four-
teenth line of the third paragraph.
2. In Section 2.2, "measuremen t" in
the next-to-the last line of the first
paragraph is corrected to read "mea-
surement."
3. In Section 2.4, "Type X" In the
fifth line is corrected to read "Type
S."
4. In Section 3.2, "ma" in the first
line is corrected to read "ma-."
5. In Section 4.1. "R," In the seventh
line of the second paragraph is re-
placed with 'TV'
6. In Section 4.1.2, "B." is inserted
between the words "other," and "Cali-
bration."
7. In Section 4.1.4.1, "C,,u)=Type S
pOot tube coefficient" is corrected to
read "C,w=Type S pitot tube coeffi-
cient."
8. In Section 4.1.5.2, the words
"pitot-nozzel" in the third line are cor-
rected to read "pitot-nozzle."
9. In Section 6, Citations 9, 13, and
18 are amended as follows:
a. In No. 9, the word "Tiangle" is
corrected to read "Triangle."
b. In No. 13, the "s" In 'Techniques"
is deleted.
c. In No. 18, the word "survey" is
corrected to read "Survey."
In Method 3 of Appendix A, Sections
1.2, 3.2.4, 4.2.6.2, 6.2, and 7 are amend-
ed as follows:
1. In Section 1.2. the title ",U. S. En-
vironmental Protection Agency." is in-
serted at the end of the second para-
graph.
2. In Section 3.2.4, "CO" in the tenth
line is corrected to read "COi."
3. In Section 4.2.6.2(b), the phrase
"or equal to" is inserted between
"than" and "15.0."
4. In Section 6.2, Equation 3-1 is cor-
rected to read as follows:
5. In Section 7, Bibliography, No. 2.
the word "with" is inserted between
the words "Sampling" and "Plastic."
In Method 4 of Appendix A, Sections
2.1.2, 2.2.1, 2.2.3. 2.3.1, 3.1.8, 3.2.1. 3.3.1,
3.3.3. 3.3.4, and Figure 4-2 are amend-
ed as follows:
1. In Section 2.1.2, the word "neasur-
ement" in the third line of the third
paragraph is corrected to read "mea-
surement."
2. In Section 2.2.1, the word
"travers" in the sixth line is corrected
to read "traverse."
3. In Section 2.2.3, the work "eak" in
the last sentence is corrected to read
"leak."
4. In Figure 4-2, the word "ocation"
in the second line on top of the figure,
is corrected to read "Location."
5. In Section 2.3.1, "M»" is changed
to read "M," and "P." v» changed to
read "pr"
6. In Section 3.1.8, "31 pm" is cor-
rected to read "3 1pm".
7. In Section 3.2.1. delete all of first
paragraph except the first sentence
and insert the following:
Leak check the sampling train as follows:
Temporarily insert h vacuum gauge at or
near the probe inlet; then, plug the probe
inlet and pull a vacuum of at least 250 mm
Hg (10 In. Hg). Note, the time rate of
change of the dry gas meter dial; alternati-
vely, a rotameter (0-40 oc/min) may be tem-
porarily attached to the dry gas meter
outlet to determine the leakage rate. A leak
rate not in exceae of 2 percent of the aver-
age sampling rate is acceptable.
NOTE.Carefully release the probe Inlet
plug before turning off the pump.
8. In Section 3.3.1, add the following
definition to the list:
Y=Dry gas meter calibration factor.
Also, "ow" is corrected to read >".
9. In Section 3.3.3, Equation 4-6 is
corrected to read as follows:
10. In Section 3.3.4, Equation 4-7 is
corrected to read as follows:
"C(SKI)
std)
V(stt) V»U)
(0.025)
In Method 5 of Appendix A, Sections
2.1.1, 2.2.4, 4.1.2, 4.1.4.2, 4.2, 6.1, 6.3,
6.11.1, and 6.11.2 are amended as fol-
lows:
1. In Section 2.1.1, the word "proble"
In the fourth line is corrected to read
"probe."
2. In Section 2.2.4, "polO-" is correct-
ed to read "poly-".
3. In Section 4.1.2, the sentence
"The sampling time at each point
shall be the same." is inserted at the
end of the fifth paragraph.
4. In Section 4.1.4.2, the word "It" in
the seventh line is corrected to read
"it."
5. In Section 4.2, the word "nylon"
in the seventh, ninth, and thirteenth
paragraphs is corrected to read
"Nylon."
6. In Section 8.1 Nomenclature,
"C.=Acetone blank residue concentra-
tions, mg/g" is corrected to read
"C.=Acetone blank residue concentra-
tion, mg/g" and "V." is changed to
read "v,."
7. In Section 6.3, page 41782,
"m,=0.3858 "K/rnm Hg for metric
units" is corrected to read "K,= 0.3858
"K/mm Hg for metric units."
8. In Section 6.11.1, Equation 5-7 is
corrected to read as follows:
9. In Section 6.11.2, the second form
of Equation 5-8 is corrected to read as
follows:
In Method 6 of Appendix A, Sections
2.1, 2.1.6, 2.1.7, 2.1.8, 2.1.11. 2.1.12,
2.3.2, 3.3.4. 4.1.2, 4.1.3. and 6.1.1 are
amended as follows:
IV-263
-------
RULES AND REGULATIONS
1. In Section 2.1, the word ~periox-
Ide" In the fourth line of the second
paragraph is corrected to read "perox-
ide."
2. In Section 2.1.6, the word "siliac"
In the third line ie corrected to read
"silica."
3. In Section 2.1.7, the word "value".
which appears twice is corrected to
read "valve."
4. In Section 2.1.8, the word "disph-
ragm" is corrected to read "dia-
phragm" and the word "surge" is in-
serted between the words "small" and
"tank."
5. In Section 2.1.11, the -word "amer-
oid" is corrected to read "aneroid."
6. In Section 2.1.12, the phrase "and
Rotameter." is inserted after the
phrase "Vacuum Gauge" and the
phrase "and 0-40 cc/min rotameter" is
inserted between the words "gauge"
and ", to."
7. In Section 2,3.2, the phrase "and
lOO-ml size" is corrected to read "and
1000-ml size."
8. In Section .3.3.4, the word "sopro-
panol" in the fourth line is corrected
to read "isopropanol."
9. In Section 4.1.2, delete the last
sentence of the last paragraph. Also
delete the second paragraph and re-
place it with the following paragraphs:
Temporarily attach a suitable (e.g., tMO
«e/min) rotameter to the outlet of the dry
gas meter and place a vacuum gauge at or
near the probe inlet. Plug the probe inlet,
poll a vacuum of at least 250 mm Hg <10 in.
Hg). and note the flow rate as indicated by
the rotameter. A leakage rate not in excess
Of 2 percent of the average sampling rate is
acceptable.
NOTE Carefully release the probe Inlet
{dug before turning off the pump.
It is suggested (not mandatory) that the
pump be leak-checked separately, either
prior to or after the sampling run. If done
prior to the sampling run, the pump leak-
check shall precede the leak check of the
sampling train described immediately above;
U done after the sampling run, the pump
leak-check shall follow the train leak-check.
To leak check the pump, proceed as follows:
Disconnect the drying tube from the probe-
Implnger assembly. Place a vacuum gauge at
the Inlet to either the drying tube or the
pump, pull a vacuum of 250 ""p (10 in.) Hg.
plug or pinch off the outlet of the flow
meter and then turn off the pump. The
vacuum should remain stable for at least 30
seconds.
10. In Section 4.1.3, the sentence "If
a leak is found, void the test run" on
the sixteenth line IB corrected to read
"U a leak Is found, void the test run, or use
procedures acceptable to the Administrator
to adjust the sample volume for the leak-
age."
11. In Section 5.1.1, the word "or" on
the sixth line is corrected to read "of."
In Method 7 of Appendix A, Sections
2.3.2. 2.3.7, 4.2, 4.3, 5.2.1, 5.2.2, 6 and 7
are amended as follows:
1. In Section 2.3.2, a semicolon re-
places the comma between the words
"step" and "the."
2. In Section 2.3.7, the phrase "(one
for each sample)" in the first line is
corrected to read "(one for each.
sample and each standard)."
3. In Section 4.2, the letter "n"- in
the seventh line is corrected to read
"in."
4. In Section 4.3, the word "poyleth-
ylene" in the seventeenth line is cor-
rected to read "polyethylene."
5. In Section 5.2.1. delete the entire
section and insert the following:
Optimum Wavelength Determination.
Calibrate the wavelength scale of the spec-
trophotometer every 6 months. The calibra-
tion may be accomplished by using an
energy source with an intense line emission
such as a mercury lamp, or by using a series
of glass filters spanning the measuring
range of the spectrophotometer. Calibration
materials are available commercially and
from the National Bureau of Standards.
Specific details on the use of such materials
should be supplied by the vendor; general
information about calibration techniques
can be obtained from general reference
books on analytical chemistry. The wave-
length scale of the spectrophotometer must
read correctly within ± 5 nm at all calibra-
tion points; otherwise, the spectrophoto-
aaeter shall be repaired and recalibrated.
Once the wavelength scale of the spectro-
photometer is in proper calibration, use 410
nm as the optimum wavelength for the mea-
surement of the absorbance of the stan-
dards and samples.
Alternatively, a scanning procedure may
be employed to determine the proper mea-
suring wavelength. If the instrument is a
double-beam spectrophotometer, scan the
spectrum between 400 and 415 nm using a
100 pg NO, standard solution in the sample
cell and a blank solution in the reference
cell. If a peak does not occur, the spectro-
photometer Is probably malfunctioning and
should be repaired. When a peak is obtained
within the 400 to 415 nm range, the wave-
length at which this peak occurs shall be
the optimum wavelength for the measure-
ment of absorbance of both the standards
and the samples. For a single-beam spectro-
photometer, follow the scanning procedure
described above, except that the blank and
standard solutions shall be scanned sepa-
rately. The optimum wavelength shall be
the wavelength at which the maximum dif-
ference in absorbance between the standard
and the blank occurs.
6. In Section 5.2.2, delete the first
seven lines and insert the following:
Determination of Spectrophotometer
Calibration Factor K«. Add 0.0 ml, 2 ml. 4
ml, 6 ml, and 8 ml of the KNO1 working
standard solution (1 ml = 100 fig NO,) to a
series of five 50-ml volumetric flasks. To
each flask, add 25 ml of absorbing solution,
10 ml deionteed, distilled water, and sodium
hydroxide (1 N) dropwise until the pH U be-
tween 8 and 12 Cabout 25 to 35 drops each).
Dilute to the mark with deionized, distilled
water. Mix thoroughly and pipette a 25-ml
aliquot of each solution into a separate por-
celain evaporating dish.
7. In Section 6.1, the word "Hass" in
the tenth line is corrected to read
"Mass."
8. In Section 7, the word "Vna" in
(1) is corrected to read "Van." The
word "drtermination" in (6) is correct-
ed to read "Determination."
In Method 8 of Appendix A, Sections
1.2, 2.32, 4.1.4, 4.2.1, 4.3.2, 6.1, and 6.7.1
are amended as follows:
1. In Section 1.2, the phrase "U.S.
EPA," is inserted in the fifth line of
the second paragraph between the
words "Administrator," and "are."
Also, delete the third paragraph and
insert, the following:
Filterable partlculate matter may be de-
termined along with SO, and SO, (subject to
the approval oJ the Administrator) by In-
serting a heated glass fiber filter between
the probe and isopropanol impinger (see
Section 2.1 of Method 6). If this option is
chosen, particulate analysis is gravimetric
only; H.SO. acid mist is not determined sep-
arately.
IV-264
-------
RULES AND REGULATIONS
2. In Section 2.3.2, the word "Bur-
rette" Is corrected to read "Burette."
3. In Section 4.1.4, the stars " * "
are corrected to read as periods ". . .".
4. In Section 4.2.1, the word "het" on
the eighth line of the second para-
graph is corrected to read "the."
5. In Section 4.3.2, the number "40"
is inserted in the fourth line between
the words "Add" and "ml."
6. In Section'6.1, Nomenclature, the
following are corrected to read ai
shown with subscripts "C^ia*, C»o2,
P*r. P**, TiU,, VO.UUD, and VKtm."
7. In Section 6.7.1, Equation 8-4 is
corrected to read as follows:
(Sees. Ill, 114, 301(a), Clean Air Act as
amended (42 U.S.C. 7411, 7414, 7601).)
[FR Doc. 78-7686 Filed 3-22-78; 8:45 am]
FEDERAL REGISTER, VOL. 43, NO. 57
THURSDAY, MARCH 23, 197S
88
Title 40Protection of Environment
CHAPTER IENVIRONMENTAL
PROTECTION AGENCY
[PRL 841-6]
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY
SOURCES
Katie Oxygen Procesi Furnaces:
Opacity Standard
AGENCY: Environmental Protection
Agency.
ACTION: Final rule.
SUMMARY: This action establishes
an opacity standard for basic oxygen
process furnace (BOPF) facilities. In
March 1974 (39 FR 9308), EPA pro-
mulgated a standard limiting the con-
centration of paniculate matter emis-
sions from BOPF's, however, an opac-
ity standard was not promulgated at
that time becuase of insufficient data
to define variations in visible emis-
sions from well-controlled facilities.
An opacity standard had been pro-
posed on June 11, 1973 (38 FR 15406)
and was reproposed on March 2, 1977
(42 FR 12130). Additional data have
provided the basis for the opacity
standard which will help insure that
control equipment is properly operat-
ed and maintained. like the concen-
tration standard, this opacity standard
applies to BOPF facilities the con-
struction or modification of which was
commenced after June 11, 1973 sine*
both standards were proposed on that
date.
EFFECTIVE DATE: April 13, 1978.
ADDRESS. The public comments re-
ceived may be inspected and copies at
the Public Information Reference
Unit (EPA Library), Room 2922, 401 M
Street SW., Washington, D.C.
FOR FURTHER INFORMATION:
Don R. Goodwin, Emission Stan-
dards and Engineering Division
(MD-13), Environmental Protection
Agency, Research Triangle Park,
North Carolina 27711, telephone No.
919-541-5271.
SUPPLEMENTARY INFORMATION:
COMMENTS
A total of 10 comment letters were
received4 from industry, 5 from gov-
ernmental agencies, and 1 from an en-
vtronmentaJ interest group. The sig-
nificant comments received and EPA's
responses are presented here.
Three commenters expressed the
need for establishing an opacity stan-
dard for fugitive emissions. Fugitive
emissions occur when off gases from
the furnace are not completely cap-
tured by the furnance hood (which
ducts waste gases to the control
device). During some operations, the
fugitive emissions can be significant.
The fugitive emissions escape to the
atmosphere through roof monitors.
EPA recognizes that fugitive emis-
sions from BOPF shops are an impor-
tant problem. However, it was not
within the scope of this evaluation to
consider an opacity standard for fugi-
tive emissions. The particulate concen-
tration standard covers only stack
emissions. The purpose of the opacity
standard for stack emissions is to serve
as a means for enforcement personnel
to insure that the particulate matter
control system is being properly oper-
ated and maintained. EPA will be re-
viewing the standards of performance
for new BOPF's in accordance with
the 1977 amendments to the Clean Air
Act. This review will address the need
for limits on fugitive emissions as well
as any revisions of the particulate con-
centration and opacity standards.
It should be noted that the absence
of standards for fugitive emissions
under this part does not preclude the
establishment of standards as part of
the new source review (NSR) and pre-
vention of significant deterioration
(PSD) programs of the Agency or as
part of the programs of State and
local agencies.
Two commenters Questioned how
the standard would apply to BOPF
shops that have plenums to exhaust
the emissions from more than one fur-
nace into a single control device. They
reasoned that if the production cycles
overlap, it would be impossible to de-
termine when an opacity of greater
than 10 percent (but less than 20 per-
cent) was attributable to a violation by
one furnace or an acceptable emission
by another furnace during oxygen
blowing. EPA was aware that this situ-
ation would occur during the develop-
ment of the opacity standard. Several
of the plants at which visible emission
tests were conducted had B single con-
trol device serving more than one fur-
nace. The furnace production cycle
data were recorded and it was not dif-
ficult to correlate the opacity data
with the production cycle. Enforce-
ment personnel can evaluate a plant's
operation (length of cycle, degree of
overlapping, etc.) prior to completing
an inspection and correctly identify
probable violations from a correlation
of their opacity readings with the
plant's production and monitoring re-
cords. Correlation of the data and the
synchronization requirements de-
scribed later will prevent the enforce-
ment problems described by the com-
menters. Promulgation of an unduly
complex standard that addresses the
peculiarities of every BOPF installa-
tion would complicate rather than
simplify enforcement. Although it is
unlikely that two furnaces will be si-
IV-265
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RULES AND REGULATIONS
multaneously started on a blow, pro-
duction data should be examined for
euch peculiarities before drawing any
conclusions from the opacity data.
Other issues raised Include the
effect of oxygen "reblows" on the
standard and a request for a more le-
nient monitoring requirement. One in-
dustry commenter claimed that there
would be a "significant" number of
production cycles with more than one
opacity reading greater than 10 per-
cent due to the blowing of additional
oxygen (after the initial oxygen blow)
Into a furnace to obtain the proper
composition. The opacity standard,
however, is based on 73 hours of
BOPF operation during which numer-
ous reblows occurred. It was found
that although the opacities could be
very large at these times, they were of
short enough duration that the six-
minute average was still 10 percent or
less.
EPA agrees with the comment that
the requirement for reporting of in-
stantaneous scrubber differential and
water supply pressures that are less
than 10 percent of the average main-
tained during the most recent perfor-
mance test needs further clarification.
The requirement has been revised so
that any deviation of more than 10
percent over a three hour averaging
period must be reported. The three
hour averaging period was chosen
since it is the minimum duration of a
performance test. Thus instantaneous
monitoring device measurements
caused by routing process fluctuations
will not be reported. The reports
needed are the periods of time when
the average scrubber pressure drop is
below the level used to demonstrate
compliance at the time of the perfor-
mance test. In addition, the require-
ment for a water pressure monitor has
been retained (despite the comment
that it will not indicate a plugged
water line) since it win perform the
function of assuring that the water
pumps have not shut down. A flow
monitoring device was not specified
because they are susceptible to plug-
ging.
To provide for the use of certain
partial combustion systems on BOPFs,
new requirements have been added to
the monitoring section and two clarifi-
cations added to the test methods and
procedures section. A partial combus-
tion system uses a closed hood to limn
gas combustion and exhaust gas vol-
umes. To recover combustible exhaust
gases, the system may be designed to
duct its emissions away from the stack
to a gas holding tank during part of
the steel production cycle. Steel plants
In this country may begin to make
more use of this approach due to its
significant energy benefits. This type
of control/recovery system presents
two problems for enforcement person-
nel. First is the problem of knowing
when the diversion of exhaust gases
from the stack occurs The new re-
quirements of paragraphs (a), (b)(3),
and (b)(4) of §60.143 address this ques-
tion. Second is the problem of how to
sample or observe stack emissions.
New provisions under §60.144 clarify
this question for determining the
opacity of emissions (paragraph (a)(5))
and for determining the concentration
of emissions (paragraph (c)).
In addition to addressing the prob-
lem posed by exhaust gas diversion,
the new requirements of paragraphs
(a), (b)(3), and (b)(4) of §60.143 are
also designed to minimise errors In re-
cording the time and duration of the
steel production cycle for all types of
BOPFs. Accurate records are essential
for determining compliance with the
opacity standard. Likewise the syn-
chronization of daily logs with the
chart recorders of monitoring devices
is necessary for determining that ac-
ceptable operation and maintenance
procedures are being used as required
by paragraph (d) of §60.11.
An alternative to the manual
method of synchronization under
paragraph (b)(3) of §60.143 which may
minimize costs of this requirement
would be to have the chart recorder
automatically mark the beginning and
end of the steel production cycle and
any period of gas diversion from the
stack. Such marking could be electri-
cally relayed from the production
equipment and exhaust duct damper
operation in order to be fully automat-
ic. Source owners or operators who
wish to employ this method or equiv-
alent methods in lieu of the synchro-
nization procedure prescribed by the
regulations may submit their plans to
the Administrator for approval under
paragraph 60.13U).
The concentration standard promul-
gated in March, 1974. applies to both
top and bottom-blown BOPFs. In de-
veloping the proposed opacity stan-
dard, data from both types of BOPFs
were considered. Scrubber-controlled
top and bottom-blown BOPFs were
demonstrated capable of meeting the
opacity limits proposed and here pro-
mulgated. Thus the promulgated opac-
ity standard applies to bottom as well
as top-blown BOPFs.
Although there was no announced
intentions to utilize electrostatic preci-
pitators (ESPs) as a control device
(rather than venturi scrubbers),
during the development of the pro-
posed standard, one industry com-
menter asserted that ESPs may
become more attractive in the future,
especially in the semi-arid regions of
the West where thr water and energy
demands of scrubbers are not easily
met. If a BOPF furnace is constructed
with an ESP control device, the estab-
lishment of a site-specific opacity stan-
dard may be necessary. Upon request
by the owner or operator of the BOPF
furnace, a determination will be made
by EPA pursuant to §60.11(e) if per-
formance tests demonstrate compli-
ance with the mass concentration
standard.
MISCELLANEOUS
It should be noted that standards of
performance for new sources estab-
lished under section 111 of the Act re-
flect emission limits achievable with
the best adequately demonstrated
technological system of -continuous
emission reduction (taking into consid-
eration the cost of achieving such
emission reduction, and any nonair
quality health and environmental
Impact and energy requirements).
State implementation plans (SIPs) ap-
proved or promulgated under section
110 of the Act, on the other hand,
must provide for the attainment and
maintenance of national ambient air
quality standards (NAAQS) designed
to protect public health and welfare.
For that purpose, SIPs must in some
cases require greater emission reduc-
tions than those required by standards
of performance for new sources. Sec-
tion 173(2) of the Clean Air Act, re-
quires, among other things, that a new
or modified source constructed in an
area which exceeds the NAAQS must,
reduce emissions to the level which re-
flects the "lowest achievable emission
rate" for such category of source,
unless the owner or operator demon-
strates that the source cannot achieve
such an emission rate. In no event can
the emission rate exceed any applica
ble standard of performance.
A similar situation may arise when a
major emitting facility is to be con-
structed in a geographic area which
falls under the prevention of signifi-
cant deterioration of air quality provi-
sions of the Act (Part C). These provi-
sions require, among other things,
that major emitting facilities to be
constructed in such areas are to be
subject to best available control tech-
nology The term "best available con-
trol technology" (BACT) means "an
emission limitation based on the maxi-
mum degree of reduction of each pol-
lutant subject to regulation under this
Act emitted from or which results
from any major emitting facility,
which the permitting authority, on a
case-by-case basis, taking into account
energy, environmental, and economic
impacts and other costs, determines is
achievable for such facilities through
application of production processes
and available methods, systems, and
techniques, including fuel cleaning or
treatment or innovative fuel combus-
tion techniques for control of each
such pollutant. In no event shall appli-
cation of 'best available control tech-
nology'' result in emissions of any pol-
lutants which will exceed the emis-
sions allowed by any applicable stan-
dard established pursuant to section
111 or 112 of this Act."
IV-266
-------
RULES AND REGULATIONS
Standards of performance should
not be viewed as the ultimate in
achievable emission control and
should not preclude the imposition of
a more stringent emission standard,
where appropriate. For example, while
cost of achievement may be an impor-
tant factor in determining standards
of performance applicable to all areas
of the country (clean as well as dirty).
costs must be accorded for less weight
in determining the "lowest achievable
emission rate for the new or modified
sources locating in areas violating sta-
tutorily-mandated health and welfare
standards. Although there may be
emission control technology available
that can reduce emissions below the
level required to comply with stan-
dards of performance, this technology-
might be selected as the basis of stan-
dards of performance due to costs as-
sociated with its use. This in no way
should preclude Its use in situations
where cost is a lesser consideration.
such as determination of the "lowest
achievable emission rate." Further-
more, since partial combustion sys-
tems and bottom blown BOPFs have
been shown to be inherently less pol-
luting, more stringent emission limits
may be placed on such sources for the
purposes of defining "best available
control technology" (under Prevention
of Significant Deterioration rerula-
tion) and "lowest achievable emission
rate" in non-attainment areas.
In addition, States are free under
section 116 of the Act to establish even
more stringent emission limits than
those established under section 111 or
those necessary to attain or maintain
the NAAQS under secton 110. Thus,
new sources may in some cases be sub-
ject to limitations more stringent than
standards of performance under sec-
tion 111, and prospective owners and
operators of new sources should be
aware of this possibility in planning
for such facilities.
The effective date of this regulation
is (date of publication), because sec-
tion llHbXlXB) of the Clean Air Act
provides that standards of perfor-
mance or revisions thereof become ef-
fective upon promulgation.
The opacity standard, like the con-
centration standard, applies to BOPFs
which commenced construction or
modification after June 11, 1973. That
is the date on which both standards
were originally proposed. The opacity
standard wiU add no new control
burden to the sources affected, but
will provide an effective means of
monitoring the compliance of these fa-
cilities. The relief provided under
§60.11(e) insures that the opacity
standard requires no greater reduction
in emissions than the concentration
standard.
NOTE.The Environmental Protection
Agency has determined that this document
does not contain a major proposal requiring
preparation of an Economic Impact Anal>-
sis under Executive Orders 11821 and 11949
and OMB Circular A-107.
Dated: April 4, 1978.
DODGLAS M. COSTLE,
Administrator.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amend-
ed as follows:
Subporl NStandards of Perfor-
mance for Iron and Steel Plants
1. Section 60.141 is amended by
adding paragraph (c) as follows:
§ 60.141 Definitions.
(c) "Startup means the setting into
operation for the first steel production
cycle of a relined BOPF or a BOPF
which has been out of production for a
minimum continuous time period of
eight hours.
2. Section 60.142 is amended by
adding paragraph (a)(2) as follows:
§ 60.142 Standard for paniculate matter.
(a)*
(2) Exit from a control device and
exhibit 10 percent opacity or greater,
except that an opacity of greater than
10 percent but less than 20 percent
jnay occur once per steel production
cycle.
(Sees ill. 301(a). Clean Air Act as amended
(42 U.S.C. 7411, 7601).}
3. A new § 6
-------
89
Title 40Protection of Environment
[PRL 882-«]
CHAPTER IENVIRONMENTAL
PROTECTION AGENCY
Svbchoptor CAir Program*
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY
SOURCES
Delegation of Authority to State/
Local Air Pollution Control Agen-
cies in Arizona, California, and
Nevada
AGENCY: Environmental Protection
Agency.
ACTION: Final Rulemaking.
SUMMARY: The Environmental Pro-
tection Agency (EPA) is amending 40
CFR 60.4 Address by adding addresses
of agencies to reflect new delegations
of authority from EPA to certain
state/local air pollution control agen-
cies in Arizona, California, and
Nevada. EPA has delegated authority
to these agencies, as described in a
notice appearing elsewhere in today's
FEDERAL REGISTER, in order to imple-
ment and enforce the standards of
performance for new stationary
sources.
EFFECTIVE DATE: May 16, 1978.
FOR FURTHER INFORMATION
CONTACT:
Gerald Katz (E-4-3), Environmental
Protection Agency, 215 Fremont
Street, San Francisco, Calif. 94105,
415-556-8005.
SUPPLEMENTARY INFORMATION:
Pursuant to delegation of authority
for the standards of performance for
new stationary sources (NSPS) to
State/Local air pollution control agen-
cies in Arizona, California, and Nevada
from March 30, 1977 to January 30,
1978, EPA is today amending 40 CFR
60.4 Address, to reflect these actions. A
Notice announcing this delegation is
published elsewhere in today's FEDER-
AL REGISTER. The amended § 60.4 is set
forth below. It adds the address of the
air pollution control agencies, to
which must be addressed all reports,
requests, applications, submittals, and
communications pursuant to this part
by sources subject to the NSPS locat-
ed within these agencies' Jurisdictions.
The Administrator finds good cause
for foregoing prior public notice and
for making this rulemaking effective
immediately in that it is an adminis-
trative change and not one of substan-
tive content. No additional substantive
burdens are imposed on the parties af-
fected. The delegation actions which
are reflected in this administrative
amendment were effective on the
RULES AND REGULATIONS
dates of delegation and it serves no
purpose to delay the technical change
on these additions of the air pollution
control agencies' addresses to the
Code of Federal Regulations.
(Sec. Ill, Clean Air Act, as amended (42
U.S.C. 74U).)
Dated: April 5, 1978.
SHEILA M. PRINDIVILLE,
Acting Regional Administrator,
Environmental Protection
Agency, Region IX.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amend-
ed as follows:
1. In § 60.4 paragraph (b) is amended
by revising subparagraphs D, F, and
DD to read as follows:
§ 60.4 Address.
*****
(b) *
(D) Arizona:
Maricopa County Department of Health
Services, Bureau of Air Pollution Control,
1825 East Roosevelt Street, Phoenix, AZ
85006.
Pima County Health Department, Air
Quality Control District, 151 West Congress,
Tucson, AZ 85701.
*****
(P) California:
Bay Area Air Pollution Control District,
939 Ellis Street, San Francisco, CA 94109.
Del Norte County Air Pollution Control
District, Courthouse, Crescent City, CA
95531.
Fresno County Air Pollution Control Dis-
trict, 515 S. Cedar Avenue, Fresno, CA
93702.
Humboldt County Air Pollution Control
District, 5600 S. Broadway, Eureka, CA
95501.
Kern County Air Pollution Control Dis-
trict, 1700 Flower Street (P.O. Box 997), Ba-
kersfield, CA 93302.
Madera County Air Pollution Control Dis-
trict, 135 W. Yosemite Avenue, Madera, CA
93637.
Mendocino County Air Pollution Control
District, County Courthouse, Ukiah, CA
94582.
Monterey Bay Unified Air Pollution Con-
trol District. 420 Church Street (P.O. Box
487), Salinas, CA 93901.
Northern Sonoma County Air Pollution
Control District, 3313 Chanate Road, Santa
Rosa, CA 95404.
Sacramento County Air Pollution Control
District, 3701 Branch Center Road, Sacra-
mento, CA 95827.
San Diego County Air Pollution Control
District, 9150 Chesapeake Drive, San Diego,
CA 92123.
San Joaquin County Air Pollution Control
District, 1601 E. Hazelton Street (P.O. Box
2009), Stockton. CA 95201.
Santa Barbara County Air Pollution Con-
trol District, 4440 Calle Real, Santa Bar-
bara, CA 93110.
Shasta County Air Pollution Control Dis-
trict, 1855 Placer Street, Redding, CA 96001.
South Coast Air Quality Management Dis-
trict, 9420 Telstar Avenue, El Monte, CA
91731.
Stanislaus County Air Pollution Control
District, 820 Scenic Drive, Modesto, CA
95350.
Trinity County Air Pollution Control Dis-
trict, Box AJ, Weaverville, CA 96093.
Ventura County Air Pollution Control
District, 625 E. Santa Clara Street, Ventura,
CA 93001.
* * * * *
(DD) Nevada:
Nevada Department of Conservation and
Natural Resources, Division of Environmen-
tal Protection, 201 South Fall Street,
Carson City, NV 89710.
Clark County County District Health De-
partment, Air Pollution Control Division,
625 Shadow Lane, Las Vegas, NV 89106.
Washoe County District Health Depart-
ment, Division of Environmental Protection,
10 Kirman Avenue, Reno, NV 89502.
*****
[PR Doc. 78-13011 Filed 5-15-78; 8:45 am]
FEDERAL REGISTER, VOL. 43, NO. 95
TUESDAY, MAY 16, 1978
IV-268
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RULES AND REGULATIONS
90
Title 40Protection of the
Environment
CHAPTER IENVIRONMENTAL
PROTECTION AGENCY
SUBCHAPTER CAIR PROGRAMS
tFRL 907-2]
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY
SOURCES
Groin Elevators
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Final rule.
SUMMARY: The standards limit emis-
sions of particulate matter from new,
modified, and reconstructed grain ele-
vators. The standards implement the
Clean Air Act and are based on the
Administrator's determination that
emissions from grain elevators contrib-
ute significantly to air pollution. The
intended effect of these standards is to
require new, modified, and recon-
structed grain elevators to use the best
demonstrated system of continuous
emission reduction, considering costs,
nonair quality health, environmental
and energy impacts.
EFFECTIVE DATE: August 3, 1978.
ADDRESSES: Copies of the standards
support documents are available on re-
quest from the U.S. EPA Library
(MD-35), Research Triangle Park,
N.C. 27711, telephone 919-541-2777 or
(FTS) 629-2777. The requester should
specify "Standards Support and Envi-
ronmental Impact Statement, Volume
1: Proposed Standards of Performance
for Grain Elevator Industry," (EPA-
450-77-OOla) and/or "Standards Sup-
port and Environmental Impact State-
ment, Volume 2: Promulgated Stand-
ards of Performance for Grain Eleva-
tor Industry."
-------
RULES AND REGULATIONS
system of continuous emission reduc-
tion. An equipment standard, there-
fore, rather than an emission standard
is being promulgated for barge and
ship unloading stations.
Another change from the proposed
standards is that section 60.14 (modifi-
cation) of the general provisions has
been clarified to ensure that only capi-
tal expenditures which are spent di-
rectly on an affected facility are used
to determine whether the annual asset
guideline repair allowance percentage
is exceeded. The annual asset guide-
line repair allowance percentage has
been defined to be 6.5 percent.
The remaining change from the pro-
posed standards is that four types of
alterations at grain elevators have
been exempted from consideration as
modifications. The exempted alter-
ations are:
(1) The addition of gravity load-out
spouts to existing grain storage or
grain transfer bins.
(2) The installation of automatic
grain weighing scales.
(3) Replacement of motor and drive
units driving existing grain handling
equipment.
(4) The installation of permanent
storage capacity with no increase in
hourly grain handling capacity.
ENVIRONMENTAL AND ECONOMIC IMPACTS
The promulgated standards will
reduce uncontrolled particulate
matter emission from new grain eleva-
tors by more than 99 percent and will
reduce particulate matter emissions by
70 to 90 percent compared to emission
limits contained in State or local air
pollution regulations. This reduction
in emissions will result in a significant
reduction of ambient air concentration
levels of particulate matter in the vi-
cinity of grain elevators. The maxi-
mum 24-hour average ambient air par-
ticulate matter concentration at a dis-
tance of 0.3 kilometer (km) from a
typical grain elevator, for example,
will be reduced by 50 to 80 percent
below the ambient air concentration
that would result from control of
emissions to the level of the typical
State or local air pollution regulations.
Several of the changes to the pro-
posed standards reduce the estimated
primary impact of the proposed stand-
ards in terms of reducing emissions of
particulate matter from grain eleva-
tors. The promulgated standards, for
example, apply only to large grain ele-
vators. These changes will permit
more emissions of particulate matter
to the atmosphere. It was estimated
that the proposed standards would
have reduced national particulate
matter emissions by approximately
21,000 metric tons over the next 5
years; it is now estimated that the pro-
mulgated standards will reduce partic-
ulate matter emissions by 11,000
metric tons over the next 5 years.
The secondary environmental im-
pacts associated with the promulgated
standards will be a small increase in
solid waste handling and disposal and
a small increase in noise pollution. A
relatively minor amount of particulate
matter, sulfur dioxide and nitrogen
oxide emissions will be discharged into
the atmosphere from steam/electric
power plants supplying the additional
electrical energy required to operate
the emission control devices needed to
comply with the promulgated stand-
ards. The energy impact associated
with the promulgated standards will
be small and will lead to an increase in
national energy consumption in 1981
by the equivalent of only 1,600 m*
-------
RULES AND REGULATIONS
egories of sources, which were evaluat-
ed to develop a long-range plan for set-
ting standards of performance for par-
ticulate matter, ranked grain elevators
relatively high. The categories were
ranked in order of priority based on
potential decrease In emissions. Var-
ious grain handling operations ranked
as follows: Grain processing4; grain
transfer6; grain cleaning and screen-
ing8; and grain drying33. There-
fore, grain elevators are a significant
source of particulate matter emissions
and standards of performance have
been developed for this source catego-
ry.
Many commenters felt, however,
that it was unreasonable to require
small country elevators to comply with
the proposed standards because of
their remote location and small
amount of emissions. This sentiment
was reflected in the 1977 amendments
to the Clean Air Act which exempted
country elevators with a grain storage
capacity of less than 88,100 m ' (ca. 2.5
million U.S. bushels) from standards
of performance. Consequently, the
scope of the proposed standards has
been narrowed and the promulgated
standards apply only to new, modified,
or reconstructed facilities within grain
elevators with a permanent storage ca-
pacity in excess of 88,100 m '.
A number of commenters also felt
small flour mills should not be covered
by standards of performance because
they are also small sources of particu-
late matter emissions and handle less
grain than some country elevators
which were exempted from standards
of performance by the 1977 amend-
ments to the Clean Air Act. These pro-
cessors are considered to be relatively
small sources of particulate matter
emissions that are best regulated by
State and local regulations. Conse-
quently, grain storage elevators at
wheat flour mills, wet corn mills, dry
corn mills (human consumption), rice
mills, and soybean oil extraction
plants with a storage capacity of less
than 35,200 ms (ca. 1 million U.S.
bushels) of grain are exempt from the
promulgated standards.
With regard to the hazardous nature
or toxicity of grain dust, the promul-
gated standards should not be Inter-
preted to imply that grain dust is con-
sidered hazardous or toxic, but merely
that the grain elevator industry is con-
sidered a significant source of particu-
late matter emissions. Studies indicate
that, as a general class, particulate
matter causes adverse health and wel-
fare effects. In addition, some studies
indicate that dust from grain elevators
causes adverse health effects to eleva-
tor workers and that grain dust emis-
sions are a factor contributing to an
increased incidence of asthma attacks
in the general population living in the
vicinity of grain elevators.
EMISSION CONTROL TECHNOLOGY
A number of commenters were con-
cerned with the reasonableness of the
emission control technology which was
used as the basis for the proposed
standards limiting emissions from rail-
car unloading stations and grain
dryers.
A number of commenters believed it
was unreasonable to base the stand-
ards on a four-sided shed to capture
emissions from railcar unloading sta-
tions at grain elevators which use unit
trains. The data supporting the pro-
posed standards were based on obser-
vations of visible emissions at a grain
elevator which used this type of shed
to control emissions from the unload-
ing of railcars. This grain elevator,
however, did not use unit trains. Based
on information included in a number
of comments, the lower rail rate for
grain shipped by unit trains places a
limit on the amount of time a grain
elevator can hold the unit train. The
additional time required to uncouple
and recouple each car individually
could cause a grain elevator subject to
the proposed standards to exceed this
time limit and thus lose the cost bene-
fit gained by the use of unit trains. In
light of this fact, the proposed visible
emission limit for railcar unloading is
considered unreasonable. The promul-
gated standards, therefore, are based
upon the use of a two-sided shed for
railcar unloading stations. This
change in the control technology re-
sulted in a change to the visible emis-
sion limit for railcar unloading sta-
tions and is discussed later.
A number of comments were re-
ceived concerning the proposed stand-
ard for column dryers. The proposed
standards would have permitted the
maximum hole size in the perforated
plates used in column dryers to be no
larger than 2.1 mm (0.084 inch) in di-
ameter for the dryer to automatically
be in compliance with the standard. A
few comments contained visible emis-
sion data taken by certified opacity ob-
servers which indicated that column
dryers with perforated plates contain-
ing holes of 2.4 mm (0.094 inch) diame-
ter could meet a 0-percent opacity
emission limit. Other comments indi-
cated that sorghum cannot be dried in
column dryers with a hole size smaller
than 2.4 mm (0.094 inch) diameter
without plugging problems. In light of
these data and information, the speci-
fication of 2.1 mm diameter holes is
considered unreasonable and the pro-
mulgated standards apply only to
column dryers containing perforated
plates with hole sizes greater than 2.4
mm in diameter.
STRINGENCY OF THX STANDARDS
Many commenters questioned
whether the standards for various af-
fected facilities could be achieved even
if the best system of emission reduc-
tion were installed, maintained, and
properly operated. These commenters
pointed out that a number of variables
can affect the opacity of visible emis-
sions during unloading, handling, and
loading of grain and they questioned
whether enough opacity observation
bad been taken to assure that the
standards could be attained under all
operating conditions. The variables
mentioned most frequently were wind
speed and type, dustiness, and mois-
ture content of grain.
It is true that wind speed could have
some effect on the opacity of visible
emissions. A well-designed capture
system should be able to compensate
for this effect to a certain extent, al-
though some dust may escape if wind
speed is too high. Compliance with
standards of performance, however, is
determined only under conditions rep-
resentative of normal operation, and
judgment by State and Federal en-
forcement personnel will take wind
conditions into account in enforcing
the standards.
It is also true that the type, dusti-
ness, and moisture content of grain
affect the amount of particulate
matter emissions generated during un-
loading, handling, and loading of
grain. A well-designed capture system,
however, should be designed to cap-
ture dust under adverse conditions and
should, therefore, be able to compen-
sate for these variables.
In developing the data base for the
proposed standards, over 60 plant
visits were made to grain terminal and
storage elevators. Various grain un-
loading, handling, and loading oper-
ations were inspected under a wide va-
riety of conditions. Consequently, the
standards were not based on conjec-
ture or surmise, but on observations of
visible emissions by certified opacity
observers at well-controlled existing
grain elevators operating under rou-
tine conditions. Not all grain elevators
were visited, however, and not all op-
erations within grain elevators were
inspected under all conditions. Thus,
while the proposed standards were
based upon a sufficiently broad data
base to allow extrapolation of the
data, particular attention was paid to
those comments submitted during the
public comment period which included
visible emission data taken by certified
observers from operations at grain ele-
vators which were using the same
emission control systems the proposed
standards were based upon. Evaluation
of these data indicates that the visible
emission limit for truck unloading sta-
tions and railcar loading stations
should be 5 percent opacity instead of
0 percent opacity which was proposed.
The promulgated standards, therefore,
limit visible emissions from these fa-
cilities to 5 percent opacity.
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RULES AND REGULATIONS
As discussed earlier, the emission
control technology selected as the
basis for the visible emissions standard
for rail car unloading has been
changed from a four-sided shed to a
two-sided shed. Visible emission data
included with the public comments in-
dicate that emissions from a two-sided
shed will not exceed 5 percent opacity.
Consequently, the promulgated stand-
ards limit visible emissions from rail-
car unloading stations to 5 percent
opacity.
A number of commenters also indi-
cated that the opacity limit included
in the proposed standards for barge
loading was too stringent. One com-
menter indicated that the elevator op-
erator had no control over when the
"topping off" operation commenced
because the ship captain and the ste-
vedores decide when to start "topping
off." Several State agencies comment-
ed that the standards should be at
least 20 percent opacity. Based on
these comments, the standards for
barge and ship loading operations
have been increased to 20 percent
opacity during all loading operations.
The comments indicate that this
standard will still require use of the
emission control technology upon
which the proposed standards were
based.
Data included with the public com-
ments confirm that a visible emission
limit of 0 percent opacity is appropri-
ate for grain -handling equipment,
grain dryers, and emission control
equipment. Consequently, the visible
emission limits for these facilities have
not been changed.
OPACITY
Many commenters misunderstood
the concept of opacity and how it is
used to measure visible emissions.
Other commenters stated that opacity
measurements were not accurate
below 10 to 15 percent opacity and a
standard below these levels was unen-
forceable.
Opacity is a measure of the degree
to which particulate matter or other
visible emissions reduce the transmis-
sion of light and obscure the view of
an object in the background. Opacity
is expressed on a scale of 0 to 100 per-
cent with a totally opaque plume as-
signed a value of 100 percent opacity.
The concept of opacity has been used
in the field of air pollution control
since the turn of the century. The con-
cept has been upheld in courts
throughout the country as a reason-
able and effective means of measuring
visible emissions.
Opacity for purposes of determining
compliance with the standard is not
determined with instruments but is de-
termined by a qualified observer fol-
lowing a specific procedure. Studies
have demonstrated that certified ob-
ervers can accurately determine the
opacity of visible emissions. To become
certified, an Individual must be trained
and must pass an examination demon-
strating his ability to accurately assign
opacity levels to visible emissions. To
remain certified, this training must be
repeated every 6 months.
In accordance with method 9, the
procedure followed in making opacity
determinations requires that an ob-
server be located in a position where
he has a clear view of the emission
source with the sun at his back. In-
stantaneous opacity observations are
recorded every 15 seconds for 6 min-
utes (24 observations). These observa-
tions are recorded in 5 percent incre-
ments (i.e., 0, 5, 10, etc.). The arithme-
tic average of the 24 observations,
rounded off to the nearest whole
number (i.e., 0.4 would be rounded off
to 0), is the value of the opacity used
for determining compliance with visi-
ble emission standards. Consequently,
a 0 percent opacity standard does not
necessarily mean there are no visible
emissions. It means either that visible
emissions during a 6-minute period are
not sufficient to cause a certified ob-
server to record them as 5 percent
opacity, or that the average of the
twenty-four 15-second observations is
calculated to be less than 0.5 percent.
Consequently, although emissions re-
leased into the atmosphere from an
emission source may be visible to a
certified observer, the source may still
be found in compliance with a 0 per-
cent opacity standard.
Similarly, a 5-percent opacity stand-
ard permits visible emissions to exceed
5 percent opacity occasionally. If, for
example, a certified observer recorded
the following twenty-four 15-second
observations over a 6-minute period: 7
observations at 0 percent opacity; 11
observations at 5 percent opacity; 3 ob-
servations at 10 percent opacity; and 3
observations at 15 percent opacity, the
average opacity would be calculated as
5.4 percent. This value would be
rounded off to 5 percent opacity and
the source would be in compliance
with a 5 percent opacity standard.
Some of the commenters felt the
proposed standards were based only on
one 6-minute reading of the opacity of
visible emissions at various grain ele-
vator facilities. None of the standards
were based on a single 6-minute read-
ing of opacity. Each of the standards
were based on the highest opacity
readings recorded over a period of
time, such as 2 or 4 hours, at a number
of grain elevators.
A number of commenters also felt
the visible emission standards were too
stringent in light of the maximum ab-
solute error of 7.5 percent opacity as-
sociated with a single opacity observa-
tion. The methodology used to develop
and enforce visible emission standards,
however, takes into account this ob-
server error. As discussed above, visi-
ble emission standards are based on
observations recorded by certified ob-
servers at well-controlled existing fa-
cilities operating under normal condi-
tions. When feasible, such observa-
tions are made under conditions which
yield the highest opacity readings
such as the use of a highly contrasting
background. These readings then
serve as the basis for establishing the
standards. By relying on the highest
observations, the standards inherently
reflect the highest positive error intro-
duced by the observers.
Observer error is also taken into ac-
count in enforcement of visible emis-
sion standards. A number of observa-
tions are normally made before an en-
forcement action is initiated. Statisti-
cally, as the number of observations
increases, the error associated with
these observations taken as a group
decreases. Thus, while the absolute
positive error associated with a single
opacity observation may be 7.5 per-
cent, the error associated with a
number of opacity observations, taken
to form the basis for an enforcement
action, may be considerably less than
7.5 percent.
ECONOMIC IMPACT
Several commenters felt the estimat-
ed economic impact of the proposed
standards was too low. Some com-
menters questioned the ventilation
flow rate volumes used in developing
these estimates. The air evacuation
flow rates and equipment costs used in
estimating the costs associated with
the standards, however, were based on
information obtained from grain ele-
vator operators during visits to facili-
ties which were being operated with
visible emissions meeting the proposed
standards. These air evacuation flow
rates and equipment costs were also
checked against equipment vendor es-
timates and found to be in reasonable
agreement. These ventilation flow
rates, therefore, are compatible with
the opacity standards. Thus, the unit
cost estimates developed for the pro-
posed standards are considered reason-
ably accurate.
Many commenters felt that the total
cost required to reduce emissions to
the levels necessary to comply with
the visible emission standards should
be assigned to the standards. The rele-
vant costs, however, are those incre-
mental costs required to comply with
these standards above the costs re-
quired to comply with existing State
or local air pollution regulations.
While it is true that some States have
no regulations, other States have regu-
lations as stringent as the promulgat-
ed standards. Consequently, an esti-
mate of the costs required to comply
with the typical or average State regu-
IV-272
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RULES AND REGULATIONS
lation, which lies between these ex-
tremes, is subtracted from the total
cost of complying with the standards
to identify the cost impact directly as-
sociated with these standards.
Most State and local regulations, for
example, require aspriation of truck
dump pit grates and installation of cy-
clones to remove particulate matter
from the aspirated air before release
to the atmosphere. The promulgated
standards would require the addition
of a bifold door and the use of a fabric
filter baghouse instead of a cyclone.
The cost associated with the promul-
gated standards, therefore, is only the
cost of the bifold doors and the differ-
ence in cost between a fabric filter
baghouse and a cyclone.
In conclusion, the unit cost esti-
mates developed for the proposed
standards are essentially correct and
generally reflect the costs associated
with the promulgated standards. As a
result, the economic impact of the pro-
mulgated standards on an individual
grain elevator is considered to be
about the same as that of the pro-
posed standards. The maximum addi-
tional cost that would be imposed on
most grain elevators subject to compli-
ance with the promulgated standards
will probably be less than a cent per
bushel. The impact of these additional
costs imposed on an individual grain
elevator will be small.
Based on information contained in
comments submitted by the National
Grain and Feed Association, approxi-
mately 200 grain terminal elevators
and grain storage elevators at grain
processing plants will be covered by
the standards over the next 5 years.
Consequently, over this 5-year period
the total incremental costs to control
emissions at these grain elevators to
comply with the promulgated stand-
ards, above the costs to control emis-
sions at these elevators to comply with
State or local air pollution control re-
quirements, is $15 million in capital
costs and $3 million in annualized
costs in the 5th year. Based on this es-
timate of the national economic
impact, the promulgated standards
will have no significant effect on the
supply and demand of grain or grain
products, or on the growth of the do-
mestic grain industry.
ENERGY IMPACT
A number of commenters believed
that the energy impact associated with
the proposed standards had been un-
derestimated and that the true impact
would be much greater. As pointed out
above, the major reason for this dis-
agreement is probably due to the fact
that these commenters assigned the
full impact of air pollution control to
the proposed standards, whereas the
impact associated with compliance
with existing State and local air pollu-
tion control requirements should be
subtracted. In the example discussed
above concerning costs, the additonal
energy requirements associated with
the promulgated standards is simply
the difference in energy required to
operate a fabric filter baghouse com-
pared to a cyclone.
For emission control equipment such
as cyclones and fabric filter bag
houses, energy consumption is directly
proportional to the pressure drop
across the equipment. It was assumed
that the pressure drop across a cy-
clone required to comply with existing
State and local requirements would be
about 80 percent of that across a
fabric filter baghouse required to
comply with tlje promulgated stand-
ards. This is equivalent to an increase
in energy consumption required to op-
erate air pollution control equipment
of about 25 percent. This represents
an increase of less than 5 percent in
the totl energy consumption of a grain
elevator.
Assuming 200 grain elevators
become subject to the promulgated
standards over the next 5 years, this
energy impact will increase national
energy consumption by less than 1,600
m' (ca. 10,000 U.S. barrels) per year in
1982. This amounts to less than 2 per-
cent of the capacity of a large marine
oil tanker and is an insignificant in-
crease in energy consumption.
MODIFICATION
Many commenters were under the
mistaken impression that all existing
grain elevators would have to comply
with the proposed standards and that
retrofit of air pollution control equip-
ment on existing facilities within grain
elevators would be required. This is
not the case. The proposed standards
would have applied only to new, modi-
fied, or reconstructed facilities within
grain elevators. Similarly, the promul-
gated standards apply only to new,
modified, or reconstructed facilities
and not existing facilities.
Modified facilities are only subject
to the standards if the modification
results in increased emissions to the
atmosphere from that facility. Fur-
thermore, any alteration which is con-
sidered routine maintenance or repair
is not considered a modification.
Where an alteration is considered a
modification, only those faculties
which are modified have to comply
with the standards, not the entire
grain elevator. Consequently, the
standards apply only to major alter-
ations of individual facilities at exist-
ing grain elevators which result in in-
creased emissions to the atmosphere,
not to alterations which are consid-
ered routine maintenance and repair.
Major alterations that do not result in
increased emissions, such as alter-
ations where existing air pollution
control equipment is upgraded to
maintain emissions at their previous
level, are not considered modifications.
The following examples illustrate
how the promulgated standards apply
to a grain elevator under various cir-
cumstances. The proposed standards
would have applied in the same way.
(1) If a completely new grain eleva-
tor were built, all affected facilities
would be subject to the standards.
(2) If a truck unloading station at an
existing grain elevator were modified
by making a capital expenditure to in-
crease unloading capacity and this re-
sulted in increased emissions to the at-
mosphere in terms of pounds per
hour, then only that affected facility
(i. e., the modified truck unloading sta-
tion) would be subject to the stand-
ards. The remaining facilities within
the grain elevator would not be sub-
ject to the standards.
(3) if a grain elevator contained
three grain dryers and one grain dryer
were replaced with a new grain dryer,
only the new grain dryer would be
subject to the standards.
The initial assessment of the poten-
tial for modification of existing facili-
ties concluded that few modifications
would occur. The few modifications
that were considered likely to take
place would involve primarily the up-
grading of existing country grain ele-
vators into high throughput grain ele-
vator terminals. A large number of
commenters, however, indicated that
they believed many modifications
would occur and that many existing
grain elevators would be required to
comply with the standards.
To resolve this confusion and clarify
the meaning of modification, a meet-
ing was held with representatives of
the grain elevator industry to identify
various alterations to existing facilities
that might be considered modifica-
tions. A list of alterations was devel-
oped which frequently occur within
grain elevators, primarily to reduce
labor costs or to increase grain han-
dling capacity, although not necessar-
ily annual grain throughput. The
impact of considering four of these al-
terations as modifications, subject to
compliance with the standards, was
viewed as unreasonable. Consequently,
they are exempted from consideration
as modifications in the promulgated
standards.
In particular, the four alterations
within grain elevators which are spe-
cifically exempt from the promulgated
standards are (1) The addition of grav-
ity load-out spouts to existing grain
storage or grain transfer bins; (2) the
addition of electronic automatic grain
weighing scales which increases
hourly grain handling capacity; (3) the
replacement of motors and drive trains
driving existing grain handling equip-
ment with larger motors and drive
IV-273
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RULES AND REGULATIONS
trains which increases hourly grain
handling capacity; and (4) the addition
of grain storage capacity with no in-
crease in hourly grain handling capac-
ity.
If the first alteration were consid-
ered a modification, this could require
installation of a load-out shed thereby
requiring substantial reinforcement of
the grain storage or grain transfer bin
to support the weight of emission con-
trol equipment. In light of the rela-
tively small expenditure usually re-
quired to install additional gravity
load-out spouts to existing grain stor-
age or transfer bins, and the relatively
large expenditure that would be re-
quired to install a load-out shed or to
reinforce the storage or transfer bin,
consideration of this sort of alteration
within an existing grain elevator as a
modification was viewed as unreason-
able.
Under the general modification reg-
ulation which applies to all standards
of performance, alteration two, the ad-
dition of electronic automatic grain
weighing scales, would be considered a
change in the method of operation of
the affected facility if it were to in-
crease the hourly grain throughput. If
this alteration were to increase emis-
sions to the atmosphere and require a
capital expenditure, the grain receiv-
ing or loading station whose method
of operation had changed (i.e., in-
creased grain throughput), would be
considered a modified facility subject
to the standards. Consideration of this
type of alteration, which would result
in only minor changes to a facility, is
viewed as unreasonable in light of the
relatively high expenditure this could
require for existing grain elevators to
comply with the standards.
Alterations three and four, replace-
ment of existing motors and drives
with larger motors and drives and ad-
dition of grain storage capacity with
no increase in the hourly grain han-
dling capacity, would probably not be
considered modifications under the
general modification regulation. Since
it is quite evident that there was con-
siderable confusion concerning modifi-
cations, however, alterations three and
four, along with alterations one and
two discussed above, are specifically
exempt from consideration as modifi-
cations in the promulgated standards.
The modification provisions in 40
CFR 60.14(e) exempt certain physical
or operational changes from being
considered as modifications, even
though an increase in emission rate
occurs. Under 40 CFR 60.14(e)(2), if an
increase in production rate of an exist-
ing facility can be accomplished with-
out a capital expenditure on the sta-
tionary source containing that facility,
the change is not considered a modifi-
cation.
A capital expenditure is defined as
any amount of money exceeding the
product of the Internal Revenue Serv-
ice (IRS) "annual asset guideline
repair allowance percentage" times
the basis of the facility, as defined by
section 1012 of the Internal Revenue
Code. In the case of grain elevators,
the IRS has not listed an annual asset
guideline repair allowance percentage.
Following discussions with the IRS,
the Department of Agriculture, and
the grain elevator industry, the
Agency determined that 6.5 percent is
the appropriate percentage for the
grain elevator industry. If the capital
expenditures required to increase the
production rate of an existing facility
do not exceed the amount calculated
under the IRS formula, the change in
the facility is not considered a modifi-
cation. If the expenditures exceed the
calculated amount, the change in op-
eration is considered a modification
and the facility must comply with
NSPS.
Often a physical or operational
change to an existing facility to in-
crease production rate will result in an
increase in the production rate of an-
other existing faculty, even though it
did not undergo a physical or oper-
ational change. For example, if new
electronic weighing scales were added
to a truck unloading station to in-
crease grain receipts, the production
rate and emission rate would increase
at the unloading station. This could
result in an increase in production rate
and emission rate at other existing fa-
cilities (e.g., grain handling oper-
ations) even though physical or oper-
ational changes did not occur. Under
the present wording of the regulation,
expenditures made throughout a grain
elevator to adjust for increased pro-
duction rate would have to be consid-
ered in determining if a capital ex-
penditure had been made on each fa-
cility whose operation is altered by the
production increase. If the capital ex-
penditure made on the truck unload-
ing station were considered to be made
on each existing facility which in-
creased its production rate, it is possi-
ble that the alterations on each such
facility would qualify as modifications.
Each facility would, therefore, have to
meet the applicable NSPS.
Such a result is inconsistent with
the intent of the regulation. The
Agency Intended that only capital ex-
penditures made for the changed fa-
cility are to be considered in determin-
ing if the change is a modification. Re-
lated expenditures on other existing
facilities -are not to be considered in
the calculation. To clarify the regula-
tion, the phrase "the stationary source
containing" is being deleted. Because
this is a clarification of intent and not
a change in policy, the amendment is
being promulgated as a final regula-
tion without prior proposal.
PERFORMANCE TEST
Several commenters were concerned
about the costs of conducting perform-
ance tests on fabric filter baghouses.
These commenters stated that the
costs involved might be a very substan-
tial portion of the costs of the fabric
filter baghouse itself, and several
baghouses may be installed at a mod-
erately sized grain elevator. The com-
menters suggested that a fabric filter
baghouse should be assumed to be in
compliance without a performance
test if it were properly sized. In addi-
tion, the opacity standards could be
used to demonstrate compliance.
It would not be wise to waive per-
formance tests in all cases. Section
60.8(b) already provides that a per-
formance test may be waived if "the
owner or operator of a source has
demonstrated by other means to the
Administrator's satisfaction that the
affected facility is in compliance with
the standard." Since performance
tests are heavily weighed in court pro-
ceedings, performance test require-
ments must be retained to insure ef-
fective enforcement.
SAFETY CONSIDERATIONS
In December 1977, and January
1978, several grain elevators exploded.
Allegations were made by various indi-
viduals within the grain elevator in-
dustry contending that Federal air
pollution control regulations were con-
tributing to an increase in the risk of
dust explosions at grain elevators by
requiring that building doors and win-
dows be closed and by concentrating
grain dust in emission control systems.
Investigation of these allegations indi
cates they are false.
There were no Federal regulations
specifically limiting dust emissions
from grain elevators which were in
effect at the time of these grain eleva-
tor explosions. A number of State and
local air pollution control agencies,
however, have adopted regulations
which limit particulate matter emis-
sions from grain elevators. Many oi
these regulations were developed by
States and included in their implemen-
tation plans for attaining and main-
taining the NAAQS for particulate
matter. Particulate matter, as a gener-
al class, can cause adverse health ef-
fects; and the NAAQS, which were
promulgated on April 30, 1971, were
established at levels necessary to pro-
tect the public health and welfare.
Although compliance with State or
local air pollution control regulations.
or the promulgated standards of per-
formance, can be achieved in some in-
stances by closing building doors and
windows, this is not the objective of
these regulations and is not an accept-
IV-274
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RULES AND REGULATIONS
able means of compliance. The objec-
tive of State and local regulations and
the promulgated standards of per-
formance is that dust be captured at
those points within grain elevators
where it is generated through the use
of effective hoods or enclosures with
air aspiration, and removed from the
grain elevator to an air pollution con-
trol device. This is the basis for the
promulgated ' standards of perform-
ance. Compliance with air pollution
control regulations and the promul-
gated standards of performance does
not require that windows and doors in
buildings be closed to prevent escape
of dust and this practice may in fact
be a major safety hazard.
Fabric filter baghouses have been
used for many years to collect combus-
tible dusts such as wheat flour. There
have been extremely few Incidences of
dust explosions or fires caused by such
emission control devices in the flour
industry. In the grain elevator indus-
try, no air pollution control device has
been identified as the cause of a grain
elevator explosion. Consequently,
fabric filter baghouses, or emission
control devices in general, which are
properly designed, operated, and main-
tained will not contribute to an in-
creased risk of dust explosions at grain
elevators.
These conclusions were supported at
a joint meeting between representa-
tives of EPA; the Federal Grain In-
spection Service (FGIS) of the Depart-
ment of Agriculture; the Occupational
Safety and Health Administration
(OSHA); the grain elevator industry;
and the fire insurance industry. Instal-
lation and use of properly designed,
operated, and maintained air pollution
control systems were found to be con-
sistent with State and local air pollu-
tion regulations, OSHA regulations,
and national fire codes. Chapter 6 of
the National Fire Code for Grain Ele-
vators and Bulk Grain Handling Fa-
cilities (NFPA No. 61-B), which was
prepared by the National Fire Protec-
tion Association, for example, recom-
mends that "dust shall be collected at
all dust producing points within the
processing facilities." The code then
goes on to specially recommend that
all elevator boots, automatic scales,
scale hoppers, belt loaders, belt dis-
charges, trippers, and discharge heads,
and all machinery such as cleaners,
scalpers, and similar devices be pro-
vided with enclosures or dust hoods
and air aspiration.
Consequently, compliance with ex-
isting State or local air pollution regu-
lations, or the promulgated standards
of performance, will not increase the
risk of dust explosions at grain eleva-
tors if the approach taken to meet
these regulations is capture and con-
trol of dust at those points within an
elevator where it is generated. If, how-
ever, the approach taken is merely to
close doors, windows, and other open-
ings to trap dust within the grain ele-
vator, or the air pollution control
equipment is allowed to deteriorate to
the point where it is no longer effec-
tive in capturing dust as it is generat-
ed, then ambient concentrations of
dust within the elevator will increase
and the risk of explosion will also in-
crease.
The House Subcommittee on Com-
pensation, Health, and Safety is cur-
rently conducting oversight hearings
to determine if something needs to be
done to prevent these disastrous grain
elevator explosions. The FGIS, EPA,
and OSHA testified at these oversight
hearings on January 24 and 25, 1978.
The testimony indicated that dust
should be captured and collected in
emission control devices in order to
reduce the incidence of dust explo-
sions at grain elevators, protect the
health of employees from such ail-
ments as "farmer's lung," and prevent
air pollution. Consequently, properly
operated and maintained air pollution
control equipment will not increase
the risk of grain elevator explosions.
MISCELLANEOUS
It should be noted that standards of
performance for new sources estab-
lished under section 111 of the Clean
Air Act reflect the degree of emission
limitation achievable through applica-
tion of the best adequately demon-
strated technological system of con-
tinuous emission reduction (taking
into consideration the cost of achiev-
ing such emission reduction, any
nonair quality health and environmen-
tal impact and energy requirements).
State implementation plans (SIP's) ap-
proved or promulgated under section
110 of the act, on the other hand,
must provide for the attainment and
maintenance of national ambient air
quality standards (NAAQS) designed
to protect public health and welfare.
For that purpose, SIP's must in some
cases require greater emission reduc-
tions than those required by standards
of performance for new sources. Sec-
tion 173 of the act requires, among
other things, that a new or modified
source constructed in an area in viola-
tion of the NAAQS must reduce emis-
sions to the level which reflects the
"lowest achievable emission rate" for
such category of source as defined in
section 171(3). In no event can the
emission rate exceed any applicable
standard of performance.
A similar situation may arise when a
major emitting facility is to be con-
structed in a geographic area which
falls under the prevention of signifi-
cant deterioration of air quality provi-
sions of the act (part C). These provi-
sions require, among other things.
that major emitting facilities to be
constructed in such areas are to be
subject to best available control tech-
nology for all pollutants regulated
under the act. The term "best availa-
ble control technology" (BACT), as de-
fined in section 169(3), means "an
emission limitation based oh the maxi-
mum degree of reduction of each pol-
lutant subject to regulation under this
act emitted from or which results
from any major emitting facility,
which the permitting authority, on a
case-by-case basis, taking into account
energy, environmental, and economic
impacts and other costs, determines is
achievable for such facility through
application of production processes
and available methods, systems, and
techniques, including fuel cleaning or
treatment or innovative fuel combus-
tion techniques for control of each
such pollutant. In no event shall appli-
cation of 'best available control tech-
nology' result in emissions of any pol-
lutants which will exceed the emis-
sions allowed by any applicable stand-
ard established pursuant to sections
111 or 112 of this Act."
Standards of performance should
not be viewed as the ultimate in
achievable emission control and
should not preclude the imposition of
a more stringent emission standard,
where appropriate. For example, while
cost of achievement may be an impor-
tant factor in determining standards
of performance applicable to all areas
of the country (clean as well as dirty),
statutorily, costs do not play such a
role in determining the "lowest achiev-
able emission rate" for new or modi-
fied sources locating in areas violating
statutorily mandated health and wel-
fare standards. Although there may be
emission control technology available
that can reduce emissions below those
levels required to comply with stand-
ards of performance, this technology
might not be selected as the basis of
standards of performance due to costs
associated with its use. This in no way
should preclude its use in situations
where cost is a lesser consideration,
such as determination of the "lowest
achievable emission rate."
In addition, States are free under
section 116 of the act to establish even
more stringent emission limits than
those established under section 111 or
those necessary to attain or maintain
the NAAQS under section 110. Thus.
new sources may in some cases be sub-
ject to limitations more stringent than
standards of performance under sec-
tion 111, and prospective owners and
operators of new sources should be
aware of this possibility in planning
for such facilities.
ECONOMIC IMPACT ASSESSMENT
An economic assessment has been
prepared as required under section 317
of the Act."
IV-275
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RULES AND REGULATIONS
Dated: July 26,1978.
DOUGLAS M. COSTLE,
Administrator.
REFERENCES
1. "Standards Support and Environmental
Impact StatementVolume I: Proposed
Standards of Performance for Grain Eleva-
tor Industry," U.S. Environmental Protec-
tion AgencyOAQPS, EPA-450/2-77-001a,
Research Triangle Park, N.C., January 1977.
2. "DraftFor Review Only: Evaluation of
Public Comments: Standards of Perform-
ance For Grain Elevators," U.S. Environ-
mental Protection AgencyOAQPS, Re-
search Triangle Park, N.C., August 1977.
3. "Standards Support and Environmental
Impact StatementVolume II: Promulgated
Standards of Performance for Grain Eleva-
tor Industry," U.S. Environmental Protec-
tion AgencyOAQPS, EPA-450/2-77-001b,
Research Triangle Park, N.C., April 1978.
Part 60 of chapter I, title 40 of the
Code of Federal Regulations is amend-
ed as follows:
Subpart AGeneral Provision*
1. Section 60.2 is amended by revis-
ing paragraph (v). The revised para-
garaph reads as follows:
§ 60.2 Definitions.
(v) "Particulate matter" means any
finely divided solid or liquid material,
other than uncombined water, as
measured by the reference methods
specified under each applicable sub-
part, or an equivalent or alternative
method.
§60.14 [Amended]
2. Section 60.14 is amended by delet-
ing the words "the stationary source
containing" from paragraph (e)(2).
3. Part 60 is amended by adding sub-
part DD as follows:
Subpart DDStandards of Performance for
Grain Elevator*
Sec.
60.300 Applicability and designation of af-
fected facility.
60.301 Definitions.
60.302 Standard for particulate matter.
60.303 Test methods and procedures.
60.304 Modification.
AUTHORITY: Sees. Ill and 301(a) of the
Clean Air Act, as amended (42 U.S.C. 7411,
7601(a)), and additional authority as noted
below.
Subpart DDStandards of
Performance for Grain Elevators
§60.300 Applicability and designation of
affected facility.
(a) The provisions of this subpart
apply to each affected facility at any
grain terminal elevator or any grain
storage elevator, except as provided
under §60.304(b). The affected facili-
ties are each truck unloading station,
truck loading station, barge and ship
unloading station, barge and ship load-
ing station, railcar loading station,
railcar unloading station, grain dryer,
and all grain handling operations.
(b) Any facility under paragraph (a)
of this section which commences con-
struction, modification, or reconstruc-
tion after (date of reinstatement of
proposal) is subject to the require-
ments of this part.
§ 60.301 Definitions.
As used in this subpart, all terms not
defined herein shall have the meaning
given them in the act and in subpart A
of this part.
(a) "Grain" means corn, wheat, sor-
ghum, rice, rye, oats, barley, and soy-
beans.
(b) "Grain elevator" means any
plant or installation at which grain is
unloaded, handled, cleaned, dried,
stored, or loaded.
(c) "Grain terminal elevator" means
any grain elevator which has a perma-
nent storage capacity of more than
88,100 m3 (ca. 2.5 million U.S. bushels),
except those located at animal food
manufacturers, pet food manufactur-
ers, cereal manufacturers, breweries,
and livestock feedlots.
(d) "Permanent storage capacity"
means grain storage capacity which is
inside a building, bin, or silo.
(e) "Railcar" means railroad hopper
car or boxcar.
(f) "Grain storage elevator" means
any grain elevator located at any
wheat flour mill, wet corn mill, dry
corn mill (human consumption), rice
mill, or soybean oil extraction plant
which has a permanent grain storage
capacity of 35,200 m3 (ca. 1 million
bushels).
(g) "Process emission" means the
particulate matter which is collected
by a capture system.
(h) "Fugitive emission" means the
particulate matter which is not collect-
ed by a capture system and is released
directly into the atmosphere from an
affected facility at a grain elevator.
(i) "Capture system" means the
equipment such as sheds, hoods, ducts,
fans, dampers, etc. used to collect par-
ticulate matter generated by an affect-
ed facility at a grain elevator.
(j) "Grain unloading station" means
that portion of a grain elevator where
the grain is transferred from a truck,
railcar, barge, or ship to a receiving
hopper.
(k) "Grain loading station" means
that portion of a grain elevator where
the grain is transferred from the ele-
vator to a truck, railcar, barge, or ship.
(1) "Grain handling operations" in-
clude bucket elevators or legs (exclud-
ing legs used to unload barges or
ships), scale hoppers and surge bins
(garners), turn heads, scalpers, clean-
ers, trippers, and the headhouse and
other such structures.
(m) "Column dryer" means any
equipment used to reduce the mois-
ture content of grain in which the
grain flows from the top to the bottom
in one or more continuous packed col-
umns between two perforated metal
sheets.
(n) "Rack dryer" means any equip-
ment used to reduce the moisture con-
tent of grain in which the grain flows
from the top to the bottom in a cas-
cading flow around rows of baffles
(racks).
(o) "Unloading leg" means a device
which includes a bucket-type elevator
which is used to remove grain from a
barge or ship.
§ 60.302 Standard for particulate matter.
(a) On and after the 60th day of
achieving the maximum production
rate at which the affected facility will
be operated, but no later than 180
days after initial startup, no owner or
operator subject to the provisions of
this subpart shall cause to be dis-
charged into, the atmosphere any
gases which exhibit greater than 0
percent opacity from any:
(1) Column dryer with column plate
perforation exceeding 2.4 mm diame-
ter (ca. 0.094 inch).
(2) Rack dryer in which exhaust
gases pass through a screen filter
coarser than 50 mesh.
(b) On and after the date on which
the performance test required to be
conducted by § 60.8 is completed, no
owner or operator subject to the provi-
sions of this subpart shall cause to be
discharged into the atmosphere from
any affected facility except a grain
dryer any process emission which:
(1) Contains particulate matter in
excess of 0.023 g/dscm (ca. 0.01 gr/
dscf).
(2) Exhibits greater than 0 percent
opacity.
(c) On and after the 60th day of
achieving the maximum production
rate at which the affected facility will
be operated, but no later than 180
days after initial startup, no owner or
operator subject to the provisions of
this subpart shall cause to be dis-
charged into the atmosphere any fugi-
tive emission from:
(1) Any individual truck unloading
station, railcar unloading station, or
railcar loading station, which exhibits
greater than 5 percent opacity.
(2) Any grain handling operation
which exhibits greater than 0 percent
opacity.
(3) Any truck loading station which
exhibits greater than 10 percent opac-
ity.
(4) Any barge or ship loading station
which exhibits greater than 20 percent
opacity.
IV-276
-------
RULES AND REGULATIONS
(d) The owner or operator of any
barge or ship unloading station shall
operate as follows:
(1) The unloading leg shall be en-
closed from the top (including the re-
ceiving hopper) to the center line of
the bottom pulley and ventilation to a
control device shall be maintained on
both sides of the leg and the grain re-
ceiving hopper.
(2) The total rate of air ventilated
shall be at least 32.1 actual cubic
meters per cubic meter of grain han-
dling capacity (ca. 40 ftVbu).
(3) Rather than meet the require-
ments of subparagraphs (1) and (2), of
this paragraph the owner or operator
may use other methods of emission
control if it is demonstrated to the Ad-
ministrator's satisfaction that they
would reduce emissions of particulate
matter to the same level or less.
§ 60.303 Test methods and procedures.
(a) Reference methods in appendix
A of this part, except as provided
under § 60.8(b). shall be used to deter-
mine compliance with the standards
prescribed under § 60.302 as follows:
(1) Method 5 or method 17 for con-
centration of particulate matter and
associated moisture content;
(2) Method 1 for sample and velocity
traverses;
(3) Method 2 for velocity and volu-
metric flow rate;
(4) Method 3 for gas analysis; and
(5) Method 9 for visible emissions.
(b) For method 5, the sampling
probe and filter holder shall be operat-
ed without heaters. The sampling time
for each run, using method 5 or
method 17, shall be at least 60 min-
utes. The minimum sample volume
shall be 1.7 dscm (ca. 60 dscf).
(Sec. 114, Clean Air Act, as amended (42
U.S.C. 7414).)
§ 60.304 Modifications.
(a) The factor 6.5 shall be used in
place of "annual asset guidelines
repair allowance percentage," to deter-
mine whether a capital expenditure as
defined by § 60.2(bb) has been made to
an existing facility.
(b) The following physical changes
or changes in the method of operation
shall not by themselves be considered
a modification of any existing facility:
(1) The addition of gravity loadout
spouts to existing grain storage or
grain transfer bins.
(2) The installation of automatic
grain weighing scales.
(3) Replacement of motor and drive
units driving existing grain handling
equipment.
(4) The installation of permanent
storage capacity with no increase in
hourly grain handling capacity.
[FR Doc. 78-21444 Piled 8-2-78; 8:45 am]
FEDERAL REGISTER, VOL. 43, NO. 150
THURSDAY, AUGUST 3, 1978
91
Title 40Protection of Environment
CHAPTER IENVIRONMENTAL
PROTECTION AGENCY
SUBCHAPTER CAW PROGRAMS
[FRL 921-7]
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY
SOURCES
Amendments to Kraft Pulp Mills
Standard and Reference Method 16
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Final rule.
SUMMARY: This action amends the
standards of performance for Kraft
pulp mills by adding a provision for
determining compliance of affected fa-
cilities which use a control system in-
corporating a process other than com-
bustion. This amendment is necessary
because the standards would place
cor.trol systems other than combus-
tion at a disadvantage. The intent of
this amendment is to remove any pre-
clusion of new and improved control
systems. This action also amends Ref-
erence Method 16 to insure that the
testing procedure is consistent with
the promulgated standards.
EFFECTIVE DATE: August 7. 1978.
FOR FURTHER INFORMATION
CONTACT:
Don R. Goodwin, Emission Stand-
ards and Engineering Division, Envi-
ronmental Protection Agency, Re-
search Triangle Park, N.C. 27711.
telephone 919-541-5271.
SUPPLEMENTARY INFORMATION:
Standards of performance for Kraft
pulp mills were promulgated on Febru-
ary 23. 1978. On March 31, 1978, the
National Council for Air and Stream
Improvement (NCASI) requested two
changes to these standards to prevent
their interpretation in a manner
which was inconsistent with their
intent. The purpose of these amend-
ments, therefore, is to clarify the
intent of the standards.
OXYGEN CORRECTION FACTORS
In §60.283(a)(l), the percent oxygen
to which TRS emissions must be cor-
rected was specified. The purpose of
this specification was to provide a con-
sistent basis for the determination of
TRS emissions. Ten percent was se-
lected because it reflected the ob-
served oxygen concentrations on facili-
ties controlled by the best system of
emission reduction which was inciner-
ation. The NCASI pointed out, howev-
er, that the specification oi a 10-per-
cent oxygen level on sources which
characteristically contain higher levels
would effectively discourage the devel-
opment of control technologies other
than incineration.
The purpose of an emission standard
is to reduce total emissions co the at-
mosphere. If an emission control tech-
nique should evolve which i;-, capable
of achieving the same mass rate of
emissions from a given facility, use of
that technique should be permitted
The standard, as written, could have
inhibited the development of new
technologies, if misinterpreted. There-
fore, to remove this potential source of
misinterpretation, §60.283(aXl)(v) has
been added to the standard to provide
for correction to untreated oxygen
concentration In the case of brown
stock washers, black liquor oxidation
systems, or digester systems.
REFERENCE METHOIT 16
The second point of concern to the
NCASI was the correction factor to bt
applied for sampling systom l^secs
contained in the post-test procedures
(paragraph 10,1! of method 16. The
specific concern waa the specification
that a test gas be introduced ct the be-
ginning of the probe to determine
sample loss in the sampling train. The
data base for the promulgated stand-
ard considered only TRS losses in the
sampling train, not the probe or probe
filter. Consequently, the post-test pro-
cedures are amended to require the de-
termination of sampling train losses
by introducing the test gas after the
probe filter consistent with the data
base supporting the promulgated
standards.
MISCELLANEOUS
The Administrator finds that good
cause exists for omitting prior notue
and public comment on these amend-
ments and for making them immedi-
ately effective because they simply
clarify the existing regulations and
impose no additional substantive re-
quirements.
Section 317 of the Clean Air Act re-
quires the Administrator to prepare an
economic impact assessment for revi-
sions determined by the Administrator
to be substantial. Since the costs asso-
ciated with the proposed amendments
would have a negligible impact on con-
sumer costs, the Administrator has de-
termined that the proposed amend-
ments are not substantial and do not
require preparation of an economic
impact assessment.
Dated: August 1, 1978.
DOUGLAS M. COSTLE,
Administrator.
Part 60 of chapter I, title 40 of the
Code of Federal Regulations is amend-
ed to read as follows:
IV-277
-------
1. In §60.283. paragraph (a)(l) is
amended to read as follows:
§ 60.2S3 Standard for total reduced sulfur
(TRS).
H) * * *
(v) The gasrs from the digester
system, brown stock washer system,
condensate stripper .system, or black
liquor oxidation sj.~U>ni are controlled
by a means other than combustion. In
this case, these systems shall not dis-
charge any gases to the atmosphere
which contain TRS in excess of 5 ppm
by volume on a dry basis, corrected to
the actual oxygen content of the un-
treated gas stream.
» »
2. In appendix A, paragraph 10.1 of
method 16 is amended to read as fol-
lows:
* *
10 POST-TEST PROCEDURES
10.1 Sample line loss. A known concen-
tration of hydrogen sulfide at the level of
the applicable standard, ± 20 percent, must
be introduced into the sampling system in
sufficient quantities to insure that there is
an excess of sample which must be vented
to the atmosphere. The sample must be in-
troduced immediately after the probe and
filter and transported through the remain-
der of the sampling system to the measure-
ment system in the normal manner The re-
sulting measured concentration should be
compared to the known value to determine
the sampling system loss.
For sampling losses greater than 20 per-
cent in a sample run, the sample run is not
to be used when determining the arithmetic
mean of the performance test. For sampling
losses of 0-20 percent, the sample concen-
tration must be corrected by dividing the
sample concentration by the fraction of re-
covery. The fraction of recovery is equal to
one minus the ratio of the measured con-
centration to the known concentration of
hydrogen sulfide in the sample line loss pro-
cedure. The known gas sample may be gen-
erated using permeation tubes. Alternative-
ly, cylinders of hydrogen sulfide mixed in
air may be used provided they are traceable
to permeation tubes. The optional pretest
procedures provide a good guideline for de-
termining if there are leaks in the sampling
sys'.em.
(Sec. Ill, 30Ka)), Clean Air Act as amended
(42 U.S.C. 7411, 7601(a)).)
CFR Doc. 78-21801 Filed 8 4 78. 8 45 am]
FEDERAL REGISTER, VOL. 43, NO. 152
MONDAY, AUGUST 7, 1978
RULES AND REGULATIONS
92
Title 40Protection of Environment
CHAPTER IENVIRONMENTAL
PROTECTION AGENCY.
SUBCHAPTER CAIR PROGRAMS
[FRL 987-8]
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY
SOURCES
Delegation of Authority for State of
Rhode Island
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Amendment.
SUMMARY: The delegation of au-
thority to the State of Rhode Island
for the standards of performance for
new stationary sources (NSPS) was
made on March 31, 1978. This amend-
ment which adds the address of the
Rhode Island Department of Environ-
menal Managment, reflects this dele-
gation. A notice announcing this dele-
gation is published today in the FEDER-
AL REGISTER.
EFFECTIVE DATE: October 16, 1978.
FOR FURTHER INFORMATION
CONTACT:
John Courcier, Air Branch, EPA
Region I, Room 2113, JFK Federal
Building, Boston, Mass. 02203, 617-
223-4448.
SUPPLEMENTARY INFORMATION:
Under the delegation of authority for
the standards of performance for new
stationary sources (NSPS) to the State
of Rhode Island on March 31, 1978,
EPA is today amending 40 CFR 60.4,
Address, to reflect this delegation. A
notice announcing this delegation is
published today elsewhere in this (43
part of the FEDERAL REGISTER. The
amended § 60.4, which adds the ad-
dress of the Rhode Island Department
of Environmental Management to
which all reports, requests, applica-
tions, submittals, and communications
to the Administrator pursuant to this
part must also be addressed, is set
forth below.
The Administrator finds good cause
for foregoing prior public notice and
for making this rulemaking effective
immediately in that it is an adminis-
trative change and not one of substan-
tive content. No additional burdens
are imposed on the parties affected.
The delegation which is reflected by
this administrative amendment was ef-
fective on March 31, 1978, and it
serves no purpose to delay the techni-
cal change of this addition of the
State address to the Code of Federal
Regulations.
This rulemaking is effective immedi-
ately, and is issued under the authori-
ty of section 111 of the Clean Air Act,
as amended, 42 U.S.C. 7412.
Dated: September 18, 1978.
WILLIAM R. ADAMS, Jr.,
Regional Administrator,
Region I.
Pan 60 of chapter I, title 40 of the
Code of Federal Regulations is amend-
ed as follows:
1. In § 60.4 paragraph (b) is amended
by adding subparagraph (OO) to read
as follows:
§60.4 Address
(b)** *
(OO) State of Rhode Island, Department
of Environmental Management, 83 Park
Street. Providence, R.I. 02908
tFR Doc. 78-29105 Filed 10-13-78: 9:49 an?]
FEDERAL REGISTER, VOL 43, NO. 200
MONDAY, OCTOBER 16, 1978
IV-278
-------
93
Title 40Protection of Environment
CHAPTER IENVIRONMENTAL
PROTECTION AGENCY
[FRL 1012-2]
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY
SOURCES
Appendix AReference Method 16
AGENCY: Environmental Protection
Agency.
ACTION: Amendment.
SUMMARY: This action amends Ref-
erence Method 16 for determining
total reduced sulfur emissions from
stationary sources. The amendment
corrects several typographical errors
and improves the reference method by
requiring the use of a scrubber to pre-
vent potential interference from high
SOi concentrations. These changes
assure more accurate measurement of
total reduced sulfur (TRS) emissions
but do not substantially change the
reference method.
SUPPLEMENTARY INFORMATION:
On Februrary 23, 1978 (43 PR 7575),
Appendix AReference Method 16 ap-
peared with several typographical
errors or omissions. Subsequent com-
ments noted these and also suggested
that the problem of high SO, concen-
trations could be corrected by using a
scrubber to remove these high concen-
trations. This amendment corrects the
errors of the original publication and
slightly modifies Reference Method 16
by requiring the use of a scrubber to
prevent potential interference from
high SO, concentrations.
Reference Method 16 is the refer-
ence method specified for use in deter-
mining compliance with the promul-
gated standards of performance for
kraft pulp mills. The data base used to
develop the standards for kraft pulp
mills has been examined and this addi-
tional requirement to use a scrubber
to prevent potential interference from
high SO, concentrations does not re-
quire any change to these standards of
performance. The data used to develop
these standards was not gathered from
kraft pulp mills with high SO, concen-
trations; thus, the problem of SO, in-
terference was not present in the data
base. The use of a scrubber to prevent
this potential interference in the
future, therefore, is completely con-
sistent with this data base and the
promulgated standards.
RULES AND .REGULATIONS
The increase in the cost of determin-
ing compliance with the standards of
performance for kraft pulp mills, as a
result of this additional requirement
to use a scrubber in Reference Method
16, is negligible. At most, this addition-
al requirement could increase the cost
of a performance test by about 50 dol-
lars.
Because these corrections and addi-
tions to Reference Method 16 are
minor in nature, impose no additional
substantive requirements, or do not re-
quire a change in the promulgated
standards of performance for kraft
pulp mills, these amendments are pro-
mulgated directly.
EFFECTIVE DATE: January 12, 1979.
FOR FURTHER INFORMATION
CONTACT:
Don R. Goodwin, Director, Emission
Standards and Engineering Division,
(MD-13) Environmental Protection
Agency, Research Triangle Park,
North Carolina 27711, telephone
number 919-541-5271.
Dated: January 2, 1979.
DOUGLAS M. COSTLE,
Administrator.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amend-
ed as follows:
APPENDIX AREFERENCE METHODS
In Method 16 of Appendix A, Sec-
tions 3.4, 4.1, 4.3, 5, 5.5.2, 6, 8.3, 9.2,
10.3, 11.3, 12.1. 12.1.1.3, 12.1.3.1,
12.1.3.1.2. 12.1.3.2, 12.1.3.2.3, and 12.2
are amended as follows:
1. In subsection 3.4, at the end of the
first paragraph, add: "In the example
system, SO2 is removed by a citrate
buffer solution prior to GC injection.
This scrubber will be used when SO*
levels are high enough to prevent
baseline separation from the reduced
sulfur compounds."
2. In subsection 4.1, change "± 3 per-
cent" to "± 5 percent."
3. In subsection 4.3, delete both sen-
tences and replace with the following:
"Losses through the sample transport
system must be measured and a cor-
rection factor developed to adjust the
calibration accuracy to 100 percent."
4. After Section 5 and before subsec-
tion 5.1.1 insert "5.1. Sampling."
5. In Section 5, add the following
subsection: "5.3 SO* Scrubber. The
Sd scrubber is a midget impinger
packed with glass wool to eliminate
entrained mist and charged with po-
tassium citrate-citric acid buffer."
Then increase all numbers from 5.3 up
to and including 5.5.4 by 0.1, e.g.,
chartge 5.3 to 5.4, etc.
6. In subsection 5.5.2, the word
"lowest" in the fourth sentence is re-
placed with "lower."
7. In Section 6, add the following
subsection: "6.6 Citrate Buffer. Dis-
solve 300 grams of potassium citrate
and 41 grams of anhydrous citric acid
In 1 liter of deionlzed water. 284 grams
of sodium citrate may be substituted
for the potassium citrate."
8. In subsection 8.3, in the second
sentence, after "Bypassing the dilu-
tion system," insert "but using the SO,
scrubber," before finishing the sen-
tence.
9. In subsection 9.2, replace sentence
with the following: "Aliquots ~of dilut-
ed sample pass through the SO, scrub-
ber, and then are injected into the
GC/FPD analyzer for analysis."
10. In subsection 10.3, "paragraph"
in the second sentence is corrected
with "subsection."
11. In subsection 11.3 under Bwo defi-
nition, insert "Reference" before
"Method 4."
12. In subsection 12.1.1.3 "(12.2.4
below)" is corrected to "(12.1.2.4
below)."
13. In subsection 12.1, add the fol-
lowing subsection: "12.1.3 SO, Scrub-
ber. Midget impinger with 15 ml of po-
tassium citrate buffer to absorb SO, in
the sample." Then renumber existing
section 12.1.3 and following subsec-
tions through and including 12.1.4.3 as
12.1.4 through 12.1.5.3.
14. The second subsection listed as
"12.1.3.1" (before corrected in above
amendment) should be "12.1.4.1.1."
15. In subsection 12.1.3.1 (amended
above to 12.1.4.1) correct "GC/FPD-1
to "GC/FPD-I."
16. In subsection 12.1.3.1.2 (amended
above to 12.1.4.1.2) omit "Packed as in
5,3.1." and put a period after "tubing."
17. In subsection 12.1.3.2 (amended
above to 12.1.4.2) correct "GC/FPD-
11" to "GC/FPD-II."
18. In subsection 12.1.3.2.3 (amended
above to 12.1.4.2.3) the phrase
"12.1.3.1.4. to 12.1.3.1.10" is corrected
to read "12.1.4.1.5 to 12.1.4.1.10."
19. In subsection 12.2, add the fol-
lowing subsection: "12.2.7 Citrate
Buffer. Dissolve 300 grams of potas-
sium citrate and 41 grams of anhy-
drous citric acid in 1 liter of deionized
water. 284 grams of sodium citrate
may be substituted for the potassium
citrate."
(Sec. 111. 301(a) of the Clean Air Act as
amended (42 U.S.C. 7411, 7601 (a))).
CFR Doc. 79-1047 Piled 1-11-79; 8:45 am]
FEDERAL REGISTER, VOL. 44, NO. 9FRIDAY, JANUARY 12, 1979
IV-279
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RVU5 AND 4K6ULAT1ONS
94
Tille 40-Protecfion of Environment
CHAPTER IENVIRONMENTAL
PROTECTION AGENCY
tFRL 1017-7]
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY
SOURCES
Wood Residue-Fired Steam
Generators
APPLICABILITY DETERMINATION
AGENCY: Environmental Protection
Agency.
ACTION: Notice of Determination.
SUMMARY: 'This notice presents the
results of a performance review of par-
ticulate 'matter control systems on
wood residue-fired steam generators.
On November 22, 1976 (41 FR 51397),
EPA amended the standards of per-
formance of new fossil-fuel-fired
steam generators to allow the heat
content of wood residue to be included
with the heat content Of fossil-fuel
when determining compliance with
the standards. EPA stated in the pre-
amble that there were some questions
about the feasibility of units burning a
large -portion of wood residue to
achieve the particulate matter stand-
ard and announced that this would be
reviewed. This review has been com-
pleted, and EPA concludes that the
particulate matter standard «an toe
achieved, therefore, no revision is nec-
essary.
ADDRESSES. The document which
presents the basis for this notice may
be obtained from the Public Informa-
tion Center (PM-215), U.S. Environ-
mental Protection Agency, Washing-
ton, D.C. 20460 (specify "Wood Resi-
due-Fired Steam Generator Particu-
late Matter Control Assessment,"
EPA-450/2-78-044.)
The document may be inspected and
copied at the Public Information Ref-
erence Unit (EPA Library), Room
2922, 401 M Street, S.W., Washington,
D.C.
FOR FURTHER INFORMATION
CONTACT:
Don R. Goodwin, Director, Emission
Standards and Engineering Division,
Environmental Protection Agency,
Research Triangle Park, North
Carolina 27711, telephone number
(919) 541-5271.
SUPPLEMENTARY INFORMATION:
On November 22, 1976, standards
under 40 CFR Part 60, Subpart D for
new fossil-fuel-fired steam generators
were amended (41 FR 51397) to clarify
that the standards apply to each
fossil-fuel and wood residue-fired
steanj generating unit capable of
firing fossil-fuel at a heat input of
more than 73 megawatts (250 million
Btu per hour). The primary objective
of this amendment is to allow the heat
input provided by wood residue to be
used as a dilution agent in the calcula-
tions necessary to determine sulfur
dioxide emissions. EPA recognized in
the preamble of the amendment that
questions remained concerning the
ability of affected facilities which
burn substantially more wood residue
than fossil-fuel to comply with the
standard for particulate matter. The
preamble also stated that EPA was
continuing to gather information on
'this question. The discussion that fol-
lows summarizes the results of EPA's
examination of available information.
INTROBVCTION
Wood residue is a waste by-product
of the pulp and paper industry which
consists of bark, sawdust, slabs, chips,
shavings, and mill trims. Disposal of
this waste prior to the 1960's consisted
mostly of incineration in Dutch ovens
or open air tepees. Since then the
advent of the spreader stroker boiler
and the Increasing costs of fossil-fuels
has made wood residue an -economical
fuel to ±mrn-in large boilers for the
generation of process steam.
There are several hundred steam
generating boilers in the pulp and
paper and allied forest product indus-
try that use fuel which is partly or to-
tally derived from wood residue. These
boilers range in size from 6 megawatts
020 million Btu per hour) to 146
megawatts (500 million "Btu per hour)
and the total emissions from all boil-
ers is estimated to be 225 tons of par-
ticulate matter per day after applica-
tion of existing air pollution control
devices.
Most existing wood residue-fired
boilers subject to State emission stand-
ards are equipped with multitube-cy-
clone mechanical collectors. Manufac-
turers of the multitube collector have
recognized that this type of control
will not meet present new source
standards and have been developing
processes and devices to meet the new
regulations. However, the use of these
various systems on -wood residue-fired
boilers has not found widespread use
to date, resulting in tin information
gap on expected performance of col-
lector types other than conventional
mechanical collectors.
In order to provide needed informa-
tion in this area and to answer ques-
tions raised in trie November 22, 1976
(41 FR 51397), amendment, a study
was conducted on the most effective
control systems in operation on wood
residue-fired boilers. Also the amount
and characteristics of the particulate
emissions from wood residue-fired boil-
ers was studied. The review that fol-
lows presents the results of that study.
PERFORMANCE REVIEW
The combustion of wood residue re-
sults in particulate emissions in the
form 'of bark char or fly ash. En-
trained with the char are varying
amounts of sapd and salt, the quantity
depending on the method by -which
the original wood was logged and de-
livered. The fly ash particulates have
a lower density and are larger in size
than fly ash from coal-fired boilers. In
general, the bark boiler exhaust gas
will have a lower fly ash content than
emissions from similar boilers burning
physically cleaned coals or low-sulfur
Western coals.
The bark fly ash, unlike most fly
ash, is primarily unburned carbon.
With collection -and reinjection to the
FEDERAL REGISTER, VOL. 44, MO. MWEDNESDAY, JANUARY 17, 1979
IV-280
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RULES AND REGULATIONS
boiler, greater carbon burnout can in-
crease boiler .efficiency from one to
four percent. The reinjection of col-
lected ash also significantly increases
the dust loading since the sand is also
recirculated with the fly ash. This in-
creased dust loading can be accommo-
dated by the use of sand separators or
decantation type dust collectors. Col-
lectors of this type in combination
with more efficient units of air pollu-
tion control equipment constitute the
systems currently in operation on ex-
isting plants that were found to oper-
ate with emissions less than the 43
nanograms per joule (0.10 pounds per
million Btu) standard for particulate
matter.
A survey of currently operated facili-
ties that fire wood residue alone or in
combination with fossil-fuel shows
that most operate with mechanical
collectors; some operate with low
energy wet scrubbers, and a few facili-
ties currently use higher energy ven-
turi scrubbers (HEVS) or electrostatic
precipitators (ESP). One facility re-
viewed is using a high temperature
baghouse control system.
Currently, the use of multitube-cy-
clone mechanical collectors on hogged-
fuel boilers provides the sole source of
particulate removal for a majority of
existing plants. The most commonly
used system employs two multiclones
in series allowing for the first collector
to remove the bulk of the dust and a
second collector with special high effi-
ciency vanes for the removal of the
finer particles. Collection efficiency
for this arrangement ranges from 65
to 95 percent. This efficiency range is
not sufficient to provide compliance
with the particulate matter standard,
but' does provide a widely used first
stage collection to which other control
systems are added.
Of special note is one facility using a
Swedish designed mechanical collector
In series with conventional multiclone
collectors. The Swedish collector Is a
small diameter multitube cyclone with
a movable vane ring that imparts a
spinning motion to the gases while at
the same time maintaining a low pres-
sure differential. This system is reduc-
ing emissions from the largest boiler
found in the review to 107 nanograms
per joule.
Electrostatic precipitators have been
demonstrated to allow compliance
with the particulate matter standard
when coal is used as an auxiliary fuel.
Available information indicates that
this type of control provides high col-
lection efficiencies on combinati6n
wood residue coal-fired boilers. One
ESP collects particulate matter from a
50 percent bark, 50 percent coal combi-
nation fired boiler. An emission level
of 13 nanograms per joule (.03 pounds
per million Btu) was obtained using
test methods recommended by the
American Society of Mechanical Engi-
neers.
The fabric filter (baghouse) particu-
late control system provides the high-
est collection efficency available, 99.9
percent. On one facility currently
using a baghouse on a wood residue-
fired boiler, the sodium chloride con-
tent of the ash being filtered is high
enough (70 percent) that the possibil-
ity of fire is practically eliminated.
Source test data collected with EPA
Method 5 showed this system reduces
the particulate emissions to 5 nano-
grams per joule (0.01 pounds per mil-
lion Btu).
The application of fabric filters to
control emissions from hogged fuel
boilers has recently gained acceptance
from several facilities of the paper and
pulp industry, mainly due to the devel-
opment of improved designs and oper-
ation procedures that reduce fire haz-
ards. Several large sized boilers, firing
salt and non-salt laden wood residue,
are being equipped with fabric filter
control systems this year and the per-
formance of these installations will
verify the effectiveness of fabric filtra-
tion.
Practically all of the facilities cur-
rently meeting the new source particu-
late matter standard are using wet
scrubbers of the venturi or wet-im-
pinger type. These units are usually
connected in series with a mechanical
collector. Three facilities reviewed
which are using the wet-impingement
type wet scrubber on large boilers
burning 100 percent bark are produc-
ing particulate emissions well below
the 43 nanograms per joule standard
at operating pressure drops of 1.5 to 2
kPa (6 to 8 inches, H2O). Five facilities
using venturi type wet scrubbers on
large boilers, two burning half oil and
half bark and the other three burning
100 percent bark, are producing partic-
ulate emissions consistently below the
standard at pressure drops of 2.5 to 5
kPa (10 to 20 inches, H,O).
One facility has a large boiler burn-
ing 100 percent bark emitting a maxi-
mum of 5023 nanograms per joule of
particulate matter into a multi-cyclone
dust collector rated at an efficiency of
87 percent. The outlet loading from
this mechanical collector is directed
through two wet impingement-type
scrubbers in parallel. With this ar-
rangement of scrubbers, a collection
efficiency of 97.7 percent is obtained
at pressure drops of 2 kPa (8 inches,
H,O). Source test data collected with
EPA Method 5 showed particulate
matter emissions to be 15 nanograms
per joule, well below the 43 nanograms
per joule standard.
Another facility with a boiler of sim-
ilar size and fuel was emitting a maxi-
mum of 4650 nanograms per joule into
a multi-cyclone dust collector operat-
ing at a collection efficiency of 66 per-
cent. The outlet loading from this col-
lector is drawn into two wet-impinge-
ment scrubbers arranged in parallel.
The operating pressure drop on these
scrubbers was varied within the range
of 1.6 to 2.0 kPa (6 to 8 inches, H,O),
resulting in a proportional decrease in
discharged loadings of 25.8 to 18.5
nanograms per Joule. Source test data
collected on this source was obtained
with the Montana Sampling Train.
Facilities using a venturi type wet
scrubber were found to be able to meet
the 43 nanogram per joule standard at
higher pressure drops than the im-
pingement type scrubber. One facility
with a large boiler burning 100 percent
bark had a multi-cyclone dust collec-
tor in series with a venturi wet scrub-
ber operating at a pressure drop of 5
kPa (20 inches, H2O). Source test data
using EPA Method 5 showed this
system consistently reduces emissions
to an average outlet loading of 17.2
nanograms per joule of particulate
matter. Another facility with a boiler
burning 40 percent bark and 60 per-
cent oil has a multi-cyclone and ven-
turi scrubber system obtaining 25.8
nanograms per joule at a pressure
drop of 2.5 kPa (10 inches, H2O). The
Florida Wet Train was used to obtain
emission data on this source. A facility
of similar design but burning 100 per-
cent bark is obtaining the same emis-
sion control, 25.8 nanograms per joule,
at a pressure drop of 3 kPa (12 inches,
H2O). Source test data collected on
this source were obtained with the
EPA Method 5.
This review has shown that the use
of a wet scrubber, ESP, or a baghouse
to control emissions from wood bark
boilers will permit attainment of the
particulate matter standard under 40
CFR Part 60. The control method cur-
rently used, which has the widest ap-
plication is the multitube cyclone col-
lector in series with a venturi or wet-
impingement type scrubber. Source
test data have shown that facilities
which burn substantially more wood
residue than fossil-fuel have no diffi-
culty in complying with the 43 nano-
gram per joule standard for particu-
late matter. Also the investigated
facilities have been in operation suc-
cessfully for a number of years with-
out adverse economical problems.
Therefore EPA has concluded from
evaluation of the available informa-
tion that no revision is required of the
particulate matter standard for wood
residue-fired boilers.
Dated: January 3, 1979.
DOUGLAS M. COSTLE,
Administrator.
[PR Doc. 79-1421 Piled 1-16-79; 8:45 am]
FEDfRAL REGISTER, VOL 44, NO. 12WEDNESDAY, JANUARY 17, 1979
IV-281
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RULES AND REGULATIONS
95
FAIT «0 STANDARDS OF FCMOHM-
ANCE FOR NEW STATIONARY
SOURCES
DELEGATION OF AUTHORITY TO
STATE OF TEXAS
AGENCY: Environmental Protection
Agency.
ACTION: Final rule.
SUMMARY: This action amends Sec-
tion «0.4, Address, to reflect the dele-
gation of authority for the Standard*
of Performance for Mew Stationary
Sources (HSPS) to the State of Texas.
DATE: February 7. 1979.
INFORMATION
FOR FURTHER
CONTACT:
James Veach, Enforcement Division,
Region 8. Environmental Protection
Agency, First' International Build-
Ing. 1201 Elm Street; Dallas. Texas
75270, telephone (214) 767-2760.
SUPPLEMENTARY INFORMATION:
A notice announcing the delegation of
authority is published elsewhere in
the Notice Section in this issue of the
FEDERAL REGISTER. These amendments
provide that all reports and communi-
cations previously submitted to the
Administrator, will now be sent to the
Texas Air Control Board, 8520 Shoal
Creek Boulevard, Austin, Texas 78758,
instead of EPA's Region 6.
As this action is not one of substan-
tjve content, but is only an administra-
tive change, public, participation was
Judged unnecessary.
(Section! Ill and JOKa) of the Clean Air
Act; Section 4(a) of Public Law 91-404, 84
8Ut. 1683; Section S of Public Law W-148,
1 8UL 604 (43 V&C. 7411 and 7601.
Dated: November 15, 1978.
ADIXHX HAMUSOX,
Reffitmnl Ad-minlslraior,
Region^.
Part 40 of Chapter 1, TiUe 40, Code
of Federal Regulations, is amended as
follows:
1. In 8«0.4, paragraph (b) <8S) Is
amended as follows:
fM.4 Addreu.
96
PART 60STANDARDS OF PERFORM-
ANCE FOR NEW STATIONARY
SOURCES
Petroleum RefineriesClarifying
Amendment
AGENCY: Environmental Protection
Agency.
ACTION: Final Rule.
SUMMARY: These amendments clari-
fy the definitions of "fuel gas" and
"fuel gas combustion device" Included
In the existing standards of perform-
ance for petroleum refineries. These
amendments will neither increase nor
decrease the degree of emission con-
trol required by the existing stand-
ards. The objective of these amend-
ments is to reduce confusion concern-
ing the applicability of the sulfur
dioxide standard to incinerator-waste
heat boilers installed on fluid or Ther-
mofor catalytic cracking unit catalyst
regenerators and fluid coking unit
coke burners.
EFFECTIVE DATE: March 12, 1979.
FOR FURTHER INFORMATION
CONTACT:
Don R. Goodwin, Director, Emission
Standards and Engineering Division
(MD-13), UJS. Environmental Pro-
tection Agency, Research Triangle
Park, North Carolina 27711, tele-
phone (919) 541-5271.
SUPPLEMENTARY INFORMATION:
On March 8. 1974 (39 PR 9315), stand
ards of performance were promulgated
limiting sulfur dioxide emissions from
fuel gas combustion devices in petro-
leum refineries under 40 CFR Part 60,
Subpart J. Fuel gas combustion de-
vices are defined as any equipment,
such as process heaters, boilers, or
flares, used to combust fuel gas. Fuel
gas is defined as any gas generated by
a petroleum refinery process unit
which 'is combusted. Fluid . catalytic
cracking unit and fluid coking unit in-
cinerator-waste heat boilers, and facili-
ties in which gases are combusted to
produce sulfur or sulfurlc acid are
FEDERAl REGISTER, VOL 44, NO. 49-MONDAY, MARCH IX 1979
(SS) State of Texas, Texas Air Con-
trol Board, 8520 Shoal Creek Boule-
vard, Austin, Texas 78758.
CFR Doc. Tft-4123 Filed 1-4-79; *:4§ ami
KDERAt tfWSTW, YOU 44, NO. VWEDNRDAT, fEMUAlY J, W»
IV-282
-------
RULES AND REGULATIONS
exempted from consideration as fuel
gas combustion devices.
Recently, the following two ques-
tions have been raised concerning the
Intent of exempting fluid catalytic
cracking unit and fluid coking unit in-
cinerator-waste heat boilers.
(1) Is it intended that Thermofor
catalytic cracking unit incinerator
waste-heat boilers be considered the
same as fluid catalytic cracking unit
incinerator-waste heat boilers?
(2) Is the exemption Intended to
apply to the incinerator-waste heat
boiler as a whole including auxiliary
fuel gas also combusted in this boiler?
The answer to the first question is
yes. The answer to the second ques-
tion is no.
The objective of the standards of
performance is to reduce sulfur diox-
ide emissions from fuel gas combus-
tion in petroleum refineries. The
standards are based on amine treating
of refinery fuel gas to remove hydro-
gen sulfide contained in these gases
before they are combusted. The stand-
ards are not intended to apply to those
gas streams generated by catalyst re-
generation in fluid or Thermofor cata-
lytic cracking units, or by coke burn-
ing in fluid coking units. These gas
streams consist primarily of nitrogen,
carbon monoxide, carbon dioxide, and
water vapor, although small amounts
of hydrogen sulfide may be present.
Incinerator-waste heat boilers can be
used to combust these gas streams as a
means of reducing carbon monoxide
emissions and/or generating steam.
Any hydrogen sulfide present is con-
verted to sulfur dioxide. It is not possi-
ble, however, to control sulfur dioxide
emissions by removing whatever hy-
drogen sulfide may be present in these
gas streams before they are combust-
ed. The presence of carbon dioxide ef-
fectively precludes the use of amine
treating, and since this technology is
the basis for these standards, exemp-
tions are included for fluid catalytic
cracking units and fluid coking unite.
Exemptions are not included for
Thermofor catalytic cracking units be-
cause this technology is considered ob-
solete compared to fluid catalytic
cracking. Thus, no new, modified, or
reconstructed Thermofor^ catalytic
cracking units are considered likely.
The possibility that an incinerator-
waste heat boiler might be added to an
existing Thermofor catalytic cracking
unit, however, was overlooked. To take
this possibility into account, the defi-
nitions of "fuel gas" and "fuel gas
combustion device" have been rewrit-
ten to exempt Thermofor catalytic
cracking units from compliance in the
same manner as fluid catalytic crack-
ing units and fluid coking units.
As outlined above, the intent is to
ensure that gas streams generated by
catalyst regeneration or coke burning
in catalytic cracking or fluid coking
units are exempt from compliance
with the standard limiting sulfur diox-
ide emissions from fuel gas combus-
tion. This is accomplished under the
standard as promulgated March 8,
1974, by exempting incinerator-waste
heat boilers installed on these unite
from consideration as fuel gas combus-
tion devices.
Incinerator-waste heat boilers In-
stalled to combust these gas streams
require the firing of auxiliary refinery
fuel gas. This is necessary to insure
complete combustion and prevent
"flame-out" which could lead to an ex-
plosion. By exempting the incinerator-
waste heat boiler, however, this auxil-
iary refinery fuel gas stream is also
exempted, which is not the intent of
these exemptions. This auxiliary refin-
ery fuel gas stream is normally drawn
from the same refinery fuel gas
system that supplies refinery fuel gas
to other process heaters or boilers
within the refinery. Amine treating
can be used, and in most major refin-
eries normally is used, to remove hy-
drogen sulfide from this auxiliary fuel
gas stream as well as from all other re-
finery fuel gas streams.
To ensure that this auxiliary fuel
gas stream fired in waste-heat boilers
is not exempt, the definition of fuel
gas combustion device is revised to
eliminate the exemption for inciner-
ator-waste heat boilers. In addition,
the definition of fuel gas is revised to
exempt those gas streams generated
by catalyst regeneration in catalytic
cracking unite, and by coke burning in
fluid coking unite from consideration
as refinery fuel gas. This will accom-
plish the original intent of exempting
only those gas streams generated by
catalyst regeneration or coke burning
from compliance with the standard
limiting sulfur dioxide emissions from
fuel gas combustion.
MISCELLANEOUS: The Administra-
tor finds that good cause exists for
omitting prior notice and public com-
ment on these amendments and for
making them immediately effective
because they simply clarify the exist-
ing regulations and impose no addi-
tional substantive requirements.
Dated: February 28,1979.
DOUGLAS M. COSTLE,
Administrator.
Part 60 of Chapter I. Title 40 of the
Code of Federal Regulations is amend-
ed as follows:
1. Section 60.101 is amended by re-
vising paragraphs (d) and (g) as fol-
lows:
§ 60.101 Definitions.
(d) "Fuel gas" means natural gas or
any gas generated by a petroleum re-
finery process unit which is combusted
separately or in any combination. Fuel
gas does not include gases generated
by catalytic cracking unit catalyst re-
generators and fluid coking unit coke
burners.
(g) "Fuel gas combustion device"
means any equipment, such as process
heaters, boilers, and flares used to
combust fuel gas, except facilities in
which gases are combusted to produce
sulfur or sulfuric acid.
(Sec. Ill, 301(a), Clean Air Act as amended
(42 UJ3.C. 7411. 760Ua»)
[PR Doc. 79-7428 Filed 3-9-79; 8:45 am}
FEDERAL REGISTER, VOL. 44, NO. 49MONDAY, MARCH 12, 1979
IV-283
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Federal Register / Vol. 44, No. 77 / Thursday, April 19, 1979 / Rules and Regulations
97
40 CFR Part 60
Standards of Performance for New
Stationary Sources; Delegation of
Authority to Washington Local Agency
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Final Rulemaking.
SUMMARY: This rulemaking announces
EPA's concurrence with the State of
Washington Department of Ecology's
(DOE) sub-delegation of the
enforcement of the New Source
Performance Standards (NSPS) program
for asphalt batch plants to the Olympic
Air Pollution Control Authority
(OAPCA) and revises 40 CFR Part 60
accordingly. Concurrence was requested
by the State on February 27,1979.
EFFECTIVE DATE: April 19, 1979.
ADDRESS:
Environmental Protection Agency,
Region X M/S 629,1200 Sixth Avenue,
Seattle, WA 98101.
State of Washington, Department of
Ecology, Olympia, WA 98504.
Olympic Air Pollution Control Authority^.
120 East State Avenue, Olympia, WA
98501.
Environmental Protection Agency,
Public Information Reference Unit,
Room 2922, 401 M Street SW.,
Washington, D.C. 20640.
FOR FURTHER INFORMATION CONTACT:
Clark L. Gaulding, Chief, Air Programs
Branch M/S 629, Environmental
Protection Agency, 1200 Sixth Avenue,
Seattle, WA 98101, Telephone No. (206)
442-1230 FTS 399-1230.
SUPPLEMENTARY INFORMATION: Pursuant
to Section lll(c) of the Clean Air Act (42
USC 7411(c)), on February 27,1979, the
Washington State Department of
Ecology requested that EPA concur with
the State's sub-delegation of the NSPS
program for asphalt batch plants to the
Olympic Air Pollution Control Authority.
After reviewing the State's request, the
Regional Administrator has determined
that the sub-delegation meets all
requirements outlined in EPA's original
February 28,1975 delegation of
authority, which was announced in the
Federal Register on April 1,1975 (40 FR
14632).
Therefore, on March 20,1979, the
Regional Administrator concurred in the
sub-delegation of authority to the
Olympic Air Pollution Control Authority
with the understanding that all
conditions placed on the original
delegation to the State shall apply to the
sub-delegation. By this rulemaking EPA
is amending 40 CFR 60.4 (WW) to reflect
the sub-delegation described above.
The amended § 60.4 provides that all
reports, requests, applications and
communications relating to asphalt
batch plants within the jurisdiction of
Olympic Air Pollution Control Authority
(Clallam, Grays Harbor, Jefferson,
Mason, Pacific and Thurston Counties)
will now be sent to that Agency rather
than the Department of Ecology. The
amended section is set forth below.
The Administrator finds good cause
for foregoing prior public notice and for
making this rulemaking effective
immediafely in that it is an
administrative change and not one of
substantive content. No additional
substantive burdens are imposed on the
parties affected.
This rulemaking is effective
immediately, and is issued under the
authority of Section lll(c) of the Clean
Air Act, as amended. (42 U.S.C. 7411(c)).
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amended
as follows:
1. In § 60.4, paragraph (b) is amended
by revising subparagraph (WW) as
follows:
§ 60.4 Address.
*****
(b) * * * -
(WW) * * *
(vi) Olympic Air Pollution Control
Authority, 120 East State Avenue,
Olympia, WA 98501.
Dated: April 13, 1979.
Douglas M. Ccxtle,
Administrator
[FRL 1202-6)
[FR Doc 79-12211 Filed 4-18-79: 8.45 am)
BILLING CODE «560-01-M
IV-284
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Federal Register / Vol. 44, No. 113 / Monday, June 11, 1979 / Rules and Regulations
98
40CFRPart60
IFRL 1240-7]
New Stationary Sources Performance
Standards; Electric Utility Steam
Generating Units
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Final rule.
SUMMARY: These standards of
performance limit emissions of sulfur
dioxide (SOj), paniculate matter, and
nitrogen oxides (NO,) from new,
modified, and reconstructed electric
utility steam generating units capable of
combusting more than 73 megawatts
(MW) heat input (250 million Btu/hour)
of fossil fuel. A new reference method
for determining continuous compliance
with SOi and NO, standards is also
established. The Clean Air Act
Amendments of 1977 require EPA to
revise the current standards of
performance for fossil-fuel-fired
stationary sources. The intended effect
of this regulation is to require new,
modified, and reconstructed electric
utility steam generating units to use the
best demonstrated technological system
of continuous emission reduction and to
satisfy the requirements of the Clean Air
Act Amendments of 1977.
DATES: The effective date of this
regulation is June 11,1979.
ADDRESSES: A Background Information
Document (BID; EPA 450/3-79-021) has
been prepared for the final standard.
Copies of the BID may be obtained from
the U.S. EPA Library (MD-35), Research
Triangle Park, N.C. 27711, telephone
919-541-2777. In addition, a copy is
available for inspection in the Office of
Public Affairs in each Regional Office,
and in EPA's Central Docket Section in
Washington, D.C. The BID contains (1) a
summary of ah the public comments
made on the proposed regulation; (2) a
summary of the data EPA has obtained
since proposal on SOj, particulate
matter, and NO, emissions; and (3) the
final Environmental Impact Statement
which summarizes the impacts of the
regulation.
Docket No. OAQPS-78-1 containing
all supporting information used by EPA
in developing the standards is available
for public inspection and copying
between 8 a.m. and 4 p.m., ge
alljnO.OOSMonday through Friday, at
EPA's Central Docket Section, room
2903B, Waterside Mall, 401 M Street,
SW., Washington, D.C. 20460.
The docket is an organized and
complete file of all the information
submitted to or otherwise considered by
the Administrator in the development of
this rulemaking. The docketing system is
intended to allow members of the public
and industries involved to readily
identify and locate documents so that
they can intelligently and effectively
participate in the rulemaking process.
Along with the statement of basis and
purpose of the promulgated rule and
EPA responses to significant comments,
the contents of the docket will serve as
the record in case of judicial review
[section 107(d)(a]].
FOR FURTHER INFORMATION CONTACT:
Don R. Goodwin, Director, Emission
Standards and Engineering Division
(MD-13), Environmental Protection
Agency, Research Triangle Park, N.C.
27711, telephone 919-541-5271.
SUPPLEMENTARY INFORMATION: This
preamble contains a detailed discussion
of this rulemaking under the following
headings: SUMMARY OF STANDARDS,
RATIONALE, BACKGROUND,
APPLICABILITY, COMMENTS ON
PROPOSAL, REGULATORY
ANALYSIS, PERFORMANCE TESTING,
MISCELLANEOUS.
Summary of Standards
Applicability
The standards apply to electric utility
steam generating units capable of firing
more than 73 MW (250 million Btu/hour)
heat input of fossil fuel, for which
construction is commenced after
September 18,1978. Industrial
cogeneration facilities that sell less than
25 MW of electricity, or less than one-
third of their potential electrical output
capacity, are not covered. For electric
utility combined cycle gas turbines,
applicability of the standards is
determined on the basis of the fossil-fuel
fired to the steam generator exclusive of
the heat input and electrical power
contribution of the gas turbine.
SOi Standards
The SOj standards are as follows;
(1) Solid and solid-derived fuels
(except solid solvent refined coal): SO,
emissions to the atmosphere are limited
to 520 ng/J (1.20 Ib/million Btu) heat
input, and a 90 percent reduction in
potential SO2 emissions is required at all
times except when emissions to the
atmosphere are less than 260 ng/J (0.60
Ib/million Btu) heat input. When SO,
emissions are less than 260 mg/J (0.60
Ib/million Btu) heat input, a 70 percent
reduction in potential emissions is
required. Compliance with the emission
limit and percent reduction requirements
is determined on a continuous basis by
using continuous monitors to obtain a
30-day rolling average. The percent
reduction is computed on the basis of
overall SO» removed by all types of SOj
and sulfur removal technology, including
flue gas desulfurization (FGD) systems
and fuel pretreatment systems (such as
coal cleaning, coal gasification, and coal
liquefaction). Sulfur removed by a coal
pulverizer or in bottom ash and fly ash
may be included in the computation.
(2) Gaseous and liquid fuels not
derived from solid fuels: SOj emissions
into the atmosphere are limited to 340
ng/J (0.80 Ib/million Btu) heat input, and
a 90 percent reduction in potential SO2
emissions is required. The percent
reduction requirement does not apply if
SOj emissions into the atmosphere are
less than 86 ng/J (0.20 Ib/million Btu)
heat input. Compliance with the SO2
emission limitation and percent
reduction is determined on a continuous
basis by using continuous monitors to
obtain a 30-day rolling average.
(3) Anthracite coal: Electric utility
steam generating units firing anthracite
coal alone are exempt from the
percentage reduction requirement of the
SO, standard but are subject to the 520
ng/J (1.20 Ib/million Btu) heat input
emission limit on a 30-day rolling
average, and all other provisions of the
regulations including the particulate
matter and NO, standards.
(4) Noncontinental areas: Electric
utility steam generating units located in
noncontinental areas (State of Hawaii,
the Virgin Islands, Guam, American
Samoa, the Commonwealth of Puerto
Rico, and the Northern Mariana Islands)
are exempt from the percentage
reduction requirement of the SO2
standard but are subject to the
applicable SOa emission limitation and
all other provisions of the regulations
including the particulate matter and NO,
standards.
(5) Resource recovery facilities:
Resource recovery facilities that fire less
than 25 percent fossil-fuel on a quarterly
(90-day) heat input basis are not subject
to the percentage reduction
requirements but are subject to the 520
ng/J (1.20 Ib/million Btu) heat input
emission limit. Compliance with the
emission limit is determined on a
continuous basis using continuous
monitoring to obtain a 30-day rolling
average. In addition, such facilities must
monitor and report their heat input by
fuel type.
(6) Solid solvent refined coal: Electric
utility steam generating units firing solid
solvent refined coal (SRC I) are subject
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to the 520 ng/J (1.20 Ib/million Btu) heat
input emission limit (30-day rolling
average) and all requirements under the
NO, and participate matter standards.
Compliance with the emission limit is
determined on a continuous basis using
continuous monitor to obtain a 30-day
rolling average. The percentage
reduction requirement for SRC I, which
it to be obtained at the refining facility
itself, is 85 percent reduction in potential
SOt emissions on.a 24-hour (daily)
averaging basis. Compliance is to be
determined by Method 19. Initial full
cale demonstration facilities may be
granted a commercial demonstration
permit establishing a requirement of 80
percent reduction in potential emissions
on a 24-hour (daily) basis.
Particulate Matter Standards
The participate matter standard limits
emissions to 13 ng/J (0.03 Ib/million Btu)
heat input. The opacity standard limits
the opacity of emission to 20 percent (8-
minute average). The standards are
based on the performance of a well-
designed and operated baghouse or
electostatic precipitator (ESP).
M?» Standards
The NO, standards are based on
combustion modification and vary
according to the fuel type. The
standards are:
(1) 86 ng/] (0.20 Ib/million Btu) heat
input from the combustion of any
gaseous fuel, except gaseous fuel
derived from coal;
(2) 130 ng/J (0.30 Ib/million Btu) heat
input from the combustion of any liquid
fuel, except shale oil and liquid fuel
derived from coal;
(3) 210 ng/J (0.50 Ib/million Btu) heat
input from the combustion of
subbituminous coal, shale oil, or any
solid, liquid, or gaseous fuel derived
from coal;
(4) 340 ng/J (0.80 Ib/million Btu) heat
input from the combustion in a slag tap
furnace of any fuel containing more than
25 percent, by weight, lignite which has
been mined in North Dakota, South
Dakota, or Montana;
(5) Combustion of a fuel containing
more than 25 percent, by weight, coal
refuse is exempt from the NO, standards
and monitoring requirements; and
(6) 260 ng/J (0.60 Ib/million Btu) heat
input from the combustion of any solid
fuel not specified under (3), (4), or (5).
Continuous compliance with the NO,
standards is required, based on a 30-day
rolling average. Also, percent reductions
in uncontrolled NO, emission levels are
required. The percent reductions are not
controlling, however, and compliance
with the NO, emission limits will assure
compliance with the percent reduction
requirements.
Emerging Technologies
The standards include provisions
which allow the Administrator to grant
commercial demonstration permits to
allow less stringent requirements for the
initial full-scale demonstration plants of
certain technologies. The standards
include the following provisions:
(1) Facilities using SRC I would be
subject to an emission limitation of 520
ng/j (1.20 Ib/million Btu) heat input,
based on a 30-day rolling average, and
an emission reduction requirement of 85
percent, based on a 24-hour average.
However, the percentage reduction
allowed under a commercial
demonstration permit for the initial full-
scale demonstration plants, using SRC I
would be 80 percent (based on a 24-hour
average). The plant producing the SRC I
would monitor to insure that the
required percentage reduction (24-hour
average) is achieved and the power
plant using the SRC I would monitor to
insure that the 520 ng/J heat input limit
(30-day rolling average) is achieved.
(2) Facilities using fluidized bed
combustion (FBC) or coal liquefaction
would be subject to the emission
limitation and percentage reduction
requirement of the SO* standard and to
the particulate matter and NO,
standards. However, the reduction in
potential SO> emissions allowed under a
commercial demonstration permit for
the initial full-scale demonstration
plants using FBC would be 85 percent
(based on a 30-day rolling average). The
NO, emission limitation allowed under a
commercial demonstration permit for
the initial full-scale demonstration
plants using coal liquefaction would be
300 ng/J (0.70 Ib/million Btu) heat input,
based on a 30-day rolling average.
(3) No more than 15,000 MW
equivalent electrical capacity would be
allotted for the purpose of commercial
demonstration permits. The capacity
will be allocated as follows:
Equivalent
Technology 'Pollutant electrical capacity
MW
SoNd solvent-refined coal
Fkiidized bed combustion
(atmospheric)
Fkudized bed combustion
(pressurized)
Coal liquefaction
SO.
SO,
so.
NO.
5,000-10,000
400-3,000
200-1,200
750-10,000
Compliance Provisions
Continuous compliance with the SO,
and NO, standards is required and is to
be determined with continuous emission
monitors. Reference methods or other
approved procedures must be used to
supplement the emission data when the
continuous emission monitors
malfunction, to provide emissions data
for at least 18 hours of each day for at
least 22 days out of any 30 successive
days of boiler operation.
A malfunctioning FGD system may be
bypassed under emergency conditions.
Compliance with the particulate
standard is determined through
performance tests.-Continuous monitors
are required to measure and record the
opacity of emissions. This data is to be
used to identify excess emissions to
insure that the particulate matter control
system is being properly operated and
maintained.
Rationale
SO, Standards
Under section lll(a) of the Act, a
standard of performance for a fossil-
fuel-fired stationary source must reflect
the degree of emission limitation and
percentage reduction achievable through
the application of the best technological
system of continuous emission reduction
taking into consideration cost and any
nonair quality health and environmental
impacts and energy requirements. In
addition, credit may be given for any
cleaning of the fuel, or reduction in
pollutant characteristics of the fuel, after
mining and prior to combustion.
ki the 1977 amendments to the Clean
Air Act, Congress was severely critical
of the current standard of performance
for power plants, and especially of the
fact that it could be met by the use of
untreated low-sulfur coal. The House, in
particular, felt that the current standard
failed to meet six of the purposes of
section 111. The six purposes are (H.
Rept. at 184-186):
1. The standards must not give a
competitive advantage to one State over
another in attracting industry.
2. The standards must maximize the
potential for long-term economic growth
by reducing emissions as much as
practicable. This would increase the
amount of industrial growth possible
within the limits set by the air quality
standards.
3. The standards must to the extent
practical force the installation of all the
control technology that will ever be
necessary on new plants at the time of
construction when it is cheaper to
install, thereby minimizing the need for
retrofit in the future when air quality
standards begin to set limits to growth.
4 and 5. The standards to the extent
practical must force new sources to bum
high-sulfur fuel thus freeing low-sulfur
fuel for use in existing sources where it
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is harder to cpntrol emissions and where
low-sulfur fuel is needed for compliance.
This will (1) allow old sources to
operate longer and (2) expand
environmentally acceptable energy
upplies.
6. The standards should'be stringent
in order to force the development of
improved technology.
To deal with these perceived
deficiences, the House initiated
revisions to section 111 as follows:
1. New source performance standards
must be based on the "best
technological" control system that has
been "adequately demonstrated," taking
cost and other factors such as energy
into account. The insertion of the word
"technological" precludes a new source
performance standard based solely on
the use of low-sulfur fuels.
2. New source performance standards
for fossil-fuel-fired sources (e.g., power
plants) must require a "percentage
reduction" in emissions, compared to
the emissions that would result from
burning untreated fuels.
The Conference Committee generally
followed the House bill. As a result, the
1977 amendments substantially changed
the criteria for regulating new power
plants by requiring the application of
technological methods of control to
minimize SO, emissions and to
maximize the use of locally available
coals. Under the statute, these goals are
to be achieved through revision of the
standards of performance for new fossil-
fuel-fired stationary sources to specify
(1) an emission limitation and (2) a
percentage reduction requirement.
According to legislative history
accompanying the amendments, the
percentage reduction requirement
should be applied uniformly on a
nationwide basis, unless the
Administrator finds that varying
requirements applied to fuels of differing
characteristics will not undermine the
objectives of the house bill and other
Act provisions.
The principal issue throughout this
rulemaking has been whether a plant
burning low-sulfur coal should be
required to achieve the same percentage
reduction in potential SO* emissions as
those burning higher sulfur coal. The
public comments on the proposed rules
and subsequent analyses performed by
the Office of Air, Noise and Radiation of
EPA served to bring into focus several
other issues as well.
These issues included performance
capabilities of SO, control technology,
the averaging period for determining
compliance, and the potential adverse
impact of the emission ceiling on high-
sulfur coal reserves.
Prior to framing the final SO,
standards, the EPA staff carried out
extensive analyses of a range of
alternative SO, standards using an
econometric model of the utility sector.
As part of this effort, a joint working
group comprised of representatives from
EPA, the Department of Energy, the
Council of Economic Advisors, the
Council on Wage and Price Stability,
and others reviewed the underlying
assumptions used in the model. The
results of these analyses served to
identify environmental, economic, and
energy impacts associated with each of
the alternatives considered at the
national and regional levels. In addition,
supplemental analyses were performed
to assess impacts of alternative
emission'ceilings on specific coal
reserves, to verify performance
characteristics of alternative SO,
scrubbing technologies, and to assess
the sulfur reduction potential of coal
preparation techniques.
Based on the public record and
additional analyses performed, the
Administrator concluded that a 90
percent reduction in potential SO,
emissions (30-day rolling average) has
been adequately demonstrated for high-
sulfur coals. This level can be achieved
at the individual plant level even under
the most demanding conditions through
the application of flue gas
desulfurization (FGD) systems together
with sulfur reductions achieved by
currently practiced coal preparation
techniques. Reductions achieved in the
fly ash and bottom ash are also
applicable. In reaching this finding, the
Administrator considered the
performance of currently operating FGD
systems (scrubbers) and found that
performance could be upgraded to
achieve the recommended level with
better design, maintenance, and
operating practices. A more stringent
requirement based on the levels of
scrubber performance specified for
lower sulfur coals in a number of
prevention of significant deterioration
permits was not adopted since
experience with scrubbers operating
with such performance levels on high-
sulfur coals is limited. In selecting a 30-
day rolling average as the basis for
determining compliance, the
Administrator took into consideration
effects of coal sulfur variability on
scrubber performance as well as
potential adverse impacts that a shorter
averaging period may have on the
ability of small plants to comply.
With respect to lower sulfur coals, the
EPA staff examined whether a uniform
or variable application of the percent
reduction requirement would best
satisfy the statutory requirements of
section 111 of the Act and the supporting
legislative history. The Conference
Report for the Clean Air Act
Amendments of 1977 says in the
pertinent part:
In establishing a national percent reduction
for new fossil fuel-fired sources, the
conferees agreed that the Administrator may.
in his discretion, set a range of pollutant
reduction that reflects varying fuel
characteristics. Any departure from the
uniform national percentage reduction
requirement, however, must be accompanied
by a finding that such a departure does not
undermine the basic purposes of the House
provision and other provisions of the act,
such as maximizing the use of locally
available fuels.
In the face of such language, it is clear
that Congress established a presumption
in favor of a uniform application of the
percentage reduction requirement and
that any departure would require careful
analysis of objectives set forth in the
House bill and the Conference Report.
This question was made more
complex by the emergence of dry SO,
control systems.. As a result of public
comments on the discussion of dry SO,
control technology in the proposal, the
EPA staff examined the potential of this
technology in greater detail. It was
found that the development of dry SO,
controls has progressed rapidly during
the past 12 months. Three full scale
systems are being installed on utility
boilers with scheduled start up in the
1981-1982 period. These already
contracted systems have design
efficiencies ranging from 50 to 85
percent SO, removal, long term average.
In addition, it was determined that bids
are currently being sought for five more
dry control systems (70 to 90 percent
reduction range) for utility applications.
Activity in the dry SO, control field is
being stimulated by several factors.
First, dry control systems are less
complex than wet technology. These
simplified designsjoffer the prospect of
greater reliability at substantially lower
costs than their wet counterparts.
Second, dry systems use less water than
wet scrubbers, which is an important
consideration in the Western part of the
United States. Third, the amount of
energy required to operate dry systems
is less than that required for wet
systems. Finally, the resulting waste
product is more easily disposed of than
wet sludge.
The applicability of dry control
technology, however, appears limited to
low-sulfur coals. At coal sulfur contents
greater than about 1290 ng/J (3 pounds
SO,/million Btu), or about 1.5 percent
sulfur coal, available data indicate that
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it probably will be more economical to
employ a wet scrubber than a dry
control system.
Faced with these findings, the
Administrator had to determine what
effect the structure of the final
regulation would have on the continuing
development and application of this
technology. A thorough engineering
review of the available data indicated
that a requirement of 90 percent
reduction in potential SOi emissions
would be likely to constrain the full
development of this technology by
limiting its potential applicability to high
alkaline content, low-sulfur coals. For
non-alkaline, low-sulfur coals, the
certainty of economically achieving a 90
percent reduction level is markedly
reduced. In the face of this finding, it
would be unlikely that the technology
would be vigorously pursued for these
low alkaline fuels which comprise
approximately one half of the Nation's
low-sulfur coal reserves. In view of this,
the Administrator sought a percentage
reduction requirement that would
provide an opportunity for dry SOi
technology to be developed for all low-
sulfur coal reserves and yet would be
sufficiently stringent to assure that the
technology was developed to its fullest
potential. The Administrator concluded
that a variable control approach with a
minimum requirement of 70 percent
reduction potential in SOj emissions (30-
day rolling average) for low-sulfur coals
would fulfill this objective. This will be
discussed in more detail later in the
preamble. Less stringent, sliding scale
requirements such as those offered by
the utility industry and the Department
of Energy were rejected since they
would have higher associated emissions,
would not be significantly less costly,
and would not serve to encourage
development of this technology.
In addition to promoting the
development of dry SO, systems, a
variable approach offers several other
advantages often cited by the utility
industry. For example, if a source chose
to employ wet technology, a 70 percent
reduction requirement serves to
substantially reduce the energy impact
of operating wet scrubbers in low-sulfur
coals. At this level of wet scrubber
control, a portion of the untested flue
gas could be used for plume reheat so as
to increase plume buoyancy, thus
reducing if not eliminating the need to
expend energy for flue gas reheat.
Further, by establishing a range of
percent reductions, a variable approach
would allow a source some flexibility
particularly when selecting intermediate
sulfur content coals. Finally, under a
variable approach, a source could move
to a lower sulfur content coal to achieve
compliance if its control equipment
failed to meet design expectations.
While these points alone would not be
sufficient to warrant adoption of a
variable standard, they do serve to
supplement the benefits associated with
permitting the use of dry technology.
Regarding the maximum emission
limitation, the Administrator had to
determine a level that was appropriate
when a 90 percent reduction in potential
emissions was applied to high-sulfur
coals. Toward this end, detailed
assessments of the potential impacts of
a wide range of emission limitations on
high-sulfur coal reserves were
performed. The results revealed that a
significant portion (up to 30 percent) of
the high-sulfur coal reserves in the East,
Midwest and portions of the Northern
Appalachia coal regions would require
more than a 90 percent reduction if the
emission limitation were established
below 520 ng/J (1.2 Ib/million Btu) heat
input on a 30-day rolling average basis.
Although higher levels of control are
technically feasible, conservatism in
utility perceptions of scrubber
performance could create a significant
disincentive against the use of these
coals and disrupt the coal markets in
these regions. Accordingly, the
Administrator concluded the emission
limitation should be maintained at 520
ng/J (1.2 Ib/million Btu) heat input on a
30-day rolling average basis. A more
stringent emission limit would be
counter to one of the purposes of the
1977 Amendments, that is, encouraging
the use of higher sulfur coals.
Having determined an appropriate
emission limitation and that a variable
percent reduction requirement should be
established, the Administrator directed
his attention to specifying the final form
of the standard. In doing so, he sought to
achieve the best balance in control
requirements. This was accomplished by
specifying a 520 ng/J (1.2 Ib/million Btu)
heat input emission limitation with a 90
percent reduction in potential SOj
emissions except when emissions to the
atmosphere were reduced below 260 ng/
J (0.6 Ib/million Btu) heat input (30-day
rolling average), when only a 70 percent
reduction in potential SO> emissions
would apply. Compliance with each of
the requirements would be determined
on the basis of a 30-day rolling average.
Under this approach, plants firing high-
sulfur coals would be required to
achieve a 90 percent reduction in
potential emissions in order to comply
with the emission limitation. Those
using intermediate- or low-sulfur content
coals would be permitted to achieve
between 70 and 90 percent reduction,
provided their emissions were less than
260 ng/J (0.6 Ib/million Btu). The 260 ng/
} (0.6 Ib/million Btu) level was selected
to provide for a smooth transition of the
percentage reduction requirement from
high- to low-sulfur coals. Other
transition points were examined but not
adopted since they tended to place
certain types of coal at a disadvantage.
By fashioning the SO* standard in this
manner, the Administrator believes he
has satisfied both the statutory language
of section 111 and the pertinent part of
the Conference Report. The standard
reflects a balance in environmental,
economic, and energy considerations by
being sufficiently stringent to bring
about substantial reductions in SOi
emissions (3 million tons in 1995) yet
does so at reasonable costs without
significant energy penalties. When
compared to a uniform 90 percent
reduction, the standard achieves the
same emission reductions at the
national level. More importantly, by
providing an opportunity for full
development of dry Sd technology the
standard offers potential for further
emission reductions (100 to 200
thousand tons per year), cost savings
(over $1 billion per year), and a
reduction in oil consumption (200
thousand barrels per day) when
compared to a uniform standard. The
standard through its balance and
recognition of varying coal
characteristics, serves to expand
environmentally acceptable energy
supplies without conveying a
competitive advantage to any one coal
producing region. The maintenance of
the emission limitation at 520 ng/J (1.2 Ib
SOj/million Btu) will serve to encourage
the use of locally available high-sulfur
coals. By providing for a range of
percent reductions, the standard offers
flexibility in regard to burning of
intermediate sulfur content coals. By
placing a minimum requirement of 70
percent on low-sulfur coals, the final
rule encourages the full development
and application of dry SOj control
systems on a range of coals. At the same
time, the minimum requirement is
sufficiently stringent to reduce the
amount of low-sulfur coal that moves
eastward when compared to the current
standard. Admittedly, a uniform 90
percent requirement would reduce such
movements further, but in the
Administrator's opinion, such gains
would be of marginal value when
compared to expected increases in high-
sulfur coal production. By achieving a
balanced coal demand within the utility
sector and by promoting the
development of less expensive SOt
control technology, the final standard
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will expand environmentally acceptable
energy supplies to existing power plants
and industrial sources.
By substantially reducing SOi
emissions, the standard will enhance the
potential for long term economic growth
at both the national and regional levels.
While more restrictive requirements
may have resulted in marginal air
quality improvements locally, their
higher costs may well have served to
retard rather than promote air quality
improvement nationally by delaying the
retirement of older, poorly controlled
plants.
The standard must also be viewed
within the broad context of me Clean
Air Act Amendments of 1977. It serves
as a minimum requirement for both
prevention of significant deterioration
and non-attainment considerations.
When warranted by local conditions,
ample authority exists to impose more
restrictive requirements through the
case-by-case new source review
process. When exercised in conjunction
with the standard, these authorities will
assure that our pristine areas and
national parks are adequately protected.
Similarly, in those areas where the
attainment and maintenance of the
- ambient air quality standard is
threatened, more restrictive
requirements will be imposed.
The standard limits SOi emissions
from facilities firing gaseous or liquid
fuels to 340 ng/J {0.80 Ib/million Btu)
heat input and requires 90 percent
reduction in potential emissions on a 30-
day rolling average basis. The percent
reduction does not apply when
emissions are less than 86 ng/J (0.20 ib/
million Btu) heat input on a 30-day
rolling average basis. This reflects a
change to the proposed standards in
that the time for compliance is changed
from the proposed 24-hour basis to a 30-
day rolling average. This change is
necessary to make the compliance times
consistent for all fuels. Enforcement of
the standards would be complicated by
different averaging times, particularly
when more than one fuel is used.
Paniculate Matter Standard
The standard forparticulate matter
limits the emissions to 13 ng/J (0.03 Ib/
million Btu} heat input and requires a 99
percent reduction in uncontrolled
emissions for solid fuels and a 70
percent reduction for liquid fuels. No
particulate matter control is necessary
for units firing gaseous fuels alone, and
a percent reduction is not required. The
percent reduction requirements for solid
and liquid fuels are not controlling, a..d
compliance with the particulate matter
emission limit will assure compliance
with the percent reduction requirements.
A 20 percent (6-minute average)
opacity limit is included in this
standard. The opacity limit is included
to insure proper operation and
maintenance of the emission control
system. If an affected facility were to
comply with all applicable standards
except opacity, the owner or operator
may request that the Administrator,
under 40 CFR 60.11(e). establish a
source-specific opacity limit for that
affected facility.
The standard is based on tie
performance of a well'designed.
operated and maintained electrostatic
precipitator (ESP) or baghouse control
system. The Administrator has
determined that these control systems
are the best adequately demonstrated
technological systems of continuous
emission reduction (taking into
consideration the cost of achieving such
emission reduction, and nonair quality
health and environmental impacts and
energy requirements).
Electrostatic Precip'tators
EPA collected emission data from 21
ESP-equipped steam generating units
which were firing low-sulfur coals (0.4-
1.9 percent). EPA evaluated emission
levels from units burning relatively low-
sulfur coal because it is more difficult
for an ESP to collect pariiculate matter
emissions generated by the combustion
of low-sulfur coal than high-sulfur coal
None of the ESP control systems at the.
21 coal-fired steam generators tested
were designed to achieve a 13 ng/J (0.03
Ib/million Btu) heat input emission level,
however, emission levels at 9 of the 21
units were below the standard. All of
the units that were firing coal with a
sulfur content between 1.0 and 1.9
percent and which had emission levels
below the standard had either a hot-side
ESP (an ESP located before the
combustion air preheater) with a
specific collection area greater than 89
square meters per actual cubic meter per
second {452 ft'/l.OOO ACFM). or a cold-
side ESP (an ESP located after the
combustion air preheater) with a
specific collection area greater than 85
square meters per actual cubic meter per
second (435 ft'/LOOO ACFM).
ESP's require a larger specific
collection area when applied to units
burning low-sulfur coal than to units
burning high-sulfur coal because the
electrical resistivity of the fly ash is
higher with low ^uifur coaL Based on an
examination of the emission data in the
record, it is the Administrator's
judgment that when low-sulfur coa] is
being fired an ESP must have a specific
collection area from about 130 (hot side)
to 200 (cold side) square meters per
actual cubic meter per second (650 to
1,000 ft2 per 1,000 ACFM) to comply with
the standard. When high-sulfur coal
(greater than 3.5 percent sulfur) is being
fired an ESP must have a specific
collection area of about 72 (cold side)
square meters per actual cubic meter per
second (360 ft1 per 1,000 ACFM) to
comply with the standard.
Cold-side ESP's have traditionally
been used to control particulate matter
emissions from power plants. The
problem of ESP collection of high-
electrical-resistivity fly ash from low-
sulfur coal can be reduced by using a
hot-side ESP. Higher fly ash collection
temperatures result in better ESP
performance by reducing fly ash
resistivity for most types of low-sulfur
coal. Reducing fly ash resistivity in itself
would decrease the ESP collection plate
area needed to meet the standard;
however, for a hot-side ESP this benefit
is reduced by the increased flue gas
volume resulting from the higher flue gas
temperature. Although a smaller
collection area is required for a hot-side
ESP than for a cold side ESP, this benefit
is cTfset by greater construction costs
due to the higher quality of materials,
thicker Insulation, and special design
provisions to accommodate the
expansion and warping potential of the
collection plates.
Baghouses
The Administrator has evaluated data
from more than 50 emission test runs
conducted at 8 baghouse-equipped coal-
fired steam generating units. Although
none of these baghouse-controlled units
were designed to achieve a 13 Ng/J (0.03
Ib/million Btu) heat input emission level,
48 of the test results achieved this level
and only 1 test at each of 2 units
exceeded 13 Ng/J (0.03 Ib/million Btu)
heat input. The emission levels at the
two units with emission levels above 13
Ng/J (0.03 Ib/million Btu) heat input
could conceivably be reduced below
that level through an improved
maintenance program. It is the
Administrator's judgment that
baghouses with an air-to-cloth ratio of
0.6 actual cubic meter per minute per
square meter (2 ACFM/ft2) will achieve
the standard at a pressure drop of less
than 1.25 kilopascals (5 in. H»O). The
Administrator has concluded that this
air/cloth ratio and pressure drop are
reasonable when considering cost,
energy, and nonair quality impacts.
When an owner or operator must
choose between an ESP and a baghoase
to meet the standard, it is the
Administrator's judgment that
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baghouses have an advantage for low-
sulfur coal applications and ESP's have
an advantage for high-sulfur coal
applications. Available data indicate
that for low-sulfur coals, ESP's (hot-side
or cold-side) require a large collection
area and thus ESP control system costs
will be higher than baghouse control
system costs. For high-sulfur coals, large
collection areas are not required for
ESP's, and ESP control systems offer
cost savings over baghouse control
systems.
Baghouses have not traditionally been
used at utility power plants. At the time
these regulations were proposed, the
largest baghouse-controlled coal-fired
steam generator for which EPA had
particulate matter emission test data
had an electrical output of 44 MW.
Several larger baghouse installations
were under construction and two larger
units were initiating operation. Since the
date of proposal of these standards, EPA
has tested one of the new units. It has
an electrical output capacity of 350 MW
and is fired with pulverized,
subbituminous coal containing 0.3
percent sulfur. The baghouse control
system for this facility is designed to
achieve a 43 Ng/J (0.01 Ib/million Btu)
heat input emission limit. This unit has
achieved emission levels below 13 Ng/J
(0.03 Ib/million Btu) heat input. The
baghouse control system was designed
with an air-to-cloth ratio of 1.0 actual
cubic meter per minute per square meter
(3.32 ACFM/ft2) and a pressure drop of
1.25 kilopascals (5 in, H2O). Although
some operating problems have been
encountered, the unit is being operated
within its design emission limit and the
level of the standard. During the testing
the power plant operated in excess of
300 MW electrical output. Work is
continuing on the control system to
improve its performance. Regardless of
type, large emission control systems
generally require a period of time for the
establishment of cleaning, maintenance,
and operational procedures that are best
suited for the particular application.
Baghouses are designed and
constructed in modules rather than as
one large unit. The baghouse control
system for the new 350 MW power plant
has 28 baghouse modules, each of which
services 12.5 MW of generating
capacity. As of May 1979, at least 28
baghouse-equipped coal-fired utility
steam generators were operating, and an
additional 28 utility units are planned to
start operation by the end of 1982. About
two-thirds of the 30 planned baghouse-
controlled power generation systems
will have an electrical output capacity
greater than 150 MW, and more than
one-third of these power plants will be
fired with coal containing more than 3
percent sulfur. The Administrator has
concluded that baghouse control
systems have been adequately
demonstrated for full-sized utility
application.
Scrubbers
EPA collected emission test data from
seven coal-fired steam generators
controlled by wet particulate matter
scrubbers. Emissions from five of the
seven scrubber-equipped power plants
were less than 21 Ng/J (0.05 Ib/million
Btu) heat input. Only one of the seven
units had emission test results less than
13 Ng/J (0.03 Ib/million Btu) heat input.
Scrubber pressure drop can be
increased to improve scrubber
particulate matter removal efficiencies;
however, because of cost and energy
considerations, the Administrator
believes that wet particulate matter
scrubbers will only be used in special
situations and generally will not be
selected to comply with the standards.
Performance Testing
When the standards were proposed,
the Administrator recognized that there
is a potential for both FCD sulfate
carryover and sulfuric acid mist to affect
particulate matter performance testing
downstream of an FGD system. Data
available at the time of proposal
indicated that overall particulate matter
emissions, including sulfate carryover,
are not increased by a properly
designed, constructed, maintained, arid
operated FGD system. No additional
information has been received to alter
this finding.
The data available at proposal
indicated that sulfuric acid mist (H2SO4)
interaction with Methods 5 or 17 would
not be a problem when firing low-sulfur
coal, but may be a problem when firing
high-sulfur coals. Limited data obtained
since proposal indicate that when high-
sulfur coal is being fired, there is a
potential for sulfuric acid mist to form
after an FGD system and to introduce
errors in the performance testing results
when Methods 5 or 17 are used. EPA has
obtained particulate matter emission
test data from two power plants that
were fired with coals having more than
3 percent sulfur and that were equipped
with both an ESP and FGD system. The
particulate matter test data collected
after the FGD system were not
conclusive in assessing the acid mist
problem. The first facility tested
appeared to experience a problem with
acid mist interaction. The second facility
did not appear to experience a problem
with acid mist, and emissions after the
ESP/FGD system were less than 13 ng/J
(0.03 Ib/million Btu) heat input. The tests
at both facilities were conducted using
Method 5, but different methods were
used for measuring the filter
temperature. EPA has initiated a review
of Methods 5 and 17 to determine what
modifications may be necessary to
avoid acid mist interaction problems.
Until these studies are completed the
Administrator is approving as an
optional test procedure the use of
Method 5 (or 17) for performance testing
before FGD systems. Performance
testing is discussed in more detail in the
PERFORMANCE TESTING section of
this preamble.
The particulate matter emission limit
and opacity limit apply at all times,
except during periods of startup,
shutdown, or malfunction. Compliance
with the particulate matter emission
limit is determined through performance
tests using Methods 5 or 17. Compliance
with the opacity limit is determined by
the use of Method 9. A continuous
monitoring system to measure opacity is
required to assure proper operation and
maintenance of the emission control
system but is not used for continuous
compliance determinations. Data from
the continuous monitoring system
indicating opacity levels higher than the
standard are reported to EPA quarterly
as excess emissions and not as
violations of the opacity standard.
The environmental impacts of the
revised particulate matter standards
were estimated by using an economic
model of the coal and electric utility
industries (see discussion under
REGULATORY ANALYSIS). This
projection took into consideration the
combined effect of complying with the
revised SO*, particulate matter, and NO,
standards on the construction and
operation of both new and existing
capacity. Particulate matter emissions
from power plants were 3.0 million tons
in 1975. Under continuation of the
current standards, these emissions are
predicted to decrease to 1.4 million tons
by 1995. The primary reason for this
decrease in emissions is the assumption
that existing power plants will come
into compliance with current state
emission regulations. Under these
standards, 1995 emissions are predicted
to decrease another 400 thousand tons
(30 percent).
NOf Standards
The NO, emission standards are
based on emission levels achievable
with a properly designed and operated
boiler that incorporates combustion
modification techniques to reduce NO,
formation. The levels to which NO,
emissions can be reduced with
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combustion modification depend not
only upon boiler operating practice, but
also upon the type of fuel burned.
Consequently, the Administrator has
developed fuel-specific NO, standards.
The standards are presented in this
preamble under Summary of Standards.
Continuous compliance with the NO,
standards is required, based on a 30-day
rolling average. Also, percent reductions
in uncontrolled NO, emission levels are
required. The percent reductions are not
controlling, however, and compliance
with the NO, emission limits will assure
compliance with the percent reduction
requirements.
One change has been made to the*
proposed NO, standards. The proposed
standards would have required
compliance to be based on a 24-hour
averaging period, whereas the final
standards require compliance to be
based on a 30-day rolling average. This
change was made because several of the
comments received, one of which
included emission data, indicated that
more flexibility in boiler operation on a
day-to-day basis is needed to
accommodate slagging and other boiler
problems that may influence NO,
emissions when coal is burned. The
averaging period for determining
compliance with the NO, limitations for
gaseous and liquid fuels has been
changed from the proposed 24-hour to a
30-day rolling average. This change is
necessary to make the compliance times'
consistent for all fuels. Enforcement of
the standards would be complicated by
different averaging times, particularly
where more than one fuel is used. More
details on the selection of the averaging
period for coal appear in this preamble
under Comments on Proposal.
The proposed standards for coal
combustion were based principally on
the results of EPA testing performed at
six electric utility boilers, all of which
are considered to represent modem
boiler designs. One of the boilers was
manufactured by the Babcock and
Wilcox Company (B&W) and was
retrofitted with low-emission burners.
Four of the boilers were Combustion
Engineering, Inc. (CE) designs originally
equipped with overfire air, and one
boiler was a CE design retrofitted with
overfire air. The six boilers burned a
variety of bituminous and
subbituminous coals. Conclusions
drawn from the EPA studies of the
boilers were that the most effective
combustion modification techniques for
reducing NO, emitted from utility
boilers are staged combustion, low
excess air, and reduced heat release
rate. Low-emission burners were also
effective in reducing NO, levels during
the EPA studies.
In developing the proposed standards
for coal, the Administrator also
considered the following; (1) data
obtained from the boiler manufacturers
on 11 CE, three B&W, and three Foster
Wheeler Energy Corporation (FW)
utility boilers; (2) the results of tests
performed twice daily over 30-day
periods at three well-controlled utility
boilers manufactured by CE; (3) a total
of six months of continuously monitored
NO, emission data from two CE boilers
located at the Colstrip plant of the
Montana Power Company; (4) plans
underway at B&W, FW, and the Riley
Stoker Corporation (RS) to develop low-
emission burners and furnace designs;
(5) correspondence from CE indicating
that it would guarantee its new boilers
to achieve, without adverse side-effects,
emission limits essentially the same as
those proposed; and (6) guarantees
made by B&W and FW that their new
boilers would achieve the State of New
Mexico's NO, emission limit of 190 ng/J
(0.45 Ib/million Btu) heat input.
Since proposal of the standards, the
following new information has become
available and has been considered by
the Administrator (1) additional data
from the boiler manufacturers on four
B&W and four RS utility boilers; (2) a
total of 18 months of continuously
monitored NO, data from the two CE
utility boilers at the Colstrip plant; (3)
approximately 10 months of
continuously monitored NO, data from
five other CE boilers; (4) recent
performance test results for a CE and a
RS utility boiler; and (5) recent
guarantees offered by CE and FW to
achieve an NO, emission limit of 190 ng/
J (0.45 Ib/million Bru) heat input in the
State of California. This and other new
information is discussed in "Electric
Utility Steam Generating Units,
Background Information for
Promulgated Emission Standards" (EPA
450/3-79-021).
The data available before and after
proposal indicate that NO, emission
levels below 210 ng/} (0.50 Ib/million
Btu) heat input are achievable with a
variety of coals burned in boilers made
by all four of the major boiler
manufacturers. Lower emission levels
are theoretically achievable with
catalytic ammonia injection, as noted by
several commenters. However, these
systems have not been adequately
demonstrated at this time on full-size
electric utility boilers that burn coal.
Continuously monitored NO, emission
data from coal-fired CE boilers indicate
that emission variability during day-to-
day operation is such that low NO,
levels can be maintained if emissions
are averaged over 30-day periods.
Although the Administrator has not
been able to obtain continuously
monitored data from boilers made by
the other boiler manufacturers, the
Administrator believes that the emission
variability exhibited by CE boilers over
long periods of time is also
characteristic of B&W, FW, and RS
boilers. This is because the
Administrator expects B&W, FW, and
RS boilers to experience operational
conditions which are similar to CE
boilers (e.g., slagging, variations in fuel
quality, and load reductions) when
burning similar fuel. Thus, the
Administrator believes the 30-day
averaging time is appropriate for coal-
fired boilers made by all four
manufacturers.'
Prior to proposal of the standards
several electric utilities and boiler
manufacturers expressed concern over
the potential for accelerated boiler tube
wastage (i.e., corrosion) during low-NO,
operation of a coal-fired boiler. The
severity of tube wastage is believed to
vary with several factors, but especially
with the sulfur content of the coal
burned. For example, the combustion of
high-sulfur bituminous coal appears to
aggravate tube wastage, particularly if it
is burned in a reducing atmosphere. A
reducing atmosphere is sometimes
associated with low-NO, operation.
The EPA studies of one B&W and five
CE utility boilers concluded that tube
wastage rates did not significantly
increase during low-NO, operation. The
significance of these results is limited,
however, in that the tube wastage tests
were conducted over relatively short
periods of time (30 days or 300 hours).
Also, only CE and B&W boilers were
studied, and the B&W boiler was not a
recent design, but was an old-style unit
retrofitted with experimental low-
emission burners. Thus, some concern
still exists over potentially greater tube
wastage during low-NO, operation
when high-sulfur coals are burned. Since
bituminous coals often have high sulfur
contents, the Administrator has
established a special emission limit for
bituminous coals to reduce the potential
for increased tube wastage during low-
NO, operation.
Based on discussions with the boiler
manufacturers and on an evaluation of
all available tube wastage information,
the Administrator has established an
NO, emission limit of 260 ng/J (0.60 lb/
million Btu) heat imput for the
combustion of bituminous coal. The
Administrator believes this is a safe
level at which tube wastage will not be
accelerated by low-NOx operation. In
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support of this belief, CE has stated that
it would guarantee Hi new boilers, when
equipped with overfire air, to achieve
the 260 ng/J (0.60 lb/million Btu) heat
input limit without increased tube
wastage rates when Eastern bituminous
coals are burned. In addition, B&W hat,
noted in several recent technical papers
that its low-emission burners allow the
furnace to be maintained in an oxidizing
atmosphere, thereby reducing the
potential for tube wastage when high-
sulfur bituminous coals are burned. The
other boiler manufacturers have also
developed techniques that reduce the
potential for tube wastage during low-
NO^ operation. Although the amount of
tube wastage data available to the
Administrator on B&W, FW, and RS
boilers is very limited, it is the
Administrator's judgement that all three
of these manufacturers are capable of
designing boilers which would not
experience increased tube wastage rates
as a result of compliance with the NO,
standards.
Since the potential for increased tube
wastage during low-NO, operation
appears to be small when low-sulfur
subbituminous coals are burned, the
Administrator has established a lower
NO, emission limit of 210 ng/J (0.50 Ib/
million Btu) heat input for boilers
burning subbituminous coal. This limit is
consistent with emission data from
boilers representing all four
manufacturers. Furthermore, CE has
stated that it would guarantee its
modern boilers to achieve an NO, limit
of 210 ng/J (0.50 Ib/million Btu) heat
input, without increased tube wastage
rates, when subbituminous coals are
burned.
The emission limits for electric utility
power plants that burn liquid and
gaseous fuels are at the same levels as
the emission limits originally
promulgated in 1971 under 40 CFR Part
60, Subpart D for large steam generators.
It was decided that a new study of
combustion modification or NO, flue-gas
treatment for oil- or gas-fired electric
utility steam generators would not be
appropriate because few, if any, of these
kinds of power plants are expected to be
built in the future.
Several studies indicate that NO,
emissions from the combustion of fuels
derived from coal, such as liquid
solvent-refined coal (SRC JTj and low-
Btu synthetic gas, may be higher than
those from petroleum oil or natural gas.
This is because coal-derived fuels have
fuel-bound nitrogen contents that
approach the levels found in coal rather
than those found in petroleum oil and
natural_gas. Based on limited emission
data from pilot-scale facilities and on
the known emission characteristics of
coal, the Administrator believes that an
achievable emission limit for solid,
liquid, and gaseous fuels derived from
coal is 210 ng/1 (0.50 lb/million Btu) beat
input Tube wastage and other boiler
problems are not expected to occur from
boiler operation at levels as low as 210
ng/J when firing these fuels because of
their low sulfur and ash contents.
NO, emission limits'for lignite
combustion were promulgated in 1978
(48 FR 9276) as amendments to the
original standards under 40 CFR Part 60,
Subpart D. Since no new information on
NO, emission rates from lignite
combustion has become available, the
emission limits have not been changed
for these standards. Also, these
emission limits are the same as the
proposed.
Little is known about the emission
characteristics of shale oil. However,
since shale oil typically has a higher
fuel-bound nitrogen content than
petroleum oil, it may be impossible for a
well-controlled unit burning shale oil to
achieve the NO, emission limit for liquid
fuels. Shale oil does have a similar
nitrogen content to coal and it is
reasonable to expect that the emission
control techniques used for coal could
also be used to limit NO, emissions from
shale oil combustion. Consequently, the
Administrator has limited NO,
emissions from units burning shale oil to
210 ng/J (0.50 Ib/million Btu) heat input,
the same limit applicable to
subbituminous coat which is the same
as proposed. There is no evidence that
tube wastage or other boiler problems
would result from operation of a boiler
at 210 Hg/J when shale oil is burned.
The combustion of coal refuse was
exempted from the original steam
generator standards under 40 CFR Part
60, Subpart D because the only furnace
design believed capable of burning
certain kinds of coal refuse, the slag tap
furnace, inherently produces NO,
emissions in excess of the NO,
standard. Unlike lignite, virtually no
NO, emission data are available for the
combustion of coal refuse in slag tap
furnaces. The Administrator has
decided to continue the coal refuse
exemption under the standards
promulgated here because no new
information on coal refuse combustion
has become available since the
exemption under Subpart D was
established.
The environmental impacts of the
revised NO, standards were estimated
by using an economic model of the coal
and electric utility industries (see
discussion under REGULATORY
ANALYSIS). This projection took into
consideration the combined effect of
complying with the revised SO*
particulate matter, and NO, standards
on the construction and operation of
both new and existing capacity.
National NO, emissions from power
plants were 6.8 million tons in 1975 and
are predicted to increase to 9.3 million
tons by 1995 under the current
standards. These standards are
projected to reduce 1995 emissions, by
600 thousand tons (6 percent).
Backgrovnd
In December 1971, under section 111
of the Clean Air Act, the Administrator
issued standards of performance to limit
emissions of SO* particulate matter,
and NO, from new, modified, and
reconstructed fossil-fuel-fired steam
generators (40 CFR 60.40 et seq.). Since
that time, the technology for controlling
emissions from this source category has
improved, but emissions of SO*,
particulate matter, and NO, continue to
be a national problem. In 1976, steam
electric generating units contributed 24
percent of the particulate matter, 65
percent of the SO* and 29 percent of the
NO, emissions on a national basis.
The utility industry is expected to
have continued and significant growth.
The capacity is expected to increase by
about 50 percent with approximate 300
new fossil-fuel-fired power plant boilers
to begin operation within the next 10
years. Associated with utility growth is
the continued long-term increase in
utility coal consumption from some 400
million tons/year in 1975 to about 1250
million tons/year in 1995. Under the
current performance standards for
power plants, national SO» emissions
are projected to increase approximately
17 percent between 1975 and 1995.
Impacts will be more dramatic on a
regional basis. For example, in the*
absence of more stringent controls,
utility SOa emissions are expected to
increase 1300 percent by 1995 in the
West South Central region of the
country (Texas, Oklahoma, Arkansas,
and Louisiana}.
EPA was petitioned on August 6,1976,
by the Sierra Club and the Oljato and
Red Mesa Chapters of the Navaho Tribe
to revise the SO, standard so as to
require a 90 percent reduction in SO»
emissions from all new coal-fired power
plants. The petition claimed that
advances in technology since 1971
justified a revision of the standard As a
result of the petition, EPA agreed to
investigate the matter thoroughly. On
January 27.1977 (42 FR 5121), EPA
announced that it had initiated a study
to review the technological, economic.
and other factors needed to determine to
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what extent theljOi standard for fossil-
fuel-fired steam generators should be
revised.
On August 7,1977, President Carter
signed into law the Clean Air Act
Amendments of 1977. The provisions
under section lll(b)(6) of the Act, as
amended, required EPA to revise the
standards of performance for fossil-fuel-
fired electric utility steam generators
within 1 year after enactment.
After the Sierra Club petition of
August 1976, EPA initiated studies to
review the advancement made on
pollution control systems at power
plants. These studies were continued
following the amendment of the Clean
Air Act. In order to meet the schedule
established by the Act, a preliminary
assessment of the ongoing studies was
made in late 1977. A National Air
Pollution Control Techniques Advisory
Committee meeting was held on
December 13 and 14,1977, to present
EPA preliminary data. The meeting was
open to the public and comments were
solicited.
The Clean Air Act Amendments of
1977 required the standards to be
revised by August 7,1978. When it
appeared that the Administrator would
not meet this schedule, the Sierra Club
filed a complaint on July 14,1978, with
the U.S. District Court for the District of
Columbia requesting injunctive relief to
require, among other things, that the
Administrator propose the revised
standards by August 7.1978 (Sierra Club
v. Costle, No. 78-1297). The Court,
approved a stipulation requiring the
Administrator to (1) deliver proposed
regulations to the Office of the Federal
Register by September 12,1978, and (2)
promulgate the final regulations within 6
months after proposal (i.e., by March 19,
1979).
The Administrator delivered the
proposal package to the Office of the
Federal Register by September 12,1978,
and the proposed regulations were
published September 19,1978 (43 FR
42154). Public comments on the proposal
were requested by December 15, and a
public hearing was held December 12
and 13, the record of which was held
open until January 15,1979. More than
625 comment letters were received on
the proposal. The comments were
carefully considered, however, the
issues could not be sufficiently
evaluated in time to promulgate the
standards by March 19,1979. On that
date the Administrator and the other
parties in Sierra Club v. Costle filed
with the Court a stipulation whereby the
Administrator would sign and deliver
the final standards to the Federal
Register on or before June 1,1979.
The Administrator's conclusions and
responses to the major issues are
presented in this preamble. These
regulations represent the
Administrator's response to the petition
of the Navaho Tribe and Sierra Club and
fulfill the rulemaking requirements
under section lll(b)(6) of the Act.
Applicability
General
These standards apply to electric
utility steam generating units capable of
firing more than 73 MW (250 million
Btu/hour) heat input of fossil fuel, for
which construction is commenced after
September 18,1978. This is principally
the same as the proposal. Some minor
changes and clarification in the
applicability requirements for
cogeneration facilities and resource
recovery facilities have been made.
On December'23,1971, "the
Administrator promulgated, under
Subpart D of 40 CFR Part 60, standards
of performance for fossil-fuel-fired
steam generators used in electric utility
and large industrial applications. The
standards adopted herein do not apply
to electric utility steam generating units
originally subject to those standards
(Subpart D) unless the affected facilities
are modified or reconstructed as defined
under 40 CFR 60 Subpart A and this
subpart. Similarly, units constructed
prior to December 23,1971, are not
subject to either performance standard
(Subpart D or Da) unless they are
modified or reconstructed.
Electric Utility Steam Generating Units
An electric utility steam generating
unit is defined as any steam electric
generating unit that is physically
connected to a utility power distribution
system and is constructed for the
purpose of selling more than 25 MW
electrical output and more than one
third of its potential electrical output
capacity. Any steam that is sold and
ultimately used to produce electrical
power for sale through the utility power
distribution system is also included
under the standard. The term "potential
electrical generating capacity" has been
added since proposal and is defined as
33 percent of the heat input rate at the
facility. The applicability requirement of
selling more than 25 MW electrical
output capacity has also been added
since proposal.
These standards cover industrial'
steam electric generating units or
cogeneration units (producing steam for
both electrical generation and process
heat) that are capable of firing more
than 73 MW (250 million Btu/hr) heat
input of fossil fuel and are constructed
for the purpose of selling through a
utility power distribution system more
than 25 MW electrical output and more
than one-third of their potential
electrical output capacity (or steam
generating capacity ultimately used to
produce electricity for sale). Facilities
with a heat input rate in excess of 73
MW (250 million Btu/hourJ that produce
only industrial steam or that generate
electricity but sell less than 25 MW
electrical output through the-utility
power distribution system or sell less
than one-third of their potential electric
output capacity through the utility
power distribution system are not %
covered by these standards, but will
continue to be covered under Subpart D,
if applicable.
Resource recovery units incorporating
steam electric generating units that
would meet the applicability
requirements but that combust less than
25 percent fossil fuel on a quarterly (90-
day) heat-input basis are not covered by
the SOj percent reduction requirements
under this standard. These facilities are
subject to the SO» emission limitation
and all other provisions of the
regulation. They are also required to
monitor their heat input by fuel type and
to monitor SO2 emissions. If more than
25 percent fossil fuel is fired on a
quarterly heat input basis, the facility
will be subject to the SO» percent
reduction requirements. This represents
a change from the proposal which did
not include such provisions.
These standards cover steam
generator emissions from electric utility
combined-cycle gas turbines that are
capable of being fired with more than 73
MW (250 million Btu/hr) heat input of
fossil fuel and meet the other
applicability requirements. Electric
utility combined-cycle gas turbines that
use only turbine exhaust gas to provide
heat to a steam generator (waste heat
boiler) or that incorporate steam
generators that are not capable of being
fired with more than 73 MW (250 million
Btu/hr) of fossil fuel are not covered by
the standards.
Modification/Reconstruction
Existing facilities are only covered by
these standards if they are modified or
reconstructed as defined under Subpart
A of 40 CFR Part 60 and this standard
{Subpart Da).
Few, if any, existing facilities that
change fuels, replace burners, etc. will
be covered by these standards as a
result of the modification/reconstruction
provisions. In particular, the standards
do not apply to existing facilities that
are modified to fire nonfossil fuels or to
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existing facilities that were designed to
Tire gas or oil fuels and that are modified
to fire shale oil, coal/oil mixtores, coal/
oil/water mixtures, solvent refined coal,
liquified coal, gasified coal, or any other
coal-derived fuel. These provisions were
included in the proposal but have been
clarified in the final standard.
Comment* OB Proposal
Electric Utility Steam Generating Units
The applicability requirements are
basically the same as those in the
proposal- electric utility steam
generating units capable of firing greater
than 73 MW (250 million Btu/hour) heat
input of fossil fuel for which
construction is commenced after
September 18,1978, are covered. Since
proposal, changes have been made to
specific applicability requirements for
industrial cogeneration facilities,
resource recovery facilities, and
anthracite coal-fired facilities. These
revisions are discussed later in this
preamble.
Only a limited number of comments
were received on the general
applicability provisions. Some
commenters expressed the opinion that
the standards should apply to both
industrial boilers and electric utility
steam generating units. Industrial
boilers are not covered by these
standards because there are significant
differences between the economic
structure of utilities and the industrial
sector. EPA is currently developing
standards for industrial boilers and
plans to propose them in 1980,
Cogeneration Facilities
Cogeneration facilities are covered
under these standards if they have the
capability of firing more than 73 MW
(250 million Btu/hour} heat input of
fossil fuel and are constructed for the
purpose of selling more than 25 MW of
electricity and more than one-third of
their potential electrical output capacity.
This reflects a change from the proposed
standards under which facilities selling
less than 25 MW of electricity through
the utility power-distribution system
may have been covered.
A number of commenters suggested
that industrial cogeneration facilities are
expected to he highly efficient and that
their construction could be discouraged
if the proposed standards were adopted.
The commenters pointed out that
industrial cogeneration facilities are
unusual in that a small capacity (10 MW
electric output capacity, for example)
steam-electric generating set may be
matched with a much larger industrial
steam generator (larger than 250 million
Bnj/hr for example). The Administrator
intended that the proposed standards
cover only electric generation sets that
would sell more than 25 MW electrical
output on the utility power distribution
system. The final standards allow the
sale of up to 25 MW electrical output
capacity before a facility is covered.
Since most industrial cogeneration units
are expected to be less than 25 MW
electrical output capacity, few, if any,
new industrial cogeneration units will
be covered by these standards. The
standards do cover large electric utility
cogeneration facilities because such
units are fundamentally electric utility
steam generating units.
Comments suggested clarifying what
was meant in the proposal by the sale of
more than one-third of its "maximum
electrical generating capacity". Under
the final standard the term "potential
electric output capacity" is used in place
of "maximum electrical generating
capacity" and is defined as 33 percent of
the steam generator heat input capacity.
Thus, a steam generator with a 500 MW
(1,700 million Btu/hr) heat input
capacity would have a 165 MW
potential electrical output capacity and
could sell up to one-third of this
potential output capacity on the grid (55
MW electrical output) before being
covered under the standard. Under the
proposal, it was unclear if the^standard
allowed the sale of up to one-third of the
actual electric generating capacity of a
facility or one-third of the potential
generating capacity before being
covered under the standards. The
Administrator has clarified his
intentions in these standards. Without
this clarification the standards may
have discouraged some industrial
cogeneration facilities that have low in-
house electrical demand.
A number of commenters suggested
that emission credits should be allowed
for improvements in cycle efficiency at
new electric utility power plants. The
commenters suggested that the use of
electrical cogeneration technology and
other technologies with high cycle
efficiencies could result in less overall
fuel consumption, which in turn could
reduce overall environmental impacts
through lower air emissions and less
solid waste generation. The final
standards do not give credit for
jncreases in cycle efficiency because the
different technologies covered by the
standards and available for commercial
application at this time are based on the
use of conventional steam generating
units which have very similar cycle
efficiencies, and credits for improved
cycle efficiency would not provide
measurable benefits. Although the final
standards do not address cycle
efficiency, this approach will not
discourage the application of more
efficient technologies.
If a facility that is planned for
construction will incorporate an
innovative control technology (including
electrical generation technologies with
inherently low emissions or high
electrical generation efficiencies) the
owner or operator may apply to the
Administrator under section lll(j] of the
Act for an innovative technology waiver
which will allow for (1) «p to four years
of operation or (2) up to seven years
after issuance of a waiver prior to
performance testing. The technology
would have to have a substantial
likelihood of achieving greater
continuous emission reduction or.
«chieve equivalent reductions at low
cost in terms of energy, economics, or
nonair quality impacts before a waiver
would be issued.
Resource Recovery Facilities
Electric utility steam generating unit;
incorporated into resource recovery
facilities are exempt from the Sd
percent reduction requirements when
less than. 25 percent of the heat input u
from fossil fuel on a quarterly heat input
basis. Such facilities are subject to all
other requirements of this standard. This
represents a change from the proposed
regulation, underwhich any steam
electric generating unit that combusts
non-fossil fuels such as wood residue,
sewage sludge, waste material, or
municipal refuse would have been
covered if the facility were capable of
firing more than 75 MW (250 million
Btu/hr) of fossil fuel.
A number of comments indicated that
the proposed standard could discourage
the construction of resource recovery
facilities that generate electricity
because of tile SO» percentage reduction
requirement One commenter suggested
that most new resource recovery
facilities will process municipal refuse
and other wastes into a dry fuel with a
low-sulfur content that can be stored
and subsequently fired. The commenter
suggested that when firing processed
refuse fuel, little if any fossil fuel will be
necessary for combustion stabilization
over the long term; however, fossil fuel
will be necessary for startup. When a
cold unit is started, 100 percent fossil
fuel (oil or gas) may be fired for a few
hours prior to firing 100 percent
processed refuse.
Other comrnenteri suggested that
resource recovery facilities would in
many cases be owned and operated by a
municipality and the electricity and
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team generated would be sold by
contract to offset operating costs. Under
such an arrangement, commenters
suggested that there may be a need to
fire fossil fuel on a short-term basis
when refuse is not readily available in
order to generate a reliable supply of
steam for the contract customer.
The Administrator accepts these
suggestions and does not wish to
discourage the construction of resource
recovery facilities that generate
electricity and/or industrial steam. For
resource recovery facilities, the
Administrator believes that less than 25
percent heat input from fossil fuels will
be required on a long-term basis; even
though 100 percent fossil fuel firing
{greater than 73 MW (250 million Btu/
hour)] may be necessary for startup or
intermittent periods when refuse is not
available. During startup such units are
allowed to fire 100 percent fossil fuel
because periods of startup are exempt
from the standards under 40 CFR 60.8(c).
If a reliable source of refuse is not
available and 100 percent fossil fuel is to
be fired more than 25 percent of the
time, the Administrator believes it is
reasonable to require such units to meet
the SO, percent reduction requirements.
This will allow resource recovery
facilities to operate with fossil fuel up to
25 percent of the time without having to
install and operate an FGD system.
Anthracite
These standards exempt facilities that
burn anthracite alone from the
percentage reduction requirements of
the SOj 'standard but cover them under
the 520 ng/J (1.2 Ib/million Btu) heat
input emission limitation and all
requirements of the particulate matter
and NO, standards. The proposed
regulations would have covered
anthracite in the same maner as all
other coals. Since the Administrator
recognized that there were arguments in
favor of less stringent requirements for
anthracite, this issue was discussed in
the preamble to the proposed
regulations.
Over 30 individuals or organizations
commented on the anthracite issue.
Almost all of the commenters favored
exempting anthracite from the SO*
percentage reduction requirement. Some
of the reasons cited to justify exemption
were: (l) the sulfur content of anthracite
is low; (2) anthracite is more expensive
to mine and burn than bituminous and
will not be used unless it is cost
competitive; and (3) reopening the
anthracite mines will result in
improvement of acid-mine-water
conditions, elimination of old mining
scars on the topography, eradication of
dangerous fires in deep mines and culm
banks, and creation of new jobs. One
commenter pointed out that the average
sulfur content of anthracite is 1.09
percent. Other commenters indicated
that anthracite will be cleaned, which
will reduce the sulfur content. One
commenter opposed exempting
anthracite, because it would result in
more SO. emissions. Another
commenter said all coal-fired power
plants including anthracite-fired units
should have scrubbers.
After evaluating all of the comments,
the Administrator has decided to
exempt facilities that burn anthracite
alone from the percentage reduction
requirements of the SO, standard. These
facilities will be subject to all other
requirements of this regulation,
including the particulate matter and NOX
standards, and the 520 ng/J (1.2 lb/
million Btu) heat imput emission
limitation under the SO, standard.
In 10 Northeastern Pennsylvania
counties, where about 95 percent of the
nation's anthracite coal reserves are
located, approximately 40,000 acres of
land have been despoiled from previous
anthracite mining. The recently enacted
Federal Surface Mining Control and
Reclamation Act was passed to provide
for the reclamation of areas like this.
Under this Act, each ton of coal mined is
taxed at 35 cents for strip mining and 15
cents for deep mining operations. One-
half of the amount taxed is
automatically returned to the State
where the coal mined and one-half is to
be distributed by the Department of
Interior. This tax is expected to lead
eventually to the reclamation of the
anthracite region, but restoration will
require many years. The reclamation
will occur sooner if culm piles are used
for fuel, the abandoned mines are
reopened, and the expense of
reclamation is born directly by the mine
operator.
The Federal Surface Mining Control
and Reclamation Act and a similar
Pennsylvania law also provide for the
establishment of programs to regulate
anthracite mining. The State of
Pennsylvania has assured EPA that total
reclamation will occur if anthracite
mining activity increases. They are
actively pursuing with private industry
the development of one area involving
12,000 to 19,000 acres of despoiled land.
In Summary, the Administrator
concludes that the higher SO2 emissions
resulting
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Federal Register / Vol. 44. No. 113 / Monday, June 11, 1979 / Rules and Regulations
power demand or complying with the
standards. These emergency provisions
are discussed in a subsequent section of
this preamble.
Concern was expressed by the
commenters that the cost impact of the
standard would be excessive and that
the benefits do not justify the cost,
especially since Alaskan coal is among
the lowest sulfur-content coal in the
country. The Administrator agrees that
for comparable sulfur-content coals,
scrubber operating costs are slightly
higher in Alaska because of the
transportation costs of required
materials such as lime. However, the
operating costs are lower than the
typical costs of FGD units controlling
emissions from higher sulfur coals in the
contiguous 48 States.
The Administrator considered
applying a less stringent SO2 standard to
Alaskan coal-fired units, but concluded
that there is insufficient distinction
between conditions in Alaska and
conditions in the northern part of the
contiguous 48 States to justify such
action. The Administrator has
concluded that Alaskan coal-fired units
should be controlled in the same manner
as other facilities firing low-sulfur coal.
Noncontinental Areas
Facilities in noncontinental areas
(State of Hawaii, the Virgin Islands,
Guam, American Samoa, the
Commonwealth of Puerto Rico, and the
Northern Mariana Islands) are exempt
from the SO2 percentage reduction
requirements. Such facilities are
required, however, to meet the SO2
emission limitations of 520 ng/J (1.2 lb/
million Btu) heat input (30-day rolling
average) for coal and 340 ng/J (0.8 lb/
million Btu) heat input (30-day rolling
average) for oil, in addition to all
requirements under the NO, and
particulate matter standards. This is the
same as the proposed standards.
Although this provision was identified
as an issue in the preamble to the
proposed standards, very few comments
were received on it. In general, the
comments supported the proposal. The
main question raised is whether Puerto
Rico has adequate land available for
sludge disposal.
After evaluating the comments and
available information, the Administrator
has concluded that noncontinental
areas, including Puerto Rico, are unique
and should be exempt from the SO2
percentage reduction requirements.
The impact of new power plants in
noncontinental areas on ambient air
quality will be minimized because each
will have to undergo a review to assure
compliance with the prevention of
significant deterioration provisions
under the Clean Air Act. The
Administrator does not intend to rule
out the possibility that an individual
BACT or LAER determination for a
power plant in a noncontinental area
may require scrubbing.
Emerging Technology
The final regulations for emerging
technologies are summarized earlier in
this preamble under SUMMARY OF
STANDARDS and are very similar to
the proposed regulations.
In general, the comments received on
the proposed regulations were
supportive, although a few commenters
suggested some changes. A few
commenters indicated that section lll(j)
of the Act provides EPA with authority
to handle innovative technologies. Some
commenters pointed out that the
proposed standards did not address
certain technologies such as dry
scrubbers for SO2 control. One
commenter suggested that SRC I should
be included under the solvent refined
coal rather than coal liquefaction
category for purposes of allocating the
15,000 MW equivalent electrical
capacity.
On the basis of the comments and
public record, the Administrator
believes the need still exists to provide
a regulatory mechanism to allow a less
stringent standard to the initial full-scale
demonstration facilities of certain
emerging technologies. At the time the
standards were proposed, the
Administrator recognized that the
innovative technology waiver provisions
under section lll(j) of the Act are not
adequate to encourage certain capital-
intensive, front-end control
technologies. Under the innovative
technology provisions, the
Administrator may grant waivers for a
period of up to 7 years from the date of
issuance of a waiver or up to 4 years
from the start of operation of a facility,
whichever is less. Although this amount
of time may be sufficient to amortize the
cost of tail-gas control devices that do
not achieve their design control level, it
does not appear to be sufficient for
amortization of high-capital-cost, front-
end control technologies. The proposed
provisions were designed to mitigate the
potential impact on emerging front-end
technologies and insure that the
standards dojiot preclude the
development of such technologies.
Changes have been made to the
proposed regulations for emerging
technologies relative to averaging time
in order to make them consistent with
the final NO, and SO, standards;
however, a 24-hour averaging period has
been retained for SRC-I because it has
relatively uniform emission rates, which
makes a 24-hour averaging period more
appropriate than a 30-day rolling
average.
Commercial demonstration permits
establish less stringent requirements for
the SOa or NO, standards, but do not
exempt facilities with these permits
from any other requirements of these
standards.
Under the final regulations, the
Administrator (in consultation with the
Department of Energy) will issue
commercial demonstration permits for
the initial full-scale demonstration
facilities of each specified technology.
These technologies have been shown to
have the potential to achieve the
standards established for commercial
facilities. If, in implementing these
provisions, the Administrator finds that
a given emerging technology cannot
achieve the standards for commercial
facilities, but it offers superior overall
environmental performance (taking into
consideration all areas of environmental
impact, including air, water, solid waste,
toxics, and land use) alternative
standards can be established.
It should be noted that these permits
will only apply to the application of this
standard and will not supersede the new
source review procedures and
prevention of significant deterioration
requirements under other provisions of
the Act.
Modification/Reconstruction
The impact of the modification/
reconstruction provisions is the same for
the final standard as it was for the
proposed standard; existing facilities are
only covered by the final standards if
the facilities are modified or
reconstructed as defined under 40 CFR
60.14, 60.15, or 60.40a. Many types of fuel
switches are expressly exempt from
modification/reconstruction provisions
under section 111 of the Act.
Few, if any, existing steam generators
that change fuels, replace burners, etc.,
are expected to qualify under the
modification/reconstruction provisions;
thus, few, if any, existing electric utility
steam generating units will become
subject to these standards.
The preamble to the proposed
regulations did not provide a detailed
discussion of the modification/
reconstruction provisions, and the
comments received indicated that these
provisions were not well understood by
the commenters. The general
modification/reconstruction pro visions
under 40 CFR 60.14 and 60.15 apply to all
source categories covered under Part 60.
Any source-specific modification/
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reconstruction provisions are defined in
more detail under the applicable subpart
(60.40a for this standard).
A number of commenters expressly
requested that fuel switching provisions
be more clearly addressed by the
standard. In response, the Administrator
has clarified the fuel switching
provisions by including them in the final
standards. Under these provisions
existing facilities that are converted to
nonfossil fuels are not considered to
have undergone modification. Similarly,
existing facilities designed to fire gas or
oil and that are converted to shale oil,
coal/oil mixtures, coal/oil/water
mixtures, solvent refined coal, liquified
coal, gasified coal, or any other coal-
derived fuel are not considered to have
undergone modification. This was the
Administrator's intention under the
proposal and was mentioned in the
Federal Register preamble for the
proposal.
SO, Standards
SO, Control TechnologyThe final
SO, standards are based on the
performance of a properly designed.
installed, operated and maintained FGD
system. Although the standards are
based on lime and limestone FGD
systems, other commercially available
FGD systems {e.g., Wellman-Lord,
double alkali and magnesium oxide) are
also capable of achieving the final
standard. In addition, when specifying
the form of the final standards, the
Administrator considered the potential
of dry SO, control systems as discussed
later in this section.
Since the standards were proposed,
EPA has continued to collect SO, data
with continuous monitors at two sites
and initiated data gathering at two
additional sites. At the Conesville No. 5
plant of Columbus and Southern Ohio
Electric company, EPA gathered
continuous SO, data from July to
December 1978. The Conesville No. 5
FGD unit is a turbulent contact absorber
(TCA) scrubber using thiosorbic lime as
the scrubbing medium. Two parallel
modules handle the gas flow from a 411-
MW boiler firing mn-of-mine 4.5 percent
sulfur Ohio coal. During the test period,
data for only thirty-four 24-hour
averaging periods were gathered
because of frequent boiler and scrubber
outages. The Conesville system
averaged 88.8 percent SO, removal, and
outlet SO, emissions averaged 0.80 lb/
million Btu. Monitoring of the Wellman-
Lord FGD unit at Northern Indiana
Public Service Company's Mitchell
station during 1978 included one 41-day
continuous period of operation. Data
from this period were combined with
previous data and analyzed. Results
indicated 0.61 Ib SO,/million Btu and
89.2 percent SO, removal for fifty-six 24-
hour periods.
From December 1978 to February 1979,
EPA gathered SO, data with continuous
monitors at the 10-MW prototype unit
(using a TCA absorber with lime) at
Tennessee Valley Authority's (TVA)
Shawnee station and the Lawrence No.
4 FGD unit (using limestone) of Kansas
Power and Light Company. During the
Shawnee test, data were obtained for
forty-two 24-hour periods in which 3.0
percent sulfur coal was fired. Sulfur
dioxide removal averaged 88.6 percent.
Lawrence No. 4 consists of a 125-MW
boiler controlled by a spray tower
limestone FGD unit. In January and
February 1979, during twenty-two 24-
hour periods of operation with 0.5
percent sulfur coal, the average SO,
removal was 96.6 percent. The Shawnee
and Lawrence tests also demonstrated
that SO, monitors can function with
reliabilities above 80 percent. A
summary of the recent EPA-acquired
SO, monitored data follows:
8tt*
Scrubber
Coal sulfur,
pet
No of 24-
hour parted,
Average SO,
removal, pel
CooetvHte No. 6...
NIPSCO
Shawnee -
Lawrence No 4 ...
Thosorbk: ime/TCA
,,....... Wellman-Lord ..._ -...
Ume/TCA ,
45
3.5
30
05
34
56
42
22
692
862
666
966
Since proposing the standards, EPA
has prepared a report that updates
information in the earlier PEDCo report
on FGD systems. The report includes
Listings of several new closed-loop
systems.
A variety of comments were received
concerning SO, control technology.
Several comments were concerned with
the use of data from FGD systems
operating in Japan. These comments
suggested that the Japanese experience
shows that technology exists to obtain
greater than 90 percent SCfe removal.
The commenters pointed out that
attitudes of the plant operators, the skill
of the FGD system operators, the close
surveillance of power plant emissions by
the Japanese Government, and technical
differences in the mode of scrubber
operation were primary factors in the
higher FGD reliabilities and efficiencies
for Japanese systems. These commenters
stated that the Japanese experience is
directly applicable to U.S. facilities.
Other comments stated that the
Japanese systems cannot be used to
support standards for power plants in
the U.S. because of the possible
differences in factors such as the degree
of closed-loop versus open-loop
operation, the impact of trace
constituents such as chlorides, the
differences in inlet SO: concentrations,
SOj uptake per volume of slurry,
Japanese production of gypsum instead
of sludge, coal blending and the amount
of maintenance.
The comments on closed-loop
operation of Japanese systems inferred
that larger quantities of water are
purged from these systems than from
their U.S. counterparts. A closed-loop
system is one where the only water
leaving the system is by: (1) evaporative
water losses in the scrubber, and (2) the
water associated with the sludge. The
administrator found by investigating the
systems referred to in the comments that
six of ten Japanese systems listed by
one commenter and two of four coal-
fired Japanese systems are operated
within the above definition of closed-
loop. The closed-loop operation of
Japanese scrubbers was also attested to
in an Interagencey Task Force Report,
"Sulfur Oxides Control Technology in
Japan" (June 30,1978) prepared for
Honorable Henry M. Jackson, Chairman,
Senate Committee on Energy and
Natural Resources. It is also important
to note that several of these successful
Japanese systems were designed by U.S.
vendors.
After evaluating all the comments, the
Administrator has concluded that the
experience with systems in Japan is
applicable to U.S. power plants and can
be used as support to show that the final
standards are achievable.
A few commenters stated that closed-
loop operation of an FGD system could
not be accomplished, especially at
utilities burning high-sulfur coal and
located in areas where rainfall into the
sludge disposal pond exceeds
evaporation from the pond. It is
important to note that neither the
proposed nor final standards require
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closed-loop operation of the FGD. The
commenters are primarily concerned
that future water pollution regulations
will require closed-loop operation.
Several of these commenters ignored the
large amount of water that is evaporated
by the hot exhaust gases in the scrubber
and the water that is combined with and
goes to disposal with the sludge in a
typical ponding system. If necessary, the
sludge can be dewatered by use of a
mechanical clarifier, filter, or centrifuge
and then sludge disposed of in a landfill
designed to minimize rainwater
collection. The sludge could also be
physically or chemically stabilized.
Most U.S. systems operate open-loop
(i.e., have some water discharge from
their sludge pond) because they are not
required to do otherwise. In a recent
report "Electric Utility Steam Generating
UnitsFlue Gas Desulfurization
Capabilities as of October 1978" (EPA-
450/3-79-001), PEDCo reported that
several utilities burning both low- and
high-sulfur coal have reported that they
are operating closed-loop FGD systems.
As discussed earlier, systems in Japan
are operating closed-loop if pond
disposal is included in'the system. Also,
experiments at the Shawnee test facility
have shown that highly reliable
operation can be achieved with high
sulfur coal (containing moderate to high
levels of chloride) during closed-loop
operation. The Administrator continues
to believe that although not required,
closed-loop operation is technically and
economically feasible if the FGD and
disposal system are properly designed.
If a water purge is necessary to control
chloride buildup, this stream can be
treated prior to disposal using
commercially available water treatment
methods, as discussed in the report
"Controlling SO? Emissions from Coal-
Fired Steam-Electric Generators: Water
Pollution Impact" (EPA-600/7-78-045b).
Two comments endorsed coal
cleaning as an SO2 emission control
technique. One commenter encouraged
EPA to study the potential of coal
cleaning, and another endorsed coal
cleaning in preference to FGD. The
Administrator investigated coal cleaning
and the relative economics of FGD and
coal cleaning and the results are
presented in the report "Physical Coal
Cleaning for Utility Boiler SO2 Emission
Control" (EPA-600/7-78-034). The
Administrator does not consider coal
cleaning alone as representing the best
demonstrated system for SO2 emission
reduction. Coal cleaning does offer the
following benefits when used in
conjuction with an FGD system: (1) the
SO2 concentrations entering the FGD
system are lower and less variable than
would occur without coal cleaning, (2)
percent removal credit is allowed
toward complying with the SO2 standard
percent removal requirement, and (3) the
SO2 emission limit can be achieved
when using a coal having a sulfur
content above that which would be
needed when coal cleaning is not
practiced. The amount of sulfur that can
be removed from coal by physical coal
cleaning was investigated by the U.S.
Department of the Interior ("Sulfur
Reduction Potential of the Coals of the
United States," Bureau of Mines Report
of Investigations/1976, RI-8118). Coal
cleaning principally removes pyritic
sulfur from coal by crushing it to a
maximum top size and then separating
the pyrites and other rock impurities
from the coal. In order to prevent coal
cleaning processes from developing into
undesirable sources of energy waste, the
amount of crushing and the separation
bath's specific gravity must be limited to
reasonable levels. The Administrator
has concluded that crushing to 1.5
inches topsize and separation at 1.6
specific gravity represents common
practice. At this level, the sulfur
reduction potential of coal cleaning for
the Eastern Midwest (Illinois, Indiana,
and Western Kentucky) and the
Northern Appalachian Coal
(Pennsylvania, Ohio, and West Virginia)
regions averages approximately 30
percent. The washability of specific coal
seams will be less than or more than the
average.
Some comments state that FGD
systems do not work on specific coals,
such as high-sulfur Illinois-Indiana coal,
high-chloride Illinois coal, and Southern
Appalachian coals. After review of the
comments and data, the Administrator
concluded that FGD application is not
limited by coal properties. Two reports,
"Controlling SO2 Emissions from Coal-
Fired Steam-Electric Generators: Water
Pollution Impact" (EPS-600/7-78-045b)
and "Flue Gas Desulfurization Systems:
Design and Operating Considerations"
(EPA-600/7-78-O30b) acknowledge that
coals with high sulfur or -chloride
content may present problems.
Chlorides in flue gas replace active
calcium, magnesium, or sodium alkalis
in the FGD system solution and cause
stress corrosion in susceptible materials.
Prescrubbing of flue gas to absorb
chlorides upstream of the FGD or the
use of alloy materials and protective
coatings are solutions to high-chloride
coal applications. Two reports, "Flue
Gas Desulfurization System Capabilities
for Coal-Fired Steam Generators" (EPA-
600/7-78-032b) and "Flue Gas
Desulfurization Systems: Design and
Operating Considerations" (EPA -600/
7-7-78-030b) also acknowledge that 90
percent SOa removal (or any given level)
is more difficult when burning high-
sulfur coal than when burning low-sulfur
coal because the mass of SO2 that must
be removed is greater when high-sulfur
coal is burned. The increased load
results in larger and more complex FGD
systems (requiring higher liquid-to-gas
ratios, larger pumps, etc). Operation of
current FGD installations such as
LaCygne with over 5 percent sulfur coal,
Cane Run No. 4 on high-sulfur
midwestern coal, and Kentucky Utilities
Green River on 4 percent sulfur coal
provides evidence that complex systems
can be operated successfully on high-
sulfur coal. Recent experience at TVA,
Widows Creek No. 8 shows that FGD
systems can operate successfully at high
SO2 removal efficiencies when Southern
Appalachian coals are burned.
Coal blending was the subject of two
comments: (1) that blending could
reduce, but not eliminate, sulfur
variability; and (2) that coal blending
was a relatively inexpensive way to
meet more relaxed standards. The
Administrator believes that coal
blending, by itself, does not reduce the
average sulfur content of coal but
reduces the variability of the sulfur
content. Coal blending is not considered
representative of the best demonstrated
system for SO2 emission reduction. Coal
blending, like coal cleaning, can be
beneficial to the operation of an FGD
system by reducing the variability of
sulfur loading in the inlet flue gas. Coal
blending may also be useful in reducing
short-term peak SO2 concentrations
where ambient SO2 levels are a
problem.
Several comments were concerned
with the dependability of FGD systems
and problems encountered in operating
them. The commenters suggested that
FGD equipment is a high-risk
investment, and there has been limited
"successful" operating experience. They
expressed the belief that utilities will
experience increased maintenance
requirements and that the possibility of
forced outages due to scaling and
corrosion would be greater as a result of
the standards.
One commenter took issue with a
statement that exhaust stack liner
problems can be solved by using more
expensive materials. The commenter
also argued that EPA has no data
supporting the assumption that
scrubbers have been demonstrated at or
near 90 percent reliability with one
spare module. The Administrator has
considered these comments and has
concluded that properly designed and
operated FGD systems can perform
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reliably. An FCD system is a chemical
process which must be designed (1) to
include materials that will withstand
corrosive/erosive conditions, (2) with
instruments to monitor process
chemistry and (3] with spare capacity to
allow for planned downtime for routine
maintenance. As with any chemical
process, a startup or shakedown period
is required before steady, reliable
operation can be achieved.
The Administrator has continued to
follow the progress of the FGD systems
cited in the supporting documents
published in conjunction with the
proposed regulations in September 1978.
Availability of the FGD system at
Kansas City Power and Light Company's
LaCygne Unit No. 1 has steadily
improved. No FGD-related forced
outages were reported from September
1977 to September 1978. Availability
from January to September 1978
averaged 93 percent. Outages reported
were a result of boiler and turbine
problems but not FGD system problems.
LaCygne Unit No. 1 burns high-sulfur (5
percent) coal, uses one of the earlier
FGD's installed in the U.S., and reduces
SO» emissions by 80 percent with a
limestone system at greater than 90
percent availability. Northern States
Power Company's Sherburne Units
Numbers 1 and 2 on the other hand
operate on low-sulfur coal (0.8 percent).
Sherburne No. 1, which began operating
early in 1976, had 93 percent availability
in both 1977 and 1978. Sherburne No. 2,
which began operation in late 1976 had
availabilities of 93 percent in 1977 and
94 percent in 1978. Both of these systems
include spare modules to maintain these
high availabilities.
Several comments were received
expressing concern over the increased
water use necessary to operate FGD
systems at utilities located in arid
regions. The Administrator believes that
water availability is a factor that limits
power plant siting but since an FGD
system uses less than 10 percent of the
water consumed at a power plant, FGD
will not be the controlling factor in the
siting of new utility plants.
A few commenters criticized EPA for
not considering amendments to the
Federal Water Pollution Control Act
(now the Clean Water Act), the
Resource Conservation and Recovery
Act, or the Toxic Substances Control
Act when analyzing the water pollution
and solid waste impacts of FGD
systems. To the extent possible, the
Administrator believes that the impacts
of these Acts have been taken into
consideration in this rule-making. The
economic impacts were estimated on the
basis of requirements anticipated for
power plants under these Acts.
Various comments were received
regarding the SO> removal efficiency
achievable with FGD technology. One
comment from a major utility system
stated that they agreed with the
standards, as proposed. Many
comments stated that technology for
better than 90 percent SOt removal
exists. One comment was received
stating that 95 percent SO] removal
should be required. The Administrator
concludes that higher SO, removals are
achievable for low-sulfur coal which
was the basis of this comment. While 95
percent SO, removal may be obtainable
on high-sulfur coals with dual alkali or
regenerable FGD systems, long-term
data to support this level are not
available and the Administrator has
concluded that the demand for dual
alkah'/regenerable systems would far
exceed vendor capabilities. When the
uncertainties of extrapolating
performance from 90 to 95 percent for
high-sulfur coal, or from 95 percent on
low-sulfur coal to high-sulfur coal, were
considered, the Administrator
concluded that 95 percent SO, removal
for lime/limestone based systems on
high-sulfur coal could not be reasonably
expected at this time.
Another comment stated that all FGD
systems except lime and limestone were
not demonstrated or not universally
-applicable. The proposed SO, standards
were based upon the conclusion that
they were achievable with a well
designed, operated, and maintained
FGD system. At the time of proposal, the
Administrator believed that lime and
limestone FGD systems would be the
choice of most utilities in the near future
but, in some instances, utilities would
choose the more reactive dual alkali or
regenerable systems. The use of
additives such as magnesium oxides
was not considered,to be necessary for
attainment of the standard, but could be
used at the option of the utility.
Available data show that greater than
90 percent SO* removal has been
achieved at full scale U.S. facilities for
short-term periods when high-sulfur coal
is being combusted, and for long-term
periods at facilities when low-sulfur
coal is burned. In addition, greater than
90 percent SO, removal has been
demonstrated over long-term operating
periods at FGD facilities when operating
on low- and medium-sulfur coals in
Japan.
Other commenters questioned the
exclusion of dry scrubbing techniques
from consideration. Dry scrubbing was
considered in EPA's background
documents and was not excluded from
consideration. Five commercial dry SO»
control systems are currently on order;
three for utility boilers (400-MW, 455-
MW, and 550-MW) and two for
industrial applications. The utility units
are designed to achieve 50 to 85 percent
reduction on a long-term average basis
and are scheduled to commence
operation in 1981-1982. The design basis
for these units is to comply with
applicable State emission limitations. In
addition, dry SO, control systems for six
other utility boilers are out for bid.
However, no full scale dry scrubbers are
presently in operation at utility plants so
information available to EPA and
presented in the background document
dealt with prototype units. Pilot scale
data and estimated costs of full-scale
dry scrubbing systems offer promise of
moderately high (70-85 percent) SO,
removal at costs of three-fourths or less
of a comparable lime or limestone FGD
system. Dry control system and wet
control system costs are approximately
equal for a 2-percent-sulfur coal. With
lower-sulfur coals, dry controls are
particularly attractive, not only because
they would be less costly than wet
systems, but also because they are
expected to require less maintenance
and operating staff, have greater
turndown capabilities, require less
energy consumption for operation, and
produce a dry solid waste material that
can be more easily disposed of than wet
scrubber sludge.
Tests done at the Hoot Lake Station (a
53-MW boiler) in Minnesota
demonstrated the performance
capability of a spray dryer-baghouse dry
control system. The exhaust gas
concentrations before the control
systems were 800 ppm SO, and an
average of 2 gr/acf particulate matter.
With lime as the sorbent, the control
system removed over 86 percent SO,
and 99.96 percent particulate matter at a
stoichiometric ratio of 2.1 moles of lime
absorbent per inlet mole of SO,. When
the spent lime dust was recirculated
from the bag filter to the lime slurry feed
tank, SOj removal efficiencies up to 90
percent ware obtained at stoichiometric
ratios of 1.3-1.5. With the lime
recirculation process, SO, removal
efficiencies of 70-80 percent were
demonstrated at a more economical
stoichiometric ratio (about 0.75). Similar
tests were performed at the Leland Olds
Station using commercial grade-lime.
Based upon the available information,
the Administrator has concluded that 70
percent SO, removal using lime as the
reactanUs technically feasible and
economically attractive in comparison
to wet scrubbing when coals containing
less than 1.5 percent sulfur are being
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combusted. The coal reserves which
contain 1.5 percent sulfur or less
represent approximately 90 percent of
the total Western U.S. reserves.
The standards specify a percentage
reduction and an emission limit but do
not specify technologies which must be
used. The Administrator specifically
took into consideration the potential of
dry SOj scrubbing techniques when
specifying the final form of the standard
in order to provide an opportunity for
their development on low-sulfur coals.
Averaging Time
Compiance with the final SOj
standards is based on a 30-day rolling
average. Compliance with the proposed
standards was based on a 24-hour
average.
Several comments state that the
proposed SO2 percent reduction
requirement is attainable using currently
available control equipment. One utility
company commented upon their
experience with operating pilot and
prototype scrubbers and a. full-scale
limestone FGD system on a 550-MW
plant. They stated that the FGD state of
the art is sufficiently developed to
support the proposed standards. Based
on their analysis of scrubber operating
variability and coal quality variability,
they indicated that to achieve an 85
percent reduction in SOt emissions 90
percent of the time on a daily basis, the
30-day average scrubber efficiency
would have to be at least 88 to 90
percent.
Other comments stated that EPA
contractors did not consider SOa
removal in context with averaging time,
that vendor guarantees were not based
on specific averaging times, and that
quoted SO» removal efficiencies were
based on testing modules. EPA found
through a survey of vendors that many
would offer 90-95 percent SO2 removal
guarantees based upon their usual
acceptance test criteria. However, the
averaging time was not specified. The
Industrial Gas Cleaning Institute (IGCI),
which represents control equipment
vendors, commented that the control
equipment industry has the present
capability to design, manufacture, and
install FGD control systems that have
the capability of attaining the proposed
SOa standards (a continuous 24-hour
average basis). Concern was expressed,
however, about the proposed 24-hour
averaging requirement, and this
commenter recommended the adoption
of 30-day averaging. Since minute-to-
minute variations in factors affecting
FGD efficiency cannot be compensated
for instantaneously, 24-hour averaging is
an impracticably short period for
implementing effective correction or for
creating offsetting favorable higher
efficiency periods.
Numerous other comments were
received recommending that the
proposed 24-hour averaging period be
changed to 30 days. A utility company
stated that their experience with
operating full scale FGD systems at 500-
and 400-MW stations indicates that
variations in FGD operation make it
extremely difficult, if not impossible, to
maintain SOa removal efficiencies in
compliance with the proposed percent
reduction on a continual daily basis. A
commenter representing the industry
stated that it is clear from EPA's data
that the averaging time could be no
shorter than 24 hours,, but that neither
they nor EPA have data at this time to
permit a reasonable determination of
what the appropriate averaging time
should be.
The Administrator has thoroughly
reviewed the available data on FGD
performance and all of the comments
received. Based on this review, he has
concluded that to alleviate this concern
over coal sulfur variability, particularly
its effect on small plant operations, and
to allow greater flexibility in operating
FGD units, the final SOa standard should
be based on a 30-day rolling average
rather than a 24-hour average as
proposed. A rolling average has been
adopted because it allows the
Administrator to enforce the standard
on a daily basis. A 30-day average is
used because it better describes the
typical performance of an FGD system,
allows adequate time for owners or
operators to respond to operating
problems affecting FGD efficiency,
permits greater flexibility in procedures
necessary to operate FGD systems in
compliance with the standard, and can
reduce the effects of coal sulfur
variability on maintaining compliance
with the final SOa standards without the
application of coal blending systems.
Coal blending systems may be required
in some cases, however, to provide for
the attainment and maintenance of the
National Ambient Air Quality Standards
for SOa.
Emission Limitation
In the September proposal a 520 ng/J
(1.20 Ib/million Btu) heat input emission
limit, except for 3 days per month, was
specified for solid fuels. Compliance
was to be determined on a 24-hour
averaging basis.
Following the September proposal, the
joint working group comprised of EPA,
The Department of Energy, the Council
of Economic Advisors, the Council on
Wage and Price Stability, and others
investigated ceilings lower than the
proposal. In looking at these
alternatives, the intent was to take full
advantage of the cost effectiveness
benefits of a joint coal washing/
scrubbing strategy on high-sulfur coal.
The cost of washing is relatively
inexpensive; therefore, the group
anticipated that a low emission ceiling,
which would require coal washing and
90 percent scrubbing, could
substantially reduce emissions in the
East and Midwest at a relatively low
cost. Since coal washing is now a
widespread practice, it was thought that
Eastern coal production would not be
seriously impacted by the lower
emission limit. Analyses using an
econometric model of the utility sector
confirmed these conclusions and the
results were published in the Federal
Register on December 8,1978 (43 FR
57834).
Recognizing certain inherent
limitations in the model when assessing
impacts at disaggregated levels, the
Administrator undertook a more
detailed analysis of regional coal
production impacts in February using
Bureau of Mines reports which provided
seam-by-seam data on the sulfur content
of coal reserves and the coal washing
potential of those reserves. The analysis
identified the amount of reserves that
would require more than 90 percent
scrubbing of washed coal in order to
meet designated ceilings. To determine
the sulfur reduction from coal washing,
the Administrator assumed two levels of
coal preparation technology, which were
thought to represent state-of-the-art coal
preparation (crushing to 1.5-inch top size
with separation at 1.6 specific gravity,
and %-inch top size with separation at
1.6 specific gravity). The amount of
sulfur reduction was determined
according to chemical characteristics of
coals in the reserve base. This
assessment was made using a model
developed by EPA's Office of Research
and Development.
As a result of concerns expressed by
the National Coal Association, a
meeting was called for April 5,1979, in
order for EPA and the National Coal
Association to present their respective
findings as they pertained to potential
impacts of lower emission limits on
high-sulfur coal reserves in the Eastern
Midwest (Illinois, Indiana, and Western
Kentucky) and the Northern
Appalachian (Ohio, West Virginia, and
Pennsylvania) coal regions. Recognizing
the importance of discussion, the
Administrator invited representatives
from the Sierra Club, the Natural
Resources Defense Council, the
Environmental Defense Fund, the Utility
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Air Regulator/Group, and the United
Mine Workers of America, as well as
other interested parties to attend.
At the April 5 meeting, EPA presented
its analysis of the Eastern Midwest and
Northern Appalachian coal regions. The
analysis showed that at a 240 ng/J (0.55
Ib/million Btu) annual emission limit
more than 90 percent scrubbing would
be required on between 5 and 10 percent
of Northern Appalachian reserves and
on 12 to 25 percent of the Eastern
Midwest reserves. At a 340 ng/J (0.80 lb/
million Btu} limit, less than 5 percent of
the reserves in each of these regions
would require greater than 90 percent
scrubbing. At that same meeting, the
National Coal Association presented
data on the sulfur content and
washability of reserves which are
currently held by member companies.
While the reported National Coal
Association reserves represent a very
small portion of the total reserve base,
they indicate reserves which are
planned to be developed in the near
future and provide a detailed property-
by-property data base with which to
compare EPA analytical results. Despite
the differences in data base sizes, the
National Coal Association's study
served to confirm the results of the EPA
analysis. Since the National Coal
Association results were within 5
percentage points of EPA's estimates,
the Administrator concluded that the
Office of Research and Development
model would provide a widely accepted
basis for studying coal reserve impacts.
In addition, as a result of discussions at
this meeting the Administrator revised
his assessment of state-of-the-art coal
cleaning technology. The National Coal
Association acknowledged that crushing
to 1.5-inch top size with separation at 1.6
specific gravity was common practice in
industry, but that crushing to smaller top
sizes would create unmanageable coal
handling problems and great expense.
In order to explore further the
potential for dislocations in regional
coal markets, the Administrator
concluded that actual buying practices
of utilities rather than the mere technical
usability of coals should be considered.
This additional analysis identified coals
that might not be used because of
conservative utility attitudes toward
scrubbing and the degree of risk that a
utility would be willing to take in buying
coal to meet the emission limit. This
analysis was performed in a similar
manner to the analysis described above
except that two additional assumptions
were made: (1) utilities would purchase
coal that would provide about a 10
percent margin below the emission limit
in order to minimize risk, and (2) utilities
would purchase coal that would meet
the emission limit (with margin) with a
90 percent reduction in potential SOS
emissions. This assumption reflects
utility preference for buying washed
coal for which only 85 percent scrubbing
is needed to meet both the percent
reduction and the emission limit as
compared to the previous assumption
that utilities would do 90 percent
scrubbing on washed coal (resulting in
more than 90 percent reduction in
potential SO» emissions). This analysis
was performed using EPA data at 430
ng/J (1.0 Ib/million Btu) and 520 ng/J
(1.20 Ib/million Btu) monthly emission
limits. The results revealed that a
significant portion (up to 22 percent) of
the high-sulfur coal reserves in the
Eastern Midwest and portions of
Northern Appalachian coal regions
would require more than a 90 percent
reduction if tRe emission limitation was
established below 520 ng/J (1.20 lb/
million Btu) on a 30-day rolling average
basis. Although higher levels of control
are technically feasible, conservatism in
utility perceptions of scrubber
performance could create a significant
disincentive against the use of these
coals and disrupt the coal markets in
these regions. Accordingly, the
Administrator concluded the emission
limitation should be maintained at 520
ng/J (1.20 Ib/million Btu) on a 30-day
rolling average basis. A more stringent
emission limit would be counter to one
of the basic purposes of the 1977
Amendments, that is, encouraging the
use of higher sulfur coals.
Full Versus Partial Control
In September 1978, the Administrator
proposed a full or uniform control
alternative and set forth other partial or
variable control options as well for
public comment. At that time, the
Administrator made it clear that a
decision as to the form of the final
standard would not be made until the
public comments were evaluated and
additional analyses were completed.
The analytical results are'discussed
later under Regulatory Analysis.
This issue focuses on whether power
plants firing lower-sulfur coals should
be required to achieve the same
percentage reduction in potential SO»
emissions as those burning higher-sulfur
coals. When addressing this issue, the
public commenters relied heavily on the
statutory language and legislative
history of Section 111 of the Clean Air
Act Amendments of 1977 to bolster their
arguments. Particular attention was
directed to the 'Conference Report which
says in the pertinent part:
In establishing a national percent reduction
for new fossil fuel-fired sources, the
conferees agreed that the Administrator may,
in his discretion, set a range of pollutant
reduction that reflects varying fuel
characteristics. Any departure from the
uniform national percentage reduction
requirement, however, must be accompanied
by a finding that such a departure does not
undermine the basic purposes of the House
provision and other provisions of the act,
such as maximizing the use of locally
available fuels.
Comments Favoring Full or Uniform
Control. Commenters in favor of full
control relied heavily on the statutory
presumption in favor of a uniform
application of the percentage reduction
requirement. They argued that the
Conference Report language, ". . . the
Administrator may, in his discretion, set
a range of pollutant reduction that
reflects varying fuel
characteristics. . . ." merely reflects the
contention of certain conferees that low-
sulfur coals may be more difficult to
treat than high-sulfur coals. This
contention, they assert, is not borne out
by EPA's technical documentation nor
by utility applications for prevention of
significant deterioration permits which
clearly show that high removal
efficiencies can be attained on low-
sulfur coals. In the face of this, they
maintain there is no basis for applying a
lower percent reduction for such coals.
These commenters further maintain
that a uniform application of the percent
reduction requirement is needed to
protect pristine areas and national
parks, particularly in the West. In doing
so, they note that emissions may be up
to seven times higher at the individual
plant level under a partial approach
than under uniform control. In the face
of this, they maintain that partial control
cannot be considered to reflect best
available control technology. They also
contend that the adoption of a partial
approach may serve to undermine the
more stringent State requirements
currently in place in the West.
Turning to national impacts,
commenters favoring a uniform
approach note that it will result in lower
emissions. They maintain that these
lower emissions are significant in terms
of public health and that such
reductions should be maximized,
particularly in light of the Nation's
commitment to greater coal use. They
also assert that a uniform standard is
clearly affordable. They point out that
the incremental increase in costs
associated with a uniform standard is
small when compared to total utility
expenditures and will have a minimal
impact at the consumer level. They
further maintain that EPA has inflated
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the costs of scrubber technology and has
failed to consider factors that should
result in lower costs in future years.
With respect to the oil impacts
associated with a uniform standard,
these same commenters are critical of
the oil prices used in the EPA analyses
and add that if a higher oil price had
been assumed the supposed oil impact
would not have materialized.
They also maintain that the adoption
of a partial approach would serve to
perpetuate the advantage that areas
producing low-sulfur coal enjoyed under
the current standard, which would be
counter to one of the basic purposes of
the House bill. On the other hand, they
argue, a uniform standard would not
only reduce the movement of low-sulfur
coals eastward but would serve to
maximize the use of local high-sulfur
coals.
Finally, one of the commenters
specified a more stringent full control
option than had been analyzed by EPA.
It called for a 95 percent reduction in
potential SOa emissions with about a
280 ng/J (0.65 Ib/million Btu) emission
limit on a monthly basis. In addition,
this alternative reflected higher oil
prices and declining scrubber costs with
time. The results were presented at the
December 12 and 13 public hearing on
the proposed standards.
Comments Favoring Partial or
Variable Control. Those commenters
advocating a partial or variable
approach focused their arguments on the
statutory language of Section 111. They
maintained that the standard must be
based on the "best technological system
of continuous emission reduction which
(taking into consideration the cost of
achieving such emission reduction, any
nonair quality health and environmental
impact and energy requirements) the
Administrator determines has been
adequately demonstrated." They also
asserted that the Conference Report
language clearly gives the Administrator
authority to establish a variable
standard based on varying fuel
characteristics, i.e., coal sulfur content.
Their principal argument is that a
variable approach would achieve
virtually the same emission reductions
at the national level as a uniform
approach but at substantially lower
costs and without incurring a significant
oil penalty. In view of this, they
maintain that a variable approach best
satisfies the statutory language of
Section 111.
In support of variable control they
also note that the revised NSPS will
serve as a minimum requirement for
prevention of significant deterioration
and non-attainment considerations, and
that ample authority exists to impose
more stringent requirements on a case-
by-case basis. They contend that these
authorities should be sufficient to
protect pristine areas and national parks
in the West and to assure the attainment
and maintenance of the health-related
ambient air quality standards. Finally,
they note that the NSPS is technology-
based and not directly related to
protection of the Nation's public health.
In addition, they argue that a variable
control option would provide a better
opportunity for the development of
innovative technologies. Several
commenters noted that, in particular, a
uniform requirement would not provide
an opportunity for the development of
dry SOa control systems which they felt
held considerable promise for bringing
about SOt emission reductions at lower
costs and in a more reliable manner.
Commenters favoring variable control
also advanced the arguments that a
standard based on a range of percent
reductions would provide needed
flexibility, particularly when selecting
intermediate sulfur content coals.
Further, if a control system failed to
meet design expectations, a variable
approach would allow a source to move
to lower-sulfur coal to achieve
compliance. In addition, for low-sulfur
coal applications, a variable option
would substantially reduce the energy
penalty of operating wet scrubbers since
a portion of the flue gas could be used
for plume reheat.
To support their advocacy of a
variable approach, two commenters, the
Department of Energy and the Utility Air
Regulatory Group (UARG, representing
a number of utilities), presented detailtd
results of analyses that had been
conducted for them. UARG analyzed a
standard that required a minimum
reduction of 20 percent with 520 ng/J
(1.20 Ib/million Btu) monthly emission
limit. The Department of Energy
specified a partial control option that
required a 33 percent minimum
requirement with a 430 ng/J (1.0 lb/
million Btu) monthly emission limit.
Faced with these comments, the
Administrator determined the final
analyses that should be performed, He
concluded that analyses should be
conducted on a range of alternative
emission limits and percent reduction
requirements in order to determine the
approach which best satisfies the
statutory language and legislative
history of section 111. For these
analyses, the Administrator specified a
uniform or full control option, a partial
control option reflecting the Department
of Energy's recommendation for a 33
percent minimum control requirement,
and a variable control option which
specified a 520 ng/J (1.20 Ib/million Btu)
emission limitation with a 90 percent
reduction in potential SO2 emissions
except when emissions to the
atmosphere were reduced below 280 ng/
J (0.60 Ib/million Btu), when only a 70
percent reduction in potential SOZ
emissions would apply. Under the
variable approach, plants firing high-
sulfur coals would be required to
achieve a 90 percent reduction in
potential emissions in order to comply
with the emission limitation. Those using
intermediate and low-sulfur content
coals would be permitted to achieve
between 70 and 90 percent, provided
their emissions were less than 260 ng/J
(0.60 Ib/million BTU).
In rejecting the minimum requirement
of 20 percent advocated by .UARG, the
Administrator found that it not only
resulted in the highest emissions, but
that it was also the least cost effective
of the variable control options
considered. The more stringent full
control option presented in the
comments was rejected because it
required a 95 percent reduction in
potential emissions which may not be
within the capabilities of demonstrated
technology for high-sulfur coals in all
cases.
Emergency Conditions
The final standards allow an owner or
operator to bypass uncontrolled flue
gases around a malfunctioning FGD
system provided (1) the FGD system has
been constructed with a spare FGD
module, (2) FGD modules are not
available in sufficent numbers to treat
the entire quantity of flue gas generated,
and (3) all available electric generating
capacity is being utilized in a power
pool or network consisting of the
generating capacity of the affected
utility company (except for the capacity
of the largest single generating unit in
the company), and the amount of power
that could be purchased from
neighboring interconnected utility
companies. The final standards are
essentially the same as those proposed.
The revisions involve wording changes
to clarify the Administrator's intent and
revisions to address potential load
management and operating problems.
None of the comments received by EPA
disputed the need for the emergency
condition provisions or objected to their
intent
The intent of the final standards is to
encourage power plant owners and
operators to install the best available
FGD systems and to implement effective
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operation and maintenance procedures
but not to create power supply
disruptions. FGD systems with spare
FGD modules and FGD modules with
spare equipment components have
greater capability of reliable operation
than systems without spares. Effective
control and operation of FGD systems
by engineering supervisory personnel
experienced in chemical process
operations and properly trained FGD
system operators and maintenance staff
are also important in attaining reliable
FGD system operation. While the
standards do not require these
equipment and staffing features, the
Administrator believes that their use
will make compliance with the
standards easier. Malfunctioning FGD
systems are not exempt from the SO»
standards except during infrequent
power supply emergency periods. Since
the exemption does not apply unless a
spare module has been installed (and
operated), a spare module is required for
the exemption to apply. Because of the
disproportionate cost of installing a
spare module on steam generators
having a generating capacity of 125 MW
or less, the standards do not require
them to have-spare modules before the
emergency conditions exemption
applies.
The proposed standards included the
requirement that the emergency
condition exemption apply only to those
facilities which have installed a spare
FGD system module or which have 125
MW or less of output capacity.
However, they did not contain
procedures for demonstrating spare
module capability. This capability can
be easily determined once the facility
commences operation. To specify how
this determination is to be performed,
provisions have been added to the
regulations. This determination is not
required unless the owner or operator of
the affected facility wishes to claim
spare module capability for the purpose
of availing himself of the emergency
condition exemption. Should the
Administrator require a demonstration
of spare module capability, the owner or
operator would schedule a test within 60
days for any period of operation lasting
from 24 hours to 30 days to demonstrate
that he can attain the appropriate SOj
emission control requirements when the
facility is operated at a maximum rate
without using one of its FGD system
modules. The test can start at any time
of day and modules may be rotated in
and out of service, but at all times in the
test period one module (but not
necessarily the same module) must not
be operated to demonstrate spare
module capability.
Although it is within the
Administrator's discretion to require the
spare module capability demonstration
test, the owner or operator of the facility
has the option to schedule the specific
date and duration of the test. A
minimum of only 24 hours of operation
are required during the test period
because this period of time is adequate
to demonstrate spare module capability
and it may be unreasonable in all
circumstances to require a longer (e.g.,
30 days) period of operation at the
facility's maximum heat input rate.
Because the owner or operator has the
flexibility to schedule the test, 24 hours
of operation at maximum rate will not
impose a significant burden on the
facility
The Administrator believes that the
standards will not cause supply
disruption because (1) well designed
and operated FGD systems can attain
high operating availability, (2) a spare
FGD module can be used to rotate other
modules out of service for periodic
maintenance or to replace a
malfunctioning module, (3) load shifting
of electric generation to another
generating unit can normally be used if a
part or all of the FGD system were to
malfunction, and (4) during abnormal
power supply emergency periods, the
bypassing exemption ensures that the
regulations would not require a unit to
stand idle if its operation were needed
to protect the reliability of electric
service. The Administrator believes that
this exemption will not result in
extensive bypassing because the
probability of a major FGD malfunction
and power supply emergency occurring
simultaneously is small.
A commenter asked that the definition
of system capacity be revised to ensure
that the plant's capability rather than
plant rated capacity be used because
the full rated capacity is not always
operable. The Administrator agrees with
this comment because a component
failure (e.g., the failure of one coal
pulverizer) could prevent a boiler from
being operated at its rated capacity, but
would not cause the unit to be entirely
shut down. The definition has been
revised to allow use of the plant's
capability when determining the net
system capacity.
One commenter asked that the
definition of system capacity be revised
to include firm contractual purchases
and to exclude firm contractual sales.
Because power obtained through
contractual purchases helps to satisfy
load demand and power sold under
contract affects the net electric
generating capacity available in the
system, the Administrator agrees with
this request and has included power
purchases in the definition of net system
capacity and has excluded sales by
adding them to the definition of system
load.
A commenter asked that the
ownership basis for proration of electric
capacity in several definitions be
modified when there are other
contractual arrangements. The
Administrator agrees with this comment
and has revised the definitions
accordingly.
One commenter asked that definitions
describing "all electric generating
equipment owned by the utility
company" specifically include
hydroelectric plants. The proposed
definitions did include these plants, but
the Administrator agrees with the
clarification requested, and the
definitions have been revised.
A commenter asked that the word
"steam" be removed from the definition
of system emergency reserves to clarify
that nuclear units are included. The
Administrator agrees with the comment
and has revised the definition.
Several commenters asked that some
type of modification be made to the
emergency condition provisions that
would consider projected system load
increases within the next calendar day.
One commenter asked that emergency
conditions apply based on a projection
of the next day's load. The
Administrator does not agree with the
suggestion of using a projected load,
which may or may not materialize, as a
criterion to allow bypassing of SO2
emissions, because the load on a
generating unit with a malfunctioning
FGD system should be reduced
whenever there is other available
system capacity.
A commenter recommended that a
unit removed from service be allowed to
return to service if such action were
necessary to maintain or reestablish
system emergency reserves. The
Administrator agrees that it would be
impractical to take a large steam
generating unit entirely out of service
whenever load demand is expected to
later increase to the level where there
would be no other unit available to meet
the demand or to maintain system
emergency reserves. To address the
problem of reducing load and later
returning the load to the unit, the
Administrator has revised the proposed
emergency condition provisions to give
an owner or operator of a unit with a
malfunctioning FGD system the option
of keeping (or bringing) the unit into
spinning reserve when the unit is
needed to maintain (or reestablish)
system emergency reserves. During this
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period, emissions must be controlled to
the extent that capability exists within
the FGD system, but bypassing
emissions would be allowed when the
capability of a partially or completely
failed FGD system is inadequate. This
procedure will allow the unit to operate
in spinning reserve rather than being
entirely shut down and will ensure that
a unit can be quickly restored to service.
The final emergency condition
provisions permit bypassing of
emissions from a unit kept in spinning
reserve, but only (1) when the unit is the
last one available for maintaining
system emergency reserves, (2) when it
is operated at the minimum load
consistent with keeping the unit in
spinning reserve, and (3) has inadequate
operational FGD capability at the
minimum load to completely control SO2
emissions. This revision will still
normally require load on a
malfunctioning unit to be reduced to a
minimum level, even if load demand is
anticipated to increase later; but it does
prevent having to take the unit entirely
out of operation and keep it available in
spinning reserve to assume load should
an emergency arise or as load increases
the following day. Because emergency
condition periods are a small percentage
of total operating hours, this revision to
allow bypassing of SO, emissions from a
unit held in spinning reserve with
reduced output is expected to have
minor impact on the amount of SO2
emitted.
One commenter stated that the
proposed provisions would not reduce
the necessity for additional plant
capacity to compensate for lower net
reliability. The Administrator does not
agree with this comment because the
emergency condition provisions allow
operation of a unit with a failed FGD
system whenever no other generating
capacity is available for operation and
thereby protects the reliability of
electric service. When electric load is
shifted from a new steam-electric
generating unit to another electric
generating unit, there would be no net
change in reserves within the power
system. Thus, the emergency condition
provisions prevent a failed FGD system
from impacting upon the utility
company's ability to generate electric
power and prevents an impact upon
reserves needed by the power system to
maintain reliable electric service.
A commenter asked that the definition
of available system capacity be clarified
because (1) some utilities have certain
localized areas or zones that, because of
system operating parameters, cannot be
served by all of the electric generating
units which constitute the utility's
system capacity, and (2) an affected
facility may be the only source of supply
for a zone or area. Almost all electric
utility generating units in the United
States are electrically interconnected
through power transmission lines and
switching stations. A few isolated units
in the U.S. are not interconnected to at
least one other electric generating unit
and it is possible that a new unit could
also be constructed in an isolated area
where interconnections would not be
practical. For a single, isolated unit
where it is not practical to construct
interconnections, the emergency
condition provisions would apply
whenever an FGD malfunction occurred
because there would be no other
available system capacity to which load
could be shifted. It is also possible that
two or three units could be
interconnected, but not interconnected
with a larger power network (e.g.,
Alaska and Hawaii). To clarify this
situation, the definitions of net system
capacity, system load, and system
emergency reserves have been revised
to include only that electric power or
capacity interconnected by a network of
power transmission facilities. Few units
will not be interconnected into a
network encompassing the principal and
neighboring utility companies. Power
plants, including those without FGD
systems, are expected to experience
electric generating malfunctions and
power systems are planned with reserve
generating capacity and interconnecting
electric transmission lines to provide
means of obtaining electricity from
alternative generating facilities to meet
demand when these occasions arise.
Arrangements for an affected facility
would typically include an
interconnection to a power transmission
network even when it is geographically
located away from the bulk of the utility
company's power system to allow
purchase of power from a neighboring
utility for those localized service areas
when necessary to maintain service
reliability. Contract arrangements can
provide for trades of power in which a
localized zone served by the principal
company owning or operating the
affected facility is supplied by a
neighboring company. The power bought
by the principal company can, if desired
by the neighboring company, be
replaced by operation of other available
units in the principal company even if
these units are located at a distance
from the localized service zone. The
proposed definition of emergency
condition was contingent upon the
purchase of power from another
electrical generation facility. To further
clarify this relationship, the
Administrator has revised the proposed
definitions to define the relationship
between the principal company (the
utility company that owns the
generating unit with the malfunctioning
FGD system) and the neighboring power
companies for the purpose of
determining when emergency conditions
exist.
A commenter requested that the
proposed compliance provisions be
revised so that they could not be
interpreted to force a utility to operate a
partially functional FGD module when
extensive damage to the FGD module
would occur. For example, a severely
vibrating fan must be shut down to
prevent damage even though the FGD
system may be otherwise functional.
The Administrator agrees with this
comment and has revised the
compliance provisions not to require
FGD operation when significant damage
to equipment would result.
One commenter asked that the
definition of system emergency reserves
account for not only the capacity of the
single largest generating unit, but also
for reserves needed for system load-
frequency regulation. Regulation of
power frequency can be a problem when
the mix of capacitive and reactive loads
shift. For example, at night capacitive
load of industrial plants can adversely
affect power factors. The Administrator
disagrees that additional capacity
should be kept independent of the load
shifting requirements. Under the
definition for system emergency
reserves, capacity equivalent to the
largest single unit in the system was set
aside for load management. If frequency
regulation has been a particular
problem, extra reserve margins would
have been maintained by the utility
company even if an FGD system were
not installed. Reserve capacity need not
be maintained within a single generating
unit. The utility company can regulate
system load-frequency by distributing
their system reserves throughout the
electric power system as needed. In the
Administrator's judgment, these
regulations do not impact upon the
reserves maintained by the utility
company for the purpose of maintaining
power system integrity, because the
emergency condition provisions do not
restrict the utility company's freedom in
distributing their reserves and do not
require construction of additional
reserves.
A commenter asked that utility
operators be given the option to ignore
the loss of SO2 removal efficiency due to
FGD malfunctions by reducing the level
of electric generation from an affected
unit. This would control the amount of
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SOi emitted on.a pounds per hour basis,
but would also allow and exemption
from the percentage of Sd removal
specified by the SOi standards. The
Administrator believes that allowing
this exemption is not necessary because
load can usually be shifted to other
electric generating units. This procedure
provides an incentive to the owner or
operator to properly maintain and
operate FGD systems. Under the
procedures suggested by the coTnmenter,
neglect of the FGD system would be
encouraged because an exemption
would allow routine operation at
reduced percentages of SO, removal.
Steam generating units are often
operated at less than rated capacity and
a fully operational FGD system would
not be required for compliance during
these periods if this exemption were
allowed. The procedure suggested by
the commenter is also not necessary
because FGD modules can be designed
and constructed with separate
equipment components so that they are
routinely capable of independent
operation whenever another module of
the steam generating unit's FGD system
is not available. Thus, reducing the level
of electric generation and removing the
failed FGD module for servicing would
not affect the remainder of the FGD
system and would permit the utility to
maintain compliance with the standards
without having to take the generating
unit entirely out of operation. Each
module should have the capability of
attaining the same percentage reduction
of Sd from the flue gas it treats
regardless of the operability of the other
modules in the system to maintain
compliance with the standards.
Although the efficiency of more than one
FGD module may occasionally be
affected by certain equipment
malfunctions, a properly designed FGD
system has no routine need for an
exemption from the SO, percentage
reduction requirement when the unit is
operated at reduced load. The
Administrator has concluded that the
final regulations provide sufficient
flexibility for addressing FGD
malfunctions and that an exemption
from the percentage SOj removal
requirement is not necessary to protect
electric service reliability or to maintain
compliance with these SO2 standards.
Particulate Matter Standard
The final standard limits particulate
matter emissions to 13 ng/J (0.03 lb/
million Btu) heat input and is based on
the application of ESP or baghouse
control technology. The final standard is
the same as the proposed. The
Administrator has concluded that ESP
and baghouse control systems are the
best demonstrated systems of
continuous emission reduction (taking
into consideration the cost of achieving
such emission reduction, and nonair
quality health and enviornmental
impacts, and energy requirements) and
that 13 ng/J (0.03 Ib/million Btu} heat
input represents the emission level
achievable through the application of
these control systems.
One group of commenters indicated
that they did not support the proposed
standard because in their opinion it
would be too expensive for the benefits
obtained; and they suggested that the
final standard limit emissions to 43 ng/J
(0.10 Ib/million Btu) heat input which is
the same as the current standard under
40 CFR Part 60 Subpart D. The
Administrator disagrees with the
commenters because the available data
clearly indicate that ESP and baghouse
control systems are capable of
performing at the 13 ng/J (0.03 Ib/million
Btu) heat input emission level, and the
economic impact evaluation indicates
that the costs and economic impacts of
installing these systems are reasonable.
The number of commenters expressed
the opinion that the proposed standard
was to strict, particularly for power
plants firing low-sulfur coal, because
baghouse control systems have not been
adequately demonstrated on full-size
power plants. The commenters
suggested that extrapolation of test data
from small scale baghhouse control
systems, such as those used to support
the proposed standard, to full-size utility
applications is not reasonable.
The Administrator believes that
baghouse control systems are
demonstrated for all sizes of power
plants. At the time the standards were
proposed, the Administrator concluded
that since baghouses are designed and
constructed in modules rather than as
one large unit, there should be no
technological barriers to designing and
constructing utility-sized facilities. The
largest baghouse-controlled, coal-fired
power plant for which EPA had
emission test data to support the
proposed standard was 44 MW. Since
the standards were proposed, additional
information has become available which
supports the Administrator's position
that baghouses are demonstrated for all
sizes of power plants. Two large
baghouse-controlled, coal-fired power
plants have recently initiated
operations. EPA has obtained emission
data for one of these units. This unit has
achieved particulate matter emission
levels below 13 ng/J (0.03 Ib/million BtuJ
heat input. The baghouse system for this
facility has 28 modules rated at 12.5 MW
capacity per module. This supports the
Administrator's conclusion that
baghouses are designed and constructed
in modules rather than as one large unit,
and there should be no technological
barriers to designing and constructing
utility-sized facilities.
One commenter indicated that
baghouse control systems are not
demonstrated for large utility
application at this time and
recommended that EPA gather one year
of data from 1000 MW of baghouse
installations to demonstrate that
baghouses can operate reliably and
achieve 13 ng/J (0.03 Ib/million Btu) heat
input. The standard would remain at 21
to 34 ng/J (0.05 to 0.08 Ib/million Btu)
heat input until such demonstration. The
Administrator does not believe this
approach is necessary because
baghouse control systems have been
adequately demonstrated for large
utility applications.
One group of commenters supported
the proposed standard of 13 ng/J (0.03
Ib/million Btu) heat input. They
indicated that in their opinion the
proposed standard attained the proper
balance of cost, energy and
environmental factors and was
necessary in consideration of expected
growth in coal-fired power plant
capacity.
Another group of commenters which
included the trade association of
emission control system manufacturers
indicated that 13 ng/J (0.03 Ib/million
Btu) is technically achievable. The trade
association further indicated the
proposed standard is technically
achievable for either high- or low-sulfur
coals, through the use of baghouses,
ESPs, or wet scrubbers.
A number of commenters
recommended that the proposed
standard be lowered to 4 ng/J (0.01 lb/
million Btu) heat input. This group of
commenters presented additional
emission data for utility baghouse
control systems to support their
recommendation. The data submitted by
the commenters were not available at
the time of proposal and were for utility
units of less than 100 MW electrical
output capacity. The commenters
suggested that a 4 ng/J (o.Ol Ib/million
Btu) heat input standard is achievable
based on baghouse technology, and they
suggested that a standard based on
baghouse technology would be
consistent with the technology-forcing
nature of section 111 of the Act. The
Administrator believes that the
available data base for baghouse
performance supports a standard of 13
ng/J (0.03 Ib/million Btu) heat input but
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does not support a lower standard such
as 4 ng/J (0.01 Ib/million Btu) heat input.
One commenter suggested that the
standard should be set at 26 ng/J (0.06
Ib/million Btu) heat imput so that
particulate matter control systems
would not be necessary for oil-fired
utility steam generators. Although it is
expected that few oil-fired utility boilers
will be constructed, the ESP
performance data which is contained in
the "Electric Utility Steam Generating
Units, Background Information for
Promulgated Emission Standards" (EPA
450/3-79-021), supports the conclusion
that ESPs are applicable to both oil
firing and coal firing. The Administrator
believes that emissions from oil-fired
utility boilers should be controlled to the
same level as coal-fired boilers.
Mi Standard
The NO, standards limit emissions to
210 ng/J (0.50 Ib/million Btu) heat input
from the combustion of subbituminous
coal and 260 ng/J (0.60 Ib/million BtuJ
heat imput from the combustion of
bituminous coal, based on a 30-day
rolling average. In addition, emission
limits have been established for other
solid, liquid, and gaseous fuels, as
discussed in the rational section of this
preamble. The final standards differ
from the proposed standards only in
that the final averaging time for
determining compliance with the
standards is based on a 30-day rolling
average, whereas a 24-hour average was
proposed. All comments received during
the public commenl period were
considered in developing the final NO,
standards. The major issues raised
during the comment period are
discussed below.
One issue concerned the possibility
that the proposed 24-hour averaging
period for coal might seriously restrict
the flexibility boiler operators need
during day-to-day operation. For
example, several commenters noted that
on some boilers the control of boiler
tube slagging may periodically require
increased excess air levels, which, in
turn, would increase NO, emissions.
One commenter submitted data
indicating that two modern Combustion
Engineering (CE) boilers at the Colstrip,
Montana plant of the Montana Power
Company do not consistently achieve
the proposed NO, level of 210 ng/J (0.50
Ib/million Btu) heat input on a 24-hour
basis. The Colstrip boilers burn
subbituminous coal and are required to
comply with the.NO, standard under 40
CFR Part 60, Subpart D of 300 ng/J (0.70
Ib/million Btu) heat input. Several other
commenters recommended that the 24-
hour averaging period be extended to 30
days to allow for greater operational
flexibility.
As an aid in evaluating the
operational flexibility question, the
Administrator has reviewed a total of 24
months of continuously monitored NO,
data from the two Colstrip boilers. Six
months of these data were available to
the Administrator before proposal of
these standards, and two months were
submitted by a commenter. The
commenter also submitted a summary of
28 months of Colstrip data indicating the
number of 24-hour averages per month
above 210 ng/J (0.50 Ib/million Btu) heat
input The remaining Colstrip data were
obtained by the Administrator from the
State of Montana after proposal. In
addition to the Colstrip data, the
Administrator has reviewed
approximately 10 months of
continuously monitored NO, data from
five modern CE utility boilers. Three of
the boilers burn subbituminous coal,
two burn bituminous coal, and all five
have monitors that have passed
certification tests. These data were
obtained from electric utility companies
after proposal. A summary of all of the
continuously monitored NO, data that
the Administrator has considered
appears in "Electric Utility Steam
Generating Units, Background
Information for Promulgated Emission
Standards" (EPA 450/3-79-021).
The usefulness of these continuously
monitored data in evaluating the ability
of modern utility boilers to continuously
achieve the NO, emission limits of 210
and 260 ng/J (0.50 and 0.60 Ib/million
Btu) heat input is somewhat limited.
This is because the boilers were
required to comply with a higher NO,
level of 300 ng/J (0.70 Ib/million Btu)
heat input. Nevertheless some
conclusions can be drawn, as follows:
(1) Nearly all of the continuously
monitored NO, data are in compliance
with the boiler design limit of 300 ng/J
(0.70 Ib/million Btu) heat input on the
basis of a 24-hour average.
(2) Most of the continuously
monitored NO, data would be in
compliance with limits of 260 ng/J (0.60
Ib/million Btu) heat input for bituminous
coal ov 210 ng/J (0.50 Ib/million Btu)
heat input for subbituminous coal when
averaged over a 30-day period. Some of
the data would be out of compliance
based on a 24-hour average.
(3) The volume of continuously
monitored NO, emission data evaluated
by the Administrator (34 months from
seven large coal-fired boilers) is
sufficient to indicate the emission
variability expected during day-to-day
operation of a utility-size boiler. In the
Administrator's judgment, this emission
variability adequately represents
slagging conditions, coal variability,
load changes, and other factors that may
influence the level of NO, emissions.
(4) The variability of continuously
monitored NO, data is sufficient to
cause some concern over the ability of a
utility boiler that burns solid fuel to
consistently iachievp a NO, boiler design
limit, whether 300, 260, or 210 ng/J (0.70,
0.60, or 0.50 Ib/million Btu) heat input,
based on 24-hour averages. In contrast,
it appears that there would be no
difficulty in achieving the boiler design
limit based on 30-day periods.
Based on these conclusions, the
Administrator has decided to require
compliance with the final standards for
solid fuels to be based on a 30-day
rolling average. The Administrator
believes that the 30-day rolling average
will allow boilers made by all four major
boiler manufacturers to achieve the
standards while giving boiler operators
the flexibility needed to handle
conditions encountered during normal
operation.
Although the Administrator has not
evaluated continuously monitored NO,
data from boilers manufactured by
companies other than CE, the data from
CE boilers are considered representative
of the other boiler manufacturers. This is
because the boilers of all four
manufacturers are capable of achieving
the same NO,[ design limit, and because
the conditions that occur during normal
operation of a boiler (e.g., slagging,
variations in fuel quality, and load
reductions) are similar for all four
manufacturer designs. These conditions,
the Administrator believes, lead to
similar emission variability and require
essentially the same degree of
operational flexibility.
Some commenters have question the
validity of the Colstrip data because the
Colstrip continuous NO, monitors have
not passed certification tests. In April
and June of 1978 EPA conducted a
detailed evaluation of these monitors.
The evaluation led the Administrator to
conclude that the monitors were
probably biased high, but by less than
21 ng/J (0.50 Ib/million Btu) heat input.
Since this error is so small (less than 10
percent), the Administrator considers
the data appropriate to use in
developing the standards.
A number of commenters expressed
concern over the ability of as many as
three of the four major boiler
manufacturer designs to achieve the
proposed standards. Although most of
the available NO, test data are from CE
boilers, the Administrator believes that
all four of the boiler manufacturers will
be able to supply boilers capable of
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achieving the standards. This conclusion
is supported with (1) emission test
results from 14 CE, seven Babcock and
Wilcox (B&W), three Foster Wheeler
(FW), and four Riley Stoker (RS) utility
boilers; (2) 34 months of continuously
monitored NO, emission data from
seven CE boilers; and (3) an evaluation
of plans under way at B&W, FW, and RS
to develop low-emission burners and
furnace designs. Full-scale tests of these
burners and furnace designs have
proven their effectiveness in reducing
NO, emissions without apparent long-
term adverse side effects.
Another issue raised by commenters
concerned the effect that variations in
the nitrogen content of coal may have on
achieving the NO, standards. The
Adminstrator recognizes that NO, levels
are sensitive to the nitrogen content of
the coal burned and that the combustion
of high-nitrogen-content coals might be
expected to result in higher NO,
emissions than those from coals with
low nitrogen contents. However, the
Administrator also recognizes that other
factors contribute to NO, levels,
including moisture in the coal, boiler
design, and boiler operating practice. In
the Administrator's judgment, the
emission limits for NO, are achievable
with properly designed and operated
boilers burning any coal, regardless of
its nitrogen content. As evidence of this,
three of the six boilers tested by EPA
burned coals with nitrogen contents
above average, and yet exhibited NO,
emission levels well below the
standards. The three boilers that burned
coals with lower nitrogen contents also
exhibited emission levels below the
standards. The Administrator believes
this is evidence that at NO, levels near
210 and 260 ng/J (0.50 and 0.60 lb/
million Btu) heat input, factors other
than fuel-nitrogen-content predominate
in determining final emission levels.
A number of commenters expressed
concern over the potential for
accelerated tube wastage (i.e.,
corrosion) during operation of a boiler in
compliance with the proposed
standards. Almost all of the 300-hour
and 30-day coupon corrosion tests
conducted during the EPA-sponsored
low-NO, studies indicate that corrosion
rates decrease or remain stable during
operation of boilers at NO, levels as low
as those required by the standards. In
the few instances where corrosion rates
increased during low-NO, operation, the
increases were considered minor. Also,
CE has guaranteed that its new boilers
will achieve the NO, emission limits
without increased tube corrosion rates.
Another boiler manufacturer, B&W, has
developed new low-emission burners
that minimize corrosion by surrounding
the flame in an oxygen-rich atmosphere.
The other boiler manufacturers have
also developed techniques to reduce the
potential for corrosion during low-NO,
operation. The Administrator has
received no contrasting information to
the effect that boiler tube corrosion
rates would significantly increase as a
result of compliance with the standards.
Several commenters stated that
according to a survey of utility boilers
subject to the 300 ng/J (0.70 Ib/million
Btu) heat input standard under 40 CFR
Part 60, Subpart D, none of the boilers
can achieve the standard promulgated
here of 200 ng/J (0.60 Ib/million Btu)
heat input on a range of bituminous
coals. Three of the-six utility boilers
tested by EPA burned bituminous coal.
(Two of these boilers were
manufactured by CE and one by B&W.J
In addition, the Administrator has
reviewed continuously monitored NO,
data from two CE boilers that burn
bituminous coal. Finally, the
Administrator has examined NO,
emission data obtained by the boiler
manufacturers on seven CE, four B&W,
three FW, 'and three RS modern boilers,
all of which burn bituminous coal.
Nearly all of these data are below the
260 ng/J (0.60 Ib/million Btu) heat input
standard. The Administrator believes
that these data provide adequate
evidence that the final NO, standard for
bituminous coal is achievable by all four
boiler manufacturer designs.
An issue raised by several
commenters concerned the use of
catalytic ammonia injection and
advanced low-emission burners to
achieve NO, emission levels as low as
15 ng/J (0.034 Ib/million Btu) heat input.
Since these controls are not yet
available, the commenters
recommended that new utility boilers be
designed with sufficient space to allow
for the installation of ammonia injection
and advanced burners in the future. In
the meantime the commenters
recommended that NO, emissions be
limited to 190 ng/J (0.45 Ib/million Btu)
heat input. The Administrator believes
that the technology needed to achieve
NO, levels as low as 15 ng/J (0.034 lb/
million Btu) heat input has not been
adequately demonstrated at this time.
Although a pilot-scale catalytic-
ammonia-injection system has
successfully achieved 90 percent NO,
removal at a coal-fired utiliiy power
plant in Japan, operation of a full-scale
ammonia-injection system has not yet
been demonstrated on a large coal-fired
boiler. Since the Clean Air Act requires
that emission control technology for new
source performance standards be
adequately demonstrated, the
Administrator cannot justify
establishing a low NO, standard based
on unproven technology. Similarly, the
Administrator cannot justify requiring
boiler designs to provide for possible
future installation of unproven
technology.
The recommendation that NO,
emissions be limited to 190 ng/J (0.45 lb/
million Btu) heat input is based on boiler
manufacturer guarantees jn California.
(No such utility boilers have been built
as yet.) Although manufacturer
guarantees are appropriate to consider
when establishing emission limits, they
cannot always be used as a basis for a
standard. As several commenters have
noted, manufacturers do not always
achieve their performance guarantees.
The standard is not established at this
level, because emission test data are not
available which demonstrate that a
level of 190 ng/J (0.45 Ib/million Btu)
heat input can be continuously achieved
without adverse side effects when a
wide variety of coals are burned.
Regulatory Analysis
Executive Order 12044 (March 24,
1978), whose objective is to improve
Government regulations, requires
executive branch agencies to prepare
regulatory analyses for regulations that
may have major economic
consequences. EPA has extensively
analyzed the costs and other impacts of
these regulations. These analyses, whicn
meet the criteria for preparation of a
regulatory analysis, are contained
within the preamble to the proposed
regulations (43 FR 42154), the
background documentation made
available to the public at the time of
proposal (see STUDIES, 43 FR 42171),
this preamble, and the additional
background information document
accompanying this action ("Electric
Utility Steam Generating Units,
Background Information for
Promulgated Emission Standards," EPA-
450/3-79-021). Due to the volume of this
material and its continual development
over a period of 2-3 years, it is not
practical to consolidate all analyses into
a single document. The following
discussion gives a summary of the most
significant alternatives considered. The
rationale for the action taken for each
pollutant being regulated is given in a
previous section.
In order to determine the appropriate
form and level of control for the
standards, EPA has performed extensive
analysis of the potential national
impacts associated with the alternative
standards. EPA employed economic
models to forecast the structure and
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operating characteristics of the utility
industry in future years. These models
project the environmental, economic,
and energy impacts of alternative
standards for the electric utility
industry. The major analytical efforts
took place in three phases as described
below.
Phase 1. The initial effort comprised a
preliminary analysis completed in April
1978 and a revised assessment
completed in August 1978. These
analyses were presented in the
September 19,1978 Federal Register
proposal (43 FR 42154). Corrections to
the September proposal package and
additional information was published on
November 27,1978 (43 FR 55258).
Further details of the analyses can be
found in "Background Information for
Proposed SOt Emission Standards
Supplement," EPA 450/2-78-007a-l.
Phase 2. Following the September 19
proposal, the EPA staff conducted
additional analysis of the economic,
environmental, and energy impacts
associated with various alternative
sulfur dioxide standards. As part of this
effort, the EPA staff met with
representatives of the Department of
Energy, Council of Economic Advisors,
Council on Wage and Price Stability,
and others for the purpose of
reexamining the assumptions used for
the August analysis and to develop
alternative forms of the standard for
analysis. As a result, certain
assumptions were changed and a
number of new regulatory alternatives
were defined. The EPA staff again
employed the economic model that was
used in August to project the national
and regional impacts associated with
each alternative considered.
The results of the phase 2 analysis
were presented and discussed at the
public hearings in December and were
published in the Federal Register on
December 8,1978 (43 FR 7834).
Phase 3. Following the public
hearings, the EPA staff continued to
analyze the impacts of alternative sulfur
dioxide standards. There were two
primary reasons for the continuing
analysis. First, the detailed analysis
(separate from the economic modeling)
of regional coal production impacts
pointed to a need to investigate a range
of higher emission limits.
Secondly, several comments were
received from the public regarding the
potential of dry sulfur dioxide scrubbing
systems. The phase 1 and phase 2
analyses had assumed that utilities
would use wet scrubbers only. Since dry
scrubbing costs substantially less then
wet scrubbing, adoption of the dry
technology would substantially change
the economic, energy, and
environmental impacts of alternative
sulfur dioxide standards. Hence, the
phase 3 analysis focused on the impacts
of alternative standards under a range
of emission ceilings assuming both wet
technology and the adoption of dry
scrubbing for applications in which it is
technically and economically feasible.
Impacts Analyzed
The environmental impacts of the
alternative standards were examined by
projecting pollutant emissions. The
emissions were estimated nationally
and by geographic region for each plant
type, fuel type, and age category. The
EPA staff also evaluated the waste
products that would be generated under
alternative standards.
The economic and financial effects of
the alternatives were examined. This
assessment included an estimation of
the utility capital expenditures for new
plant and pollution control equipment as
well as the fuel costs and operating and
maintenance expenses associated with
the plant and equipment. These costs
were examined in terms of annualized
costs and annual revenue requirements.
The impact on consumers was
determined by analyzing the effect of
the alternatives on average consumer
costs and residential electric bills. The
alternatives were also examined in
terms of cost per ton of SO» removal.
Finally, the present value costs of the
alternatives were calculated.
The effects of the alternative
proposals on energy production and
consumption were also analyzed.
National coal use was projected and
broken down in terms of production and
consumption by geographic region. The
amount of western coal shipped to the
Midwest and East was also estimated.
In addition, utility consumption of oil
and natural gas was analyzed.
Major Assumptions
Two types of assumptions have an
important effect on the results of the
analyses. The first group involves the
model structure and characteristics. The
second group includes the assumptions
used to specify future economic
conditions.
The utility model selected for this
analysis can be characterized as a cost
minimizing economic model. In meeting
demand, it determines the most
economic mix of plant capacity and
electric generation for the utility system,
based on a consideration of construction
and operating costs for new plants and
variable costs for existing plants. It also
determines the optimum operating level
for new and existing plants. This
economic-based decision criteria should
be kept in mind when analyzing the
model results. These criteria imply, for
example, that all utilities base decisions
on lowest costs and that neutral risk is
associated with alternative choices.
Such assumptions may not represent
the utility decision making process in all
cases. For example, the model assumes
that a utility bases supply decisions on
the cost of constructing and operating
new capacity versus the cost of
operating existing capacity.
Environmentally, this implies a tradeoff
between emissions from new and old
sources. The cost minimization
assumption implies that in meeting the
standard a new power plant will fully
scrub high-sulfur coal if this option is
cheaper than fully or partially scrubbing
low-sulfur coal. Often the model will
have to make such a decision, especially
in the Midwest where utilities can
choose between burning local high-
sulfur or imported western low-sulfur
coal. The assumption of risk neutrality
implies that a utility will always choose
the low-cost option. Utilities, however,
may perceive full scrubbing as involving
more risks and pay a premium to be able
to partially scrub the coal. On the other
hand, they may perceive risks
associated with long-range
transportation of coal, and thus opt for
full control even though partial control
is less costly.
The assumptions used in the analyses
to represent economic conditions in a
given year have a significant impact on
the final results reached. The major
assumptions uaed in the analyses are
shown in Table 1 and the significance of
these parameters is summarized below.
The growth rate in demand for electric
power is very important since this rate
determines the amount of new capacity
which will be needed and thus directly
affects the emission estimates and the
projections of pollution control costs. A
high electric demand growth rate results
in a larger emission reduction
associated with the proposed standards
and also results in higher costs.
The nuclear capacity assumed to be
installed in a given year is also.
important to the analysis. Because
nuclear power is less expensive, the
model will predict construction of new
nuclear plants rather than new coal
plants. Hence, the nuclear capacity
assumption affects the amount of new
coal capacity which will be required to
meet a given electric demand level. In
practice, there are a number of
constraints which limit the amount of
nuclear capacity which can be
constructed, but for this study, nuclear
capacity was specified approximately
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equal to the mpderate growth
projections of the Department of Energy.
The oil price assumption has a major
impact on the amount of predicted new
coal capacity, emissions, and oil
consumption. Since the model makes
generation decisions based on cost, a
low oil price relative to the cost of
building and operating a new coal plant
will result in more oil-fired generation
and less coal utilization. This results in
less new coal capacity which reduces
capital costs but increases oil
consumption and fuel costs because oil
is more expensive per Btu than coal.
This shift in capacity utilization also
affects emissions, since an existing oil
plant generally has a higher emission
rate than a new coal plant even when
only partial control is allowed on the
new plant.
Coal transportation and mine labor
rates both affect the delivered price of
coal. The assumed transportation rate is
generally more important to the
predicted consumption of low-sulfur
coal (relative to high-sulfur coal), since
that is the coal type which is most often
shipped long distances. The assumed
mining labor cost is more important to
eastern coal costs and production
estimates since this coal production is
generally much more labor intensive
than western coal.
Because of the uncertainty involved in
predicting future economic conditions,
the Administrator anticipated a large
number of comments from the public
regarding the modeling assumptions.
While the Administrator would have
liked to analyze each scenario under a
range of assumptions for each critical
parameter, the number of modeling
inputs made such an approach
impractical. To decide on the best
assumptions and to limit the number of
sensitivity runs, a joint working group
was formed. The group was comprised
of representatives from the Department
of Energy, Council of Economic
Advisors, Council on Wage and Price
Stability, and others. The group
reviewed model results to date,
identified the key inputs, specified the
assumptions, and identified the critical
parameters for which the degree of
uncertainty was such that sensitivity
analyses should be performed. Three
months of study resulted in a number of
changes which are reflected in Table 1
and discussed below. These
assumptions were used in both the
phase 2 and phase 3 analyses.
After more evaluation, the joint
working group concluded that the oil
prices assumed in the phase 1 analysis
were too high. On the other hand, no
firm guidance was available as to what
oil prices should be used. In view of this,
the working group decided that the best
course of action was to use two sets of
oil prices which reflect the best
estimates of those governmental entities
concerned with projecting oil prices. The
oil price sensitivity analysis was part of
the phase 2 analysis which was
distributed at the public hearing. Further
details are available in the draft report,
"Still Further Analysis of Alternative
New Source Performance Standards for
New Coal-Fired Power Plants (docket
number IV-A-5)." The analysis showed
that while the variation in oil price
affected the magnitude of emissions,
costs, and energy impacts, price
variation had little effect on the relative
impacts of the various NSPS alternatives
tested. Based on this conclusion, the
higher oil price was selected for
modeling purposes since it paralleled
more closely the middle range
projections by the Department of
Energy.
Reassessment of the assumptions
made in the phase 1 analysis also
revealed that the impact of the coal
washing credit had not been considered
in the modeling analysis. Other credits
allowed by the September proposal,
such as sulfur removed by the
pulverizers or in bottom ash and flyash,
were determined not to be significant
when viewed at the national and
regional levels. The coal washing credit,
on the other hand, was found to have a
significant effect on predicted emissions
levels and, therefore, was factored into
the analysis.
As a result of this reassessment,
refinements also were made in the fuel
gas desulfurization (FGD) costs
assumed. These refinements include
changes in sludge disposal costs, energy
penalties calculated for reheat, and
module sizing. In addition, an error was
corrected in the calculation of partial
scrubbing costs. These changes have
resulted in relatively higher partial
scrubbing costs when compared to full
scrubbing.
Changes were made in the FGD
availability assumption also. The phase
1 analysis assumed 100 percent
availability of FGD systems. This
assumption, however, was in conflict
with EPA's estimates on module
availability. In view of this, several
alternatives in the phase 2 analysis were
modeled at lower system availabilities.
The assumed availability was consistent
with a 90 percent availability for
individual modules when the system is
equipped with one spare. The analysis
also took into consideration the
emergency by-pass provisions of the
proposed regulation. The analysis
showed that lower reliabilities would
result in somewhat higher emissions and
costs for both the partial and full control
cases. Total coal capacity was slightly
lower under full control and slightly
higher under partial control. While it
was postulated that the lower reliability
assumption would produce greater
adverse impacts on full control than on
partial control options, the relative
differences in impacts w<,,-e found to be
insignificant. Hence, the working group
discarded the reliability issue as a major
consideration in the analyzing of
national impacts of full and partial
control options. The Administrator still
believes that the newer approach better
reflects the performance of well
designed, operated, and maintained
FGD systems. However, in order to
expedite the analyses, all subsequent
alternatives were analyzed with an
assumed system reliability of 100
percent.
Another adjustment to the analysis
was the incorporation of dry SO»
scrubbing systems. Dry scrubbers were
assumed to be available for both new
and retrofit applications. The costs of
these systems were estimated by EPA's
Office of Research and Development
based on pilot plant studies and
contract prices for systems currently
under construction. Based on economic
analysis, the use of dry scrubbers was
assumed for low-sulfur coal (less than
1290 ng/J or 3 Ib SO,/million Btu)
applications in which the control
requirement was 70 percent or less. For
higher sulfur content coals, wet
scrubbers were assumed to be more
economical. Hence, the scenarios
characterized as using "dry" costs
contain a mix of wet and dry technology
whereas the "wet" scenarios assume
wet scrubbing technology only.
Additional refinements included a
change in the capital charge rate for
pollution control equipment to conform
to the Federal tax laws on depreciation,
and the addition of 100 billion tons of
coal reserves not previously accounted
for in the model.
Finally, a number of less significant
adjustments were made. These included
adjustments in nuclear capacity to
reflect a cancellation of a plant,
consideration of oil consumption in
transporting coal, and the adjustment of
costs to 1978 dollars rather than 1975
dollars. It should be understood that all
reported costs include the costs of
complying with the proposed particulate
matter standard and NO, standards, as
well as the sulfur dioxide alternatives.
The model does not incorporate the
Agency's PSD regulations nor
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forthcoming requirements to protect
visibility.
Public Comments
Following the September proposal, a
number of comments were received on
the impact analysis. A great number
focused on the model inputs, which
were reviewed in detail by the joint
working group. Members of the joint
working group represented a spectrum
of expertise (energy, jobs, environment,
inflation, commerce). The following
paragraphs discuss only those
comments addressed to parts of the
analysis which were not discussed in
the preceding section.
One commenter suggested that the
costs of complying with State
Implementation Plan (SEP) regulations
and prevention of significant
deterioration requirements should not
be charged to the standards. These cost?
are not charged to the standards in the
analyses. Control requirements under
PSD are based on site specific, case-by-
case decisions for which the standards
serves as a minimum level of control.
Since these judgments cannot be
forecasted accurately, no additional
control was assumed by the model
beyond the requirements of these
standards. In addition, the cost of
meeting the various SEP regulations was
included as a base cost in all the
scenarios modeled. Thus, any forecasted
cost differences among alternative
standards reflect differences in utility
expenditures attributable to changes in
the standards only.
Another commenter believed that the
time horizon for the analysis (1990/1995)
was too short since most plants on line
at that time will not be subject to the
revised standard. Beyond 1995, our data
show that many of the power plants on
line today will be approaching
retirement age. As utilization of older
capacity declines, demand will be
picked up by newer, better controlled
plants. As this replacement occurs,
national SO, emissions will begin to
decline. Based on this projection, the
Administrator believes that the 1990-
1995 time frame will represent the peak
years for SO, emissions and is,
therefore, the relevant time frame for
this analysis.
Use of a higher general inflation rate
was suggested by one commenter. A
distinction must be made between
general inflation rates and real cost
escalation. Recognizing the uncertainty
of future inflation rates, the EPA staff
conducted the economic analysis in a
manner that minimized reliance on this"
assumption. All construction, operating,
and fuel costs were expressed as
constant year dollars and therefore the
analysis is not affected by the inflation
rate. Only real cost escalation was
included in the economic analysis. The
inflation rates will have an impact on
the present value discount rate chosen
since this factor equals the inflation rate
plus the real discount rate. However,
this impact is constant across all
scenarios and will have little impact on
the conclusions of the analysis.
Another commenter opposed the
presentation of economic impacts in
terms of monthly residential electric
bills, since this treatment neglects the
impact of higher energy costs to
industry. The Administrator agrees with
this comment and has included indirect
consumer impacts in the analysis. Based
on results of previous analysis of the
electric utility industry, about half of the
total costs due to pollution control are
felt as direct increases in residential
electric bills. The increased costs also
flow into the commercial and industrial
sectors where they appear as increased
costs of consumer goods. Since the
Administrator is unaware of any
evidence of a multiplier effect on these
costs, straight cost pass through was
assumed. Based on this analysis, the
indirect consumer impacts (Table 5]
were concluded to be equal to the
monthly residential bills ("Economic
and Financial Impacts of Federal Air
and Water Pollution Controls on the
Electric Utility Industry," EPA-230/3-
76/013, May 1976).
One utility company commented that
the model did not adequately simulate
utility operation since it did not carry
out hour-by-hour dispatch of generating
units. The model dispatches by means of
load duration curves which were
developed for each of 35 demand
regions across the United States.
Development of these curves took into
consideration representative daily load
curves, traditional utility reserve
margins, seasonal demand variations,
and historical generation data. The
Administrator believes that this
approach is adequate for forecasting
long-term impacts since it plans for
meeting short-term peak demand
requirements.
Summary of Results
The final results of the analyses are
presented in Tables 2 through 5 and
discussed below. For the three
alternative standards presented,
emission limits and percent reduction
requirements are 30-day rolling
averages, and each standard was
analyzed with a particulate standard of
13 ng/J (0.03 Ib/million Btu) and the
proposed NO, standards. The full
control option was specified as a 520
ng/I (1.2 Ib/million Btu) emission limit
with a 90 percent reduction in potential
SOa emissions. The other options are the
same as full control except when the
emissions to the atmosphere are
reduced below 260 ng/j (0.6 Ib/million
Btu) in which case the minimum percent
reduction requirement is reduced. The
variable control ontion requires a 70
percent minimum reduction and the
partial control option has a 33 percent
minimum reduction requirement. The
impacts of each option were forecast
first assuming the use of wet scrubbers
only and then assuming introduction of
dry scrubbing technology. In contrast to
the September proposal which focused
on 1990 impacts, the analytical results
presented today are for the year 1995.
The Administrator believes that 1995
better represents the differences among
alternatives since more new plants
subject to the standard will be on line
by 1995. Results of the 1990 analyses are
available in the public record.
Wet Scrubbing Results
The projected SO2 emissions from
utility boilers are shown by plant type
and geographic region in Tables 2 and 3.
Table 2 details the 1995 national SO,
emissions resulting from different plant
types and age groups. These standards
will reduce 1995 SO2 emissions by about
3 million tons per year (13 percent) as
compared to the current standards. The
emissions from new plants directly
affected by the standards are reduced
by up to 55 percent. The emission
reduction from new plants is due in part
to lower emission rates and in part to
reduced coal consumption predicted by
the model. The reduced coal
consumption in new plants results from
the increased cost of constructing and
operating new coal plants due to
pollution controls. With these increased
costs, the model predicts delays in
construction of new plants and changes
in the utilization of these plants after
start-up. Reduced coal consumption by
new plants is accompanied by higher
utilization of existing plants and
combustion turbines. This shift causes
increased emissions from existing coal-
and.oil-fired plants, which partially
offsets the emi ssion reductions achieved
by new plants subject to the standard.
Projections of 1995 regional SOa
emissions are summarized in Table 3.
Emissions in the East are reduced by
about 10 to 13 percent as compared to
predictions under the current standards,
whereas Midwestern emissions are
reduced only slightly, The smaller
reductions in the Midwest are due to a
slow growth of new coal-fired capacity.
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In general, introductions of coal-fired
capacity tends to reduce emissions since
new coal plants replace old coal- and
oil-fired units which have higher
emission rates. The greatest emission
reduction occurs in the West and West
South Central regions where significant
growth is expected and today's
emissions are relatively low. For these
two regions combined, the full control
option reduces emissions by 40 percent
from emission levels under the current
standards, while the partial and variable
options produce reductions of about 30
percent.
Table 4 illustrates the effect of the
proposed standards on 1995 coal
production, western coal shipped east,
and utility oil and gas consumption.
National coal production is predicted to
triple by 1995 under all the alternative
standards. This increased demand
raises production in all regions of the
country as compared to 1975 levels.
Considering these major increases in
national production, the small
production variations among the
alternatives are not large. Compared to
production under the current standards,
production is down somewhat in the
West, Northern Great Plains, and
Appalachia, while production is up in
the Midwest. These shifts occur because
of the reduped economic advantage of
low-sulfur coals under the revised
standards. While three times higher than
1975 levels, western coal shipped east is
lower under all options than under the
current standards.
Oil consumption in 1975 was 1.4
million barrels per day. The 3.1 million
barrels per day figure for 1975
consumption in Table 4 includes utility
natural gas consumption (equivalent of
1.7 million barrels per day) which the
analysis assumed would be phased out
by 1990. Hence, in 1995, the 1.4 million
barrel per day projection under current
standards reflects retirement of existing
oil capacity and offsetting increases in
consumption due to gas-to-oil
conversions.
Oil consumption by utilities is
predicted to increase under all the
options. Compared to the current
standards, increased consumption is
200,000 barrels per day under the partial
and variable options and 400,000 barrels
per day under full control. Oil
consumption differences are due to the
higher costs of new coal plants under
these standards, which causes a shift to
more generation from existing oil plants
and combustion turbines. This shift in
generation mix has important
implications for the decision-making
process, since the only assumed
constraint to utility oil use was the
price. For example, if national energy
policy imposes other constraints which
phase out or stabilize oil use for electric
power generation, then the differences
in both oil consumption and oil plant
emissions (Table 2) across the various
standards will be mitigated.
Constraining oil consumption, however,
will spread cost differences among
standards.
The economic effects in 1995 are
shown in Table 5. Utility capital
expenditures increase under all options
as compared to the $770 billion
estimated to be required through 1995 in
the absence of a change in the standard.
The capital estimates in Table 5 are
increments over the expenditures under
the current standard and include both
plant capital (for new capacity] and
pollution control expenditures. As
shown in Table 2, the model estimates
total industry coal capacity to be about
17 GW (3 percent) greater under the
non-uniform control options. The cost of
this extra capacity makes the total
utility capital expenditures higher under
the partial and variable options, than
under the full control option, even
though pollution control capital is lower.
Annualized cost includes levelized
capital charges, fuel costs, and
operation and maintenance costs
associated with utility equipment. All of
the options cause an increase in
annualized cost over the current
standards'. This increase ranges from a
low of $3.2 billion for partial control to
$4.1 billion for full control, compared to
the total utility annualized costs of
about $175 billion.
The average monthly bill is
determined by estimating utility revenue
requirements which are a function of
capital expenditures, fuel costs, and
operation and maintenance costs. The
average bill is predicted to increase only
slightly under any of the options, up to a
maximum 3-percent increase shown for
full control. Over half of the large total
increase in the average monthly bill
over 1975 levels ($25.50 per month) is
due to a significant increase in the
amount of electricity used by each
customer. Pollution control
expenditures, including those to meet
the current standards, account for about
15 percent of the increase in the cost per
kilowatt-hour while the remainder of the
cost increase is due to capital intensive
capacity expansion and real escalations
in construction and fuel cost.
Indirect consumer impacts range from
$1.10 to $1.60 per month depending on
the alternative selected. Indirect
consumer impacts reflect increases in
consumer prices due to the increased
energy costs in the commercial and
industrial sectors.
The incremental costs per ton of SO,
removal are also shown in Table 5. The
figures are determined by dividing the
change in annualized cost by the change
in annual emissions, as compared to the
current standards. These ratios are a
measure of the cost effectiveness of the
options, where lower ratios represent a
more efficient resource allocation. All
the options result in higher cost per ton
than the current standards with the full
control option being the most expensive.
Another measure of cost effectiveness
is the average dollar-per-ton cost at the
plant level. This figure compares total
pollution control cost with total SOj
emission reduction for a model plant.
This average removal cost varies
depending on the level of control and
the coal sulfur content. The range for full
control is from $325 per ton on high-
sulfur coal to $1,700 per ton on low-
sulfur coal. On low-sulfur coals, the
partial control cost is $2,000 per ton, and
the variable cost is $1,700 per ton.
The economic analyses also estimated
the net present value cost of each
option. Present value facilitates
comparison of the options by reducing
the streams of capital, fuel, and
operation and maintenance expenses to
one number. A present value estimate
allows expenditures occurring at
different times to be evaluated on a
similar basis by discounting the
expenditures back to a fixed year. The
costs chosen for the present value
analysis were the incremental utility
revenue requirements relative to the
current NSPS. These revenue
requirements most closely represent the
costs faced by consumers. Table 5
shows that the present value increment
for 1995 capacity is $41 billion for full
control, $37 billion for variable control,
and $32 billion for partial control.
Dry Scrubbing Results
Tables 2 through 5 also show the
impacts of the options under the
assumption that dry SOi scrubbing
systems penetrate the pollution control
market. These analyses assume that
utilities will install dry scrubbing
systems for all applications where they
are technologically feasible and less
costly than wet systems. (See earlier
discussion of assumptions.)
The projected SO» emissions from
utility boilers are shown by plan type
and geographic region in Tables 2 and 3.
National emission projections are
similar to the wet scrubbing results.
Under the dry control assumption,
however, the variable control option is
predicted to have the lowest national
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emissions primarily due to lower oil
plant emissions relative to the full
control option. Partial control produces
more emissions than variable control
because of higher emissions from new
plants. Compared to the current
standards, regional emission impacts
are also similar to the wet scrubbing
projections. Full control results in the
lowest emissions in the West, while
variable control results hi the lowest
emissions in the East. Emissions in the
Midwest and West South Central are
relatively unaffected by the options.
Inspection of Tables 2 and 3 shows
that with the dry control assumption the
current standard, full control, and
partial control cases produce slightly
higher emissions than the corresponding
wet control cases. This is due to several
factors, the most important of which is a
shift in the generation mix. This shift
occurs because dry scrubbers have
lower capital costs and higher variable
costs than wet scrubbers and, therefor,
the two systems have different effects
on the plant utilization rates. The higher
variable costs are due primarily to
transportation charges on intermediate
-to low sulfur coal which must be used
with dry scrubbers. The increased
variable cost of dry controls alters the
dispatch order of existing plants so that
older, uncontrolled plants operate at
relatively higher capacity factors than
would occur under the wet scrubbing
assumption, hence increasing total
emissions. Another factor affecting
emissions is utility coal selection which
may be altered by differences in
pollution control costs.
Table 4 shows the effect to the
proposed standards on fuels in 1995.
National coal production remains
essentially the same whether dry or wet
controls are assumed. However, the use
of dry controls causes a slight
reallocation in regional coal production,
except under a full control option where
dry controls cannot be applied to new
plants. Under the variable and partial
options Appalachian production
increases somewhat due to greater
demand for intermedia^ sulfur coals
while Midwestern coal production
declines slightly. The non-uniform
options also result in a small shifting in
the western regions with Northern Great
Plains production declining and
production in the rest of West
increasing. The amount of western coal
shipped east under the current standard
is reduced from 122 million to 99 million
tons (20% decrease) due to the increased
use of eastern intermediate sulfur coals
for dry scrubbing applications. Western
coal shipped east is reduced further by
the revised standards, to a low of 55
million tons under full control. Oil
impacts under the dry control
assumption are identical to the wet
control cases, with full control resulting
in increased consumption of 200
thousand barrels per day relative to the
partial and variable options.
The 1995 economic effects of these
standards are presented in Table 5. In
general, the dry control assumption
results in lower costs. However, when
comparing the dry control costs to the
wet control figures it must be kept in^
mind that the cost base for comparison,
the current standards, is different under
the dry control and wet control
assumptions. Thus, while the
uncremental costs of full control are
higher under the dry scrubber
assumption the total costs of meeting
the standard is lower than if wet
controls were used.
The economic impact figures show
that when dry controls are assumed the
cost savings associated with the
variable and partial options is
significantly increased over the wet
control cases. Relative to full control the
partial control option nets a savings of
$1.4 billion in annualized costs which
equals a $14 billion net present value
savings. Variable control results in a
$1.1 billion annualized cost savings
which is a savings of $12 billion in net
present value. These changes in utility
costs affect the average residential bill
only slightly, with partial control
resulting in a savings of $.50 per month
and variable control savings of $.40 per
month on the average bill, relative to full
control.
Conclusions
One finding that has been clearly
demonstrated by the two years of
analysis is that lower emission
standards on new plants do not
necessarily result in lower national SO.
emissions when total emissions from the
entire utility system are considered.
There are two reasons for this finding.
First, the lowest emissions tend to result
from strategies that encourage the
construction of new coal capacity. This
capacity, almost regardless of the
alternative analyzed, will be less
polluting than the existing coal- or oil-
fired capacity that it replaces. Second,
the higher cost of operating the new
capacity (due to higher pollution costs)
may cause the newer, cleaner plants to
be utilized less than they would be
under a less stringent alternative. These
situations are demonstrated by the
analyses presented here.
The variable control option produces
emissions that are equal to or lower
than the other options under both the
wet and dry scrubbing assumptions.
Compared to full control, variable
control is predicted to result in 12 GW to
17 GW more coal capacity. This
additional capacity replaces dirtier
existing plants and compensates for the
slight increase in emissions from new
plants subject to the standards, hence
causing emissions to be less than or
equal to full control emissions
depending on scrubbing cost assumption
(i.e., wet or dry). Partial control and
variable control produce about the same
coal capacity, but the additional 300
thousand ton emission reduction from
new plants causes lower total emissions
under {he variable option. Regionally, all
the options produce about the same
emissions in the Midwest and West
South Central regions. Full control
produces 200 thousands tons less
emissions in the West than the variable
option and 300 thousand tons less than
partial control. But the variable and
partial options produce between 200 and
300 thousand tons less emissions in the
East.
The variable and partial control
options have a clear advantage over full
control with respect to costs under both
the wet and dry scrubbing assumptions.
Under the dry assumption, which the
Administrator believes represents the
best prediction of utility behavior,
variable control saves about $1.1 billion
per year relative to full control and
partial control saves an additional $0.3
billion.
All the options have similar impacts
on coal production especially when
considering the large increase predicted
over 1975 production levels. With
respect to oil consumption, however, the
hill control option causes a 200,000
barrel per day increase as compared to
both the partial and variable options.
Based on these analyses, the
Administrator has concluded that a non-
uniform control strategy is best
considering the environmental, energy,
and economic impacts at both national
and regional levels. Compared to other
options analyzed, the variable control
standard presented above achieves the
lowest emissions in an efficient manner
and will not disrupt local or regional
coal markets. Moreover, this option
avoids the 200 thousand barrel per day
oil penalty which has been predicted
under a number of control options. For
these reasons, the Administrator
believes that the variable control option
provides the best balance of national
environmental, energy, and economic
objectives.
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Table 1.Ai»y Modeling Assumptions
Assumption
Growth rates.
Nuclear capacity -
01 prices <* 1875).
Cod t*roport*l»n.
Coal mnng labor oasts..
Capital charge rate
Cost reporting tin*
FGDcort»_
Coal cleaning ereo*
Bottom ash and fly ash content
1876-1985 4.6%/yr.
1985-1995: 4.0%.
1965 97 GW.
1890 185.
1896 226.
1885 $12.90/bot
1890 $1640.
1985 $21.00.
1% per year real renew.
U M W settlement and 1% real Increase thereafter.
12.5% lor pollution control expenditure*.
1978bo4tars,
No change from phase 2 analysis except for the addition of dry
' acrubbinfl systems tor certain applicalleos.
5%-35% SO, reducaon assumed tor high auMur bituminous coate
only.
No credit assumed.
Tatota 2.National 1995 SO, Emissions From Utility Boilers
(Million tons)
Plant category
Level of control*
1975
Current standards
FuH cufiUul
Partial cxmljol
93% minimum
Variable control
70% rnmmun
SffVNSPS Plants'
New Plants'
Ol Plants..
Total National
Emission*
15.5
7.1
1.0
Dry
15.8
7.0
1.0
Wai
16.0
1.4
Dry
16J
S.1
1.4
15.9
a.e
1J
Dry
16.2
S.4
1.2
Wet Dry
16.0 161
S.3 1.1
14 1.2
18.6
23.7
23.8
20.6
20.7
20.9
20.6
20.5
Total Coal
Capacity (GW) 205
Stodge generated (mWon
tons dry)
552
23
654
27
521
56
520
86
534
43
637
39
533
SO
537
41
Results of joint EPA/DOE analyses completed in May 1979 based on oi prices of $12.90. $16.40, and t21.0Wbbl in the
years 196$. 1890. and 1995. respectively.
'With 520 ng/J maximum emission kmit
< Plants subject to existing State regulations or the current NSPS of 1.2 fc SCVmHon BTU.
Based on wet SO, scrubbing costs.
'Baaed on dry SO. scrubbing costs where applicable.
'Plants subject to the revised standards.
Tabte 3.Regional 1995 SO, Emissions From Utility Boilers
(Mann tons]
Level of control'
1975
Currant standards
Ful control
Partial ixMAut
33% minimum
Variable control
70% minimum
Total National
Emissions
MM* Oy4
18,8 23.7 234
*W Oy
20.6 20.7
»W Dry
*0.8 20.9
M Dry
20.6 20.5
Regional Emissions:
East*
West South Central _
Total Coal
Capacity (GW).._
11.2
....,.,. 1.1
_ 2.6
1.7
tti
X3
2.6
1.7
10.1
74
1.7
OJ
10.1
74
1.7
04
8.8
74
14
1.2
.8
8J)
14
U
8.8
74
14
1.1
8.7
8.0
1.T
1.1
205
552
554
S21
620
634
637
633
537
Results of joint EPA/DOE analyses completed in May 1979 based on ol prices of $12.90. $16.40. and $21.00/bbl In the
years 1885. *890, and 1895. reapectrvely.
With 520 ng/J maximum emission fend
' Based on wet SO, scrubbing costs.
' Based on dry SO, scrubbing costs where applicable.
New England. Middle Atlantic, South Atlantic, and East South CanM Camus Regtona.
'East North Central and West North Central Census Regions.
West South Central Census Region.
* Mountain and PacMc Census Regtona.
Performance Testing
Paniculate Matter
The final regulations require that
Method 5 or 17 under 40 CFR Part 60,
Appendix A, be used to determine
compliance with the particulate matter
emission limit. Particulate matter may
be collected with Method 5 at an
outstack filter temperature up to 160 C
(320 F); Method 17 may be used when
stack temperatures are less than 160 C
(320 F). Compliance with the opacity
standard in the final regulation is
determined by means of Method 9,
under 40 CFR Part 60. Appendix A. A
transmissometer that meets
Performance Specification 1 under 40
CFR Part 60, Appendix B is required.
Several comments were received
which questioned the accuracy of
Methods 5 and 17 when used to measure
particulate matter at the level of the
standard. The accuracy of Methods 5
and 17 is dependent on the amount of
sample collected and not the
concentration in the gas stream. To
maintain an accuracy comparable to the
accuracy obtained when testing for
mass emission rates higher than the
standard, it is necessary to sample for
longer times. For this reason, the
regulation requires a minimum sampling
time of 120 minutes and a minimum
sampling volume of 1.7 dscm (60 dscf).
Three comments raised the issue of
potential interference of acid mist with
the measurement of particulate matter.
The Administrator recognized this issue
prior to proposal of the regulations. In
the preamble to the proposed
regulations, the Administrator indicated
that investigations would continue to
determine the extent of the problem. A
series of tests at an FGD-equipped
facility burning 3-percent-sulfur coal
indicate that the amount of sample
collected using Method 5 procedures is
temperature sensitive over the range of
filter temperatures used (250° F to 380*
F], with reduced weights at higher
temperatures. Presumably, the
decreased weight at higher filter
temperatures reflect vaporization of acid
mist. Recently received particulate
emission data using Method 5 at 32* F
for a second coal-fired power plant
equipped with an electrostatic
precipitator and an FGD system
apparently conflicts with the data
generated by EPA. For this plant,
particulate matter was measured at 0.02
Ibs/million Btu. It is not known what
portion of this particulate matter, if any
was attributable to sulfuric acid mist.
The intent of the particulate matter
standard is to insure the Installation,
operation, and maintenance of a good
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Table tImpacts on Fuels In 1995*
Level of control*
1975
dual
Current standards
full control
Partial control
33% minimum
Variable control
70% minimum
Wet'
Dry-
Dry
Wet
Dry
Wet
Dry
U S Coal Production (million
Ions)
Appalachia
Midwest
Northern Great Plains....
West
Total
Western Coal Snipped East
(mthon tons)
Oil Consumpton by Power
Plants (million bbl/day).
Coal Transportation
396
151
54
46
647
21
489
404
655
230
1 778
122
1 2
02
524
391
630
222
1 767
99
1.2
0.2
463
487
633
182
1 765
59
1 6
02
465
488
628
180
1 761
55
16
02
475
456
622
212
1 765
66
t 4
02
486
452
576
228
1 742
59
14
0.2
470
465
632
203
1 770
71
14
0.2
484
450
602
217
1 752
70
1 4
0.2
Total ....
31
1.4
1.8
1.8
1.6
16
16
1.6
Results of EPA analyses completed m May 1979 based on OK prices of $12 90, $16.40, and $21.00/bW m the years 1985,
1990, and 1995. respectively
' With 520ng/j maximum emission limit
' Based on wet SO, scrubbing costs
Based on dry SO, scrubbing where applicable.
Tibte 5. 1995 Economic Impacts
(1978 dollars)
Level of control''
Current standards
Wet* Dry1
Average Monthly Residential Bills ($/
month) _ $53 00 $52 85
Indirect Consumer Impacts ($/month) -
Incremental Utility Capital Expendi-
tures. Cumulative 1976-1995 ($ bi-
llons)
Incremental Annuahzed Cost (S bil-
lions) ~
Present Value of Incremental Utility
Revenue Requirements ($ Mhons)....
Incremental Cost of SO' Reduction ($/
ton) ,, ,. .
Full control
Wet
$5450
1.50
4
4.1
41
1,322
Dry
$5445
1.60
5
4.4
45
1,428
Partial control
33% minimum
Wet
$54.15
115
6
3.2
32
1,094
Dry
$5395
1 10
-3
3.0
31
1,012
Vanabte control
70% minimum
Wet
$5430
1.30
10
36
37
1.163
Dry
$54.05
1.20
-1
3.3
33
1.036
Results of EPA analyses completed m May 1979 based on oil prices of $12 90, $16.40, and $21 00/bW n the years 1985,
1990, and 1995, respectively.
' With 520 ng/J maximum emission kmrt.
' Based on wet SO, scrubbing costs.
' Based on dry SO, scrubbing costs where applicable.
emission control system. Since
technology is not available for the
control of sulfuhc acid mist, which is
condensed in the FGD system, the
Administrator does not believe the
particulate matter sample should
include condensed acid mist. The final
regulation, therefore, allows particulate
matter testing for compliance between
the outlet of the particulate matter
control device and the inlet of a wet
FGD system. EPA will continue to
investigate revised procedures to
minimize the measurement of acid mist
by Methods 5 or 17 when used to
measure particulate matter after the
FGD system. Since technology is
available to control particulate sulfate
carryover from an FGD system, and the
Administrator believes good mist
eliminators should be included with all
FGD systems, the regulations will be
amended to require particulate matter
measurement after the FGD system
when revised procedures for Methods !i
or 17 are available.
SO, and NOX
The final regulation requires that
compliance with the sulfur dioxide and
nitrogen oxides standards be
determined by using continuous
monitoring systems (CMS) meeting
Performance Specifications 2 and 3,
under 40 CFR Part 60, Appendix B. Data
from the CMS are used to calculate a 30-
day rolling average emission rate and
percentage reduction (sulfur dioxide
only) for the initial performance test
required under 40 CFR 60.8. At the end
of each boiler operating day after the
initial performance test a new 30-day
rolling average emission rate for sulfur
dioxide and nitrogen oxides and an
average percent reduction for sulfur
dioxide are determined. The final
regulations specify the minimum amount
of data that must be obtained for each
30 successive boiler operating days but
requires the calculation of the average
emission rate and percentage reduction
based on all available data. The
minimum data requirements can be
satisfied by using the Reference
Methods or other approved alternative
methods when the CMS, or components
of the system, are inoperative.
The final regulation requires operation
of the continuous monitors at all times,
including periods of startup, shutdown,
malfunction (NO, only), and emergency
conditions (SO, only), except for those
periods when the CMS is inoperative
because of meilfunctions, calibration or
span checks.
The proposed regulations would have
required that compliance be based on
the emission rate and percent reduction
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(sulfur dioxide only) for each 24-hour
period of operation. Continual
determination of compliance with the
proposed standard would have
necessitated that each source owner or
operator install redundant CMS or
conduct manual testing in the event of
CMS malfunction.
Comments on the proposed testing
requirements for sulfur dioxide and
nitrogen oxides indicated that CMS
could not operate without malfunctions;
therefore, every facility would require
redundant CMS. One commenter
calculated that seven CMS would be
needed to provide the required data.
Comments also questioned the
practicality and feasibility of obtaining
around-the-clock emissions data by
means of manual testing in the event of
CMS malfunction. The commenter
stated that the need for immediate
backup testing using manual methods
would require a stand-by test team at all
times and that extreme weather
conditions or other circumstances could
often make if impossible for the test
team to obtain the required data. The
Administrator agrees with these
comments and has redefined the data
requirements to reflect the performance
that can be achieved with one well-
maintained CMS. The final requirements
are designed to eliminate the need for
redundant CMS and minimize the
possibility that manual testing will be
necessary, while assuring acquisition of
sufficient data to document compliance.
Compliance with the emission
limitations for sulfur dioxide and
nitrogen oxides and the percentage
reduction for sulfur dioxide is
determined from all available hourly
averages, except for periods of startup,
shutdown, malfunction or emergency
conditions for each 30 successive boiler
operating days. Minimum data
requirements have been established for
hourly averages, for 24-hour periods,
and for the 30 successive boiler
operating days. These minimum
requirements eliminate the need for
redundant CMS and minimize the need
for testing using manual sampling
techniques. The minimum requirements
apply separately to inlet and outlet
monitoring systems.
The regulation allows calculation of
hourly averages for the CMS using two
or more of the required four data points.
This provision was added to
accommodate those monitors for which
span and calibration checks and minor
repairs might require more than 15
minutes.
For any 24-hour period, emissions
data must be obtained for a minimum of
75 percent of the hours during which the
affected facility is operated (including
startup, shutdown, malfunctions or
emergency conditions). This provision
was added to allow additional time for
CMS calibrations and to correct minor
CMS problems, such as a lamp failure, a
plugged probe, or a soiled lens.
Statistical analyses of data obtained by
EPA show that there is no significant
difference (at the 95 percent confidence
interval) between 24-hour means based
on 75 percent of the data and those
based on the full data set.
To provide time to correct major CMS
malfunctions and minimize the
possibility that supplemental testing will
be needed, a provision has been added
which allows the source owner or
operator to demonstrate compliance if
the minimum data for each 24-hour
period has been obtained for 22 of tbe 30
successive boiler operating days. This
provision is based on EPA studies that
have shown that a single pair of CMS
pollutant and diluent monitors can be
made available in excess of 75 percent
of the time and several comments
showing CMS availability in excess of
90 percent of the time.
In the event a CMS malfunction would
prevent the source owner or operator
from meeting the minimum data
requirements, the regulation requires
that the reference methods or other
procedures approved by the
Administrator be used to supplement
the data. The Administrator believes,
however, that a single properly
designed, maintained, and operated
CMS with trained personnel and an
appropriate inventory of spare parts can
achieve the monitoring requirements
with currently available CMS
equipment. In the event that an owner or
operator fails to meet the minimum data
requirements, a procedure is provided
which may be used by the
Administrator to determine compliance
with the SO, and NO, standards. The
procedure is provided to reduce
potential problems that might arise if an
owner or operation is unable to meet the
minimum data requirements or attempts
to manipulate the acquisition of data so
as to avoid the demonstration of
noncompliance. The Administrator
believes that an owner or operator
should not be able to avoid a finding of
noncompliance with the emission
standards solely by noncompliance with
the minimum data requirements.
Penalties related only to failure to meet
the minimum data requirements may be
less than those for failure to meet the
emission standards and may not provide
as great an incentive to maintain
compliance with the regulations.
The procedure involves the
calculation of standard deviations for
the available inlet SOZ monitoring data
and the available outlet SO2 and NO,
monitoring data and assumes the data
are normally distributed. The standard
deviation of the inlet monitoring data for
SOj is used to calculate the upper
confidence limit of the inlet emission
rate at the 95 percent confidence
interval. The upper confidence limit of
the inlet emission rate is used to
determine the potential combustion
concentration and the allowable
emission rate. The standard deviation of
the outlet monitoring data for SO2 and
NO, are used to calculate the lower
confidence limit of the outlet emission
rates at the 95 percent confidence
interval. The lower confidence limit of
the outlet emission rate is compared
with the allowable emission rate to
determine compliance. If the lower
confidence limit of the outlet emission
rate is greater than the allowable
emission rate for the reporting period,
the Administrator will conclude that
noncompliance has occurred.
The regulations require the source
owner or operator who fails to meet the
minimum data requirements to perform
the calculations required by the added
procedure, and to report the results of
the calculations in the quarterly report.
The Administrator may use this
information for determining the
compliance status of the affected
facility.
It is emphasized that while the
regulations permit a determination of
the compliance status of a facility in the
absence of data reflecting some periods
of operation, an owner and operator is
required by 40 CFR 60.11(d) to continue
to operate the facility at all times so as
to minimize emissions consistent with
good engineering practice. Also, the
added procedure which allows for a
determination of compliance when less
than the minimum monitoring data have
been obtained does not exempt the
source owner or operator from the
minimum data requirements. Exemption
from the minimum data requirements
could allow the source owner to
circumvent the standard, since the
added procedure assumes random
variations in emission rates.
One commenter suggested that
operating data be used in place of CMS
data to demonstrate compliance. The
Administrator does not believe,
however, that the demonstration of
compliance can be based on operating
data alone. Consideration was given to
the reporting of operating parameters
during those periods when emissions
data have not been obtained. This
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alternative was rejected because it
would mean that the source owner or
operator would need to record the
operating parameters at all times, and
would impose an administrative burden
on source owners or operators in
compliance with the emission
monitoring requirements. The regulation
requires the owner or operator to certify
that the emission control systems have
been kept in operation during periods
when emissions data have not been
obtained.
Several commenters indicated that
CMS were not sufficiently accurate to
allow for a determination of compliance.
One commenter provided calculations
showing that the CMS could report an
FGD efficiency ranging from 77.5 to 90
percent, with the scrubber operating at
an efficiency of 85 percent The analysis
submitted by the commenler is
theoretically possible for any single data
point generated by the CMS. For the 30-
day averaging periods, however, random
variations in individual data points are
not significant. The criterion of
importance in showing compliance for
this longer averaging time is the
difference between the mean values
measured by the CMS and the reference
methods. EPA is developing quality
assurance procedures, which will
require a periodic demonstration that
the mean emission rates measured by
the CMS demonstrates a consistent and
reproducible relationship with the mean
emission rates measured by the
reference methods or acceptable
modifications of these methods.
A specific comment received on the
monitoring requirements questioned the
need to respan the CMS for sulfur
dioxide when the sulfur content of the
fuel changed by 0.5 percent The intent
of this requirement was to assure that a
change in fuel sulfur content would not
result in emissions exceeding the range
of the CMS. This requirement has been
deleted on the premise that the source
owner or operator will initiate his own
procedures to protect himself against
loss of data.
Several comments were also received
concerning detailed technical items
contained in Performance Specifications
2 and 3. One comment, for example,
suggested that a single "relative
accuracy" specification be used for the
entire CMS, as opposed to separate
values for the pollutant and diluent
monitors. Another comment questioned
the performance specification on
instrument response time, while still
other comments raised questions on
calibration procedures. EPA is in the
process of revising Performance
Specifications 2 and 3 to respond to
these, and other questions. The current
performance specifications, however,
are adequate for the determination of
compliance.
Fuel Pretreatment
The final regulation allows credit Cor
fuel pretreatment to remove sulfur or
increase heat content. Fuel pretreatment
credits are determined in accordance
with Method 19. This means that coal or
oil may be treated before firing and the
sulfur removed may be credited toward
meeting the SO, percentage reduction
requirement The final fuel pretreatment
provisions are the same as those
proposed.
Most all ooxmnenters on this issue
supported the fuel pretreatment
crediting procedure* proposed by EPA.
Several commenters requested that
credit also be given for sulfur removed
in the coal bottom ash and fly ash. This
is allowed under the final regulation and
was also allowed under the proposal in
the optional "as-fired" fuel sampling
procedures under the SO* emission
monitoring requirements. By monitoring
SOi emissions (ng/J, lb/million Btu) with
an as-fired fuel sampling system located
upstream of coal pulverizers and with
an in-stack continuous SO* monitoring
system downstream of the FGD system,
sulfur removal credits are combined for
the coal pulverizer, bottom ash. fly a&h
and FGD system into one removal
efficiency. Other alternative sampling
procedures may also be submitted to the
Administrator for approval.
Several commenters indicated that
they did not understand the proposed
fuel pretreatment crediting procedure for
refined fuel oil. The Administrator
intended to allow fuel pretreatment
credits for all fuel oil desulfurizau'on
processes used in preparation of utility
boiler fuels. Thus, the input and output
from oil desulfurization processes {e.g.,
hydrotreatment units) that are used to
pretreat utility boiler fuels used in
determining pretreatment credits. If
desulfurized oil is blended with
undesulfurized oil, fuel pretreatment
credits are prorated based on heat input
of oils blended. The Administrator
believes that the oil input to the
desulfurizer should be considered the
input for credit determination and not
the well head crude oil or input oil to the
refinery. Refining of crude oil results in
the separation of the base stock into
various density fractions which range
from lighter products such as naphtha
and distillate oils. Most of the sulfur
from the crude oil is bound to the
heavier residual oils which may have a
sulfur content of twice the input crude
oil. The residual oils can be upgraded to
a lower sulfur utility steam generator
fuel through th« use of desulfurization
technology {scrch as
hydrodesulfurization). The
Administrator believes that it is
appropriate to give full fuel pretreatment
credit for hydrotreatment units and not
to penalize hydrodesulfurization units
which are used to process high-sulfur
residual oils. Thus, the input to the
hydrodesulfurizarion unit is treed to
determine oil pretreatment credits and
not the lower sulfur refinery input crude.
This procedure will allow full credit for
residual oil hydrodesulfurization units.
In relation to fuel pretreatment credits
for coal, commenters requested that
sampling be allowed prior to the 'initial
coal breaker. Under the final standards,
coal sampling may be conducted at any
location (either before or after the initial
coal breaker). It is desirable to sample
coal after the initial breaker because the
smaller coal volume and coal size will
reduce sampling requirements under
Method 19. If sampling were conducted
before the initial breaker, rock removed
by the coal breaker would not result in
any additional sulfur removal credit
Coal samples are analyzed to determine
potential SO. emissions in ng/J (lb/
million Btu) and any removal of rock or
other similar reject material will not
change the potential SO» emission rate
(ng/j; Ib/million Btu).
An owner or operator of an affected
facility who elects to use fuel
pretreatment credits is responsible for
insuring that the EPA Method 19
procedures are followed in determining
SOa removal credit for pretreatment
equipment.
Miscellaneous
Establishment of standards of
performance for electric utility steam
generating units was preceded by the
Administrator's determination that these
sources contribute significantly to air
pollution which causes or contributes to
the endangerment of public health or
welfare (36 FR 5931), and by proposal of
regulations on September 19,1978 (43 FR
42154). In addition, a preproposal public
hearing (May 25-26,1977) and a
postproposal public hearing (December
12-13,1978) was held after notification
was given in the Federal Register. Under
section 117 of the Act, publication of
these regulations was preceded by
consultation with appropriate advisory
committees, independent experts, and
Federal departments and agencies.
Standards of performance for new
fossil-fuel-fired stationary sources
established under section 111 of the
Clean Air Act reflect:
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Application of the best technological
system of continuous emission reduction
which (taking into consideration the cost of
achieving such emission reduction, any
nonair quality health and environmental
impact and energy requirements) the
Administrator determines has been
adequately demonstrated, [section lll(a)(l)]
Although there may be emission
control technology available that can
reduce emissions below those levels
required to comply with standards of
performance, this technology might not
be selected as the basis of standards of
performance due to costs associated
with its use. Accordingly, standards of
performance should not be viewed as
the ultimate in achievable emission
control. In fact, the Act requires (or has
potential for requiring) the imposition of
s more stringent emission standard in
several situations.
For example, applicable costs do not
play as prominent a role in determining
the "lowest achievable emission rate"
for new or modified sources located in
nonattainment areas, i.e., those areas
where statutorily-mandated health and
welfare standards are being violated. In
this respect, section 173 of the Act
requires that a new or modified source
constructed in an area that exceeds the
National Ambient Air Quality Standard
(NAAQS) must reduce emissions to the
level that reflects the "lowest
achievable emission rate" (LAER), as
defined in section 171(3), for such source
category. The statute defines LAER as
that rate of emission which reflects:
(A) The most stringent emission
limitation which is contained in the
implementation plan of any State for
such class or category of source, unless
the owner or operator of the proposed
source demonstrates that such
limitations are not achievable, or
(B) The most stringent emission
limitation which is achieved in practice
by such class or category of source,
whichever is more stringent.
In no event can the emission rate
exceed any applicable new source
performance standard [section 171(3)].
A similar situation may arise under
the prevention of significant
deterioration of air quality provisions of
the Act (Part C). These provisions
require that certain sources [referred to
in section 169(1)] employ "best available
control technology" [as defined in
section 169(3)] for all pollutants
regulated under the Act. Best available
control technology (BACT) must be
determined on a case-by-case basis,
taking energy, environmental and
economic impacts, and other costs into
account. In no event may the application
of BACT result in emissions of any
pollutants which will exceed the
emissions allowed by any applicable
standard established pursuant to section
111 (or 112) of the Act.
In all events, State implementation
plans (SIP's) approved or promulgated
under section 110 of the Act must
provide for the attainment and
maintenance of National Ambient Air
Quality Standards designed to protect
public health and welfare. For this
purpose, SIP's must in some cases
require greater emission reductions than
those required by standards of
performance for new sources.
Finally, States are free under section
116 of the Act to establish even more
stringent emission limits than those
established under section 111 or those
necessary to attain or maintain the
NAAQS under section 110. Accordingly,
new sources may in some cases be
subject to limitations more stringent
than EPA's standards of performance
under section 111, and prospective
owners and operators of new sources
should be aware of this possibility in
planning for such facilities.
Under EPA's sunset policy for
reporting requirements in regulations,
the reporting requirements in this
regulation will automatically expire five
years from the date of promulgation
unless the Administrator takes
affirmative action to extend them.
Within the five year period, the
Administrator will review these
requirements.
Section 317 of the Clean Air Act
requires the Administrator to prepare an
economic impact assessment for
revisions determined by the
Administrator to be substantial. The
Administrator has determined that these
revisions are substantial and has
prepared an economic impact
assessment and included the required
information in the background
information documents.
Dated: June 1,1979.
Douglas M. Costle,
Administrator.
PART 60STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
In 40 CFR Part 60, § 60.8 of Subpart A
is revised, the heading and § 60.40 of
Subpart D are revised, a new Subpart
Da is added, and a new reference
method is added to Appendix A as
follows:
1. Section 60.8{d) and § 60.8{f) are
revised as follows:
{60.8 Performance tests.
(d) The owner or operator of an
affected facility shall provide the
Administrator at least 30 days prior
notice of any performance test, except
as specified under other subparts, to
afford the Administrator the opportunity
to have an observer present.
*****
(f) Unless otherwise specified in the
applicable subpart, each pt.formance
test shall consist of three separate runs
using the applicable test method. Each
run shall be conducted for the time and
under the conditions specified in the
applicable standard. For the purpose of
determining compliance with an
applicable standard, the arithmetic
means of results of the three runs shall
apply. In the event that a sample is
accidentally lost or conditions occur in
which one of the three runs must be
discontinued because of forced
shutdown, failure of an irreplaceable
portion of the sample train, extreme
meteorological conditions, or other
circumstances, beyond the owner or
operator's control, compliance may,
upon the Administrator's approval, be
determined using the arithmetic mean of
the results of the two other runs.
2. The heading for Subpart D is
revised to read as follows:
Subpart DStandards of Performance
for Fossil-Fuel-Fired Steam Generators
for Which Construction Is Commenced
After August 17,1971
3. Section 60.40 is amended by adding
paragraph (d) as follows:
§60.40 AppttcaWHty and designation of
affected facility.
*****
(d) Any facility covered under Subpart
Da is not covered under This Subpart.
(Sec. Ill, 301(a) of the Clean Air Act as
amended (42 U.S.C. 7411, 7601(a)).J
4. A new Subpart Da is added as
follows:
Subpart DaStandards of Performance for
Electric Utility Steam Generating Units for
Which Construction Is Commenced After
September 18,1978
Sec.
60.40a Applicability and designation of
affected facility.
60.41a Definitions.
60.42a Standard for particulate matter.
60.43a Standard for sulfur dioxide.
60.44a Standard for nitrogen oxides.
60.45a Commercial demonstration permit.
60.48a Compliance provisions.
60.47a Emission monitoring.
60.48a Compliance determination
procedures and methods.
60.49a Reporting requirements.
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Authority: Sec. 111. 9m(a) of Hie CSem Air
Act a* amended (42 U.S.C. 7411,7601(a)), and
additional authority M moled below.
Subpart DaStandards of
Performance for Electric Utility Steam
Generating Units for Which
Construction Is Commenced After
September W, 1878
f 60.40a Appflcabfltty and designation of
affected facility.
(a) The affected facility to which this
subpart applies is each electric utility
steam generating unit:
(1) That is capable of combusting
more than 73 megawatts (250 million
Btu/hour) heat input of fossil fuel (either
alone or in combination with any other
fuel); and
(2) For which construction or
modification is commenced after
September 18,1978.
[bj This subpart applies to electric
utility combined cycle gas turbines that
are capable of combusting more than 73
megawatt* (250 million Btu/hour) heat
input of fossil fuel in the steam
generator. Only emissions resulting from
combustion of fuels in the steam
generating unit are subject to this
subpart. (The gas turbine emissions are
subject to Subpart GG.)
(c) Any change to an existing fossil-
fuel-fired steam generating unit to
accommodate the use of combustible
materials, other than fossil fuels, shall
not bring that unit under the
applicability of this subparL
(d) Any change to an existing steam
generating unit originally designed to
fire gaseous or liquid fossil fuels, to
accommodate the use of any other fuel
(fossil or nonfossil) shall not bring that
unit under the applicability of this
subpart.
f6O41a Definition*.
As used in this subpart, all terms not
defined herein shall have the meaning
given them in the Act and in subpart A
of this part.
"Steam generating unit" means any
furnace, boiler, or other device nsed for
combusting fuel for the purpose of
producing steam (including fossil-fuel-
fired steam generators associated with
combined cycle gas turbines; nuclear
steam generators are not included].
"Electric utility steam generating unit"
means any steam electric generating
unit that is constructed for the purpose
of supplying more than one-third of its
potential electric output capacity and
more than 25 MW electrical output to
any utility power distribution system for
sale. Any steam supplied to a steam
distribution system for the purpose of
providing steam to a steam-electric
generator that would produce electrical
energy for sale is also considered in
determining the electrical energy output
capacity of the affected facility.
"Fossil fuel" means natural gas,
petroleum, coal, and any form of solid,
liquid, or gaseous fuel derived from each
material for the purpose of creating
useful heat.
"Sabbiruminoos coal" means coal that
is classified as subbitaminoos A, B, or C
according to the American Society of
Testing and Materials' (ASTM)
Standard Specification for Classification
of Coals by Rank 0368-66.
"Lignite" means coal that is classified
as lignite A or B according to the
American Society of Testing and
Material*' (ASTM] Standard
Specification for Classification of Coals
by Rank 0388-06.
"Coal refuse" means waste products
of coal mining, physical coal cleaning,
and coal preparation operations (e.g.
culm, gob, etc.) containing coal, matrix
material, clay, and other organic and
inorganic material.
"Potential combustion concentration"
means the theoretical emissions (ng/J,
Ib/million Btu heat input) that would
result from combustion of a fuel in an
uncieaned state Owithout emission
control systems) and:
(a) For particulate matter is:
(1) 3,000 ng/J (7.0 ib/million Btu) beat
input for solid fuel; and
(2) 75 ng/J (0.17 Ib/millionBtu) heat
input for liquid fuels.
(b) For sulfur dioxide is determined
under § 60.48a(b).
(c) For nitrogen oxides is:
(1) 290 ng/J (0.67 Ib/million Btu) heat
input for gaseous fuels;
(2) 310 ng/J (0.72 Ib/million Btu) heat
input for liquid fuels; and
(3) 990 ng/J (2.30 Ib/million Btu) heat
input for solid fuels.
"Combined cycle gas turbine" means
a stationary turbine combustion system
where heat from the turbine exhaust
gases is recovered fay a steam
generating unit
"Interconnected" means that two or
more electric generating units are
electrically tied together by a network of
power transmission lines, and other
power transmission equipment
"Electric utility company" means the
largest interconnected organization,
business, or governmental entity that
generates electric power for sale (e.g., a
holding company with operating
subsidiary companies).
"Principal company" means the
electric utility company or companies
which own the affected facility.
"Neighboring company" means any
one of those electric utility companies
with one or more electric power
interconnections to the principal
company and which have
geographically adjoining service areas.
"Net system capacity" means the sum
of the net electric generating capability
(not necessarily equal to rated capacity)
of all electric generating equipment
owned by an electric utility company
(including steam generating units,
internal combustion engines, gas
turbines, rmciear units, hydroelectric
units, and all other electric generating
equipment) pins firm contractual
purchases that are interconnected to the
affected facility that has the
malfunctioning flue gas desulfurization
system. The electric generating
capability of equipment under multiple
ownership is prorated based on
ownership unless the proportional
entitlement to electric output is
otherwise established fay contractual
arrangement
"System load" means the entire
electric demand of an electric utility
company's service area interconnected
with the affected facility that has the
malfunctioning flue gas desulfurization
system phis firm contractual sales to
other electric utility companies. Sales to
other electric utility companies (ag.,
emergency power) not on a firm
contractual basis may also be included
in the system load when no available
system capacity exists in the electric
utility company to which the power is
supplied for sale.
"System emergency reserves" means
an amount of electric generating
capacity equivalent to the rated
capacity of the single largest electric
generating unit in the electric utility
company (including steam generating
units, internal combustion engines, gas
turbines, nuclear units, hydroelectric
units, and all other electric generating
equipment) which is interconnected with
the affected facility that has the
Malfunctioning flue gas desulfurization
system. The electric generating
capability of equipment under multiple
ownership is prorated based on
ownership unless the proportional
entitlement to electric output is
otherwise established by contractual
arrangement.
"Available system capacity" means
the capacity determined by subtracting
the system load and the system
emergency reserves from the net system
capacity.
"Spinning reserve" means the sum of
the unutilized net generating capability
of all units of the electric utility
company that are synchronized to the
power distribution system and that are
capable of immediately accepting
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additional load. The electric generating
capability of equipment under multiple
ownership is prorated based on
ownership unless the proportional
entitlement to electric output is
otherwise established by contractual
arrangement.
"Available purchase power" means
the lesser of the following:
(a) The sum of available system
capacity in all neighboring companies.
(b) The sum of the rated capacities of
the power interconnection devices
between the principal company and all
neighboring companies, minus the sum
of the electric power load on these
interconnections.
(c) The rated capacity, of the power
transmission lines between the power
interconnection devices and the electric
generating units (the unit in the principal
company that has the malfunctioning
flue gas desulfurization system and the
unit(s) in the neighboring company
supplying replacement electrical power)
less the electric power load on these
transmission lines.
"Spare flue gas desulfurization system
module" means a separate system of
sulfur dioxide emission control
equipment capable of treating an /
amount of flue gas equal to the total
amount of flue gas generated by an
affected facility when operated at
maximum capacity divided by the total
number of nonspare flue gas
desulfurization modules in the system.
"Emergency condition" means that
period of time when:
(a) The electric generation output of
an affected facility with a
malfunctioning flue gas desulfurization
system cannot be reduced or electrical
output must be increased because:
(1) All available system capacity in
the principal company interconnected
with the affected facility is being
operated, and
(2) All available purchase power
interconnected with the affected facility
is being obtained, or
(b) The electric generation demand is
being shifted as quickly as possible from
an affected facility with a
malfunctioning flue gas desulfurization
system to one or more electrical
generating units held in reserve by the
principal company or by a neighboring
company, or
{c) An affected facility with a
malfunctioning flue gas desulfurization
system becomes the only available unit
to maintain a part or all of the principal
company's system emergency reserves
and the unit is operated in spinning
reserve at the lowest practical electric
generation load consistent with not
causing significant physical damage to
the unit. If the unit is operated at a
higher load to meet load demand, an
emergency condition would not exist
unless the conditions under (a) of this
definition apply.
"Electric utility combined cycle gas
turbine" means any combined cycle gas
turbine used for electric generation that
is constructed for the purpose of
supplying more than one-third of its
potential electric output capacity and
more than 25 MW electrical output to
any utility power distribution system for
sale. Any steam distribution system that
is constructed for the purpose of
providing steam to a steam electric
generator that would produce electrical
power for sale is also considered in
determining the electrical energy output
capacity of the affected facility.
"Potential electrical output capacity"
is defined as 33 percent of the maximum
design heat input capacity of the steam
generating unit (e.g., a steam generating
unit with a 100-MW (340 million Btu/hr)
fossil-fuel heat input capacity would
have a 33-MW potential electrical
output capacity). For electric utility
combined cycle gas turbines the
potential electrical output capacity is
determined on the basis of the fossil-fuel
firing capacity of the steam generator
exclusive of the heat input and electrical
power contribution by the gas turbine.
"Anthracite" means coal that is
classified as anthracite according to the
American Society of Testing and
Materials' (ASTM) Standard
Specification for Classification of Coals
by Rank D388-66.
"Solid-derived fuel" means any solid,
liquid, or gaseous fuel derived from solid
fuel for the purpose of creating useful
heat and includes, but is not limited to,
solvent refined coal, liquified coal, and
gasified coal.
"24-hour period" means the period of
time between 12:01 a.m. and 12:00
midnight.
"Resource recovery unit" means a
facility that combusts more than 75
percent non-fossil fuel on a quarterly
(calendar) heat input basis.
"Noncontinental area" means the
State of Hawaii, the Virgin Islands,
Guam, American Samoa, the
Commonwealth of Puerto Rico, or the
Northern Mariana Islands.
"Boiler operating day" means a 24-
hour period during which fossil fuel is
combusted in a steam generating unit for
the entire 24 hours.
§ 60.42a Standard for participate matter.
(a) On and after the date on which the
performance test required to be
conducted under § 60.8 is completed, no
owner or operator subject to the
provisions of this subpart shall cause to
be discharged into the atmosphere from
any affected facility any gases which
contain particulate matter in excess of:
(1) 13 ng/J (0.03 Ib/million Btu) heat
input derived from the combustion of
solid, liquid, or gaseous fuel;
(2) 1 percent of the potential
combustion concentration (99 percent
reduction) when combusting solid fuel;
and
(3) 30 percent of potential combustion
concentration (70 percent reduction)
when combusting liquid fuej.
(b) On and after the date the
particulate matter performance test
required to be conducted under § 60.8 is
completed, no owner or operator subject
to the provisions of this subpart shall
cause to be discharged into the
atmosphere from any affected facility
any gases which exhibit greater than 20
percent opacity (6-minute average),
except for one 6-minute period per hour
of not more than 27 percent opacity.
§ 60.43a Standard for sulfur dioxide.
(a) On and after the date on which the
initial performance test required to be
conducted under § 60.8 is completed, no
owner or operator subject to the
provisions of this subpart shall cause to
be discharged into the atmosphere from
any affected facility which combusts
solid fuel or solid-derived fuel, except as
provided under paragraphs (c), (d), (f) or
(h) of this section, any gases which
contain sulfur dioxide in excess of:
(1) 520 ng/J (1.20 Ib/million Btu) heat
input and 10 percent of the potential
combustion concentration (90 percent
reduction), or
(2) 30 percent of the potential
combustion concentration (70 percent
reduction), when emissions are less than
260 ng/J (0.60 Ib/million Btu) heat input.
(b) On and after the date on which the
initial performance test required to be
conducted under § 60.8 is completed, no
owner or operator subject to the
provisions of this subpart shall cause to
be discharged into the atmosphere from
any affected facility which combusts
liquid or gaseous fuels (except for liquid
or gaseous fuels derived from solid fuels
and as provided under paragraphs (e) or
(h) of this section), any gases which
contain sulfur dioxide in excess of:
(1) 340 ng/J (0.80 Ib/million Btu) heat
input and 10 percent of the potential
combustion concentration (90 percent
reduction), or
(2) 100 percent of the potential
combustion concentration (zero percent
reduction) when emissions are less than
86 ng/J (0.20 Ib/million Btu) heat input.
(c) On and after the date on which the
initial performance test required to be
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conducted under § 60.8 is complete, no
owner or operator subject to the
provisions of this subpart shall cause to
be discharged into the atmosphere from
any affected facility which combusts
solid solvent refined coal (SRC-I) any
gases which contain sulfur dioxide in
excess of 520 ng/J (1.20 Ib/million Btu)
heat input and 15 percent of the
potential combustion concentration (85
percent reduction) except as provided
under paragraph (f) of this section;
compliance with the emission limitation
is determined on a 30-day rolling
average basis and compliance with the
percent reduction requirement is
determined on a 24-hour basis.
(d) Sulfur dioxide emissions are
limited to 520 ng/J (1.20 Ib/million Btu)
heat input from any affected facility
which:
(1) Combusts 100 percent anthracite,
(2) Is classified as a resource recovery
facility, or
(3) Is located in a noncontinental area
and combusts solid fuel or solid-derived
fuel.
(e) Sulfur dixoide emissions are
limited to 340 ng/J (0.80 Ib/million Btu)
heat input from any affected facility
which is located in a noncontinental
area and combusts liquid or gaseous
fuels (excluding solid-derived fuels).
(f) The emission reduction
requirements under this section do not
apply to any affected facility that is
operated under an SO, commercial
demonstration permit issued by the
Administrator in accordance with the
provisions of § 60.45a.
(g) Compliance with the emission
limitation and percent reduction
requirements under this section are both
determined on a 30-day rolling average
basis except as provided under
paragraph (c) of this section.
(h) When different fuels are
combusted simultaneously, the
applicable standard is determined by
proration using the following formula:
(1) If emissions of sulfur dioxide to the
atmosphere are greater than 260 ng/J
(0.60 Ib/million Btu) heat input
En, = (340 x + 520 y]/100 and
PIO, 10 percent
(2) It emissions of sulfur dioxide to the
atmosphere are equal to or less than 260
ng/J (0.60 Ib/million Btu) heat input:
Ego, = (340 x -f 520 y]/100 and
Pso, =(90x + 70y]/100
where:
Ego, is the prorated sulfur dioxide emission
limit (ng/J heat input),
PIO, is the percentage of potential sulfur
dioxide emission allowed (percent
reduction required 100PIO,],
x is the percentage of total heat input derived
from the combustion of liquid or gaseous
fuels (excluding solid-derived fuels)
y is the percentage of total heat input derived
from the combustion of solid fuel
(including solid-derived fuels)
{ 60.44a Standard for nitrogen oxides.
(a) On and after the date on which the
initial performance test required to be
conducted under § 60.8 is completed, no
owner or operator subject to the
provisions of this subpart shall cause to
be discharged into the atmosphere from
any affected facility, except as provided
under paragraph (b) of this section, any
gases which contain nitrogen oxides in
excess of the following emission limits,
based on a 30-day rolling average.
(1) NO, Emission Limits
Fuel type
Gaseous Fuels:
Coal-denved fuels
All other fuels
liquid Fuels
Coal-derived fuel*
Shale oil ,.
AH other fuel*..
SoMFuete:
Coal-dertved fuels
Any fuel containing more than
25%, by weight, coal refuse .
Any fuel containing more than
25%, by weight (grata If the
Agrafe n mined in North
Dakota, South Dakota, or
Montana, and * combusted
In a slag tap furnace .._ _
Ugrate not subject to the 340
ng/J heat input emission Hmtt
Subbrtummous coal
BftummoMS COftl ,,,
Anthracite coal..... ,,
All other fuels
Emission fentt
ng/J (Ib/mlhon Btu)
heat Input
210 $.50)
66 (0.20)
210 (0.50)
210 J0.50)
130 (0.30)
210 (0.50)
Exempt from NO?
standards and NO,
monitoring
requirement*
340 (0.80)
260 (060)
210 (0.50)
260 (0.60)
860 (060)
260 (0.60)
(2) NOX reduction requirements
Fuel type
Percent reduction
of potential
combustion
concentration
Gaseous fuels....
liquid fuels..
Solid fuels....
25%
30%
65%
(b) The emission limitations under
paragraph (a) of this section do not
apply to any affected facility which is
combusting coal-derived liquid fuel and
is operating under a commercial
demonstration permit issued by the
Administrator in accordance with the
provisions of § 60.45a.
(c) When two or more fuels are
combusted simultaneously, the
applicable standard is determined by
proration using the following formula:
*(86 w+130 x+210 y+260 zj/100
where;
ENO, '» the applicable standard for nitrogen
oxides when multiple fuels are
combusted simultaneously (ng/J heat
input);
w is the percentage of total heat input
derived from the combustion of fuels
subject to the 86 ng/J heat input
standard;
x is the percentage of total heat input derived
from the combustion of fuels subject to
the 130 ng/J heat input standard;
y is the percentage of total heat input derived
from the combustion of fuels subject to
the 210 ng/J heat input standard; and
2 is the percentage of total heat input derived
from the combustion of fuels subject to
tie 260 ngf] heat input standard.
i 60.45a Commercial demonstration
permit
(a) An owner or operator of an
affected facility proposing to
demonstrate an emerging technology
may apply to the Administrator for a
commercial demonstration permit. The
Administrator will issue a commercial
demonstration permit in accordance
with paragraph (e) of this section.
Commercial demonstration permits may
be isfiued only by the Administrator,
and this authority will not be delegated.
(b) An owner or operator of an
affected facility that combusts solid
solvent refined coal (SRC-I) and who is
issued a commercial demonstration
permit by the Administrator is not
subject to the SOj emission reduction
requirements under § 60.43a(c) but must,
as a minimum, reduce SO, emissions to
20 percent of the potential combustion
concentration (80 percent reduction) for
each 24-hour period of steam generator
operation and to less than 520 ng/J (1.20
Ib/million Btu) heat input on a 30-day
rolling average basis.
(c) An owner or operator of a fluidized
bed combustion electric utility steam
generator (atmospheric or pressurized)
who is issued a commercial
demonstration permit by the
Administrator is not subject to the SO»
emission reduction requirements under
§ 60.43a(a) but must, as a minimum,
reduce SOa emissions to 15 percent of
the potential combustion concentration
(85 percent reduction) on a 30-day
rolling average basis and to less than
520 ng/J (1.20 Ib/million Btu) heat input
on a 30-day rolling average basis.
(d) The owner or operator of an
affected facility that combusts coal-
derived liquid fuel and who is issued a
commercial demonstration permit by the
Administrator is not subject to the
applicable NO, emission limitation and
percent reduction under § 60.44a(a) but
must, as a minimum, reduce emissions
to less than 300 ng/J (0.70 Ib/million Btu)
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heat input on a 30-day rolling average
basis.
(e) Commercial demonstration permits
may not exceed the following equivalent
MW electrical generation capacity for
any one technology category, and the
.total equivalent MW electrical
generation capacity for all commercial
demonstration plants may not exceed
15.000 MW.
Technology
Equhwtenl
Metrical
Pohitar* capacity
(MWrtectncal
output)
Solid toKwnt noned coal
(SHC !)..._ ........ _ ............
FUfzed tod contwstion
SO, 6,000-10,000
SO. 400-3400
FludRed bed combustion
(pfesjwrized) .......... .... ......
so,
NO,
Total afcMabto tor el
400-1.200
750-10,000
15.000
|W.46a Compliance provision*.
(a) Compliance with the particulate
matter emission limitation under
| 60.42a(a)(l) constitutes compliance
with the percent reduction requirements
for particulate matter under
§ 60.42a(a)[2) and (3).
(b) Compliance with the nitrogen
oxides emission limitation under
S 60.44a(a) constitutes compliance with
the percent reduction requirements
under $ 60.44a(a){2).
(c) The particulate matter emission
standards under 160.42a and the
nitrogen oxides emission standards
under § 60.44a apply at all times except
during periods of startup, shutdown, or
malfunction. The sulfur dioxide emission
standards under { 60.43a apply at all
times except during periods of startup,
shutdown, or when both emergency
conditions exist and the procedures
under paragraph (d) of this section are
implemented.
(d) During emergency conditions in
the principal company, an affected
facility with a malfunctioning flue gas
desulfurization system may be operated
if sulfur dioxide emissions are
minimized by:
(1) Operating all operable flue gas
desulfurization system modules, and
bringing back into operation any
malfunctioned module as soon as
repairs are completed,
(2) Bypassing flue gases around only
those flue gas desulfurization system
modules that have been taken out of
operation because they were incapable
of any sulfur dioxide emission reduction
or which would have suffered significant
physical damage if they had remained in
operation, and
(3) Designing, constructing, and
operating a spare flue gas
desulfurization system module for an
affected facility larger than 365 MW
(1,250 million Btu/hr) heat input
(approximately 125 MW electrical
output capacity). The Administrator
may at his discretion require the owner
or operator within 80 days of
notification to demonstrate spare
module capability. To demonstrate this
capability, the owner or operator must
demonstrate compliance with the
appropriate requirements under
paragraph (a), (b), (d), (e), and (i) under
} 60.43a for any period of operation
lasting from 24 hours to 30 days when:
(i) Any one flue gas desulfurization
module is not operated,
(ii) The affected facility is operating at
the maximum heat input rate,
(iii) The fuel fired during the 24-hour
to 30-day period is representative of the
type and average sulfur content of fuel
used over a typical 30-day period, and
(iv) The owner or operator has given
the Administrator at least 30 days notice
of the date and period of time over
which the demonstration will be
performed.
(e) After the initial performance test
required under § 60.8, compliance with
the sulfur dioxide emission limitations
and percentage reduction requirements
under § 60.43a and the nitrogen oxides
emission limitations under § 60.44a is
based on the average emission rate for
30 successive boiler operating days. A
separate performance test is completed
at the end of each boiler operating day
after the initial performance test, and a
new 30 day average emission rate for
both sulfur dioxide and nitrogen oxides
and a new percent reduction for sulfur
dioxide are calculated to show
compliance with the standards.
(f) For the initial performance test
required under $ 60.8, compliance with
the sulfur dioxide emission limitations
and percent reduction requirements
under $ 60.43a and the nitrogen oxides
emission limitation under S 60.44a is
based on the average emission rates for
sulfur dioxide, nitrogen oxides, and
percent reduction for sulfur dioxide for
the first 30 successive boiler operating
days. The initial performance test is the
only test in which at least 30 days prior
notice is required unless otherwise
specified by the Administrator. The
initial performance test is to be
scheduled so that the first boiler
operating day of the 30 successive boiler
operating days is completed within 60
days after achieving the maximum
production rate at which the affected
facility will be operated, but not later
than 180 days after initial startup of the
facility.
(g) Compliance is determined by
calculating the arithmetic average of all
hourly emission rates for SO* and NO,
for the 30 successive boiler operating
days, except for data obtained during
startup, shutdown, malfunction (NO,
only), or emergency conditions (SO»
only). Compliance with the percentage
reduction requirement for SO, is
determined based on the average inlet
and average outlet SO, emission rates
for the 30 successive boiler operating
days.
(h) If an owner or operator has not
obtained the minimum quantity of
emission data as required under § 60.47a
.of this subpart, compliance of the
affected facility with the emission
requirements under $ $ 60.43a and 60.44a
of this subpart for the day on which the
30-day period ends may be determined
by the Administrator by following the
applicable procedures in sections 6.0
and 7.0 of Reference Method 19
(Appendix A).
}60.47« Enrisskm monitoring.
(a) The owner or operator of an
affected facility shall install, calibrate,
maintain, and operate a continuous
monitoring system, and record the
output of the system, for measuring the
opacity of emissions discharged to the
atmosphere, except where gaseous fuel
is the only fuel combusted. If opacity
interference due to water droplets exists
in the stack (for example, from the use
of an FGD system), the opacity is
monitored upstream of the interference
(at the inlet to the FGD system). If
opacity interference is experienced at
all locations (both at the inlet and outlet
of the sulfur dioxide control system),
alternate parameters indicative of the
particulate matter control system's
performance are monitored (subject to
the approval of the Administrator).
(b) The owner or operator of an
affected facility shall install calibrate.
maintain, and operate a continuous
monitoring system, and record the
output of the system, for measuring
sulfur dioxide emissions, except where
natural gas is the only fuel combusted.
as follows:
(1) Sulfur dioxide emissions are
monitored at both the inlet and outlet of
the sulfur dioxide control device.
(2) For e facility which qualifies under
the provisions of { 60.43a(d), sulfur
dioxide emissions are only monitored
discharged to the atmosphere.
(3) An "as fired" fuel monitoring
system (upstream of coal pulverizers)
meeting the requirement* of Method 19
(Appendix A) may be used to determine
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potential sulfur dioxide emissions in
place of a continuous sulfur dioxide
emission monitor at the inlet to the
sulfur dioxide control device as required
under paragraph (b)(l) of this section.
(c) The owner or operator of an
affected facility shall install, calibrate,
maintain, and operate a continuous
monitoring system, and record the
output of the system, for measuring
nitrogen oxides emissions discharged to
the atmosphere.
(d) The owner or operator of an
affected facility shall install, calibrate,
maintain, and operate a continuous
monitoring system, and record the
output of the system, for measuring the
oxygen or carbon dioxide content of the
flue gases at each location where sulfur
dioxide or nitrogen oxides emissions are
monitored.
(e) The continuous monitoring
systems under paragraphs (b), (c), and
(d) of this section are operated and data
recorded during all periods of operation
of the affected facility including periods
of startup, shutdown, malfunction or
emergency conditions, except for
continuous monitoring system
breakdowns, repairs, calibration checks,
and zero and span adjustments.
(f) When emission data are not
obtained because of continuous
monitoring system breakdowns, repairs,
calibration checks and zero and span
adjustments, emission data will be
obtained by using other monitoring
systems as approved by the
Administrator or the reference methods
as described in paragraph (h) of this
section to provide emission data for a
minimum of 18 hours in at least 22 out of
30 successive boiler operating days.
(g) The 1-hour averages required
under paragraph § 60.13(h) are
expressed in ng/J (Ibs/million Btu) heat
input and used to calculate the average
emission rates under § 60.46a. The 1-
hour averages are calculated using the
data points required under § 60.13(b). At
least two data points must be used to
calculate the 1-hour averages.
(h) Reference methods used to
supplement continuous monitoring
system data to meet the minimum data
requirements in paragraph § 60.47a(f)
will be used as specified below or
otherwise approved by the
Administrator.
(1) Reference Methods 3,6, and 7, as
applicable, are used. The sampling
location(s) are the same as those used
for the continuous monitoring system.
(2) For Method 6, the minimum
sampling time is 20 minutes and the
minimum sampling volume is 0.02 dscm
(0.71 dscf) for each sample. Samples are
taken at approximately 60-minute
intervals. Each sample represents a 1-
hour average.
(3) For Method 7, samples are taken at
approximately 30-minute intervals. The
arithmetic average of these two
consective samples represent a 1-hour
average.
(4) For Method 3, the oxygen or
carbon dioxide sample is to be taken for
each hour when continuous SOj and
NO, data are taken or when Methods 6
and 7 are required. Each sample shall be
taken for a minimum of 30 minutes in
each hour using the integrated bag
method specified in Method 3. Each
sample represents a 1-hour average.
(5) For each 1-hour average, the
emissions expressed in ng/J (Ib/million
Btu) heat input are determined and used
as needed to achieve the minimum data
requirements of paragraph (f) of this
section.
(i) The following procedures are used
to conduct monitoring system
performance evaluations under
§ 60.13(c) and calibration checks under
§ 60.13(d).
(1) Reference method 6 or 7, as
applicable, is used for conducting
performance evaluations of sulfur
dioxide and nitrogen oxides continuous
monitoring systems.
(2) Sulfur dioxide or nitrogen oxides,
as applicable, is used for preparing
calibration gas mixtures under
performance specification 2 of appendix
B to this part.
(3) For affected facilities burning only
fossil fuel, the span value for a
continuous monitoring system for
measuring opacity is between 60 and 80
percent and for a continuous monitoring
system measuring nitrogen oxides is
determined as follows:
Fostffuel
Span value for
nitrogen oxides (ppm)
Gas
Uqud _,
SoM
Combination..
500
500
1,000
500 (x+y)+1.000Z
where:
x is the fraction of total heat input derived
from gaseous fossil fuel,
y is the fraction of total heat input derived
from liquid fossil fuel, and
z is the fraction of total heat input derived
from solid fossil fuel.
(4) All span values computed under
paragraph (b)(3) of this section for
burning combinations of fossil fuels are
rounded to the nearest 500 ppm.
(5) For affected facilities burning fossil
fuel, alone or in combination with non-
fossil fuel, the span value of the sulfur
dioxide continuous monitoring system at
the inlet to the sulfur dioxide control
device is 125 percent of the maximum
estimated hourly potential emissions of
the fuel fired, and the outlet of the sulfur
dioxide control device is 50 percent of
maximum estimated hourly potential
emissions of the fuel fired.
(Sec. 114, Clean Air Act as amended (42
U.S.C. 7414).)
§ 60.48a Compliance determination
procedures and methods.
(a) The following procedures and
reference methods are used to determine
compliance with the standards for
particulate matter under § 60.42a.
(1) Method 3 is used for gas analysis
when applying method 5 or method 17.
(2) Method 5 is used for determining
particulate matter emissions and
associated moisture content. Method 17
may be used for stack gas temperatures
less than 160 C (320 F).
(3) For Methods 5 or 17, Method 1 is
used to select the sampling site and the
number of traverse sampling points. The
sampling time for each run is at least 120
minutes and the minimum sampling
volume is 1.7 dscm (60 dscf) except thai
smaller sampling times or volumes,
when necessitated by process variables
or other factors, may be approved by the
Administrator.
(4) For Method 5, the probe and filter
holder heating system in the sampling
train is set to provide a gas temperature
no greater than 160°C (32°F).
(5) For determination of particulate
emissions, the oxygen or carbon-dioxide
sample is obtained simultaneously with
each run of Methods 5 or 17 by
traversing the duct at the same sampling
location. Method 1 is used for selection
of the number of traverse points except
that no more than 12 sample joints are
required.
(6) For each run using Methods 5 or 17,
the emission rate expressed in ng/J heat
input is determined using the oxygen or
carbon-dioxide measurements and
particulate matter measurements
obtained under this section, the dry
basis Fc-factor and the dry basis
emission rate calculation procedure
contained in Method 19 (Appendix A).
(7) Prior to the Administrator's
issuance of a particulate matter
reference method that does not
experience sulfuric acid mist
interference problems, particulate
matter emissions may be sampled prior
to a wet flue gas desulfurization system.
(b) The following procedures and
methods are used to determine
compliance with the sulfur dioxide
standards under § 60.43a.
(1) Determine the percent of potential
combustion concentration (percent PCC)
emitted to the atmosphere as follows:
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(I) Fuel Pretreatment (% Rf):
Determine the percent reduction
achieved by any fuel pretreatment using
the procedures in Method 19 (Appendix
A). Calculate the average percent
reduction for fuel pretreatment on a
quarterly basis using fuel analysis data.
The determination of percent R( to
calculate the percent of potential
combustion concentration emitted to the
atmosphere is optional. For purposes of
determining compliance with any
percent reduction requirements under
{ 60.43a, any reduction in potential SO»
emissions resulting from the following
processes may be credited:
(A) Fuel pretreatment (physical coal
cleaning, hydrodesulfurization of fuel
oil, etc.).
(B) Coal pulverizers, and
(C) Bottom and flyash interactions.
(ii) Sulfur Dioxide Control System (%
Rt): Determine the percent sulfur
dioxide reduction achieved by any
sulfur dioxide control system using
' emission rates measured before and
after the control system, following the
procedures in Method 19 (Appendix A);
or, a combination of an "as fired" fuel
monitor and emission rates measured
after the control system, following the
procedures in Method 19 (Appendix A).
When the "as fired" fuel monitor is
used, the percent/reduction is calculated
using the average emission rate from the
sulfur dioxide control device and the
average SO« input rate from the "as
fired" fuel analysis for 30 successive
boiler operating days.
(iii) Overall percent reduction (% Ra):
Determine the overall percent reduction
using the results obtained in paragraphs
(b)(l) (i) and (ii) of this section following
the procedures in Method 19 (Appendix
A). Results are calculated for each 30-
day period using the quarterly average
percent sulfur reduction determined for
fuel pretreatment from the previous
quarter and the sulfur dioxide reduction
achieved by a sulfur dioxide control
system for each 30-day period in the
current quarter.
(iv) Percent emitted (% PCC):
Calculate the percent of potential
combustion concentration emitted to the
atmosphere using the following
equation: Percent PCC = 100-Percent R,,
(2) Determine the sulfur dioxide
emission rates following the procedures
in Method 19 (Appendix A).
(c) The procedures and methods
outlined in Method 19 (Appendix A) are
used in conjunction with the 30-day
nitrogen-oxides emission data collected
under § 60.47a to determine compliance
with the applicable nitrogen oxides
standard under § 60.44.
(d) Electric utility combined cycle gas
turbines are performance tested for
particulate matter, sulfur dioxide, and
nitrogen oxides using the procedures of
Method 19 (Appendix A). The sulfur
dioxide and nitrogen oxides emission
rates from the gas turbine used in
Method 19 (Appendix A) calculations
are determined when the gas turbine is
performance tested under subpart GG.
The potential uncontrolled particulate
matter emission rate from a gas turbine
is defined as 17 ng/J (0.04 Ib/million Btu)
heat input
J 60.49a Reporting requirements.
(a) For sulfur dioxide, nitrogen oxides,
and particulate matter emissions, the
performance test data from the initial
performance test and from the
performance evaluation of the
continuous monitors (including the
transmissometer) are submitted to the
Administrator.
(b) For sulfur dioxide and nitrogen
oxides the following information's
reported to the Administrator for each
24-hour period.
(1) Calendar date.
(2) The average sulfur dioxide and
nitrogen oxide emission rates (ng/J or
Ib/million Btu) for each 30 successive
boiler operating days, ending with the
last 30-day period in the quarter;
reasons for non-compliance with the
emission standards; and, description of
corrective actions taken.
(3) Percent reduction of the potential
combustion concentration of sulfur
dioxide for each 30 successive boiler
operating days, ending with the last 30-
day period in the quarter; reasons for
non-compliance with the standard; and,
description of corrective actions taken.
(4) Identification of the boiler
operating days for which pollutant or
dilutent data have not been obtained by
an approved method for at least 18
hours of operation of the facility;
justification for not obtaining sufficient
data; and description of corrective
actions taken.
(5) Identification of the times when
emissions data have been excluded from
the calculation of average emission
rates because of startup, shutdown,
malfunction (NO, only), emergency
conditions (SOi only), or other reasons,
and justification for excluding data for
reasons other than startup, shutdown,
malfunction, or emergency conditions.
(6) Identification of "F" factor used for
calculations, method of determination,
and type of fuel combusted.
(7) Identification of times when hourly
averages have been obtained based on
manual sampling methods.
(B) Identification of the times when
the pollutant concentration exceeded
full span of the continuous monitoring
system.
(9) Description of any modifications to
the continuous monitoring system which
could affect the ability of the continuous
monitoring system to comply with
Performance Specifications 2 or 3.
(c) If the minimum quantity of
emission data as required by § 60.47a is
not obtained for any 30 successive
boiler operating days, the following
information obtained under the
requirements of § 60.46a(h) is reported
to the Administrator for that 30-day
period:
(1) The number of hourly averages
available for outlet emission rates (n,,)
and inlet emission rates (n,) as
applicable.
(2) The standard deviation of hourly
averages for outlet emission rates (s0)
and inlet emission rates (s,j as
applicable.
(3) The lower confidence limit for the
mean outlet emission rate (E0*) and the
upper confidence limit for the mean inlet
emission rate (E|*) as applicable.
(4) The applicable potential
combustion concentration.
(5) The ratio of the upper confidence
limit for the mean outlet emission rate
(£*) and the allowable emission rate
(E«d) as applicable.
(d) If any standards under § 60.43a are
exceeded during emergency conditions
because of control system malfunction,
the owner or operator of the affected
facility shall submit a signed statement:
(1) Indicating if-emergency conditions
existed and requirements under
§ 60.46a(d) were met during each period,
and
(2) Listing the following information:
(i) Time periods the emergency
condition existed;
(ii) Electrical output and demand on
the owner or operator's electric utility
system and the affected facility;
(iii) Amount of power purchased from
interconnected neighboring utility
companies during the emergency period;
(iv) Percent reduction in emissions
achieved;
(v) Atmospheric emission rate fng/J)
of the pollutant discharged; and
(vi) Actions taken to correct control
system malfunction.
(e) If fuel pretreatment credit toward
the sulfur dioxide emission standard
under § 60.43a is claimed, the owner or
operator of the affected facility shall
submit a signed statement:
(1) Indicating what percentage
cleaning credit was taken for the
calendar quarter, and whether the credit
was determined in accordance with the
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provisions of § 60.48a and Method 19
(Appendix A); and
(2) Listing the quantity, heat content,
and date each pretreated fuel shipment
was received during the previous
quarter; the name and location of the
fuel pretreatment facility; and the total
quantity and total heat content of all
fuels received at the affected facility
during the previous quarter.
(f) For any periods for which opacity,
sulfur dioxide or nitrogen oxides
emissions data are not available, the
owner or operator of the affected facility
shall submit a signed statement
indicating if any changes were made in
operation of the emission control system
during the period of data unavailability.
Operations of the control system and
affected facility during periods of data
unavailability are to be compared with
operation of the control system and
affected facility before and following the
period of data unavailability.
(g) The owner or operator of the
affected facility shall submit a signed
statement indicating whether:
(1) The required continuous
monitoring system calibration, span, and
drift checks or other periodic audits
have or have not been performed as
specified.
(2) The data used to s^how compliance
was or was not obtained in accordance
with approved methods and procedures
of this part and is representative of
plant performance.
(3) The .minimum data requirements
have or have not been met; or, the
minimum data requirements have not
been met for errors that were
unavoidable. v
(4) Compliance with the standards has
or has not been achieved during the
reporting period.
(h) For the purposes of the reports
required under § 60.7, periods of excess
emissions are defined as all 6-minute
periods during which the average
opacity exceeds the applicable opacity
standards under § 60.42a(b). Opacity
levels in excess of the applicable
opacity standard and the date of such
excesses are to be submitted to the
Administrator each calendar quarter.
(i) The owner or operator of an
affected facility shall submit the written
reports required under this section and
subpart A to the Administrator for every
calendar quarter. All quarterly reports
shall be postmarked by the 30th day
following the end of each calendar
quarter.
(Sec. 114, Clean Air Act as amended (42
U.S.C. 7414).)
4. Appendix A to part 60 is amended
by adding new reference Method 19 as
follows:
Appendix AReference Methods
Method 19. Determination of Sulfur
Dioxide Removal Efficiency and
Particulate, Sulfur Dioxide and Nitrogen
Oxides Emission Rates From Electric
Utility Steam Generators
1. Principle and Applicability
.1 Principle.
1.1.1 Fuel samples from before and
after fuel pretreatment systems are
collected and analyzed for sulfur and
heat content, and the percent sulfur
dioxide (ng/Joule, Ib/million Bru)
reduction is calculated on a dry basis.
(Optional Procedure.)
1.1.2 Sulfur dioxide and oxygen or
carbon dioxide concentration data
obtained from sampling emissions
upstream and downstream of sulfur
dioxide control devices are used to
calculate sulfur dioxide removal
efficiencies. (Minimum Requirement.) As
an alternative to sulfur dioxide
monitoring upstream of sulfur dioxide
control devices, fuel samples may be
collected in an as-fired condition and
analyzed for sulfur and heat content.
(Optional Procedure.)
1.1.3 An overall sulfur dioxide
emission reduction efficiency is
calculated from the efficiency of fuel
pretreatment systems and the efficiency
of sulfur dioxide control devices.
1.1.4 Particulate, sulfur dioxide,
nitrogen oxides, and oxygen or carbon
dioxide concentration data obtained
from sampling emissions downstream
from sulfur dioxide control devices are
used along with F factors to calculate
particulate, sulfur dioxide, and nitrogen
oxides emission rates. F factors are
values relating combustion gas volume
to the heat content of fuels.
1.2 Applicability. This method is
applicable for determining sulfur
removal efficiencies of fuel pretreatment
and sulfur dioxide control devices and
the overall reduction of potential sulfur
dioxide emissions from electric utility
steam generators. This method is also
applicable for the determination of
particulate, sulfur dioxide, and nitrogen
oxides emission rates.
2. Determination of Sulfur Dioxide
Removal Efficiency of Fuel
Pretreatment Systems
2.1 Solid Fossil Fuel.
2.1.1 Sample Increment Collection.
Use ASTM D 2234'. Type I, conditions
A, B, or C, and systematic spacing.
Determine the number and weight of
increments required per gross sample
representing each coal lot according to
Table 2 or Paragraph 7.1.5.2 of ASTM D
2234'. Collect one gross sample for each
raw coal lot and one gross sample for
each product coal lot.
2.1.2 ASTM Lot Size. For the purpose
of Section 2.1.1, the product coal lot size
is defined as the weight of product coal
produced from one type of raw coal. The
raw coal lot size is the weight of raw
coal used to produce one product coal
lot. Typically, the lot size is the weight
of coal processsed in a 1-day (24 hours)
period. If more than one type of coal is
treated and produced in 1 day, then
gross samples must be collected and
analyzed for each type of coal. A coal
lot size equaling the 90-day quarterly
fuel quantity for a specific power plant
may be used if representative sampling
can be conducted for the raw coal and
product coal.
Note.Alternate definitions of fuel lot
sizes may be specified subject to prior
approval of the Administrator.
2.1.3 Grass Sample Analysis.
Determine the percent sulfur content
(%S) and gross calorific value (GCV) of
the solid fuel on a dry basis for each
gross sample. Use ASTM 2013 for
sample preparation, ASTM D 3177 ] for
sulfur analysis, and ASTM D 3173 ' for
moisture analysis. Use ASTM D 3176 *
for gross calorific value determination.
2.2 Liquid Fossil Fuel.
2.2.1 Sample Collection. Use ASTM
D 270 l following the practices outlined
for continuous sampling for each gross
sample representing each fuel lot.
2JZ.2 Lot Size. For the purposes of
Section 2.2.1, the weight of product fuel
from one pretreatment facility and
intended as one shipment (ship load,
barge load, etc.) is defined as one
product fuel lot. The weight of each
crude liquid fuel type used to produce
one product fuel lot is defined as one
inlet fuel lot.
Note. Alternate deTinitioos of fuel lot
sizes may be specified subject to prior
approval of the Administrator.
Note. For the purposes of this method,
raw or inlet fuel (coal or oil) is defined as the
fuel delivered to the desulfurization
pretreatment facility or to the steam
generating plant. For pretreated oil the input
oil,to the oil desurfurizajion process (e.g.
hydrotreatment emitted) is sampled.
2.2.3 Sample Analysis. Determine
the percent sulfur content (%S) and
gross calorific value (GCV). Use ASTMD
240 l for the sample analysis. This value
can be assumed to be on a dry basis.
1 Use the molt recent revision or designation of
the ASTM procedure specified.
'Use the most recent revision or designation of
the ASTM procedure specified.
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2.3 Calculation of Sulfur Dioxide
Removal Efficiency Due to Fuel
Pretregtment. Calculate the percent
sulfur dioxide reduction due to fuel
pretreatment using the following
equation:
1R. « 100
*VGCVo
SS1/GCV1
Where:
XR<=Sulfur dioxide removal efficiency due
pretreatment; percent.
*S»=Sulfur content of the product fuel lot on
a dry basis; weight percent
%Si=Sulfur content of the inlet fuel lot on a
dry basis; weight percent.
GCV,=Gross calorific value for the outlet
fuel lot on a dry basis; k]/kg (Btu/lb).
GCV,=Gro88 calorific value for the inlet fuel
lot on a dry basis; kj/kg (Btu/lb).
Note.If more than one fuel type is used to
produce the product fuel, use the following
equation to calculate the sulfur contents per
unit of heat content of the total fuel lot %S/
GCV:
SS/GCV
k-1
Where:
Yk«The fraction of total mass input derived
from each type, k. of fuel.
*Sfc= Sulfur content of each fuel type, k/on a
dry basis; weight percent
GCVk=GroBS calorific, value for each fuel
type, k, on a dry basis; kj/kg (Btu/lb).
n The number of different types of fuels.
3. Determination of Sulfur Removal
Efficiency of the Sulfur Dioxide Control
Device
3.1 Sampling. Determine SO»
emission rates at the inlet and outlet of
the sulfur dioxide control system
according to methods specified in the
applicable subpart of the regulations
and the procedures specified in Section
5. The inlet sulfur dioxide emission rate
may be determined through fuel analysis
(Optional, see Section 3.3.)
3.2. Calculation. Calculate the
percent removal efficiency using the
following equation:
100 * (1.0 -
^0
021
Where:
%R, =Sulfur dioxide removal efficiency of
the sulfur dioxide control system using
inlet and outlet monitoring data; percent.
Ego o=Sulfur dioxide emission rate from the
outlet of the sulfur dioxide control
system; ng/J (Ib/million Btu).
- En i=Sulfur dioxide emission rate to the
outlet of the sulfur dioxide control
system; ng/J (Ib/million Btu).
3.3 As-fired Fuel Analysis (Optional
Procedure). If the owner or operator of
an electric utility steam generator
chooses to determine the sulfur dioxide
imput rate at the inlet to the sulfur
dioxide control device through an as-
fired fuel analysis in lieu of data from a
sulfur dioxide control system inlet gas
monitor, fuel samples must be collected
in accordance with applicable
paragraph in Section 2. The sampling
can be conducted upstream of any fuel
processing, e.g., plant coal pulverization.
For the purposes of this section, a fuel
lot size is defined as the weight of fuel
consumed in 1 day (24 hours) and is
directly related to the exhaust gas
monitoring data at the outlet of the
sulfur dioxide control system.
3.3.1 Fuel Analysis. Fuel samples
must be analyzed for sulfur content and
gross calorific value. The ASTM
procedures for determining sulfur
content are defined in the applicable
paragraphs of Section 2.
3.3.2 Calculation of Sulfur Dioxide
Input Rate. The sulfur dioxide imput rate
determined from fuel analysis is
calculated by:
2.0(»Sf
GCV
x 10 for S. I. units.
2.0(JS.) .
g^T x 10 for English units.
Where:
I
Sulfur dioxide Input rate from as-fired fuel analysis,
ng/J (Ib/mUllon Btu).
XSf » Sulfur content of as-fired fuel, on a dry basis; weight
percent.
GCV'» Gross calorific value for as-fired fuel, on a dry basis;
kJ/kg (Btu/lb).
3.3.3 Calculation of Sulfur Dioxide 3.3.2 and the sulfur dioxide emission
Emission Reduction Using As-fired Fuel rate, ESQI, determined in the applicable
Analysis. The sulfur dioxide emission paragraph of Section 5.3. The equation
reduction efficiency is calculated using f°r sulfur dioxide emission reduction
the sulfur imput rate from paragraph efficiency is:
5R
9(f)
100
(1.0 -
Where:
*Rg(f) " Sulfur d1ox'lde removal efficiency of the sulfur
dioxide control system using as-fired fuel analysis
data; percent.
Eso Sulfur dioxide emission rate fron sulfur dioxide control
*U2
system; ng/J (lb/m1lUon Btu).
I$ Sulfur dioxide Input rate from as-fired fuel analysis;
ng/J Ob/nil lion Btu}.
IV-325
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Federal Register / Vol. 44. No. 113 / Monday, June 11, 1979 / Rules and Regulations
4. Calculation of Overall Reduction in
Potential Sulfur Dioxide Emission
4.1 The overall percent sulfur
dioxide reduction calculation uses the
sulfur dioxide concentration at the inlet
to the sulfur dioxide control device as
loon.o- O.o -
the base value. Any sulfur reduction
realized through fuel cleaning is
introduced into the equation as an
average percent reduction, %Rt,
4.2 Calculate the overall percent
sulfur redaction as:
*Rfl
O.O-lrf)]
Where:
Overall sulfur dioxide reduction; percent.
XR- Sulfur dioxide removal efficiency of fuel pretreatment
from Section 2; percent. Refer to applicable subpart
for definition of ipplicable averaging period.
$R Sulfur dioxide removal efficiency of sulfur dioxide control
device either 0. or CO- - based calculation or calculated
froa fuel analysts and emission data, from Section 3;
percent. Refer to applicable subpart for definition of
applicable averaging period.
5. Calculation of Particulate, Sulfur
Dioxide, and Nitrogen Oxides Emission
Rates
and oxygen concentrations have been
determined in Section 5.1, wet or dry F
factors are used (Fw) factors and
associated emission calculation
procedures are not applicable and may
not be used after wet scrubbers; (FJ or
(Fd) factors and associated emission
calculation procedures are used after
wet scrubbers.) When pollutant and
carbon dioxide concentrations have
been determined in Section 5.1, F,
factors are used.
5.2.1 A verage F Factors, Table 1
shows average Fd, F^ and Fe factors
(scm/J, scf/million Btu) determined for
commonly used fuels. For fuels not
listed in Table 1. the F factors are
calculated according to the procedures
outlined in Section 5.2.2 of this section.
5.2.2 Calculating an F Factor. If the
fuel burned is not listed in Table 1 or if
the owner or operator chooses to
determine an F factor rather than use
the tabulated data, F factors are
calculated using the equations below.
The sampling and analysis procedures
followed in obtaining data for these
calculations are subject to the approval
of the Administrator and the
Administrator should be consulted prior
to data collection.
5.1 Sampling. Use the outlet SOi or
Ot or COa concentrations data obtained
in Section 3.1. Determine the particulate,
NO,, and O. or CO, concentrations
according to methods specified in an
applicable subpart of the regulations.
5.2 Determination of an F Factor.
Select an average F factor (Section 5.2.1)
or calculate an applicable F factor
(Section 5.2.2.). If combined fuels are
fired, the selected or calculated F factors
are prorated using the procedures in
Section 5.2.3. F factors are ratios of the
gas volume released during combustion
of a fuel divided by the heat content of
the fuel A dry F factor (FJ is the ratio of
the volume of dry flue gases generated
to the calorific value of the fuel
combusted; a wet F factor (Fw) la the
ratio of the volume of wet flue gases
generated to the calorific value of the
fuel combusted; and the carbon F factor
(FJ is the ratio of the volume of carbon
dioxide generated to the calorific value
of the fuel combusted. When pollutant
For SI Units:
227.0(«H) + 95.7(tC) + 35.4(«S) + 8.6«N) - 28.5QO)
GCY
347.4(SH)+95.7(tC)-t-35.4(«S}+8.6(lN}-28.5(tO)+13.0(SH20)«*
For English Units:
, . 106[5.S7(tH)
1.53(«C) + 0.57(tS) *
- 0.<6(tO)]
GCV
106[5.57(«H)+1.53(SC)*0.57(JS)+0.14(lN)-0.46(«0)-fO.21(^0)**]
The »2° tern nay be omitted If SH and W include the unavailable
hydrogen and oxygen In the fora of (UO.
IV-326
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Federal Register / Vol. 44. No. 113 / Monday. June 11. 1979 / Rules and Regulations
Where:
F« F,, and Fc have the units of scm/J, or scf/
million Btu; %H, %C, %S, %N, %O, and
%HW) and the pollutant
concentration (C,) are measured in the
flue gas on a wet basis, the following
equations are applicable: (Note: Fw
factors are not applicable after wet
scrubbers.)
(a)
20.9
120.9(1 -
Where:
8,,=Proportion by volume of water vapor in
the ambient air.
In lieu of actual measurement, B,.
may be estimated as follows:
Note.The following estimating factors are
selected to assure that any negative error
introduced in the term:
/ 20.9 x
20.9(1 - B ) - *0,
will not be larger than 1.5 percent
However, positive errors, or over-
estimation of emissions, of as much as 5
percent may be introduced depending
upon the geographic location of the
facility and the associated range of
ambient mositure.
(i) Bw.=0.027. This factor may be used
as a constant value at any location.
(ii) B».=Highest monthly average of
Bw. which occurred within a calendar
year at the nearest Weather Service
Station.
(iii) 8,,=Highest daily average of BW,
which occurred within a calendar month
at the nearest Weather Service Station,
calculated from the data for the past 3
years. This factor shall be calculated for
each month and may be used as an
estimating factor for the respective
calendar month.
(b)
Sr rd
20.9
L20.9 (1 - 8WS) -
Where:
Bwl=Proportion by volume of water vapor in
the stack gas.
5.3.1.3 Dry/Wet Basis. When the
pollutant concentration (Cw) is measured
on a wet basis and the oxygen
concentration (%Oad) or measured on a
dry basis, the following equation is
applicable:
E -
r] C-
20.9
20.9 - SO,
2d
When the pollutant concentration (CJ
is measured on a dry basis and the
oxygen concentration (%OM) is
measured on a wet basis, the following
equation is applicable:.
Cd Fd
20.9
20.9 -
5.3.2 Carbon Dioxide-Based F Factor
Procedure.
5.3.2.1 Dry Basis. When both the
percent carbon dioxide (%COj,i) and the
pollutant concentration (Cd) are
measured in the flue gas on a dry basis,
the following equation is applicable:
5.3.2.2 Wet Basis. When both the
percent carbon dioxide (%COt») and the
pollutant concentration (C,) are
measured on a wet basis, the following
equation is applicable:
5.3.2.3 Dry/Wet Basis. When the
pollutant concentration (Cw) is measured
on a wet basis and the percent carbon
dioxide (%COJd) is measured on a dry
basis, the following equation is
applicable:
C F
100
When the pollutant concentration (CJ
is measured on a dry basis and the
precent carbon dioxide (%CO>W) is
measured on a wet basis, the following
equation is applicable:
E ' C 0 - B) F
5.4 Calculation of Emission Rate
from Combined Cycle-Gas Turbine
Systems. For gas turbine-steam
generator combined cycle systems, the
emissions from supplemental fuel fired
to the steam generator or the percentage
reduction in potential (SO>) emissions
cannot be determined directly. Using
measurements from the gas turbine
exhaust (performance test, subpart GG)
and the combined exhaust gases from
the steam generator, calculate the
emission rates for these two points
following the appropriate paragraphs in
Section 5.3.
Note. Fw factors shall not be used to
determine emission rates from gas turbines
because of the injection of steam nor to
calculate emission rates after wet scrubbers;
Fd or Fc factor and associated calculation
procedures are used to combine effluent
emissions according to the procedure in
Paragraph 5.2.3.
The emission rate from the steam generator
is calculated as:
IV-327
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Federal Register / Vol. 44, No. 113 / Monday, June 11. 1979 / Rules and Regulations
4. Calculation of Overall Reduction in
Potential Sulfur Dioxide Emission
4.1 The overall percent sulfur
dioxide reduction calculation uses the
sulfur dioxide concentration at the inlet
to the sulfur dioxide control device as
XR.
the base value. Any sulfur redaction
realized through fuel cleaning is
introduced into the equation as an
average percent reduction, %Rf.
4.2 Calculate the overall percent
sulfur reduction «:
Where:
XR » Overall sulfur dioxide reduction; percent.
XR- Sulfur dioxide removaV efficiency of fuel pretreatment
from Section 2; percent. Refer to applicable subpart
for definition of applicable averaging period.
XR Sulfur dioxide removal efficiency of sulfur dioxide control
9
device either 0. or CO. - based calculation or calculated
fro* fuel analysts *nd emission data, from Section 3;
percent. Refer to applicable subpart for definition of
applicable averaging period.
5. Calculation of Particulate, Sulfur
Dioxide, and Nitrogen Oxides Emission
Rates
and oxygen concentrations have been
determined in Section 5.1, wet or dry F
factors are used. (Fw) factors and
associated emission calculation
procedures are not applicable and may
not be used after wet scrubbers; (FJ or
(Fd) factors and associated emission
calculation procedures are used after
wet scrubbers.] When pollutant and
carbon dioxide concentrations have
been determined in Section 5.1, Fc
factors are used.
5.2.1 Average F Factors, Table 1
snows average Fd. F,,, and Fc factors
(scm/J, scf/million Btu) determined for
commonly used fuels. For fuels not
listed in Table 1, the F factors are
calculated according to the procedures
outlined in Section 5.2.2 of mis section.
5.2.2 Calculating an F Factor. If the
fuel burned is not listed in Table 1 or if
the owner or operator chooses to
determine an F factor rather than use
the tabulated data, F factors are
calculated using the equations below.
The sampling and analysis procedures
followed in obtaining data for these
calculations are subject to the approval
of the Administrator and the
Administrator should be consulted prior
to data collection.
5.1 Sampling. Use the outlet SOi or
Oi or CO* concentrations data obtained
in Section 3.1. Determine the particulate,
NO,, and Oa or CO, concentrations
according to methods specified in an
applicable subpart of the regulations.
5.2 Determination of an F Factor.
Select an average F factor (Section 5.2.1)
or calculate an applicable F factor
(Section 5.2.2.). If combined fuels are
fired, the selected or calculated F factors
are prorated using the procedures in
Section 5.2.3. F factors are ratios of the
gas volume released during combustion
of a fuel divided by the heat content of
the fuel A dry F factor (FJ is the ratio of
the volume of dry flue gases generated
to the calorific value of the fuel
combusted; a wet F factor (F.) is the
ratio of the volume of wet flue gases
generated to the calorific value of the
fuel combusted; and the carbon F factor
(FJ is the ratio of the volume of carbon
dioxide generated to the calorific value
of the fuel combusted. When pollutant
For SI Units:
Z27.0(XH) * »5.7(XC) * 35.4(XS) + 8.6UN) - 28.5(XO)
GCV
347.4(XH)*95.7(SC)-t-35.4(tS}+e.6(%N)-28.5(SO)-H3.0(«H20)**
For English Units:
r . 106[5.57(»H) * 1.53OC)
*0.57(XS)
GCV
O.UflH) - 0.46(M)1
106[5.57(XH)+1.53(SC)-*0.57(XS)+0.14(XN)-0.46(»5)*0.2USH20}**]
The »20 tern My be omitted If tH and SO Include the unavailable
hydrogen and oxygen In the for* of M.O.
IV-328
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Federal Register / Vol. 44, No. 113 / Monday, June 11, 1079 / Rules and Regulations
59 V
Where:
Ew=Pollutant emission rate from steam
generator effluent, ng/J (lb/million Btu).
E,«= Pollutant emission rate in combined
cycle effluent; ng/J (Ib/million Btu).
Elt=Pollutant emission rate from gas turbine
effluent; ng/J (Ib/million Btu).
X»=Fraction of total heat input from
upplemental fuel fired to the steam
generator.
X,,=Fraction of total heat input from gas
turbine exhaust gases.
Note.The total heat input to the steam
generator is the sum of the heat input from
upplemental fuel fired to the steam
generator and the heat input to the steam
generator from the exhaust gases from the
gas turbine.
5.5 Effect of Wet Scrubber Exhaust,
Direct-Fired Reheat Fuel Burning. Some
wet scrubber systems require that the
temperature of the exhaust gas be raised
above the moisture dew-point prior to
the gas entering the stack. One method
used to accomplish this is directfiring of
an auxiliary burner into the exhaust gas.
The heat required for such burners is
from 1 to 2 percent of total heat input of
the steam generating plant. The effect of
this fuel burning on the exhaust gas
components will be less than ±1.0
percent and will have a similar effect on
emission rate calculations. Because of
this small effect, a determination of
effluent gas constituents from direct-
fired reheat burners for correction of
stack gas concentrations is not
necessary.
Where:
§,,=Standard deviation of the average outlet
hourly average emission rates for the
reporting period; ng/J (Ib/million Btu).
a, = Standard deviation of the average inlet
hourly average emission rates for the
reporting period; ng/J (Ib/million Btu).
6.3 Confidence Limits. Calculate the
lower confidence limit for the mean
outlet emission rates for SO, and NO,
and, if applicable, the upper confidence
limit for the mean inlet emission rate for
SO, using the following equations:
Table 1»-1.F Factors for Various fuels*
E,*=E,+U.i.8,
Where:
Eo*=The lower confidence limit for the mean
outlet emission rates; ng/J (Ib/million
Btu).
E,* =The upper confidence limit for the mean
inlet emission rate; ng/J (Ib/million Btu).
t».«= Values shown below for the indicated
number of available data points (n):
F.
n Values for IM
2
Fuel type
dscm
J
diet
10* Btu
mem
J
MCt
10* Btu
cm
J
Kf
10* Btu
Coot:
Anthracite _
Bituminous « -
UBnAs._ ,.
Gac
M*tuml ,, .,,
Propene....«««...»»»«...«..»««...
Butane .«..«.-«-. ..
MUfoli||
Wood Bark
2.71x10"
2.63x10-
265x10-
2.47x10-
2.43x10-
2.34x10-
2.34x10-
2.48x10-
2.58x10'
(10100)
(9780)
(9660)
(9190)
(8710)
(8710)
(8710)
(9240) ..
(9600) -
2.83x10-
^e6x10-
3.21X10"
2.77X 10"
2.85x10"
2.74x10'
2.79x10'
(10540)
(10640)
(11950)
(10320)
(10810)
(10200)
(10390)
0.530X10-'
0.484x10-'
0.513x10-'
0383x10"'
0.287x10-'
0.321x10-'
0.337x10-'
0.492x10"'
0.497X10"'
(1970)
(1600)
(1910)
(1420)
(1040)
(1190)
(1250)
(1830)
(1850)
A* classified accordng to ASTM D 388-66.
Crude, residual, or distillate.
Determined «t standard conditions: 20' C (68* F) and 760 mm Hg (29.92 la Hg).
10
11
12-16
17-21
22-26
27-31
32-51
52-91
92-151
152 or more
I.
6.31
2.42
2.35
213
2.02
1.94
1.89
1.86
1.83
1.81
1.77
1.73
1.71
1.70
1.66
1.67
1.66
1.65
6. Calculation of Confidence Limits for
Inlet and Outlet Monitoring Data
6.1 Mean Emission Rates. Calculate
the mean emission rates using hourly
averages in ng/J (Ib/million Btu) for SO,
and NO, outlet data and, if applicable,
SOa inlet data using the following
equations:
6.2 Standard Deviation of Hourly
Emission Rates. Calculate the standard
deviation of the available outlet hourly
average emission rates for SO! and NO,
and, if applicable, the available inlet
hourly average emission rates for SO«
using the following equations:
1 nj
Where:
E.=Mean outlet emission rate; ng/J (lb/
million Btu).
E,=Mean inlet emission rate; ng/J (Ib/million
Btu).
x.Hourly average outlet emission rate; ng/J
(Ib/million Btu).
X|Hourly average in let emission rate; ng/j
(Ib/million Btu).
n.sNumber of outlet hourly averages
available for the reporting period.
ni« Number of inlet hourly average!
available for reporting period.
1 -(^F£) C/^r?
\~ j \^
PCC
The values of this table are corrected for
n-1 degrees of freedom. Use n equal to
the number of hourly average data
points.
7. Calculation to Demonstrate
Compliance When Available
Monitoring Data Are Less Than the
Required Minimum
7.1 Determine Potential Combustion
Concentration (PCCjforSOt.
7.1.1 When the removal efficiency
due to fuel pretreatment (% Rf) is
included in the overall reduction in
potential sulfur dioxide emissions (% R«)
and the "as-fired" fuel analysis is not
used, the potential combustion
concentration (PCC) is determined as
follows:
10'; ng/J
Ib/million Btu.
Potential emissions removed by the pretreatment
l process, using the fuel parameters defined In
section 2.3; ng/J (Ib/million Btu).
IV-329
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Federal Register / Vol. 44, No. 113 / Monday, June 11, 1079 / Rules and Regulations
7.1.2 When the "as-fired" fuet
analysis is used and the removal
efficiency due to fuel pretreatment (% R,)
is not included Ln the overall reduction
in potential sulfur dioxide emissions (%
RJ, the potential combustion
concentration (PCC) is determined as
follows:
PCC=I.
PCC
PCC
I. + 2
I. * 2
7.1.4 When inlet monitoring data are
used and the removal efficiency due to
fuel pretreatment (% R,) is not included
in the overall reduction in potential
sulfur dioxide emissions (% R,), the
potential combustion concentration
(PCC) is determined as follows:
PCC = E,*
Where:
E,* = The upper confidence limit of the mean
inlet emission rate, as determined in
section 6.3.
7.2 Determine Allowable Emission
Rates
7.2.1 NO*. Use the allowable
emission rates for NOX as directly
defined by the applicable standard in
terms of ng/J (Ib/million Btu).
7.2.2 SO,. Use the potential
combustion concentration (PCC) for SOj
as determined in section 7.1, to
determine the applicable emission
standard. If the applicable standard is
an allowable emission rate in ng/J (lb/
million Btu), the allowable emission rate
When:
I, = The luUar dioxide Input rate a* defined
in Motion 3.3
7.1.3 When the "as-fired" fuel
analysis is used and the removal
efficiency due to fuel pretreatment [% RJ
i« included in the overall reduction {%
RO), the potential combustion
concentration (PCC) is determined as
follows:
ng/J
Ib/«ni1on 6tu.
is used as E.^. If the applicable standard
is an allowable percent emission,
calculate the allowable emission rate
(E.u] using the following equation:
E«« = %PCC/100
Where:
% PCC = Allowable percent emission as
defined by the applicable standard;
percent.
73 Calculate E, * lEua . To determine
compliance for the reporting period
calculate the ratio:
Where:
Eo* = The lower confidence limit for the
mean outlet emission rates, as defined in
section 6.3; ng/J (Ib/million Btu).
E.U, = Allowable emission rate an denned in
section 7.2; ng/J (Ib/million Btu).
If Eo'fEat is equal to or less than 1.0, the
facility is in compliance; if E,,*/E^ is greater
than 1.0, the facility is not in compliance for
the reporting period.
(FR Doc. 7V-17W7 Piled e-B-Tft &« *m]
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Federal Register / Vol. 44, No. 163 / Tuesday, August 21, 1979 / Rules and Regulations
99
40 CFR Pan 60
[FRL 1276-3]
Priority List and Additions to the List
of Categories of Stationary Sources
AGENCY: Environmental Protection'
Agency.
ACTION: Final rule.
SUMMARY: This action contains EPA's
promulgated list of major source
categories for which standards of
performance for new stationary sources
are to be promulgated by August 1982.
The Clean Air Act Amendments of 1977
specify that the Administrator publish a
list of the categories of major stationary
sources which have not been previously
listed as source categories for which
standards of performance will be
established. The promulgated list
implements the Clean Air Act and
reflects the Administrator's
determination that, based on
preliminary assessments, emissions
from the listed source categories
contribute significantly to air pollution.
The intended effect of this promulgation
is to identify major source categories for
which standards of performance are to
be promulgated. The standards would
apply only to new or modified
statiorrary sources of air pollution.
EFFECTIVE DATE: August 21, 1979.
ADDRESSES: The background document
for the promulgated priority list may be
obtained from the U.S. EPA Library
(MD-35), Research Triangle Park, North
Carolina 27711, telephone number 919-
541-2777. Please refer to "Revised
Prioritized List of Source Categories for
New Source Performance Standards,"
EPA-450/3-79-023. The prioritization
methodology is explained in the
background document for the proposed
priority list. This document, "Priorities
for New Source Performance Standards
under the Clean Air Act Amendments of
1977," EPA-450/3-78-019, can also be
obtained from the Research Triangle
Park EPA Library. Copies of all
comment letters received from
interested persons participating in this
rulemaking, a summary of these
comments, and a summary of the
September 29, 1978, public hearing are
available for inspection and copying
during normal business hours at EPA's
Public Information Reference Unit,
Room 2922 [EPA Library), 401 M Street,
SW., Washington, DC.
FOR FURTHER INFORMATION CONTACT
Gary D. McCutchen, Emission Standards
and Engineering Division (MD-13),
Environmental Protection Agency,
Research Triangle Park, N.C. 27711,
telephone number (919) 541-5421.
SUPPLEMENTARY INFORMATION: On
August 31,1978 (43 FR 38872), EPA
proposed a priority list of major source
categories for which standards of
performance would be promulgated by
August 1982, and invited public
comment on the list and the
methodology used to prioritize the
source categories. Promulgation of this
list is required by section lll(f) of the
Clean Air Act as amended August 7,
1977. The significant comments that
were received during the public
comment period, including those made
at a September 29,1978, public hearing,
have been carefully reviewed and
considered and, where determined by
the Administrator to be appropriate,
changes have been included in this
notice of final rulemaking.
Background
The program to establish standards of
performance for new stationary sources
(also called New Source Performance
Standards or NSPS) began on December
1970, when the Clean Air Act was
signed into law. Authorized under
section 111 of the Act, NSPS were to
require the best control system
(considering cost) for new facilities, and
were intended to complement the other
air quality management approaches
authorized by the 1970 Act. A total of 27
source categories are regulated by
NSPS, with NSPS for an additional 25
source categories under development.
During the 1977 hearings on the Clean
Air Act, Congress received testimony on
the need for more rapid development of
NSPS. There was concern that not all
sources which had the potential to
endanger public health or welfare were
controlled by NSPS and that the
potential existed for "environmental
blackmail" from source categories not
subject to NSPS These concerns were
reflected in the Clean Air Act
Amendments of 1977, specifically in
section lll(f).
Section lll(f) requires that the
Administrator publish a list of major
stationary sources of air pollution not
listed, as of August 7, 1977, under
section lll(b)(l)(A), which in effect
meant those sources for which NSPS
had not yet been proposed or
promulgated. Before promulgating this
list, the Administrator was to provide
notice of and opportunity for a public
hearing and consult with Governors and
State air pollution control agencies. In
developing priorities, section lll(f)
specifies that the Administrator
consider (1) the quantity of emissions
from each source category, (2) the extent
to which^ach pollutant endangers
public health or welfare, and (3) the
mobility and competitive nature of each
stationary source category, e.g., the
capability of a new or existing source to
locate in areas with less stringent air
pollution control regulations. Governors
may at any time submit applications
under section lll(g) to add major source
categories to the list, add any source
category to the list which may endanger
public health or welfare, change the
priority ranking, or revise promulgated
NSPS.
Development of the Priority List
Development of the priority list was
initiated by compiling data on a large
number of source categories from
literature resources. The data were first
analyzed to determine major source
categories, those categories for which an
average size plant has the potential to
emit 100 tons or more per year of any
one pollutant. These major source
categories were then subjected to a
priority ranking procedure using the
three criteria specified in section lll(f)
of the Act.
The procedure used first ranks source
categories on a pollutant by pollutant
basis. This resulted in nine lists (one for
each pollutantvolatile organic
compounds (VOC), nitrogen oxides,
particulate matter, sulfur dioxide,
carbon monoxide, lead, fluorides, acid
mist, and hydrogen sulfide) with each
list ranked using the criteria in the Act.
In this ranking, first priority was given
to quantity of emissions, second priority
to potential impact on health or welfare,
and third priority to mobility. Thus.
sources with the greatest growth rales
and emission reduction potential were
high on each list; sources with limited
choice of location, low growth and small
emission reduction potential were low
on each list.
The nine lists were combined into one
by selecting pollutant goalsa
procedure which, in effect, assigned a
relative priority to pollutants based
upon the potential impact of NSPS After
the pollutant goals were selected, the
final priority list was established
through the selection of source
categories which have maximum impact
on attaining the selected goals. The
effect of this procedure was to
emphasize control of all criteria
pollutants except carbon monoxide and
to give carbon monoxide and non-
criteria pollutants a lower priority.
IV-331
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Federal Register / Vol. 44, No. 163 / Tuesday, August 21, 1979 / Rules and Regulations
In the background reports and in the
preamble to the proposed priority list,
the term "hydrocarbon" was used even
though the emissions referred to were
VOC which, unlike hydrocarbon
compounds, can contain elements other
than carbon and hydrogen. A VOC is
defined by EPA as any organic
compound that, when released to the
atmosphere, can remain long enough to
participate in photochemical reactions.
Since VOC contribute to ambient levels
of photochemical oxidants, they are
considered a criteria pollutant.
The ranking of source categories on
the list and the differentiation between
major and minor sources was sensitive
to the accuracy of the data utilized. The
data base used to establish the priority
list was obtained from a number of
literature sources including EPA
screening studies. However, screening
studies were not available for all source
categories. Therefore, if new information
becomes avajlable after promulgation of
the list, the Administrator may delete
from or add to the list in response to this
new information.
Additional detail on the prioritization
methodology, the input factors used, and
the ranking of individual source
categories is available in the two
background documents (see
"ADDRESSES").
Significance of Priority List
The promulgated list is essentially an
advance notice of future standard
development activity. It identifies major
source categories and the approximate
order in which NSPS development
would be initiated. However, if further
study indicates that an NSPS would
have little or no effect on emissions, or
that an NSPS would be impractical, a
source category would be given a lower
priority or removed from the list.
Similarly, new information may increase
the priority of a source category. The
Administrator may also concurrently
develop standards for sources which are
not on the priority list, especially certain
"minor" sources which, in aggregate.
represent a large quantity of emissions.
The distinction between major and
minor source categories is defined only
for the purpose of determining NSPS
priorities and should not be used to
determine sources subject to New
Source Review, which is conducted on a
case-by-case basis. Moreover, some
New Source Review programs, such as
prevention of significant deterioration,
have separate and distinct criteria for
defining a major source (e.g., 100 tons
per year potential for certain source
types and 250 tons per year for others).
Identification of Source Categories
Two groups of sources in addition to
minor sources are not included on the
promulgated list. One group includes
sources which could not be evaluated
due to insufficient information. This lack
of data suggests that these sources,
which are identified in the background
report, "Priorities for NSPS under the
Clean Air Act of 1977," have not
previously been regulated or studied
and, therefore, are probably not major
sources. Nevertheless, the Administrator
will continue to investigate these
sources and will consider development
of NSPS for any which are identified as
being significant sources of air pollution.
The second group of source categories
not on the priority list consists of those
listed under section lll(b)(l)(A) on or
before August 7,1977. These are.
Fossil-fuel-fired steam generators
Incinerators
Portland Cement Plants
Nitric Acid Plants
Sulfuric Acid Plants
Asphalt Concrete Plants
Petroleum Refineries
Storage Vessels for Petroleum Liquids
Secondary Lead Smelters
Secondary Brass and Bronze Ingot Production
Plants
Iron and Steel Plants
Sewage Treatment Plants
Primary Copper Smelters
Primary Zinc Smelters
Primary Lead Smelters
Primary Aluminum Reduction Plants
Phosphate Fertilizer Industry. Wet Process
Phosphoric Acid Plants
Phosphate Fertilizer Industry:
Superphosphonc Acid Plants
Phosphate Fertilizer Industry. Diammonium
Phosphate Plants
Phosphate Fertilizer Industry. Triple
Superphosphate Plants
Phosphate Fertilizer Industry. Granular Triple
Superphosphate Storage Facilities
Coal Preparation Plants
Ferroalloy Production Facilities
Steel Plants Electric Arc Furnaces
Kraft Pulp Mills
Lime Plants
Grain Elevators
There are. however, some facilities (or
subcategones) within these source
categories for which NSPS have not
been developed, but which may by
themselves be significant sources of air
pollution. A number of these facilities
were evaluated as if they were separate
source categories; three which rank high
in priority are included on the
promulgated list to indicate that the
Administrator plans to develop
standards for them: Petroleum refinery
fugitive emissions, industrial fossil-fuel-
fired steam generators, and non-
municipal incinerators. In addition to
these, the Administrator will continue to
evaluate affected facilities within listed
source categories and may from time to
time develop NSPS for such facilities.
The iron and steel industry provides an
example of a category which is already
listed (so does not appear on the priority
list), but in which an active interest
remains. Although the growth rate for
new sintering capacity is presently very
low, the Administrator is continuing to
assess emission control and
measurement technology with a view
toward possible development of an
NSPS for sintering plants at a later date
A project is also underway to update
emission factors for all steelmaking
processes, including fugitive emissions,
in an effort to determine the relative
significance of emissions from each
process. In addition, byproduct coke
ovens, nearly always associated with
steel mills, are included on the priority
list and are undergoing standard
development stud;es
There are some differences between
the format of the list in the background
report, "Revised Prioritized List of
Source Categories for NSPS
Promulgation" and the format of the list
which appears here These differences
are primarily a result of aggregation of
subcategones which had been
subdivided for size classification and
priority ranking analysis. Non-metallic
mineral processing, for example, had
been subdivided into nine subcategories
for prioritization. eight of which were
analyzed separately (stone, sand and
gravel, clay, gypsum lime, borax,
fluorspar, and phosphate rock mining)
and one of which is considered a minor
source (mica mining) EPA plans to
study the entire non-metallic mineral
processing industry at one time, since
many of the processes and control
techniques are similar For this reuson,
the industr\ is identified by a single
aggregated listing This does not
necessarily implv that a single standard
would apply to all sources within the
listed category Ralher. as described
below in the case of the synthetic
organic chemical manufacturing
industry, the nature and scope of
standards will be determined only after
a detailed study of sources within the
category
In addition to the major sources, three
source categories not identified as being
major source categories have been
added to the list organic solvent
cleaning, industrial surface coating of
metal furniture, and lead acid battery
manufacture
Organic solvent cleaning was chosen
for study because this source category
accounts for some 5 percent of
stationary source VOC emissions
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typical air quality control region. Thus.
although individual facilities typically
emit less than 100 tons per year, this is a
significant source of VOC emissions and
the Administrator considers it prudent
to continue the development of a
standard for this source category.
The metal furniture coating industry is
also a significant source of VOC
emissions, and there are over 300
existing facilities with the potential to
emit more than 100 tons per year.
Lead acid battery manufacture is a
significant source of lead emissions. An
NSPS for this source category is
expected to assist in attainment of the
National Ambient Air Quality Standard
for lead.
Stationary gas turbines are included
on this list because this source category
had not been listed by August 7,1977,
when the Clean Air Act Amendments
were enacted. However, this source
category has not been prioritized, since
it was listed under section lll(b)(l)(A)
and NSPS were proposed October 3,
1977.
One listed source category which
deserves special attention is the
synthetic organic chemical
manufacturing industry (SOCMI).
Preliminary estimates indicate that there
may be over 600 different processes
included in this source category, but
only 27 of these processes have been
evaluated. For the others, there was not
enough information available. As is the
case with several other aggregated
source categories, generic standards will
be used to cover as many of the sources
as possible, so separate NSPS for each
of the 600 processes are unlikely.
Based on an effort which has been
underway within EPA for two years to
study this complex source category, the
generic standards could regulate nearly
all emissions by covering four broad
areas: Process facilities, storage
facilities, leakage, and transport and
handling losses. Also, since a number of
the pollutants emitted are potentially
toxic or carcinogenic, regulation under
section 112, Nation"! Emission
Standards for Hazardous Air Pollutants
(NESHAP), rather than NSPS may be
more appropriated. Therefore, SOCMI is
listed as a single source category The 27
processes considered the most likely
candidates for NSPS or NESHAP
coverage through generic standards are
listed in the preamble to the proposed
priority list and discussed in the
background documents.
Additional information has resulted in
the exclusion from the list of some
source categories which are shown in
the background reports. Mixed fuel
boilers and feed and grain milling are
regulated by the NSPS for fossil-fuel
steam generators and grain elevators,
respectively. Beer manufacture has a
much lower emission level than had
been assumed in the background report,
and whiskey manufacture was deleted
due to a lack of any demonstrated
control technology.
Public Participation
The Clean Air Act requires that the
Administrator, prior to promulgating this
list of source categories, consult with
Governors and State air pollution
control agencies. An invitation was
extended on February 28,1978, to the
State and Territorial Air Pollution
Program Administrators (STAPPA) and
the National Governors' Association
(NGA) to attend the first Working Group
meeting, March 16,1978, and review the
draft background report and the
methods used to apply the priority
criteria. On March 24,1978, each
Governor and the director of each State
air pollution control agency was notified
by letter of this project, including an
invitation to participate or comment:
(1) At the April 5-6,1978, National Air
Pollution Control Techniques Advisory
Committee (NAPCTAC) meeting in
Alexandria, Virginia;
(2) When the final background report
was mailed to them;
(3) When the list was proposed in the
Federal Register; or
(4) At a public hearing to be held on
the proposed list. The draft background
report for,the proposed list was mailed
to all N APCTAC members, five of which
represent State or local agencies, two of
which represent environmental groups,
and eight of which represent industry.
Copies were mailed to six
environmental groups and three
consumer groups at the sam'e time, and
to a representative of the NGA. Copies
of the final background report for the
proposed list were sent to the
Governors, State and local air pollution
control agencies, NAPCTAC members,
environmental groups, the NGA, and
other requesters in July 1978.
The public comment period on the
proposed lish published in the August
31,1978, Federal Register, extended
through October 30,1978. There were 18
'comment letters received, 10 from
industry and 8 from various regulatory
agencies. Several comments resulted in
changes to the proposed priority list.
A public hearing was held on
September 29,1978, to discuss the
proposed priority list in accordance with
section lll(g)(8) of the Clean Air Act.
There were no written comments and
only one verbal statement resulting from
the public hearing.
Significant Comments and Changes to
the Proposed Priority List
As a result of public comments and
the availability of new screening studies
and reports, 34 major and 11 minor
source category data sets were
reevaluated. This reexamination
resulted in data changes for 29 major
and 9 minor source categories.
Ten source categories have been
removed from the proposed priority list.
Eight of these source category deletions
are a result of new data indicating that
NSPS would have little or no effect.
These source categories are: Varnish,
carbon black, explosives, acid sulfite
wood pulping, NSSC wood pulping.
gasoline additives manufacturing, alfalfa
dehydrating, and hydrofluoric acid
manufacturing. Printing ink
manufacturing was reclassified from a
major to a minor source category. In
addition, two source categories, gray
iron and steel foundries, were combined
fato one source category. Finally, fuel
conversion was removed from the list
due to uncertainties regarding the
approach and scheduled involved in
developing environmental standards for
the various processes. Likely candidates
for NSPS include coal gasification (both
low and high pressure), coal
liquefaction, and oil shale and tar sand
processing. These actions reduce the
final priority list to 59 source categories.
The most significant comments and
changes made to the proposed
regulations are discussed below:
1. Definition of "Mobility." Several
commenters felt that the treatment of
source category mobility (movability)
was too broad. Mobility in the
prioritization analysis refers to the
feasibility a stationary source has to
relocate to, or locate new facilities in,
areas with less stringent air pollution
control regulations. Non-movable
stationary source categories were
identified on the basis of being firmly
tied either to the market (e.g.. dry
cleaners) or to a supply of materials
(e.g., mining operations). The
Administrator recognizes that there are
many other factors which would be
considered in plant siting situations, but
considers the approach used in
determining the priority list sufficient for
the purposes of this study.
2. Source Category Aggregation.
Several commenters indicated that there
were discrepancies between the source
categories named in the priority list and
those in the background document. The
differences between the priority listing
in the Federal Register and the
background document list is a result of
aggregation of sources which had been
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Federal Register / Vol. 44, No. 163 / Tuesday, August 21, 1979 / Rules and Regulations
subcategorized for size classification
and priority ranking analysis in the
background document. Aggregation
indicates that all source categories
under a generic industry heading, such
as non-metallic mineral processing, will
be evaluated at the same time, although
this does not necessarily imply that a
single standard would apply to all
sources within the listed category.
3. Control Costs. Two commentere felt
that the cost of pollution control to meet
NSPS limitations should have been
included in the criteria for prioritization.
The Clean Air Act priority list criteria
do not include the cost of pollution
control, but pollution control costs were
considered during the determination of
control technology assumed for the
priority list study. Control costs are
examined in more detail during NSPS
development studies for each source
category, and must be considered in
determining each NSPS.
4. Minor Source Categories. One
commenter felt that the Administrator
lacks statutory authority to make a
policy decision to develop NSPS for a
minor source category until after the
major sources have been dealt with,
lince Congress indicated major sources
must be given priority. The
Administrator, in promulgating this list,
is placing an almost exclusive emphasis
on NSPS for major source categories.
However, the Clean Air Act does not
prohibit concurrent promulgation of
NSPS for minor, but significant, source
categories. For the three minor source
categories listed in this regulation, NSPS
development had been initiated before
the priority list was available, and
completion of standards development
for these sources is considered justified.
5. Stationary Fuel Combustion/Waste
Incineration. Two State agencies felt
that stationary fuel combustion and
waste incineration should have a high
priority because of source activity
growth in their respective States. In the
promulgated list, both of these source
categories are given high priority based
on the most recent growth rates
available. Given the concern expressed
by these agencies, the Administrator has
already initiated standard development
studies for these source categories.
6. Chemical Products Manufacture/
Fuel Conversion. One commenter felt
that the growth rate and, therefore, the
need for coal gasification plant NSPS is
overestimated. High Btu coal
gasification was reexamined; although
no commercial-scale plants currently
exist in this country, environmental
programs need to keep pace with the
emphasis on energy programs. The fuel
conversion processes have been
removed from the priority list for special
study.
7. Chemical Products Manufacture/
Printing Ink Manufacture. One
commenter indicated that neither
existing conditions within the printing
ink industry nor projections of future
growth of the industry justify its
categorization as a major source. The
Administrator has examined the new
data provided, and has reclassified
printing ink manufacturing plants as a
minor source category. As was
discussed earlier, however, the
Administrator may still develop
standards for "minor" source categories,
especially those which, in aggregate,
represent a significant quantity of
emissions.
8. Wood Processing/NSSC and Acid
Sulfite Pulping. One commenter
indicated that acid sulfite pulp
production is a declining growth
industry and therefore should not be
included in the priority list. The
Administrator agrees with this
comment, based on examination of acid
sulfite pulp production projections in a
new screening study. In addition, the
screening study indicates that NSSC
pulping is, in effect, controlled by the
promulgated NSPS for Kraft pulp mills,
resulting in little or no further emission
reduction from promulgation of an NSSC
NSPS. Therefore, both acid sulfite and
NSSC pulping have been removed from
the list.
Development of Standards
The Administrator has undertaken a
program to promulgate NSPS for the
source categories on this priority list by
August 7,1982. Development of
standards has already been initiated for
nearly two-thirds of the source
categories listed; work on the remaining
source categories will be initiated within
the next year.
The priority ranking is indicated by
the number to the left of each source
category and will be used to decide the
order in which new projects are
initiated, although this is not necessarily
an indication of the order in which
projects will be completed. In fact,
higher priority source categories often
present difficult technical and regulatory
problems, and may be among the later
source categories for which standards
are promulgated.
It should be pointed out that several
of the source categories listed could be
subject to standards which may be
adopted under section 112 of the Clean
Air Act, national emission standards for
hazardous air pollutants (NESHAP).
Included are byproduct coke ovens and
several source categories within the
petroleum transport and marketing
industry. If standards are developed
under section 112 for these or any other
source categories on the promulgated
list, then standards may not be
-developed for those source categories
under section 111.
Promulgation of this list not only
fulfills the section lll(f) requirements
concerning establishment of priorities,
but also constitutes notice that all
source categories on the priority list are
considered significant sources of air
pollution and are hereby listed in
accordance with section lll(b)(l)(A) 11
should be noted, however, that the
source categories identified on this
priority list, even though listed in
accordance with section lll(b)(l)(A),
are not subject to the provisions of
section lll(b)(l)(B), which would
require proposal of an NSPS for each
listed source category within 120 days of
adoption of the list. Rather, the
promulgation of standards for sources
contained on this priority list will be
undertaken in accordance with the time
schedule prescribed in section lll(f)(l)
of the Clean Air Act Amendments. That
is, NSPS for 25 percent of these source
categories are to be promulgated by
August 1980, 75 percent by August 1981,
and all of the NSPS by August 1982.
Dated August 15,1979.
Douglas M. Costle,
Administrator.
Part 60 of Chapter I of Title 40 of the
Code of Federal Regulations is amended
by adding § 60.16 to Subpart A as
follows:
§60.16 Priority list.
Prioritized Major Source Categories
Priority Number'
Source Category
1. Synthetic Organic Chemical Manufacturing
(a) Unit processes
(b) Storage and handling equipment
(c) Fugitive emission sources
(d) Secondary sources
2. Industrial Surface Coating Cans
3. Petroleum Refineries Fugitive Sources
4. Industrial Surface Coating Paper
5. Dry Cleaning
(a) Perchloroethylene
(b) Petroleum soKent
6. Graphic Arts
7. Polymers and Resins Acrylic Resins
B. Mineral Wool
9. Stationary Internal Combustion Engine-.
10. Industrial Surface Coating- Fabric
11. Fossil-Fuel-Fired Steam Generators
Industrial Boilers
12. Incineration: Non-Municipal
13. Non-Metallic Mineral Processing
14. Metallic Mineral Processing
' Low numbers have highest priority e g N
high priority. No 59 is low priority
IV-334
-------
Federal Register / Vol. 44, No. 163 / Tuesday. August 21.1979 / Rules and Regulations
IS. Secondary Copper
16. Phosphate Rock Preparation
17. Foundriet: Steel and Gray Iron
18. Polymers and Resins: Polyethylene
19. Charcoal Production
10. Synthetic Rubber
(a) Tire manufacture
(bj SBR production
21. Vegetable Oil
22. Industrial Surface Coating: Metal Coil
23. Petroleum Transportation and Marketing
24. By-Product Coke Ovens
26. Synthetic Fibers
26. Plywood Manufacture
27. Industrial Surface Coating: Automobiles .
26. Industrial Surface Coating: Large
Appliances
29. Crude Oil and Natural Gas Production
30. Secondary Aluminum
31. Potash
32. Sintering: Clay and Fly Ash
33. Glass
34. Gypsum
35. Sodium Carbonate
36. Secondary Zinc
37. Polymers and Resins: Phenolic
38. Polymers and Resins: UreaMelamme
39. Ammonia
40. Polymers and Resins: Polystyrene
41. Polymers and Resins: ABS-SAN Resins
42. Fiberglass
43. Polymers and Resins: Polypropylene
44. Textile Processing
45. Asphalt Roofing Plants
46. Brick and Related Clay Products
47. Ceramic Clay Manufacturing
48. Ammonium Nitrate Fertilizer
49. Castable Refractories
60. Borax and Boric Acid
51. Polymers and Resins Polyester Resins
52. Ammonium Sulfate
S3. Starch
54 Perlite
55. Phosphoric Acid: Thermal Process
56. Uranium Refining
57. Animal Feed Defluorination
SB. Urea (for fertilizer and polymers)
59. Detergent
Other Source Categories
Lead acid battery manufacture"
Organic solvent cleaning"
Industrial surface coating metal furniture"
Stationary gas turbines'"
(Sec. Ill, 301(a). Clean Air Act as amended
(42US.C. 7411. 7601))
|FR Doc 79-26656 Filed B-20-79. 8 45 am]
MLUNG COOt (MO-01-M
" Minor source category but included on list
unce an NSPS it being developed for that source
category
"' Not prioritized, since an NSPS for thit major
»oim.e category has alreadv been nronnwd
100
40 CFR Part 60
[FRL 1231-3]
Standards of Performance for New
Stationary Sources: Asphalt Concrete;
Review of Standards
AGENCY: Environmental Protection
Agency (EPA)
ACTION: Review of Standards.
SUMMARY: EPA has reviewed tjie
standard of performance for asphalt
concrete plants (40 CFR 60.9, Subpart I).
The review is required under the Clean
Air Act, as amended August 1977. The
purpose of this notice is to announce
EPA's intent not to undertake revision of
the standards at this time.
DATES: Comments must be received by
October 29,1979.
ADDRESS: Comments should be
submitted to the Central Docket Section
(A-130), U.S. Environmental Protection
Agency, 401 M Street, S.W.,
Washington, D.C. 20460, Attention-
Docket No. A-79-04.
FOR FURTHER INFORMATION CONTACT:
Mr. Robert Ajax, telephone: (919) 541-
5271. The document "A Review of
Standards of Performance for New
Stationary SourcesAsphalt Concrete"
(EPA-450/3-79-014) is available upon
request from Mr. Robert Ajax (MD-13),
Emission Standards and Engineering
Division, U.S. Environmental Protection
Agency, Research Triangle Park, North
Carolina 27711.
IV-335
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Federal Register / Vol. 44, No. 171 / Friday. August 31. 1979 / Rules and Regulations
SUPPLEMENTARY INFORMATION:
Background
In June 1973, EPA proposed a
standard under Section 111 of the Clean
Air Act to control participate matter
emissions from asphalt concrete plants.
The standard, promulgated on March 8,
1974, limits the discharge of particulate
matter into the atmosphere to a
maximum of 90 mg/dscm from any
affected facility. The standard also
limits the opacity of emissions to 20
percent. The standard is applicable to
asphalt concrete plants which
commenced construction or
modification after June 11,1973.
The Clean Air Act Amendments of
1977 require that the Administrator of
the EPA review and, if appropriate,
revise established standards of
performance for new stationary sources
at least every 4 years [Section
lll(b)(l)(B)]. Following adoption of the
Amendments, EPA contracted with the
MITRE Corporation to undertake a
review of the asphalt concrete industry
and the current standard. The MITRE
review was completed in January 1979.
Preliminary findings were presented to
and reviewed by the National Air
Pollution Control Techniques Advisory
Committee at its meeting in Alexandria,
Virginia, on January 10,1979. This notice
announces EPA's decision regarding the
need for revision of the standard.
Comments on the results of this review
and on EPA's decision are invited.
Findings
Overview of the Asphalt Concrete
Industry
The asphalt concrete industry consists
of about 4,500 plants, widely dispersed
throughout the Nation. Plants are
stationary (60 percent), mobile (20
percent), or transportable (20 percent),
i.e., easily taken down, moved and
reassembled. Types of plants include
batch-mix (91 percent), continuous mix
(6 5 percent), or dryer-drum mix (2.5
percent). The d-yer-drum plants, which
are becoming increasingly popular,
differ from the others in that drying of
the aggregate and mixing with the liquid
asphalt both take place in the same
rotary dryer. It is estimated that within
the next few years, dryer-drum plants
will represent up to 85 percent of all
plants under construction.
Current national production is about
263 to 272 million metric tons (MG)/
year, with a continued rise expected in
the future. It is estimated that
approximately 100 new and 50 modified
plants become subject to the standard
each year. Operation is seasonal, with
plants reportedly averaging 666 hours/
year although many operate more
extensively.
Particulate Matter Emissions and
Control Technology
The largest source of particulate
emissions is the rotary dryer. Both dry
(fabric filters) and wet (scrubbers)
collectors are used for control and are
both capable of achieving compliance
with the standard. However, all systems
of these types have not automatically
achieved control at or below the level of
the standard.
Based on data from a total of 72
compliance tests, it was found that 53 or
about three-fourths of the tests for
particulate emissions showed
compliance. Thirty-three of the 53
produced results between 45 and 90
MgVdscm (.02 and .04 gr/dscf). Of the 47
tests of fabric filters or venturi scrubber
controlled sources over 80 percent
showed compliance. The available data
do not provide details on equipment
design and an analysis of the cause of
failures has not been performed.
However, EPA is not aware of any
instances in which a properly designed
and installed fabric filter system or high-
efficiency scrubber has failed to achieve
compliance with the standard. The fact
that certian facilities controlled by
fabric filters and high-efficiency
scrubbers have failed to comply is
attributed to faulty design, installation,
and/or operation. This conclusion and
these data are consistent with data and
findings considered in the development
of the present standard.
On the basis of these findings, EPA
concludes that the present standard for
particulate matter is appropriate and
that no revision is needed.
Much less test data are available for
opacity than for particulates. Of the 26
tests for which opacity levels are
reported, only 5 failed to show
compliance with the opacity standard.
However, none of these 5 met the
standard for particulate matter. Of the
21 plants reported as meeting the
current standard for opacity, 19 met the
particulate standard. On the basis of
these data, EPA concludes that the
opacity standard is appropriate and
should not be revised. While the data do
indicate that a tighter standard may be
possible, the rationale and basis used to
establish the present standard are
considered to remain valid.
Enforcement of the Standard
Because the cost of performance tests
which are required to demonstrate
compliance with the standard are
essentially fixed and are independent of
plant size, this cost is disproportionately
high for small plants. Due to this, the
issue was raised as to whether formal
testing could be waived and lower cost,
alternative means be established for
determining compliance at small plants.
Support for such a waiver can be found
in the fact that emission rates are
generally lower at these plants and
errors in compliance determinations
would not be large in terms of absolute
emissions. However, testing costs at all
sizes of plants are small in relation to
the cost of asphalt concrete production
over an extended period and these costs
can be viewed as a legitimate expense
to be considered by an owner at the
time a decision to construct is made. A
number of State agencies presently
require, under SIP regulations, initial
and in some cases annual testing of
asphalt concrete plants. Moreover,
available compliance test data show
that performance of control devices is
variable and even with installation of
accepted best available control
technology the standard can be
exceeded by a significant degree if the
control system is not properly designed,
operated, and maintained. Relaxing the
requirement for formal testing thus
could lead to a proliferation of low
quality or marginal control equipment
which would require costly repair or
retrofit at a later time.
A further performance testing problem
indentified in the review of the standard
concerns operation at less than full
production capacity during a compliance
test. When this occurs, EPA normally
accepts the test result as a
demonstration of compliance at the
tested production rate, plus 23 Mg (25
tons)/hr. To operate at a higher
production rate, an owner or operator
must demonstrate compliance by testing
at that higher rate. Industry
representatives view this limitation as
an unfair production penalty. It is noted
in particular that reduced production is
sometimes an unavoidable consequence
associated with use of high moisture
content aggregate. Furthermore, it is
argued that facilities which show
compliance at the maximum production
rate associated with a given moisture
level can be assumed to comply at
higher production rates when moisture
is lower. However, this argument
assumes that the uncontrolled emission
rate from the facility does not increase
as production rate increases and EPA is
not aware of data ,o support this
assumption.
As a general policy it is EPA's intent
to minimize administrative costs
imposed on owners and operators by a
standard, to the maximum extent thdt
this can be done without sacrificing the
Agency's responsibility for assuring
IV-336
-------
Federal Register / Vol. 44, No. 171 / Friday, August 31, 1979 / Rules and Regulations
compliance. Specifically, in the cases
cited above, EPA does not intend to
impose costly testing requirements on
small facilities or any facilities if
compliance with the standard can be
determined through less costly means.
However, EPA at this time is not aware
of a procedure which could be employed
at a significantly lower cost to
determine compliance with an
acceptable degree of accuracy. Although
opacity correlators with grain loading
and serves as a valid means for
identifying excess emissions, due to
dependence on stack diameter and other
factors opacity alone is not adequate to
accurately assess compliance with the
mass rate standard. Similarly, the
purchase and installation of a baghouse
or venturi scrubber does not in itself
necessarily imply compliance. EPA is
concerned that approval of such
equipment without compliance test data
or a detailed assessment of design and
operating factors would provide an
incentive for installation of low cost,
under-designed equipment. This would
place vendors of more costly systems
which are well designed and properly
constructed and operated at a
competitive disadvantage; in the long
term this would not only increase
emissions but would be to the detriment
of the industry.
EPA has, however, concluded that a
study program to investigate alternative
compliance test and administrative
approaches for asphalt plants is needed.
An EPA contractor working for the
Office of Enforcement has initiated a
study designed to assess several
administrative aspects of the standard,
including possible low cost alternative
test methods; administrative
mechanisms to deal with the problem of
process variability during testing; and
physical constraints affecting the ability
to perform tests. If the results of this
program, which is scheduled to be
completed later in 1979, show that the
regulations or enforcement policies can
be revised to lower costs, such revisions
will be adopted.
Hydrocarbon Emissions
While the principal pollutant
associated with asphalt concrete
production is particulate matter, the
trend noted previously toward dryer-
drum mix plants has raised question as
to the significance of hydrocarbon
emissions from these facilities. In the
dryer-drum mix plant, drying of the
aggregate as well as mixing with asphalt
and additional fines takes place within a
rotary drum. Because the drying takes
place within the same container as the
mixing, emissions are partly screened by
the curtain of asphalt added so that the
uncontrolled particulate emissions from
the dryer are lower than from
conventional plants. In contrast, it has
been reported that the rate of
hydrocarbon emissions may be
substantially higher than from
conventional plants. However, data
recently reported from one test in a
plant equipped with fabric filters
showed only traces of hydrocarbons in
dust and condensate and did not
support this suggestion. Thus, while
these data do not indicate a need to
revise the standard, more definitive data
are needed on hydrocarbon emission
rates and related process variables. This
has been identified as an area for
further research by EPA.
An additional source of hydrocarbon
emissions in the asphalt industry is the
use of cutback asphalts. Although not
directly associated with asphalt
concrete plants, this represents a
significant source of hydrocarbon
emissions. As such, the need for
possible standards of performance
pertaining to use of cutback asphalt was
rasied in this review. The term cutback
asphalt refers to liquified asphalt
products which are diluted or cutback
by kerosene or other petroleum
distillates for use as a surfacing
material. Cutback asphalt emits
significant quantities of hydrocarbons
at a high rate immediately after
application and continuing at a
diminishing rate over a period of years.
It is estimated that over 2 percent of
national hydrocarbon emissions result
from use of cutback asphalt.
The substitution of emulsified
asphalts, which consist of asphalt
suspended in water containing an
emulsifying agent, for cutback asphalt
nearly eliminates the release of volatile
hydrocarbons from paving operations.
This substitute for petroleum distillate is
approximately 98 percent water and 2
percent emulsifiers. The water in
emulsified asphalt evaporates during
curing while the non-volatile emulsifier
is retained in the asphalt.
Because cutback asphalt emissions
result from the use of a product rather
than from a conventional stationary
source, the feasibility of a standard of
performance is unclear and the Agency
has no current plans to develop such a
standard. However, EPA has issued a
control techniques guideline document,
Control of Volatile Organic Compounds
from Use of Cutback Asphalt (EPA-450/
2-77-037) and is actively pursuing
control through the State
Implementation Plan process in areas
where control is needed to attain
oxidant standards. Because of area-to-
area differences in experience with
IV-337
emulsified asphalt, availability of
suppliers, and ambient temperatures, the
Agency believes that control can be
implemented effectively by the States.
Asphalt Recycling Plants
A process for recycling asphalt paving
by crushing up old road beds for
reprocessing through direct-fired asphalt
concrete plants has been recently
implemented on an experimental basis.
Plants using this process, which uses
approximately 20 to 30 percent virgin
material mixed with the recycled
asphalt, are subject to the standard and
at least two have demonstrated
compliance. However, preliminary
indications are that the process may
have difficulty in routinely attaining the
allowable level of particulate emissions
and/or that the cost of control may be
higher than a conventional process. The
partial combustion of the recycled
asphalt cement reportedly produces a
blue smoke more difficult to control than
the mineral dusts of plants using virgin
material.
It is EPA's conclusion that there is no
need at this time to revise the standard
as it affects recycling, due to its limited
practice and due to the data showing
that compliance can be achieved at
facilities which recycle asphalt.
However, this matter is being studies
further under the previously noted study
by an EPA contractor.
Educational Program for Owners and
Operators
The asphalt industry consists of a
large number of facilities which in many
cases are owned and operated by smaii
businessmen who are not trained or
experienced in the operation, design, or
maintenance of air pollution control
equipment. Because of this, the need to
comply with emission regulations, and
the changing technology in the industry
(i.e., the introduction of dryer-drum
plants, recycling, the possible move
toward coal as a fuel, and the use of
emulsions), the need for a training and
educational program for owners and
operators in the operation and
maintenance of air pollution control
equipment has been voiced by industry.
This offers the potential for cost and
energy savings along with reduced
pollution.
To meet this need, EPA's Office of
Enforcement, in cooperation with the
National Asphalt Paving Association,
conducted a series of workshops in 1978
for asphalt plant owners and operators.
Only limited future workshops are
currently planned. However, EPA will
consider expansion of the programs if a
continued need exists.
Dated: August 23,1979.
Douglas Costle,
Administrator
-------
Federal Register / Vol. 44. No. 176 / Monday, September 10.1979 / Rules and Regulations
101
40 CFR Part 60
[FRL 1276-2]
Standards of Performance for New
Stationary Sources; Gas Turbines
AGENCY: Environmental Protection
Agency.
ACTION: Final rule.
SUMMARY: This rule establishes
standards of performance which limit
emissions of nitrogen oxides and sulfur
dioxide from new, modified and
reconstructed stationary gas turbines.
The standards implement the Clean Air
Act and are based on the
Administrator's determination that
stationary gas turbines contribute
significantly to air pollution. The
intended effect of this regulation is to
require new, modified and reconstructed
stationary gas turbines to use the best
demonstrated system of continuous
emission reduction. _^
EFFECTIVE DATE: September 10,1979.
ADDRESSES: The Standards Support and
Environmental Impact Statement
(SSEIS) may be obtained from the U.S.
EPA Library (MD-35), Research Triangle
Park, North Carolina 27711 (specify
Standards Support and Environmental
Impact Statement, Volume 2:
Promulgated Standards of Performance
for Stationary Gas Turbines, EPA-450/
2-77-017b).
FOR FURTHER INFORMATION CONTACT:
Don R. Goodwin, Director, Emission
Standards and Engineering Division,
Environmental Protection Agency,
Research Triangle Park, North Carolina
27711, telephone No. (919) 541-5271.
SUPPLEMENTARY INFORMATION:
The Standards
The promulgated standards apply to
all new, modified, and reconstructed
stationary gas turbines with a heat input
at peak load equal to or greater than
10.7 gigajoules per hour (about 1,000
horsepower). The standards apply to
simple and regenerative cycle gas
turbines and to the gas turbine portion
of a combined cycle steam/electric
generating system.
The promulgated standards limit the
concentration of nitrogen oxides (NO,)
in the exhaust gases from stationary gas
turbines with a heat input from 10.7 to
and including 107.2 gigajoules per hour
(about 1,000 to 10,000 horsepower), from
offshore platform gas turbines, and from
stationary gas turbines used for oil or
gas transportation and production not
located in a Metropolitan Statistical
Area (MSA), to 0.0150 percent by
volume (150 PPM) at 15 percent oxygen
on a dry basis. The promulgated
standards also limit the concentration of
NO, in the exhaust gases from
stationary gas turbines with a heat input
greater than 107.2 gigajoules per hour,
and from stationary gas turbines used
for oil or gas transportation and
production located in an MSA, to 0.0075
percent by volume (75 PPM) at 15
percent oxygen on a dry basis (see
Table 1 for summary of NO, emission
limits). Both of these emission limits (75
and 150 PPM) are adjusted upward for
gas turbines with thermal efficiencies
greater than 25 percent using an
equation included in the promulgated
standards. These emission limits are
also adjusted upward for gas turbines
burning fuels with a nitrogen content
greater than 0.015 percent by weight
using a fuel-bound nitrogen allowance
factor included in the promulgated
standards, or a "custom" fuel-bound
nitrogen allowance factor developed by
the gas turbine manufacturer and
approved for use by EPA. Custom fuel-
bound nitrogen allowance factors must
be substantiated with data and
approved for use by the Administrator
before they may be used for determining
compliance with the standards.
The promulgated NO, emission limits
are referenced to International Standard
Organization (ISO) standard day
conditions of 288 degrees Kelvin, 60
percent relative humidity, and 101.3
kilopascals (1 atmosphert) pressure.
Measured NO, emission levels,
therefore, are adjusted to ISO reference
conditions by use of an ambient
condition correction factor included in
the standards, or by a custom ambient
condition correction factor developed by
the gas turbine manufacturer and
approved for use by EPA. Custom
ambient condition correction factors can
only include the following variables:
combustor inlet pressure, ambient air
pressure, ambient air humidity, and
ambient air temperature. These factors
must be substantiated with data and
approved for use by the Administrator
before they may be used for determining
compliance with the standards.
Stationary gas turbines with a heat
input at peak load from 10.7 to, and
including, 107.2 gigajoules per hour are
to be exempt from the NO, emission
limit included in the promulgated
standards for five years from the date of
proposal of the standards (October 3,
1977). New gas turbines with this heat
input at peak load which are
constructed, or existing gas turbines
with this heat input at peak load which
are modified or reconstructed during
this five-year period do not have to
comply with the NO, emission limit
included in the promulgated standards
at the end of this period. Only those new
gas turbines which are constructed, or
existing gas turbines which are modified
or reconstructed, following this five-year
period must comply with the NOX
emission limit.
Emergency-standby gas turbines.
military training gas turbines, gas
turbines involved in certain research
and development activities, and
firefighting gas turbines are exempt from
compliance with the NO, emission limits
included in the promulgated standards
In addition, stationary gas turbines
sing wet controls are temporarily
exempt from the NO, emission limit
during those periods when ice fog
created by the gas turbine is deemed by
(he owner or operator to present a
traffic hazard, and during periods of
drought when water is not available.
None of the exemptions mentioned
above apply to the sulfur dioxide (SO2)
emission limit. The promulgated
standards limit the SO2 concentration in
the exhaust gases from stationary gas
turbines with a heat input at peak load
of 10.7 gigajoules per hour or more to
0.015 percent by volume (150 PPM)
corrected to 15 percent oxygen on a dry
basis. The standards include an
alternative SO2 emission limit on the
sulfur content of the fuel of 0.8 percenl
sulfur by weight | see Table 1 for
summary of exemptions and SO?
emission limits).
Table 1.Summary of Gas Turtine New Source Performance Standard
Gas turbrne size and usage
NO. emis-
sion hlTHI '
Applicability date lor
NO,
SOi emission limit
Applicability dale 101
SO,
Less than 10 7 gigajoules/hour (all uses)
None Standard does not
apply
Between 10 7 and 107 2 gigajoules/hour (all 150 ppm . October 3, 1882
uses)
None
Standard does nol
apply
150ppmSOjOt tnea Octobers 1977
fuel with less man
0.8% suHuf
Greater than or equal to 107 2
giga|oules/nour
1 Gas and ml transportation or produc- 150 ppm October 3,1877 Same as above October 3 197?
ton not located m an MSA
2 Gas and oil transportation or produc- 75 ppm October 3,1S77 Same as above . October 3 t977
ton located m an MSA
3. All other uses 75 ppm October 3, 1977 Same as above . October 3, 1977
Emergency standby, firefighting, military None... Standard does not Same as above . Octobers 1977
(except for garrison facility), military tram- apply
no, and research and development tur-
bines
' NO, emission limit adjusted upward for gas turbines with thermal efficiencies greater than 25 percenl and tor gas turbines
firing tueto with a nitrogen content of more than 0.015 weight percent Measured NO, emissions adjusted to ISO conditions IP
determining compliance with the NO, emission limit
IV-338
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Federal Register / Vol. 44, No. 176 / Monday, September 10, 1979 / Rules and Regulations
Environmental, Energy, and Economic
Impact
The promulgated standards will
reduce NO, emissions by about 190,000
tons per year by 1982 and by 400,000
tons per year by 1987. This reduction
will be realized with negligible adverse
solid waste and noise impacts.
The adverse water pollution impact
associated with the promulgated
standards will be minimal. The quantity
of water or steam required for injection
into the gas turbine to reduce NO,
emissions is less than 5 percent of the
water consumed by a comparable size
steam/electric power plant using cooling
towers. There will be no adverse water
pollution impact associated with those
gas turbines which employ dry NO,
control technology.
The energy impact associated with the
promulgated standards will be small.
Gas turbine fuel consumption could
increase by as much as 5 percent in the
worst cases. The actual energy impact
depends on the rate of water injection
necessary to comply with the
promulgated standards. Assuming the
"worst case," however, the standards
would increase fuel consumption of
large stationary gas turbines (i.e.,
greater than 10,000 horsepower) by
about 5,500 barrels of fuel oil per day in
1982. The standards would increase fuel
consumption of small stationary gas
turbines (i.e., less than 10,000
horsepower) by about 7,000 barrels of
fuel oil per day in 1987. This is
equivalent to an increase in projected
1982 and 1987 national crude oil
consumption of less than 0.03 percent.
As mentioned, these estimates are
based on "worst case" assumptions. The
actual energy impact of the promulgated
standard is expected to be much lower
than these estimates because most gas
turbines will not experience anywhere
near a 5 percent fuel penalty due to
water or steam injection. In addition,
many gas turbines will comply with the
standards using dry control, which in
most cases has no energy penalty.
The economic impact associated with
the promulgated standards is considered
reasonable. The Standards will increase
the capital costs or purchase price of a
gas turbine for most installations by
about 1 to 4 percent. The annualized
costs will be increased by about 1 to 4
percent, with the largest application.
utilities, realizing less than a 2 percent
increase.
The promulgated standards will
increase the total capital investment
requirements for users of large
stationary gas turbines by about 36
million dollars by 1982. For the period
1982 through 1987, the standards will
increase the capital investment
requirements for users of both large and
small stationary gas turbines by about
67 million dollars. Total annualized
costs for these users of stationary gas
turbines will be increased by about 11
million dollars in 1982 and by about 30
million dollars in 1987. These impacts
will result in price increases for the end
products or services provided by
industrial and commercial users of
stationary gas turbines ranging from less
than 0.01 percent in the petroleum
refining industry, to about 0.1 percent in
the electric utility industry.
Public Participation
Prior to proposal of the standards,
interested parties were advised by
public notice in the Federal Register of
meetings of the National Air Pollution
Control Techniques Advisory
Committee to discuss the standards
recommended for proposal. These
meetings occurred on February 21,1973;
May 30,1973; and January 9,1974. The
meetings were open to the public and
each attendee was given ample
opportunity to comment on the
standards recommended for proposal.
The standards were proposed and
published in the Federal Register on
October 3,1977. Public comments were
solicited at that time and, when
requested, copies of the Standards
Support and Environmental Impact
Statement (SSEIS) were distributed to
interested parties. The public comment
period extended from October 3,1977, to
January 31,1978.
Seventy-eight comment letters were
received on the proposed standards of
performance. These comments have
been carefully considered and, where
determined to be appropriate by the
Administrator, changes have been made
in the standards which were proposed.
Significant Comments and Changes to
the Proposed Regulation
Comments on the proposed standards
were received from electric utilities, oil
and gas producers, gas turbine
manufacturers, State air pollution
control agencies, trade and professional
associations, and several Federal
agencies. Detailed discussion of these
comments can be found in Volume 2 of
the SSEIS. The major comments can be
combined into the following areas:
general, emission control technology,
modification and reconstruction,
economic impacts, environmental
impacts, energy impacts, and test
methods and monitoring.
General
Small stationary gas turbines (i.e,
those with a heat input at peak load
between 10.7 and 107.2 gigajoules per
hourabout 1,000 to 10,000 horsepower)
are exempt from the standards for a
period of five years following the date of
proposal. Some commenters felt it was
not clear whether small gas turbines
would be required to retrofit NO,
emissions controls after the exemption
period ended. These commenters felt
this was not the intent of the standards
and they recommended that this point
be clarified.
The intent of both the proposed and
the promulgated standards is to consider
small gas turbines which have
commenced construction on or before
the end of the five year exemption
period as existing facilities. These
facilities will not have to retrofit at the
end of the exemption period. This point
has been clarified in the promulgated
standards.
Several commenters requested
exemptions for temporary and
intermittent operation of gas turbines to
permit research and development into
advanced combustion techniques under
full scale conditions.
This is considered a reasonable
request. Therefore, gas turbines
involved in research and development
for the purpose of improving combustion
efficiency or developing emission
control technology are exempt from the
NO, emission limit in the promulgated
standards. Gas turbines involved in this
type of research and development
generally operate intermittently and on
a temporary basis. The standards have
been changed, therefore, to allow
exemptions in such situations on a case-
by-case basis.
Emissions Control Technology
The selection of wet controls, or water
injection, as the best system of emission
reduction for stationary gas turbines
was criticized by a number of
commenters. These commenters pointed
out that although dry controls will not
reduce emissions as much as wet
controls, dry controls will reduce NOS
emissions without the objectionable
results of water injection (i.e., increased
fuel consumption and difficulty in
securing water of acceptable quality).
These commenters, therefore,
recommended postponement of
standards until dry controls can be
implemented on gas turbines.
As pointed out in Volume 1 of the
SSEIS, a high priority has been
established for control of NO,
emissions. Wet and dry controls are
considered the only viable alternative
control techniques for reducing NO,
emissions from gas turbines. Control of
NO, emissions by either of these two
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alternatives clearly favored the
development of the standards of
performance based on wet controls from
an environmental viewpoint. Reductions
in NO, emissions of more than 70
percent have been demonstrated using
wet controls on many large gas turbines
used in utility and industrial
applications. Thus, wet controls can be
applied immediately to large gas
turbines, which account for 85-90
percent of NOX emissions from gas
turbines.
The technology of wet control is the
same for both large and small gas
turbines. The manufacturers of small gas
turbines, however, have not
experimented with or developed this
technology to the same extent as the
manufacturers of large gas turbines. In
addition, small gas turbines tend to be
produced or more of an assembly line
basis than large gas turbines.
Consequently, the manufacturers of
small gas turbines need a lead time of
five years (based on their estimates) to
design, test, and incorporate wet
controls on small gas turbines.
Even with a five-year delay in
application of standards to small gas
turbines, standards of performance
based on wet controls will reduce
national NO, emissions by about 190,000
tons per year by 1982. Therefore, the
reduction in NO, emissions resulting
from standards based on wet controls is
significant.
Dry controls have demonstrated NO,
emissions reduction of only about 40
percent in laboratory and combustor rig
tests. Because of the advanced state of
research and development into dry
control by the manufacturers of large
gas turbines, the much longer lead time
involved in ordering large gas turbines,
and the greater attention that can be
given to "custom" engineering designs of
large gas turbines, dry controls can be
implemented on large gas turbines
immediately. Manufacturers of small gas
turbines, however, estimate that it
would take them as long to incorporate
dry controls as wet controls on small
gas turbines. Basing the standards only
on dry controls, therefore, would
significantly reduce the amount of NO,
emission reductions achieved.
The economic impact of standards
based on wet controls is considered
reasonable for large gas turbines. (See
Economic Impact Discussion.) Thus, wet
controls represent ". . . the best system
of continuous emission reduction . . .
(taking into consideration the cost of
achieving such emission reduction, any
nonair quality health and environmental
impact and energy requirements). . ."
for large gas turbines.
The economic impact of standards
based on wet controls, however, is
considered unreasonable for small gas
turbines, gas turbines located on
offshore platforms, and gas turbines
employed in oil or gas production and
transportation which are not located in
a Metropolitan Statistical Area. The
economic impact of standards based on
dry controls, on the other hand, is
considered reasonable for these gas
turbines. (See Economic Impact
Discussion.) Thus, dry controls
represent ". . . the best system of
continuous emission reduction . . .
(taking into consideration the cost of
achieving such emission reduction, any
nonair quality health and environmental
impact and energy requirements). . ."
for small gas turbines, gas turbines
located on offshore platforms, and gas
turbines employed in oil or gas
production and transportation which are
not located in a Metropolitan Statistical
Area.
Volume 1 of the SSE1S summarizes the
data and information available from the
literature and other nonconfidential
sources concerning the effectiveness of
dry controls in reducing NO, emissions
from stationary gas turbines. More
recently, additional data and
information have been published in the
Proceedings of the Third Stationary
Source Combustion Symposium (EPA-
600/7-79-050C). Advanced Combustion
Systems for Stationary Gas Turbines
(interim report) prepared by the Pratt
and Whitney Aircraft Group for EPA
(Contract 68-02-2136), "Experimental
Clean Combustor Program Phase III"
(NASA CR-135253) also prepared by the
Pratt and Whitney Aircraft Group for
the National Aeronautics and Space
Administration (NASA), and "Aircraft
Engine Emissions" (NASA Conference
Publication 2021). These data and
information show that dry controls can
reduce NO, emissions by about 40
percent. Multiplying this reduction by a
typical NO, emission level from an
uncontrolled gas turbine of about 250
ppm leads to an emission limit for dry
controls of 150 ppm. This, therefore, is
the numerical emission limit included in
the promulgated standards for small gas
turbines, gas turbines located on
offshore platforms, and gas turbines
employed in oil or gas production or
transportation which are not located in
Metropolitan Statistical Areas.
The five-year delay from the date of
proposal of the standards in the
applicability date of compliance with
the NO, emission limit for small gas
turbines has been retained in the
promulgated standards. As discussed
above, manufacturers of small gas
turbines have estimated that it will take
this long to incorporate either wet or dry
controls on these gas turbines.
Several commenters criticized the
fuel-bound nitrogen allowance included
in the proposed standards. It was felt
that greater flexibility in the equations
used to calculate the fuel-bound
nitrogen NO, emissions contribution
should be permitted, due to the limited
data on conversion of fuel-bound
nitrogen to NO,. These commenters
recommended that manufacturers of gas
turbines be allowed to develop their
own fuel-bound nitrogen allowance.
As discussed in Volume I of the
SSEIS, the reaction mechanism by which
fuel-bound nitrogen contributes to NOX
emissions is not fully understood. In
addition, emission data are limited with
respect to fuels containing significant
amounts of fuel-bound nitrogen. The
problem of quantifying the fuel-bound
nitrogen contribution to total NO,
emissions is further complicated by the
fact that the amount of nitrogen in the
fuel has an effect on this contribution.
In light of this sparsity of data, the
commenters' recommendations seem
reasonable. Therefore, a provision has
been added to the standards to allow
manufacturers to develop custom fuel-
bound nitrogen allowances for each gas
turbine model. The use of these factors,
however, must be approved by the
Administrator before the initial
performance test required by Section
60.8 of the General Provisions. Petitions
by manufacturers for approval of the use
of custom fuel-bound nitrogen
allowance factors must be supported by
data which clearly provide a basis for
determining the contribution of fuel-
bound nitrogen to total NO, emissions.
In addition, in no case will EPA approve
a custom fuel-bound nitrogen allowance
factor which would permit an increase
in NO, emissions of more than 50 ppm.
(See Energy Impact Discussion.) Notice
of approval of the use of these factors
for various gas turbine models will be
given in the Federal Register.
Modification and Reconstruction
Some commenters felt that existing
gas turbines which now burn natural gas
and are subsequently altered to burn oil
should be exempt from consideration as
modifications. The high cost and
technical difficulties of compliance with
the standards would discourage fuel
switching to conserve natural gas
supplies.
As outlined in the General Provisions
of 40 CFR Part 60, which are applicable
to all standards of performance, most
changes to an existing facility which
result in an increase in emission rate to
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the atmosphere are considered
modifications. However, according to
section 60.14(e)(4) of the General
Provisions, the use of an alternative fuel
or raw material shall not be considered
a modification if the existing facility
was designed to accommodate that
alternative use. Therefore, if a gas
turbine is designed to fire both natural
gas and oil, then switching from one fuel
to the other would not be considered a
modification even if emissions were
increased. If a gas turbine that is not
designed for firing both fuels is switched
from firing natural gas to firing oil,
installation of new injection nozzles
which increase mixing to reduce NO,
production, or installation of new NO,
combustors currently on the market,
would in most cases maintain emissions
at their previous levels. Since emissions
would not increase, the gas turbine
would not be considered modified, and
the real impact of the standards on gas
turbines switching from natural gas to
oil will probably be quite small.
Therefore, no special provisions for fuel
switching have been included in the
promulgated standards.
Economic Impact
Several commenters stated that water
injection could increase maintenance
costs significantly. One reason cited
was that chemicals and minerals in the
water would likely be deposited on
internal surfaces of gas turbines, such as
turbine blades, leading to downtime for
repair and cleaning. In addition, the
commenters felt that higher
maintenance requirements could be
expected due to the increased
complexity of a gas turbine with water
injection.
As pointed out in Volume 1 of the
SSE1S, to avoid deposition of chemicals
and minerals on gas turbine blades, the
water used for water injection must be
treated. Costs for water treatment were
included in the overall costs of water
injection and, for large gas turbines,
these costs are considered reasonable.
Actual maintenance and operating
costs for gas turbines operating with
water or steam injection are limited.
Several major utilities, however, have
accumulated significant amounts of
operating time on gas turbines using
water or steam injection for control of
NO, emissions. There have been some
problems attributable to water or steam
injection, but based on the data
available, these problems have been
confined to initial periods of operation
of these systems. Most of these reported
problems such as turbine blade damage,
flame-outs, water hammer damage, and
ignition problems, were easily corrected
by minor redesign of the equipment
hardware. Because of the knowledge
gained from these systems, such
problems should not arise in the future.
As mentioned, some utilities have
accumulated substantial operating
experience without any significant
increase in maintenance or operating
costs or other adverse effects. One
utility, for example, has used water
injection on two gas turbines for over
55,000 hours without making any major
changes to their normal maintenance
and operating procedures. They
followed procedures essentially
identical to those required for a similar
gas turbine not using water injection,
and the plant experienced no outages
attributable to the water injection
system. Another company has
accumulated over 92,000 hours of
operating time with water injection on
17 gas turbines with approximately 116
hours of outage attributable to their
water injection system. Increased
maintenance costs which can be
attributed to these water injection
systems are not available, as such costs
were not accounted for separately from
normal maintenance. However, they
were not reported as significant.
Some commenters exresssed the
opinion that the cost estimates for
controlling NO, emissions from large
gas turbines were too low. Accordingly,
these commenters felt that wet control
technology should not be the basis of
the standards for large stationary gas
turbines.
The costs associated with wet control
technology for large gas turbines were
reassessed. In a few cases, it appeared
the water-to-fuel ratio used in Volume 1
of the SSEIS was somewhat low. In
these cases, the capital and annualized
operating costs associated with wet
control on large gas turbines were
revised to reflect injection of more water
into the gas turbine. None of these
revisions, however, resulted in a
significant change in the projected
economic impact of wet controls on
large gas turbines. Thus, depending on
the size and end use of large gas
turbines, wet controls are still projected
to increase capital and annualized
operating costs by no more than 1 to 4
percent. Increases of this order of
magnitude are considered reasonable in
light of the 70 percent reduction in NO,
emissions achieved by wet controls.
Consequently, the basis of the
promulgated standards for large gas
turbines remains the same as that for
the proposed standardswet controls.
A number of commenters also
expressed the opinion that the cost
estimates for wet controls to reduce NO,
emissions from small gas turbines were
too low. Therefore, the standards for
small gas turbines should not be based
on wet controls.
Information included in the comments
submitted by manufacturers of small gas
turbines indicated the costs of
redesigning these gas turbines for water
injection are much greater than those
included in Volume 1 of the SSEIS.
Consequently, it appears the costs of
water injection would increase the
capital cost of small gas turbines by
about 16 percent, rather than about 4
percent as originally estimated. Despite
this increase in capital costs, it does not
appear water injection would increase
the annualized operating costs of small
gas turbines by more than 1 to 4 percent
as originally estimated, due to the
predominance oT fuel costs in operating
costs. An increase of 16 percent in the
capital cost of small gas turbines,
however, is considered unreasonable.
Very little information was presented
in Volume 1 of the SSEIS concerning the
costs of dry controls. The conclusion
was drawn, however, that these costs
would undoubtedly be less than those
associated with wet controls.
Little information was also included in
the comments submitted by the
manufacturers of small gas turbines
concerning the costs of dry controls.
Most of the cost information dealt with
the costs of wet controls. One
manufacturer, however, did submit
limited information which appears to
indicate that the capital cost impact of
dry controls on small gas turbines might
be only a quarter of that of wet controls.
Thus, dry controls might increase the
capital costs of small gas turbines by
only about 4 percent. The potential
impact of dry controls on annualized
operating costs would certainly be no
greater than wet controls, and would
probably be much less. Consequently, it
appears dry controls might increase the
capital costs of small gas turbines by
about 4 percent and the annualized
operating costs by about 1 to 4 percent.
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The magnitude of these impacts is
essentially the same as those originally
associated with wet controls in Volume
1 of the SSEIS, and they are considered
reasonable. Consequently, the basis of
the promulgated standards for small gas
turbines is dry controls.
A number of commenters stated that
the costs associated with wet controls
on gas turbines located on offshore
platforms, and in arid and remote
regions were unreasonable. These
commenters felt that the costs of
obtaining, transporting, and treating
water in these areas prohibited the use
of water injection.
As mentioned by the commenters, the
costs associated with water injection on
gas turbines in these locations are all
related to lack of water of acceptable
quality or quantity. Review of the costs
included in Volume 1 of the SSEIS for
water injection on gas turbines located
on offshore platforms, indicates that the
required expenditures for platform
space were not incorporated into these
estimates. Based on information
included in the comments, platform
space is very expensive, and averages
approximately $400 per square foot.
When this cost is included, the use
water treatment systems to provide
water for NO, emissions control would
increase the capital costs of a gas
turbine located on an offshore platform
by approximately 33 percent. This is
considered an unreasonable economic
impact.
Dry controls, unlike wet controls,
would not require additional space on
offshore platforms. Although most gas
turbines located on offshore platforms
would be considered small gas turbines
under the standards, it is possible that
some large gas turbines might be located
on offshore platforms. Therefore, all the
information available concerning the
costs associated with standards based
on dry controls for large gas turbines
was reviewed.
Unfortunately, no additional
information on the costs of dry controls
was included in the comments
submitted by the manufacturers of large
gas turbines. As mentioned above, the
information presented in Volume 1 of
the SSEIS is very limited concerning the
costs of dry controls, although the
conclusion is drawn that these costs
would undoubtedly be less than the
costs of wet controls. It also seems
reasonable to assume that the costs of
dry controls on large gat turbines would
certainly be less than the costs of dry
controls on small gas turbines.
Consequently, standards based on dry
controls should not increase the capital
and annualized operating costs of large
gas turbines by more than the 1 to 4
percent projected for small gas turbines.
This conclusion even seems
conservative in light of the projected
increase in capital and annualized
operating costs for wet controls on large
gas turbines of no more than 1 to 4
percent. In any event, the costs of
standards based on dry controls for
large gas turbines are considered
reasonable. Therefore, the promulgated
standards for gas turbines located on
offshore platforms are based on dry
controls.
In many arid and remote regions, gas
turbines would have to obtain water by
trucking, installing pipelines to the site,
or by construction of large water
reservoirs. While costs included in
Volume 1 of the SSEIS do not show
trucking of water to gas turbine sites to
be unreasonable, these costs are not
based on actual remote area conditions.
That is, these costs are based on paved
road conditions and standard ICC
freight rates. Gas turbines located in
arid and remote regions, however, are
not likely to have good access roads.
Consequently, it is felt that the costs of
trucking water, laying a water pipeline,
or constructing a water reservoir would
be unreasonable for most arid and
remote areas.
As discussed above, the economic
impact of standards based on dry
controls for both large and small gas
turbines in considered reasonable.
Consequently, provisions have been
included in the promulgated standards
which essentially require gas turbines
located in arid and remote areas to
comply with an NO, emission limit
based on the use of dry controls. A
number of options were considered
before the specific provisions included
in the promulgated standards were '
selected.
The first option considered was
defining the term "arid and remote."
While this is conceptually
straightforward, it proved impossible to
develop a satisfactory definition for
regulatory purposes. The second option
considered was defining all gas turbines
located more than a certain distance
from an adequate water supply as "arid
and remote" gas turbines. Defining the
distance and an adequate water supply,
however, proved as impossible as
defining the term "arid and remote." The
third option considered was a case-by-
case exemption for gas turbines where
the costs of wet controls exceeded
certain levels. This option, however,
would provide incentive to owners and
operators to develop grossly inflated
costs to justify exemption and would
require detailed analysis of each case on
the part of the Agency to insure this did
not occur. In addition, the numerous
disputes and disagreements which
would undoubtedly arise under this
option would lead to delays and
demands on limited resources within
both the Agency and industry to resolve.
Analysis of the end use of most gas
turbines located in arid and remote
regions gave rise to a fourth option.
Generally, gas turbines located in arid
or remote regions are used for either oil
and gas production, or oil and gas
transportation. Consequently, the
promulgated standards require gas
turbines employed in oil and gas
production or oil and gas transportation,
which are not located in a Metropolitan
Statistical Area [MSA), to meet an NO,
emission limit based on the use of dry
controls. The promulgated standards,
however, require gas turbines employed
in oil and gas production or oil and gas
transportation which are located in a
MSA to meet the 75 ppm NO, emission
limit. This emission limit is based on the
use of wet controls and in an MSA a
suitable water supply for water injection
will be available.
Environmental Impact
A number of commenters felt gas
turbines used as "peaking" units should
be exempt. Peaking units operate
relatively few hours per year. According
to commenters, use of water injection
would result in a very small reduction in
annual NO, emissions and negligible
improvement in .ground level
concentrations.
As pointed out in Volume 1 of the
SSEIS, about 90 percent of all new gas
turbine capacity is expected to be
installed by electric utility companies to
generate electricity, and possibly as
much as 75 percent of all NO, emissions
from stationary gas turbines are emitted
from these installations. Of these
electric utility gas turbines, a large
majority are used to generate power
during periods of peak demand.
Consequently, by their very nature,
peaking gas turbines tend to operate
when the need for emission control is
greatest, that is, when power demand is
highest and air quality is usually at its
worst. Therefore, it does not seem
reasonable to exempt peaking gas
turbines from compliance with the
standards.
A number of commenters also ftlt that
small gas turbines should be exempt
from the standards because they emit
only about 10 percent of the total NO,
emissions from all stationary gas
turbines and therefore, the
environmental impact of not regulating
these turbines would be small.
A high priority has been established
for NO, emission control and dry control
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techniques are considered a
demonstrated and economically
reasonably means for reducing NO,
emissions from small gas turbines.
Therefore, the promulgated standards
limit NO, emissions from small gas
turbines to 150 ppm based on the use of
dry control technology.
Energy Impact
A number of writers commented on
the potential impact of the standards on
the use of the oil-shale, coal-derived,
and other synthetic fuels. It was
generally felt that these types of fuels
should not be covered by the the
standards at this time, since this could
hinder their development.
Total NO, emissions from any
combustion source, including stationary
gas turbines, are comprised of thermal
NOE and organic NO,. Thermal NO, is
formed in a well-defined high
temperature reaction between oxygen
and nitrogen in the combustion air.
Organic NO, is produced by the
combination of fuel-bound nitrogen with
oxygen during combustion in a reaction
that is not yet fully understood. Shale
oil, coal-derived, and other synthetic
fuels generally have high nitrogen
contents and, therefore, will produce
relatively high organic NO, emissions
when combusted.
Neither wet nor dry control
technology for gas turbines is effective
in reducing organic NO, emissions. As
discussed in Volume I of the SSEIS, as
fuel-bound nitrogen increases, organic
NO, emissions from a gas turbine
become the predominant fraction of
total NO l, emissions. Consequently,
emission standards must address in
some manner the contribution to NO,
emissions of fuel-bound nitrogen.
Low nitrogen fuels, such as premium
distillate fuel oil and natural gas, are
now being fired in nearly all stationary
gas turbines. Energy supply
considerations, however, may cause
more gas turbines to fire heavy fuel oils
and synthetic fuels in the future. A
standard based on present practice of
firing low nitrogen fuels, therefore,
would too rigidly restrict the use of high
nitrogen fuel, especially in light of the
uncertainty in world energy markets.
Since control technology is not in
reducing organic NO, emissions from
gas turbines, the possibility of basing
standards on removal of nitrogen from
the fuel prior to combustion was
considered. The cost of removing
nitrogen from fuel oil, however, ranges
from $2.00 to $3.00 per barrel. Another
alternative considered was exempting
gas turbines using high nitrogen fuels, as
some commenters requested. Exempting
gas turbines based on the type of fuel
used, however, would not require the
use of beat control technology in all
cases.
A third alternative considered was the
use of a fuel-bound nitrogen allowance.
Beyond some point it is simply not
reasonable to allow combustion of high
nitrogen fuels in gas turbines. In
addition, high nitrogen fuels, including
shale oil and coal-derived fuels, can be
used in other combustion devices where
some control of organic NO, emissions
is possible. Greater reduction of
nationwide NO, emissions could be
achieved by utilizing these fuels in
facilities where organic NO, emission
control is possible than in gas turbines
where organic NO, emissions are
essentially uncontrolled. This approach,
therefore, balances the trade-off
between allowing unlimited selection of
fuels for gas turbines controlling NO,
emissions.
A limited fuel-bound nitrogen
allowance which would allow increased
NO, emissions above the numerical NO,
emissions limits including in the
promulgated standards seems most
reasonable. An upper limit on this
allowance of 50 ppm NO, was selected.
Such a limit would allow approximately
50 percent of existing heavy fuel oils to
be fired in stationary gas turbines. (See
Volume I of the SSEIS.) This approach is
considered a reasonable means of
allowing flexibility hi the selection of
fuels while achieving reductions hi NO,
emissions from stationary gas turbines.
(See Control Technology for further
discussion.)
A number of commenters felt the
efficiency correction factor included to
the standards should use the overall
efficiency of a gas turbine installation
rather than the thermal efficiency of the
gas turbine itself. For example, many
commenters recommended that the
overall efficiency of a combined cycle
gas turbine installation be used in this
correction factor.
Section 111 of the Clean air Act
requires that standards of performance
for new sources reflect the use of the
best system of emission reduction. With
the few exceptions noted above, water
injection is considered the best system
of emission control for reducing NO,
emissions from stationary gas turbines.
To be consistent with the intent of
section 111, the standards must reflect
the use of water injection independent
of any ancillary waste heat recovery
equipment which might be associated
with a gas turbine to increase its overall
efficiency. To allow an upward
adjustment in the NO, emission limit
based on the overall efficiency of a
combined cycle gas turbine could mean
that water injection might not have to be
applied to the gas turbine. Thus, the
standards would not reflect the use of
the best system of emission reduction.
Therefore, the efficiency factor must be
based on the gas turbine efficiency
itself, not the overall efficiency of a gas
turbine combined with other equipment.
Test Methods and Monitoring
A large number of commenters
objected to the amount of monitoring
required. The proposed standards called
for daily monitoring of sulfur content,
nitrogen content and lower heating
value of the fuel The commenters were
generally in favor of less frequent
periodic monitoring.
These comments seem reasonable.
Therefore, the standards have been
changed to permit determination of
sulfur content, nitrogen content, and
lower heating value only when a fresh
supply of fuel is added to the fuel
storage facilities for a gas turbine.
Where gas turbines are fueled without
intermediate storage, such as along oil
and gas transport pipelines, daily
monitoring is still required by the
standards unless the owner or operator
can show that the composition of the
fuel does not fluctuate significantly. In
these cases, the owner or operator may
develop an individual monitoring
schedule for determining fuel sulfur
content nitrogen content and lower
heating value. These schedules must be
substantiated by data and submitted to
the Administrator for approval on a
case-by-case basis.
Several commenters stated that the
standards should be clarified to allow
the performance test to be performed by
the gas turbine manufacturer in lieu of
the owner/operator. To simplify
verification of compliance with the
standards and to reduce costs to
everyone involved, the recommendation
was made that each gas turbine be
performance tested at the
manufacturer's site. The commenters
maintained that gas turbines should not
be required to undergo a performance
test at the owner/operator's site if they
have been shown to comply with the
standard by the gas turbine
manufacturer.
Section 111 of the Clean Air Act is not
flexible enough to permit the use of a
formal certification program such as that
described by the commenter.
Responsibility for complying with the
standards ultimately rests with the
owner/operator, not with the gas turbine
manufacturers. The general provisions
of 40 CFR Part 60, however, which apply
to all standards of performance, allow
the use of approaches other than
performance tests to determine
compliance on a case-by-case basis. The
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alternate approach must demonstrate to
the Administrator's satisfaction that the
facility is in compliance with the
standard. Consequently, gas turbine
manufacturers' tests may be considered,
on a case-by-case basis, in lieu of
performance tests at the owner/
operator's site to demonstrate
compliance with the standards. For a
gas turbine manufacturers^ test to be
acceptable in lieu of a performance test,
as a minimum the operating conditions
of the gas turbine at the installation site
would have to be shown to be similar to
those during the. manufacturer's test In
addition, this would not preclude the
Administrator from requiring a
performance test at any time to
demonstrate compliance with the
standards.
Miscellaneous
It should be noted that standards of
performance for new stationary sources
established under section 111 of the
Clean Air Act reflect:
". . . application of the best technological
system of continuous emission reduction
which (taking into consideration the cost of
achieving such emission reduction, any
nonair quality health and environment
impact and energy requirements) the
Administrator determines has been
adequately demonstrated, [section lll(a)(l)]
Although there may be emission
control technology available that can
reduce emissions below those levels
required to comply with standards of
performance, this technology might not
be selected as the basis of standards of
performance due to costs associated
with its use. Accordingly, standards of
performance should not be viewed as
the ultimate in achievable emission
control. In fact, the Act requires (or has
potential for requiring) the imposition of
a more stringent emission standard in
several situations.
For example, applicable costs do not
play as prominent a role in determining
the "lowest achievable emission rate"
for new or modified sources located in
nonattainment areas, i.e., those areas
where statutorily mandated health and
welfare standards are being violated. In
this respect, section 173 of the act
requires that a new or modified source
constructed in an area which exceeds
the National Ambient Air Quality
Standard (NAAQS) must reduce
emissions to the level which reflects the
"lowest achievable emission rate"
(LAER), as defined in section 171(3), for
such category of source. The statute
defines LAER as that rate of emission
which reflects:
(A) The most stringent emission
limitation which is contained in the
implementation plan of any State for
such class or category of source, unless
the owner or operator of the proposed
source demonstrates that such
limitations are not achievable, or
(B) The most stringent emission
limitation which is achieved in practice
by such class or category of source,
whichever is more stringent
In no event can the emission rate
exceed any applicable new source
performance standard (section 171(3)).
A similar situation may arise under
the prevention of significant
deterioration of air quality provisions of
the Act (part C). These provisions
require that certain sources (referred to
in section 169(1)) employ "best available
control technology" (as defined in
section 169(3)) for all pollutants
regulated under the Act. Best available
control technology (BACT) must be
determined on a case-by-case basis,
taking energy, environmental and
economic impacts, and other costs into
account. In no event may the application
of BACT result in emissions of any
pollutants which will exceed the
emissions allowed by any applicable
standard established pursuant to section
111 (or 112) of the Act.
In all events, State implementation
plans (SIPs) approved or promulgated
under section 110 of the Act must
provide for the attainment and
maintenance of National Ambient Air
Quality Standards designed to protect
public health and welfare. For this
purpose, SIPs must in some cases
require greater emission reductions than
those required by standards of
performance for new sources.
Finally, States are free under section
116 of the Act to establish even more
stringent emission limits than those
established under section 111 or those
necessary to attain or maintain the
NAAQS under section 110. Accordingly,
new sources may in some cases be
subject to limitations more stringent
than EPA's standards of performance
under section 111, and prospective
owners and operators of new sources
should be aware of this possibility in
planning for such facilities.
This regulation will be reviewed 4
years from the date of promulgation.
This review will include an assessment
of such factors as the need for
integration with other programs, the
existence of alternative methods,
enforceability, and improvements in
emissions control technology.
No economic impact assessment
under Section 317 was prepared on this
standard. Section 317(a) requires such
an assessment only if "the notice of
proposed rulemaking in connection with
such standard ... is published in the
Federal Register after the date ninety
days after August 7,1977." This
standard was proposed in the Federal
Register on October 3,1977, less than
ninety days after August 7,1977, and an
assessment was therefore not required.
Dated: August 28.1979.
Douglas M. Costle,
Administrator,
PART 60STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
It is proposed to amend Part 60 of
Chapter I, Title 40 of the Code of Federal
Regulations as follows:
1. By adding subpart GG as follows:
Subpart GGStandard* of performance for
Stationary Gas Turbines
Sec.
60.330 Applicability and designation of
affected facility.
60.331 Definitions.
60.332 Standard for nitrogen oxides.
60.333 Standard for sulfur dioxide.
60.334 Monitoring of operations.
60.335 Test methods and procedures.
Authority: Sees. Ill and 301 (a) of the Clean
Air Act, as amended, [42 U.S.C. 1857c-7,
1857g(a)], and additional authority as noted
below.
Subpart GGStandards of
Performance for Stationary Gas
Turbines
S 60.330 Applicability and designation of
affected facility.
The provisions of this subpart are
applicable to the following affected
facilities: all stationary gas turbines
with a heat input at peak load equal to
or greater than 10.7 gigajoules per hour,
based on the lower heating value of the
fuel fired.
S 60.331 Definitions.
As used in this subpart, all terms not
defined herein shall have the meaning
given them in the Act and in subpart A
of this part.
(a) "Stationary gas turbine" means
any simple cycle gas turbine,
regenerative cycle gas turbine or any
gas turbine portion of a combined cycle
steam/electric generating system that is
not self propelled. It may, however, be
mounted on a vehicle for portability.
(b) "Simple cycle gas turbine" means
any stationary gas turbine which does
not recover heat from the gas turbine
exhaust gases to preheat the inlet
combustion air to the gas turbine, or
which does not recover heat from the
gas turbine exhaust gases to heat water
or generate steam.
(c) "Regenerative cycle gas turbine"
means any stationary gas turbine which
recovers heat from the gas turbine
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exhaust gases to preheat the inlet
combustion air to the gas turbine.
(d) "Combined cycle gas turbine"
means any stationary gas turbine which
recovers heat from the ga* turbine
exhaust gases to heat water or generate
steam.
(e) "Emergency gas turbine" means
any stationary gas turbine which
operates as a mechanical or electrical
power source only when the primary
power source for a facility has been
rendered inoperable by an emergency
situation.
(f) "Ice fog" means an atmospheric
suspension of highly reflective ice
crystals.
(g) "ISO standard day conditions"
means 288 degrees Kelvin, 60 percent
relative humidity and 101.3 kilopascals
pressure.
(h) "Efficiency" means the gas turbine
manufacturer's rated heat rate at peak
load in terms of heat input per unit of
power output based on the lower
heating value of the fuel.
(i) "Peak load" means 100 percent of
the manufacturer's design capacity of
the gas turbine at ISO standard day
conditions.
0) "Base load" means the load level at
which a gas turbine is normally
operated.
(k) "Fire-fighting turbine" means any
stationary gas turbine that is used solely
to pump water for extinguishing fires.
(!) "Turbines employed in oil/gas
production or oil/gas transportation"
means any stationary gas turbine used
to provide power to extract crude oil/
natural gas from the earth or to move
crude oil/natural gas, or products
refined from these substances through
pipelines.
(m) A "Metropolitan Statistical Area"
or "MSA" as defined by the Department
of Commerce.
(n) "Offshore platform gas turbines"
means any stationary gas turbine
located on a platform in an ocean.
(o) "Garrison facility" means any
permanent military installation.
(p) "Gas turbine model" means a
group of gas turbines having the same
nominal air flow, combuster inlet
pressure, combuster inlet temperature,
firing temperature, turbine inlet
temperature and turbine inlet pressure.
§60.332 Standard for nitrogen oxides.
(a) On and after the date on which the
performance test required by § 60.8 is
completed, every owner or operator
subject to the provisions of this subpart,
as specified in paragraphs (b), (c), and
(d) of this section, shall comply with one
of the following, except as provided in
paragraphs (e), (f), (g), (h), and (i) of this
section.
(1) No owner or operator subject to
the provisions of this subpart shall
cause to be discharged into the
atmosphere from any stationary gas
turbine, any gases which contain
nitrogen oxides in excess of:
(14 4)
STD = 0.0075 + p
32
where:
STD=aBowable NO, emissions (percent by
volume at 15 percent oxygen and on a
dry basis).
Y= manufacturer's rated heat rate at
manufacturer's rated load [kilojoules per
watt how) or, actual measured heat rate
based on lower heating value of fuel as
measured at actual peak load for the
facility. The value of Y shall not exceed
14.4 kilojoules per watt hour.
F=NO, emission allowance for fuel-bound
nitrogen as defined in part (3) of this
paragraph.
t2) No owner or operator subject to the
provisions of this subpart shall cause to be
discharged into the atmosphere from any
stationary gas turbine, any gases which
contain nitrogen oxides in excess of:
STD = 0.0150 (-) + F
where:
STD=allowable NO, emissions (percent by
Toiume at 15 percent oxygen and on a
dry basis).
Y = manufacturer's rated heat rate at
manufacturer'i rated peak load
(kilajoules per watt hour), or actual
measured heat rate based on lower
heating value of fuel as measured at
actual peak load for the facility. The
value of Y shall not exceed 14.4
kilojoules per watt hour.
F=NO, emission allowance for fuel-bound
nitrogen as defined in part (3) of this
paragraph.
(3) F shall be defined according to the
nitrogen content of the fuel as follows:
Fuel-Bound Nitrogen F
(percent by neigM) {NO percent by »olume)
N < 0 0)5
0 015 < H < 0 1
0 1 « N ; 0 ?5
N > 0.25
0 04(M)
0.004 0 0067(N-O.I)
0.005
where:
N = the nitrogen content of the fuel (percent
by weight).
Manufacturers may develop custom
fuel-bound nitrogen allowances for each
ga* turbine model they manufacture.
These fuel-bound nitrogen allowances
shall be substantiated with data and
must be approved for use by the
Administrator before the initial
performance test required by 5 60.8.
Notices of approval of custom fuel-
bound nitrogen allowances will be
published in the Federal Register.
(b) Stationary gas turbines with a heat
input at peak loed greater than 107.2
gigajoules per hour (100 million Btu/
hour] based on the lower heating value
of the fuel fired except as provided in
§ 60.332(d) shall comply with the
provisions of § 60.332(a)(l).
(c) Stationary gas turbines with a heat
input at peak load equal to or greater
than 10.7 gigajoules per hour (10 million
Btu/hour) but less than or equal to 107.2
gigajoules per hour (100 million Btu/
hour} based on the lower heating value
of the fuel fired, shall comply with the
provisions of § 60.332(a)(2).
(d) Stationary gas turbines employed
in oil/gas production or oil/gas
transportation and not located in
Metropolitan Statistical Areas; and
offshore platform turbines shall comply
with the provisions of § 60.332(a)(2).
(e) Stationary gas turbines with a heat
input at peak load equal to or greater
than 10.7 gigajoules per hour (10 million
Btu/hour) but less than or equal to 107.2
gigajoules per hour (100 million Btu/
hour) based on the lower heating value
of the fuel fired and that have
commenced construction prior to
October 3,1962 are exempt from
paragraph (a) of this section.
(f) Stationary gas turbines using water
or steam injection for control of NO,
emissions are exempt from paragraph
(a) when ice fog is deemed a traffic
hazard by the owner or operator of the
gas turbine.
(g) Emergency gas turbines, military
gas turbines for use in other than a
garrison facility, military gas turbines
installed for use as military training
facilities, and fire fighting gas turbines
are exempt from paragraph (a) of this
section.
(h) Stationary gas turbines engaged by
manufacturers in research and
development of equipment for both gas
turbine emission control techniques and
gas turbine efficiency improvements are
exempt from paragraph (a) on a case-by-
case basis as determined by the
Administrator.
(i) Exemptions from the requirements
of paragraph (a) of this section will be
granted on a case-by-case basis as
determined by the Administrator in
specific geographical areas where
mandatory water restrictions are
required by governmental agencies
because of drought conditions. These
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exemptions will be allowed only while'
the mandatory water restrictions are in
effect.
5 60.333 Standard for sulfur dioxide.
On and after the date on which the
performance test required to be
conducted by § BO.ff is completed, every
owner or operator subject to the
provision of this subpart shall comply
with one or the other of the following
conditions:
(a) No owner or operator subject to
the provisions of this subpart shall
cause to be discharged into the
atmosphere from any stationary gas
turbine any gases which contain sulfur
dioxide in excess of 0.015 percent by
volume at 15 percent oxygen and on a
dry basis.
(b) No owner or operator subject to
the provisions of this subpart shall burn
in any stationary gas turbine any fuel
which contains sulfur in excess of 0.8
percent by weight.
§ 60.334 Monitoring of operations.
(a) The owner or operator of any
stationary gas turbine subject to the
provisions of this subpart and using
water injection to control NO, emissions
shall install and operate a continuous
monitoring system to monitor and record
the fuel consumption and the ratio of
water to fuel being fired in the turbine.
This system shall be accurate to within
±5.0 percent and shall be approved by
the Administrator.
(b) The owner or operator of any
stationary gas turbine subject to the
provisions of this subpart shall monitor
sulfur content and nitrogen content of
the fuel being fired in the turbine. The
frequency of determination of these
values shall be as follows:
(1) If the turbine is supplied its fuel
from a bulk storage tank, the values
shall be determined on each occasion
that fuel is transferred to the storage
tank from any other source.
(2) If the turbine is supplied its fuel
without intermediate bulk storage the
values shall be determined and recorded
daily. Owners, operators or fuel vendors
may develop custom schedules for
determination of the values based on the
design and operation of the affected
facility and the characteristics of the
fuel supply. These custom schedules
shall be substantiated with data and
must be approved by the Administrator
before they can be used to comply with
paragraph (b) of this section.
(c) For the purpose of reports required
under § 60.7(c), periods of excess
emissions that shall be reported are
defined as follows:
(1) Nitrogen oxides. Any one-hour
period during which the average water-
to-fuel ratio, as measured by the
continuous monitoring system, falls
below the water-to-fuel ratio determined
to demonstrate'compliance with 8 60.332
by the performance test required in .
8 60.8 or any period during which the
fuel-bound nitrogen of the fuel is greater
than the maximum nitrogen content
allowed by the fuel-bound nitrogen
allowance used during the performance
test required hi 8 60.8. Each report shall
include the average water-to-fuel ratio,
average fuel consumption, ambient
conditions, gas turbine load, and
nitrogen content of the fuel during the
period of excess emissions, and the
graphs or figures developed under
8 60.335[a).
(2) Sulfur dioxide. Any daily period
during which the sulfur content of the.
fuel being fired in the gas turbine
exceeds 0.8 percent.
(3) Ice fog. Each period during which
an exemption provided in 8 60.332(g) is
in effect shall be reported in writing to
the Administrator quarterly. For each
period the ambient conditions existing
during the period, the date and time the
air pollution control system was
deactivated, and the date and time the
air pollution control system was
reactivated shall be reported. All
quarterly reports shall be postmarked by
the 30th day following the end'of each
calendar quarter.
(Sec. 114 of the Clean Air Act as amended [42
U.S.C. 1857C-9]).
$ 60.335 Test methods and procedures.
(a) The reference methods in
Appendix A to this part, except as
provided in § 60.8(b], shall be used to
determine compliance with the
standards prescribed in § 60.332 as
follows:
(1) Reference Method 20 for the
concentration of nitrogen oxides and
oxygen. For affected facilities under this
subpart, the span value shall be 300
parts per million of nitrogen oxides.
(i) The nitrogen oxides emission level
measured by Reference Method 20 shall
be adjusted to ISO standard day
conditions by the following ambient
condition correction factor:
NOV- (N0v
Obs
Obs
(Hobs - 0.00633)
'AMB j.53
where:
NO, = emissions of NO, at 15 percent oxygen
and ISO standard ambient conditions,
NOIOM=measured NO, emissions at 15
percent oxygen, ppmv.
Pref=reference combuster inlet absolute
pressure at 101.3 kilopascals ambient
pressure.
FOB. = measured combustor inlet absolute
pressure at test ambient pressure.
H,,,, = specific humidity of ambient air at test.
e = transcendental constant (2.718).
TAKE = temperature of ambient air at test.
The adjusted NO, emission level shall
be used to determine complianre with
§ 60.332.
(ii) Manufacturers may develop
custom ambient condition correction
factors for each gas turbine model they
manufacture in terms of combustor inlet
pressure, ambient air pressure, ambient
air humidity and ambient air
temperature to adjust the nitrogen
oxides emission level measured by the
performance test as provided for in
i 60.8 to ISO standard day conditions.
These ambient condition correction
factors shall be substantiated with data
and must be approved for use by the
Administrator before the initial
performance test required by § 60.8.
Notices of approval of custom ambient
condition correction factors will be
published in the Federal Register.
(iii) The water-to-fuel ratio necessary
to comply with § 60.332 will be
determined during the initial
performance test by measuring NO,
emission using Reference Method 20 and
the water-to-fuel ratio necessary to
comply with $ 60.332 at 30, 50, 75, and
100 percent of peak load or at four
points in the normal operating range of
the gas turbine, including the minimum
point in the range and peak load. All
loads shall be corrected to ISO
conditions using the appropriate
equations supplied by the manufacturer.
(2) The analytical methods and
procedures employed to determine the
nitrogen content of the fuel being fired
shall be approved by the Administrator
and shall be accurate to within ±5
percent.
(b) The method for determining
compliance with 8 60.333, except as
provided in § 60.8(b), shall be as
follows:
(1) Reference Method 20 for the
concentration of sulfur dioxide and
oxygen or
(2) ASTM D2880-71 for the sulfur
content of liquid fuels and ASTM
D1072-70 for the sulfur content of
gaseous fuels. These methods shall also
be used to comply with § 60.334(b).
(c) Analysis for the purpose of
determining the sulfur content and the
nitrogen content of the fuel as required
by § 60.334(b), this subpart, maybe
performed by the owner/operator, a
service contractor retained by the
owner/operator, the fuel vendor, or any
other qualified agency provided that the
analytical methods employed by these
agencies comply with the applicable
paragraphs of this section.
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(Sec. 114 of the Clean Air Act as amended [42
U.S.C. 18570-81]).
Appendfc AReference Methods
2, Part 60 is amended by adding
Reference Method 20 to Appendix A as
follows:
*****
Method 20Determination of Nitrogen
Oxides, Sulfur Dioxide, and Oxygen
Emissions from Stationary Gas Turbines
I. Applicability and Principle
1.1 Applicability. This method is
applicable for the determination of nitrogen
oxides (NO,), sulfur dioxide (SO:,), and
oxygen (O?) emissions from stationary gas
turbines. For the NO, and Oa determinations.
this method includes: (1) measurement
system design criteria, (2) analyzer
performance specifications and performance
test procedures; and (3) procedures for
emission testing.
1.2 Principle. A gas sample is
continuously extracted from the exhaust
ttream of a stationary gas turbine; 8 portion
of the sample stream is conveyed to
instrumental analyzers for determination of
NO, and O> content. During each NO, and
OO> determination, a separate measurement
of SO, emissions is made, using Method 6, or
it equivalent. The Oa determination is used to
adjust the NO, and SOj concentrations to a
reference condition.
2. Definitions
2.1 Measurement System. The total
equipment required for the determination of a
gas concentration or a gas emission rate. The
system consists of the following major
subsystems:
2.1.1 Sample Interface. That portion of a
system that is used for one or more of the
following: sample acquisition, sample
transportation, sample conditioning, or
protection of the analyzers from the effects of
the stack effluent.
2.1.2 NO, Analyzer. That portion of the
system that senses NO, and generates an
output proportional to the gas concentration.
2.1.3 Oj Analyzer. That portion of the
system that senses O2 and generates an
output proportional to the gas concentration.
2.2 Span Value. The upper limit of a gas
concentration measurement range that is
specified for affected source categories in the
applicable part of the regulations.
23 Calibration Gas. A known
concentration of a gas in an appropriate
diluent gas.
2/4 Calibration Error. The difference
bet ween the gas concentration indicated by
the measurement system and the known
concentration of the calibration gas.
2.6 Zero Drift The difference in the
measurement system output readings before
and after a stated period of operation during
which no unscheduled maintenance, repair,
or adjustment took place and the input
concentration at the time of the
measurements was zero.
2.6 Calibration Drift. The difference in the
measurement system output readings before
and after a stated period of operation during
which no unscheduled maintenance, repair,
or adjustment took place and the input at the
time of the measurements was a high-level
value.
2.7 Residence Time. The elapsed time
from the moment the gas sample enters the
probe tip to the moment the same gas sample
reaches the analyzer inlet.
2.8 Response Time. The amount of time
required for the continuous monitoring
system to display on the data output 95
percent of a step change in pollutant
concentration.
2.9 Interference Response. The output
response of the measurement system to a
component in the sample gas, other than the
gas component being measured.
3. Measurement System Performance
Specifications
3.1 NO, to NO Converter. Greater than 90
percent conversion efficiency of NOa to NO.
. 3.2 Interference Response. Less than ± 2
percent of the span value.
3.3 Residence Time. No greater than 30
seconds.
3.4 Response Time. No greater than 3
minutes.
3.5 Zero Drift. Less than ± 2 percent of
the span value.
3.6 Calibration Drift. Less than ± 2
percent of the span value.
4. Apparatus and Reagents
4.1 Measurement System. Use any
measurement system for NO, and O2 that is
expected to meet the specifications in this
method. A schematic of an acceptable
measurement system is shown in Figure 20-1.
The essential components of the
measurement system are described below:
Figure 20 1. Measurement system design for stationary gas turbines.
EXCESS
SAMPLE TO VENT
4.1.1 Sample Probe. Heated stainless
steel, or equivalent, open-ended, straight tube
of rofflcient length to traverse the sample
points.
4.1.2 Sample Line. Heated (>95'C)
stainless steel or Teflon *,bing to transport
the sample gas to the sample conditioners
and analyzers.
4.1.3 Calibration Valve Assembly. A
three-way valve assembly to direct the zero
and calibration gases to the sample
conditioners and to the analyzers. The
calibration valve assembly shall be capable
of blocking the sample gas flow and of
introducing calibration gases to the
measurement system when in the calibration
mode.
4.1.4 NOa to NO Converter. That portion
of the system that converts the nitrogen
dioxide (NOi) in the sample gas to nitrogen
oxide (NO). Some analyzers are designed to
measure NO, as NO* on a wet basis and can
be used without an NO, to NO converter or n
moisture removal trap provided the sample
line to the analyzer is heated (>95'C) to thv
inlet of the analyzer. In addition, an NOs to
NO converter is not necessary if the NOj
portion of the exhaust gas is less than 5
percent of the total NO, concentration. As «<
guideline, an NO, to NO converter is not
necessary if the gas turbine is operated at 90
percent or more of peak load capacity. A
converter is necessary under lower load
conditions.
4.1.5 Moisture Removal Trap. A
refrigerator-type condenser designed to
continuously remove condensate from the
sample gas. The moisture removal trap is not
necessary for analyzers that can measure
NO, concentrations on a wet basis; for these
analyzers, (a) heat the sample line up to the
inlet of the analyzers, (b) determine the
moisture content using methods subject to I hi
approval of the Administrator, and (c) correc-
the NO, and O, concentrations to a dry basis
4.1.6 Particulate Filter. An in-stack or an
out-of-stack glass fiber filter, of the type
specified in EPA Reference Method 5:
however, an out-of-stack filter is
recommended when the stack gas
temperature exceeds 250 to 300°C.
4.1.7 Sample Pump. A nonreactive leak
free sample pump to pull the sample gas
through the system at a flow rate sufficient t<
minimize transport delay. The pump shall be
made from stainless steel or coated with
Teflon or equivalent.
4.1.8 Sample Gas Manifold. A sample gdf-
manifold to divert portions of the sample g.ts
stream to the analyzers. The manifold may be
constructed of glass, Teflon, type 316
stainless steel, or equivalent.
4.1.9 Oxygen and Analyzer. An analyze)
to determine the percent Oi concentration of
the sample gas stream.
4.1.10 Nitrogen Oxides Analyzer. An
analyzer to determine the ppm NO,
concentration in the sample gas stream.
4.1.11 Data Output. A strip-chart recorder.
analog computer, or digital recorder for
recording measurement data.
4.2 Sulfur Dioxide Analysis. EPA
Reference Method 6 apparatus and reagent*
4.3 NO, Caliberation Gases. The
calibration gases for the NO, analyzer may
be NO in N,, NO, in air or N,, or NO and NO,
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in Nj. For NOX measurement analyzers thai
require oxidation of NO to NOt, the
calibration gases must be in the form of NO
in Nj. Use four calibration gas mixtures as
specified below:
4.3.1 High-level Gas. A gas concentration
that is equivalent to 80 to 90 percent of the
span value.
4.3.2 Mid-level Gas. A gas concentration
that is equivalent to 45 to 55 percent of the
span value.
4.3.3 Low-level Gas. A gas concentration
that is equivalent to 20 to 30 percent of the
span value.
4.3.4 Zero Gas. A gas concentration of
less than 0.25 percent of the span value.
Ambient air may be used for the NO, zero
grtS.
44 O» Calibration Gases. Use ambient air
it 20.9 percent as the high-level O, gas. Use a
gas concentration that is equivalent to 11-14
percent O2 for the mid-level gas. Use purified
nitrogen for the zero gas.
4.5 NO3/NO Gas Mixture. For
determining the conversion efficiency of thr
\O, to NO converter, use a calibration gas
mixture of NO2 and NO in N,. The mixture
uill be known concentrations of 40 to 60 ppm
NO* and 90 to 110 ppm NO and certified by
the gas manufacturer. This certification of gds
concentration must include a brief
description of the procedure followed in
determining the concentrations.
5. Measurement System Performance Trsl
Procedures
Perform the following procedures prior to
measurement of emissions (Section 6] and
only once for each test program, i.e./the
series of all test runs for a given gas turbine
engine.
5.1 Calibration Gas Checks. There are
two alternatives for checking the
concentrations of the calibration gases, (a)
The first is to use calibration gases that are
documented traceable to National Bureau of
Standards Reference Materials. Use
Traceability Protocol for Establishing True
Concentrations of Gases Used for
Calibrations and Audits of Continuous
Source Emission Monitors (Protocol Number
1) that is available from the Environmental
Monitoring and Support Laboratory. Quality
Assurance Branch. Mail Drop 77,
Environmental Protection Agency, Research
Triangle Park, North Carolina 27711. Obtain a
certification from the gas manufacturer that
the protocol was followed. These calibration
gases are not to be analyzed with the
Reference Methods, (b) The second
alternative is to use calibration gases not
prepared according to the protocol. If this
alternative is chosen, within 1 month prior to
the emission test, analyze each of the
calibration gas mixtures in triplicate using
Reference Method 7 or the procedure outlined
in Citation B.I for NO, and use Reference
Method 3 for O». Record the results on a data
sheet (example is shown in Figure 20-2). For
the low-level, mid-level, or high-level gas
mixtures, each of the individual NO,
an.ilytir.rfl results must be within 10 percent
(or 10 ppm. whichever is greater) of the
triplit.tu- set average (O, test results must be
within 0.5 percent O,); otherwise, discard the
entire set and repeat the triplicate analyses.
If the average of the triplicate reference
method lest results is within 5 percent for
NO, gas or 0.5 percent Oi for the O» gas of
the calibration gas manufacturer's tag value,
use the tag value; otherwise, conduct at least
three additional reference method test
analyses until 1he results of six individual
NO, runs (the three original plus three
additional) agree within 10 percent (or 10
ppm, whichever is greater) of the average (Oj
test results must be within 0.5 percent Oz).
Then use this average for the cylinder value.
5.2 Measurement System Preparation.
Prior to the emission test, assemble the
measurement system following the
manufacturer's written instructions in
preparing and operating the NOi to NO
Converter, the NO, analyzer, the Ot analyzer,
and other components.
Date.
.(Must be within 1 month prior to the test period)
Reference method used.
Sample run
1
2
3
Average
Maximum % deviation'1
Gas concentration, ppm
Low level*
Mid leveJb
High level0
3 Average must b*20 to 30% of span value.
b Average must be 45 to 55% of span value
c Average must be 80 to 90% of span value.
d Must be < ± 10% of applicable average or 10 ppm.
whichever is greater.
Figure 20-2. Analysis of calibration gases
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5.3 Calibration Check. Conduct the
calibration checks for both the NO, and the
O, analyzers as follows:
5.3.1 After the measurement system has
been prepared for use (Section 5.2), introduce
zero gases and the mid-level calibration
gases; set the analyzer output responses to
the appropriate levels. Then introduce each
of the remainder of the calibration gases
described in Sections 4.3 or 4.4, one at a time.
to the measurement system. Record the
responses on a form similar to Figure 20-3.
5.3.2 If the linear curve determined from
the zero and mid-level calibration gas
responses does not predict the actual
response of the low-level (not applicable for
the Ot analyzer] and high-level gases within
±2 percent of the span value, the calibration
shall be considered invalid. Take corrective
measures on the measurement system before
proceeding with the test.
5.4 Interference Response. Introduce the
gaseous components listed in Table 20-1 into
the measurement system separately, or as gas
mixtures. Determine the total interference
output response of the system to these
components in concentration units; record the
values on a form similar to Figure 20-4. If the
sum of the interference responses of the test
gases for either the NO, or Oi analyzers is
greater than 2 percent of the applicable span
value, take corrective measure on the
measurement system.
Tabto 20-1.Interference Test Gas Concentration
CO 500±50 ppm.
SO, 200±20 ppm.
CO, ,. 10± 1 percent
O.. 20 9± 1
percent
DttMol «*' .
Fiqut* 20 4 In1i-r1«rence re>po<>M
Turbine type:
Date:
Identification number,
Test number
Analyzer type:.
Identification number.
Cylinder Initial analyzer Final analyzer Difference:
value, response, responses, initial-final,
ppm or % ppm or % ppm or % ppm or %
Zero gas
Low - level gas
Mid - level gas
High - level gas
Percent drift =
Figure 20-3.
Absolute difference
X100.
Span value
Zero and calibration data.
Conduct an interference response test of
each analyzer prior to its initial use in the
field. Thereafter, recheck the measurement
system if changes are made in the
instrumentation that could alter the
interference response, e.g., changes in the
type of gas detector.
In lieu of conducting the interference
response test, instrument vendor data, which
demonstrate that for the test gases of Table
20-1 the interference performance
specification is not exceeded, are acceptable.
5.5 Residence and Response Time.
5.5.1 Calculate the residence time of the
sample interface portion of the measurement
system using volume and pump flow rate
information. Alternatively, if the response
time determined as defined in Section 5.5.2 is
less than 30 seconds, the calculations are not
necessary.
5.5.2 To determine response time, first
introduce zero gas into the system at the
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talibration valve until all readings are stable
then, switch to monitor the stack effluenl
until a stable reading can be obtained.
Record the upscale response time. Next,
introduce high-level calibration gas into the
system. Once the system has stabilized at the
high-level concentration, switch to monitor
the stack effluent and wait until a stable
value is reached. Record the downscale
response time. Repeat the procedure three
times A stable value is equivalent to a
change of less than 1 percent of span value
for 30 seconds or less than 5 percent of the
measured average concentration for 2
minutes. Record the response time data on a
form similar to Figure 20-5, the readings of
the upscale or downscale reponse time, and
report the greater time as the "response time"
for the analyzer. Conduct a response time
test prior to the Initial field use of the
measurement system, and repeat if changes
are made in the measurement system.
Date of test.
Analyzer type.
S/IM
Span gas concentration.
Analyzer span setting_
Upscale
1.
2.
3.
ppm
.seconds
. seconds
.seconds
Average upscale response.
1
Downscale 2
3
. seconds
. seconds
. seconds
. seconds
Average downscale response.
. seconds
System response time = slower average time =.
.seconds.
Figure 20-5 Response time
5 0 NO* NO Conversion Efficiency
Introduce to the system, at the calibration
i«lve assembly the NO2/NO gas mixtuie
(Section 4 5) Record the response of the, NO,
analyzer If the instrument response indicates
less than 90 percent NO2 to NO conversion.
make corrections to the measurement system
and repeat the check. Alternatively, the NO;
In \'O converter check described in Title 40
I1,111 86 Certification and Test Procedures fur
I Ii'ovy-Duty Engines for 1979 and Later
Wui1?I Years may be used. Other alternate
procedures may be used with approval of the
Adnimifttiator.
i> Km.main Measurement Test Procedure
b 1 Preliminaries
G l 1 Selection of a Sampling Site. Select a
sampling site as close as practical to the
exhaust of the turbine. Turbine geometry.
stack configuration, internal baffling and
point of introduction of dilution air will vary
for different turbine designs. Thus, each of
these factors must be given special
consideration in order to obtain a
representative sample. Whenever possible,
the sampling site shall be located upstream of
the point of introduction of dilution air into
the duct. Sample ports may be located before
or after the upturn elbow, in order to
accommodate the configuration of the turning
vanes and baffles and to permit a complete.
unobstructed traverse of the stack. The
sample ports shall not be located within 5
feet or 2 diameters (whichever is less) of the
gas discharge to atmosphere. For
supplementary-fired, combined-cycle plants.
the sampling site shall be located between
the gas turbine and the boiler. The diameter
of the sample ports shall be sufficient to
allow entry of the sample probe.
6.1.2 A preliminary O2 traverse is made
for the purpose of selecting low Ot values.
Conduct this test at the turbine condition that
is the lowest percentage of peak load
operation included in the program Follow the
procedure below or alternative procedures
subject to the approval of the Administrator
may be used:
6.1.2.1 Minimum Number of Points. Select
a minimum number of points as follows: (1)
eight, for stacks having cross-sectional areas
less than 1 5m2(161 ft2); (2) one sample point
for each 0.2 m2(2.2 ft2 of areas, for stacks of
1.5 m2 to 10.0 m' (16.1-107.6 ft=) in cross-
sectional area; and (3) one sample point for
each 0.4 ni'-'(4.4 ft2) of area, for stacks greater
than 10.0 m - (107.6 ft *) in cross-sectional
area. Note that for circular ducts, the number
of sample points must be a multiple of 4. and
for rectangular ducts, the number of points
must be one of those listed in Table 20-2:
therefore, round off the number of points
(upward), when appropriate.
6.1.2.2 Cross-sectional Layout and
Location of Traverse Points. After the numbtr
of traverse points for the preliminary O3
sampling has been determined, use Method 1
to located the traverse points.
6.1.2.3 Preliminary O"Measurement
While the gas turbine is operating at she
lowest percent of peak load, conduct a
preliminary O2 measurement as follows.
Position the probe at the first traverse point
and begin sampling The minimum sampling
time at each point shall be 1 minute plus the
average system response time. Determine the
average steady-state concentration of O2at
each point and record the data on Figrre 20-
6.
6.1.2.4 Selection of Emission It;;.)
Sampling Points Select the eight sampling
points at which the lowest O" conct r.lration
were obtained Use these same points for all
the test runs at the different turbine load
conditions More than eight points rray lie
used, if desired
Tabte 20-2.Cross-secUona: Layout to
Rectangular Stacks
No of traverse poinls
9
12
16
20
25
30
36
42.. . .
49
iayojt
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Federal Register / Vol. 44, No. 178 / Monday, September 10, 1979 / Rules and Regulations
Location:
Plant.
Date.
City, State.
Turbine identification:
Manufacturer
Model, serial number.
Sample point
Oxygen concentration, ppm
Figure 20-6. Preliminary oxygen traverse.
6.2 NO, and O, Measurement. This test is
to be conducted at each of the specified load
conditions. Three te'st runs 3t each load
condition constitute a complete test.
6.21 At the beginning of each NO, test
run and, as applicable, during the run, record
turbine data as indicated m Figure 20-7. Also.
record the location and number of the
traverse points on a diagram.
ILLING CODE 6MO-01-M
6.2.2 Position the probe at the tirst point
determined in the preceding section and
begin sampling. The minimum sampling time
at each point shall be at least 1 minute plus
the average system response time Determine
the average steady-state concentration of O,
and NO, at each point and record the data on
Figure 2O-8
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Federal Register / Vol. 44, No. 176 / Monday. September 10,1979 / Rules and Regulations
TURBINE OPERATION RECORD
Test operator Date
Turbine identification:
Type
Serial No
Location:
Plant
City
Ultimate fuel
Analysis C
H
N
Ambient temperature.
Ambient humidity
Test time start
Ash
H2O
Trace Metals
Na
Test time finish.
Fuel flow ratea_
Va
etcD
Water or steam.
Flow rate3
Ambient Pressure.
Operating load.
"Describe measurement method, i.e., continuous flow meter,
start finish volumes, etc.
bi.e., additional elements added for smoke suppression.
Figure 20-7. Stationary gas turbine data.
Turbine identification: Test operator name.
Serial N
Mndpl, sprial No . . ,._... .... _ NOu instnimp
Serial N
Location:
Sample
Tity State
Amhipnt prp«nrp _
Hato
Tp«t timp -start ,
n
n
Time,
mm.
f
NO*.
ppm
Test time - finish.
aAverage steady-state value from recorder or
instrument readout.
Figure 20-8. Stationary gas turbine sample point record.
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6.2.3 After sampling the last point,
conclude the test run by recording the final
turbine operating parameters and by
determining the zero and calibration drift, as
follows:
Immediately following the test run at each
load condition, or if adjustments are
necessary for the measurement system during
the tests, reintroduce the zero and mid-level
calibration gases as described in Sections 4.3,
and 4.4, one at a time, to the measurement
system at the calibration valve assembly.
(Make no adjustments to the measurement
system until after the drift checks are made).
Record the analyzers' responses on a form
similar to Figure 20-3. If the drift values
exceed the specified limits, the test run
preceding the check is considered invalid and
will be repeated following corrections to the
measurement system. Alternatively, the test
results may be accepted provided the
measurement system is recalibrated and the
calibration data that result in the highest
corrected emission rate are used.
6.3 SO2 Measurement. This test is
conducted only at the 100 percent peak load
condition. Determine SOj using Method 6, or
equivalent, during the test. Select a minimum
of six total points from those required for the
NO. measurements; use two points for each
sample run. The sample time at each point
shall be at least 10 minutes. Average the Oi
readings taken during the NO, test runs at
sample points corresponding to the SOj
traverse points (see Section 6.2.2) and use
this average Oi concentration to correct the
integrated SO2 concentration obtained by
Method 6 to 15 percent O2 (see Equation 20-
1).
If the applicable regulation allows fuel
sampling and analysis for fuel sulfur content
to demonstrate compliance with sulfur
emission unit, emission sampling with
Reference Method 6 is not required, provided
the fuel sulfur content meets the limits of the
regulation.
7. Emission Calculations
7.1 Correction to 15 Percent Oxygen.
Using Equation 20-1, calculate the NO, and
SOi concentrations (adjusted to 15 percent
Ot). The correction to 15 percent O2 is
sensitive to the accuracy of the O2
measurement. At the level of analyzer drift
specified in the method (±2 percent of full
scale), the change in the O> concentration
correction can exceed 10 percent when the Oj
content of the exhaust is above 16 percent Oi.
Therefore Oi analyzer stability and careful
calibration are necessary.
adj
(Equat10n
Where:
C«u=Pollutant concentration adjusted to
15 percent Oj (ppm)
Cn>««i=Pollutant concentration measured,
dry basis (ppm)
5.9=20.9 percent Oz -15 percent O2, the
defined O2 correction basis
Percent O2=Percent Oz measured, dry
basis (%}
7.2 Calculate the average adjusted NO,
concentration by summing the point values
and dividing by the number of sample points.
8. Citations
8.1 Curtis, F. A Method for Analyzing NO,
Cylinder Gases-Specific Ion Electrode
Procedure, Monograph available from
Emission Measurement Laboratory, ESED,
Research Triangle Park, N.C. 27711, October
1978.
[FR Doc 78-27993 Filed 9-7-7ft 8 45 am]
BILLING CODE (560-01-M
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Federal Register / Vol. 44, No. 187 / Tuesday, September 25, 1979 / Rules and Regulations
102
40 CFR Part 60
IFRL 1327-8]
Standards of Performance for New
Stationary Sources; General
Provisions; Definitions
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Final Rule.
SUMMARY: This document makes some
editorial changes and rearranges the
definitions alphabetically in Subpart
AGeneral Provisions of 40 CFR Part
60. An alphabetical list of definitions
will be easier to update and to use.
EFFECTIVE DATE: September 25,1979.
FOR FURTHER INFORMATION CONTACT:
Mr. Don R. Goodwin, Director, Emission
Standards and Engineering Division
(MD-13), U.S. Environmental Protection
Agency, Research Triangle Park, North
Carolina 27711, telephone (919) 541-
5271.
SUPPLEMENTARY INFORMATION: The
"Definitions" section (I 60.2) of the
General Provisions of 40 CFR Part 60
now lists 28 definitions by paragraph
designations. Due to the anticipated
increase in the number of definitions to
be added to the General Provisions in
the future, continued use of the present
system of adding definitions by
paragraph designations at the end of the
Hst could become administratively
cumbersome and could make the list
difficult to use. Therefore, paragraph
designations are being eliminated and
the definitions are rearranged
alphabetically. New definitions will be
added to { 60.2 of the General
Provisions jn alphabetical order
automatically.
Since this rule simply reorganizes
existing provisions and has no
regulatory impact, it is not subject to the
procedural requirements of Executive
Order 12044.
Dated. September 19,1979.
Edward F. Tuerk,
Acting Assistant Administrator for Air, Noise,
and Radiation.
40 CFR 60.2 is amended by removing
all paragraph designations and by
rearranging the definitions in
alphabetical order as follows:
{60.2 Definitions.
The terms used in this part are
defined in the Act or in this section as
follows:
"Act" means the Clean Air Act (42
U.S.C. 1857 et seq., as amended by Pub.
L. 91-604, 84 Stat. 1676).
"Administrator" means the
Administrator of the Environmental
Protection Agency or his authorized
representative.
"Affected facility" means, with
reference to a stationary source, any
apparatus to which a standard is
applicable.
"Alternative method" means any
method of sampling and analyzing for
an air pollutant which is not a reference
or equivalent method but which has
been demonstrated to the
Administrator's satisfaction to, in
specific cases, produce results adequate
for his determination of compliance.
"Capital expenditure" means an
expenditure for a physical or
operational change to an existing facility
which exceeds the product of the
applicable "annual asset guideline
repair allowance percentage" specified
in the latest edition of Internal Revenue
Service Publication 534 and the existing
facility's basis, as defined by section
1012 of the Internal Revenue Code.
"Commenced" means, with respect to
the definition of "new source" in section
lll(a)(2) of.the Act, that an owner or
operator has undertaken a continuous
program of construction or modification
or that an owner or operator has entered
into a contractual obligation to
undertake and complete, within a
reasonable time, a continuous program
of construction or modification.
"Construction" means fabrication.
erection, or installation of an affected
facility.
"Continuous monitoring system"
means the total equipment, required
under the emission monitoring sections
in applicable subparts, used to sample
and condition (if applicable), to analyze,
and to provide a permanent record of
emissions or process parameters.
"Equivalent method" means any
method of sampling and analyzing for
an air pollutant which has been
demonstrated to the Administrator's
satisfaction to have a consistent and
quantitatively known relationship to the
reference method, under specified
conditions.
"Existing facility" means, with
reference to a stationary source, any
apparatus of the type for which a
standard is promulgated in this part, and
the construction or modification of
which was commenced before the date
of proposal of that standard; or any
apparatus which could be altered in
such a way as to be of that type.
"Isokinetic sampling" means sampling
in which the linear velocity of the gas
entering the sampling nozzle is equal to
that of the undisturbed gas stream at the
sample point.
"Malfunction" means any sudden and
unavoidable failure of air pollution
control equipment or process equipment
or of a process to operate in a normal or
usual manner. Failures that are caused
entirely or in part by poor maintenance,
careless operation, or any other
preventable upset condition or
preventable equipment breakdown shall
not be considered malfunctions.
"Modification" means any physical
change in, or change in the method of
operation of, an existing facility which
increases the amount of any air
pollutant (to which a standard applies)
emitted into the atmosphere by that
facility or which results in the emission
of any air pollutant (to which a standard
applies) into the atmosphere not
previously emitted.
"Monitoring device" means the total
equipment, required under the
monitoring of operations sections in
applicable subparts, used to measure
and record (if applicable) process
parameters.
"Nitrogen oxides" means all oxides of
nitrogen except nitrous oxide, as
measured by test methods set forth in
this part.
"One-hour period" means any 60-
minute period commencing on the hour.
"Opacity" means the degree to which
emissions reduce the transmission of
light and obscure the view of an object
in the background.
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Federal Register / Vol. 44, No. 187 / Tuesday, September 25. 1979 / Rules and Regulations.
"Owner or operator" means any
person who owns, leases, operates,
controls, or supervises an affected
facility or a stationary source of which
an affected facility is a part.
"Particulate matter" means any finely
divided solid or liquid material, other
than uncombined water, as measured by
the reference methods specified under
each applicable subpart, or-an
equivalent or alternative method.
"Proportional sampling" means
sampling at a rate that produces a
constant ration of sampling rate to stack
gas flow rate.
"Reference method" means any
method of sampling and analyzing for
an air pollutant as described in
Appendix A to this part.
"Run" means the net period of time
during which an emission sample is
collected. Unless otherwise specified, a
run may be either intermittent or
continuous within the limits of good
engineering practice.
"Shutdown" means the cessation of
operation of an affected facility for any
purpose.
"Six-minute period" means any one of
the 10 equal parts of a one-hour period.
"Standard" means a standard of
performance proposed or promulgated
under this part.
"Standard conditions" means a
temperature of 293 K (68°F) and a
pressure of 101.3 kilopascals (29.92 in
Hg).
"Startup" means the setting in
operation of an affected facility for any
purpose.
"Stationary source" means any
building, structure, facility, or
installation which emits or may emit
any air pollutant and which contains
any one or combination of the following:
(a) Affected facilities.
(b) Existing facilities.
(c) Facilities of the type for which no
standards have been promulgated in this
part.
(Sec. 111. 301(a), Clean Air Act as amended
(42 U.S.C. 7411 and 7601(a))
|FRDoc 79-29769 Filed 9-24-79 8 45 am)
ILLING CODE 6SCO-01-M
IV-355
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Federal Register J Vol. 44. No. 208 / Thursday, October 25,1979 / Rules and Regulations
103
40 CFR Part 60
IFRL 1331-5]
Standards of Performance for New
Stationary Sources; Petroleum
Refinery Claus Sulfur Recovery Plants;
Amendment
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Final rule.
SUMMARY: This action deletes the
requirement that a Claus sulfur recovery
plant of 20 long tons per day (LTD) or
less must be associated with a "small
petroleum refinery" in order to be
exempt from the new source
performance standards for petroleum
refinery Claus sulfur recovery plants.
This action will result in only negligible
changes in the environmental, energy,
and economic impacts of the standards
EFFECTIVE DATE: October 25, 1979
ADDRESS: All comments received on the
proposal are available for public
inspection and copying at the EPA
Central Docket Section (A-130), Room
2903B, Waterside Mall, 401 M Street,
S.W., Washington, D.C. 20460. The
docket number is OAQPS-79-10.
FOR FURTHER INFORMATION CONTACT:
Don R. Goodwin, Director, Emission
Standards and Engineering Division
(MD-13), Environmental Protection
Agency, Research Triangle Park, North
Carolina 27711, telephone (919) 541-
5271.
SUPPLEMENTARY INFORMATION:
Background
On March 15, 1978, EPA promulgated
new source performance standards for
petroleum refinery Claus sulfur recovery
plants. These standards did not apply to
Claus sulfur recovery plants of 20 LTD
or less associated with a small
pe iroleum refinery, 40 CFR 60.100 (1978).
"Small petroleum refinery" was defined
as a "petroleum refinery which has a
crude oil processing capacity of 50.000
barrels per stream day or less, and
which is owned or controlled by a
refiner with a total combined crude oil
processing capacity of 137.500 barrels
per stream day or less," 40 Cl-'R
60 101 (m) (1978).
On May 12, 1978, two oil companies
filed a Petition for Review of these now
source performance standards. One
issue was whether the definition of
"small petroleum refinery" was unduly
restrictive.
On March 20,1979, EPA proposed to
amend trie definition of "small
petroleum refinery" by deleting the
requirement that it be "owned or
controlled by a refiner with a total
combined crude oil processing capacity
of 137,500 barrels per stream day (BSDJ
or less," 44 FR 17120. This proposal
would have had a negligible effect on
sulfur dioxide (SO2) emissions, casts,
and energy consumption. The oil
company petitioners agreed to dismiss
their entire Petition for Review if tbe
final regulation did not differ
substantively from this proposal.
EPA provided a 60 day period for
comment on the proposal and the
opportunity for interested personi to
request a hearing. The comment period
closed May 21,1979. EPA received six
written comments and no requests for a
hearing
Summary of Amendment
The promulgated amendment deletes
the requirement that a Claus sulfur
recovery plant of 20 LTD or less must be
associated with a "small petroleum
refinery" in order to be exempt from the
new source performance standards for
such plants. Thus, Ihe final standard wiU
apply to any petroleum refinery Glaus
sulfur recovery plant of more than 20
LTD processing capacity. This
amendment will apply, like the
.standards themselves, to affected
facilities, the construction or
modification of which commenced after
October 4,1976, the date the standards
of performance for petroleum refinery
Clans sulfur recovery plants were
proposed.
Environmental. Energy, and Ecomonic
Impacts
The promulgated amendment will
result in a negligible increase in
nationwide sulfur dioxide emissions
compared to the proposed amendment
and the existing standard. The
promulgated amendment will also have
essentially no impact on other aspects of
environmental quality, such as solid
waste disposal, water pollution, or
noise Finally, the promulgated
amendment will have essentially no
impact on nationwide energy
consumption or refinery product prices.
Summary of Comments and Rationale
All six comments received were from
the petroleum refinery industry. Two
commenters expressed agreement with
the proposal. The other four also were
not opposed to the proposal, but felt the
definition of "small petroleum refinery"
was still too restrictive, as explained
below
Two of the four argued for deletion of
Hie 50,000 BSD refinery size cutoff and
also that sulfur recovery plant size was
not only a function of refinery size (as
they felt EPA had apparently assumed
in establishing the refinery size cutoff),
but depended on such factors as the
crude oil sulfur content and actual crude
oil throughput.
Tbe other two commenters, each
planning to construct small Claus sulfur
recovery plants, objected that the
environmental benefits of subjecting
small Claus sulfur recovery plants to the
standards was not substantial even
when a Claus sulfur recovery plant was
associated with a petroleum refinery of
more that 50,000 BSD capacity. EPA
agrees. Accordingly, EPA believes it is
appropriate under the circumstances to
delete the refinery size requirement.
Thus, the promulgated standard
would exempt from coverage by the
standards any Claus sulfur recovery
plant of 20 LTD or less. Alternatively,
the standards of performance for
petroleum refinery Claus sulfur recovery
plants would apply to all plants of more
than 20 LTD processing capacity.
Deletion of the refinery size
requirement from the standards will not
result in a significant increase in the
emissions of Sd from petroleum
refinery Claus sulfur recovery plants.
This, is due to the small number of small
Claus sulfur recovery plants (i.e., 20 LTD
or less capacity) that are likely to be
built at refineries of more than 50,000
BSD and the fact that most of these
exempted plants will still be required by
State regulations to achieve 99.0 percent
control of SO2 (compared to the 99.9
percent control required for large Claus
sulfur recovery plants). In many cases
the exempted Claus sulfur recovery
plants would be required to achieve
greater than 99.0 percent control of SO;
due to prevention of significant
deterioration (PSD) requirements This
change will also result in a negligible-
decrease in costs and essentially no
impart on energy and economic impacts.
compared to the proposed amendment.
Docket
Docket No OAQPS-79-10, containing
all supporting information used by EPA.
is available for public inspection and
copying between 8:00 a.m. and 4:00 p m.,
Monday through Friday, at EPA's
Central Docket Section. Room 2903B
(see ADDRESS Section of this
preamble).
The docketing system is intended to
allow members of the public and
industries involved to readily identify
and locate documents so that they can
intelligently and effectively participate
in the rulemaking process. Along with
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the statement of basis and purpose of
the promulgated rule and EPA responses
to comments, the contents of the dockets
will serve as the record in case of
judicial review [Section 307(d)(a)].
Miscellaneous
The effective date of this regulation is
October 25,1979. Section lll(b)(l)(B) of
the Clean Air Act provides that
standards of performance become
effective upon promulgation and apply
to affected facilities, construction or
modification of which was commenced
after the date of proposal on October 4,
1976 (41 FR 43866).
EPA will review this regulation four
years from the date of promulgation.
This jeview will include an assessment
of such factors as the need for
integration with other programs the
existence of alternative methods,
enforceability, and improvements in
emission control technology.
It should be noted that standards of
performance for new stationary sources
established under Section 111 of the
Clean Air Act reflect: "* * * application
of the best technological system of
continuous emission reduction which
(taking into consideration the cost of
achieving such emission reduction, any
non-air quality health and
environmental impact and energy
requirements) the Administrator
determines has been adequately
demonstrated." [Section lll(a)(l)]
Although there may be emission
control technology available that can
reduce emissions below those levels
required to comply with standards of
performance, this technology might not
be selected as the basis of standards of
performance due to costs associated
with its use. Accordingly, standards of
performance should not be viewed as
the ultimate inachievable emission
control. In fact, the Act requires (or has
potential for requiring) the imposition of
a more stringent emission standard in
several situations.
For example, applicable costs do not
play as prominent a role in determining
the "lowest achievable emission rate"
for new or modified sources locating in
nonattainment areas, i.e., those areas
where statutorily mandated health and
welfare standards are being violated. In
this respect, Section 173 of the Act
requires that a new or modified source
constructed in an area which exceeds
the National Ambient Air Quality
Standard (NAAQS) must reduce
emissions to the level which reflects the
"lowest achievable emission rate"
(LAER), as defined in Section 171(3), for
such category of source. The statute
defines LAER as that rate of emissions
based on the following, whichever is
more stringent:
(A) the most stringent emission
limitation which is contained in the
implementation plan of any State for
such class or category of source, unless
the owner or operator of the proposed
source demonstrates that such
limitations are not achievable, or
(B) the most stringent emission
limitation which is achieved in practice
by such class or category of source. In
no event can the emission rate exceed
any applicable new source performance
standard [Section 171(3)].
A similar situation may arise under
the prevention of significant
deterioration of air quality provisions of
the Act (part C). These provisions
require that certain sources [referred to
in Section 169(1)] employ "best
available control technology" [as
defined in Section 169(3)] for all
pollutants regulated under the Act. Best
available control technology (BACT)
must be determined on a case-by-case
basis, taking energy, environmental, and
economic impacts and costs into
account. In no event may the application
of BACT result in emissions of any
pollutants which will exceed the
emissions allowed by any applicable
standard established pursuant to
Section 111 (or 112) of the Act.
In all events, State implementation
plans (SIP's) approved or promulgated
under Section 110 of the Act must
provide for the attainment and
maintenance of NAAQS designed to
protect public health and welfare. For
this purpose, SIP's must in some cases
require greater emission reductions than
those required by standards of
performance for new sources.
Finally, States are free under Section
116 of the Act to establish even more
stringent emission limits than those
established under Section 111 or those
necessary to attain or maintain the
NAAQS under Section 110. Accordingly,
new sources may in some cases be
subject to limitations more stringent
than EPA's standards of performance
under Section 111; and prospective
owners and operators of new sources
should be aware of this possibility in
planning for such facilities.
Section 317 of the Clean Air Act
requires the Administrator to, among
other things, prepare an economic
assessment for revisions to new source
performance standards determined to be
substantial. Executive Order 12044
requires certain analyses of significant
regulations. Since this amendment lacks
the economic impact and significance to
require additional analyses, it is not
subject to the above requirements.
Dated: October 16, 1979.
Douglas M. Costle,
Administrator.
Part 60 of chapter I, Title 40 of the
Code of Federal Regulations is amended
as follows:
1. § 60.100 is amended by revising
paragraph (a), as follows:
f 60.100 Applicability and designation of
affected facility.
(a) The provisions of this subpart are
applicable to the following affected
facilities in petroleum refineries: fluid
catalytic cracking unit catalyst
regenerators, fuel gas combustion
devices, and all Glaus sulfur recovery
plants except Claus plants of 20 long
tons per day (LTD) or less. The Claus
sulfur recovery plant need not be
physically located within the boundaries
of a petroleum refinery to be an affected
facility, provided it processes gases
produced within a petroleum refinery.
(b) * * *
2. $ 60.101 is amended by revoking
and reserving paragraph (m), as follows:
§ 60.101 Definitions
*****
(m) [Reserved]
(Sec. Ill, 301(a), Clean Air Act as amended
(42 U.S.C. 7411, 7601(a)].)
|FR Doc. 79-32778 Filed 10-24-79: 845 am)
IV-357
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Federal Register / Vol. 44. No. 219 / Friday, November 9, 1979 / Rules and Regulations
104
[FRL 1342-6}
Regulations for Ambient Air Quality
Monitoring and Data Reporting
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Amendment to final rule.
SUMMARY: This action amends air
quality monitoring and reporting
regulations which were promulgated
May 10,1979 (44 FR 27558). The
amendments correct several technical
errors that were made in the
promulgation notice. The amendments
reflect the intent of the regulations as
discussed in the preambles to the
proposed (August 7,1978, 43 FR 34892)
and final regulations.
DATES: These amendments are effective
November 9,1979.
FOR FURTHER INFORMATION CONTACT:
Stanley Sleva, Monitoring and Data
Analysis Division, (MD-14)
Environmental Protection Agency,
Research Triangle Park, N.C. 27711.
telephone number 919-541-5351.
SUPPLEMENTARY INFORMATION: On May
10,1979, EPA promulgated a new 40 CFR
Part 58 entitled, "Ambient Air Quality
Surveillance." The new regulations
consist of requirements for monitoring
ambient air quality and reporting data to
EPA as well as other regulations such as
public reporting of a daily air quality
index. The requirements replace § 51.17
and portions of § 51.7 from 40 CFR Part
51 and make necessary reference
changes in Parts 51, 52, and 60. Other
accompanying changes were made to
Part 51, such as restructuring the
unchanged portion of § 51.7 into a new
subpart, adding regulations concerning
public notification of air quality
information, and applying quality
assurance requirements to such
monitoring as may be required by the
prevention of significant deterioration
program.
These amendments to the May 10,
1979, regulations correct technical errors
which were discovered after
promulgation. The corrections are
consistent with the intent of the
rulemaking and are therefore not being
proposed.
The last correction is in Part 60. The
correction involves a change of
references in § 60.25. The change was
proposed with the other regulations on
August 7,1978, but was inadvertently
left out of the final promulgation.
Part 60 of Title 40, Code of Federal
Regulations, is amended as follows:
Section 60.25, paragraph (e), is
amended by changing the reference to a
semi-annual report required by § 51.7 to
an annual report required by § 51.321.
As amended, | 60.25 reads as follows:
§ 0.25 Emission inventories, source
surveillance, reports.
*****
(e) The State shall submit reports on
progress in plan enforcement to the
Administrator on an annual (calendar
year) basis, commencing with the first
full report period after approval of a
plan or after promulgation of a plan by
the Administrator. Information required
under this paragraph must be included
in the annual report required by § 51.321
of this chapter.
*****
(Sec. 110, 301(a), 319 of the Clean Air Act as
amended [42 U S C 7410. 7601(a). 7619))
|FR Dor 70-34525 Filed 11-8-79 8 45 am]
Federal Register / Vol. 44, No. 233 / Monday. December 3, 1979
10 5
40 CFR Part 60
[FRL 1369-3]
New Source Performance Standards;
Delegation of Authority to the State of
Maryland
AGENCY: Environmental Protection
Agency.
ACTION: Final rulemaking.
SUMMARY: Pursuant to the delegation of
authority for New Source Performance
Standards (NSPS) to the State of
Maryland on September 15,1978, EPA is
today amending 40 CFR 60.4, Address, to
reflectJhis delegation.
EFFECTIVE DATE: December 3,1979.
FOR FURTHER INFORMATION CONTACT:
Tom Shiland, 215 597-7915.
SUPPLEMENTARY INFORMATION: A Notice
announcing this delegation is published
today elsewhere in this Federal Register.
The amended 60.4 which adds the
address of the Maryland Bureau of Air
Quality to which all reports, requests,
applications, submittals. and
communications to the Administrator
pursuant to this part must also be
addressed, is set forth below.
The Administrator finds good cause
for foregoing prior public notice and for
making this rulemaking effective
immediately in that it is an
administrative change and not one of
substantive content. No additional
substantive burdens are imposed on the
parties affected. The delegation which is
reflected by this administrative
amendment was effective on September
15,1978, and it serves no purpose to
delay the technical change of this
address to the Code of Federal
Regulations.
This rulemaking is effective
immediately, and is issued under the
authority of Section 111 of the Clean Air
Act, as amended, 42 U.S.C. 7411.
Dated: November 14,1979.
Douglas M. Costle,
Administrator.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amended
as follows:
1. In § 60.4 paragraph (b) is amended
by revising Subparagraph (V) to read as
follows:
§60.4 Address.
*****
(b) * * *
(AHU)' * *
(V) State of Maryland: Bureau of Air
Quality and Noise Control, Maryland State
Department of Health and Mental Hygiene,
201 West Preston Street, Baltimore, Maryland
21201.
IV-358
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Federal Register / Vol. 44. No. 237 / Friday. December 7. 1979 / Rules and Regulations
106
40 CFR Part 60
[FRL 1353-2]
Standards of Performance for New
Stationary Sources; Delegation of
Authority to State of Delaware
AGENCY: Environmental Protection
Agency.
ACTION: Final rule.
SUMMARY: This document amends 40
CFR 60.4 to reflect delegation to the
State of Delaware of authority to
implement and enforce certain
Standards of Performance for New
Stationary Sources.
EFFECTIVE DATE: December 7,1979.
FOR FURTHER INFORMATION CONTACT:
Joseph Arena, Environmental Scientist,
Air Enforcement Branch, Environmental
Protection Agency, Region III, 6th and
Walnut Streets, Philadelphia,
Pennsylvania 19106, Telephone (215)
597-4561.
SUPPLEMENTARY INFORMATION:
I. Background
On October 5,1978, the State of
Delaware requested delegation of
authority to implement and enforce
certain Standards of Performance for
New Stationary Sources for Sulfuric
Acid Plants. The request was reviewed
and on October 9,1979 a letter was sent
to John E. Wilson III, Acting Secretary,
Department of Natural Resources and
Environmental Control, approving the
delegation and outlining its conditions
The approval letter specified that if
Acting Secretary Wilson or any other
representatives had any objections to
the conditions of delegation they were
to respond within ten (10) days after
receipt of the letter. As of this date, no
objections have been received.
II. Regulations Affected by this
Document
Pursuant to the delegation of authority
for certain Standards of Performance for
New Stationary Sources to the State of
Delaware, EPA is today amending 40
CFR 60.4, Address, to reflect this
delegation. A Notice announcing this
delegation is published today in the
Notices Section of this Federal Register.
The amended § 60.4, which adds the
address of the Delaware Department of
Natural Resources and Environmental
Control, to which all reports, requests,
applications, submittals, and
communications to the Administrator
pursuant to this part must also be
addressed, is set forth below.
III. General
The Administrator finds good cause
for foregoing prior public notice and for
making this rulemakmg effective
immediately in that it is an
administrative change and not one of
substantive content. No additional
substantive burdens are imposed on the
parties affected. The delegation which is
reflected by this administrative
amendment was effective on October 9,
1979, and it serves no purpose to delay
the technical change of this address to
the Code of Federal Regulations
This rulemaking is effective
immediately, and is issued under the
authority of Section 111 of the Clean Air
Act as amended, 42 U.S.C. 7411.
Dated: December 3,1979.
Douglas M. Costle,
Administrator.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amended
as follows:
1. In § 60.4, paragraph (b) is amended
by revising subparagraph (I) to read as
follows:
§ 60.4 Address.
*****
(b) * ' *
(A)-(H) ' * *
(I) Stale of Delaware (for fossil fuel-fired
steam generators; incinerators; nitric acid
plants, asphalt concrete plants; storage
vessels for petroleum liquids; sulfuric acid
plants; and sewage treatment plants only.
Delaware Department of Natural Resources
and Environmental Control, Edward Tatnall
Building, Dover, Delaware 19901.
|FR Doc 79-37655 Filed 12-6-79. 8:45 am)
IV-359
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Federal Register / Vol. 44, No. 250 / Friday, December 28, 1979 / Rules and Regulations
107
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Part 60
(FRL 1366-3]
Standards of Performance for New
Stationary Sources; Adjustment of the
Opacity Standard for a Fossil Fuel-
Fired Steam Generator
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Final rule.
SUMMARY: This action adjusts the NSPS
opacity standard (40 CFR Part 60,
Subpart D) applicable to Southwestern
Public Service Company's Harrington
Station Unit #1 in Amarillo, Texas. The
action is based upon Southwestern's
demonstration of the conditions that
entitle it to such an adjustment under 40
CFR 60.11(e).
EFFECTIVE DATE: December 28,1979.
ADDRESS: Docket No. EN-79-13,
containing material relevant to this
rulemaking, is located in the U.S.
Environmental Protection Agency,
Central Docket Section, Room 2903 B,
401 M St., SW., Washington, D.C. 20460.
The docket may be inspected between 8
a.m. and 4 p.m. on weekdays, and a
reasonable fee may be charged for
copying.
The docket is an organized and
complete file of all the information
submitted to or otherwise considered by
the Administrator in the development of
this rulemaking. The docketing system is
intended to allow members of the public
and industries involved to readily
identify and locate documents so that
they can intelligently and effectively
participate in the rulemaking process.
FOR FURTHER INFORMATION CONTACT:
Richard Biondi, Division of Stationary
Source Enforcement (EN-341),
Environmental Protection Agency, 401 M
Street. SW., Washington, DC 20460,
telephone No. 202-755-2564.
SUPPLEMENTARY INFORMATION:
Background
The standards of performance for
fossil fuel-fired steam generators as
promulgated under Subpart D of Part 60
on December 23.1971 (36 FR 24876) and
amended on December 5,1977 [42 FR
61537) allow emissions of up to 20%
opacity (6-minute average), except that
27% opacity is allowed for one 6-minute
period in any hour. This standard also
requires continuous opacity monitoring
and requires reporting as excess
emissions all hourly periods during
which there are two or more 6-minute
periods when the average opacity
exceeds 20%
On December 15.1977, Southwestern
Public Service Company (SPSC) of
Amarillo, Texas, petitioned the
Administrator under 40 CF'R 60.11(e) to
adjust the 20% opacity standard
applicable to its Harrington Station
coal-fired Unit #1 in Amarillo. Texas.
The Administrator proposed, on June 29,
1979 (44 FR 37960), to grant the prtition
for adjustment, concluding that SPSC
had demonstrated the presence at its
Harrington Station Unit #1 of the
conditions that entitle it to such relief,
as specified in 40 CFR 60.11(e)(3).
These final regulations are identical to
the proposed ones. EPA hereby grants
SPSC's petition for adjustment for
Harrington Station Unit #1 from
compliance with the opacity standard of
40 CFR 60.42[a)(2). As an alternative,
SPSC shall not cause to be discharged
into the atmosphere from the Harrington
Station Unit #1 any gases which exhibit
greater than 35% opacity (6-minute
average), except that a maximum of 42%
opacity shall be permitted for not more
than one 6-minute period in any hour.
This adjustment will not relieve SPSC of
its obligation to comply with any other
federal, state or local opacity
requirements, or particulate matter, SO2
or NO, control requirements.
Comments
Two comment letters were received,
both from industry and both supporting
the proposed action. One industry
representative approved of EPA efforts
to adjust NSPS to account for well-
known opacity difficulties found in large
steam electric generating units which
have hot side electrostatic precipitators
and combust low-sulfur western coal.
A second industry representative
suggested that the use of Best Available
Control Technology on coal-fired units
has not assured compliance with
applicable opacity standards, and that
opacity standards do not complement
standards for particulate emissions. EPA
disagrees with this comment. Violations
of opacity standards generally reflect
violations of mass emission standards,
and EPA will continue to impose opacity
standards as a valued tool in insuring
proper operation and maintenance of air
pollution control devices.
Miscellaneous
This revision is promulgated under the
authority of Section 111 and 301(a) of
the Clean Air Act, as amended (42
U.S.C. 7411 and 7601(a)).
Dated: December 17. 1979.
Douglas M. Costle,
Administrator.
PART 60STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
40 CFR part 60 is amended as follows:
Subpart DStandards of Performance
for Fossil Fuel-Fired Steam Generators
1. Section 60.42 is amended by adding
paragraph (b)(l) as follows:
§ 60.42 Standard for particulate matter.
(a) * * *
(b)(l) On and after (the date of
publication of this amendment), no
owner or operator shall cause to be
discharged into the atmosphere from the
Southwestern Public Service Company's
Harrington Station Unit #1, in Amarillo,
Texas, any gases which exhibit greater
than 35% opacity, except that a
maximum of 42% opacity shall be
permitted for not more than 6 minutes in
any hour.
(Sec. Ill, 301(a), Clean Air Act as amended
(42, U.S.C. 7411, 7601))
2. Section 60.45(g)(l) is amended by
adding paragraph (i) as follows:
§ 60.45 Emission and fuel monitoring.
* * * * *
(8) * * *
(I)''*
(i) For sources subject to the opacity
standard of § 60.42(b)(l), excess
emissions are defined as any six-minute
period during which the average opacity
of emissions exceeds 35 percent opacity,
except that one six-minute average per
hour of up to 42 percent opacity need
not be reported.
|FR Doc 78-J9509 Filed 12-27-78 B 45 am |
108
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Part 60
[FRL 1392-6]
Standards of Performance for New
Stationary Sources; Delegation of
Authority to Commonwealth of
Pennsylvania
AGENCY: Environmental Protection
Agency.
ACTION: Final rule.
SUMMARY: This document amends 40
CFR 60.4 to reflect delegation to the
Commonwealth of Pennsylvania for
authority to implement and enforce
certain Standards of Performance for
New Stationary Sources.
EFFECTIVE DATE: January 16,1980.
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Federal Register / Vol. 45, No. 11 / Wednesday, January 16, 1980 / Rules and Regulations
FOR FURTHER INFORMATION CONTACT:
Joseph Arena, Environmental Scientist,
Air Enforcement Branch, Environmental
Protection Agency, Region III, 6th and
Walnut Streets, Philadelphia,
Pennsylvania 19106, Telephone (215)
597-4561.
SUPPLEMENTARY INFORMATION:
I. Background
On October 1,1979, the
Commonwealth of Pennsylvania
requested delegation of authority to
implement and enforce certain
Standards of Performance for New
Stationary Sources. The request was
reviewed and on December 7,1979 a
letter was sent to Clifford L. Jones,
Secretary, Department of Environmental
Resources, approving the delegation and
outlining its conditions. The approval
letter specified that if Secretary Jones or
any other representatives had any
objections to the conditions of
delegation they were to respond within
ten (10) days after receipt of the letter.
As of this date, no objections have been
received.
II. Regulations Affected by This
Document
Pursuant to the delegation of authority
for Standards of Performance for New
Stationary Sources to the
Commonwealth of Pennsylvania, EPA is
today amending 40 CFR 60.4, Address, to
reflect this delegation. A Notice
announcing this delegation is published
today in the Federal Register. The
amended § 60.4, which adds the address
of the Pennsylvania Department of
Environmental Resources, to which all
reports, requests, applications,
submittals, and communications to the
Administrator pursuant to this part must
also be addressed, is set forth below.
III. General
The Administrator finds good cause
for foregoing prior public notice and for
making this rulemaking effective
immediately in that it is an
administrative change and not one of
substantive content. No additional
substantive burdens are imposed on the
parties affected. The delegation which is
reflected by this administrative
amendment was effective on December
7,1979, and it serves no purpose to
delay the technical change of this
address to the Code of Federal
Regulations.
This rulemaking is effective
immediately, and is issued under the
authority of Section 111 of the Clean Air
Act, as amended, 42 U.S.C. 7411.
Dated: December 7,1979.
R. Sarah Compton,
Director, Enforcement Division.
Part 60 of Chapter I, Title 40 of the
Code of Federal Regulations is amended
as follows:
1. In § 60.4, paragraph (b) is amended
by revising subparagraph (OO) to read
as follows:
§60.4 Address.
*****
(b) * * *
(A)-{NN] * * *
(OO) Commonwealth of Pennsylvania:
Department of Environmental Resources,
Post Office Box 2063, Harrisburg,
Pennsylvania 17120.
[FR Doc 80-1468 Filed 1-15-80; M5 am)
109
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Part 60
[FRL 1374-2]
Standards of Performance for New
Stationary Sources; Modification,
Notification, and Reconstruction;
Amendment and Correction
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Final rule.
SUMMARY: This amendment revokes the
bubble concept as a means of
determining what constitutes a
"modified" source for the purpose of
applying new source performance
standards promulgated under the Clean
Air Act. The United States Court of
Appeals for the District of Columbia
Circuit rejected the bubble concept in
ASARCO v. EPA, 578 F.2d 319. The
intent of this action is to comply with
the Court's ruling. This action also
amends the definition of "capital
expenditure" and updates a statutory
reference.
EFFECTIVE DATE: January 23,1980.
FOR FURTHER INFORMATION CONTACT:
Mr. Don R. Goodwin, Director, Emission
Standards and Engineering Division
(MD-13), Environmental Protection
Agency, Research Triangle Park, North
Carolina 27711, telephone number (919)
541-5271.
SUPPLEMENTARY INFORMATION:
Background
On December 16,1975 (40 FR 58416),
EPA promulgated amendments to the
general provisions of 40 CFR Part 60.
The purpose of those amendments was,
in part, to clarify the definition of
"modification" in the Clean Air Act
(hereafter referred to as the Act) with
regard to a stationary source. The
general provisions of 40 CFR Part 60
apply to all standards of performance
for new, modified, and reconstructed
stationary sources promulgated under
section 111 of the Act.
"Modification" is defined in those
amendments as any physical change in
the method of operation of an existing
facility which increases the amount of
any air pollutant (to which a standard
applies) emitted into the atmosphere by
that facility or which results in the
emission of any air pollutant (to which a
standard applies) into the atmosphere
not previously emitted. "Existing
facility" means any apparatus of the
type for which a standard of
performance is promulgated in 40 CFR
Part 60, but the construction or
modification of which was commenced
before the date of proposal of that
standard. Upon modification, an existing
facility becomes an "affected facility,"
the basic unit to which a standard of
performance applies. Depending on the
circumstances of each particular
regulation, EPA may designate an entire
plant as an affected facility of an
individual production process or piece
of equipment within a plant as an
affected facility.
The amendments to the general
provisions of 40 CFR Part 60 also
expanded the statutory definition of
"stationary source" to reflect EPA's
interpretation of the language of the Act.
"Stationary source" is defined in the Act
as a "building, facility, or installation
which emits or may emit any air
pollutant" [section lll(a){3)]. The
amendments expanded this definition
with the addition, "and which contains
any one or combination of the following:
(1) Affected facilities.
(2) Existing facilities.
(3) Facilities of the type for which no
standards have been promulgated in this
part."
Thus, a distinction was made between
"affected facility," any apparatus to
which a standard applies, and
"stationary source," which could be a
combination of affected, existing, and
other facilities.
Based on these interpretive
definitions, 5 60.14(d) of the
amendments allowed an existing facility
to undergo a physical or operational
change but not be considered modified if
emission increases associated with the
physical or operational change were
offset by emission decreases of the same
pollutant from other affected and
existing facilities at the same stationary
source. This is referred to as the "bubble
concept."
In effect, a "bubble" could be placed
over an entire plant when determining if
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Federal Register / Vol. 45, No. 16 / Wednesday, January 23, 1980 / Rules and Regulations
physical or operational change to an
existing facility within the plant
constituted a modification. Emissions of
a pollutant from an existing facility
could increase as a result of a physical
or operational change but that facility
would not be deemed "modified" as
long as emissions of that pollutant
coming out of the "bubble" over all
affected and existing facilities at the
plant did not increase.
EPA did not extend the bubble
concept to new-facility construction at
existing plant sites.
Challenges to the bubble concept
The Sierra Club challenged EPA's use
of the bubble concept in determining if a
modification of an existing facility had
taken place for the purpose of applying
standards of performance for new,
modified, and reconstructed stationary
sources promulgated under section 111
of the Act. The Sierra Club contended
that the interpreted definition of
"stationary source" promulgated by
EPA, and essential to EPA's use of the
bubble concept, was inconsistent with
the language of section 111 of the Act.
Sierra Club argued that the Act defines
a stationary source as an individual
building, structure, facility or
installation as distinguished from a
combination of such units. Sierra Club
claimed that once EPA had chosen the
affected facility to which standards of
performance apply, it could not
subsequently examine a combination of
existing and affected facilities for the
purpose of determining if a particular
existing facility had been modified, and
was therefore subject to standards.
ASARCO also challenged this use of
the bubble concept by EPA, but for a
different reason. ASARCO claimed that
the bubble concept should be extended
to cover new source construction at
existing plant sites rather than to
modifications only.
In a decision rendered January 27,
1978, the United States Court of Appeals
for the District of Columbia Circuit
agreed with the Sierra Club and rejected
the bubble concept as a means of
determining if a modification to an
existing facility had occurred for the
purpose of applying standards of
performance under section 111 of the
Act (ASARCO v. EPA, 578 F.2d 319). The
Court held that EPA had no authority to
change the basic unit to which the NSPS
apply from a single building, structure,
facility or installation as specified in the
Act to a combination of such units. In
addition, the Court ruled that since
EPA's use of the bubble concept for
determining modifications was illegal to
begin with, the bubble concept could not
be extended to cover new sources as
requested by industry.
In response to the Court's decision,
EPA is, with this action, deleting the
portions of § 60.14 of the general
provisions of 40 CFR Part 60 which
implement the bubble concept. The
definition of "stationary source" in
S 60.2 is also deleted. For the purposes
of regulations promulgated in 40 CFR
Part 60, the term "stationary source"
will hereafter have the same meaning as
in the Act.
Miscellaneous
The definition of "capital
expenditure" in § 60.2 is being amended
with the qualification that when
computing the total expenditure for a
physical or operational change to an
existing facility, it must not be reduced
by any "excluded additions" as defined
in IRS Publication 534, as would be done
for tax purposes. This qualification was
noted in the preamble to the original
regulation but not included in the
regulation text as intended.
Finally, the reference to "section
119(d)(5)" of the Act in § 60.14(e}(4) is
changed to "section lll(a)(8)" to reflect
changes in the 1977 Clean Air Act
Amendments (Public Law 95-95, August
7,1977).
Since these actions reflect the
mandate of the Court, correct an
unintentional omission, and update a
statutory reference, notice and public
comment thereon is unnecessary and
good cause exists for making them
effective immediately.
Dated: January 16,1980.
Douglas M. Costle,
Administrator.
40 CFR Part 60 is amended as follows:
1. Section 60.2 is amended by deleting
the definition of "Stationary source" and
by revising the definition of "Capital
expenditure" as follows:
§ 60.2 Definitions.
*****
"Capital expenditure" means an
expenditure for a physical or
operational change to an existing facility
which exceeds the product of the
applicable "annual asset guideline
repair allowance percentage" specified
in the latest edition of Internal Revenue
Service (IRS) Publication 534 and the
existing facility's basis, as defined by
section 1012 of the Internal Revenue
Code, However, the total expenditure
for a physical or operational change to
an existing facility must not be reduced
by any "excluded additions" as defined
in IRS Publication 534, as would be done
for tax purposes.
§60.7 [Amended]
2. In § 60.7, the first sentence in
paragraph (a)(4) is amended by deleting
the phrase, " and the exemption is not
denied under § 60.14(d)(4)."
§60.14 [Amended]
3. In § 60.14, the first sentence of,
paragraph (a) is amended, paragraph (d)
is revoked and reserved, the last
sentence of paragraph (e)(4) is amended,
and paragraph (g) is amended as
follows:
§60.14 Modification.
(a) Except as provided under
paragraphs (e) and (f) of this section,
any physical or operational change to an
existing facility which results in an
increase in the emission rate to the
atmosphere of any pollutant to which a
standard applies shall be considered a
modification within the meaning of
section 111 of the Act. * * *
*****
(d) [Reserved]
(e) * * *
(4) * * * Conversion to coal required
for energy considerations, as specified
in section lll(a)(8) of the Act, shall not
be considered a modification.
*****
(g) Within 180 days of the completion
of any physical or operational change
subject to the control measures specified
in paragraph (a) of this section,
compliance with all applicable
standards must be achieved.
(Sec. Ill, 301(a) of the Clean Air Act as
amended [42 U.S.C. 7411, 7801(a)]).
(FR Doc 80-2122 Filud 1-22-80; 8 45 am)
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no
Federal Register / Vol. 45, No. 26 / Wednesday, February 6, 1980 / Rules and Regulations
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Part 60
[FRL -M04-6J
Standards of Performance for New
Stationary Sources; Electric Utility
Steam Generating Units; Decision in
Response to Petitions for
Reconsideration
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Denial of Petitions for
Reconsideration of Final Regulations.
SUMMARY: The Environmental Defense
Fund, Kansas City Power and Light
Company, Sierra Club, Sierra Pacific
Power Company and Idaho Power
Company, State of California Air
Resources Board, and Utility Air
Regulatory Group submitted petitions
for reconsideration of the revised new
source performance standards for
electric utility steam generating units
that were promulgated on June 11,1979
(44 FR 33580). The petitions were
evaluated collectively since the
petitioners raised several overlapping
issues. When viewed collectively, the
petitioners sought reconsideration of the
standards of performance for sulfur
dioxide (SO^), particulate matter, and
nitrogen oxides (NO,). In denying the
petitions, the Administrator found that
the petitioners had failed to satisfy the
statutory requirements of section
307(d)(7)(B) of the Clean Air Act. That
is, the petitioners failed to demonstrate
either (1) that it was impractical to raise
their objections during the period for
public comment or (2) that the basis of
their objection arose after the close of
the period for public comment and the
objection was of central relevance to the
outcome of the rule. This notice also
responds to certain procedural issues
raised by the Environmental Defense
Fund (EOF). It should be noted that the
Natural Resources Defense Council
(NRDC) filed a July 9, 1979, letter in
which they concurred with the
procedural issues raised by EDF.
DATES: Effective February 6,1980.
Interested persons may advise the
Agency of any technical errors by
March 7,1980.
ADDRESSES: EPA invites information
from interested persons. This
information should be sent to: Mr. Don
R. Goodwin, Director, Emission
Standards and Engineering Division
(MD-13), Environmental Protection
Agency, Research Triangle Park, North
Carolina 27711, telephone (919) 541-
5271.
Docket Number OAQPS-78-1
contains all supporting materials used
by EPA in developing the standards,
including public comments and
materials pertaining to the petitions for
reconsideration. The docket is available
for public inspection and copying
between 9:00 a.m. and 4:00 p.m., Monday
through Friday at EPA's Central Docket
Section, Room 2903B, Waterside Mall,
401 M Street, SW., Washington. D.C.
20460.
FOR FURTHER INFORMATION CONTACT:
Mr. Don R. Goodwin, Director, Emission
Standards and Engineering Division
(MD-13), Environmental Protection
Agency, Research Triangle Park, North
Carolina 27711, telephone (919) 541-
5271.
SUPPLEMENTARY INFORMATION:
Background
On September 19,1978, pursuant to
Section 111 of the Clean Air Act
Amendments of 1977, EPA proposed
revised standards of performance to
limit emissions of sulfur dioxide (SO2),
particulate matter, and nitrogen oxides
(NOi) from new, modified, and
reconstructed electric utility steam
generating units (43 FR 42154). A public
hearing was held on December 12 and
13,1978. In addition, on December 8,
1978, EPA published additional
information on the proposed rule (43 FR
57834). In this notice, the Administrator
set forth the preliminary results of the
Agency's analysis of the environmental,
economic, and energy impacts
associated with several alternative
standards. This analysis was also
presented at the public hearing on the
proposed standards. The public
comment period was extended until
January 15,1979, to allow for comments
on this information.
After the Agency had carefully
evaluated the more than 600 comment
letters and related documents, the
Administrator signed the final standards
on June 1,1979. In turn, they were
promulgated in the Federal Register on
June 11,1979.
On June 1,1979, the Sierra Club filed a
petition for judicial review of the
standards with the United States Court
of Appeals for the District of Columbia.
Additional petitions were filed by
Appalachian Power Company, et al., the
Environmental Defense Fund, and the
State of California Air Resources Board
before the close of the filing period on
August 10,1979.
In addition, pursuant to section
307(d)(7)(B) of the Clean Air Act, the
Environmental Defense Fund, Kansas
City Power and Light Company, Sierra
Club, Sierra Pacific Power Company and
Idaho Power Company, State of
California Air Resources Board, and
Utility Air Regulatory Group petitioned
the Administrator for reconsideration of
the revised standards.
Section 307(d)(7)(B) of the Act
provides that:
Only an objection to a rule or procedure
which was raised with reasonable specificity
during the period for public comment
(including any public hearing] may be raised
during judicial review. If the person raising
an objection can demonstrate to the
Administrator that it was impracticable to
raise such objection within such time or if the
grounds for such objection arose after the
period for public comment (but within the
time specified for judicial review) and if such
objection is of central relevance to the
outcome of the rule, the Administrator shall
convene a proceeding for reconsideration of
the rule and provide the same procedural
rights as would have been afforded had the
information been available at the time the
rule was proposed. If the Administrator
refuses to convene such a proceeding, such
person may seek review of such refusal in the
United Stales Court of Appeals for the
appropriate circuit (as provided in subsection
(b)).
The Administrator's findings and
responses to the issues raised by the
petitioners are presented in this notice.
Summary of Standards
Applicability
The standards apply to electric utility
steam generating units capable of firing
more than 73 MW (250 million Btu/hour)
heat input of fossil fuel, for which
construction is commenced after
September 18,1978. Industrial
cogeneration facilities that sell less than
25 MW of electricity, or less than one-
third of their potential electrical output
capacity, are not covered. For electric
utility combined cycle gas turbines,
applicability of the standards is
determined on the basis of the fossil-fuel
fired to the steam generator exclusive of
the heat input and electrical power
contribution of the gas turbine.
SO, Standards
The SOz standards are as follows:
(1) Solid and solid-derived fuels
(except solid solvent refined coal): SO2
emissions to the atmosphere are limited
to 520 ng/J (1.20 Ib/million Btu) heat
input, and a 90 percent reduction in
potential SO2 emissions is required at all
times except when emissions to the
atmosphere are less than 260 ng/J (0.60
Ib/million Btu) heat input. When SO,
emissions are less than 260 ng/J (0.60 lb/
million Btu) heat input, a 70 percent
reduction in potential emissions is
required. Compliance with the emission
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limit and percent reduction requirements
is determined on a continuous basis by
using continuous monitors to obtain a
30-day rolling average. The percent
reduction is computed on the basis of
overall SOS removed by all types of SO2
and sulfur removal technology, including
flue gas desulfurization (FGD) systems
and fuel pretreatment systems (such as
coal cleaning, coal gasification, and coal
liquefaction). Sulfur removed by a coal
pulverizer or in bottom ash and fly ash
may be included in the computation.
(2) Gaseous and liquid fuels not
derived from solid fuels: SO» emissions
into the atmosphere are limiteed to 340
ng/J (0.80 Ib/million Btu) heat input, and
a 90 percent reduction in potential SO,
emissions is required. The percent
reduction requirement does not apply if
SO2 emissions into the atmosphere are
less than 86 ng/J (0.20 Ib/million Btu)
heat input. Compliance with the SOi
emission limitation and percent
reduction is determined on a continuous
basis by using continuous monitors to
obtain a 30-day rolling average.
(3) Anthracite coal: Electric utility
steam generating units firing anthracite
coal alone are exempt from the
percentage reduction requirement of the
SO? standard but are subject to the 520
ng/J (1.20 Ib/million Btu) heat input
emission limit on a 30-day rolling
average, and all other provisions of the
regulations including the particulate
matter and NO, standards.
(4) Noncontinental areas: Electric
utility steam generating units located in
noncontinental areas (State of Hawaii,
the Virgin Islands, Guam, American
Samoa, the Commonwealth of Puerto
Rico, and the Northern Marina Islands)
are exempt from the percentage
reduction requirement of the SOj
standard but are subject to the
applicable SO, emission limitation and
all other provisions of the regulations
including the particulate matter and NO,
standards.
(5) Resource recovery facilities:
Resource recovery facilities which
incorporate electric utility steam
generating units that fire less than 25
percent fossil-fuel on a quarterly (90-
day) heat input basis are not subject to
the percentage reduction requirements
but are subject to the 520 ng/J (1.20 lb/
million Btu) heat input emission limit.
Compliance with the emission limit is
determined on a continuous basis using
continuous monitoring to obtain a 30-
day rolling average. In addition, such
facilities must monitor and report their
heat input by fuel type.
(6) Solid solvent refined coal: Electric
utility steam generating units firing solid
solvent refined coal (SRC I) are subject
to the 520 ng/J (1.20 Ib/million Btu) heat
input emission limit (30-day rolling
average) and all requirements under the
NO, and particulate matter standards.
Compliance with the emission limit is
determined on a continuous basis using
a continuous monitor to obtain a 30-day
rolling average. The percentage
reduction requirement, which is
obtained at the refining facility itself, is
85 percent reduction in potential SOa
emissions on a 24-hour (daily) averaging
basis. Compliance is to be determined
by Method 19. Initial full-scale
demonstration facilities may be granted
a commercial demonstration permit
establishing a requirement of 80 percent
reduction in potential emissions on a 24-
hour (daily) basis.
Particulate Matter Standards
The particulate matter standard limits
emissions to 13 ng/J (0.03 Ib/million Btu)
heat input. The opacity standard limits
the opacity of emissions to 20 percent (6-
minute average). The standards are
based on the performance of a well-
designed and operated baghouse or
electrostatic precipitator.
M3, Standards
The NO, standards are based on
combustion modification and vary
according to the fuel type. The
standards are:
(1) 86 ng/J (0.20 Ib-million Btu) heat
input from the combustion of any
gaseous fuel, except gaseous fuel
derived from coal;
(2) 130 ng/J (0.30 Ib/million Btu) heat
input from the combustion of any liquid
fuel, except shale oil and liquid fuel
derived from coal;
(3) 210 ng/J (0.50 Ib/million Btu) heat
input from the combustion of
subbituminous coal, shale oil, or any
solid, liquid, or gaseous fuel derived
from coal;
(4) 340 ng/J (0.80 Ib/million Btu) heat
input from the combustion in a slag tap
furnace of any fuel containing more than
25 percent, by weight, lignite which has
been mined in North Dakota, South
Dakota, or Montana;
(5) Combustion of a fuel containing
more than 25 percent, by weight, coal
refuse is exempt from the NO, standards
and monitoring requirements; and
(6) 260 ng/J (0.60 Ib/million Btu) heat
input from the combustion of anthracite
coal, bituminous coal, or any other solid
fuel not specified under (3), (4), or (5).
Continuous compliance with the NO,
standards is required, based on a 30-day
rolling average. Also, percent reductions
in uncontrolled NO, emission levels are
required. The percent reductions are not
controlling, however, and compliance
with the NO, emission limits will assure
compliance with the percent reduction
requirements.
Emerging Technologies
The standards include provisions
which allow the Administrator to grant
commercial demonstration permits to
allow less stringent requirements for the
initial full-scale demonstration plants of
certain technologies. The standards
include the following provisions:
(1) Facilities using SRC I are subject to
an emission limitation of 520 ng/J (1.20
Ib/million Btu) heat input, based on a
30-day rolling average, and an emission
reduction requirement of 85 percent,
based on a 24-hour average. However,
the percentage reduction allowed under
a commercial demonstration permit for
the initial full-scale demonstration plant
using SRC I would be 80 percent (based
on a 24-hour average). The plant
producing the SRC I would monitor to
ensure that the required percentage
reduction (24-hour average) is achieved
and the power plant using the SRC I
would monitor to ensure that the 520 ng/
Jlieat input limit (30-day rolling
average) is achieved.
(2) Facilities using fluidized bed
combustion (FBC) or coal liquefaction
would be subject to the emission
limitation and percentage reduction
requirement of the SO2 standard and to
the particulate matter and NO,
standards. However, the reduction in
potential SO2 emissions allowed under a
commercial demonstration permit for
the initial full-scale demonstration
plants using FBC would be 85 percent
(based on a 30-day rolling average). The
NO, emission limitation allowed under a
commercial demonstration permit for
the initial full-scale demonstration
plants using coal liquefaction would be
300 ng/J (0.70 Ib/million Btu) heat input,
based on a 30-day rolling average.
(3) No more than 15,000 MW
equivalent electrical capacity would be
allotted for the purpose of commercial
demonstration permits. The capacity
will be allocated as follows:
Technology
Equivalent electrical
Pollutant capacity MW
Solid solvent-refined coal . .. .
Fluidized bed combustion
(atmospheric)
Fluidized bed combustion
(pressunzed)
Coal liquefaction
SO,
SO,
so.
NO,
6.000-10.000
400-3,000
400-1 200
750-10000
Compliance Provisions
Continuous compliance with the SO*
and NO, standards is required and is to
be determined with continuous emission
monitors. Reference methods or other
approved procedures must be used to
supplement the emission data when the
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conlinuous emission monitors
malfunction in order to provide emission
data for at Irast 18 hours of each day for
at least 22 days out of any 30
consecutive days of boiler operation.
A malfunctioning FGD system may be
b\ passed under emergency conditions.
Compliance with the paniculate
standard is determined through
performance tests. Continuous monitors
are required to measure and record the
opacity of emissions. The continuous
op;icity data will be used to identify
excess emissions to ensure that the
particulate matter control system is
being properly operated and maintained.
Issues Raised in the Petitions for
Reconsideration
1. SOi Maximum Emission Limitation of
520 ng/J (1.2 Ib/Millton BtuJ Htiat Input
The Environmental Defense Fund
(EOF), Siena Club, and State of
California Air Resources Board (CARD)
requested that a proceeding be
convened to reconsider the maximum
SO2 emission limitation of 520 ng/J (1.2
Ib/million Btu) heat input. In their
petition, EDF stt forth several
procedural questions as the basis for
their request. First, they maintained that
they did not have the opportunity to
comment on certain information which
was submitted to EPA by the National
Coal Association at an April 5,1979,
meeting and in subsequent
correspondence. The information
pertained to the impacts that different
emission limitations will have on coal
production in the Midwest and Northern
Appalachia. They argued that this
information materially influenced the
Administrator's final decision. Further,
they maintained that the
Administrator's decision in setting the
emission limitation was based on ex
parte communications and improper
congressional pressure.
The Sierra Club also raised objections
to information developed during the
post-comment period. They cited the
information supplied by the National
Coal Association, and the EPA staff
analysis of the impact that different
emission limitations would have on
burnable coal reserves. In addition, they
challenged the assumption that
conservatism in utility perceptions of
scrubber peiformance could create a
significant disincentive against the
burning of high-sulfur coal reserves The
Sierra Club maintained that this
inforrr.dtion is of "central relevance"
since it formed the basis of the
establishment of the final emission
limitation and that the Sierra Club was
denied the opportunity to comment on
Ihis information. Finally, the Sierra Club
and CARB subscribed fully to arguments
presented by EDF concerning ex parte
communications.
Background
The potential impact that the emission
limitation may have on high-sulfur coal
reserves did not arise for the first time in
the post-comment period. It was an
issue throughout the rulemaking. In the
proposal, the Agency stated that two
factors had to be taken into
consideration when selecting the
emission limitationFGD efficiency and
the impact of the emission limitation on
high-sulfur coal reserves (43 FR 42160,
middle column). The proposal also
indicated that, in effect, scrubber
performance determines the maximum
sulfur content of coals that can be fired
in compliance with emission limitation
even when coal preparation is
employed. From the discussion it is clear
that the Administrator recognized that
midwestern high-sulfur coal reserves
could be severely impacted if the
emission limitation was not selected
with care (43 FR 42160, middle column).
In addition, the Administrator also
specifically sought comment on the
related question of new coal production
as it pertained to consideration of coal
impacts in the final decision (43 FR
42155, right column).
At the December 1978 public hearing
on the proposed standards, the Agency
specifically sought to solicit information
on the impact that lower SOZ emission
limits (below 520 ng/J (1.2 Ib/million
Btu) heat input) would have on high-
sulfur coal reserves. In response to
questions from an EPA panel member
and the audience, Mr. Hoff Stauffer of
ICF. Inc. (an EPA consultant) testified
that the potential impact of lower
emission limitations on high-sulfur coal
reserves would be greater in certain
states than was indicated by the results
of the macroeconomic analysis
conducted by his firm. He added further
that if the degree of reduction
achievable through coal preparation or
scrubbers changed from the values
assumed in the analysis (35 percent for
coal preparation on high-sulfur coal and
90 percent for scrubbers) the coal
impacts would vary accordingly. That is,
if greater reduction could be achieved
by either coal preparation or by
scrubbers the impacts would be
reduced. Conversely, if the degree of
reduction achievable by either coal
preparation or scrubbers was less than
the values assumed, the impacts would
be more severe (public hearing
transcript, December 12, 1978, pages 46-
47).
The subject was bicached again when
Mr. Richard Ayres, representing the
Natural Resources Defense Council and
serving as introductory spokesperson for
other public health and environmental
organizations, was asked by the panel
what effect lowering the emission
limitation would have on local high-
sulfur coal reserves. Mr. Ayres
responded that a lower emission
limitation may have the effect of
requiring certain coals to be scrubbed
more than required by the standard. He
added that the utilities would have an
economic choice of either buying local
high-sulfur coal and scrubbing more or
buying lower-sulfur coal which may not
be local and scrubbing less. He further
indicated that it was not clear that a
lower limitation would have the effect of
precluding any coal. In doing so, he
noted that the "conclusion depended
entirely on assumptions about the
possible emission efficiencies of
scrubbers." Finally, Mr. Ayres was
asked whether as long as production in
a given region increased that the
requirement of the Act to maximize the
use of local coal was satisfied. He
responded that it was a "matter of
degree" and that he would not say as
long as production in a given region did
not decline the statute was served
(public hearing transcript, December 12,
1978, pages 77-80).
Mr. Robert Rauch, representing the
Environmental Defense Fund, also
recognized in his testimony that
lowering the emission limitation to the
level recommended by EDF (340 ng/J
(0.8 Ib/million Btu) heat input) would
adversely impact high-sulfur coal
reserves. In his testimony he stated
"Adoption of the proposed lower ceiling
would result in the exclusion of certain
high-sulfur coal reserves from use in
power plants subject to the revised
standard." He added that the use of
adipic acid and other slurry additives
would enhance scrubber performance,
thereby alleviating the impacts on high-
sulfur coal (public hearing transcript,
December 13,1978, pages 189-191).
Mr. Joseph Mullan of the National
Coal Association testified in response to
a question from the hearing panel that
lowering the emission limitation from
520 ng/J (1.2 Ib/million Btu) heat input
would preclude the use of certain high-
sulfur coals. He added that the National
Coal Association would furnish data on
such impacts (public hearing transcript,
December 13,1978, page 246).
Turning now to the written comments
on the proposed standard submitted
jointly by the Natural Resources
Defense Council and the Environmental
Defense Fund, we see that they carefully
assessed the potential impacts on high-
sulfur coal reserves that could result
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from various emission limitations. They
concluded, "Generally, the higher the
percent removal requirement, the
smaller the percentage of coal reserves
which are effectively eliminated for use
by utility generating units." They went
on to argue that if their recommended
standard of 95 percent reduction in
potential SO2 emission was accepted a
lower emission limitation could be
adopted without adverse impacts on
coal reserves (OAQPS-78-1. IV-D-631,
page V-128).
Rationale for the Maximum Emission
Limit
The testimony presented at the public
hearing and the written comments
served to confirm the Agency's initial
position that scrubber performance and
potential impacts on high-sulfur coal
reserves had to be carefully considered
when establishing the emission
limitation. Meanwhile, it became
apparent that the analysis performed by
EPA's consultant on emission limits
below 520 ng/J (1.2 Ib/million Btu) heat
input might not fully reflect the impacts
on major high-sulfur coal production
areas. This finding was evident by study
of the consultant's report (OAQPS-78-1,
IV-A-5, Appendix D) which showed
that the model used to estimate coal
production in Appalachia and the
Midwest was relatively insensitive to
broad variations in the emission ceiling.
The Agency then concluded that the
macroeconomic model was adequate for
assessing national impacts on coal use,
but lacked the specificity to assess
potential dislocations in specific coal
production regions. In effect the analysis
tended to mask the impacts in specific
coal producing regions through
aggregation. Concern was also raised as
to the validity of the modeling
assumption that a 35 percent reduction
in potential SO2 emissions can be
achieved by coal washing on all high-
sulfur coal reserves.
In view of these concerns, EPA
concluded shortly after the close of the
comment period that additional analysis
was needed to support the final
emission limitation. In February, EPA
began analyzing the impacts of
alternative emission limits on local high-
sulfur coal reserves. To account for
actual and perceived efficiencies of
scrubbers, the staff assumed three levels
of scrubber control85 percent, 90
percent, and 95 percent. In addition, two
levels of physical coal cleaning were
reflected. The first level was crushing to
1.5 inch top-size and the second was
crushing to % inch top-size, both
followed by wet beneficiation. In
addition, by using seam-by-seam data
on coal reserves and their sulfur
reduction potential (developed for EPA's
Office of Research and Development) it
was possible to estimate the sulfur
content of the final product coal based
on reported chemical properties of coals
in the reserve base (OAQPS-78-1, IV-E-
12). Since this approach did not require
the staff to assume a single level of
sulfur reduction for all coal preparation
plants, it introduced a major refinement
to the analysis previously performed by
EPA's consultant. The analysis was
substantially completed in March 1979
(OAQPS-78-1, IV-B-57 and IV-B-72).
The April 5,1979, meeting was called
to discuss coal reserve data and the
degree of sulfur removal achievable
with physical coal cleaning (OAQPS-
78-1, IV-E-10). The meeting gave EPA
the opportunity to present the results of
its analysis and to verify the data and
assumptions used with those persons
who are most knowledgeable on coal
production and coal preparation. EPA
sought broad representation at the
meeting. Invitees including not only the
National Coal Association but
representatives from the Environmental
Defense Fund, Natural Resources
Defense Council, Sierra Club, Utility Air
Regulatory Group, United Mine Workers
of America, and other interested parties.
The invitees were furnished copies of
the materials presented at the meeting,
subsequent correspondence from the
National Coal Association, and minutes
of the meeting.
The meeting served to confirm that
the coal reserve and preparation data
developed independently by the EPA
staff were in close agreement with those
prepared by the National Coal
Association (NCA). In addition, the
discussion led EPA to conclude that coal
preparation technology which required
crushing to 3/s-inch top-size would be
unduly expensive, lead to unacceptable
energy losses, and pose coal handling
problems (OAQPS-78-1, IV-E-11). As a
result, the Administrator revised his
assessment of state-of-art coal cleaning
technology (44 FR 33596, left column).
In an April 19,1979, letter to the
Administrator (OAQPS-78-1, IV-D-763).
attorneys for the Environmental Defense
Fund and the Natural Resources
Defense Council submitted comments on
the information presented by the
National Coal Association at the April 5,
1979, meeting and in a subsequent NCA
letter to the Administrator dated April 6,
1979. In their comments, they were
critical of the National Coal
Association's assumptions concerning
scrubber performance and the removal
efficiencies of coal preparation plants.
They also noted that the Associaton's
data was based on a small survey of the
total coal reserves in the Midwest and
Northern Appalachia. They argued
further that coal blending could serve to
reduce the adverse impact on high-sulfur
coal caused by a lower emission limit. In
doing so, they recognized that the
application of coal blending would have
to be undertaken on a case-by-case
basis. Finally, they maintained that
there is no evidence that the coal
industry would be unable to meet
increases in coal demand even if the
National Coal Association's reserve
data on coal preclusions were accepted
In conclusion, they noted that the
Association's data was of questionable
relevance since it was predicated on a
maximum removal efficiency of 90
percent.
Subsequent correspondence from the
National Coal Association served to
reaffirm a point that had been made
earlier in the rulemaking. That is,
utilities would have a choice of either
buying lower-sulfur coal and scrubbing
to meet the percent removal requirement
or buying higher-sulfur coal and
scrubbing more than required by the
standard in order to meet the emission
limitation. In addition, they cited the
conservative nature of utilities and
stressed that this would be reflected in
their coal buying practices. As was
discussed at the public hearing and in
the written comments such behavior by
utilities would result in adverse impacts
on the use of certain local high-sulfur
coals.
In reaching final conclusions about
the impact oi the SO2 standard on coal
production, the Administrator judged
that utilities would be inclined to select
coals that would meet the emission hmi!
with no more than 90 percent reduction
in potential SO2 emissions ' (44 FR
33590, left column). With this
assumption, the analysis revealed that
an emission limit of less than 520 r.g/J
(1.20 Ib/million Btj) heat input would
create a disincentive to burn a
significant portion of the coal reserves
in the Midwest and Northern
Appalachia (OAQPS-78-1, IV-B-72). If
the emission limit had been set at 430
ng/J (1.0 Ib/million Btu) heat input, 15
percent of the total reserve base in the
Eastern Midwest (Illinois, Indiana, and
Western Kentucky) would have been
impacted. The impact in Northern
Appalachia would be 6 percent and this
impact would have been concentrated in
the areas of Ohio and the northern part
of West Virginia. If only currently
'The previous version of the EPA anahsis had
assumed either 85 or 90 percent control levels in
addition to coal washing That approach
disregarded the fact that the net reduction in
potential SO? emissions may have been greater th
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Federal Register / Vol. 45, No. 26 / Wednesday, February 6, 1980 / Rules and Regulations
owned coal reserves are considered, up
to 19 percent of the high-sulfur coals in
some regions would be impacted
(OAQPS-78-1, IV-B-72). The
Administrator judged that such impacts
are unacceptable.
The final point made by NCA was
that utility coal buying practice typically
incorporates a margin of safety to
ensure compliance with SOj emission
limitations. Rather than purchasing a
high-sulfur coal that would barely
comply with the emission limit, the
prudent utility would adopt a more
conservative approach and purchase
coal that would meet the emission limit
with a margin of safety in order to
account for uncertainty in coal sulfur
variability. This approach, which
reflects sound engineering principles,
could result in the dislocation of some
high-sulfur coal reserves.
The Administrator determined that
consideration of a margin of safety in
coal buying practice was reasonable.
Using NCA's recommendation of an 8.5
percent margin (reported as "about 10
percent" in the preamble to
promulgation), coal impacts were
reanalyzed. This study showed
additional coal market dislocations
(OAQPS-78-1, IV-B-72). For example, in
Illinois, Indiana, and Western Kentucky,
the impact on coal reserves by a 430 ng/
J (1.0 Ib/million Btu) heat input emission
limit increased from 15 percent without
the margin to 22 percent when the
margin was assumed. Considering only
currently owned reserves, the impact
increased from 19 percent to 30 percent.
Even with the margin, the analysis
predicted no significant impact for a 520
ng/J (1.2 Ib/million Btu) heat input
standard.
Having determined the extent of the
potential coal impacts associated with a
lower emission limit, the Agency then
as.-essed the potential environmental
benefits. The assessment revealed that
by 1995 an emission limit of 430 ng/J (1.0
Ib/million Btu) heat input would reduce
national emissions by only 50 thousand
tons per year relative to the 520 ng/J (1.2
Ib/million Btu) heat input limit. That is,
the projected emissions from new plants
would be reduced from 3.10 million tons
to a 3.05 million tons as a result of the
more stringent emission limit (OAQPS-
78-1, IV-B-75).
The petitions providing no information
to either refute the assumptions or the
findings of the final coal impact
analysis. The Sierra Club argued that
EPA had misinterpreted its own analysis
of coal impacts (Sierra Club petition,
page 9). They maintained that the EPA
figures presented at the April 5 meeting
(OAQPS-78-1, IV-E-11, attachment 3)
supported establishment of a 340 ng/J
(0.8 Ib/million Btu) heat input standard.
In doing so the Sierra Club ignored the
analysis performed by the Agency after
the April 5 meeting, particularly with
respect to the Administrator finding that
utilities would purchase coal which
would meet the emission limit (with
margin) with no more than 90 percent
reduction in potential SO2 emissions.
In conclusion, the decision as to the
appropriate level of emission limitation
rested squarely on two factors. First, the
Administrator's finding that a 90 percent
reduction in potential SOj emissions,
measured as a 30-day rolling average,
represented the emission reduction
achievable through the use of the best
demonstrated system of emission
reduction, and second, that the marginal
environmental benefit of a 430 ng/J (1.0
Ib/million Btu) heat input standard
coupled with a 90 percent reduction in
potential SO2 emissions could not be
justified in light of the potential impacts
on high-sulfur coal reserves. If he had
determined, as some petitioners
suggested, that higher removal
efficiencies were achievable on high-
sulfur coals, the emission limitation
could have been established at a lower
level without significant impacts on
local high-sulfur coal reserves.
Environmental Defense Fund Procedural
Issues
EDF's petition objected to the fact that
after the close of the public comment
period, representatives of the National
Coal Association and a number of
members of Congress talked to EPA
officials and submitted documents to
EPA arguing that the ceiling should be
set at 520 ng/J (1.2. Ibs/million Btu) heat
input. EDF objected to these
communications on a number of
grounds. First, they argued that it was
improper, under Section 307(d) of the
Act, for the Agency to consider
information submitted more than 30
days after the public hearing. Second,
they objected that the Agency failed to
make transcripts of the oral
communications, and that, in any event,
the summaries of those communications
that the Agency placed in the docket
were inadequate. Third, they implied
that Agency officials received additional
oral communications which were not
documented in the rulemaking docket.
Fourth, they objected that these written
and oral communications were exparte
and therefore improper, citing, for
example, United States Lines, Inc. v.
FMC, 584 F. 2d 519 (D.C. Cir., 1978).
Fifth, they argued that the
Administrator's decision on the ceiling
was based in part on information
obtained in ex parte discussions and
thus not placed in the docket as of the
date of promulgation, in violation of
Section 307(d). Finally, they argued that
the communications from members of
Congress constituted improper pressure
on the Administrator's decision, citing,
for example, D.C. Federation of Civic
Associations \. Volpe, 459 F. 2d 1231
(D.C. Cir. 1972). EDF argued that these
alleged procedural errors were of
central relevance to the outcome of the
rule, and that the Agency should
therefore convene a proceeding to
reconsider.
The Administrator does not believe
that the procedures cited by EDF were
improper. Moreover, as discussed
below, any arguable errors were not of
central relevance to the outcome of the
rule, and therefore do not constitute
grounds for granting EDF's petition to
reconsider.
First, it was not improper for the
Administrator to consider information
submitted more than 30 days after the
public hearing. Section 307(d)(5) requires
that the Administrator consider
documents submitted up to 30 days after
the hearing. It does not forbid the
Administrator to consider additional
comments submitted after that 30-day
period.
Second, the Agency's summaries of
oral communications were adequate.
Section 307(d){5) does not require, as
EDF argues, that Agency officials keep
transcripts of their oral discussions with
persons outside the Agency. It simply
requires the Agency to make a transcript
of the public hearing on a proposed
rulemaking. Third, Agency officials
wrote memoranda of all significant oral
communcalions between Agency
officials and persons outside the
executive branch, such as the two
meetings with Senator Byrd, and the
memoranda were promptly placed in the
rulemaking docket. These memoranda
accurately reflect the information and
arguments communicated to the Agency.
Fourth, the oral and written
communications cited by EDF were not
exparte. The Agency promptly placed
the written comments in the rulemaking
docket where they were available to the
public. Also, the NCA sent copies of its
written comments directly to the
principal parties to the rulemaking,
including EDF and NRDC. Similarly, the
Agency placed the memoranda of oral
communcations in the docket where
they were available to the public. Any
member of the public has had the
opportunity to submit a petition for
reconsideration if that information was
used erroneously by EPA in setting the
standard, and several persons have
done so.
Fifth, contrary to EDF's assertion, the
Administrator's decision on the
T\7-1
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emission ceiling was not based on any
information not in the docket
Finally, it was not improper for the
Administrator to listen to and consider
the views of Senators and Congressmen,
including Senator Byrd. It is not unusual
for members of Congress to express
their views on the merits of Agency
rulemaking, and it is entirely proper for
the Administrator to consider those
views.
F.DF objects particularly to a meeting
the Administrator attended with Senator
Byrd on April 26,1979, arguing that the
contact was exparle and improperly
influenced the Administrator's decision.
Neither contention is correct. A
memorandum summarizing the
discussion at the meeting was placed in
the docket, and members of the public
have had the opportunity to comment on
it, as EDF has done. No new information
was presented to the Administrator al
the meeting.
Senator Byrd's comments at this
meeting also did not improperly
influence the Administrator. Although
the Senator strongly urged the
Administrator to set the emission ceiling
at a level that would not preclude the
use of any significant coal reserves, the
Administrator had already concluded
from the 1977 Amendments to the Clean
Air Act that the revised standards
should not preclude significant reserves.
This view was based on the
Administrator's interpretation of the
legislative intent of the 1977
Amendments and was reflected in the
proposed emission ceiling of 520 ng/J
(1.2 Ibs/million Btu) heat input as
discussed in the preamble to the
proposed standards (43 FR 42160).
This view was reaffirmed in the final
rulemaking, based on the intent of the
1977 Amendments (44 FR 33595-33596).
Although the Administrator was aware
(as he would have been even in the
absence of a meeting) of Senator Byrd's
concern that a ceiling lower then 520 ng/
] (1.2 Ibs/million Btu) heat input would
inappropriately preclude significant coal
reserves, the Administrator's decision
was not based on Senator Byrd's
expression of concern. The
Administrator had already concluded
that anything more than a minimal
preclusion of the use of particular coal
reserves would, in the absence of
significant resulting emission reductions,
be inconsistent with the intent of the
1977 Amendments. Because the
Agency's analysis showed that even an
emission limit of 430 ng/J (1.0 Ibs/
million Btu) heat input could preclude
the use of up to 22 percent of certain
coal reserves without significantly
reducing overall emissions, the
Administrator's judgment was that a
ceiling lower than 520 ng/J (1.2 Ibs/
million Btu) heat input was not justified.
Thus, the views of Senator Byrd and
other members of Congress, at most,
served to reinforce the Administrator's
own judgment that the proper level for
the standard was 520 ng/J (1.2 Ibs/
million Btu) heat input. Even assuming
therefore, that it was improper for the
Administrator to consider the views of
members of Congress, this procedural
"error" was not of central relevance tc
the outcome of the rule.
//. SOj Minimum Control Level (70
Percent Reduction of Potential
Emissions)
The Kansas City Power and Light
Company (KCPL), Sierra Club, and
Utility Air Regulatory Group (UARG)
requested that a proceeding be
convened to reconsider the 70 percent
minimum control level which is
applicable when burning low-sulfur
coals. Both the Sierra Club and UARG
maintained that they did not have an
opportunity to fully comment on either
the final regulatory analysis or dry SO2
scrubbing technology since the phase 3
macroeconomic analysis of the standard
(44 FR 33603, left column) and
supporting data were entered into the
record after the close of the public
comment period Both claimed that their
evaluation of this additional information
provided insights which are of central
relevance to the Administrator's final
decision and that reconsideration of the
standard is warranted. The KCPL
petition did not allege improper
administrative procedures, but asked for
reconsideration based on their
evaluation of the merits of the standard.
In seeking a more stringent minimum
reduction requirement, the Sierra Club
contended that dry SO2 scrubbing is not
a demonstrated technology and,
therefore, no basis exists for a variable
control standard. Alternatively, the
Sierra Club maintained that if dry
technology is considered demonstrated
the record supports a more stringent
minimum control level With respect to
the regulatory analysis, the petition
charged that faulty analytical
methodology and assumptions led the
Agency to erroneous conclusions about
the impacts of the promulgated standard
relative to the more stringent uniform or
full control alternative. They suggested
that analysis performed -using proper
assumptions would support adoption of
a uniform standard.
In support of a less stringent minimum
reduction requirement, the UARG
petition presented a regulatory analysis
which was prepared by their consultant,
National Economic Research Associates
(NERA). Based on this study. UARG
argued that a 50 percent minimum
requirement would be superior in terms
of emissions, costs, and energy impacts.
Finally, they argued that a lower percent
reduction would provide greater
opportunity to develop dry SO2
scrubbing technology.
In (heir petition KCPL sought either «n
ehminalion of the percent reduction
requirement when emissions are 520
ng/J (1.2 Ib/million Btu) heat input or
less, or, as an alternative, a reduction m
the 70 percent requirement. In support of
their request, KCPL set forth several
arguments. First, they cited the
economic and energy impacts
associated with the application of
scrubbing technology on low sulfur
coals Second, they noted that a
significant portion of sulfur in the coal
they plan to burn will be removed in the
fly ash. Finally, they asserted that health
and welfare considerations do not
warrant scrubbing of low sulfur coals
since (heir uncontrolled SO2 emissions
are less than the emissions allowed by
the standard for high-sulfur coals with
90 percent scrubbing.
The primary basis for the UARG and
Sierra Club requests for reconsideration
of the minimum control level was the
Agency's phase 3 economic modeling
analysis (44 FR 33602). Because the
phase 3 analysis was completed after
the close of the public comment period,
it is important that the results of that
study are viewed in proper perspective
to their role in the Administrator's
decision. The petitioners implied that
the adoption of the 70 percent variable
control standard was based solely on
the phase 3 analysis and that the phase
3 analysis was a new venture by the
Agency, and therefore, the public was
excluded from active participation in the
decision process. This notion is false.
Contrary to views of the UARG and
the Sierra Club, the phase 3 study did
not mark a significant departure from
the Agency's earlier analysis of the
issue of uniform versus variable control.
No new economic modeling concepts
were introduced nor were any modeling
input assumptions changed from those
presented in the phase 2 analysis.
Instead, the phase 3 study served merely
(a) to refine the analysis by
incorporating consideration of dry SO2
scrubbing in response to public
comments and (b) to facilitate
specification of the final standard. In
effect, phase 3 brought together the
results of an analysis that had
proceeded under close public scrutiny
for more than a year. In order to
consider the full range of applicability of
dry SOj scrubbing systems, it was
necessary to introduce a new alternative
standardthe variable control standard
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Federal Register / Vol. 45, No. 26 / Wednesday, February 6, 1980 / Rules and Regulations
with a 70 percent minimum control level.
Introduction of this option was
considered appropriate since it raised
the same kind of economic, legal, and
technical policy issues as the earlier
analyses of 33, 50, and 90 percent
minimum control options.
Within this context, many of the
objections to the economic modeling are
inappropriate grounds under section
307(d)(7)(B) for reconsideration since
they do not involve information on
which it was impracticable to comment
during the public comment period. For
example, the Sierra Club's comments
regarding modeling assumptions merely
restated those that had been
incorporated by reference into their
January 1979 comments (OAQPS-78-1,
IV-D-631 and IV-D-626). The only new
modeling issue raised during phase 3
was the application and cost of dry SOZ
scrubbing. These problems
notwithstanding each of the issues
raised by the various petitions were
evaluated carefully and are discussed
below.
Dry Scrubbing Technology
The Sierra Club and UARG both
raised issues concerning dry SO2
scrubbing technology in their petitions
for reconsideration. While UARG
concurred with EPA's basic approach
with respect to dry scrubbing, they
maintained that the Agency's objective
of developing the full potential of this
technology would be better served by a
50 percent minimum reduction
requirement. On the other hand, the
Sierra Club was most critical of EPA's
consideration of dry scrubbing in the
rulemaking. They maintained that the
public was not afforded sufficient
opportunity to comment on dry
scrubbing technology. They argued that
EPA had not identified dry scrubbing as
a demonstrated technology nor had the
Agency set forth any regulatory options
that embraced the technology. They also
asserted that the treatment of dry
scrubbing in the rulemaking was
inconsistent with Agency actions
concerning other emerging technologies
such as the establishment of commercial
demonstration permits for solvent
refined coal and fluidized bed
combustion, and the rejection of
catalytic ammonia injection for NO,
control on the grounds that it had not
been employed on a full-scale facility.
They also maintained that EPA had
shown little interest in dry scrubbing
prior to the spring of 1979 and seized
upon it only after the need arose to
justify a 70 percent minimum reduction
requirement. Finally, the Sierra Club
asserted that even if one assumed dry
scrubbing is adequately demonstrated.
the 70 percent reduction requirement is
too low. In doing so, they cited
information (Sierra Club petition, page
8) in the record that indicated that "up
to 90 percent reduction" can be
achieved with such systems.
A review of the public record belies
these charges. The preamble to the
proposed standards identified dry SO»
scrubbing, including spray drying, as an
alternative to wet FGD system; (43 FR
42160, left column). Subsequently, a
number of individuals and organizations
either submitted written comment or
presented testimony at the public
hearing in support of a variable control
standard since it would not foreclose the
development of dry SOj control
technology. For example, the spokesman
for the Public Service Company of
Colorado (PSCC) testified that his firm
was actively pursuing dry SO2 control
technology (dry injection of sodium-
based reagents upstream of a baghouse)
because it offered a number of
advantages compared to wet
technology. Advantages included lower
energy consumption, fewer maintenance
problems, and simplified waste disposal
(public hearing transcript, December 13,
1978, pages 92-94). When questioned by
the hearing panel, PSCC testified that 70
percent removal is achievable with dry
scrubbing and that they would pursue
the technology if a 70 percent
requirement was adopted (public
hearing transcript, December 13,1978,
page 102). Similarly, Northern States
Power testified that adoption of a sliding
scale would give impetus to their
examination of dry SO2 control systems
which employ a spray absorber and a
fabric filter (public hearing transcript,
December 13,1978, page 226). Finally,
the Department of Public Utilities, City
of Colorado Springs testified that they
have a program to conduct on-site pilot
tests of a spray-drying system for SO2
control. It was also noted that if a
sliding scale approach was adopted "we
feel there is no question but that dry
techniques would be used" (public
hearing transcript, December 13, 1978,
pages 266-267).
The Air Pollution Control
Commission, Colorado Department of
Health urged in their written comments
that the proposed emission floor be
raised to 172 ng/J (0.40 Ib/million Btu)
heat input in order to permit the
development and application of dry
control techniques such as the injection
of dry absorbants into a baghouse. They
noted that their recommendation would
require approximately 65 percent
reduction on a typical western low-
sulfur coal (OAQPS-78-1, IV-D-212).
The Washington Public Power Supply
System also submitted written
comments that affirmed the Agency's
finding on dry scrubbers as set forth in
the proposal. They indicated that dry
scrubbing was superior to wet
technology when applied to western
low-sulfur coal. They noted that the
application of dry scrubbers would
result in lower capital, fuel, and
operation and maintenance costs, as
well as .lower water use and simplified
waste disposal. They indicated further
that the uncertainty of being able to
achieve the proposed 85 percent
reduction requirement would foreclose
the installation of dry scrubbing
technology. Therefore, they
recommended that the proposed
emission floor be raised to at least 210
ng/J (0.5 Ib/million Btu) heat input
(OAQPS-78-1, IV-D-330).
Because of these comments and the
public hearing testimony, the Agency
carried out additional investigations of
dry scrubbing technology during the
post-comment period. The findings of
the analysis (44 FR 33582 and EPA 450/
3-79-021, page 3-61) confirmed the
views of the commenters that the
adoption of a uniform percentage
reduction requirement would have
constrained the development of dry
scrubbing technology. After carefully
reviewing the available pilot plant data
and information on the three full-scale
units that are under construction, it was
the Administrator's judgment that the
technology employing spray dryers
could achieve 70 percent reduction in
potential SO2 emissions on both low-
sulfur alkaline and nonalkaline coals.
Data on higher emission reduction levels
such as those noted by the Sierra Club
were discounted since they reflected
short-term removal efficiencies (not
representative of longer periods of
performance) and they were achieved
when high-alkaline content coals were
fired. The Administrator's judgment was
also tempered in this regard by the
public comments which indicated that
removal requirements higher than 70
percent would discourage the continued
development of the technology.
Similarly, these same commenters
clearly indicated that the technology
was capable of exceeding the 50 percent
reduction requirement suggested by the
Utility Air Regulatory Group.
The Sierra Club commented that EPA
was inconsistent in its treatment of dry
scrubbing and catalytic ammonia
injection. In rejecting catalytic ammonia
injection for NO, control, the
Administrator noted that it had not been
adequately demonstrated. A review of
the record reveals that the primary
proponent of this technology, the State
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of California Air Resources Board, also
recognized that it was not sufficiently
advanced at this time to be considered.
Instead, they merely recommended that
the standard require plants to set aside
space so that catalytic ammonia
injection could be added at some future
date (OAQPS-78-1, JV-D-268). In
comparison, dry scrubbing has
undergone extensive testing at pilot
plants, and there are three full-scale
facilities under construction that will
begin operation in the 1981-82 period.
With respect to commercial
demonstration permits for solvent
refined coal and fluidized bed
combustion, the standard merely allows
initial, full-scale demonstration units
some flexibility. Subsequent commercial
facilities will be required to meet the
final standards. In adopting this
provision, the Administrator recognized
that initial full-scale demonstration units
often do not perform to design
specification, and therefore some
flexibility was required if these capital
intensive, front-end technologies were to
be pursued. On the other hand, the
Agency concluded that more
conventional devices such as dry
scrubbers could be scaled up to
commercial-sized facilities with
reasonable assurance that the initial
facilities would comply with the
applicable requirements. In view of this,
the inclusion of dry scrubbing under the
commercial demonstration permit
piovision was not appropriate.
Finally, in a letter dated September 17
1979, to the Administrator, the Sierra
Club submitted additional information
to buttress its argument that dry
scrubbing is not demonstrated
technology. This letter cited EPA's "FGD
quarterly Report" of Spring 1979. The
report indicates that the direct injection
of dry absorbents (such as nahcolite)
into the gas stream may be a
breakthrough, yet it calls for further pilot
plan! studies. The inference the Sierra
Club drew from the article was that the
EPA technical staff does not believe dry
scrubbing is sufficiently developed to be
considered in the rulemaking. The Sierra
Club failed to recognize that there are
several different dry scrubbing
approaches in different stages of
development. The "FGD Quarterly
Report" does not pertain to the
approach employing a spray dryer and
baghouse with lime absorbent which
serves as the basis for the
Administrator's finding [EPA-450/3-70-
021 at 3-61).
The Sierra Club also cited an article in
the Summer 1979 "FGD Quarterly
Report" on vendors' perspectives
toward dry scrubbing. In doing so, the
Sierra Club noted that the article
indicates that vendors expressed an
attitude of caution toward dry scrubbing
which led the Sierra Club to conclude
that the technology is not available. It
should be noted from the article that
only one of the vendors present was
actively engaged in dry scrubbing and
that firm was quite positive in their
remarks. Babcock and Wilcox, who had
conducted spray dryer pilot plant
studies and is pursuing contracts for
full-scale installations, commented thai
"while the dry scrubbing approach is
new, the technology is proven."
Economic Modeling
The Agency's regulatory analysis
concluded that the variable control
standard with a 70 percent minimum
control level would result in equal or
lower national sulfur dioxide emissions
than the uniform 90 percent standard
while having less impact on costs, waste
disposal, and oil consumption (44 FR
33607, middle column and 33608). The
Sierra Club petition charged that the
Agency used an unrealistic model and
faulty assumptions in reaching these
conclusions. The petition alleged that
utility behavior as predicted by the EPA
model is "incredible" and that this
incredible behavior leads to "the
outlandish notion that stricter emission
controls will lead to more emissions."
The Administrator finds this allegation
to be without merit.
The principle modeling concept being
challenged is whether or not increased
costs of constructing and operating a
new plant (due to increased pollution
control costs) will affect the utility
operator's decisions on boiler retirement
schedules, the dispatching of plants to
meet electrical demand, and the rate of
construction of new plants. The model
used for the analysis assumed that
utility companies over the long term will
make decisions that minimize the cost of
electricity generation. That is, (1) under
any demand situation utilities will first
operate their equipment with the lowest
operating costs, and (2) existing
generating capacity will be replaced
only if its operating costs exceed the
capital and operating costs of new
equipment. While political, financial, or
institutional constraints may bar cost-
minimizing behavior in individual cases,
the Administrator continues to believe
that the assumption of such behavior is
the most sound method of analyzing the
impacts of alternative standards.
Under this approach, the model
simultaneously adjusts both the
utilization of existing plants and the
construction schedule of new plants
(subject to Subpart Da) based on the
relative economics of generating
electricity under alternative standards.
Hence, average capacity factors for the
population of new plants may vary
among standards due to variations in
the mix of base and intermediate loaded
plants which are brought on line in any
one year. But this does not mean, as
concluded in the Sierra Club petition at
page 8, that the model predicted that
utilities would permit new base-loaded
units to remain idle while they continue
to build still more new units.
The petition also alleged that this
modeling concept was introduced in the
phase 3 analysis, which was completed
after the close of the public comment
period, and hence the modeling
rationale was not subject to public
review. The petition went on to criticize
some of the assumptions in the mode)
charging that they were not even
mentioned in the record.
The Administrator finds no basis for
the Sierra Club's assertion that the
modeling methodology and input
assumptions were not exposed for
public review. First, the same model
was used for the phase 1, 2, and 3
analyses. The basic model logic was
explained in the preamble to the
September proposal and comments were
solicited-specifically on the use of a cost
optimization model for simulating utility
decisions (43 FR 42162, left column).
Secondly, the model's input
assumptions were subjected to broad
review. Assumptions were presented in
the September preamble and in even
greater detail in the consultant's reports
which are part of the record (OAQPS-
78-1, II-A-42, II-A-90, and II-A-91)
Following proposal, the Agency
convened an interagency working group
to review the macroeconomic model and
the Agency's input assumptions (44 FR
33604, left column). Members of the
group represented a spectrum of
expertise and interests (energy,
employment, environment, inflation,
commerce). The group me! numerous
times over a period of two months,
including meetings with UARG, NRDC,
and Sierra Club. As a result of the
group's recommendations, the phase 2
analysis was conducted. A full
description of the analysis including
changes to the modeling assumptions
was presented at the public hearing and
a detailed report was put into the record
(OAQPS-78-1, IV-A-5). For the phase 3
analysis accompanying promulgation,
the only change in modeling
assumptions from phase 2 was the
introduction of dry scrubbing
technology. Based on the detailed record
established, the Administrator
concludes that the Sierra Club had
ample opportunity to analyze and
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comment on the Agency's analytical
approach and did so by incorporating
the EOF and NRDC comments into their
January 1979 comments (OAQPS-78-1,
IV-D-626).
The Sierra Club also criticized the
conclusions of the Agency's regulatory
analysis because the assumed oil prices
were too low and the nuclear plant
growth rate was too high. To assist in
evaluating the petitions, two sensitivity
tests were performed on the Agency's
regulatory analysis. Using the phase 3
assumptions as a base, the analysis was
rerun first assuming higher oil prices
and then assuming both higher oil prices
and a lower nuclear growth rate
{OAQPS-7&-1, VI-B-16). The studies
addressed the promulgated standard,
the full control option (uniform 90
percent control), and a variable control
standard with a 50 percent minimum
control requirement as recommended by
UARG. The predictions for 1995 are
summarized in Tables 2 and 3,
respectively. For comparison, the phase
3 results are repeated in Table 1.
With respect to energy input
assumptions, the oil prices used by the
Agency for the phase 3 analysis were
based on the Department of Energy's
estimate of future crude oil prices. These
estimates are now probably low
because of the 1979 OPEC price increase
which occurred after promulgation of
the standard. For the sensitivity
analysis, the following oil prices in 1979
dollars were assumed:
Assumed Oil Prices
[Dollars per Barrel)
1985 ,
1990
1995
Sensitivity Pt"
analysis
25
30
38
iase 3
16
20
26
These prices were obtained from
conversations with DOE's policy
analysis staff. The prices may appear
low in comparison to the example of
$41.00 per barrel spot market oil given in
the Sierra Club petition, but the Sierra
Club figure is misleading because
utilities seldom purchase spot market
oil. The meaningful parameter is the
average refiners' acquisition cost, which
was $21/barrel at the time of this
analysis. The original nuclear capacity
assumptions were based on the
industry's announced plans for new
capacity. For sensitivity testing, these
estimates were modified by excluding
nuclear power plants in the early
planning stages while retaining those
now under construction or for which,
based on permit status, plans appear
firm. The following assumptions of total
nuclear capacity resulted:
Table 1.Summary of 1995 Impacts With Phase 3 Assumptions'
Level of control with 520 ng/J maximum emission limit
Current
standards
Vanable con-
trol. 50 pet
minimum
Variable con-
trol. 70 pel
minimum
Full
control
National SOi Emissions (million tons) .. . .. ..
East '
M.dwest . .
West South Central . ...
West
Incremental Annualized Cost (billions 1978 $)
Incremental Cosl of SO, Reduction (1978 $/ton)
Oil Consumption (million bbl/day) . ...
Coal Production (million tons)
Total Coal Capacity (GW)....
23 B
112
63
26
1 7
1 4
1,767
554
206
97
80
1 8
1 1
29
914
1 6
1,745
537
1 With wet and dry scrubbing and the following energy assumptions
Year
1985
1990
1995
Oil prices Nuclear
($ 1975) Capacity
(GW)
$12.90 97
16 40 165
21 00 228
205
97
80
1 7
1 1
33
1.036
1 6
1,752
537
207
101
79
1 7
09
44
1,428
1 8
1,761
520
7 See 44 FR 33608 for designation of census regions
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Table 2.Summary of 1995 Impacts With Higher Oil Pnces'
Level ol control with 520 ng/J maximum emission limit
Current Variable con- Vanable con- Full
standards trol, 50 pel Irol, 70 pet control
minimum minimum
East = ... ....
West South Central . ..
West
Total Coat Capacity (GW)
232
109
82
26
16
09
1,800
588
198
91
79
1 7
1 1
33
967
0.9
1,797
587
196
91
78
16
1.0
36
977
09
1.802
587
197
95
78
15
09
50
1,049
09
1.832
587
1 With wet and dry scrubbing and the following energy assumptions
Year
1985...
1990 .
1995...
Oil prices Nuclear
($ 1975) capacity
(GW)
$20.20 97
24 20 165
30 70 228
'See 44 FR 33608 lor designation ol census regions
Table 3.Summary of 1995 Impacts With Higher Oil Pnces and Less Nuclear Growth'
Level ol control with 520 ng/J maximum emission limit
Current
standards
Vanable con-
trol, 50 pet
minimum
Variable con-
trol. 70 pet
minimum
Full
control
National SO, Emissions (million tons)
East'
Midwest
West South Central
West
Incremental Annualized Cost (billions 1978 $)
Incremental Cost of SO, Reduction (1978 $/ton)
Oil Consumption (million bbl/day)
Coal Production (million tons)
Total Coal Capacity (GW)
250
120
86
86
1.7
09
1,940
644
209
98
8.2
18
12
3.6
883
09
1,943
644
206
97
61
1 7
1 1
41
914
09
1.946
644
205
101
80
16
09
59
1,259
09
1,984
643
1 With wet and dry scrubbing and the following energy assumptions
Year.
1985...
1990...
1995...
Oil prices Nuclear
($ 1975) Capacity
(GW)
$20 20 92
24 20 141
3070 173
See 44 FR 33608 for designation ol census regions
Assumed Nuclear Capacity
1985
1990
1995
Sensitivity
analysis
92 GW
141 GW
173 GW
Phase 3
97 GW
165GW
228 GW
Environmentally, the impact of higher
oil prices was to reduce SO2 emissions
(Table 2). For example, under the
promulgated standard (hereafter
referred to as "the standard") national
SO2 emissions in 1995 were projected to
drop from 20.5 million tons predicted in
phase 3 (44 FR 33608) to 19.6 million
tons. This reduction occurred because
the higher oil prices led to the retirement
of about 50 gigawatts (GW) of existing
oil-fired capacity. While these
retirements increased the demand for
new coal-fired plants, new plants
(subject to Subpart Da) on average were
less polluting than the oil-fired capacity
they replaced. Therefore, the net effect
of oil replacement on a broad regional
basis was to reduce SO2 emissions.
The relative impacts of the alternative
standards under the sensitivity tests
remained about the same. Sulfur dioxide
emissions under the standard were still
predicted to be lower than with either
full control or the 50 percent variable
standard. The emissions benefit relative
to full control was reduced from 200,000
tons per year to 100,000 tons per year.
Regionally, the effect of the higher oil
prices on the relative impacts of the
standards was mixed. In comparison to
full control, the standard continued to
reduce emissions in the East by 400,000
tons per year, but resulted in an
additional 70,000 tons in the West and
100,000 tons in the West South Central
(relative to phase 3). However, as
pointed out above, emissions in all
regions were less than or equal to those
under the phase 3 oil price assumptions.
The cost of all the standards
increased under the higher oil price
assumption. This increase was due to
the cost of additional coal capacity and
corresponding emission control
equipment. Relative to the standard, the
cost of full control increased by $300
million per year over the $1.1 billion
difference predicted under lower oil
prices.
At the higher oil prices, 1995 oil
consumption by utilities was predicted
to be the same under all standards
tested. Depending on the standard,
consumption was 500,000 to 800,000
barrels per day lower than under the
phase 3 projections with lower prices.
The reason that the environmental
standards had no effect on oil
consumption was that at the assumed
rate of oil price increase, all base- and
intermediate-loaded oil capacity was
retired by 1995 and the only remaining
oil use was in combustion turbines used
to meet peak demand.
Under the assumption of both high oil
prices and slowed nuclear growth
(Table 3), national and regional SO2
emissions were predicted to be about
the same as under the phase 3
projections. This effect was due to the
counterbalancing emission impacts. As
noted above, higher oil prices resulted in
a net decrease in SO2 emissions. But at
the same time the reduced supply of
nuclear generation capacity precipitated
demand for an additional 55 GW of new
coal capacity beyond that required
under the projection with high oil prices.
On a national level the emissions from
these new coal-fired plants offset the
emission reductions achieved by the oil
replacements.
With this additional 55 GW of new
coal-fired capacity, the environmental
impact of alternative standards was
more significant. Baseline emission
projections (i.e., assuming no change to
the original standard) increased from
23.8 million tons per year under the
phase 3 energy assumptions to 25.0
million tons per year. Accordingly, the
promulgated standard reduced national
SO2 emissions in 1995 by almost 4.5
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million tons per year in contrast to
about 3.5 million tons per year under
both the phase 3 and the high oil price
sensitivity projections.
While emission levels were roughly
the same as under the phase 3 energy
assumptions, the relative impacts of the
alternative standards changed
somewhat. National emissions were
predicted to be 100,000 tons less under
full control than under the standard.
Relative to full control, the standard
was still predicted to reduce emissions
by about 400,000 tons in the East, but on
a national basis this was offset by
emission increases in the other regions.
With higher oil prices and less nuclear
capacity, the environmental benefit of
full control in the West and West South
Central was greater by about 100,000
tons, but this impact is masked in Table
3 due to rounding. The variable standard
with a 50 percent minimum control level
resulted in about 400,000 tons per year
more emissions than full control and
about 300,000 tons per year more than
the standard.
The total cost of all the alternatives
increased due to the increased coal
capacity. Relative to the standard, the
cost of the 50 percent variable control
standard remained about the same. The
full control standard, however, was
significantly more expensive. The
marginal cost of full control (relative to
the standard) increased from $1.1 billion
under the phase 3 energy assumptions to
$1.8 billion.
Energy impacts were about the same
as those predicted in the high oil price
sensitivity runs. Oil consumption was
still predicted at about 900 000 barrels
per day under all alternative standards.
Coal production under all alternatives
increased by about 100 million tons per
year.
Even considering the uncertainty of
futuie oil prices and nuclear capacity,
the Administrator found no basis for
convening a proceeding on the modeling
issue. The sensitivity runs did not show
significant changes in the relative
impacts of the alternatives. Under the
sensitivity test with both high oil prices
and slowed nuclear growth, full control
for the first time showed lower
emissions nationally than the standard.
But the cost of this additional 100,000
tons of control was estimated at $1.8
billion, which represents more than a 40
percent increase in the incremental cost
of the standad (Table 3). The principal
environmental benefit of full control
would be felt in the West and West
South Central. Through case-by-case
new source review ample authority
exists to require more stringent controls
as necessary to protect our pristine
areas and natioral parks (44 FR 33504,
left column). As a result, the
Administrator continues to believe that
the flexibility offered by the standard
will lead to the best balance of energy,
environmental, and economic impacts
than either a uniform 90 percent
standard or a 50 percent variable
standard and hence better satisfies the
purposes of the Act.
On the other side of the modeling
issue, UARG charged that the Agency's
regulatory analysis does not support a
70 percent minimum requirement. The
petition called the Agency's control cost
estimates unrealistic and presented a
macrceconomic analysis which
concluded that a 50 percent minimum
requirement would result in a more
favorable balance of cost, energy, and
environmental impacts.
Response to the UARG petition was
difficult because the UARG position was
presented in two separate reports
submitted at different times, and the two
reports reached different conclusions. In
the formal petition, UARG
recommended 50 percent minimum
control and promised a detailed report
by NERA supporting their position.
When the NERA report arrived six
weeks later, if recommended 30 percent
control. In light of this confusion, it was
decided to review each report
separately based on its own merits, but
devote primary attention to the 50
percent recommendation. After
reviewing UARG's macrceconomic
analysis, the Administrator finds no
convincing arguments for altering the
conclusion that the 70 percent minimum
removal requirement provides the best
balance of impacts. In the formal
petition, UARG's conclusion that a 50
percent standard is superior was based
on a NERA economic analysis which
assumed that only wet scrubbing
technology v, .is available to utilities. A
detailed analysis of the NERA results
was not possible because only summary
outputs were supplied in their
comments. But the results of this
analysis set,m to coincide with the
Agency's conclusions that there are
energy, environmental, and economic
benefits, associated with standards that
provide a lower cost control alternative
for lower sulfur coals. The problem with
the UARG initial analysis is that it
overlooked the economic benefits of dry
scrubbing.
In recognition of this shortcoming,
UARG presented their estimate of the
costs of dry scrubbing made by Battelle
Columbus Laboratories {UARG petition,
page 25) and then hypothesized without
supporting analysis that "with realistic
cost assumptions the advantages of a
lower percent remo\al are likely to
increase even further" (UARG petition,
page 27). Table 4 compares Battelle's
costs to those used in the EPA
regulatory analysis. The two estimates
are almost the same. More importantly,
the two estimates agree that the cost of
a 70 percent efficient dry system is not
significantly greater than the cost of a 50
percent efficient system, and this
conclusion had important implications
in the specification of the standard.
Based on these comparisons, the
Administrator finds that the UARG
petition supports the Agency's dry
scrubbing cost assumptions and the
finding that no significant cost benefit
will result from a standard with a 50
percent minimum control level.
Table 4.Comparison of UARG and EPA dry SOt
Scrubbing Costs ' (Mills/kwhJ
Percent removal
50
70
Inlet sulfur (Ibs
SO./million
Btu)
080
200
060
200
UARG
'168
'213
197
254
EPA
206
244
266
266
' Wet scrubbing costs range up to 6 mills/kwh
1 UARG cos>ts based on 55 percent removal
In their second report, UARG
presented additional economic analyses
by NERA. In those analyes, the impacts
of 30, 50, and 70 percent minimum
control standards were tested assuming
that both wet and dry scrubbing
technology were available. The analyses
were performed with three different sets
of control cost assumptionsEPA's
costs. Battelle's costs, and an additional
set of costs specified by NERA. The
report concluded that the 70 percent
standard is superior using EPA's costs
but that under the other cost estimates
the 30 percent standard is better. The
cost effectiveness of alternative
standards (dollars per ton of pollutant
removed) was their principal basis of
evaluation. UARG then alleged that EPA
overestimated the differences in cost
between wet and dry scrubbing and that
this error led to the wrong conclusion
about the impacts of the 70 percent
minimum removal requirement. The EPA
cost assumptions were criticized
primarily because different methods
were used to estimate dry and wet
scrubbing costs. To justify their position,
UARG presented estimates of wet and
dry scrubbing costs developed by
Battelle. UARG believes that Battelle
understand scrubber costs, but that
Battelle's relationship between wet and
dry scrubbing costs is more accurate
than EPA's (UARG petition, page 7). As
noted above, Battelle agreed with the
Agency's dry scrubbing costs, but for
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wet scrubbing the Battelle costs were
substantially lower than the Agency's.
Typically, when comparing results of
studies, the Agency has detailed
documentation with which to compare
the methods of costing and analysis. In
this case, the Administrator had
documentation for neither the NERA
costs nor the Battelle costs. The NERA
costs were unreferenced and supported
by neither engineering analysis nor
vendor bids. They assumed that the
capital cost of a dry scrubber is 10
percent less than that for a comparable
wet scrubber and that the operating
costs and energy requirements are the
same for the two systems. The UARG
petition promised a detailed report from
Battelle, but the report was not
delivered. Without a basis for
evaluation, the Battelle and NERA costs
can only be considered as hypothetical
data sets for the purpose of sensitivity
testing of the economic analysis. They
cannot be considered as new
information on SO2 control costs.
The EPA cost estimates, on the other
hand, have withstood several critical
tests. The PEDCo cost model for wet
scrubbers which was used by EPA was
thoroughly reviewed by Department of
Energy (DOE) consultants, and DOE
concurred with the EPA estimates
through the interagency working group.
Later, the Agency's costs were again
reviewed in detail against wet scrubber
costs predicted by the Tennessee Valley
Authority's scrubber design model.
While the two models initially seemed
to produce divergent results, careful
analysis of the respective costing
methodology showed that for similar
design specifications the two models
produced costs that were very close, the
major difference stemming from
different assumptions about the
construction contingency fee (OAQPS-
78-1, IV-B-50). The Administrator
concluded from these cost comparisons
that the Agency's flue gas
desulfurization cost assumptions are
reasonable.
The EPA dry scrubbing costs were
based primarily on engineering studies
submitted by electric utility companies
and equipment vendors for the full-scale
utility systems now on order or under
construction. Using these studies, the
EPA cost estimates were made in full
cognizance of the basic assumptions
used in the PEDCo wet scrubbing model.
The result was that for economic
modeling purposes (OAQPS-78-1, IV-
A-25, page B-17) the dry scrubbing cost
estimates in the background document
(EPA 450/5-79-021, page 3-67) were
increased to reflect similar fuel
parameters, local conditions, and degree
of design conservatism as reflected in
the wet scrubbing costs. Since care was
taken in aligning these costs, the
Administrator does not accept UARG's
allegation that EPA's costs for wet and
dry scrubbing are invalid because they
were developed on an inconsistent
basis.
Even if EPA accepted UARG's
unsubstantiated cost assumptions, the
NERA sensitivity analyses provided no
new insights nor did they materially
contradict the Agency's basic *
conclusions about the standard. Using
the Battelle costs and NERA's
"alternative scrubber costs" as a range,
NERA predicted that relative to 50
percent minimum control, a 70 percent
standard would reduce national SO»
emissions by an additional 250 to 450
thousand tons per year compared to
about 100 thousand tons estimated by
EPA (Table 1). NERA predicted the
additional costs of a 70 percent
minimum standard relative to a 50
percent requirement would be between
$300 million and $400 million per year
compared to $300 million predicted by
EPA. It was only in moving to 30 percent
control that the NERA results showed a
distinct cost savings ($600 to $900
million) over the 70 percent level, but
the 30 percent standard produced an
additional 700 thousand tons per year of
SO2 under both of their control cost
scenarios. The Administrator rejects the
30 percent standard advocated by
UARG because the potential cost
savings do not justify the potential
emission increases. In conclusion, the
trade-offs between costs and emissions
shown by UARG are generally similar to
those predicted by EPA in promulgating
the standard and therefore do not
support a different standard from the 70
percent variable standard adopted.
Other Issues
Kansas City Power and Light
Company sought either an elimination of
the percent reduction requirement when
emissions are 520 ng/J (1.2 Ibs/million
Btu) heat input or less or as an
alternative a reduction in the 70 percent
minimum control requirement. In their
arguments, KCPL cited annualized
control costs for wet scrubbing of $11.4
million and an energy penalty of 70
thousand tons of coal per year to
operate a scrubber. Second, they noted
that 14 percent of the potential SO2
emissions from the coal they plan to
burn will be removed by the fly ash.
Taking these two factors in account,
KCPL computed a cost effectiveness
ratio for a hypothetical 650 MW unit to
be $3,600 per ton of sulfur removed and
concluded that such control was too
expensive. Finally, they concluded that
scrubbing low-sulfur coals is not
warranted since uncontrolled SO2
emissions from their new plants will be
less than the emissions allowed by the
standard for high-sulfur coals with 90
percent scrubbing.
After careful review, the
Administrator finds that the KCPL
petition provided no legal or technical
basis for reconsidering the final rule.
First, the question of whether a plant
burning low-sulfur coal should be
required to meet the same percentage
reduction requirement as those burning
high-sulfur coal has been a central issue
throughout this decision-making. Since
this issue was raised in the proposal (43
FR 42155, left column), KCPL had ample
opportunity to make their points during
the public comment period. In fact, it
was the recognition of this trade-off in
emissions between high-sulfur and low-
sulfur coal that led the Administrator to
first consider the concept of variable
control standards (43 FR 42155, right
column). While sulfur removal by fly ash
does not represent best demonstrated
technology for SO2 control, sulfur
removal by fuel pretreatment, fly ash,
and bottom ash may be credited toward
meeting the 70 percent requirement.
Second, the KCPL petition does not
allege the requisite procedural error that
the standard was based on information
on which they had no opportunity to
comment. Their objections center
primarily on the economic and energy
impacts of wet SO2 scrubbing on low-
sulfur coal. These issues were clearly
identified by the Agency in the
background document supporting
proposal (OAQPS-78-1, III-B-3,
Chapters 5 and 7). Furthermore, the
preamble to proposal specifically
requested comments on the Agency's
assumptions for the regulatory analysis
(43 FR 42162, left column).
Finally, and more importantly, the
major points made by KCPL are not of
central relevance to the outcome of the
rule because the information presented
does not refute the Agency's data base
on wet scrubbing. Consider the
following comparisons to the
assumptions of the EPA regulatory
analysis.
(a) The control costs quoted by KCPL
for a 650 MW unit were $31 million in
capital and $6.2 million in operating
expenses. The EPA assumptions applied
to a comparably sized unit result in $55
million in capital costs and $7 million in
operating expense.
(b) KCPL quoted an energy impact of 8
tons of coal per hour to operate the
scrubber. Considering their operating
requirement of 460 tons of coal per hour,
the energy penalty of SO2 control is 1.7
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percent. The Agency's economic model
assumed 2.2 percent.
(c) KCPL computed cost effectiveness
of the standard at $3600 per ton of sulfur
removed. This figure is based on a
misunderstanding of the application of
the fly ash removal credit toward the 70
percent removal requirement. According
to the standard, the scrubbing
requirement when assuming a 14 percent
SO2 removal in flyash is 55 percent
rather than 56 percent as cakiJaH'd by
KCPL. At C5 peir,ent scrubbing. Ihs cost
per ton of sulfur removed is $3100. This
converts to a cost of $1550 per ton of
sulfur dioxide removed which is similar
to the cos's estimated by EPA for low-
sulfur coal applications (OAQPS-78-1,
II1-R--3 and 1V-B-14).
Thus, the Administrator has already
concluclud that energy and economic
cos's greatei than those cited by KCPL
ar? justified to achieve the emission
reductions required by the standard.
Conclusions on Minimum Control Level
After carefully weighing the
a/puments by the three petitioners, the
Administrator can find no new
infoimation or insights which are of
central relevance to his conclusions
about the benefits of a variable control
standard with a 70 percent minimum
removal requirement. The Sierra Club
and UARG correctly point out that the
Agency's phase 3 analysis was
completed after the close of the public
comment period and that they were
therefore unable to comment on the final
step of the regulatory analysis. But in
assessing these comments it is important
to put the phase 3 analysis in proper
context with its role in the final
decision. The Administrator's
conclusions about the responses of the
utility industry to alternative standards
were no! based on phase 3 alone, but a
seiies of economic studies spanning
more than a year's effort. These
analyses were performed under a range
of assumptions of economic conditions,
regulatory options, and flue gas
desulfurization parameters. The phase 3
analysis was merely a fine tuning of the
regulatory analysis to reflect dry
scrubbing technology.
No new modeling concepts or
assumptions were introduced in phase 3.
The fundamental modeling concept as
introduced in the September proposal
(43 FR 42161, right column) has not
changed. The model input assumptions
were the same as those of the phase 2
analysis presented on December 8, 1978
(44 FR 54834, middle column), and at the
December 12 and 13,1978, public
hearing. Detailed consultants' reports on
the modeling analyses were available
for comment before the close of the
public comment period. This public
record provided adequate opportunity
for the public to comment both on the
principal concepts and detailed
implementation of the regulatory
analysis before the close of the public
comment period.
Even though new information was
added to the record after the close of the
comment period, none of the petitions
raised valid objections to this
information or cast any uncertainty that
is gnrmane to the final decision. The
Administrator has very carefully
weighed the petitioners comments on
dry scrubbing and the UARG sensitivity
analysis on pollution control costs. Not
only did the UARG analysis generally
confirm the conclusions of the EPA
regulatory analyses, but it established
that even if dry scrubbing costs vary
substantially, the relative impacts of a
50 versus 70 percent minimum removal
requirement change very little. The 70
percent standard was estimated to
produce lower emissions for only
slightly higher costs. Differences in cost
efiectiveness, which UARG seem to
weigh most heavily, varied by only $2 to
a maximum of $50 per ton of SOS
removed across alternative cost
estimates. In the final analysis none of
the petitions repudiated the Agency's
findings on the state of development,
range of applicability, or costs of dry
SOa scrubbing. In light of these findings,
the Administrator finds the information
in the petitions not of central relevance
to the final rule and therefore denies the
requests to convene a proceeding to
reconsider the 70 percent minimum
removal requirement.
///. SO, Maximum Control Level (90
percertt reduction of potential SO,
emissions)
Petitions for reconsideration
submitted by the Utility Air Regulatory
Group (UARG) and the Sierra Club
questioned the basis for the maximum
control level of 90 percent reduction in
potential SOj emissions, 30-day rolling
average. The other petitions did not
address this issue. However, in a July 18,
1979, letter, the Environmental Defense
Fund (EOF) requested EPA to review
utilization of adipic acid scrubbing
additives as a basis for a more stringent-
maximum control level. An additional
analysis by UARG was Forwarded to
EPA on January 28,1980. Although it
was reviewed by EPA, a detailed
response could not be prepared in the
three days afforded EPA for comment
prior to the court's doadline of January
31, I960, for EPA to respond to the
petitions. However, the only issue not
previously raised by I'ARG (boiler load
variation) has been addressed by this
response.
With their petition, UARG submitted a
statistical analysis of flue gas
desulfurization (FGD) system test data
which purportedly revealed certain
flaws in the Agency's conclusions. The
UARG petition maintained that a
scrubber with a geometric mean
(median) efficiency of 92 percent could
not achieve the standard because of
variations in its performance. UARG
also maintained that the highest removal
efficiency standard that can be justified
by the Agency's data is 85 percent, 30-
day rolling average. In the alternative,
they suggested that the 90 percent, 30-
day rolling average standard could be
retained if an adequate number of
exemptions were permitted during any
given 30-day averaging period. On the
other hand, the Sierra Club questioned
why the standard had been established
at 90 percent when the Agency had
documented that well-designed,
operated, and maintained scrubbers
could achieve a median efficiency of 92
percent. In doing so, they argued that a
90 percent, 30-day rolling average
standard was not sufficiently stringent.
After reviewing their petitions, the
Administrator finds that the Sierra Club
and UARG overlooked several
significant factors which were of critical
importance to the decision to
promulgate a 90 percent, 30-day rolling
average standard. The Sierra Club
position was based on a
misunderstanding of the statistical basis
for the standard. The UARG analysis
was flawed because it did not consider
the sulfur removed by coal washing,
coal pulverizers, bottom ash, and fly ash
(hereafter, collectively referred to as
sulfur reduction credits). Instead the
UARG petition based its conclusions on
the performance of the FGD system
alone. In short, UARG did not analyze
the promulgated standard (44 FR 33582,
center column). Furthermore, UARG
underestimated the minimum
performance capability of scrubbers by
assuming that future scrubbers would
not even achieve the level of process
control demonstrated by the best
existing systems tested by EPA.
EPA has prepared two reports which
re-analyze the same FGD test data
considered in UARG's analysis. One
report identified the important design
and operating differences in the FGD
systems tested (OAQPS-78-1, Vl-B-14)
by EPA and the second report provided
additional statistical analyses of these
data (OAQPS-78-1, VI-B-13). The
results of the EPA analyses showed that:
1. Flue gas desulfurization systems
can achieve a 30-day rolling average
efficiency between 88 percent and 89
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percent (base loaded boilers) or
between 86 and 87 percent (peak loaded
boilers) with no improvements in
currently demonstrated process control.
2. Even if a new FGD system attained
only 85 percent efficiency (30-day rolling
average), a 90 percent reduction in
potential SOj emissions can be met
when sulfur reduction credits are
considered.
To clarify the basis for the Agency's
conclusions, the following discussion
reviews the development of information
used to establish the final percent
reduction standard. Initially, EPA
studied the application of FCD systems
for the control of SOj emissions from
power plants. As part of that effort,
information which described the status
and performance of FGD systems in the
U.S. and Japan was inventoried and
evaluated. These evaluations included
the development of design information
on how to improve the median
efficiency of FGD systems based upon
an extensive testing program at the
Shawnee facility (OAQPS-78-1, II-A-
75). The Shawnee test data and other
data (OAQPS-78-1, II-A-71) on existing
FGD systems were generated by short-
term performance tests. These data did
not define the expected performance
range (the minimum and maximum SO?
percent removal) of state-of-the-art FGD
systems.
Because a continuous compliance
standard was under consideration,
information about the process variation
of FGD systems was needed to project
the performance range of scrubber
efficiency around the median percent
removal level. For the purpose of
measuring process variation, several
existing FGD systems were monitored
with continuous measurement
instrumentation. The selection of FGD
systems to be tested was limited
principally to the few FGD systems
available which were attaining 80 to 90
percent median reduction of high-sulfur
coal emissions. When examining the
results of these tests, it should be
recognized that they do not reflect the
performance of a new FGD system
specifically designed to attain a
continuous compliance standard.
When the percent reduction standard
was proposed, EPA projected the
performance of newly designed FGD
systems. The projection, referred to as
the "line of improved performance" in
the analysis, was principally based on
the information on how to improve
median system performance (OAQPS-
78-1, III-B-4). The line showed that
compliance with the proposed standard
(85 percent reduction in potential SO2
emissions, 24-hour average) could be
attained with an FGD system if the only
improvement made relative to an
existing FGD system was to increase the
median efficiency to 92 percent. The
"line of improved performance" did not
reflect the sulfur reduction credits that
could be applied towards compliance
with the proposed standard or the
improvements in process control (less
than 0.289 geometric standard deviation)
that could be designed into a new
facility. While these alternatives were
discussed in detail and included within
the basis for the proposed standard
(OAQPS-78-1, III-B-4), the purpose of
the "line of improved performance" was
to show that even without credits or
process control improvements, the
proposed standard could be met. Upon
proposal, the source owner was
provided a choice of complying with the
percent reduction standard by (1) an
FGD system alone (85 percent reduction,
24-hour standard), or by (2) use of sulfur
reduction credits together with an FGD
system attaining less than 85 percent
reduction.
After proposal, EPA continued to
analyze regulatory options for
establishing the final percent removal
requirement. On December 8,1978,
economic analyses of these additional
options were published in the Federal
Register (43 FR 57834) for public
comment. In this notice EPA stated that:
Reassessment of the assumptions made in
the August analysis also revealed that the
impact of the coal washing credit had not
been considered in the modeling analysis.
Other credits allowed by the September
proposal, such as sulfur removed by the
pulverizers or in bottom ash and flyash, were
determined not to be significant when viewed
at the national and regional levels. The coal
washing credit on the other hand, was found
to have a significant effect on predicated
emissions levels and, therefore, was taken
into consideration in the results presented
here.
This statement gave notice that the
effect of the coal washing credit on
emission levels for the proposed control
options had not been properly assessed
in previous modeling anayses. In the
economic analyses completed before
proposal, the environmental benefits of
the proposed standard were optimistic
because it was assumed that all high-
sulfur coal would be washed, but a
corresponding reduction in the level of
scrubbing needed for compliance was
not taken into account. This error
resulted in the analyses understimating
the amount of national and regional SO2
emissions that would have been allowed
by the proposed standard. This problem
was discussed at length at the public
hearing on December 12,1978 (OAQPS-
78-1, IV-F-1, p. 11, 22, 28, and 29).
UARG addressed this question of coal
washing in comments submitted in
response to recommendations presented
at the public hearing by the Natural
Resources Defense Council (OAQPS-78-
1. IV-F-1, p. 65,12-12-78) that the final
standards be based upon the removal of
sulfur from fuel together with the
removal of SO» from flue gases with a
FGD system. In their comments
(OAQPS-78-1, IV-D-725, Appendix A,
p. 23), UARG had three main objections:
(1) All coals are not washable to the
same degree.
(2) Coal cleaning may not be
economically feasible.
(3) The Clean Air Act and the
Resource Conservation and Recovery
Act may preclude the construction of
coal washing facilities at every mine.
EPA has reviewed these comments
again and does not find that they change
the Administrator's conclusion that
washed coal can be used in conjunction
with FGD systems to attain a 90 percent
reduction in potential SO» emissions.
First, EPA realizes that all coal is not
equally washable. In the regulatory
analaysis, the degree of coal washing
was a function of the rank and sulfur
content of the coal. Moreover, because
of the variable control scale inherent in
the standard, 75 percent of U.S coal
reserves would require less than 90
percent reduction in potential SO»
emissions. The remaining 25 percent are
high sulfur coals on which the highest
degree of sulfur removal by coal
washing are acheived. Second, the
washing assumptions used by the
Agency reflected the percentage of
sulfur removal currently being attained
by conventional coal washing plants in
the U.S. (OAQPS-78-1, IV-D-756).
These washing percentages were
therefore cost-feasible assumptions
because they are typical of current
washing practices. Finally, the Agency
does not believe that environmental
regulations will prohibit the cleaning of
coal. The Clean Air Act and the
Resource Conservation and Recovery
Act may impose certain environmental
controls, but would not prevent the
routine construction of coal washing
plants. Thus, the Agency concluded that
the basis for the promulgated standard
could be a combination of FGD control
and fuel credits.
Based on these findings, EPA stated
(44 FR 33582) that the 90 percent
reduction standard "can be achieved at
the individual plant level even under the
most demanding conditions through the
application of flue gas desulfurization
(FGD) systems together with sulfur
reductions achieved by currently
practiced coal preparation techniques.
Reductions achieved in the fly ash and
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bottom ash are also applicable". Thus,
FGD systems together with removal of
sulfur from the fuel was'the basis for the
final standard. The standard prohibits
the emission of more than "10 percent of
the potential combustion concentration
[90 percent reduction)." That is, the final
standard requires 90 percent reduction
of the potential emissions (the
theoretical emissions that would result
from combustion of fuel in an uncleaned
state), not 90 percent removal by a
scrubber.
Since UARG failed to take into
consideration sulfur reduction credits,
UARG analyzed a more stringent
standard than was promulgated.
Furthermore, EPA's review revealed that
while the statistical methodology in the
UARG analysis was basically correct, it
was flawed by UARG's assumption
about the process variation of a new
FGD system. As a result, the statistical
anaysis was improperly used by UARG
to project the number of violations
expected by a new FGD system.
To elaborate on the variability issue,
page 14 of the UARG petition states:
The range of efficiency variability values
resulting from this analysis represents the
range of efficiency variabilities that can be
expected to be encountered at future FGD
sites
This assumption artificially inflated
the amount of variability that would
reasonably be expected in a new FGD
system because it presumed that there
were no major design and operational
differences in the existing FGD systems
tested and that the performance of new
systems would not improve beyond that
of systems tested by EPA. To estimate
process variability of new FGD systems,
UARG simply averaged together all data
from all systems tested including
malfunctioning systems (Conesville).
EPA's review of these data showed that
there were major design and operating
differences in the existing FGD systems
tested and that the process control could
be improved in new FGD systems
(OAQPS-78-1, VI-B-14). Therefore, not
all of the FGD systems tested by EPA
were representative of best
demonstrated technology for SO2
control.
These major differences in the FGD
systems tested are apparent when the
test reports are examined (OAQPS-78-1,
VI-B-14).One of the tests was
conducted when the FGD systems were
not operating properly (Conesville). Two
tests were conducted on regenerative
FGD systems (Philadelphia and
Chicago) which are not representative of
a lime or limestone FGD system.
Another test was on an adipic acid/lime
FGD system (Shawnee-venturi). None of
these tests were representative of the
process variation of well-operated, lime
or limestone FGD systems on a high-
sulfur coal application (OAQPS-78-1,
VI-B-14).
Only three systems were tested when
(1) the unit was operating normally, and
(2) pH control instrumentation was in
place and operational (Pittsburgh,
Shawnee-TCA, and Louisville). Only at
Shawnee did EPA purposely have
skilled engineering and technician
personnel closely monitor the operation
during the test (OAQPS-78-1, VI-B-14).
Data from these systems best describe
the process control performance of
existing lime/limestone FGD systems.
During the Pittsburgh test, there were
some problems with pH meters. The
data was separated into Test I (pH
meter inoperative) and Test II (pH meter
operative). During Test I, operators
measured pH hourly with a portable
instrument (OAQPS-78-1, VI-B-14).
Analysis of these data show low
process variation during each test period
(OAQPS-78-1, VI-B-13). Although the
process variation during the second test
was 10 percent lower, the difference
was not found to be statistically
significant. Data taken during each test
(I and II) are representative of control
attainable with pH controls only. Boiler
load was relatively stable during the
test. Average process variation as
described by the geometric standard
deviation was 0.21 and 0.23,
respectively.
At Shawnee, only pH controls were in
use, but additional attention was given
to controlling the process by technical
personnel. Boiler load was purposely
varied. Geometric standard deviation
was 0.18, which was similar to that
recorded at Pittsburgh. UARG
acknowledged that careful attention to
control of the FGD operation by skilled
personnel was an important factor in
control of the Shawnee-TCA scrubber
process (OAQPS-78-1, II-D-440, page
3). It was at the Shawnee test that the
best control of FGD process variability
by an existing FGD system was
demonstrated (OAQPS-78-1, II-B-13).
The Louisville test appears to
represent a special case. The average
process variation was significantly
higher (0.30 and 0.34 for the two units
tested) than was recorded at the two
other tests (Pittsburgh and Shawnee).
An EPA contractor identified two
factors which potentially could
adversely affect process control at
Louisville (OAQPS-78-1, VI-B-14). First,
they noted that Louisville was originally
designed in the 1960's and has had
significant retrofit design changes which
could affect process control. Second, the
degree of operator attention given to
process control is unknown. In addition,
UARG showed that an additional factor
which may affect the FGD process
control is boiler load changes. Unlike a
new boiler, the Louisville unit is an
older boiler which has been placed into
peaking service and therefore
experiences significant load changes
during the course of a day. As was the
case with Pittsburgh and Shawnee,
Louisville only uses pH controls to
regulate the process. The process
variation was analyzed and the
maximum process variation of the
Louisville system, at a 95 percent
confidence level, was determined to be
0.36 geometric standard deviation
(OAQPS-78-1, VI-B-13). This estimate
of process variation represents a "worst
case" situation since it reflects the
degree of FGD variability at a peaking
unit rather than on the more easily
controlled immediate- or base-loaded
applications.
In addition to basing their projections
on nonrepresentative systems, UARG
has also ignored information in a
background information document
(OAQPS-78-1, II-B-4. section 4.2.6) on
feasible process control improvements
which were currently used in Japan
(OAQPS-78-1, H-I-359). An appraisal of
the degree of process instrumentation
and control in use at the existing FGD
systems tested and a review of the
feasible process control improvements
which can be designed into new FGD
systems was also reviewed (OAQPS-
78-1, VI-B-14). As described in this
review, none of systems tested had
automatic process instrumentation
control in operation. All adjustments to
scrubber operation were made by
intermittent, manual adjustments by an
operator. Automatic process controls,
which provide immediate and
continuous adjustments, can reduce the
process control response time and the
magnitude of FGD efficiency variation.
Even the best controlled FGD systems
tested (the Shawnee FGD system, which
was designed in the 1960's) employed
only feedback pH process control
systems (OAQPS-78-1, IV-J-20). None
of these existing FGD systems were
designed with the feedforward process
control features now used in Japan
(OAQPS-78-1, II-I-359) for the
automatic adjustment of scrubber make-
up in response to changing operating
conditions. These systems respond to
boiler load changes or the amount of
SOi in the flue gases to be cleaned
before they impact the scrubbing
system. The use of such systems would
improve the control of short-term FGD
efficiency variation. At the FGD systems
tested, the actual flue gas SO»
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concentration (affected by coal sulfur
content) and gas volume (affected by
boiler load) was not routinely monitored
by the FGD system operators for the
purpose of controlling the FGD
operation as is currently practiced in
Japan (OAQPS-78-1.11-I-359). Thus,
even the best controlled existing
systems tested were not representative
of the control of process variation that
would be expected in the performance
of new FGD systems to be operated in
the 1980's (OAQPS-78-1, VI-B-14). For
the purpose of describing the range in
performance of an FGD system using
only feedback pH control and which are
known to have received close attention
by operating personnel, the data
recorded at these two existing FGD
systems (Pittsburgh, test II and
Shawnee-TCA) have been used by EPA
to project the maximum process
variation that would result (0.23
geometric standard deviation) at a 95
percent confidence interval for a base
loaded boiler. The data from Louisville
was used to represent performance of a
peak loaded boiler (0.36 geometric
standard deviation at the 95 percent
confidence level). These values are
conservative because the data collected
at the existing FGD systems tested are
not representative of the lower process
variation that would be expected in
future FGD systems designed with
improved process control systems
(OAQPS-78-1, VI-B-14).
EPA's statistical analysis of scrubber
efficency is in close agreement with the
UARG analysis when-the same process
variation and amount of autocorrelation
was assumed. EPA's analysis showed
about the same autocorrelation effect
(the tendency for scrubber efficiency to
follow the previous day's performance)
as UARG's analysis. A "worst-case" 0.7
autocorrelation factor was used in both
analyses even though a more favorable
0.6 factor could have been used based
upon the measured autocorrelation of
the data at the Shawnee-TCA and
Pittsburgh tests. A comparison of the
minimum 30-day average performance
of a FGD system based upon EPA and
UARG process variation assumptions is
given in Table 5a.
The EPA analysis (OAQPS-78-1, VI-
B-13) summarized in Tables 5a and 5b
shows the median scrubbing efficieny
required to achieve various minimum 30-
day rolling average removal levels
(probability of 1 violation in 10 years).
The three sets of estimates shown are
based on (1) the same process control
demonstrated at Pittsburgh, test II and
loaded, well-operated existing plant
(a,=0.20 on average and cr,=0.23 at the
95 percent confidence level), (2) the
same process control demonstrated at
Louisville which represents a peak
loaded, existing plant (or,=0.32 on
average and o-,=0.36 at the 95 percent
confidence level), and (3) the poor
process control projected by UARG
(or,=0.29 on average and o-,=0.43 at the
95 percent confidence level). The
process variation is described on a 24-
hour, geometric standard deviation (o-()
basis to allow comparison with UARG's
analysis. However, the minimum FGD
efficiencies shown in Tables 5a and 5b
are 30-day rolling averages.
It is evident from the analysis
summarized in Table 5a that if a new
FGD system could be operated at least
as well as the two best controlled
existing FGD systems tested, a 92
percent efficient scrubber (median) can
achieve between 88 and 89 percent
control on a 30-day rolling average
Shawnee-TCA. which represents a base
basis.'More than 89 percent minimum
reduction could be obtained if the
process variations in new FGD systems
are kept under better control with new
control system instruments and careful
attention by operating personnel. Even
the peak-loaded Louisville system,
which has much higher process
variability (o-,=0.32 on average), could
achieve 86 to 87 percent reduction.
When reviewing the results of
analyses contained in Tables 5a and 5b,
it must be kept in mind that they
represent "worst case" projections of
compliance capability. Neither the
UARG nor EPA projections took into
account load shifting or the effect of a
spare FGD module as a means of
countering worst-case system
performance (as portrayed by the 95
percent confidence level).
1 With a risk assumption of one violation per year
(the assumption used by UARG] the minimum 30-
day rolling average was between 89 percent and 90
percent control at the 95 percent confidence level
(OAQPS-78-1. VI-B-13, page 1-4).
Table Sa.Median FGD Efficiency to Attain Minimum 30-day Rolling Average Standard for Base Loaded
Units1**
Minimum 30-day rolling average Median efficiency for existing well-controlled
FGD efficiency FGD systems tested [EPA basts]
Median efficiency lor an existing FGD
systems tested [UARG basts]
Average
to-.=0.20J
Maximum Average
tcr.oO.23] {cr.-0.29]
Maximum [ Estimates are based on probability of only 1 violation in 10 yean. Process variation (cr, to expressed as one geometric
standard deviation, 24-hour basts). The maximum process variation is projected at the 95th percentite.
Table St.Median FGD Efficiency to Attain
' Minimum 30-day Rolling A verage Standard for Peak
Loaded Units.
Minimum 30-day
rolling average
FGD efficiency
Median efficiency for peak loaded,
existing FGD systems tested [EPA
basis]
90
89
88
87
86
85
Average
t Estimates are based on probability of only 1 violation in
10 years. Process variation (o-J expressed as one geomet-
ric standard deviation, 24-hour basts. The maximum process
variation is projected at the 95th percentile.
EPA also contended that an FGD
system supplier could miss the mark in
designing a 92 percent median efficiency
FGD system and that a miscalculation of
only 1 or 2 percent in median efficiency
would prevent the FGD system from
complying with the final SO> percent
reduction standard (UARG petition,
Appendix B, p. 64). EPA specifically
addressed this miss-the-mark argument
when it established a variable control
standard (70 percent to 90 percent
reduction). In the preamble to the final
standard EPA stated, "Finally, under a
variable approach, a source could move
to a lower sulfur content coal to achieve
compliance if its control equipment
failed to meet design expectations" (44
FR 33583, left column). An FGD system
designed for high-sulfur coal would
increase in scrubbing efficiency if a
lower-sulfur coal were fired, and the
amount of removal required for
compliance would drop from 90 percent
to as low as 70 percent reduction in
potential SOa emissions.
Even if, as UARG contends, an FGD
system on a 30-day rolling average basis
(through poor design or operating
practices) could only attain 85 percent
reduction, the facility would comply
with the promulgated 90 percent
reduction standard when credits for
sulfur removed by coal washing,
pulverizers, and in bottom and fly ash
are considered. These credits which can
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be substantial, are summarized as
follows:
1. Coal washing. On high-sulfur
midwestern coals that would be subject
to the 90 percent reduction requirement,
an average of 27 percent sulfur removal
was achieved by conventional coal
washing plants in 1978 (OAQPS-78-1),
IV-D-761). Even in Ohio where the
lowest average coal washing reduction
was recorded, 20 percent reduction was
attained. These data represent current
industry practice and do not necessarily
represent full application of state-of-the-
art in coal cleaning technology.
2. Coal pulverizers. Additional sulfur
reductions are also attainable with coal
pulverizers used at power plants. Coal is
typically pulverized at power plants
prior to combustion. By selecting a
specific type of coal pulverizer (one that
will reject pyrites from the pulverized
coal), sulfur can be removed. One utility
company reported to EPA that sulfur
reductions of 12% to 38% (with 24%
average removal) had been obtained
(OAQPS-78-1, II-D-179) by the
pulvizers alone when a program had
been implemented to optimize the
rejection of pyrites by the pulverizer
equipment.
3. Ash retention. One utility company
has reported 0.4% to 5.1% sulfur removal
credit in bottom ash alone with eastern
and midwestern coals and 7.3% to 15.9%
removal with a western coal (OAQPS-
78-1, Il-B-72). To determine how much
sulfur is removed by the bottom ash and
fly ash combined, EPA conducted a
study in which numerous boilers were
tested. The amount of Sd emitted was
compared to the potential SO> emissions
in the coal. For eight western coals and
six midwestern coals, an average sulfur
retention of 20 percent and 10 percent,
respectively, was found (OAQPS-78-1,
IV-A-6). Thus, an average of at least 10
percent SO* reduction can be attributed
to sulfur retention in coal ash.
These credits together with an FGD
system continuously achieving as little
as 85 percent reduction are sufficient to
attain compliance with the final SOi
percent reduction standard as is shown
in Table 6:
Table 6.Impact of Sulfur Reduction Credits
on Required FGD Control Efficiencies to
Attain 90 Percent Overall SO, Reduction
SOi removal method
Compliance
Option
C
Coal washing removal, percent...- 27 20 8
Pulvenzei, lly ash, and bottom ash
reduction, percent ... 10 4 0
FGD system removal, percent 65 67 89
Overall SO, reduction in potential
emissions «. _.T. T.lllll[[ Qo BO 80
Table 6 illustrates that even if the
FGD system attained only 85 percent
reduction as UARG has claimed, the 90
percent removal standard would be
achieved (Option A) even if a coal
washing plant attained only 27 percent
reduction in sulfur (the average
reduction reported by the National Coal
Association for conventional coal
washing plants, OAQPS-78-1. IV-D-
761). In addition, Table 6 illustrates that
less fuel credit is needed when the FGD
system attains more than 85 percent
reduction (Options B and C). For
example, even if the minimum amount of
coal washing curently being achieved
(20 percent in Ohio) is attained, only 87
percent FGD reduction would bex
needed. Thus, less than average or only
average sulfur reduction credits (i.e.,
only 8-27% coal washing and 0-10%
pulverizer, bottom ash and fly ash
credits) would be needed to comply with
the 90 percent reduction standard even
if the FGD system alone only attained 85
to 89 percent control. Moreover, for 75
percent of the nation's coal reserves
which have potential emissions less
than 260 ng/J (6.0 Ibs/million Btu) heat
input (OAQPS-78-1, IV-E-12. page 18),
less than 90 percent reduction in
potential SOt emissions would be
needed to meet the standard
The statistical analysis submitted by
UARG does not address the basis (FGD
and sulfur reduction credits) of the
standard and therefore does not alter
the conclusions regarding the
achievability of the promulgated percent
reduction standard. The prescribed level
can be achieved at the individual plant
level even under the most demanding
conditions through the application of
scrubbers together with sulfur reduction
credits.
Finally, UARG's petition (p. 15) states
that the final standard was biased by an
error in the preamble (see table, 44 FR
33592) which incorrectly referred to
certain FGD removal efficiencies as
"averages" rather than as geometric
"means" (medians). These removal
efficiencies were properly referred to as
"means" in the EPA test reports. This
discrepancy had no bearing on EPA's
decision to promulgate a 90 percent SOS
standard. Even though UARG claims a
bias was introduced, their consultant's
report states (see Appendix B, Page 46):
Therefore, even though EPA mistakenly
used the term "average SOt removal" in the
promulgation, it it obvious that when the
phrase "mean FGD efficiency" is used, EPA is
correctly referred to the mean (or median) of
the long-normal distribution of (1-eff).
Thus, even though Entropy (UARG's
consultant which prepared their
statistical analysis in Appendix B)
"discovered a discrepancy" as UARG
alleges, they did not reach a conclusion
as UARG has done, that a simple
transcription error in preparation of the
preamble undermined the credibility of
EPA's analysis of the test data. In fact,
the analysis of test data performed by
EPA (OAQPS-78-1,0-B-4) used correct
statistical terminology.
The Sierra Club also submitted a
petition that questioned the promulgated
90 percent, 30-day rolling average
standard. The petition asks "why the
final percentage of removal for 'full
scrubbing' was set at only 90 percent for
a 30-day average" in view of the
preamble to the proposal which
mentions a 92 percent reduction (43 FR
42159). The petition states that "EPA
indicated that 85 percent scrubbing on a
24-hour average was equivalent to 92
percent on a 30-day average." This
statement is a misquotation. The
preamble actually stated that "an FGD
system that could achieve a 92 percent
long-term (30 days or more) mean SO»
removal would comply with the
proposed 85 percent (24-hour average)
requirement." The long-term mean
referred to is the median value
(geometric mean) of FGD system
performance, not an equivalent
standard. Reference in the preamble
was made to the background
information supplement (OAQPS-78-1,
III-B-4) which provided "a more
detailed discussion of these findings."
The 92 percent removal is described
therein as the median (geometric mean)
of the statistical distribution defined by
the "line of improved performance" in
Figure 4-1. A median is the middle
number in a given sequence of numbers.
Thus for a sequence of 24-hour or 30-day
rolling average efficiencies, the median
SOt removal (92 percent) is a level at
which one-half of the 30-day rolling
average FGD system efficiencies would
be higher and one-half would be lower.
Since one-half of the expected removal
efficiencies would be lower than the 92
percent median, a standard could not be
set at that level. The standard must
recognize the range of 30-day rolling
average FGD efficiencies that would be
expected. The petition is based upon a
misconception as to the meaning of the
92 percent value (a median) and is
therefore not new information of central
relevance to this issue.
The Environmental Defense Fund
requested that EPA consider the
relevance of the lime/limestone-adipic
acid tests at Shawnee to this
rulemaking. Adipic acid has been found
to increase FGD system performance by
limiting the drop in pH that normally
occurs at the gas/liquid interface during
SOi absorption. Test runs at Shawnee
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showed increased FGD performance (in
one test series the efficiency increased
from 71 percent to 93 percent) with no
apparent adverse impact upon FGD
system operation.
EPA agrees that use of adipic acid
additive in lime/limestone scrubbing
solutions appears very promising and is
currently planning a full-scale FGD
system demonstration. Several
important areas are to be evaluated in
the EPA test program. The handling and
disposal characteristics of waste sludges
from the scrubber must be evaluated to
see that adipic acid does not affect
control of leachates into groundwater. In
addition, the consumption rate of adipic
acid by the FGD system and its ultimate
disposition must be evaluated.
Furthermore, tests must be conducted to
show whether or not the concentration
of adipic acid in FGD system sludge
poses significant environmental
problems. In the absence of such data,
EPA does not believe it prudent to
include adipic acid as a basis for the
current revised standard.
IV. Particulate Matter Standards
Only one of the four petitions for
reconsideration raised issues concerning
the particulate matter standard. In their
petition, the Utility Air Regulatory
Group (UARG) argued principally that
baghouse technology was not
demonstrated on large coal-fired utility
boilers and that the 13 ng/J (0.03 lb/
million Btu) heat input standard could
not be achieved at reasonable costs
with electrostatic precipitators on low-
sulfur coal applications. They also noted
that emission test data on a 350 MW
baghouse application was placed in the
record after the close of the comment
period. In response to these data, UARG
presented operating information on
baghouse systems obtained from two
coal-fired installations. In addition they
restated arguments that had been raised
in their January 1979 comments
concerning EPA's data base and the
potential effects of NO, and SO,
emission control on particulate
emissions.
In reaching his decision that baghouse
technology is adequately demonstrated,
the Administrator took into account a
number of factors. In addition to the
emission test data and other technical
information contained in the record, he
placed significant weight on the fact that
at least 26 baghouse-equipped coal-fired
electric utility steam generators were
operating prior to promulgation of the
standard and that 28 additional units
were planned to start operation by the
end of 1982. He also noted that some of
the utility companies operating
baghouses on coal-fired steam
generators were ordering more
baghouses and that none of them had
announced plans to decommission or
retrofit a baghouse controlled plant
because of operating or cost problems.
The Administrator believed that this
was a strong indication that some
segments of the utility industry believe
that baghouses are practical,
economical, and adequately
demonstrated systems for control of
particulate emissions. These electric
utility baghouses are being applied to a
wide range of sizes of steam generators
and to coals of varying rank and sulfur
content. The Industrial Gas Cleaning
Institute speaking for the manufacturers
of baghouses submitted comments
(OAQPS-78-1, IV-D-247) confirming
that baghouses are adequately
demonstrated systems for control of
particulate emissions from coal-fired
steam-electric generators of all sizes and
types.
In the proposal, EPA acknowledged
that large baghouses of the size that
would typically be used to meet the
standard had only been recently
activated. Further, the Agency
announced that it planned to test a 350
MW unit (43 FR 42169, center column).
The validated test data from this unit,
located at the Harrington Station,
demonstrated that the standard could be
achieved at large facilities (OAQPS-78-
1, V-B-1, page 4-1). The Agency also
became aware that the operators of the
facility were encountering start-up
problems. After carefully evaluating the
situation, the Agency concluded that the
problems were temporary in nature (44
FR 33585, left column).
Furthermore, Appendix E of the
UARG petition supports the Agency
finding. According to Appendix E, the
start-up problems experienced at
Harrington Station (Unit #2} have not
affected unit availability nor have they
altered the utility's plans for equipping
another large coal-fired steam generator
at the site (Unit #3) with a baghouse.
Appendix E noted, "The company feels
that the baghouse achieved an
availability equal to that of the
electrostatic precipitator installed in
unit 1" (UARG petition, Appendix E,
page 2). The Appendix also examined
two retrofit baghouse installations on
boilers firing Texas lignite at the
Monticello Station (Unit #1 and Unit
#2). While the first unit that came on
line experienced problems, Appendix E
notes, "Since the start-up of Unit 2 bag
filter, the baghouse has been operational
at all times the boiler was on line (due
to the solution of the majority of the
problems associated with Unit 1
baghouse)" (UARG petition, Appendix
E, page 5). These findings served to
reinforce the Agency's conclusion that
problems encountered at these initial
installations are correctible.
Based on the Harrington and
Monticello experience, UARG
maintained that EPA did not properly
consider the cost of activating and
maintairiing a baghouse. Contrary to
UARG's position, the cost estimates
developed by EPA provide liberal
allowances for start-up and continued
maintenancei For example, the Agency's
cost estimates for a baghouse for a 350
MW power plant provided over $1.4
million for start-up and first year
maintenance of which $440,000 was
included for bag replacement (OAQPS-
78-1, II-A-64 and VI-B-12). For
subsequent years, $710,000 per year was
allowed for routine maintenance of
which $440,000 was included for bag
replacement. In comparison, the UARG
petition indicated that bag replacement
costs during the first year of operation of
the baghouse at the Harrington Station
(350 MW capacity) would be $250,000
and the bag replacement costs at the
two Monticello baghouse units (610 MW
capacity total) would total about
$642,000. From the information provided
by UARG, it appears that the Agency
has fully accounted for any potential
costs that may be incurred during start-
up or annual maintenance.
UARG further maintained that higher
pressure drops encountered at these
initial installations would increase the
cost of power to operate a baghouse
beyond those estimated by the Agency.
The Administrator agrees that if higher
pressure drops are encountered an
increase in cost will be incurred.
However, even assuming that the
pressure drops initially experienced at
the Harrington and Monticello Stations
occur generally, the annual cost will not
increase sufficiently to affect the
Administrator's decision that the
standard can be achieved at a
reasonable cost. For example, the
increase in pressure drop reported by
UARG (UARG petition, page 43) at the
Harrington station would result in a cost
penalty of about $191,000 per year,
which represents only a 4.5 percent
increase in the total annualized
baghouse costs projected by EPA
(OAQPS-78-1, II-A-64, page 3-18) and
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less than one percent increase in
relation to utility operating costs. It
should be reported, however, that as a
result of corrective measures taken at
Harrington station since start-up, the
operating pressure drop reported by
UARG has been reduced. If the pressure
drop stabilizes at this improved level 2
kilopascals (8 inches H2O) rather than
the 2.75 kilopascals (11 inches H2O)
suggested by UARG the $191.000 cost
penalty would be reduced by some
$90,000 per year (OAQPS-7&-1, VI-B-11
and UARG petition, page 43).
UARG also maintained that a period
longer than 180 days after start-up is
required to shake down new baghouse
installations, and that EPA should
amend 40 CFR 60.8, which requires
compliance to be demonstrated within
180 days of start-up. UARG based these
comments on the experience at the
Harrington and Monticello Stations. It is
important to understand that 40 CFR
60.8 only requires compliance with the
emission standards within 180 days of
start-up and does not require, or even
suggest, that the operation of the facility
be optimized within that time period.
Optimization of a system is a continual
process based on experience gained
with time. On the other hand, a system
may be fully capable of compliance with
the standard before it is fully optimized.
In the case of the Harrington station
the initial performance test was
conducted by the utility during October
1978 (which was within four months of
start-up). The initial test and a
subsequent one were found however, to
be invalid due to testing errors and
therefore it was February 1979 before
valid test results were obtained for the
Harrington Unit (OAQPS-78-1, IV-B-1,
page 42). This test clearly demonstrated
achievement of the 13 ng/J (0.03 lb/
million Btu) heat input emission level.
These results were obtained even
though the unit was still undergoing
operation and maintenance refinements.
With respect to the Monticello station.
UARG reported that no actual
performance test data are available
(UARG petition, Appendix E, page 6).
UARG also maintained that
baghouses are not suitable for peaking
units because of the high energy penalty
associated with keeping the baghouse
above the dew point. EPA recognizes
that baghouses may not be the best
control device for all applications. In
those instances where high energy
penalties may be incurred in heating the
baghouse above the dew point, the
utility would have the option of
employing an electrostatic precipitator.
However, some utilities will be using
bughouses for peaking units. For
example, the baghouse control system
on four subbituminous, pulverized coal-
fired boilers at the Kramer Station have
been equipped with baghouse preheat
systems and that station will be placed
in peaking service in the near future
(OAQPS-78-1, VI-B-10).
UARG also argued that it may be
necessary to install a by-pass system in
conjunction with a baghouse to protect
the baghouse from damage during
certain operation modes. The use of
such a system during periods of start-up,
shutdown, or malfunction is allowed by
the standard when in keeping with good
operating practice.
The UARG petition implied that the
test data base for electrostatic
precipitator systems (ESP) is inadequate
for determining that such systems can
meet the standard. Contrary to UARG's
position, the EPA data base for the
standard included test data obtained
under worst-case conditions, such as (1)
when high resistivity ash was being
collected, (2) during sootblowing, and (3)
when no additives to enhance ESP
performance were used (OAQPS-78-1,
1II-B-1, page 4-11 and 4-12). Even when
all of the foregoing worst-case
conditions were incurred
simultaneously, particulate matter
emission levels were still less than the
standard. It should also be understood
that none of the ESP systems tested
were larger than the model sizes used
for estimating the cost of control under
worst-case conditions.
The UARG petition also questioned
the Administrator's reasoning in failing
to evaluate the economic impact of
applying a 197 square meter per actual
cubic meter per second (1000 ft 2/1000
ACFM) cold-side ESP to achieve the
standard under adverse conditions such
as when firing low-sulfur coal. The
Administrator did not evaluate the
economic impact of applying a large.
cold-side ESP because a smaller, less
costly 128 square meter per actual cubic
meter per second (650 ft J/1000 ACFM)
hot-side ESP would typically be used.
The Administrator believed that it
would ha\e been non-productive to
investigate the economics of a cold-side
ESP when a hot-side ESP would achieve
the same level of emission control at a
lower cost.
The UARG petition also suggested
that hot-side ESP's are not always the
best choice for low-sulfur coal
applications. The Administrator agrees
with this position. In some case, low-
sulfur coals produce an ash which is
relatively easy to collect since flyash
resistivity is not a problem. Under such
conditions it would be less costly to
apply a cold-side ESP and therefore it
would be the preferred approach.
However, when developing cost impacts
of the standard, the Agency focused on
typical low-sulfur coal applications
which represents worst case conditions,
and therefore assessed only hot-side
precipitators.
The UARG petition suggests that in
some cases the addition of chemical
additives to the flue gas may be required
to achieve the standard with ESPs, and
the Agency should have fully assessed
the environmental impact of using such
additives. The Administrator, after
assessing all available data, concluded
that the use of additives to improve ESP
performance would not be necessary
(OAQPS-78-1, III-B-1, page 4-11).
Therefore, it was not incumbent upon
EPA to account for the environmental
impact of the use of additives other than
to note that such additives could
increase SO3 or acid mist emissions. In
instances where a utility elects to
employ additives as a cost saving
measure, their potential effect on the
environment can be assessed on a case-
by-case basis during the new source
review process.
UARG also maintained that there are
special problems with some low-sulfur
coals that would preclude the use of hot-
side ESPs and attached Appendix F in
support of their position. Review of
Appendix F reveals that while the
author discussed certain problems
related to the application of hot-side
ESPs on some western low-sulfur coal,
he also set forth effective techniques for
resolving these problems. The author
concluded, "The evidence of more than
11 years of experience indicates that hot
precipitators are here to stay and very
likely their use on all types of coal will
increase."
UARG also argued that the data base
in support of the final particulate
standard for oil-fired steam generating
units was inadequate. The standard is
based on a number of studies of
particulate matter control for oil-fired
boilers. These studies were summarized
and referenced in the BID for the
proposed standard (OAQPS-78-1, III-B-
1, page 4-39). These earlier studies
(Control of Particulate Matter from Oil
Burners and Boilers. April 1976, EPA-
450/3-76-005; and Particulate Emission
Control Systems for Oil-fired Boilers.
December 1974, EPA-450/3-74-063)
support the conclusion that ESP control
systems are applicable to oil-fired steam
generators and that such emission
control systems can achieve the
standard. The achievability of the
standard was also confirmed by the
Hawaiian Electric Company, a firm that
would be significantly affected by the
standard since virtually all their new
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generating capacity will be oil-fired due
to their location. In their comments the
company indicated, "Hawaiian Electric
Company supports the standards as
proposed in so far as they impact upon
the electric utilities in Hawaii"
(OAQPS-78-1, IV-D-159).
UARG also argued that the
Administrator had little or no data upon
which to base a conclusion that the
particulate standard is achievable for
lignite-fired units. In making this
assertion, UARG failed to recognize that
the Agency had extensively analyzed
lignite-fired units in 1976 and concluded
that they could employ the same types
of control systems as those used for
other coal types (EPA-450/2-76-030a,
page 11-29). Additionally, review of the
literature and other sources revealed no
new data that would alter this finding
(Some of the data considered includes
OAQPS-78-1,11-I-59, H-I-312, and II-I-
322) and the Agency continues to
believe that the emission standards are
achievable when firing all types of coal
including lignite coal. UARG has not
provided any information during the
comment period or in their petition
which would suggest any unique
problems associated with the control of
particulate matter from lignite-fired
units.
The UARG petition alleged that the
Administrator did not take into account
the effect of NO, control in conjunction
with promulgation of the particulate
standard. In developing the NO,
standard, the Administrator assessed
the possibility that NO, controls may
increase ash combustibles and thereby
affect the mass and characteristics of
particulate emissions. The
Administrator concluded, however, that
the NO, standard can be achieved
without any increase in ash
combustibles or any significant change
in ash characteristics and therefore
there would be no impact on the
particulate standard (OAQPS-78-1, III-
B-2, page 6-14).
UARG also raised the issue of sulfate
carryover from the scrubber slurry and
its potential effect on particulate
emissions. EPA initially addressed this
issue at proposal and concluded that
with proper mist eliminator design and
maintenance, liquid entrainment can be
controlled to an acceptable level (43 FR
42170, left column). Since that time, no
new information has been presented
that would lead the Administrator to
reconsider that finding.
In summary, UARG failed to present
any new information on particulate
matter control that is centrally relevant
to the outcome of the rule.
V. NOx Standards
The Utility Air Regulatory Group
(UARG) sought reconsideration of the
NO, standards. They maintained that
the record did not support EPA's
findings that the final standards could
be achieved by all boiler types, on a
variety of coals, and on a continuous
basis without an unreasonable risk of
adverse side effects. In support of this
position, they argued that while EPA's
short-term emissions data provided
insight into NO, levels attainable by
utility boilers under specified conditions
during short-term periods, they did not
sufficiently support EPA's standards
based on continuous compliance.
Further, they maintained that the
continuous monitoring data relied on by
the Agency does not support the general
conclusions that all boiler types can
meet the standards on a variety of coals
under all operating conditions. They
also argued that the Agency failed to
collect or adequately analyze data on
the adverse side effects of low-NO,
operations. Finally, they contended that
vendor guarantees have been shown not
to support the revised standards. The
arguments presented in the petition
were discussed in detail in an
accompanying report prepared by
UARG's consultant.
In general, the UARG petition merely
reiterated comments submitted in
January 1979. Their arguments
concerning short-term test data, the
potential adverse side effects of low-
NO, operation, and manufacturer's
guarantees did not reflect new
information nor were they substantially
different from those presented earlier.
For example, in their petition, UARG
asserted that new information received
at the close of comment period revealed
that certain data EPA relied upon to
conclude that low-NO, operations do
not increase the emissions of polycyclic
organic matter (POM) are of
questionable validity (UARG petition,
page 56). This comment repeats the
position stated in UARG's January 15,
1979, submittal (OAQPS 7&-1, IV-D-«11.
attachmentKVB report, January 1979,
page 86). More importantly, UARG
failed to recognize that EPA did not rely
on the tests in question and that the
Agency noted in the BID for the
proposed standards (OAQPS-78-1. III-
B-2, page 6-12) that the data were
insufficient to draw any conclusion on
the effects of modern, low-NO, Babcock
and Wilcox burners on POM emissions.
Instead, EPA based its conclusions in
regard to POM on its finding that
combustion efficiency would not
decrease during low-NO, operation and
therefore, there would not be an
increase in POM emissions (43 FR 42171,
left column and OAQPS-78-1, III-B-2,
page 9-6).
Similarly, UARG did not present any
new data in regard to boiler tube
corrosion. They merely restated the
arguments they had raised in their
January 1979 comments which
questioned EPA's reliance on corrosion
test samples (coupons). EPA believes
that proper consideration has been
given to the corrosion issues and
substantial data exist to support the
Administrator's finding that the final
requirements are achievable without
any significant adverse side effect (44
FR 33602, left column). In addition,
UARG also maintained that the Agency
should explain why it dismissed the 190
ng/J (0.45 Ib/million Btu) heat input NO,
emission limit (44 FR 33602, right
column) applicable to power plants in
New Mexico. In dismissing the
recommendation that the Agency adopt
a 190 ng/J emission limit, the
Administrator noted that the only
support for such an emission limitation
was in the form of vendor guarantees.
In relation to vendor guarantees,
UARG maintained in their January
comments and reiterate in their petition
that EPA should not rely on vendor
guarantees as support for the revised
standards. EPA cannot subscribe to
UARG's narrow position. While vendor
guarantees alone would not provide a
sufficient basis for a new source
performance standard, EPA believes
that consideration of vendor guarantees
when supported by other findings is
appropriate. In this instance, the vendor
guarantees served to confirm EPA
findings that the boiler manufacturers
possess the requisite technology to
achieve the final emission limitations.
This approach was described by Foster
Wheeler in their January 3,1979, letter
to UARG, (OAQPS 78-1, IV-D-611,
attachmentKVB report, January 1979,
page 119) that states, "When a
government regulation, which has a
major effect on steam generator design,
is changed it is unreasonable to judge
the capability of a manufacturer to meet
the new regulation by evaluating
equipment designed for the older less
stringent regulation."
This observation is also germane to
the arguments raised by UARG with
respect to EPA data on short-term
emission tests and continuous
monitoring. In essence, UARG
maintained that the EPA data base was
inadequate because boilers designed
and operated to meet the old 300 ng/J
(0.7 Ib/million Btu) heat input limitation
under Subpart D have not been shown
to be in continuous compliance with the
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new standard under Subpart Da. While
this statement is true, these units, which
were designed and operated to meet the
old standard, incurred only five
exceedances of the new standards on a
monthly basis. Moreover, a review of
the available 34 months of continuous
monitoring data from six utility boilers
revealed that they all operated well
below the applicable standard (OAQPS-
78-1. V-B-1).
In addition, UARG argued that the
available continuous monitoring data
demonstrated that the Agency should
not have relied on short-term test data.
Citing Colstrip Units 1 and 2, they noted
that less than one-third of the 30-day
average emissions fell below the units'
performance test levels of 125 ng/J (0.29
Ib/million Btu) heat input and 165 ng/J
{0.38 Ib/million Btu) heat input,
respectively. They further maintained
that this had not been considered by the
Agency. In fact, the Administrator
recognized at the time of promulgation
that emission values obtained on short-
term tests could not be achieved
continuously because of potential
adverse side effects and therefore
established emission limits well above
the values measured by such tests (44
FR 42171, left column). In addition. EPA
took into account the emission
variability reflected by the available
continuous monitoring data when it
established a 30-day rolling average as
the basis of determining compliance in
the standards (44 FR 33586, left column).
UARG also maintained in their
petition that EPA should not rely on the
Colstrip continuous monitoring data
because it was obtained with uncertified
monitors. The Administrator recognized
that the Colstrip data should not be
relied on in absolute terms since
monitors were probably biased high by
approximately 10 percent (OAQPS 78-1,
III-B-2, page 5-7). EPA's analysis of
data revealed, however, that it would be
appropriate to use the data to draw
conclusions about variability in
emissions since the shortcoming of the
Colstrip monitors did not bias such
findings. This data together with data
obtained using certified continuous
monitors at five other facilities (OAQPS
78-1, V-B-1, page 5-3) and the results
from 30-day test programs (manual tests
performed about twice per day) at three
additional plants (OAQPS 78-1, 0-8-62
and II-B-70) enabled the Administrator
to conclude that emission variability
under low-NO, operating conditions
was small and therefore the prescribed
emission levels are achievable on a
continuous basis.
UARG argued that since the only
continuous monitoring data available
was obtained from boilers manufactured
by Combustion Engineering and on a
limited number of coal types, the
Agency did not have a sufficient basis
for finding that the standards can be
achieved by other manufacturers or
when other types of coals are burned.
The Administrator concluded after
reviewing all available information that
the other three major boiler
manufacturers can achieve the same
level of emission reduction as
Combustion Engineering with a similar
degree of emission variability (43 FR
42171, left column and 44 FR 33588,
middle column). This finding was
confirmed by statements submitted to
UARG and EPA by the other vendors
that their designs could achieve the final
standards, although they expressed
some concern about tube wastage
potential (OAQPS-78-1, UI-D-611,
attachment-KVB report, pages 116-121
and IV-D-30). EPA has considered tube
wastage (corrosion) throughout the
rulemaking and has determined that it
will not be a problem at the NO,
emission levels required by the
standards (44 FR 33602, left column).
With respect to different coal types, the
Agency concluded from its analysis of
available data that NO. emissions are
relatively insensitive to differing coal
characteristics and therefore other coal
types will not pose a compliance
problem (43 FR 42171, left column and
OAQPS-78-1, IV-B-24). UARG did not
submit any data to refute this finding.
UARG also argued that the continuous
monitoring data should have been
accompanied by data on boiler
operating conditions. EPA noted that the
data were collected during extended
periods representative of normal
operations and therefore it reflected all
operational transients that occurred. In
particular, at Colstrip units 1 and 2 more
than one full year of continuous
monitoring data was analyzed for each
unit. In view of this, EPA believes that
the data base accurately reflects the
degree of emission variability likely t*
be encountered under normal operating
conditions. UARG recognized this in
principle in their January 15 comments
(Part 4, page 15) when they stated that
"continuous monitors would measure all
variations in NO, emissions due to
operational transients, coal variability,
pollution control equipment degradation,
etc/-
In their petition, UARG restated their
January 1979 comments that EPA's
short-term test data were not
representative and therefore should not
serve as a basis for the standard. As
noted earlier, EPA did not rely
exclusively on short-term test data in
setting the final regulations. In addition,
contrary to the UARG claim, EPA
believes that the boiler test
configurations used to achieve low-NO,
operations reflect sound engineering
judgement and that the techniques
employed are applicable to modern
boilers. This is not to say that the boiler
manufacturers may not choose other
approaches such as low-NO, burners to
achieve the standards. While
recognizing that EPA's test program was
concentrated on boilers from one
manufacturer, sufficient data was
obtained on the other major
manufacturers' boilers to confirm the
Agency's finding that they would exhibit
similar emission characteristics (44 FR
33586, left column). Therefore, in the
absence of new information, the
Administrator has no basis to
reconsider his finding that the
prescribed emission limitations are
achievable on modern boilers produced
by all four major manufacturers.
VI. Emission Measurement and
Compliance Determination
The Utility Air Regulatory Group
(UARG) raised several issues pertaining
to the accuracy and reliability of
continuous monitors used to determine
compliance with the SOi and NO,
standards. UARG particularly
commented on the data from the
Conesville Station. In addition, they also
maintained that the sampling method for
particulates was flawed. With respect to
compliance determinations, UARG
maintained that the method for
calculating the 30-day rolling averages
should be changed so that emissions
before boiler outages are not included
since they might bias the results. In
addition, UARG argued that the
standards were flawed since EPA had
not included a statement as to how the
Agency would consider monitoring
accuracy in relation to compliance
determination. With the exception of the
method of calculating the 30-day rolling
average and the comments on the
Conesville station, the petition merely
reiterated comments submitted prior to
the close of the public comment period.
As to the reliability and durability of
continuous monitors, information in the
docket (OAQPS-78-1. D-A-88, IV-A-20.
IV-A-21, and IV-A-22) demonstrates
that on-site continuous monitoring
systems (CMS) are capable and have
operated on a long-term basis producing
data which meet or exceed the minimum
data requirements of the standards.
In reference to the Conesville project.
UARG questioned why EPA dismissed
the continuous monitoring results since
it was the only long-term monitoring
effort by EPA to gain instrument
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Register / Vol. 45, No. 26 / Wednesday, February 6, 1980 / Rules and Regulations
operating experience. UARG maintained
that this study showed monitor
degradation over time and that it was
representative of state-of-the-art
monitoring system performance. This
conclusion is erroneous. EPA does not
consider the Conesville project adequate
for drawing conclusions about monitor
reliability because of problems which
occurred during the project.
To begin with, UARG is incorrect in
suggesting that the goal of the project
was to obtain instrument operating
experience. The primary purpose of the
project was to obtain 90 days of
continuous monitoring data on FGD
system performance. Because of
intermittent operation of the steam
generator and the FGD system, this
objective could not be achieved. As the
end of the 90-day period approached, a
decision was made to extend the test
duration from three to six months. The
intermittent system operation continued.
As a result, when the FGD outages were
deleted from the total project time of six
months, the actual test duration was
similar to those at the Louisville,
Pittsburgh, and Chicago tests and did
not, therefore, represent an extended
test program.
EPA does not consider the Conesville
results to be representative of state-of-
the-art monitoring system performance.
Because of the intermittent operation
throughout the test period (OAQPS-78-
1, IV-A-19, page 2), it became obvious
that the goals of the program could not
be met. As a result, monitoring system
maintenance lapsed somewhat. For
example, an ineffective sample
conditioning system caused differences
in monitor and reference method results
(OAQPS-7&-1, IV-A-20, page 3-2). If the
EPA contractor had performed more
rigorous quality assurance procedures,
such as a repetition of the relative
accuracy tests after monitor
maintenance more useful results of the
monitor's performance would have been
obtained. Thus, the Conesville study re-
emphasized the need for periodic
comparisons of monitor and reference
method data and the inherent value of
sound quality assurance procedures.
The UARG petition suggested that the
standards incorporate a statement as to
how EPA will consider monitoring
system accuracy during compliance
determination. More specifically, UARG
recommended that EPA define an error
band for continuous monitoring data
and explicitly state that the Agency will
take no enforcement action if the data
fall within the range of the error band.
The Agency believes that such a
provision is inappropriate. Throughout
this rulemaking, EPA recognized the
need for continuous monitoring systems
to provide accurate and reproducible
data. EPA also recognized that the
accuracy of a CMS is affected by basic
design principals of the CMS and by
operating and maintenance procedures.
For these reasons, the standards require
that the monitors meet (1) published
performance specifications (40 CFR Part
60 Appendix B] and (2) a rigorous
quality assurance program after they are
installed at a source. The performance
specifications contain a relative
accuracy criterion which establishes an
acceptable combined limit for accuracy
and reproducibility for the monitoring
system. Following the performance test
of the CMS, the standards specify
quality assurance requirements with
respect to daily calibrations of the
instruments. As was noted in the
rulemaking (44 FR 33611, right column),
EPA has initiated laboratory and field
studies to further refine the performance
requirements for continuous monitors to
include periodic demonstration of
accuracy and reproducibility. In view of
the existing performance requirements
and EPA's program to further develop
quality assurance procedures, the
Administrator believes that the issue of
continuous monitoring system accuracy
was appropriately addressed. In doing
so, he recognized that any questions of
accuracy which may persist will have to
be assessed on a case-by-case basis.
The UARG petition also raised as an
issue the calculation of the 30-day
rolling average emission rate. UARG
maintained that the use of emission data
collected before a boiler outage may not
be representative of the control system
performance after the boiler resumes
operation. UARG indicated that boiler
outage could last from a few days to
several weeks and suggested that if an
outage extends for more than 15 days, a
new compliance period should be
initiated. UARG also suggested that if a
boiler outage is less than 15 days
duration and the performance of the
emission control system is significantly
improved following boiler start-up, a
new compliance period should be
initiated. UARG argued that the data
following start-up would be more
descriptive of the current system
performance and hence would provide a
better basis for enforcement.
A basic premise of this rulemaking
was that the standard should encourage
not only installation of best control
systems but also effective operating and
maintenance procedures (44 FR 33595
center column, 33601 right column, and
33597 right column). The 30-day rolling
average facilitates this objective. In
selecting this approach, the Agency
recognized that a 30-day average better
reflects the engineering realities of SO2
and NO, control systems since it affords
operators time to identify and respond
to problems that affect control system
efficiency. Daily enforcement (rolling
average) was specified in order to
encourage effective operating and
maintenance procedures. Under this
approach, any improvement in emission
control system performance following
start-up will be reflected in the
compliance calculation along with
efficiency degradations occurring before
the outage. Therefore, the 30-day rolling
average provides an accurate picture of
overall control system performance.
On the other hand, the UARG
suggestion would provide a distorted
description of system performance since
it would discount certain episodes of
poor control system performance. Thai
is, the system operator could allow the
control system to degrade and then shut-
down the boiler before a violation of the
standard occurred. After start-up and
any required maintenance, a new
compliance period would commence,
thereby excusing any excursions prior to
a shut-down. In addition, since a new
averaging period would be initiated the
Agency would be unable to enforce the
standard for the first 29 boiler operating
days after the boiler had resumed
operation. In the face of this potential
for circumvention of the standards, the
Administrator rejects the UARG
approach.
UARG also reiterated their previous
comments that EPA did not properly
consider the accuracy and precision of
Reference Method 5 for measuring
particulate concentrations at or below
13 ng/J (0.03 Ib/million Btu) heat input.
EPA has recognized throughout this
rulemaking that obtaining accurate and
precise measurements of very low
concentrations of particulate matter is
difficult. In view of this, detailed and
exacting procedures for the clean-up
and analyses of the sample probe, filter
holder, and the filter were specified in
Method 5 to assure accuracy in
determining the mass collected.
Additionally, EPA has required that the
sampling time be increased from 60
minutes to 120 minutes. This will
increase the total sample volume frcjm a
minimum of 30 dscf to 60 dscf, thus
increasing the total mass collected to
about 100 mg at a loading of 13 ng/J
(0.03 Ib/million Btu) heat input. EPA has
concluded that measurement of mass at
this level can be reproduced within ±10
percent.
UARG also maintained that less than
ideal sampling can cause particulate
emission measurements to be inaccurate
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and this has not been evaluated. EPA
has addressed the question of
determining representative locations
and the number of sampling points in
some detail in the reference methods
and appropriate subparts. These
procedures were designed to assure
accurate measurements. EPA has also
evaluated the effects of less than ideal
sampling locations and concluded that
generally the results would be biased
below actual emissions. Assessment of
the extent of possible biases in
measurement data, however, must be
made on a case-by-case basis.
UARG raised again the issue of acid
mist generated by the FGD system being
collected in the Reference Method 5
sample, therefore rendering the emission
limit unachievable. EPA has recognized
this problem throughout the rulemaking.
In response to the Agency's own
findings and the public comments, the
standards permit determination of
particulate emissions upstream of the
scrubber. In addition, EPA announced
that it is studying the effect of acid mist
on particulate collection and is
developing procedures to correct the
collected mass for the acid mist portion.
VII. Applicability of Standards
Sierra Pacific Power Company and
Idaho Power Company (collectively,
"Sierra Pacific") petitioned the
Administrator to reconsider the
definition of "affected facility," asking
that the applicability date of the
standards be established as the date of
promulgation rather than the date of
proposal. 40 CFR 60.40a provides:
(a) The affected facility to which this
subpart applies is each electric utility steam
generating unit:
* * *
(2) For which construction or modification
is commenced after September 18.1978.
September 19,1978, is the date on
which the proposed standard was
published in the Federal Register. EPA
based this definition on sections
lll(a}(2) and lll(b)(6)of the Act.
Section lll(a)(2) provides:
The term "new source" means any
stationary source, the construction or
modification of which is commenced after the
publication of regulations (or. if earlier,
proposed regulations) prescribing a standard
of performance under this section which will
be applicable to such source.
Section lll(b)(6) includes a similar
provision specifically drafted to govern
the applicability date of revised
standards for fossil-fuel burning sources
(of which this standard is the chief
example.) It provides:
Any new or modified fossil fuel-fired
stationary source which commences
construction prior to the date of publication
of the proposed revised standards shall not
be required to comply with such revised
standards.
Sierra Pacific does not dispute that
the Agency's definition of affected
facility complies with the literal terms of
sections lll(a)(2) and lll(b)(6). Sierra
Pacific maintains, however, that the
definition is unlawful, because the
standard was promulgated more than 6
months after the proposal, in violation of
sections lll(b)(l)(B) and 307(d)(10).
Section lll(b)(l)(B) provides that a
standard is to be promulgated within 90
days of its proposal. Section 307(d)(10)
allows the Administrator to extend
promulgation deadlines, such as the 90-
day deadline in section lll(b)(l)(B), to
up to 6 months after proposal. Sierra
Pacific argues that section lll(a)(2) does
not apply unless the deadlines in
sections lll(b)(l)(B) and 307(d)(10) are
met. In this case the final standard was
promulgated on June 11,1979, somewhat
less than 9 months after proposal. (It
was announced by the Administrator at
a press conference on May 25,1979, and
signed by him on June 1,1979.)
In the Administrator's view, the
applicability date is properly the date of
proposal. First, the plain language of
section lll(a)(2) provides that the
applicability date is the date of
proposal. Second, the legislative history
of section 111 shows that Congress did
not intend that the applicability date
should be the date of proposal only
where a standard was promulgated
within 90 days of proposal. Section
lll(a)(2) took its present form in the
conference committee bill that became
the 1970 Clean Air Act Amendments,
whereas the 90-day requirement came
from the Senate bill, and there is no
indication that Congress intended to link
these two provisions.2
Moreover, this interpretation
represents longstanding Agency
practice. Even where responding to
public comments delays promulgation
more than 90 days, or more than 6
months, after proposal, the applicability
dates of new source performance
standards are established as the date of
proposal. See 40 CFR Part 60, Subparts
D et seq.
Sierra Pacific argues that its position
has been adopted by EPA in
"analogous" circumstances under the
Clean Water Act. This is inaccurate.
Section 306 of the Clean Water Act
specifically provides that the date of
proposal of a new source standard is the
applicability date only if the standard is
promulgated within 120 days of proposal
(section 306(a)(2), (b)(l)(B)).
Sierra Pacific suggests that utilities
are "unfairly prejudiced" by the
applicability date, but does not submit
any information to support this claim. In
any event, there does not seem to be
"In any event, in the Administrator's view the 90-
day requirement in section lll(b)(l)(B) no longer
governs the promulgation or revision of new source
slanddrds. It has been replaced by procedures set
forth in section lll(f) enacted by the 1977
amendments.
IV-385
any substantial unfair prejudice. At the
time of proposal, the Administrator had
not decided whether a full or partial
control alternative should be adopted in
the final SOa standard. As a result, the
Administrator proposed the full control
alternative stating (43 FR 42154, center
column):
* * * the Clean Air Act provides that new
source performance standards apply from the
date they are proposed and it would be easier
for power plants that start construction
during the proposal period to scale down to
partial control than to scale up to full control
should the final standard differ from the
proposal.
In fact, the final SO8 standard was less
stringent than the proposed rule.
In this case, utilities were on notice on
September 19,1978, of the proposed
form of the standard, and that the
standard would apply to facilities
constructed after that date. In March
1979, it became clear to the Agency that
it would not be possible to respond to
all the public comments and promulgate
the final standards by March 19, as
required by the consent decree in Sierra
Club v. Costle, a suit brought to compel
promulgation of the standard. {The
comment period had only closed on
January 15; EPA had received over 625
comment letters, totalling about 6,000
pages, and the record amounted to over
21,000 pages.) The Agency promptly
contacted the other parties to Sierra
Club v. Costle, and all the parties jointly
filed a stipulation that the standand
should be signed by June 1 and that the
Administrator should not seek "any
further extensions of time." This
stipulation was well-publicized (see, for
example, 9 Environment Reporter
Current Developments 2246, March 30,
1979). Thus utilities such as Sierra
Pacific had reasonable assurance that
the standard would be signed by June 1,
as it was.
Even assuming, as Sierra Pacific does,
that section 111 required the standard to
be promulgated by March 19, utilities
had to wait only an additional period of
84 days to know the precise form of the
promulgated standard. This delay is not
substantial in light of the long lead times
required to build a utility boiler, and in
light of the fact that the pollution control
techniques required to comply with the
promulgated standard are substantially
the same as those required by the
proposed standard.
Sierra Pacific's proposal that the
applicability date be shifted to the date
of promulgation is also inconsistent with
Congress' clear desire that the revised
standard take effect promptly. See
section lll(b)(6).
In conclusion, Sierra Pacific has
submitted no new information, has not
shown that it has been prejudiced in any
way, and has simply presented an
argument that is incorrect as a matter of
law. Its objection is therefore not of
central relevance and its petition is
denied.
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Federal Register / Vol. 45. No. 67 / Friday, April 4,1980 / Rules and Regulations
ENVIRONMENTAL PROTECTION
AGENCY
40CFRPart60
[FRL1370-5]
Standards of Performance for New
Stationary Sources; Petroleum Liquid
Storage Vessels
AGENCY: Environmental Protection
Agency.
ACTION: Final rule.
SUMMARY: This regulation establishes
equipment standards which limit
emissions of volatile organic compounds
(VOC) from new, modified or
reconstructed petroleum liquid storage
vessels. The standards implement the
Clean Air Act and are based on the
Administrator's determination that
emissions from petroleum liquid storage
vessels contribute significantly to air
pollution. The intended effect of this
regulation is to require new, modified or
reconstructed petroleum liquid storage
vessels to use the best demonstrated
system of continuous emission reduction
considering costs and nonair quality
health, environmental and energy
impacts.
EFFECTIVE DATE: April 4,1980.
ADDRESSES: Docket No. OAQPS-78-2.
containing all supporting information
used by EPA in developing the
standards, is available for public
inspection and copying between 8 a.m.
and 4 p.m., Monday through Friday, at
EPA's Central Docket Section, Room
2903B, Waterside Mall, 401 M Street,
SW., Washington, D.C. 20460.
FOR FURTHER INFORMATION CONTACT:
Don R. Goodwin, Director, Emission
Standards and Engineering Divison
(MD-13), U.S. Environmental Protection
Agency, Research Triangle Park, North
Carolina 27711. telephone no. (919) 541-
5271.
SUPPLEMENTARY INFORMATION:
The Standards
The standards promulgated under
Subpart Ka require each new, modified
or reconstructed petroleum liquid
storage vessel of greater than 151,416
liters (40,000 gallons) capacity
containing a petroleum liquid with a true
vapor pressure greater than 10.3 kPa (1.5
psia) to be equipped with one of the
following:
1. An external floating roof fitted with
a double seal system between the tank
wall and the floating roof;
2. A fixed roof with an internal-
floating cover equipped with a seal
between the tank wall and the edge of
the coven
3. A vapor recovery and disposal or
return system which reduces VOC
emissions by at least 95 percent, by
weight; or
4. Any system which is demonstrated
to the Administrator to be equivalent to
those described above.
Each affected vessel storing a
petroleum liquid with a true vapor
pressure greater than 76.6 kPa (11.1 psia)
must be equipped with a vapor recovery
and disposal or return system, or
equivalent. Storage vessels of less than
1,589,800 liters (420,000 gallons) capacity
used for petroleum or condensate stored
prior to custody transfer are exempt
from the standards.
Many of the petroleum liquid storage
vessels covered by the standards are
likely to be in locations other than
petroleum refineries. If the storage
vessel contains petroleum or
condensate, or finished or intermediate
products manufactured at a petroleum
refinery, and the size and true vapor
pressure applicability criteria are met,
the vessel would be covered by the
standards regardless of its location. For
example, cyclohexane may be produced
at a petroleum refinery and then stored
at a chemical plant before being used in
the plant. The storage vessel at the
chemical plant would be covered by the
standards if its size and the true vapor
pressure of the cyclohexane are greater
than the cut-offs in the standards.
The regulation contains allowable
seal gap criteria based on gap surface
area per unit of storage vessel diameter.
The standards require owners or
operators to measure and report seal
gaps annually for the secondary seal
and every five years for the primary seal
for each affected storage vessel. The
standards also require owners or
operators to monitor and maintain
records of the petroleum liquid stored,
the period of storage, and the maximum
true vapor pressure of the petroleum
liquid during its storage period for each
affected storage vessel.
Several definitions and the monitoring
and record keeping requirements of
Subpart K have been revised to make
them consistent with those in Subpart
Ka. These revisions to Subpart K clarify
the regulation and make it less
burdensome for owners and operators
but do not affect the emission reductions
required by Subpart K.
The promulgated standards are in
terms of equipment specifications and
maintenance requirements rather than
mass emission rates. It is extremely
difficult to quantify mass emission rates
for petroleum liquid storage vessels
because of the varying loss mechanisms
and the number of variables affecting
loss rate. Section lll(h)(l) of the Act
provides that equipment standards may
be established for a source category if it
is not feasible to prescribe or enforce a
standard which specifies an emission
limitation.
Environmental and Economic Impact
Compliance with these standards will
reduce VOC emissions to the
atmosphere from petroleum liquid
storage vessels with external floating
roofs by about 75 percent. This estimate
is based on a comparison of VOC
emissions between storage vessels
equipped with external floating roofs
and single seals and storage vessels
equipped with any of the systems
required in the standards. The standards
will reduce VOC emissions by about
4,545 megagrams per year (5000 tons per
year) by 1985.
This emission reduction will be
realized without adverse impacts on
other aspects of environmental quality,
such as solid waste disposal, water
pollution, or noise. There will be no
adverse energy impacts associated with
the standards. In fact, energy savings
will result because the standards will
help prevent the loss of valuable
petroleum products. The economic
impact, of the standards is considered
reasonable. The cost of complying with
the standards will be only the
incremental cost of installing a
secondary seal. This will increase the
cost of a new 81-meter diameter storage
vessel, by about 0.6 to 1.3 percent. The
incremental capital costs will be about
$12,000 to $19,000, and the average
incremental annualized costs will vary
between $1,100 and $3,300 per storage
vessel depending on the true vapor
pressure of the petroleum liquid, the
average wind velocity, and the cost of
the petroleum liquid.
Public Participation
The Standards were proposed in the
Federal Register on May 18,1978 (43 FR
21615), To provide interested persons
the opportunity for oral presentation of
data, views, or arguments concerning
the proposed standards, a public hearing
was held on June 7,1978, in Washington,
D.C. In addition, during the public
comment period from May 18,1978, to
July 19,1978, a total of 35 comment
letters was received. These comments
have been carefully considered and,
where determined to be appropriate,
changes have been made in the final
regulation.
IV-386
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Significant Comments and Changes
Made
Comments were received from
industry representatives, utility
companies, and State and Federal
agencies. Most of the comment letters
contained multiple comments. The
comments have been divided into the
following areas for discussion: testing
and monitoring, technology, impacts,
and general.
Testing and Monitoring
Most of the comments concerned the
proposed requirements for inspecting
the seals on external floating roof
storage vessels. The proposed standards
required that inspection of the seals be
performed while the roof was floating.
They also required, however, that the
secondary seal be kept in place at all
times if the storage vessel contained a
petroleum liquid with true vapor
pressure greater than 10.3 kPa (1.5 psia).
This meant that if the secondary seal
would have to be dislodged or removed
to inspect the primary seal, the vessel
would have to be empted of petroleum
liquid and the roof raised with some
other liquid. The preamble suggested
using water to do this. Commenters
pointed out that the use of a liquid other
than a petroleum liquid would put the
storage vessel out of service for an
indefinite period, that water was
unavailable in many areas, and that
water, if used, would become
contaminated with petroleum liquids
which would have to be separated prior
to discharge.
EPA has determined that these
comments are valid and that the VOC
emissions occurring during the relatively
short inspection period would be
insignificant when compared to the
impact of using water as the test fluid.
Therefore, the final regulation allows the
removal of the secondary seal for the
inspection of the primary seal while the
storage vessel is in operation. Higher
emissions will, however, result from the
removal of the secondary seal. To
reduce this period of increased
emissions, the final standards require
inspection of the primary seal to be
performed as rapidly as possible and the
secondary seal replaced as soon as
possible.
Many commenters stated that seal gap
measurement at one level would provide
sufficient indication of seal integrity and
that the proposed requirement for
measuring at eight levels would be too
burdensome, expensive, and would
provide little, if any, additional
information. Most of these commenters
recommended measuring seal gaps at
the "as found" level. It is not clear
whether the benefits of the eight-level
gap measurement would outweigh the
adverse impacts. In addition, since the
final standards allow removal of the
secondary seal during measurement and
inspection of the primary seal, it is
important to minimize the amount of
time the secondary seal is not in place.
Reducing the number of required
measurement levels thus will help to
minimize the VOC emissions during
primary seal gap measurements.
Therefore; the final regulation requires
that seal gaps be measured at one level
with the stipulation that the roof be
floating off the roof leg supports. The
owner or operator is required to notify
EPA prior to gap measurement and
provide all of the results of such
measurements to EPA each time they
are performed
The proposed seal gap measurement
frequency of five years was criticized by
many commenters. Some claimed this to
be too frequent while two commenters
suggested performing gap measurements
during scheduled storage vessel
maintenance periods. Requiring seal gap
measurements only during scheduled
maintenance would not provide uniform
impacts on owners and operators. Those
with more frequent maintenance periods
would be required to measure seal gaps
more often than those with less frequent
maintenance periods. Therefore the
same measurement frequency is
required of all owners and operators
regardless of their maintenance
schedules. The promulgated standards
require a different frequency, however,
for the primary seal than for the
secondary seal. Data derived from tests
conducted by Chicago Bridge and Iron
Company (CBI) on a 20-foot diameter
test storage vessel clearly indicate that
secondary seal gaps increase VOC
emissions to a greater degree than gaps
in the primary seal. Because of its
greater sensitivity, a more frequent
inspection of the secondary seal is
considered necessary. Consequently, the
final regulation requires the secondary
seal gaps to be measured at initial fill
and at least once annually and the
primary seal gaps at initial fill and at
least once every five years. The
requirement for more frequent gap
measurements for secondary seals is not
expected to increase the impact of the
final standards in comparison to the
proposed standards. In fact, the impact
will be less because gap measurements
are required at only one roof level
instead of the proposed eight levels, and
they may be conducted without taking
the storage vessel out of service. If a
storage vessel is out of service {i.e.,
empty) for more than one year, gap
measurements must be conducted upon
refilling. This is considered necessary to
ensure that the seal system integrity has
not severely deteriorated during the
period of inactivity. The final regulation
therefore, defines such refilling as
"initial fill" and the required frequency
of gap measurements would be based
upon the date of refilling.
One commenter suggested requiring
visual seal inspections instead of seal
gap measurements. This approach was
considered but rejected because of the
inability to develop a visual inspection
procedure which could be applied
uniformly. The subjectiveness of such a
procedure would preclude the use of the
data that would be obtained.
The gap criteria by size classes
specified in the proposed regulation
were unfair, claimed two commenters,
and are not consistent with the CBI
data. As pointed out by one commenter,
a three-sixteenths inch gap around the
entire storage vessel would produce less
gap surface area than the proposed
standards allowed yet would be out of
compliance with the proposed gap
criteria. To eliminate this possibility, the
final regulation specifies total gap
surface area criteria specific to the
storage vessel diameter for the primary
and the secondary seal. Since the seal
gap surface area allowed in the final
standards is approximately equal to that
allowed in the proposed standards,
about the same VOC emission reduction
and cost of performing gap
measurements will result. The final
standards, however, will provide a more
effective and uniform procedure for
ensuring that seals are properly
installed and maintained.
Two commenters questioned the
apparently inflexible requirement in the
proposal Aat only pre-sized probes
were to be used for gap measurements.
As pointed out by one commenter, use
of an L-shaped probe, in some cases,
could eliminate the need to remove the
secondary seal when measuring gaps in
the primary seal. The secondary seal, in
many cases, could merely be pulled
back and the L-shaped probe inserted
for accurate gap determinations. Such
an approach may be reasonable, and
there may be other suitable methods for
measuring gaps. Therefore, the
regulation specifies one method of gap
measurement but includes provisions for
allowing other methods provided they
can be demonstrated to be equivalent.
According to four commenters, the
monitoring requirements specified in the
proposed rule were too burdensome and
were probably of little value. They also
pointed out problems with Reid vapor
pressure conversions and true vapor
pressure determinations in some cases.
TT7_ "> O -7
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Federal Register / Vol. 45, No. 67 / Friday, April 4, 1980 / Rules and Regulations
EPA agreed with this comment and has
re-evaluated the amount of monitoring
information needed to be able to ensure
that owners or operators of storage
vessels covered by the regulation are
complying with the standards. As a
result, the final regulation has been
revised to require that a record be kept
of the maximum true vapor pressure and
the periods of storage of each vessel's
contents. This maximum true vapor
pressure can be determined from
available data on the typical Reid vapor
pressure and the maximum expected
storage temperature. This precludes the
proposed requirement that an average
temperature record be kept. For any
crude oil with a true vapor pressure less
than 13.8 kPa (2.0 psia) or whose
physical properties preclude
determination by the recommended
methods, the true vapor pressure is to be
determined from available data and
recorded if the estimated true vapor
pressure is greater than 6.9 kPa (1.0
psia). The final regulation allows two
exemptions from the monitoring
requirements: (1) If the petroleum liquid
has a Reid vapor pressure less than 6.9
kPa (1.0 psia) and the true vapor
pressure will never exceed 6.9 kPa (1.0
psia) or (2) if the storage vessel is
equipped with a vapor return or disposal
system in accordance with the
requirements of the standard This
revision relieves much of the record
keeping and monitoring burden of the
proposed regulation but is not expected
to impact the amount of VOC emissions.
Two letters commented on the
requirement in the proposed standard
that there be four access points through
the secondary seal to the primary seal to
allow inspection while the storage
vessel is in operation. One commenter
said it was unnecessary while the other
commenter stated that the access points
should be chosen at random by the
inspector. Since the regulation has been
revised to allow removal of the
secondary seal for primary seal
inspections and gap measurements
while the vessel is in operation,
requiring the owner or operator to
provide four access points to the
primary seal is not necessary. Therefore,
this requirement has been deleted.
Technology
Seven commenters questioned the
validity of scaling up the CBI test vessel
data by linear extrapolation to Held size
storage vessels as was done to calculate
actual emission reductions. Many of
these commenters also believed that the
static test conditions were not
representative of dynamic field
conditions. These commenters
recommended awaiting results of the
American Petroleum Institute (API)
study of VOC emissions from petroleum
liquid storage vessels in actual field
conditions. Preliminary results of the
API study have been released, however,
and indicate that VOC emissions from
field storage vessels are directly
proportional to vessel diameter.
Therefore, the VOC emission estimates
based on CBI data are considered valid.
Four commenters stated that storage
vessels could not meet seal gap
specifications even if they met current
plumbness and roundness specifications
contained in API Standard 650 which is
used for construction standards for new
storage vessels. The out-of-plumbness
specification in API Standard 650 allows
V* percent of the height of the vessel and
the roundness specification is grouped
by vessel diameter as follows:
Storage Ve»Ml Diameter and Radius Tolerance
Inches
0 to 40 feet exclusive _,
40 to 1 SO feet exclusive..
150 to 250 leel exclusive..,
250 feet and over
±V4
±%
±1
Some of these commenters felt that
the construction tolerances would have
to be reduced considerably for primary
and secondary seals to maintain
compliance with the gap criteria at all
roof levels, thereby effecting a
significant economic impact of increased
construction costs which EPA failed to
consider. However, a compilation by
EPA of the California Air Resources
Board (GARB) petroleum liquid storage
vessel inspection reports showed that a
majority of existing welded vessels
inspected in California would have been
in compliance with the seal gap criteria
in both the proposed and final
regulations had these regulations been
in effect. Since the majority of those
tanks were found to be in compliance
with the seal gap standards, it is EPA's
judgement that all new petroleum liquid
storage vessel seals could meet the gap
standards. Therefore, EPA believes the
standards are attainable under present
construction standards.
In the proposed regulation, the
requirement that a vapor recovery and
return or disposal system be capable of
collecting and preventing the release of
all VOC vapors implied 100 percent
control efficiency, and four commenters
stated that this was impossible to
achieve. EPA did not intend to
necessarily require 100 percent control
but rather to require that the system be
properly designed, installed, and
operated. There are two parts to a vapor
recovery and return or disposal system.
The vapor recovery portion collects the
VOC vapors and gases from the storage
vessel and vents them to a control
device which then processes them by
either recovering them as product or
disposing of them. A properly designed
collection system would be capable of
collecting all the VOC vapors and gases
except when pressure relief vents on the
storage vessel roof would open and
release VOC emissions to the
atmosphere. The only time these vents
would open is during periods when the
emission control system is not operating
properly and VOC vapors are not being
vented to the control device, causing a
pressure buildup in the storage vessel.
Such an occurrence would be
considered a malfunction if it could not
be avoided through proper operation
and maintenance and, therefore, would
not cause the storage vessel to be out of
compliance with the standard.
Therefore, EPA considers the
requirement that the system "collect all
the vapors and gases discharged from
the storage vessel" to be achievable and
reasonable and has retained it hi the
final regulation. EPA agrees with the
commenters that the second part of the
system, the return or disposal portion, is
not likely to be able to achieve 100
percent control efficiency. It is generally
acknowledged, however, that greater
than 95 percent VOC emission reduction
can be achieved by at least two
commonly used types of vapor control
devices, thermal oxidation and carbon
adsorption. Therefore, the final
regulation requires that any vapor
recovery and return or disposal system
used to comply with the standard must
collect all the VOC vapors and gases
discharged from the storage vessel and
be capable of processing them so as to
reduce their emission to the atmosphere
by at least 95 percent by weight.
To enable EPA to determine
compliance with the requirements for
vapor recovery and return or disposal
systems, the regulation requires the
owner or operator to submit plans and
specifications for the system to EPA on
or before the date on which construction
of the storage vessel is commenced.
Owners and operators are encouraged
to provide this information as far in
advance as possible of commencing
construction.
One commenter suggested that the
section on "Equivalent Equipment" be
expanded to include the use of
innovative vapor control equipment
other than the three types specified in
the proposed standards. To encourage
innovation, an equivalency clause is
provided in the final regulation that
applies to all parts of the standards
provided no decrease in emission
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reduction will result and can be so
demonstrated. Determinations of
equivalency for VOC emission reduction
systems not specifically mentioned in
the regulation will generally be made by
comparing the VOC emissions from such
a source to the VOC emissions
calculated for an external floating roof
welded storage vessel with secondary
and primary seals according to
equations in API Bulletin 2517.
"Evaporation Loss from External
Floating Roof Tanks." February 1980.
There will probably be cases in which
determinations of equivalency cannot be
made through a strict comparison of
emission reduction, and these will be
based on sound engineering judgment
Therefore, the regulation requires that
any request for an equivalency
determination be accompanied by VOC
emission reduction data, if available,
and also by detailed equipment and
procedural specifications which would
enable a sound engineering judgment to
be made. In accordance with section
lll(h)(3) of the Clean Air Act. any
equivalency determination shall be
preceded by a notice in the Federal
Register and an opportunity for a public
hearing.
Non-metallic, resilient primary seals
were considered by four commenters to
be equivalent to metallic shoe seals. A
revaluation of available data, some of
which were received after issuance of
the proposed regulation, indicates that
various types of seals may provide
essentially the same degree of emission
reduction. The final regulation,
therefore, allows use of liquid-mounted,
foam-filled seals; liquid-mounted, liquid-
filled seals; or vapor-mounted, foam-
filled seals in addition to metallic shoe
seals as primary seals on external
floating roofs. Vapor-mounted seals,
however, are equivalent to the others
only when the gap area of vapor-
mounted seals is significantly less than
the gap area of the others. Therefore, the
final regulation requires more stringent
gap criteria for vapor-mounted primary
seals.
Several commenters recommended
exemption from the standards for
storage vessels involved in oil field and
production operations. Such vessels are
generally small, bolted, and equipped
with fixed roofs. This is to enable them
to be dismantled, transported and
reerected as needed. Therefore, to
comply with the standards, a new
production field vessel would have to be
equipped with either an internal floating
roof or a vapor recovery system.
Commenters provided information
which indicated that vapor recovery
would be very difficult and expensive
due to the remote location of many
vessels. One commenter also submitted
data to show that internal floating roofs
would generally not be cost-effective for
production vessels with capacities less
than 1,589,873 liters (420,000 gallons).
Therefore, the final regulation exempts
each storage vessel with a capacity of
less than 1,589,873 liters (420,000
gallons) used for petroleum or
condensate stored, processed, or treated
prior to custody transfer. This
exemption applies to storage between
the time that the petroleum liquid is
removed from the ground and the time
that custody of the petroleum liquid is
transferred from the well or producing
operations to the transportation
operations. If it is determined in the
future that VOC emissions from new
production field vessels smaller than
1,589,873 liters (420,000 gallons) are
significant, separate standards of
performance will be developed.
One commenter indicated that
internal non-contact floating roofs do
not reduce emissions to the same degree
as contact floating roofs and points out
that API Standard 650 recommends the
use of the contact type. EPA is
concerned about the difference in
emission control of these two types of
floating roofs although insufficient data
exist at present to justify a revision to
the standards for petroleum liquid
storage vessels. One type of non-contact
floating roof was tested at CBI and the
results were forwarded to EPA in late
1978. The results indicate that the roof
did not reduce emissions to the same
degree as a contact roof. However,
slight auxiliary equipment differences
such as different seals used with the
different roofs prohibit development of
valid conclusions. Therefore, more
information is necessary to determine if
the petroleum liquid storage vessels
standard should be revised.
Consequently, EPA is considering a
study specifically to determine
differences in VOC emission control of
these two types of internal floating
roofs.
Impacts
The proposed regulation specified that
the roof must be floating on the liquid at
all times except when the storage vessel
is completely emptied, during initial fill,
or performance tests. Three commenters
stated that the level of the liquid should
be allowed to go below the level where
the roof comes to rest on the roof leg
supports even if the vessel is not
completely emptied. This would avoid
the loss of working-capacity and, thus,
the need for more storage vessels. A
significant amount of VOC emissions,
however, would result upon refilling.
The intent of the regulation is to avoid
having a vapor space between the roof
and the petroleum liquid surface for
extended periods. The quantity of
petroleum liquid remaining in the
bottom of a storage vessel with the
floating roof on its leg supports asd the
time it remains in this condition
determines the amount of VOC
saturation of the vapor space and the
subsequent emissions upon refilling th»
storage vessel. It is therefore considered
beneficial to the environment for the
roof to be kept floating at all times
except when the tank is initially filled or
completely emptied and refilled for such
purposes as routine tank maintenance,
inspections, petroleum liquid deliveries,
or transfer operations. Therefore, the
final regulation requires that the roof be
floating on the liquid at all times except
during initial fill and when the vessel is
completely emptied and refilled. To
minimize the amount of time the
petroleum liquid remains in the storage
vessel while the roof is resting on the
roof leg supports, the final regulation
also requires that the process of
emptying and refilling be performed as
rapidly as possible.
As mentioned before, the proposed
regulation did not require the roof to be
floating on the petroleum liquid during
performance tests. This exemption was
needed since the proposal required that
gap measurements be conducted with a
liquid other than a petroleum liquid in
the storage vessel (the preamble
suggested using water). Therefore, the
storage vessel would have had to be
emptied and the roof re-floated on the
non-petroleum liquid. Since the final
regulation allows gap measurements to
be conducted while the vessel contains
petroleum liquid, this exemption has
been removed.
General
It was pointed out by two commenters
that because the proposed regulation
stated that a secondary seal gap would
exist only if the probe touched the
primary seal, gaps in the same location
in the primary seal and the secondary
seal would not be allowed. The
proposed regulation stated that "a gap is
deemed to exist under the following
conditions: * * * for a secondary seal,
the probe is to touch the primary seal
without forcing." This erroneously
implied that a secondary seal gap would
not exist should the probe be able to
pass between the secondary and
primary seals and the tank wall and
touch the liquid surface. These
commenters concluded that EPA
intended to regulate not only the size
and area of seal gaps but also their
locations in each seal. This was not the
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Federal Register / Vol. 45, No. 67 / Friday, April 4, 1980 / Rules and Regulations
intent of the proposed regulation. The
final regulation eliminates this
ambiguity and redefines "gaps" as those
places where a uniform one-eighth inch
diameter probe passes freely between
the seal and the tank wall
Two commenters stated that a person
walking on an external floating roof
could alter gap configuration and would
pose a safety hazard because the roof
could possibly sink. Three commenters
felt that a fire hazard would be created
by the vapor that would become trapped
between the primary and secondary
seals. These comments were expressed
as opinions without any supporting data
or information. Since no such incidents
have been reported to EPA, and since
external floating roofs with double seals
are commonly used and apparently
operating safely even during
inspections, it is EPA's judgement that
the standards will not create either of
these hazards. A person walking on an
external floating roof should not cause
significant gap alterations since these
roofs are designed and built for this
purpose. Any small gap alteration
should not affect compliance status of
seal gaps since the allowable gap
criteria are based on total surface area
of all gaps.
The term "hydrocarbon" has been
changed to "volatile organic compounds
(VOC)" in the final regulation. This
change in terminology is consistent with
current EPA policy concerning
compounds which react
photochemically in the atmosphere to
form ozone. Reference has been made in
the past to "organic solvents,"
"thinners," and "hydrocarbons," in
addition to "VOC" to represent these
compounds. Some organics which are
ozone precursors are not hydrocarbons
in the strictest definition and are not
always used as solvents. Therefore, all
reference to emissions and emission
reduction in the standards refer to the
organic compounds which are ozone
precursors and have been designated
VOC.
Docket
The docket is an organized and
complete file of all the information
submitted to or otherwise considered by
the Administrator in the development of
this rulemaking. The docketing system is
intended to allow members of the public
and industries involved to readily
identify and locate documents so that
they can intelligently and effectively
participate in the rulemaking process.
Along with the statement of basis and
purpose of the promulgated rule and
EPA responses to significant comments,
the contents of the docket will serve as
the record in case of judicial review.
Miscellaneous
The effective date of this regulation is
April 4.1980. Section 111 of the Clean
Air Act provides that standards of
performance become effective upon
promulgation and apply to affected
facilities, construction or modification of
which was commenced after the date of
proposal (May 18,1978).
EPA will review this regulation four
years from the date of promulgation.
This review will include an assessment
of such factors as the need for
integration with other programs, the
existence of alternative methods.
enforceability, and improvements in
emission control technology.
It should be noted that standards of
performance for new stationary sources
established under section 111 of the
Clean Air Act reflect
* * * Application of the best technological
system of continuous emission reduction
which (taking into consideration the cost of
achieving such emission reduction, any non
air quality health and environmental impact
and energy requirements) the Administrator
determines has been adequately
demonstrated (section lll(a)(l)).
Although there may be emission
control technology available that can
reduce emissions below those levels
required to comply with standards of
performance, this technology might not
be selected as the basis of standards of
performance due to costs associated
with its use. Accordingly, standards of
performance should not be viewed as
the ultimate in achievable emission
control. In fact, the Act requries (or has
the potential for requiring) the
imposition of a more stringent emission
standard in several situations.
For example, applicable costs do not
play as prominent a role in determining
the "lowest achievable emission rate"
for new or modified sources locating in
nonattainment areas, i.e., those areas
where statutorily-mandated health and
welfare standards are being violated. In
this respect, section 173 of the Act
requires that a new or modified source
constructed in an area which exceeds
the National Ambient Air Quality
Standard (NAAQS) must reduce
emissions to the level which reflects the
"lowest achievable emission rate"
(LAER), as defined in section 171(3), for
such category of source. The statute
defines LAER as that rate of emissions
based on the following, whichever is
more stringent:
(A) The most stringent emission limitation
which is contained in the implementation
plan of any State for such class or category of
source, unless the owner or operator of the
proposed source demonstrates that such
limitations are not achievable, or
(B) The most stringent emission limitation
which is achieved in practice by such class or
category of source.
In no event can the emission rate
exceed any applicable new source
performance standard (section 171(3)).
A similar situation may arise under
the prevention of significant
deterioration of air quality provisions of
the Act (Part C). These provisions
require that certain sources [referred to
in section 169(1)] employ "best available
control technology" (BACT) as defined
in section 169(3) for all pollutants
regulated under the Act Best available
control technology must be determined
on a case-by-case basis, taking energy,
environmental and economic impacts,
and other costs into account. In no event
may lie application of BACT result in
emissions of any pollutants which will
exceed the emissions allowed by any
applicable standard established
pursuant to section 111 (or 112) of the
Act.
In all events. State implementation
plans (SIP's) approved or promulgated
under section 110 of the Act must
provide for the attainment and
maintenance of National Ambient Air
Quality Standards designed to protect
public health and welfare. For this
purpose, SIP's must in some cases
require greater emission reductions than
those required by standards of
performance for new sources.
Finally, States are free .under section
116 of the Act to establish even more
stringent emission limits than those
established under section 111 or those
necessary to attain or maintain the
NAAQS under section 110. Accordingly,
new sources may in some cases be
subject to limitations more stringent
than EPA's standards of performance
under section 111, and prospective
owners and operators of new sources
should be aware of this possibility in
planning for such facilities.
Section 317 of the Clean Air Act
requires the Administrator to prepare an
economic impact assessment for
revisions of standards of performance
which the Administrator determines to
be substantial. An economic impact
assessment has been prepared and is
included in the docket All the
information in the economic impact
assessment was considered in
determining the cost of these standards.
Dated: March 28.1980.
Douglas M Cootie,
A dminis trator.
40 CFR Part 60 is amended by revising
§ 60.11(a); the heading of Subpart K;
§ 60.110(c)(l) and (c)(2); § 60.111(b) and
(c); the heading of 5 60.112; § 60.113; and
by adding a new Subpart Ka as follows:
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1. Paragraph [a] of § 60.11 is revised to
read as follows:
§ 60.11 Compliance with standards and
maintenance requirements.
(a) Compliance with standards in this
part, other than opacity standards, shall
be determined only by performance
tests established by § 60.8, unless
otherwise specified in the applicable
standard.
*****
2. The heading for subpart K is revised
to read as follows:
Subpart KStandards of Performance
for Storage Vessels for Petroleum
Liquids Constructed After June 11,
1973 and Prior to May 19,1978
3. Paragraphs (c)(l) and (c)(2) of
§ 60.110 of Subpart K are revised to read
as follows:
§ 60.110 Applicability and designation of
affected facility.
*****
(c) * * *
(1) Has a capacity greater than 151,
416 liters (40,000 gallons), but not
exceeding 246,052 liters (65,000 gallons),
and commences construction or
modification after March 8,1974, and
prior to May 19,1978.
(2) Has a capacity greater than 246,052
liters (65,000 gallons) and commences
construction or modification after June
11,1973, and prior to May 19,1978.
*****
4. Paragraphs (b) and (c) of § 60.111 of
Subpart K are revised to read as
follows:
§60.111 Definitions.
*****
(b) "Petroleum liquids" means
petroleum, condensate, and any finished
or intermediate products manufactured
in a petroleum refinery but does not
mean Nos. 2 through 6 fuel oils as
specified in ASTM-D-396-78, gas
turbine fuel oils Nos. 2-GT through 4-
GT as specified in ASTM-D-2880-78, or
diesel fuel oils Nos. 2-D and 4-D as
specified in ASTM-D-97578.
(c) "Petroleum refinery" means each
facility engaged in producing gasoline,
kerosene, distillate fuel oils, residual
fuel oils, lubricants, or other products
through distillation of petroleum or
through redistillation, cracking,
extracting, or reforming of unfinished
petroleum derivatives.
*****
5. The heading of § 60.112 of Subpart
K is revised to read as follows:
S 60.112 Standard for volatile organic
compounds (VOC).
6. Section 60.113 of Subpart K is
revised to read as follows:
§ 60.113 Monitoring of operations.
(a) Except as provided in paragraph
(d) of this section, the owner or operator
subject to this subpart shall maintain a
record of the petroleum liquid stored,
the period of storage, and the maximum
true vapor pressure of that liquid during
the respective storage period.
(b) Available data on the typical Reid
vapor pressure and the maximum
expected storage temperature of the
stored product may be used to
determine the maximum true vapor
pressure from nomographs contained in
API Bulletin 2517, unless the
Administrator specifically requests that
the liquid be sampled, the actual storage
temperature determined, and the Reid
vapor pressure determined from the
sample(s).
(c) The true vapor pressure of each
type of crude oil with a Reid vapor
pressure less than 13.8 kPa (2.0 psia) or
whose physical properties preclude
determination by the recommended
method is to be determined from
available data and recorded if the
estimated true vapor pressure is greater
than 6.9 kPa (1.0 psia).
(d) The following are exempt from the
requirements of this section:
(1) Each owner or operator of each
affected facility which stores petroleum
liquids with a Reid vapor pressure of
less than 6.9 kPa (1.0 psia) provided the
maximum true vapor pressure does not
exceed 6.9 kPa (1.0 psia).
(2) Each owner or operator of each
affected facility equipped with a vapor
recovery and return or disposal system
in accordance with the requirements of
S 60.112.
7. A new Subpart Ka is added to read
as follows:
Subpart KaStandards of Performance for
Storage vessels for Petroleum Liquids
Constructed After May 18,1978
Sec.
GO.llOa Applicability and designation of
affected facility.
60.1113 Definitions.
60.112a Standard for volatile organic
compounds (VOC).
60.113a Testing and procedures.
60.114a Equivalent equipment and
procedures.
60.115a Monitoring of operations.
Authority: Sec. Ill, 301 (a) of the Clean Air
Act as amended (42 U.S.C. 7411, 7601 (a)}, and
additional authority as noted below.
Subpart KaStandards of
Performance for Storage Vessels for
Petroleum Liquids Constructed After
May 18,1978
§ 60.110a Applicability and designation of
affected facility.
(a) Except as provided in paragraph
(b) of this section, the affected facility to
which this subpart applies is each
storage vessel for petroleum liquids
which has a storage capacity greater
than 151,416 liters (40,000 gallons) and
for which construction is commenced
after May 18,197&
(b) Each petroleum liquid storage
vessel with a capacity of less than
1,589,873 liters (420,000 gallons) used for
petroleum or condensate stored,
processed, or treated prior to custody
transfer is not an affected facility and,
therefore, is exempt from the
requirements of this subpart
§60.11 la Definitions.
In addition to the terms and their
definitions listed in the Act and Subpart
A of this part the following definitions
apply in this subpart:
(a) "Storage vessel" means each tank,
reservoir, or container used for the
storage of petroleum liquids, but does
not include:
(1) Pressure vessels which are
designed to operate in excess of 204.9
kPa (15 psig) without emissions to the
atmosphere except under emergency
conditions.
(2) Subsurface caverns or porous rock
reservoirs, or
(3) Underground tanks if the total
volume of petroleum liquids added to
and taken from a tank annually does not
exceed twice the volume of the tank.
(b) "Petroleum liquids" means
petroleum, condensate, and any finished
or intermediate products manufactured
in a petroleum refinery but does not
mean Nos. 2 through 6 fuel oils as '
specified in ASTM-D-396-78, gas
turbine fuel oils Nos. 2-GT through 4-
GT as specified in ASTM-D-2880-78, or
diesel fuel oils Nos. 2-D and 4-D as
specified in ASTM-D-975-78.
(c) "Petroleum refinery" means each
facility engaged hi producing gasoline,
kerosene, distillate fuel oils, residual
fuel oils, lubricants, or other products
through distillation of petroleum or
through redistillation, cracking,
extracting, or reforming of unfinished
petroleum derivatives.
(d) "Petroleum" means the crude oil
removed from the earth and the oils
derived from tar sands, shale, and coal.
(e) "Condensate" means hydrocarbon
liquid separated from natural gas which
condenses due to changes in the
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temperature or pressure, or both, and
remains liquid at standard conditions.
(f) "True vapor pressure" means the
equilibrium partial pressure exerted by
a petroleum liquid such as determined in
accordance with methods described in
American Petroleum Institute Bulletin
2517, Evaporation Loss from Floating
Roof Tanks, 1962.
(g) "Reid vapor pressure" is the
absolute vapor pressure of volatile
crude oil and volatile non-viscous
petroleum liquids, except liquified
petroleum gases, as determined by
ASTM-D-323-58 (reapproved 1968).
(h) "Liquid-mounted seal" means a
foam or liquid-filled primary seal
mounted in contact with the liquid
between the tank wall and the floating
roof continuously around the
circumference of the tank.
(i) "Metallic shoe seal" includes but is
not limited to a metal sheet held
vertically against the tank wall by
springs or weighted levers and is
connected by braces to the floating roof.
A flexible coated fabric [envelope)
spans the annular space between the
metal sheet and the floating roof.
(j) "Vapor-mounted seal" means a
foam-filled primary seal mounted
continuously around the circumference
of the tank so there is an annular vapor
space underneath the seal. The annular
vapor space is bounded by the bottom of
the primary seal, the tank wall, the
liquid surface, and the floating roof.
(k) "Custody transfer" means the
transfer of produced petroleum and/or
condensate, after processing and/or
treating in the producing operations,
from storage tanks or automatic transfer
facilities to pipelines or any other forms
of transportation.
§ 60.112a Standard for volatile organic
compounds (VOC).
(a) The owner or operator of each
storage vessel to which this subpart
applies which contains a petroleum
liquid which, as stored, has a true vapor
pressure equal to or greater than 10.3
kPa (1.5 psia) but not greater than 76.6
kPa (11.1 psia) shall equip the storage
vessel with one of the following:
(1) An external floating roof,
consisting of a pontoon-type or double-
deck-type cover that rests on the surface
of the liquid contents and is equipped
with a closure device between the tank
wall and the roof edge. Except as
provided in paragraph (a)(l)(ii)(D) of
this section, the closure device is to
consist of two seals, one above the
other. The lower seal is referred to as
the primary seal and the upper seal is
referred to as the secondary seal. The
roof is to be floating on the liquid at all
times (i.e., off the roof leg supports)
except during initial fill and when the
tank is completely emptied and
subsequently refilled. The process of
emptying and refilling when the roof is
resting on the leg supports shall be
continuous and shall be accomplished
as rapidly as possible.
(i) The primary seal is to be either a
metallic shoe seal, a liquid-mounted
seal, or a vapor-mounted seal. Each seal
is to meet the following requirements:
(A) The accumulated area of gaps
between the tank wall and the metallic
shoe seal or the liquid-mounted seal
shall not exceed 212 cm* per meter of
tank diameter (10.0 in *per ft of tank
diameter) and the width of any portion
of any gap shall not exceed 3.81 cm (1%
in).
(B) The accumulated area of gaps
between the tank wall and the vapor-
mounted seal shall not exceed 21.2 cm*
per meter of tank diameter (1.0 in* per ft
of tank diameter) and the width of any
portion of any gap shall not exceed 1.27
cm (% in).
(C) One end of the metallic shoe is to
extend into the stored liquid and the
other end is to extend a minimum
vertical distance of 61 cm (24 in) above
the stored liquid surface.
(D) There are to be no holes, tears, or
other openings in the shoe, seal fabric,
or seal envelope.
(ii) The secondary seal is to meet the
following requirements:
(A) The secondary seal is to be
installed above the primary seal so that
it completely covers the space between
the roof edge and the tank wall except
as provided in paragraph (a)(l)(ii)(B) of
this section.
(B) The accumulated area of gaps
between the tank wall and the
secondary seal shall not exceed 21.2 cm*
per meter of tank diameter (1.0 in* per ft
of tank diameter) and the width of any
portion of any gap shall not exceed 1.27
cm (V4 hi).
(C) There are to be no holes, tears or
other openings in the seal or seal fabric.
(D) The owner or operator is
exempted from the requirements for
secondary seals and the secondary seal
gap criteria when performing gap
measurements or inspections of the
primary seal.
(iii) Each opening in the roof except
for automatic bleeder vents and rim
space vents is to provide a projection
below the liquid surface. Each opening
in the roof except for automatic bleeder
vents, rim space vents and leg sleeves is
to be equipped with a cover, seal or lid
which is to be maintained in a closed
position at all times (i.e., no visible gap)
except when the device is in actual use
or as described in pargraph (a)(l)(iv) of
this section. Automatic bleeder vents
are to be closed at all times when the
roof is floating, except when the roof is
being floated off or is being landed on
the roof leg supports. Rim vents are to
be set to open when the roof is being
floated off the roof legs supports or at
the manufacturer's recommended
setting.
(iv) Each emergency roof drain is to
be provided with a slotted membrane
fabric cover that covers at least 90
percent of the area of the opening.
(2) A fixed roof with an internal
floating type cover equipped with a
continuous closure device between the
tank wall and the cover edge.'The cover
is to be floating at all times, [i.e., off the
leg supports) except during initial fill
and when the tank is completely
emptied and subsequently refilled. The
process of emptying and refilling when
the cover is resting on the leg supports
shall be continuous and shall be
accomplished as rapidly as possible.
Each opening in the cover except for
automatic bleeder vents and the rim
space vents is to provide a projection
below the liquid surface. Each opening
in the cover except for automatic
bleeder vents, rim space vents, stub
drains and leg sleeves is to be equipped
with a cover, seal, or lid which is to be
maintained in a closed position at all
times (i.e., no visible gap) except when
the device is in actual use. Automatic
bleeder vents are to be closed at all
times when the cover is floating except
when the covtsr is being floated off or is
being landed on the leg supports. Rim
vents are to be set to open only when
the cover is being floated off the leg
supports or at the manufacturer's
recommended setting.
(3) A vapor recovery system which
collects all VOC vapors and gases
discharged from the storage vessel, and
a vapor return or disposal system which
is designed to process such VOC vapors
and gases so as to reduce their emission
to the atmosphere by at least 95 percent
by weight.
(4) A system equivalent to those
described in paragraphs (a)(l), (a)(2), or
(a)(3) of this section as provided in
{ 60.114a.
(b) The owner or operator of each
storage vessel to which this subpart
applies which contains a petroleum
liquid which, as stored, has a true vapor
pressure greater than 76.6 kPa (11.1
psia), shall equip the storage vessel with
a vapor recovery system which collects
all VOC vapors and gases discharged
from the storage vessel, and a vapor
return or disposal system which is
designed to process such VOC vapors
and gases so as to reduce their emission
to the atmosphere by at least 95 percent
by weight.
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Federal Register / Vol. 45, No. 67 / Friday, April 4, 1980 / Rules and Regulations
§ 60.113a Testing and procedures.
(a) Except as provided in § 60.8(b)
compliance with the standard
prescribed in § 60.112a shall be
determined as follows or in accordance
with an equivalent procedure as
provided in § 60.114a.
(1) The owner or operator of each
storage vessel to which this subpart
applies which has an external floating
roof shall meet the following
requirements:
(i) Determine the gap areas and
maximum gap widths between the
primary seal and the tank wall, and the
secondary seal and the tank wall
according to the following frequency
and furnish the Administrator with a
written report of the results within 60
days of performance of gap
measurements:
(A) For primary seals, gap
measurements shall be performed within
60 days of the initial fill with petroleum
liquid and at least once every five years
thereafter. All primary seal inspections
or gap measurements which require the
removal or dislodging of the secondary
seal shall be accomplished as rapidly as
possible and the secondary seal shall be
replaced as soon as possible.
(B) For secondary seals, gap
measurements shall be performed within
60 days of the initial fill with petroleum
liquid and at least once every year
thereafter.
(C) If any storage vessel is out of
service for a period of one year or more,
subsequent refilling with petroleum
liquid shall be considered initial fill for
the purposes of paragraphs (a)(l)(i)(A)
and (a)(l)(i)((B) of this section.
(ii) Determine gap widths in the
primary and secondary seals
individually by the following
procedures:
(A) Measure seal gaps, if any, at one
or more floating roof levels when the
roof is floating off the roof leg supports.
(B) Measure seal gaps around the
entire circumference of the tank in each
place where a Vs" diameter uniform
probe passes freely (without forcing or
binding against seal) between the seal
and the tank wall and measure the
circumferential distance of each such
location.
(C) The total surface area of each gap
described in paragraph (a)(l)(ii)(B) of
this section shall be determined by using
probes of various widths to accurately
measure the actual distance from the
tank wall to the seal and multiplying
each such width by its respective
circumferential distance.
(iii) Add the gap surface area of each
gap location for the primary seal and the
secondary seal individually. Divide the
sum for each sea) by the nominal
diameter of the tank and compare each
ratio to the appropriate ratio in the
standard in § 60.112a(a)(l)(i) and
(iv) Provide the Administrator 30 days
prior notice of the gap measurement to
afford the Administrator the opportunity
to have an observer present.
(2) The owner or operator of each
storage vessel to which this subpart
applies which has a vapor recovery and
return or disposal system shall provide
the following information to the
Administrator on or before the date on
which construction of the storage vessel
commences:
(i) Emission data, if available, for a
similar vapor recovery and return or
disposal system used on the same type
of storage vessel, which can be used to
determine the efficiency of the system.
A complete description of the emission
measurement method used must be
included.
(ii) The manufacturer's design
specifications and estimated emission
reduction capability of the system.
(iii) The operation and maintenance
plan for the system.
(iv) Any other information which will
be useful to the Administrator in
evaluating the effectiveness of the
system in reducing VOC emissions.
(Sec. 114, Clean Air Act as amended (42
U.S.C. 7414))
f 60. 11 4a Equivalent equipment and
procedures.
(a) Upon written application from an
owner or operator and after notice and
opportunity for public hearing, the
Administrator may approve the use of
equipment or procedures, or both, which
have been demonstrated to his
satisfaction to be equivalent in terms of
reduced VOC emissions to the
atmosphere to the degree prescribed for
compliance with a specific paragraph(s)
of this subpart.
(b) The owner or operator shall
provide the following information in the
application for determination of
equivalency:
(1) Emission data, if available, which
can be used to determine the
effectiveness of the equipment or
procedures in reducing VOC emissions
from the storage vessel. A complete
description of the emission
measurement method used must be
included.
(2) The manufacturer's design
specifications and estimated emission
reduction capability of the equipment.
(3) The operation and maintenance
plan for the equipment.
(4) Any other information which will
be useful to the Administrator in
evaluating the effectiveness of the
equipment or procedures in reducing
VOC emissions.
(Sec. 114 of the Clean Air Act as amended (42
U.S.C. 7414))
§60.115a Monitoring of operations.
(a) Except as provided in paragraph
(d) of this section, the owner or operator
subject to this subpart shall maintain a
record of the petroleum liquid stored,
the period of storage, and the maximum
true vapor pressure of that liquid during
the respective storage period.
(b) Available data on the typical Reid
vapor pressure and the maximum
expected storage temperature of the
stored product may be used to
determine the maximum true vapor
pressure from nomographs contained in
API Bulletin 2517, unless the
Administrator specifically requests that
the liquid be sampled, the actual storage
temperature determined, and the Reid
vapor pressure determined from the
sample(s).
(c) The true vapor pressure of each
type of crude oil with a Reid vapor
pressure less than 13.8 kPa (2.0 psia) or
whose physical properties preclude
determination by the recommended
method is to be determined from
available data and recorded if the
estimated true vapor pressure is greater
than 6.9 kPa (1.0 psia).
(d) The following are exempt from the
requirements of this section:
(1) Each owner or operator of each
storage vessel storing a petroleum liquid
with a Reid vapor pressure of less than
6.9 kPa (1.0 psia) provided the maximum
true vapor pressure does not exceed 6-9
kPa (1.0 psia).
(2) Each owner or operator of each
storage vessel equipped with a vapor
recovery and return or disposal system
in accordance with the requirements of
§§ 60.112a(a)(3) and 60.112a(b).
(Sec. 114 of the Clean Air Act as amended (42
U.S.C. 7414))
[FR Doc. 80-10222 Filed 4-3-80: 8:45 «m]
BILLING CODE 6S60-01-M
IV-393
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112
Federal Register / Vol. 45, No. 105 / Thursday, May 29, 1980 / Rules and Regulations
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Part 60
[FBL-1493-1]
Standards of Performance of New
Stationary Sources: Adjustment of
Opacity Standard for Fossil Fuel Fired
Steam Generator
AGENCY: Environmental Protection
Agency.
ACTION: Final rule.
SUMMARY: On April 1,1980, there was
published in the Federal Register (45 FR
21302) a notice of proposed rulemaking
setting forth a proposed EPA adjustment
of the capacity standard for Interstate
Power Company's Lansing Unit No. 4, in
Lansing, Iowa. The proposal was based
on Interstate's demonstration of the
conditions that entitle it to such an
adjustment under 40 CFR 60.11(e).
Interested persons were given thirty
days in which to submit comments on
the proposed rulemaking.
No written comments have been
received and the proposed adjustment is
approved without change and is set
forth below.
Effective Date: May 29,1980.,
FOR FURTHER INFORMATION CONTACT:
Henry Rompage, Enforcement Division,
EPA, Region VII, Area Code 816-374-
3171.
Signed at Washington, D.C., on May 22,
1980.
Douglas M. Costle,
Administrator.
In consideration of the foregoing, Part
60 of 40 CFR Chapter I is amended as
follows:
Subpart DStandards of Performance
for Fossil Fuel-Fired Generators
§ 60.42 [Amended]
1. Section 60.42 is amended by adding
paragraph (b)(2):
*****
(b) * * *
(2) Interstate Power Company shall
not cause to be discharged into the
atmosphere from its Lansing Station
Unit No. 1 in Lansing, Iowa, any gases
which exhibit greater than 32% opacity,
except that a maximum of 39% opacity
shall be permitted for not more than six
minutes in any hour.
(Sec. 111.301(a), Clear Air Act as amended
(42 U.S.C. 7411, 7601)).
2. Section 60.45(g)(l) is amended by
adding Paragraph (ii) as follows:
f 60.45 Emission and fuel monitoring.
(g) * * *
(1) * * *
(i) * * *
(ii) For sources subject to the opacity
standard of § 60.42(b)(2), excess
emissions are defined as any six-minute
period during which the average opacity
of emissions exceeds 32 percent opacity,
except that one six-minute average per
hour of up to 39 percent opacity need
not be reported.
[FR Doc. 8O-1B409 Filed 5-28-80, 8 45 am)
BILLING CODE 656O-01-M
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113
Federal Register / Vol. 45, No. 121 / Friday, June 20,1980 / Rules and Regulations
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Part 60
[FRL 1458-4]
Standards of Performance for New
Stationary Sources; Revised
Reference Methods 13A and 13B
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Final rule.
SUMMARY: This rule revises Appendix A,
Reference Methods 13A and 13B, the
detailed requirements used to measure
total fluoride emissions to determine
whether affected facilities at phosphate
fertilizer and primary aluminum plants
are in compliance with the standard of
performance. Since the methods were
originally promulgated on January 26,
1976, several revisions that would
clarify, correct, and improve the
methods have been evaluated. Adoption
of these revisions will make Methods
ISA and 13B more accurate and reliable.
EFFECTIVE DATE: June 20,1980.
FOR FURTHER INFORMATION CONTACT:
Mr. Roger T. Shigehara, Emission
Measurement Branch (MD-19), U.S.
Environmental Protection Agency,
Research Triangle Park, North Carolina
27711, telephone number (919) 541-2237.
SUPPLEMENTARY INFORMATION: The
specific changes to Methods 13A and
13B are:
1. Aluminum and silicon dioxide are
no longer listed as interferences since
sample distillation eliminates this
problem. Grease on sample-exposed
surfaces, which may adsorb F, has been
added as a potential interference.
2. The heat source for the sample
distillation has been changed from a hot
plate to a bunsen burner.
3. The requirements for the sample
train filter when it is placed between the
probe and first impinger have been
changed to allow any filter that can
meet certain specifications. The filter (1)
must withstand prolonged exposure to
temperatures up to 135°C (275°F), (2)
have at least 95 percent collection
efficiency for 0.3 ftm dioctyl phthalate
smoke particles, and (3) have a low F
blank value.
4. A requirement to oven dry the
sodium fluoride before preparing the
standardizing solution has been added.
5. Additional details have been added
to clarify sample recovery procedures.
6. A requirement to collect and
analyze a sample blank has been added.
7. To prevent F carryover after
distillation of high concentration F
samples, a procedure to remove the
residual F has been added.
8. The definition of Vt has been
changed to make it clearer.
9. Method 13B requires additional
standardizing solutions for specific ion
electrodes which do not display a linear
response to low concentration F
samples.
PUBLIC COMMENTS: Upon proposal of the
amendments to the New Source
Performance Standard for Primary
Aluminum plants, a comment was
received on Methods 13A and 13B. The
comment noted that in some cases the
sampling train may be required to
collect sample continuously over a
period of 24 hours. Such a large sample
would exceed the capacity of the train's
silica gel to absorb the residual moisture
in the sample.
EPA agrees with this comment and
has modified Methods ISA and 13B to
eliminate this potential problem. These
changes are consistent with the changes
in Method 5 allowing the following
options: (1) alternative systems of
cooling the gas stream and measuring
the condensed moisture, (2) addition of
extra silica gel to the impinger train, or
(3) replacement of spent silica gel during
a sample run.
The Administrator finds that these
amendments are minor and technical,
and that they will have no effect on the
stringency of the affected NSPS's. Notice
and public procedure on these
amendments are therefore unnecessary.
(Sections 111, 114, and 301(a) of the Clean Air
Act as amended (42 U.S.C. 7411, 7414. and
7C01(a))
Dated: )une 16,1960.
Douglas M. Costle,
Administrator.
40 CFR Part 60 is amended by revising
Methods ISA and 13B of Appendix A to
read as follows:
Appendix AReference Test Methods
*****
Method 13A. Determination of Total Fluoride
Emissions From Stationary Sources; SPADNS
Zirconium Lake Method
1. Applicability and Principle
1.1 Applicability. This method applies to
the determination of fluoride (F) emissions
from sources as specified in the regulations. It
does not measure fluorocarbons, such as
freons.
1.2 Principle. Gaseous and paniculate F
are withdrawn isokmetically from the source
and collected in water and on a filter. The
total F is then determined by the SPADNS
Zirconium Lake colorimetric method.
2. Range and Sensitivity
The range of this method is 0 to 1.4 fig F/
ml. Sensitivity has not been determined.
3. Interferences
Large quantities of chloride will interfere
with the analysis, but this interference can be
prevented by adding silver sulfate into the
distillation flask (see Section 7.3.4). If
chloride ion is present, it may be easier to use
the Specific Ion Electrode Method (Method
13B). Grease on sample-exposed surfaces
may cause low F results due to adsorption.
4. Precision, Accuracy, and Stability
4.1 Precision. The following estimates
are based on a collaborative test done at a
primary aluminum smelter. In the test, six
laboratories each sampled the stack
simultaneously using two sampling trains for
a total of 12 samples per sampling run.
Fluoride concentrations encountered during
the test ranged from 0.1 to 1.4 mg F/ms. The
within-laboratory and between-laboratory
standard deviations, which include sampling
and analysis errors, were 0.044 mg F/m3 with
60 degrees of freedom and 0.064 mg F/m*
with five degrees of freedom, respectively.
4.2 Accuracy. The collaborative test did
not find any bias in the analytical method.
4.3 Stability. After the sample and
colorimetric reagent are mixed, the color
formed is stable for approximately 2 hours. A
3°C temperature difference between the
sample and standard solutions produces an
error of approximately 0.005 mg F/liter. To
avoid this error, the absorbances of the
sample and standard solutions must be
measured at the same temperature.
5. Apparatus
5.1 Sampling Train. A schematic of the
sampling train is shown in Figure 13A-1; it is
similar to the Method 5 train except the filter
position is interchangeable. The sampling
train consists of the following components:
5.1.1 Probe Nozzle, Pilot Tube,
Differential Pressure Gauge, Filter Heating
System, Metering System, Barometer, and
Gas Density Determination Equipment.
Same as Method 5, Sections 2.1.1, 2.1.3, 2.1.4,
2.1.6. 2.1.8, 2.1.9, and 2.1.10. When moisture
condensation is a problem, the filter heating
system is used.
5.1.2 Probe Liner. Borosilicate glass or
316 stainless steel. When the filter is located
immediately after the probe, the tester may
use a probe heating system to prevent filter
plugging resulting from moisture
condensation, but the tester shall not allow
the temperature in the probe to exceed
120±14°C (248±25°F).
5.1.3 Filter Holder. With positive seal
against leakage from the outside or around
the filter. If the filter is located between the
probe and first impinger, use borosilicate
glass or stainless steel with a 20-mesh
stainless steel screen filter support and a
silicone rubber gasket: do not use a glass frit
or a sintered metal filter support. If the filter
is located between the third and fourth
impingers, the tester may use borosilicate
glass with a glass frit filter support and a
silicone rubber gasket. The tester may also
use other materials of construction with
approval from the Administrator.
5.1.4 Impingers. Four impingers
connected as shown in Figure 13A-1 with
ground-glass (or equivalent), vacuum-tight
fittings. For the first, third, and fourth
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Federal Register / Vol. 45, No. 121 / Friday. June 20,1980 / Rules and Regulations
TEMPERATURE
SENSOR
/
STACK WALL
' PROBE
-^ PITOTTUBE
i !
I OPTIONAL FILTER
HOLDER LOCATION
FILTER HOLDER
PROBE
REVERSE TYPE
PITOT TUBE
THERMOMETER
rS
C/1 ^ CHECK VALVE
VACUUM LINE
VACUUM GAUGE
AIR TIGHT PUMP
DRY TEST METER
Figure 13A 1. Fluoride sampling train.
CONNECTING TUIE .
12 mm ID
§24/40
THERMOMETER
124/40
CONDENSER
SM-nil
ERLENMEYER
FLASK
Figure 13A-2. Fluoride distillation pparatu*.
impingers. use the Greenburg-Smith design,
modified by replacing the tip with a 1.3-cm-
inside-diameter (Vfe in.) glass tube extending
to 1.3 cm (Vt in.) from the bottom of the flask.
For the second impinger, use a Greenburg-
Smith impinger with the standard tip. The
tester may use modifications (e.g., flexible
connections between the impingers or
materials other than glass), subject to the
approval of the Administrator. Place a
thermometer, capable of measuring
temperature to within 1°C (2°F), at the outlet
of the fourth impinger for monitoring
purposes.
5.2 Sample Recovery. The following
items are needed:
5.2.1 Probe-Liner and Probe-Nozzle
Brushes, Wash Bottles, Graduated Cylinder
and/or Balance, Plastic Storage Containers,
Rubber Policeman, Funnel. Same as Method
5, Sections 2.2.1 to 2.2.2 and 2.2.5 to 2.2.8,
respectively.
5.2.2 Sample Storage Container. Wide-
mouth, high-density-polyethylene bottles for
impinger water samples, 1-liter.
5.3 Analysis. The following equipment is
needed:
5.3.1 Distillation Apparatus. Glass
distillation apparatus assembled as shown in
Figure 13A-2.
5.3.2 Bunsen Burner.
5.3.3 Electric Muffle Furnace. Capable of
heating to 600°C.
5.3.4 Crucibles. Nickel, 75- to 100-ml.
5.3.5 Beakers. 500-ml and 1500-ml.
5.3.6 Volumetric Flasks. 50-ml.
5.3.7 Erlenmeyer Flasks.or Plastic Bottles.
500-ml.
5.3.8 Constant Temperature Bath.
Capable of maintaining a constant
temperature of ±1.0°C at room temperature
conditions.
5.3.9 Balance. 300-g capacity to measure
to ±0.5 g.
5.3.10 Spectrophotometer. Instrument
that measures absorbance at 570 nm and
provides at least a 1-cm light path.
5.3.11 Spectrophotometer Cells. 1-cm
pathlength.
ft Reagents
6.1 Sampling. Use ACS reagent-grade
chemicals or equivalent, unless otherwise
specified. The reagents used in sampling are
as follows:
6.1.1 Filters.
6.1.1.1 If the filter is located between the
third and fourth impingers, use a Whatman '
No 1 filter, or equivalent, sized to fit the filter
holder.
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Federal Register / Vol. 45, No. 121 / Friday, June 20, 1980 / Rules and Regulations
6.1.1.2 If the filter is located between the
probe and first impinger, use any suitable
medium (e.g., paper organic membrane) that
conforms to the following specifications: (1)
The filter can withstand prolonged exposure
to temperatures up to 135°C (275°F). (2) The
filter has at least 95 percent collection
efficiency (<5 percent penetration) for 0.3 ftm
dioctyl phthalate smoke particles. Conduct
the filter efficiency test before the test series,
using ASTM Standard Method D 2986-71, or
use test data from the supplier's quality
control program. (3) The filter has a low F
blank value (<0.015 mg F/cm2of filter area).
Before the test series, determine the average
F blank value of at least three filters (from
the lot to be used for sampling) using the
applicable procedures described in Sections
7.3 and 7.4 of this method. In general, glass
fiber filters have high and/or variable F
blank values, and will not be acceptable for
use.
0.1.2 Water. Deionized distilled, to
conform to ASTM Specification D1193-74,
Type 3. If high concentrations of organic
matter are not expected to be present, the
analyst may delete the potassium
permanganate test for oxidizable organic
matter.
6.1.3 Silica Gel, Crushed Ice, and
Stopcock Grease. Same as Method 5,
Section 3.1.2, 3.1.4, and 3.1.5, respectively.
6.2 Sample Recovery. Water, from same
container as described in Section 6.1.2, is
needed for sample recovery.
6.3 Sample Preparation and Analysis.
The reagents needed for sample preparation
and analysis are as follows:
6.3.1 Calcium Oxide (CaO). Certified
grade containing 0.005 percent F or less.
6.3 2 Phenolphthalein Indicator.
Dissolve 0.1 g of phenolphthalein in a mixture
of 50 ml of 90 percent ethanol and 50 ml of
deionized distilled water.
8.3.3 Silver Sulfate (Ag^O,).
6.3.4 Sodium Hydroxide (NaOH).
Pellets.
6.3.5 Sulfuric Acid (H.SO.), Concentrated.
6.3 6 Sulfuric Acid, 25 percent (V/V).
Mix 1 part of concentrated HiSO. with 3
parts of deionized distilled water.
6.3.7 Filters. Whatman No. 541, or
equivalent.
6.3.8 Hydrochloric Acid (HC1),
Concentrated.
6.3.9 Water. From same container as
described in Section 6.1.2.
6 3.10 Fluoride Standard Solution, 0.01 mg
F/ml. Dry in an oven at 110'C for at least 2
hours. Dissolve 0.2210 g of NaF in 1 liter of
deionized distilled water. Dilute 100 ml of thii
solution to 1 liter with deionized distilled
water.
6.3.11 SPADNS Solution [4, 5 dihydroxy-3-
(p-sulfophenylazo)-2,7-naphthalene-disuifonic
acid trisodium salt). Dissolve 0.960 ± 0.010
g of SPADNS reagent in 500 ml deionized
distilled water. If stored in a well-sealed
bottle protected from the sunlight, this
solution is stable for at least 1 month.
6.3.12 Spectrophotometer Zero Reference
Solution. Prepare daily. Add 10 ml of
SPADNS solution (6.3.11) to 100 ml deionized
distilled water, and acidify with a solution
prepared by diluting 7 ml of concentrated HC1
to 10 ml with deionized distilled water.
6.3.13 SPADNS Mixed Reagent. Dissolve
0.135 ± 0.005 g of zirconyl chloride
octahydrate (ZrOCU 8H,O) in 25 ml of
deionized distilled water. Add 350 ml of
concentrated HC1, and dilute to 500 ml with
deionized distilled water. Mix equal volumes
of this solution and SPADNS solution to form
a single reagent. This reagent is stable for at
least 2 months.
7. Procedure
7.1 Sampling. Because of the complexity
of this method, testers should be trained and
experienced with the text procedures to
assure reliable results.
7.1.1 Pretest Preparation. Follow the
general procedure given in Method 5, Section
4.1.1, except the filter need not be weighed.
7.1.2 Preliminary Determinations.
Follow the general procedure given in
Method 5, Section 4.1.2., except the nozzle
size selected must maintain isokinetic
sampling rates below 28 liters/min (1.0 cfm).
7.1.3 Preparation of Collection Train.
Follow the general procedure given in
Method 5, Section 4.1.3, except for the
following variations:
Place 100 ml of deionized distilled water in
each of the first two impingerg, and leave the
third impinger empty. Transfer approximately
200 to 300 g of preweighed silica gel from its
container to the fourth impinger.
Assemble the train as shown in Figure
13A-1 with the filter between the third and
fourth impingers. Alternatively, if a 20-mesh
stainless steel screen is used for the filter
support, the tester may place the filter
between the probe and first impinger. The
tester may also use a filter heating system to
prevent moisture condensation, but shall not
allow the temperature around the filter holder
to exceed 120 ± 14°C (248 ± 25°F). Record
the filter location on the data sheet.
7.1.4 Leak-Check Procedures. Follow the
leak-check procedures given in Method 5,
Sections 4.1.4.1 (Pretest Leak-Check), 4.1.4.2
(Leak-Checks During the Sample Run), and
4.1.4.3 (Post-Test Leak-Check).
7.1.5 Fluoride Train Operation.. Follow
the general procedure given in Method 5,
Section 4.1.5, keeping the filter and probe
temperatures (if applicable) at 120 ± 14°C
(248 ± 25°F) and isokinetic sampling rates
below 28 liters/min (1.0 cfm). For each run.
record the data required on a data sheet such
as the one shown in-Method 5, Figure 5-2.
7.2 Sample Recovery. Begin proper
cleanup procedure as soon as the probe is
removed from the stack at the end of the
sampling period.
Allow the probe to cool. When it can be
safely handled, wipe off all external
particulate matter near the tip of the probe
nozzle and place a cap over it to keep from
losing part of the sample. Do not cap off the
probe tip tightly while the sampling train is
cooling down, because a vacuum would form
in the filter holder, thus drawing impinger
water backward.
Before moving the sample train to the
cleanup site, remove the probe from the
sample train, wipe off the sihcone grease, and
cap the open outlet of the probe. Be careful
not to lose any condensate, if present.
Remove the filter assembly, wipe off the
sihcone grease from the filter holder inlet,
and cap this inlet. Remove the umbilical cord
from the last impinger, and cap the impinger.
After wiping off the silicone grease, cap off
the filter holder outlet and any open impinger
inlets and outlets. The tester may use ground-
glass stoppers, plastic caps, or serum caps to
close these openings.
Transfer the probe and filter-impinger
assembly to an area that is clean and
protected from the wind so that the chances
of contaminating or losing the sample is
minimized.
Inspect the train before and during
disassembly, and note any abnormal
conditions. Treat the samples as follows:
7.2.1 Container No. 1 (Probe, Filter, and
Impinger Catches). Using a graduated
cylinder, measure to the nearest ml, and
record the volume of the water in the first
three impingers; include any condensate in
the probe in this determination. Transfer the
impinger water from the graduated cylinder
into this polyethylene container. Add the
filter to this container. (The filter may be
handled separately using procedures subject
to the Administrator's approval.) Taking care
that dust on the outside of the probe or other
exterior surfaces does not get into the
sample, clean all sample-exposed surfaces
(including the probe nozzle, probe fitting,
probe liner, first three impingers, impinger
connectors, and filter holder) with deionized
distilled water. Use less than 500 ml for the
entire wash. Add the washings to the sampler
container. Perform the deionized distilled
water rinses as follows:
Carefully remove the probe nozzle and
rinse the inside surface with deionized
distilled water from a wash bottle. Brush with
a Nylon bristle brush, and rinse until the
rinse shows no visible particles, after which
make a final rinse of the inside surface. Brush
and rinse the inside parts of the Swagelok
fitting with deionized distilled water in a
similar way.
Rinse the probe liner with deionized
distilled water. While squirting the water into
the upper end of the probe, tilt and rotate the
probe so that all inside surfaces will be
wetted with water. Let the water drain from
the lower end into the sample container. The
tester may use a funnel (glass or
polyethylene) to aid in transferring the liquid
washes to the container. Follow the rinse
with a probe brush. Hold the probe in an
inclined position, and squirt deionized
distilled water into the upper end as the
probe brush is being pushed with a twisting
action through the probe. Hold the sample
container underneath the lower end of the
probe, and catch any water and particulate
matter that is brushed from the probe. Run
the brush through the probe three times or
more. With stainless steel or other metal
probes, run the brush through in the above
prescribed manner at least six times since
metal probes have small crevices in which
particulate matter can be entrapped. Rinse
the brush with deionized distilled water, and
quantitatively collect these washings in the
sample container. After the brushing, make a
final rinse of the probe as described above.
It is recommended that two people clean
the probe to minimize sample losses.
Between sampling runs, keep brushes clean
and protected from contamination.
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Rinse the inside surface of each of the first
three impingers (and connecting glassware)
three separate times. Use a small portion of
deionized distilled water for each rinse, and
brush each sample-exposed surface with a
Nylon bristle brush, to ensure recovery of
fine particulate matter. Make a final rinse of
each surface and of the brush.
After ensuring that all joints have been
wiped clean of the silicone grease, brush and
rinse with deionized distilled water the inside
of the filter holder (front-half only, if filter is
positioned between the third and fourth
impingers). Brush and rinse each surface
three times or more if needed. Make a final
rinse of the brush and filter holder.
After all water washings and particulate
matter have been collected in the sample
container, tighten the lid so that water will
not leak out when it is shipped to the
laboratory. Mark the height of the fluid level
to determine whether leakage occurs during
transport. Label the container clearly to
identify its contents.
7.2.2 Container No. 2 (Sample Blank).
Prepare a blank by placing an unused filter in
a polyethylene container and adding a
volume of water equal to the total volume in
Container No. 1. Process the blank in the
same manner as for Container No. 1.
7.2.3 Container No. 3 (Silica Gel). Note
the color of the indicating silica gel to
determine whether it has been completely
spent and make a notation of its condition.
Transfer the silica gel from the fourth
impinger to its original container and seal.
The tester may use a funnel to pour the silica
gel and a rubber policeman to remove the
silica gel from the impinger. It is not
necessary to remove the small amount of dust
particles that may adhere to the impinger
wall and are difficult to remove. Since the
gain in weight is to be used for moisture
calculations, do not use any water or other
liquids to transfer the silica gel. If a balance
is available in the field, the tester may follow
the analytical procedure for Container No. 3
in Section 7.4.2.
7.3 Sample Preparation and Distillation.
(Note the liquid levels in Containers No. 1
and No. 2 and confirm on the analysis sheet
whether or not leakage occurred during
transport. If noticeable leakage had occurred,
either void the sample or use methods,
subject to the approval of the Administrator,
to correct the final results.) Treat the contents
of each sample container as described below:
7.3.1 Container No. 1 (Probe, Filter, and
Impinger Catches). Filter this container's
contents, including the sampling filter,
through Whatman No. 541 filter paper, or
equivalent, into a 1500-ml beaker.
7.3.1.1 If the filtrate volume exceeds 900
ml, make the filtrate basic (red to
phenolphthalein) with NaOH, and evaporate
to less than 900 ml.
7.3.1.2 Place the filtered material
(including sampling filter) in a nickel crucible,
add a few ml of deionized distilled water,
and macerate the filters with a glass rod.
Add 100 mg CaO to the crucible, and mix
the contents thoroughly to form a slurry. Add
two drops of phenolphthalein indicator. Place
the crucible in a hood under infrared lamps
or on a hot plate at low heat. Evaporate the
water completely. During the evaporation of
the water, keep the slurry basic (red to
phenolphthalein) to avoid loss of F. If the
indicator turns colorless (acidic) during the
evaporation, add CaO until the color turns
red again.
After evaporation of the water, place the
crucible on a hot plate under a hood and
slowly increase the temperature until the
Whatman No. 541 and sampling filters char. It
may take several hours to completely char
the filters.
Place the crucible in a cold muffle furnace.
Gradually (to prevent smoking) increase the
temperature to 600°C, and maintain until the
contents are reduced to an ash. Remove the
crucible from the furnace and allow to cool.
Add approximately 4 g of crushed NaOH to
the crucible and mix. Return the crucible to
the muffle furnace, and fuse the sample for 10
minutes at 600°C.
Remove the sample from the furnace, and
cool to ambient temperature. Using several
rinsings of warm deionized distilled water,
transfer the contents of the crucible to the
beaker containing the filtrate. To assure
complete sample removal, rinse finally with
two 20-ml portions of 25 percent H2SO4, and
carefully add to the beaker. Mix well, and
transfer to a 1-liter volumetric flask. Dilute to
volume with deionized distilled water, and
mix thoroughly. Allow any undissolved solids
to settle.
7.3.2 Container No. 2 (Sample Blank).
Treat in the same manner as described in
Section 7.3.1 above.
7.3.3 Adjustment of Acid/Water Ratio in
Distillation Flask. (Use a protective shield
when carrying out this procedure.) Place 400
ml of deionized distilled water in the
distillation flask, and add 200 ml of
concentrated HjSO«. (Caution: Observe
standard precautions when mixing HaSO«
with water. Slowly add the acid to the flask
with constant swirling.) Add some soft glass
beads and several small pieces of broken
glass tubing, and assemble the apparatus as
shown in Figure 13A-2. Heat the flask until it
reaches a temperature of 175°C to adjust the
acid/water ratio for subsequent distillations.
Discard the distillate.
7.3.4 Distillation. Cool the contents of
the distillation flask to below 80°C. Pipet an
aliquot of sample containing less than 10.0 mg
F directly into the distillation flask, and add
deionized distilled water to make a total
volume of 220 ml added to the distillation
flask. (To estimate the appropriate aliquot
size, select an aliquot of the solution and
treat as described in Section 7.4.1. This will
be an approximation of the F content because
of possible interfering ions.) Note: If the
sample contains chloride, add 5 mg of AgsSOj
to the flask for every mg of chloride.
Place a 250-ml volumetric flask at the
condenser exit. Heat the flask as rapidly as
possible with a Bunsen burner, and collect all
the distillate up to 175°C. During heatup, play
the burner flame up and down the side of the
flask to prevent bumping. Conduct the
distillation as rapidly as possible (15 minutes
or less). Slow distillations have been found to
produce low F recoveries. Caution: Be careful
not to exceed 175°C to avoid causing HjSO4
to distill over.
If F distillation in the mg range is to be
followed by a distillation in the fractional mg
range, add 220 ml of deionized distilled water
and distill it over as in the acid adjustment
step to remove residual F from the distillation
system.
The tester may use the acid in the
distillation flask until there is carry-over of
interferences or poor F recovery. Check for
these every tenth distillation using a
deionized distilled water blank and a
standard solution. Change the acid whenever
the F recovery is less than 90 percent or the
blank value exceeds 0.1 >ig/ml.
7.4 Analysis.
7.4.1 Containers No. 1 and No. 2. After
distilling suitable aliquots from Containers
No. 1 and No. 2 according to Section 7.3.4,
dilute the distillate in the volumetric flasks to
exactly 250 ml with deionized distilled water,
and mix thoroughly. Pipet a suitable aliquot
of each sample distillate (containing 10 to 40
fig F/ml) into a beaker, and dilute to 50 ml
with deionized distilled water. Use the same
aliquot size for the blank. Add 10 ml of
SPADNS mixed reagent (6.3.13), and mix
thoroughly.
After mixing, place the sample in_a
constant-temperature bath containing the
Standard solutions (see Section 8.2) for 30
minutes before reading the absorbance on the
spectrophotometer.
Set the spectrophotometer to zero
absorbance at 570 nm with the reference
solution (6.3.12), and check the
spectrophotometer calibration with the
standard solution. Determine the absorbance
of the samples, and determine the
concentration from the calibration curve. If
the concentration does not fall within the
range of the calibration curve, repeat the
procedure using a different size aliquot.
7.4.2 Container No. 3 (Silica Gel). Weigh
the spent silica gel (or silica gel plus
impinger) to the nearest 0.5 g using a balance.
The tester may conduct this step in the field.
8. Calibration
Maintain a laboratory log of all
calibrations.
8.1 Sampling Train. Calibrate the
sampling train components according to the
indicated sections in Method 5: Probe Nozzle
(Section 5.1); Pilot Tube (Section 5.2);
Metering System (Section 5.3); Probe heater
(Section 5.4); Temperature Gauges (Section
5.5); Leak Check of Metering System (Section
5.6); and Barometer (Section 5.7).
8.2 Spectrophotometer. Prepare the
blank standard by adding 10 ml of SPADNS
mixed reagent to 50 ml of deionized distilled
water. Accurately prepare a series of
standards from the 0.01 mg F/ml standard
fluoride solution (6.3.10) by diluting 0, 2, 4, 6,
8, 10,12, and 14 ml to 100 ml with deionized
distilled water. Pipet 50 ml from each solution
and transfer each to a separate 100-ml
beaker. Then add 10 ml of SPADNS mixed
reagent to each. These standards will contain
0,10, 20, 30, 40 50,60, and 70 fig F (0 to 1.4 jig/
ml), respectively.
After mixing, place the reference standards
and reference solution in a constant
temperature bath for 30 minutes before
reading the absorbance with the
spectrophotometer. Adjust all samples to this
same temperature before analyzing.
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With the spectrophotometer at 570 nm, use
the reference solution (6.3.12) to set the
absorbance to zero.
Determine the absorbance of the
standards. Prepare a calibration curve by
plotting Hg F/50 ml versus absorbance on
linear graph paper. Prepare the standard
curve initially and thereafter whenever the
SPADNS mixed reagent is newly made. Also,
run a calibration standard with each set of
samples and if it differs from the calibration
curve by ±2 percent, prepare a new standard
curve.
9. Calculations
Carry out calculations, retaining at least
one extra decimal figure beyond that of the
acquired data. Round off figures after final
calculation. Other forms of the equations may
be used, provided that they yield equivalent
results.
9.1 Nomenclature.
A,, =4 Aliquot of distillate taken for color
development, ml.
A, = Aliquot of total sample added to still,
ml.
B,s = Water vapor in the gas stream,
proportion by volume.
C. = Concentration of F in stack gas, mg/ms,
dry basis, corrected to standard
conditions of 760 mm Hg (29.92 in. Hg)
and 293=K (528'R).
l(f
F)
Ft = Total F in sample, mg,
Hg F = Concentration from the calibration
curve, ng.
Tm = Absolute average dry gas meter
temperature (see Figure 5-2 of Method 5),
K(°R).
T, = Absolute average stack gas temperature
(see Figure 5-2 of Method 5), °K (°R).
Vd = Volume of distillate collected, ml.
VmUui) = Volume of gas sample as measured
by dry gas meter, corrected to standard
conditions, dscm (dscf).
V, = Total volume of F sample, after final
dilution, ml.
V«(,w> = Volume of water vapor in the gas
sample, corrected to standard conditions,
scm (scf).
9.2 Average Dry Gas Meter Temperature
and Average Orifice Pressure Drop. See data
sheet (Figure 5-2 of Method 5).
9.3 Dry Gas Volume. Calculate Vm(,^ and
adjust for leakage, if necessary, using the
equation in section 6.3 of Method 5.
9.4 Volume of Water Vapor and Moisture
Content. Calculate the volume of water vapor
V»(st and moisture content Bsl from the data
obtained in this method (Figure 13A-1); use
Equations 5-2 and 5-3 of Method 5.
9.5 Concentration.
9.5.1 Total Fluoride in Sample. Calculate
the amount of F in the sample using the
following equation:
Eq. 13A-1
9.5.2 Fluoride Concentration in Stack Gas. Determine the F concentration in the stack
gas using the following equation:
K
Xstd)
Where:
K = 35.31 ft'/m'if V^uw) is expressed in
English units.
= 1.00 m'/m3 if Vm^u> is expressed in
metric units.
9.6 Isokinetic Variation and Acceptable
Results. Use Method 5, Sections 6.11 and
6.12.
10. Bibliography
1. Bellark. Ervin, Simplified Fluoride
Distillation Method. Journal of the American
Water Works Association. 50/5306. 1958.
2 Mitchell, W. J., J. C. Suggs, and F. J.
Bergman. Collaborative Study of EPA method
13A and Method 13B. Publication No. EPA-
600/4-77-050. Environmental Protection
Agency. Research Triangle Park, North
Carolina. December 1977.
3. Mitchell, W. J. and M. R. Midgett.
Adequacy of Sampling Trains and Analytical
Procedures Used for Fluoride. Atm. Environ.
70-865-672.1978.
Eq. 13A-2
Method 13B. Determination of Total Fluoride
Emissions From Stationary Sources; Specific
Ion Electrode Method
1. Applicability and Principle
1.1 Applicability. This method applies to
the determination of fluoride (F) emissions
from stationary sources as specified in the
regulations It does not measure
fluorocarbons, such as freons.
1.2 Principle. Gaseous and par'iculate F
are withdrawn isokmetically from the source
and collected in water and on a filter. The
total F is then determined by the specific ion
electrode method.
2. Range and Sensitivity
The range of this method is 0.02 to 2.000 fig
F/ml. however, measurements of less than 0.1
fig F/ml require extra care. Sensitivity has
not been determined.
3. Interferences
Grease on sample-exposed surfaces may
cause low F results because of adsorption.
4. Precision and Accuracy
4.1 Precision. The following estimates
are based on a collaborative test done at a
primary aluminum smelter. In the test, six
laboratories each sampled the stack
simultaneously using two sampling trains for
a total of 12 samples per sampling run.
Fluoride concentrations encountered during
the test ranged from 0.1 to 1.4 mg F/m5. The
within-laboratory and between-laboratory
standard deviations, which include sampling
and analysis errors, are 0.037 mg F/ms with
60 degrees of freedom and 0.056 mg F/m3
with five degrees of freedom, respectively.
4.2 Accuracy. The collaborative test did
not find any bias in the analytical method.
5. Apparatus
5.1 Sampling Train and Sample Recovery.
Same as Method 13A, Sections 5.1 and 5.2,
respectively.
5.2 Analysis. The following items are
needed:
5.2.1 Distillation Apparatus, Bunsen
Burner, Electric Muffle Furnace, Crucibles,
Beakers, Volumetric Flasks, Erlenmeyer
Flasks or Plastic Bottles, Constant
Temperature Bath, and Balance. Same as
Method ISA, Sections 5.3.1 to 5.3.9,
respectively, except include also 100-ml
polyethylene beakers.
5.2.2 Fluoride Ion Activity Sensing
Electrode.
5.2.3 Reference Electrode. Single
junction, sleeve type.
5.2.4 Electrometer. A pH meter with
millivolt-scale capable of ±0.1-mv resolution.
or a specific ion meter made specifically for
specific ion use.
5.2.5 Magnetic Stirrer and TFE *
Fluorocarbon-Coated Stirring Bars.
6. Reagents
6.1 Sampling and Sample Recovery.
Same as Method ISA, Sections 6.1 and 6.2,
respectively.
6.2 Analysis. Use ACS reagent grade
chemicals (or equivalent), unless otherwise
specified. The reagents needed for analysis
are as follows:
6.2.1 Calcium Oxide (CaO). Certified
grade containing 0.005 percent F or less.
6.2.2 Phenolphthalem Indicator.
Dissolve 0.1 g of phenolphthalein in a mixture
of 50 ml of 90 percent ethanol and 50 ml
deionized distilled water.
6.2.3 Sodium Hydroxide (NaOH).
Pellets.
6.2.4 Sulfuric Acid (HZSO4), Concentrated.
6.2.5 Filters. Whatman No. 541, or
equivalent.
6.2.6 Water. From same container as
6.1.2 of Method 13A.
6.2.7 Sodium Hydroxide, 5 M. Dissolve
20 g of NaOH in 100 ml of deionized distilled
water.
6.2.8 Sulfuric Acid, 25 percent (V/V).
Mix 1 part of concentrated H2SO« with 3
parts of deionized distilled water.
* Mention of any trade name or specific product
does not constitute endorsement by the
Environmental Protection Agency.
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6.2.9 Total Ionic Strength Adjustment
Buffer (TISAB). Place approximately 500 ml
of deionized distilled water in a 1-liter
beaker. Add 57 ml of glacial acetic acid, 56 g
of sodium chloride, and 4 g of cyclohexylene
dinitrilo tetraacetic acid. Stir to dissolve.
Place the beaker in a water bath to cool it
Slowly add 5 M NaOH to the solution,
measuring the pH continuously with a
calibrated pH/reference electrode pair, until
the pH is 5.3. Cool to room temperature. Pour
into a 1-liter volumetric flask, and dilute to
volume with deionized distilled water.
Commercially prepared TISAB may be
substituted for the above.
6.2.10 Fluoride Standard Solution. 0.1 M.
Oven dry some sodium fluoride (Nap) for a
minimum of 2 hours at 110°C, and store in a
desiccator. Then add 4.2 g of NaF to a 1-liter
volumetric flask, and add enough deionized
distilled water to dissolve. Dilute to volume
with deionized distilled water.
7. Procedure
7.1 Sampling, Sample Recovery, and
Sample Preparation and Distillation. Same
as Method 13A, Sections 7.1, 72, and 7.3,
respectively, except the notes concerning
chloride and sulfate interferences are not
applicable.
7.2 Analysis.
7.2.1 Containers No. 1 and No. 2. Distill
suitable aliquots from Containers No. 1 and
No. 2. Dilute the distillate in the volumetric
flasks to exactly 250 ml with deionized
distilled water and mix thoroughly. Pipet a
25-ml aliquot from each of the distillate and
separate beakers. Add an equal volume of
TISAB, and mix. The sample should be at the
same temperature as the calibration
standards when measurements are made. If
ambient laboratory temperature fluctuates
more than ±2°C from the temperature at
which the calibration standards were
measured, condition samples and standards
in a constant-temperature bath before
measurement. Stir the sample with a
magnetic stirrer during measurement to
minimize electrode response time. If the
tirrer generates enough heat to change
solution temperature, place a piece of
temperature insulating material such as cork,
between the stirrer and the beaker. Hold
dilute samples (below 10' * M fluoride ion
content) in polyethylene beakers during
measurement.
Insert the fluoride and reference electrodes
into the solution. When a steady millivolt
reading is obtained, record it. This may take
several minutes. Determine concentration
from the-calibration curve. Between electrode
measurements, rinse the electrode with
distilled water.
7.2.2 Container No. 3 (Silica Gel). Same
as Method 13A, Section 7.4.2.
8. Calibration
Maintain a laboratory log of all
calibrations.
8.1 Sampling Train. Same as Method
13A.
8.2 Fluoride Electrode. Prepare fluoride
standardizing solutions by serial dilution of
the 0.1 M fluoride standard solution. Pipel 10
ml of 0.1 M fluoride standard solution into a
100-ml volumetric flask, and make up to the
mark with deionized distilled water for a 10"*
M standard solution. Use 10 ml of 10"* M
solution to make a 10"' M solution in the
same manner. Repeat the dilution procedure
and make lO'^and 10"* solutions.
Pipet 50 ml of each standard into a
separate beaker. Add 50 ml of TISAB to each
beaker. Place the electrode in the most dilute
standard solution. When a steady millivolt
reading is obtained, plot the value on the
linear axis of semilog graph paper versus
concentration on the log axis. Plot the
nominal value for concentration of the
standard on the log axis, e.g., when 50 ml of
10~2M standard is diluted with 50 ml of
TISAB, the concentration is still designated
"10" 2M."
Between measurements soak the fluoride
sensing electrode in deionized distilled water
for 30 seconds, and then remove and blot dry.
Analyze the standards going from dilute to
(M)
Where:
K=l9mg/ml.
10. References
1. Same as Method 13A, Citations 1 and 2
of Section 10.
2. MacLeod, Kathryn E. and Howard L.
concentrated standards. A straight-line
calibration curve will be obtained, with
nominal concentrations of 10"*, 10"', 10"*,
and 10"' fluoride molarity on the log axis
plotted versus electrode potential (in mv) on
the linear scale. Some electrodes may be
slightly nonlinear between 10"* and 10" 4M. If
this occurs, use additional standards between
these two concentrations.
Calibrate the fluoride electrode daily, and
check it hourly. Prepare fresh fluoride
standardizing solutions daily (10~*M or less).
Store fluoride standardizing solutions in
polyethylene or polypropylene containers.
(Note: Certain specific ion meters have been
designed specifically for fluoride electrode
use and give a direct readout of fluoride ion
concentration. These meters may be used in
lieu of calibration curves for fluoride
measurements over narrow concentration
ranges. Calibrate the meter according to the
manufacturer's instructions.)
9. Calculations
Carry out calculations, retaining at least
one extra decimal figure beyond that of the
acquired data. Round off figures after final
calculation.
9.1 Nomenclature. Same as Method 13A,
Section 9.1. In addition:
M = F concentration from calibration curve,
molarity.
9.2 Average Dry Gas Meter Temperature
and Average Orifice Pressure Drop, Dry Gas
Volume, Volume of Water Vapor and
Moisture Content, Fluroide Concentration in
Stack Gas, and Isokinetic Variation and
Acceptable Results. Same as Method 13A,
Section 9.2 to 9.4, 9.5.2. and 9.6, respectively.
9.3 Fluoride in Sample. Calculate the
amount of F in the sample using the
following:
Equation 13B-1
Crist. Comparison of the SPADNS
Zirconium Lake and Specific Ion Electrode
Methods of Fluoride determination in Stack
Emission Samples. Analytical Chemistry.
45:1272-1273.1973.
|FR Doc 8O-186S8 Filed 0-19-80: 8.45 am)
BILLING CODE 6560-01-M
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ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Part 60
IFRL 1442-1]
Standards of Performance for New
Stationary Sources Primary Aluminum
Industry; Amendments
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Final rule.
SUMMARY: The amendments permit
fluoride emissions to exceed, under
certain circumstances, emission limits
contained in the previously promulgated
standards of performance for new
primary aluminum plants. Such
excursions cannot be more than 0.3 kg/
Mg of aluminum produced (0.6 Ib/ton)
above the promulgated standards of 0.95
kg/Mg (1.9 Ib/ton) and 1.0 kg/Mg (2.0 lb/
ton) for prebake and Soderbcrg plants,
respectively. For an excursion to be
allowed, a proper emission control
system must have been installed and
properly operated and maintained at the
time of the excursion. The intended
effect of these amendments is to take
into account an inherent variability of
fluoride emissions from the aluminum
reduction process.
The amendments require monthly
testing of emissions and revise
Reference Method 14 for measuring
fluoride emission rates. The
amendments also respond to argument*
raised during litigation of the standards
of performance.
DATES: The effective date of the
amendments is June 30.1980. The
applicability date of the amendments is
October 23,1974. All primary aluminum -
plants which commence construction on
.and after the applicability date are
subject to the standards of performance,
as amended here.
ADDRESSES: Background Information
Document. The background information
documents for the proposed and final
amendments may be obtained from the
U.S. EPA Library (MD-35), Research
Triangle Park, North Carolina 27711,
telephone (919) 541-2777. Please refer to
Primary Aluminum Background
Information: Proposed Amendments
(EPA 450/2-76-025a) and Promulgated
Amendments (EPA 450/3-79-026).
Docket: Docket No. OAQPS-78-10,
containing supporting information used
to develop the amendments, is available
for public inspection and copying
between 8:00 a.m. and 4.00 p.m., Monday
through Friday, at EPA's Central Docket
Section, Room 2902, Waterside Mall, 401
M Street, S.W.. Washington, D.C. 20460.
FOR FURTHER INFORMATION CONTACT:
John Crenshaw, Emission Standards and
Engineering Division (MD-13), U.S.
Environmental Protection Agency,
Research Triangle Park, North Carolina
27711, telephone (919) 541-5477.
SUPPLEMENTARY INFORMATION:
Final Amendments
The amendments allow fluoride
emissions from aluminum plant
potrooms to exceed the original limits of
0.95 kg/Mg (1.9 Ib/ton) for prebake
plants and 1.0 kg/Mg (2.0 Ib/ton) for
Soderberg plants if the owner or
operator of the plant can establish that a
proper emission control system was
installed and properly operated and
maintained at the time the excursion
above the original limits occurred.
Emissions may not, however, exceed
1.25 kg/Mg (2.5 Ib/ton) for prebake
plants and 1.3 kg/Mg (2.6 Ib/ton) for
Soderberg plants at any time.
The amendments also require
performance testing to be conducted at
least once each month throughout the
life of the plant. The owner or operator
of a new plant may apply to the
Administrator for an exemption from the
monthly testing requirement for the
primary control system and the anode
bake plant. An exemption from the
testing of secondary emissions from roof
monitors, however, is not permitted.
Finally, the amendments: (1) require
the potroom anemometers and
associated equipment used in
conjunction with Reference Method 14
to be checked for calibration once each
year, unless the anemometers are found
to be out of calibration, in which case an
alternative schedule would be
implemented; [2] clarify other Reference
Method 14 procedures; (3) clarify the
definition of potroom group; (4) replace
English and metric units of measure with
the International System of Units (SI);
and (5) clarify the procedure for
determining the rate of aluminum
production for fluoride emission
calculations. The amendments do not
change the fluoride emission limit of 0.05
kg/Mg (0.1 Ib/ton) of aluminum
equivalent for anode baking facilities at
prebake plants.
Summary of Environmental, Economic,
and Energy Impacts
The amendments allow excursions
above the original standard, but only
under certain conditions. Each excursion
must be reported to the Administrator
and the adequacy of control equipment
and operating and maintenance
procedures must be established by the
plant owner or operator. Based on
emission test results at the Anaconda
Aluminum Company's Sebree, Kentucky
plant, such excursions may be expected
approximately eight percent of the time.
Assuming that each of these excursions
is at the upper limit allowed (1.25 kg/Mg
for a prebake plant), fluoride emissions
from a typical new primary aluminum
plant could be around three to four
percent higher (3.8 Mg/yr, or 4.2 tons/yr,
more) than had been originally
calculated. It is important to stress that
excursions are expected to occur at any
new plant trying to meet the original
standards; the amendments simply
acknowledge that some excursions are
unavoidable.
Although the emission control
efficiency required by the original
standards is still required, it would be
theoretically possible to operate a new
plant so that emissions were always at
the upper limit permitted by these
amendments. Using this "worst case"
assumption, fluoride emissions from a
typical new primary aluminum plant
could increase above levels associated
with the original emission limits by
about 30 percent, or 33 Mg/yr (36 tons/
yr). Assuming that two new plants
become subject to the amended
standards during the next five years,
nationwide emissions of fluorides during
that period could increase by 66 Mg/yr
(72 tons/yr) above the levels which
would result if the original limits were in
effect. No other environmental impacts
are associated with the amendments.
The amendments will result in
performance test costs of about
$415.000/yr during the first year and
$330,000/yr during succeeding years of
operation of a new plant. The increase
in annualized costs, however, would be
less than 0.5 percent for the first and
succeeding years. There are no other
significant costs associated with the
amendments.
No increase in energy consumption
will result from the amendments. The
environmental, economic, and energy
impacts are discussed in greater detail
in Primary Aluminum Background
Information: Promulgated Amendments
(EPA 450/3-79-026).
Background
Standards of performance for new
primary aluminum plants were proposed
on October 23,1974 (39 FR 37730), and
promulgated on January 26,1976 (41 FR
3826). These standards limited fluoride
emissions to 1.0 kg/Mg (2 Ib/ton) for
Soderberg plants, 0.95 kg/Mg (1.9 Ib/ton)
for prebake plants, and 0.05 kg/Mg (0.1
Ib/ton) for anode bake plants. There are
two emission sources from Soderberg
and prebake plants. The first source is
the primary control system, which
includes hoods to capture emissions
from the pots and the control device
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used to treat these emissions; the
exhaust from this system still contains
some fluorides. The second source is the
roof monitor, through which flow the
emissions (called secondary, or roof
monitor, emissions) not captured by the
primary control system. A few plants
use secondary control systems to
capture and collect roof monitor
emissions.
Shortly after promulgation, petitions
for review of the standards were filed
by four aluminum companies. The
principal argument raised by the
petitioners was that the emission limits
contained in the standards were too
stringent and could not be achieved
consistently by new, well-controlled
facilities. Facilities which commenced
construction prior to October 23, 1974.
are not affected by the standard.
Following discussions with the
petitioning aluminum companies, EPA
conducted an emission test program at
the Anaconda Aluminum Company'
plant in Sebree, Kentucky. At the time of
testing, the Sebree plant was the newest
primary aluminum plant in the United
States, and its emission control system
was considered by the Administrator
representative of the best technological
system of continuous emission
reduction. The purpose of the test
program was to gather additional data
for reevaluating the standards. The test
results were available in August of 1977
and indicated that emissions for a new,
well-controlled plant could exceed the
original emission limits approximately
eight percent of the time. The
amendments proposed on September 19,
1978 (43 PR 42186] and promulgated here
address this potential problem by
amending the standards to permit
excursions of fluoride emissions up to
0.3 kg/Mg {0.6 Ib/ton) above the
emission limits contained in the original
standards provided that proper control
equipment was installed and properly
operated and maintained during the time
the excursion occurred.
In addition to amending the original
standards, EPA has revised Reference
Method 14 to reflect knowledge gained
during the Sebree test program. The
revisions clarify and improve the
reliability of the testing procedures, but
do not change the basic test method
and. therefore, do not invalidate earlier
Method 14 test results.
Rationale
The Administrator's decision to
amend the existing standard is based
primarily on the results of the Sebree
test program. The test results may be
summarized as follows: (1) the measured
emissions were variable, ranging from
0.43 to 1.37 kg/Mg (0.85 to 2.74 Ib/ton)
for single test runs; and (2) emission
variability appeared to be inherent in
the production process and beyond the
control of plant personnel. Since the
Sebree plant represents a best
technological system of continuous
emission reduction for new aluminum
plants, the Administrator expects that
the other new plants covered by the
standard will also exhibit emission
variability.
An EPA analysis of the nine Sebree
test runs indicates that there is about
eight percent probability that a
performance test would violate the
current standard. (A performance test is
defined in 40 CFR 60.8(f) as the
arithmetic mean of three separate test
runs, except in situations where a run
must be discounted or canceled and the
Administrator approves using the
arithmetic mean of two runs.) The
petitioners have estimated chances of a
violation ranging from about 2.5 to 10
percent. Although the Sebree data base
is not large enough to permit a thorough
statistical analysis, the Administrator
believes it is adequate to demonstrate a
need for amending the current standard.
The approach selected is to amend
Subpart S to allow a performance test
result to be above the current standard
provided the owner or operator submits
to EPA a report clearly demonstrating
that the emission control system was
properly operated and maintained
during the excursion above the
standard. The report would be used as
evidence that the high emission level
resulted from random and
uncontrollable emission variability, and
that the emission variability was
entirely beyond the control of the owner
or operator of the affected facility.
Under no circumstances, however,
would performance test results be
allowed above 1.25 kg/Mg (2.5 Ib/ton)
for prebake plants or 1.3 kg/Mg (2.6 lb/
ton) for Soderberg plants. The
Administrator believes that emissions
from a plant equipped with the proper
control system which is properly
operated and maintained would be
below these limits at all times.
For performance test results which fall
between the original standard and the
1.25 or 1.3 kg/Mg upper limit to be
considered excursions rather than
violations, the owner or operator of the
affected facility must, within 15 days of
receipt of such performance test results,
submit a report to the Enforcement
Division of the appropriate EPA
Regional Office. As a minimum, the
report should establish that all
necessary control devices were on-line
and operating properly during the
performance test, describe the operation
and maintenance procedures followed,
and set forth any explanation for the
excursion.
The amendments also require,
following the initial performance test
required under 40 CFR 60.8(a),
additional performance testing at least
once each month during the life of the
affected facility. During visits to existing
plants, EPA personnel have observed
that the emission control systems are
not always operated and maintained as
well as possible. The Administrator
believes that good operation and
maintenance of control systems are
essential and expects the monthly
testing requirement to help achieve this
goal. The Administrator has the
authority under section 114 of the Clean
Air Act to require additional testing if
necessary.
It is important to emphasize that the
purpose of the amendments is to allow
for inherent emission variability, not to
permit substandard control equipment
installation, operation or maintenance.
Unfortunately, proper control equipment
and proper operation and maintenance
are difficult to describe and may vary
considerably on a case-by-case basis.
There are, however, a few guidelines
that can be used as indicators.
The first guideline is that the control
equipment should be designed to meet
the original standard. This means a 95-
97 percent overall control efficiency
(capture efficiency times collection
efficiency) for a potroom group.
Equipment capable of this level of
control is described in the background
document (EPA 450/2-74-020a).
Assuming proper control equipment is
installed, the adequacy of operating and
maintenance procedures can be
evaluated on the basis of the frequency
of excursions above the original
standard. Based on the Sebree test
results, more than one excursion per
year (assuming performance tests are
conducted monthly) may indicate a
problem. Note, however, that legally
every performance test result could be
an excursion as long as proper
equipment, operation and maintenance
are shown.
As a guide to proper operation and
maintenance, the following are
considered basic to good control of
emissions:
(1) Hood covers should fit properly
and be in good repair;
(2) If the exhaust system is equipped
with an adjustable air damper system.
the hood exhaust rate for individual pots
should be increased whenever hood
covers are removed from a pot (the
exhaust system should not, however, be
overloaded by placing too many pots on
high exhaust);
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(3) Hood covers should be replaced as
soon as possible after each potroom
operation;
(4) Dust entrainment should be
minimized during materials handling
operations and sweeping of the working
aisles;
(5) Only tapping crucibles with
functional aspirator air return systems
(for returning gases under the collection
hooding) should be used; and
(6) The primary control system should
be regularly inspected and properly
maintained.
The amendments affect not only
prebake designs such as the Scbree
plant, but also Soderberg plants.
Available data for existing plants
indicate that Soderberg and prebake
plants have similar emission variability.
Thus, the Administrator feels justified in
extrapolating the conclusions about the
Sebree prebake plant to cover Soderberg
designs, It is unlikely that any new
Soderberg plant will be built due to the
high cost of emission control for these
designs. However, existing Soderberg
plants may be modified to such an
extent that they would be subject to
these regulations.
Under the amendments, anode bake
plants would be subject to the monthly
testing requirement, but emissions
would not be allowed under any
circumstances to be above the level of
the current bake plant standard. Since
there is no evidence that bake plant
emissions are as variable as potroom
emissions, there is no need to allow for
excursions above the bake plant
standard.
The amendments allow the owner or
operator of a new plant to apply to the
Administrator for an exemption from the
monthly testing requirement for the
primary control system and the anode
bake plant. The Administrator believes
that the testing of these system* as often
as once aach month may be
unreasonable given that (1) the
contribution of primary and bake plant
emissions (after exhausting from the
primary control system) to the total
emission rate is minor, averaging about
2.5 and 5 percent, respectively; (2)
primary and bake plant emissions are
much less variable than secondary
emissions; and (3) the cost of primary
and bake plant emissions sampling is
high. An application to the
Administrator for an exemption from
monthly testing would be required Jo
include [1] evidence that the primary
and bake plant emissions have low
variability; (2) an alternative testing
schedule; and (3) the method to be used
to determine primary control system
emissions for the purpose of calculating
total fluoride emissions from the
potroom group.
The Administrator estimates the costs
associated with monthly performance
testing to average about $4,200 for
primary tests, $5,100 for secondary tests,
and $4,200 for bake plant tests. These
estimates assume that (1) testing would
be performed by plant personnel; (2)
each monthly performance test would
consist of the average of three 24 hour
runs; (3) sampling would be performed
by two crews working 13-hour shifts; (4)
primary control system sampling would
be performed at a single point in the
stack; and (5) Sebree in-house testing
costs would be representative of
average costs for other new plants.
Although these assumptions may not
hold for all situations, the Administrator
believes they provide a representative
estimate of what testing costs would be
for new plants.
Also amended is the procedure for
determining the rate of aluminum
production. Previously, the rate was
based on the weight of metal tapped
during the test period. However, since
the weight of metal tapped does not
always equal the weight of metal
produced, undertapping or overlapping
during a test period would result in
erroneous production rates. The
Administrator believes it is more
reasonable to judge the weight of metal
produced according to the weight of
metal tapped during a 30-day period (720
hours) prior to and including the test
date. The 30-day period allows
overlapping and undertapping to
average out, and gives a more accurate
estimate of the true production rate.
Public Comment*
Upon proposal of the amendments, the
public was invited to submit written
comments on all aspects of the
amendment* and Reference Method 14
revision*. Thes« comments were
reviewed and considered in developing
the final amendments. All of the
comment* received are summarized and
discussed in Primary Aluminum
Background Information: Promulgated
Amendments (EPA 450/3-79-026).
The most significant change resulting
from these comments concerns the
requirement in Reference Method 14 to
periodically check the calibration of the
anemometers located in the roof
monitors of aluminum plant potrooms.
The use of anemometers is required by
the test method to determine the
velocity and flow rate of air exiting the
potroom roofs. Commenters felt that the
proposed requirement to check
anemometer calibration every month
was unnecessary and would lead to
substantially increased costs.
Review of anemometer calibration
data indicates that anemometer
calibration checks as often as every
month are unnecessary. Consequently,
Reference Method 14 has been revised
to require an anemometer calibration
check 12 months after the initial
anemometer installation. The results of
this check will be used to determine the
schedule of subsequent anemometer
checks.
Several commenters noted thai the
proposed requirement to conduct
performance testing at least once each
month throughout the life of a new
primary aJuminum plant would impose a
large economic burden on the plant In
general, the commenters believed that
testing at less frequent intervals should
be sufficient to determine compliance
with the standard. Three alternatives to
monthly performance testing were
suggested:
(1) One commenter believed that an
initial performance test would be
sufficient to demonstrate compliance.
Periodic visual inspections could then
be used to determine whether the
control systems were being properly
maintained. If the visual inspections
indicated that maintenance was poor,
monthly testing could then be required.
This procedure would not impose the
burden of monthly testing on the entire
industry.
(Z) Another commenter, noting that
the proposed monthly testing
requirement was excessively stringent,
recommended that criteria be
established for determining when
monthly testing is required. For
example, testing could be performed on
a semi-annual basis until a violation
occurred, when testing would revert to a
monthly schedule.
(3) A third commenter suggested that
the provision* permitting the
Administrator, upon application, to
establish »n alternative test schedule for
primary and bake plant emissions be
extended to Include secondary
emi*sions. For example, quarterly
testing of secondary emissions could be
required until a violation occurred.
Monthly testing could then be invoked
for some period of time, possibly six
months, until emissions were once again
consistently below the level of the
standard. Quarterly testing would then
resume.
During the development of the
amendments, the administrator learned
that the operation and maintenance of
aluminum plant emission control
systems had seriously deteriorated
during the past several years. The
Administrator believes that regular
emission testing will help remedy this
situation by providing an incentive for
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good operation and maintenance
throughout the life of the plant. Although
no continuous monitoring method is
available, the level of roof monitor
emissions provides a good indication of
the adequacy of operation and
maintenance procedures for the most
sensitive portion of the primary control
system: capture of the pot emissions.
The frequency of testing selectedonce
per monthis a judgmental compromise
between high testing costs (as would
occur with weekly tests) and the
possibility of inadequate maintenance
between tests (which seems more likely
to occur as the time between tests
increases).
In evaluating comments on the
proposed monthly testing requirement.
the administrator focused his attention
on costs. Since the cost of the monthly
testing requirement is less than 0.5
percent of the annualized costs of a
typical primary aluminum plant, the
Administrator considered the
requirement reasonable.
The original standards required
potroom emissions to be below 0.95 kg/
Mg (1.9 )b/ton) for prebake plants and
1.0 kg/Mg (2.0 Ib/ton) for Soderberg
plants. One commenter, noting that the
0.05 kg/Mg (0.1 Ib/ton) difference
between the standards is reasonable in
view of the differences between the two
types of plants, felt this same reasoning
should be followed in developing the
proposed never-to-be-exceeded limit of
1.25 kg/Mg (2.5 Ib/ton) which applied to
both prebake and Soderberg plants. The
commenter recommended that a never-
to-be-exceeded limit of 1.3 kg/Mg (2.6
Ib/ton) be established for Soderberg
plants while retaining the proposed 1.25
kg/Mg (2.5 Ib/ton) limit for prebake
plants.
This comment is incorporated in the
final amendments, which allow
emissions from Soderberg plants where
exemplary operation and maintenance
of the emission control systems has
been demonstrated to be as high as 1.3
kg/Mg (2.6 Ib/ton).
One commenter expressed concern
over the correct number or Reference
Method 14 sampling manifolds to be
located in potroom groups where two or
more potroom segments are ducted to a
common control system. The regulation
defines potroom group as an
uncontrolled potroom. a potroom which
is controlled individually, or a group of
potrooms or potroom segments ducted to
a common control system. In situations
where a potroom group consists of a
group of potroom segments ducted to a
common control system, the manifold
would be installed in only one potroom
segment. The manifold may not be
di\ ided among potroom segments
however, additional sampling manifolds
may be installed in the other segments,
if desired.
When only one manifold is located in
a potroom group, care must be taken to
ensure that operations are normal in the
potroom segments where manifolds are
not located, but which are ducted to the
same control system. During normal
operation, most pots should be
operating, no major upsets should occur.
and the operating and maintenance
procedures followed in each potroom
segment, including the segment tested,
should be the same. Otherwise, the
emission levels measured in the tested
potroom segment may not be
representative of emission levels in the
other potroom segments.
One commenter felt that the
amendments would unjustly require the
use of tapping crucibles with aspirator
air return systems, since the preamble
for the proposed amendment stated that
certain operating and maintenance
procedures, including the use of
aspirator air return systems, represent
good emission control and should be
implemented. Although this statement
reflects the Administrator's judgment
about which procedures would enable
the standards to be achieved, the
regulation does not actually require that
these procedures be implemented.
Instead these procedures provide useful
guidance for improving emission control
when the standards are being exceeded
If emissions are below 0.95 kg/Mg (1.9
Ib/ton) for prebake potrooms and 1.0
kg/Mg (2.0 Ib/ton) for Soderberg
potrooms, any combination of
procedures may be used. If emission
levels are between 0.95 and 1.25 kg/Mg
(1.9 and 2.5 Ib/ton) for prebake
potrooms or 1.0 and 1.3 kg/Mg (2.0 and
2.6 Ib/ton) for Soderberg pptrooms, the
regulation requires the owner or
operator of a plant to demonstrate that
exemplary operating and maintenance
procedures were used. Otherwise the
excursion is considered a violation of
the standard. The Administrator has not
defined exemplary operating and
maintenance procedures in the
regulation because different plants.
depending on plant design, may
incorporate different procedures, but the
basic procedures listed in the preamble
rationale proxide guidance as to which
operating and maintenance procedures
should be effected to reduce or prevent
excursions.
Several commenters expressed
concern that the standards of
performance and test methods would be
applied to existing primary aluminum
plants. It is emphasized, however, that
the standards and test methods apply
onlv to new. modified, or reconstructed
plants. Existing plants often differ in
design from new plants and cannot be
controlled to the same level, except at
much higher costs. As an aid to the
States in controlling emissions from
existing primary aluminum plants, the
Administrator has recently published
draft emission guidelines for existing
plants (44 FR 21754), These draft
guidelines may be obtained from the
U.S. EPA Library. Request Primary
Aluminum Draft Guidelines for Control
of Fluoride Emissions from Existing
Primary Aluminum Plants (EPA 450/2-
78-049a).
Another commenter was concerned
about the required length of each test
run Section 5.3.4 of Reference Method
14 states that each test run shall last at
least eight hours, and if a question exists
as to the representativeness of an eight-
hour period, a longer period should be
selected. It is essential that the sampling
period be representative of all potroom
operations and events, including
tapping, carbon setting, and tracking.
For most recently-constructed plants. 24
hours are required for all potroom
operations and events to occur in the
area beneath the sampling manifold.
Thus, a 24-hour sampling period would
be necessary for these plants.
Another commenter expressed
concern about the procedure for
conducting performance tests. The
General Provisions for standards of
performance for new stationary sources
|40 CFR 60 8(f)] state that each
performance test shall consist of the
arithmetic mean of three separate test
runs Although the results of the three
test runs are to be calculated separately.
the runs may be conducted
consecutive!}. as was done during the
Sebree test program.
One commenter suggested that the
rate of aluminum production, as used to
calculate final emission rates, be based
on the weight of metal tapped during the
month in which testing was performed
rather than on the test date. This, the
commenter believed, would be a more
convenient and practical method for
calculating the aluminum production
rate because production records are
commonly kept on a monthly basis The
Administrator believes, however, that if
the rate of aluminum production were
determined on a calendar-month basis.
as the commenter suggests, then in
situations where testing is conducted al
the beginning of a month, the final test
results would not be known until the
end of the month. This delay could
allow emissions to be above the
standard for nearly an entire month
before a violation could be determinpd
and corrective actions taken It is
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preferable thdt the test results be known
as soon as possible after the testing is
completed, as provided for in the
proposed and final amendments.
As a result of comments, several other
minor changes were made to the
proposal. These include provisions
allowing an owner or operator the
option of: (1) installing anemometers
halfway across the width of the potroom
roof monitor: (2) balancing the sampling
manifold for flow rate prior to its
installation in the roof monitor; or (3)
making anemometer installations non-
permanent.
Docket
The docket is an organized and
complete file of all the information
submitted to or otherwise considered in
the development of this rulemaking. The
principal purposes of the docket are: (1)
to allow interested parties to readily
identify and locate documents so that
they can intelligently and effectively
participate in the rulemaking process:
and (2) to serve as the record in case of
judicial review. The docket is available
for public inspection and copying, as
noted under ADDRESSES.
Miscellaneous
The proposed amendments contained
a revision to Section 60,8(d) of the
General Provisions which would have
allowed the owner or operator to give
less than 30 days prior notice of testing
if required to do so in specific
regulations. Since this revision has
already been promulgated with another
regulation (44 FR 33580), it is not
contained in the final amendments
promulgated here.
The final amendments do not alter the
applicability date of the original
standards. The standards continue to
apply to all new primary aluminum
plants for which construction or
modification began on or after October
23. 1974, the original proposal date.
As prescribed by section 111 of the
Clean Air Act, promulgation of the
original standards of performance (41
FR 3826) was preceded by the
Administrator's determination that
primary aluminum plants contribute
significantly to air pollution which
causes or contnbutes to the
endangerment of public health or
welfare. In accordance with section 117
of the Act, publication of the originally
proposed standards (39 FR 37730) was
preceded by consultation with
appropriate advisory committees,
independent experts, and Federal
departments and agencies.
It should be noted that standards of
performance for new sources
established under section 111 of the
Clean Air Act reflect:
' " " application of the best technological
system of continuous emission reduction
which (taking into consideration the cost of
achieving such emission reduction, and any
nonair quality health and environmental
impact and energy requirements) the
Administrator determines has been
adequately demonstrated (section lll(a)(l)].
Although there may be emission
control technology available that can
reduce emissions below those levels
required to comply with standards of
performance, this technology might not
be selected as the basis of standards of
performance due to costs associated
with its use. Accordingly, standards of
performance should not be viewed as
the ultimate in achievable emission
control. In fact, the Act requires (or has
the potential for requiring) the
imposition of a more stringent emission
standard in several situations.
For example, applicable costs do not
necessarily play as prominent a role in
determining the "lowest achievable
emission rate" for new or modified
sources locating in nonattainment areas,
i.e.. those areas where statutorily-
mandated health and welfare standards
are being violated. In this respect,
section 173 of the Act requires that new
or modified sources constructed in an
area which exceeds the National
Ambient Air Quality Standard (NAAQS)
must reduce emissions to the level
which reflects the "lowest achievable
emission rate" (LAER), as defined in
section 171(3) for such category of
source. The statute defines LAER as that
rate of emissions based on the
following, whichever is more stringent:
(A) The most stringent emission limitation
which is contained in the implementation
plan of any State for such class or category of
source, unless the owner or operator of the
proposed source demonstrates that such
limitations are not achievable, or
|B) The most stringent emission limitation
which is achieved in practice by such class or
category of source.
In no event can the emission rate exceed
any applicable new source performance
standard (section 171(3)).
A similar situation may arise under
the prevention of significant
deterioration of air quality provisions of
the Act (Part C). These provisions
require that certain sources (referred to
in section 169(1)) employ "best available
control technology" (BACT) as defined
in section 169(3) for all pollutants
regulated under the Act. Best available
control technology must be determined
on a case-by-case basis, taking energy,
environmental and economic impacts
and other costs into account. In no event
may the application of BACT result in
emissions of any pollutants which will
exceed the emissions allowed by any
applicable standard established
pursuant to section 111 (or 112) of the
Act.
In all events. State Implementation
Plans (SIP's) approved or promulgated
under section 110 of the Act must
provide for the attainment and
maintenance of NAAQS designed to
protect public health and welfare. For
this purpose, SIP's must in some cases
require greater emission reduction than
those required by standards of
performance for new sources.
Finally, States are free under section
116 of the Act to establish even more
stringent limits than those established
under section 111 and prospective
owners and operators of new sources
should be aware of this possibility in
planning for such facilities.
Section 317 of the Clean Air Act
requires the Administrator to prepare an
economic impact assessment and
environmental impact statement for
substantial revisions to standards of
performance. Although these
amendments are not substantial
revisions, certain economic information
was developed and is presented in
Primary Aluminum Background
Information: Promulgated Amendments
(EPA 450/3-79-026). The revisions to the
standards of performance were not
significant enough to warrant
preparation of an environmental impact
statement.
Dated: ]une 24.1980.
Douglas M. Costle,
Administrator.
PART 60STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
40 CFR Part 60 is revised as follows:
1. Subpart S is revised to read as
follows:
Subpart SStandards of Performance
for Primary Aluminum Reduction
Plants
Authority: Sections 111 and 301 (a) of the
Clean Air Act as amended (42 U.S.C. 7411,
7601(a)), and additional authority as noted
below.
Section 60.190 paragraph (a) is revised
as follows:
§ 60.190 Applicability and designation of
affected facility.
(a) The affected facilities in'primary
aluminum reduction plants to which this
subpart applies are potroom groups and
anode bake plants.
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Section 60.191 is revised to read as
follows:
§60.191 Definitions.
As used in this subpart. all terms not
defined herein shall have the meaning
gi\en them in the Act and in subpart A
of this part.
"Aluminum equivalent" means an
amount of aluminum which can be
produced from a Mg of anodes produced
by an anode bake plant as determined
by § 60.195(g).
"Anode bake plant" means a facility
which produces carbon anodes for use
in a primary aluminum reduction plant
"Potroom" means a building unit
which houses a group of electrolytic
cells in which aluminum is produced
"Potroom group" means an
uncontrolled potroom. a potroom which
is controlled individually, or a group of
potrooms or potroom segments ducted to
a common control system.
"Primary aluminum reduction plant"
means any facility manufacturing
aluminum by electrolytic reduction
"Primary control system" means an
air pollution control system designed to
remove gaseous and particulate
flourides from exhaust gases which are
captured at the cell,
"Roof monitor" means that portion of
the roof of a potroom where gases not
captured at the cell exit from the
potroom.
"Total fluorides" means elemental
fluorine and all fluoride compounds as
measured by reference methods
specified in § 60.195 or by equivalent or
alternative methods (see | 60.8(b))
Section 60.193 is revised to read as
follows:
§ 60.192 Standards for fluorides.
(a) On and after the date on which the
initial performance test required to be
conducted by § 60.8 is completed, no
owner or operator subject to the
provisions of this subpart shall cause to
be discharged into the atmosphere from
any affected facility any gases
containing total fluorides, as measured
according to § 60.8 above, in excess of
(1) 1.0 kg/Mg (2.0 Ib/ton) of aluminum
produced for potroom groups at
Soderberg plants: except that emissions
between 1.0 kg/Mg and 1.3 kg/Mg (2.6
Ib/ton) will be considered in compliance
if the owner or operator demonstrates
that exemplary operation and
maintenance procedures were used with
respect to the emission control system
and that proper control equipment was
operating at the affected faciht\ during
the performance tests;
(2) 0.95 kg/Mg (1.9 Ib/ton) of
aluminum produced for potroom groups
at prebake plants; except that emissions
between 0 95 kg/Mg and 1 25 kg/Mg (2.5
Ib/ton) will be considered in compliance
if the owner or operator demonstrates
that exemplary operation and
maintenance procedures were used with
respect to the emission control system
and that proper control equipment was
operating at the affected facility during
the performance test; and
(3) 0.05 kg/Mg (0.1 Ib/ton) of
aluminum equivalent for anode bake
plants.
(b) Within 30 days of any performance
test which reveals emissions which fall
between the 1.0 kg/Mg and 1.3 kg/Mg
levels in paragraph (a](l) of this section
or between the 0.95 kg/Mg and 1.25 kg/
Mg levels in paragraph (a)(2) of this
section, the owner or operator shall
submit a report indicating whether all
necessary control devices were on-line
and operating properly during the
performance test, describing the
operating and maintenance procedures
followed, and setting forth any
explanation for the excess emissions, to
the Director of the Enforcement Division
of the appropriate EPA Regional Office.
Section 60.193 is revised to read as
follows:
§ 60.193 Standard lor visible emissions.
(a) On and after the date on which the
performance test required to be
conducted by § 60.8 is completed, no
owner or operator subject to the
provisions of this subpart shall cause to
be discharged into the atmosphere:
(1) From any potroom group any gases
which exhibit 10 percent opacity or
greater, or
(2) From any anode bake plant any
gases which exhibit 20 percent opacity
or greater.
Section 60.194 paragraphs (a) and (b)
are revised as follows:
§60.194 Monitoring of operations.
(a) The owner or operator of any
affected facility subject to the provisions
of this subpart shall install, calibrate.
maintain, and operate monitoring
devices which can be used to determine
daily the weight of aluminum and anode
produced. The weighing devices shall
have an accuracy of ± 5 percent over
their operating range.
(b) The owner or operator of any
affected facility shall maintain a record
of daily production rates of aluminum
and anodes, raw material feed rates.
and cell orpotlme voltages.
(Section 114 of the Clean Air Act as amended
(42 U.SC. 7414))
Section 60.195 is reused as follows
§ 60.195 Te>t methods and procedures.
(d) Following the initial performance
test as required under § 60.8(a). an
owner or operator shall conduct a
performance test at least once each
month during the life of the affected
facility except when malfunctions
prevent representative sampling, as
provided under § 60.8(c). The owner or
operator shall gi\e the Administrator at
least 15 days ad\ ance notice of each
test. The Administrator may require
additional testing under section 114 of
the Clean Air Act.
(b) An owner or operator may petition
the Administrator to establish an
alternatee testing requirement thdt
requires testing less frequently than
once each month for a priman, control
system or an anode bake plant. If the
owner or operator show that emissions
from the primary control system or the
anode bake plant have low variability
during day-to-day operations, the
Administrator may establish such an
alternative testing requirement. The
alternative testing requirement shall
include a testing schedule and, in the
case of a primary control system, the
method to be used to determine pnmarj
control system emissions for the purpose
of performance tests The Administrator
shall publish the alternative testing
requirement in the Federal Register.
(c) Except as pro\ided in § 60.8(b).
reference methods specified in
Appendix A of this part shall be used to
determine compliance with the
standards prescribed in § 60.192 as
follows:
(1J For sampling emissions from
stacks:
(i) Method 1 for sample and veJocih
traverses.
(n) Method 2 for velocity and
volumetric flow rate.
(lii) Method 3 for gas analysis, and
(iv) Method 13A or 13B for the
concentration of total fluorides and the
associated moisture content.
(2) For sampling emissions from roof
monitors not employing stacks or
pollutant collection systems:
(i) Method 1 for sample and velociH
traverses.
(ii) Method 2 and Method 14 for
velocity and volumetric flow rate,
(iii] Method 3 for gas analysis, and
(iv) Method 14 for the concentration of
total fluorides and associated moisture
content.
(3) For sampling emissions from roof
monitors not employing stacks but
equipped with pollutant collection
systems, the procedures under § 60 8(b)
shall be followed.
(d'J For Method 13A or 13B, the
sampling time for each run shall be at
least 8 hours for any potroom sample
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and at least 4 hours for any anode bake
plant sample, and (he minimum sample
volume shall be 6.8 dscm (240 dscf) for
any potroom sample and 3.4 dscm {120
dscf) for any anode bake plant sample
except that shorter sampling times or
smaller volumes, when necessitated by
process variables or other factors, may
be approved by the Administrator.
(e) The air pollution control system for
each affected facility shall be
constructed so that volumetric flow
rates and total fluoride emissions can be
accurately determined using applicable
methods specified under paragraph (c)
of this section.
(f) The rate of aluminum production is
determined by dividing 720 hours into
the weight of aluminum tapped from the
affected facility during a period of 30
days prior to and including the final run
of a performance test.
(g) For anode bake plants, the
aluminum equivalent for anodes
produced shall be determined as
follows:
(1) Determine the average weight (Mg)
of anode produced in anode bake plant
during a representative oven cycle using
a monitoring device which meets the
requirements of § 60.194(a).
(2) Determine the average rate of
anode production by dividing the total
weight of anodes produced during the
representative oven cycle by the length
of the cycle in hours.
(3) Calculate the aluminum equivalent
for anodes produced by multiplying the
average rate of anode production by
two. (Note: An owner or operator may
establish a different multiplication
factor by submitting production records
of the Mg of aluminum produced and the
concurrent Mg of anode consumed by
potrooms.)
(h) For each run, potroom group
emissions expressed in kg/Mg of
aluminum produced shall be determined
using the following equation:
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Federal Register / Vol. 45. No. 127 / Monday, June 30, 1980 / Rules and Regulations
two alternatives. The first is to make a
iclocity traverse of the width of the roof
monitor where an anemometer is to be placed
and install the anemometer at a point of
average velocity along this traverse. The
traverse may be made with any suitable low
velocity measuring device, and shall be made
during normal process operating conditions.
The second alternative, at the option of the
tester, is to install the anemometer halfway
across the width of the roof monitor. In this
latter case, the velocity traverse need not be
conducted.
2.1.3 Recorders. Recorders, equipped with
suitable auxiliary equipment (e.g.
transducers) for converting the output signal
from each anemometer to a continuous
recording of air flow velocity, or to an
integrated measure of volumetric flowrate. A
suitable recorder is one that allows the
output signal from the propeller anemometer
to be read to within 1 percent when the
velocity is between 100 and 120 m/min (350
and 400 fpm). For the purpose of recording
velocity, "continuous" shall mean one
readout per 15-minute or shorter time
interval. A constant amount of time shall
elapse between readings. Volumetric flow
rate may be determined by an electrical
count of anemometer revolutions. The
recorders or counters shall permit
identification of the velocities or flowrate
measured by each individual anemometer.
2.1.4 Pilot tube. Standard-type pilot tube.
as described in Section 2.7 of Method 2, and
having a coefficient of 0.99±0.01.
2.1.5 Pilot tube (optional). Isolated, Type
S pilot, as described in Section 2.1 of Method
2. The pilot tube shall have a known
coefficient, determined as outlined in Section
4.1 of Melhod 2.
2.1.6 Differentia] pressure gauge. Inclined
manometer or equivalent, as described in
Section 2.1.2 of Method 2.
2.2 Roof monitpr air sampling system.
2.2.1 Sampling ductwork. A minimum of
one manifold system shall be installed for
each potroom group (as defined in Subpart S.
Section 60.191). The manifold system and
connecting duct shall be permanently
installed to draw an air sample from the roof
monitor to ground level. A typical installation
of a duct for drawing a sample from a roof
monitor to ground level is shown in Figure
14-1. A plan of a manifold system that is
located in a roof monitor is shown in Figure
14.2. These drawings represent a typical
installation for a generalized roof monitor
The dimensions on these figures may be
altered slightly to make the manifold system
fit into a particular roof monitor, but the
general configuration shall be followed.
There shall be eight nozzles, each having a
diameter of 0.40 to 0.50 m. Unless otherwise
specified by the AdminiMrator. Ihe length of
the manifold system from the first nozzle to
the eighth shall be 35 m or eight percent of
the length of the potroom (or potroom
segment) roof monitor, whichever is greater.
The duct leading from the roof monitor
manifold shall lie round with a diameter of
0.30 to 0.40 m. As shown in Figure 14-2, each
of the sample legs of the manifold shall have
a device, such as a blast gate or valve, to
enable adjustment of the flow mto each
sample nozzle.
BILLING CODE 6560-Ot-M
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IV-409
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Federal Register / Vol. 45, No. 127 / Monday, June 30, 1980 / Rules and Regulations
0.025 DIA
CALIBRATION
HOLE
DIMENSIONS IN METERS
NOT TO SCALE
Figure 14 2 Sampling manifold and nozzles
BILLING COM 66SO-01-C
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Federal Register / Vol. 45, No. 127 / Monday, June 30, 1980 / Rules and Regulations
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IV-411
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Federal Register / Vol. 45, No. 127 / Monday, June 30, 1980 / Rules and Regulations
The manifold sh
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Federal Register / Vol. 45, No. 127 / Monday, June 30, 1980 / Rules and Regulations
SIDE
(A)
FRONT
SIDE
(B)
FROM
Figure 144. Check of anemometer starting torque. A "y" gram weight placed "x" centimeters
from center of propeller shaft produces a torque of "xy" g-cm. The minimum torque which pro-
duces a 90° (approximately) rotation of the propeller is the "starting torque."
IV-413
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Federal Register / Vol. 45, No. 127 / Monday, June 30, 1980 / Rules and Regulations
o
UJ*
a
o
K
O
tr
<
FPM
(m/tnin)
20
(6)
40
(12)
60
(18)
80
(24)
100
(30)
120
(36)
140
(42)
THESHOLD VELOCITY FOR HORIZONTAL MOUNTING
Figure 145. Typical curve of starting torque vs horizontal threshold velocity for propeller
anemometers. Based on data obtained by R.M. Young Company, May, 1977.
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4 1.2 Thermocouple. Check the calibration
of the thermocouple-potentiometer system,
using the procedures outlined in Section 4.3
of Method 2. at temperatures of 0,100, and
150' C If the CHliliration is off by more than
5'C at any of the temperatures, repair or
replace the system; otherwise, the system can
be used.
4.1.3 Recorders and/or counters. Check
the calibration of each recorder and/or
counter (see Section 2.1.3) at a minimum of
three points, approximately spanning the
expected range of velocities. Use the
calibration procedures recommended by the
manufacturer, or other suitable procedures
(subject to the approval of the
Administrator). If a recorder or counter is
found to be out of calibration, by an average
amount greater than 5 percent for the three
calibration points, replace or repair the
sys'em: otherwise, the system can be used.
4.1 4 Manifold Intake Nozzles. In order to
balance the flow rates in the eight individual
nuzzles, proceed as follows: Adjust the
exhaust fan to draw a volumetric flow rate
(refer to Equation 14-1) such that the
entrance velocity into each manifold nozzle
approximates the average effluent velocity in
the roof monitor. Measure the velocity of the
air entering each nozzle by inserting a
standard pilot tube into a 2.5 cm or less
diameter hole (see Figure 14-2) located in the
manifold between each blast gate (or valve)
and nozzle. Note that a standard pilot tube is
used, rather than a type S, to eliminate
possible velocity measurement errors due to
cross-section blockage in the small (0.13 m
diameter) manifold leg ducts. The pitot tube
tip shall be positioned at the center of each
manifold leg duct. Take care to insure that
there is no leakage around the pilot tube.
which could affect the indicated velocity in
the manifold leg If the velocity of air being
didwn into each nozzle is not the same, open
or close earh blast gate (or valve) until the
velocity in each nozzle is the same Fasten
each blast gate (or vaNe) so that it will
remain in this position and close the pitot
port holes. This calibration shall be
performed when the manifold system is
installed Alternativelv. the manifoRi may be
prdissembled and the flow rates balanced on
the ground, before being installed.
4.2 Periodical performance checks.
Twelve months afler their iniUal installation,
ch«.k the calibration of the propeller
anemometers, thermocouple-potentiometer
system, and the recorders and/or counters as
in Section 4 1. If the above systems pass the
performance checks, (i.e., if no repair or
replacement of any component is necessary),
continue with the performance checks on a
12-month interval basis However, if any of
the above systems fail the performance
checks, repair or replace the system(s) that
failed and conduct the periodical
performance checks on a 3-mohth interval
basis, until sufficient information (consult
with the Administrator) is obtained to
establish a modified performance check
schedule and calculation procedure.
Note.If any of the above systems fatl the
initial performance checks, the data for the
past year need no! be recalculated.
5. Procedure.
5.1 Roof Monitor Velocity Determination.
5.1.1 Velocity estimate(s) for setting
isokinetic flow. To assist in setting isokinetic
flow in the manifold sample nozzles, the
anticipated average velocity in the section of
the roof monitor containing the sampling
manifold shall be estimated prior to each test
run. The tester may use any convenient
means to make this estimate (e.g.. the
velocity indicated by the anemometer in the
section of the roof monitor containing the
sampling manifold may be continuously
monitored during the 24-hour period prior to
the test run).
If there is question as to whether a single
estimate of average velocity is adequate for
an entire test run (e.g., if velocities are
anticipated to be significantly different
during different potroom operations), the
tester may opt to divide the test run into two
or more "sub-runs," and to use a different
estimated average velocity for each sub-run
(see Section 5.3.2 2.)
5.1 2 Velocity determination during a test
run. During the actual test run, record the
velocity or volumetric flowrate readings of
each propeller anemometer in the roof
monitor. Readings shall be taken for each
anemometer every 15 minutes or at shorter
equal time intervals (or continuously).
5.2 Temperature recording. Record the
temperature of the roof monitor every 2 hours
during the test run.
5.3 Sampling.
5.3.1 Preliminary air flow in duct. During
24 hours preceding the Jest, turn on the
exhaust fan and draw roof monitor air
through the manifold duct to condition the
ductwork. Adjust the fan to draw a
volumetric flow through the duct such that
the velocity of gas entering the manifold
nozzles approximates the average velocity of
the air exiting the roof monitor in the vicinity
of the sampling manifold.
5.3.2 Manifold isokinetic sample rate
adjustment(s).
5.3.2.1 Initial adjustment. Prior to the test
run (or first sub-run, if applicable: see Section
5.11 and 5.3.2 2), adjust the fan to provide the
necessary volumetric flowrate in the
sampling duct, so that air enters the manifold
sample nozzles at a velocity equal to the
appropriate estimated average velocity
determined under Section 5.1.1. Equation 14-1
gives the correct stream velocity needed in
the duct at the sampling location, in order for
Sample gas to be drawn isokinetically into
the manifold nozzles. Next, verify that the
correct stream velocity has been achieved, by
performing a pitot tube traverse of the sample
duct (using either a standard or type S pitot
tube); use the procedure outlined in Method 2.
8 (D .)' 1 min
(vj
(Equation 14-1)
(D,,)' 60 sec
Where:
.va = Desired velocity in duct at sampling
location. m/»ec.
Dn = Diameter of a roof monitor manifold
nozzle, m.
D,i = Diameter of duct at sampling location,
m.
vm = Average velocity of the air stream in
the roof monitor, m/min, as determined
under Section 5.1.1.
5.3.2.2 Adjustments during run. If the test
run is divided into two or more "sub-runs"
(see Section 5.1.1), additional isokinetic rote
adjustment(s) may become necessary during
the run. Any such adjustment shall be made
just before the start of a sub-run, using the
procedure outlined in Section 5.3.2.1 above.
Note.Isokinetic rate adjustments are not
permissible during a sub-run.
5.3.3 Sample train operation. Sample the
duct using the standard fluoride train and
methods described in Methods 13A and 13B.
Determine the number and location of the
sampling points in accordance with Method
1. A single train shall be used for the entire
sampling run Alternatively, if two or more
sub-runs are performed, a separate train may
be used for each sub-run; note, however, that
if this option is chosen, the area of the
sampling nozzle shall be the same (± 2
percent) for each train. If the test run is
divided into sub-runs, a complete traverse of
the duct shall be performed during each sub-
run.
5.3 4 Time per run. Each test run shall last
8 hours or more; if more than one run is to be
performed, all runs shall be of approximately
the same (± 10 percent) length. If question
exists as to the representativeness of an 8-
hour test, a longer period should be selected.
Conduct each run during a period when all
normal operations are performed underneath
the sampling manifold. For most recently-
constructed plants, 24 hours are required for
all potroom operations and events to occur in
the area beneath the sampling manifold.
During the test period, all pots in the potroom
group shall be operated such that emissions
are representative of normal operating
conditions in the potroom group.
5 3.5 Sample recovery. Use the sample
recovery procedure described in Method ISA
or!3B.
5.4 Analysis, Use the analysis procedures
described in Method 13A or 13B.
6. Calculations.
6.1 Isokinetic sampling check.
6.1.1 Calculate the mean velocity (vm) for
the sampling run. as measured by the
anemometer in the section of the roof monitor
containing the sampling manifold If two or
more sub-runs have been performed, the
tester may opt to calculate the mean velocity
for each sub-run.
6.1.2 Using Equation 14-1. calculate the
expected average velocity (va) in the
sampling duct, corresponding to each value of
vm obtained under Section 6.1.1.
6.1 3 Calculate the actual average velocity
(vj in the sampling duct for each run or sub-
run, according to Equation 2-9 of Method 2,
and using data obtained from Method 13.
6.1 4 Express each value v, from Section
6.1 3 as a percentage of the corresponding va
value from Section 6 1.2.
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6.1.4.1 If v, is less than or equal to 120
percent of vd, the results are acceptable (note
that in cases where the above calculations
have been performed for each sub-run, the
results are acceptable if the average
percentage for all sub-runs \e less than or
equal to 120 percent).
6.1.4.2 If v. is more than 120 percent of vd,
multiply the reported emission rate by the
following factor.
200
6.2 Average velocity of roof monitor
gases. Calculate the average roof monitor-
n
velocity using all the velocity or volumetric
flow readings from Section 5.1.2.
6.3 Roof monitor temperature. Calculate
the mean value of the temperatures recorded
in Section 5.2.
6.4 Concentration of fluorides in roof
monitor air (in mg F/m3).
6.4.1 If a single sampling train was used
throughout the run, calculate the average
fluoride concentration for the roof monitor
using Equation 13A-2 of Method 13A.
6.4.2 If two or more sampling trains were
used (i.e., one per sub-run), calculate the
average fluoride concentration for the run, as
follows:
(Equation 14-2)
Where:
C,=Average fluoride concentration in roof
monitor air, mg F/dscm.
F,=Total fluoride mass collected during a
particular sub-run, mg F (from Equation
13A-1 of Method ISA or Equation 13B-1
of Method 13B).
Vm(sui)=Total volume of sample gas
passing through the dry gas meter during
a particular sub-run, dscm (see Equation
5-1 of Method 5).
n=Total number of sub-runs.
6.5 Average volumetric flow from the roof
monitor of the potroom(s) (or potroom
segment(s)) containing the anemometers is
given in Equation 14-3.
Vw(A) (Ma) P,,,|293 K)
(760mmHg)
(Equation 14-3)
Where:
Qro=Average volumetric flow from roof
monitor at standard conditions on a dry
basis, m3/min.
A = Roof monitor open area. m2.
vml = Average velocity of air in the roof
monitor, m/min, from Section 6.2.
Pm = Pressure in the roof monitor; equal to
barometric pressure for this application,
mm Hg.
Tm = Roof monitor temperature. °C, from
Section 6.3.
Md = Mole fraction of dry gas. which is
given by:
M. = n B.J
Note.B»s is the proportion by volume of
water vapor in the gas stream, from Equation
5-3, Method 5.
7. Bibliography.
1. Shigehara, R. T. A guideline for
Evaluating Compliance Test Results
(Isokinetic Sampling Rate Criterion). U.S.
Environmental Protection Agency, Emission
Measurement Branch. Research Triangle
Park, North Carolina. August 1977.
|FR Doc 80-19516 Filed 6-27-80 8 45 am|
BILLING CODE 6SCO-01-M
IV-416
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SECTION V
STANDARDS OF
PERFORMANCE FOR
NEW STATIONARY
SOURCES
Proposed Amendments
-------
V. PROPOSED AMENDMENTS
Subpart
A General Provisions
Definitions
D Fossil-Fuel-Fired Industrial Steam Generators
Advance Notice of Proposed Rulemaking
E Incinerators
Review of Standards
F Portland Cement Plants
Review of Standards
G Nitric Acid Plants
Review of Standards
H Sulfuric Acid Plants
Review of Standards
J Petroleum Refinery
Review of Standards
Clarification of Definition
L Secondary Lead Smelters
Review of Standards
M Secondary Brass and Bronze Ingot Production
Review of Standards
N Iron and Steel Plants, Basic Oxygen Furnace
Review of Standards
0 Sewage Treatment Plants
Review of Standards
AA Electric Arc Furnaces (Steel Industry)
Review of Standards
CC Glass Manufacturing Plants
Proposed Standards
-------
Subpart
FF
JJ
KK
NN
PP
Appendix A
Appendix B
Stationary Internal Combustion Engines
Proposed Standards
Organic Solvent Cleaners
Proposed Standards
Lead-Acid Battery Manufacture
Proposed Standards
Automobile and Light Duty Truck Surface Coating Operations
Proposed Standards
Phosphate Rock Plants
Proposed Standards
Ammonium Sulfate Manufacture
Proposed Standards
Method 12 - Inorganic Lead Emissions from Stationary Sources,
see Subpart KK
Method 23 - Halogenated Organics from Stationary Sources,
see Subpart JJ
Method 24 (Candidate 1) - Volatile Content (as Carbon) of
Paint, Varnish, Lacquer, or Related Products, see Subpart MM
Method 24 (Candidate 2) - Volatile Organic Compound Content
(as Mass) of Paint, Varnish, Lacquer, or Related Products,
see Subpart MM
Method 25 - Total Gaseous Nonmethane Organic Emissions as
Carbon: Manual Sampling and Analysis Procedure, see Subpart MM
Performance Specification 1 - Opacity Continuous Monitoring
Systems in Stationary Sources
Performance Specification 2 - S02 and NOX Continuous Monitoring
Systems in Stationary Sources
Performance Specification 3 - C02 and 02 Continuous Monitors
in Stationary Sources
Performance Specification 4 - Carbon Monoxide Continuous
Monitoring Systems in Stationary Sources
-------
ENVIRONMENTAL
PROTECTION
AGENCY
STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
GENERAL PROVISIONS
SUBPART A
-------
Federal Register / Vol. 44. No. 106 / Thursday. May 31.1979 / Rule8 and Regulations
ENVIRONMENTAL PROTECTION
AGENCY
[ 40 CFR Parts 90 *>d 61]
[FRL 1085-1]
Standards of Performance for New
Stationary Sources and National
Emission Standards for Hazardous Air
Pollutants; Definition of "Commenced"
4BENCY: Environmental Protection
Agency (EPA).
ACTION: Proposed Rule.
SUMMARY: This action proposes an
amendment to the definition of
"commenced" as used under 40 CFR
Parts 60 and 61 (standards of
performance for new stationary sources
and national emission standards for
hazardous air pollutants). The
legislative history of the Clean Air Act
Amendments of 1977 indicates that EPA
should revise the definition of
"commenced" to be consistent with the
definition contained in the prevention of
significant deterioration requirements of
the Act. This proposal would effect that
revision.
DATES: Comments must be received on
or before July 30,1979.
ADDRESSES: Comments should be
submitted to Jack R. Farmer, Chief,
Standards Development Branch (MD-
13), Emission Standards and Engineering
Division, Environmental Protection
Agency, Research Triangle Park, North
Carolina 27711. Public comments
received may be inspected and copied
at the Public Information Reference Unit
(EPA Library) Room 2922, 401 M Street,
S.W., Washington, D.C.
FOR FURTHER INFORMATION CONTACT:
Don R. Goodwin, Director, Emission
Standards and Engineering Division
(MD-13), Environmental Protection
Agency, Research Triangle Park, North
Carolina 27711, telephone number 919-
541-5271.
SUPPLEMENTARY INFORMATION: For
many of EPA's regulations, it is
important to determine whether a
facility has commenced construction by
a certain date. For instance, as provided
under section 111 of the Clean Air Act,
facilities for which construction is
commenced on or after the date of
proposal of standards of performance
are covered by the promulgated
standards. The definition of
"commenced" is thus one factor
determining the scope of coverage of the
proposed standards. "Commenced" is
currently defined under 40 CFR Part 60
as meaning:
* * with respect to the definition of "new
source" in section lll(a)(2) of the Act that an
owner or operator has undertaken a
continuous program of construction or
modification or that an owner or operator has
entered into a contractual obligation to
undertake and complete, within reasonable
time, a continuous program of construction or
modification.
A similar definition (minus the
reference to section lll(a)(2)) is used
under 40 CFR Part 61. As provided under
section 112 of the Act, facilities which
commence construction after the date of
proposal of a national emission
standard for a hazardous air pollutant
are subject to different compliance
schedule requirements than those
facilities which commence before
proposal.
The Clean Air Act Amendments of
1977 include a definition of
"commenced" under Part CPrevention
of Significant Deterioration (PSD) of Air
Quality. The PSD definition of
"commenced" requires an owner or
operator to obtain all necessary
preconstruction permits and either (1) to
have begun physical on-site construction
or (2) to have entered into a binding
agreement with significant cancellation
penalties before a project is considered
to have "commenced."
On November 1,1977, Congress
adopted some technical and conforming
amendments to the Clean Air Act
Amendments of 1977. Representative
Paul Rogers presented a Summary and
Statement of Intent which stated:
In no event is there any intent to inhibit or
prevent the Agency from revising its existing
regulations to conform with the requirements
of section 165. In fact, the Agency should do
so as soon as possible. It is also expected
that the Agency will act as soon as possible
to revise its new source performance
standards and the definition of 'commenced
construction' for the purpose of those revised
standards to conform to the definition
contained in part C
In view of this background, EPA has
decided to make the definition of
"commenced" as used under Part 60
consistent with the definitions used
under the PSD requirement of Parts 51
and 52. Even though Congress did not
specify any changes to the definition
under Part 61, it is reasonable to also
change that definition to be consistent
with those under Parts 60, 51, and 52.
The manner in which the definition
would be interpreted is expressed in the
preamble to the PSD regulations 43 FR
26395-26396. For complete consistency
with the Clean Air Act and Parts 51 and
52, a new definition of "necessary
preconstruction approvals or permits"
has also been added.
EPA does not intend that sources
would be brought under the standards
by the revised definitions that would not
have been covered by the existing
definitions, The revised definitions
would be effective 30 days after
promulgation of the final definitions.
Facilities which have commenced
construction under the present
definitions before the effective date of
the revised definitions would be
considered to have commenced
construction under the revised
definitions, i.e., the revised definitions
would not be applied retroactively.
Note, however, that under the PSD
regulations, sources could be required to
apply control technology capable of
meeting the most recent standard of
performance even though that standard
is not applicable, because the applicable
standard of performance requirements
are only the minimum criteria for
granting a PSD permit.
During the public comment period,
comments are invited regarding the
impact of the revised definition. In
particular, comments are invited
regarding actual compliance problems
which may occur because of this
revision.
Dated: May 23,1979.
Douglas M. Costle,
Administrator.
It is proposed to amend 40 CFR Parts
60 and 61 by amending § § 60.2(i) and
61.02(d) and by adding §§ 60.2(cc) and
61.02(q) as follows:
PART 60STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
Subpart AGeneral Provisions
§60.2 Definitions.
(i) "Commenced" means, with respect
to the definition of "new source" in
section lll(a)(2) of the Act, either that:
(1) An owner or operator has obtained
all necessary preconstruction approvals
or permits and either has:
(i) Begun, or caused to begin, a
continuous program of physical on-site
construction of the facility to be
completed within a reasonable time; or
(U) Entered into binding agreements or
contractual obligations, which cannot be
cancelled or modified without
substantial loss to the owner or
operator, to undertake a program of
construction of the facility to be
completed within a reasonable time, or
(2) An owner or operator had
commenced construction before
(effective date of this definition) under
V-A-7
-------
Federal Register / Vol. 44. No. 106 / Thursday, May 31, 1979 / Proposed Rules
the definition of "commenced" in effect
before (effective date of this definition).
*****
(cc) "Necessary preconstruction
approvals or permits" means those
permits or approvals required under
Federal air quality control laws and
regulations and those air quality control
laws and regulations which are part of
the applicable State implementation
plan.
(Sec. 111. 301(a) of the Clean Air Act as
amended (42 U.S.C.7411, 7601(a))),
V-A-8
-------
ENVIRONMENTAL
PROTECTION
AGENCY
STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
FOSSIL FUEL-FIRED STEAM GENERATORS
SUBPART D
-------
Federal Register / Vol. 44. No. 126 / Thursday. June 26. 1979 / Proposed Rules
ENVIRONMENTAL PROTECTION
AGENCY
[40 CFR Part 60]
[FRL 1094-6]
Standards of Performance for New
Stationary Sources; Fossll-Fuel-Flred
Industrial Steam Generators
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Advance Notice of Proposed
Rulemaking. _^__^_
SUMMARY: EPA seeks comments on its
plan to develop and implement new
source performance standards for air
pollutants from fossil-fuel-fired
industrial (non-utility) steam generators.
The Clean Air Act, as amended, August
1977, requires the EPA to develop
standards for categories of fossil-fuel-
fired stationary sources. The standards
will require application of the best
systems of emission reduction for
particulates, sulfur dioxide, and nitrogen
oxides to new industrial steam
generators.
DATES: Comments must be received on
or before August 27,1979.
ADDRESS: Comments should be
submitted to the Central Docket Section
(A-130), United States Environmental
Protection Agency, 401 M Street, S.W.
Washington, D.C. 20460, ATTN: Docket
No. A79-02.
FOR FURTHER INFORMATION CONTACT:
Stanley T. Cuffe, Chief, Industrial
Studies Branch (MD-13), Emission
Standards and Engineering Division,
United States Environmental Protection
Agency, Research Triangle Park, North
Carolina 27711, (919) 541-5295.
SUPPLEMENTARY INFORMATION: In
December 1971, pursuant to Section 111
of the Clean Air Act, the Administrator
promulgated standards of performance
for particulate, sulfur dioxide, and
oxides of nitrogen from new or modified
fossil fuel fired steam generators with
greater than 250 million BTU/hour heat
input (40 CFR 60.60). Since that time, the
technology for controlling these
emissions has been improved. In August
1977, Congress adopted amendments to
the Clean Air Act which specified that
the Environmental Protection Agency
develop standards of performance for
categories of fossil-fuel-fired stationary
sources. The standards are to establish
allowable emission limitations and
require the achievement of a percentage
reduction in the emissions. EPA is
required to consider a broad range of
issues in promulgating or revising a
standard issued under Section 111 of the
Clean Air Act.
Pursuant to the requirements of the
Act, EPA developed and proposed on
September 19,1978, a revised standard
applicable to fossil-fuel-fired utility
boilers with heat input greater than 250
MM BTU/hour.
Development of Industrial Boiler
Standard
In June 1978, the Agency initiated a
program to develop standards which
would apply to all sizes and categories
of industrial (non-utility) fossil-fuel-fired
steam generators. In this program, the
Agency is studying the technological,
economic, and other information needed
to establish a basis for standards for
particulate, sulfur dioxide and oxides of
nitrogen emissions from fossil-fuel-fired
steam generators. Pertinent information
is being gathered on eight technologies
for reducing boiler emissions: oil
cleaning and existing clean oil, coal
cleaning and existing clean coal;
synthetic fuels; fluidized bed
combustion; particulate control; flue gas
desu'furization; NOx combustion
modifications; and NOx flue gas
treat.-nent. The studies for each
technology will discuss the
characteristics, emission reduction
methods and potential control costs,
energy and environmental
considerations and emission test data. A
status report on the studies was
presented to the National Air Pollution
Control Techniques Advisory
Committee (NAPCTAC), on January 11.
1979. Future presentations to the
NAPCTAC will be announced in the
Federal Register. The final technological
and economic documentation necessary
to support the standards is scheduled for
completion by June 1980. Interested
persons are invited to participate in
Agency efforts by submitting written
data, opinions, or arguments as they
may desire. The Agency is specifically
interested in information on the
following subjects.
a. Should one standard be proposed
for all industrial applications or should
standards be set for separate industrial
categories?
b. Should a single standard be
proposed for all sizes of industrial
boilers or should several standards be
proposed for various boiler size
categories?
c. Should emerging technologies such
as solvent refined coal, fluidized bed
combustion, and synthetic natural gas
be exempt from industrial boiler
standards, should they have separate
standards, or should they be required to
meet the same standards as
conventional boilers burning natural
fuels?
d. Will enforcement of standards at
cogeneration facilities present special
problems which should be considered?
e. How prevalent is the use of lignite
and anthracite coal in industrial boilers?
f. Are there special problems which
should be considered when controlling
partioulate, SO,, or NO, emissions from
combustion of lignite or anthracite
coals?
Dated: June 13,1979.
Douglas M. Costle,
Administrator.
(FR Doe. 79-20058 Filed 6-27-Tfc S.-45 amj
BILLING CODE MW-01-M
V-D-2
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ENVIRONMENTAL
PROTECTION
AGENCY
STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
INCINERATORS
SUBPARTE
-------
Federal Register / Vol. 44, No. 229 /.Tuesday, November 27,1979 / Proposed Rules
40 CFR Part 60
[FRL 1310-2]
Standards of Performance for New
Stationary Sources: Incinerators;
Review of Standards
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Review of standards.
SUMMARY: EPA has reviewed its
standard of performance for municipal
incinerators (40 CFR 60.50, Subpart E).
The review is required under the Clean
Air Act, as amended August 1977. The
purpose of this notice is to announce
EPA's intent to investigate the
establishment of a revised standard
which would be consistent with the
performance capabilities of
demonstrated best available control
technology and which would include a
limitation on the opacity of emissions
DATES: Comments must be received by
January 28, 1980.
ADDRESS: Send comments to. Central
Docket Section (A-130), U.S.
Environmental Protection Agency, 401 M
Street SW., Washington, D.C. 20460,
Attention: Docket A-79-18. Comments
should be submitted in duplicate if
possible.
FOR FURTHER INFORMATION CONTACT:
Mr. Robert Ajax, Telephone: (919) 541-
5271. The document "A Review of
Standards of Performance for New
Stationary SourcesIncinerators"
(EPA-450/3-79-009) is available upon
request from Mr. Robert Ajax (MD-13),
Emission Standards and Engineering
Division, U.S. Environmental Protection
Agency, Research Triangle Park. N.C
27711.
SUPPLEMENTARY INFORMATION:
Background
N'evv Source Performance Standards
(\SPS) for incinerators were
promulgated by the Environmental
Protection Agency on December 23, 1971
(40 CFR 60.50, Subpart E). These
standards regulate the emission of
particulate matter to the atmospheie
from municipal solid waste incinerators
having charging rates greater than 45 Mg
(50 tons) per day. These regulations
apply to any affected facility which
commenced construction or
modification after August 17,1971
The Clean Air Act Amendments of
1977 require that the Administrator of
the EPA review and, if appropriate,
revise established standards of
performance for new stationary sources
at least every 4 years [Section
lll(b)(l)(B)]. Following adoption of the
Amendments, EPA contracted with the
MITRE Corporation to undertake a
review of the municipal incinerator
industry and the current standard. The
MITRE review was completed in March
1979. This notice announces EPA's
decision regarding the need for revision
of the standard. Comments on the
results of this review and on EPA's"
decision are invited.
Findings
Industry Status: In 1972 there were 193
incinerator plants operating in the U.S.
By 1977 this number had decreased to
103 plants which include a total of 252
furnaces and a total solid waste
disposal capacity of about 36,000 Mg/
day (40,000 tons/day). The estimated
national particulate emissions from
municipal incineration in 1975 were
between 60,000 and 100,000 tons or
between 0.4 and 0.6 percent of all
particulate emissions in the U.S.
Since 1971 five new incinerator
facilities involving a total of eighfnew
furnaces with a combined capacity of
2,700 Mg/day (2,970 tons/day) have
become operational. In 1978,17 cities
were identified where new incinerators
are planned or under construction. Both
existing units and the units which are
planned or under construction are
concentrated primarily in the Northeast
and Midwest.
Coincineration: A factor having an
increasingly important impact on the use
of incineration as a waste disposal
process is the increasing cost of energy
and the relatively new concept of
resource recovery not only for recycling
of material but also for utilization of the
energy content of solid waste as a
processed fuel source. A recent survey
indicates that there are at least 28
resource recovery systems in operation,
under construction, or in the final
contract stage. Total capacity of these
operations will be about27,000 Mg/day
(30,000 tons/day), or about three-fourths
of the current installed incinerator
capacity. For the most part, these
systems are characterized by
substantial processing of solid waste
into usable recycled material and a
homogenous fuel.
The processing of solid waste prior to
combustion is a growing trend that has
implications in the definition of
incineration and the applicability of the
standard. Refuse derived fuel (RDF) may
be used in an industrial or utility boiler
which may or may not be located at the
new solid waste processing center.
Similarly, RDF may be used to provide
fuel for incinerating sewage sludge in a
fluidized bed reactor. Such
coincineration of municipal solid waste
and sewage sludge has been practiced
in Europe for several years and on a
limited scale in the U.S. Where energy
resources are scarce and land disposal
is economically or technically
"unfeasible, the recovery of the heat
content of dewatered sludge as an
energy source will become more
desirable. Due to the institutional
commonality of these wastes and
advances in the preincineration
processing of municipal refuse to a
waste fuel, many communities may find
joint incineration in energy recovery
incinerators an economically attractive
alternative to their waste disposal
problems.
Coincineration of municipal solid
waste and sewage sludge as described
above is not explicitly covered in 40
CFR 60. The particulate standard for
municipal solid waste described in
Subpart E (0.18 grams/dscm or 0.08
grains/dscf at 12 percent CO2) applies to
the incineration of municipal solid waste
in furnaces with a capacity of at least 45
Mg/day (50 tons/day). Subpart 0, the
particulate standard for sewage sludge
incineration (0.65 grams/kg dry sludge
input or 1.3 Ib/ton dry sludge), applies to
any incinerator that burns sewage
sludge with the exception of small
communities practicing coincineration.
When coincineration is practiced,
determination of the applicability of the
two standards is made by EPA's Office
of Enforcement according to policies
which are described in the information
document identified at the beginning of
this notice. Such determinations ere not
straight forward, however, due to the
differing form of the two standards and
the relative stringency which, in terms
of particulate matter concentration or
grain loading, differs by a factor of more
than two.
Particulate Matter Emissions and
Control Technology
Control systems on municipal
incinerators have evolved from the use
of simple settling chambers which
remove large particles, to the use of
electrostatic precipitators (ESPs) that
remove up to 99 percent of all
particulate matter. Many of the
incinerators constructed prior to 1971
utilized mechanical cyclone collectors
with removal efficiencies in the range of
60 to 80 percent. Various scrubber
techniques including the submerged
entry of gases, the spray wetted-wall
cyclone, and the venturi scrubber were
also employed. High efficiency
electrostatic precipitators were utilized
in a limited number of cases.
Since the adoption in 1971 of the new
source performance standard, the
control device which has been most
widely used and which has been most
V-E-2
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Federal Register / Vol. 44. No. 229 / Tuesday. November 27, 1979 / Proposed Rules
effective is the electrostatic precipitator
A limited number of venturi scrubbers
and, in one case, a fabric filter have also
been employed.
In this review of the standard, a total
of 19 emission tests were identified
which had been performed on 14
incinerators. The control equipment on
these incinerators was designed to
comply with the Federal new source
performance standard for particulate
matter or State or local standards which
are as stringent or more stringent than
the NSPS. The emission tests in each
case were performed with EPA Method
5. A summary of the test results is
provided in Table 1.
Table \.-Munapal Incinerator Test Results
Stale
City/name
(Tons/day)
Control
Test results
Massachusetts
Massachusetts
Tennessee . .
Virginia
Utah . ..
District ol Columbia ...
Ntmois
Maryland
Pennsylvania
Pennsylvania
Illinois
Kentucky
Wisconsin
Rhode Island
Nashville
Norfolk (Navy)
Ogden-3
Washington . .
Chicago NW
EC Philadelphia.
NW Philadelphia
Calumet
Louisville
Sheboygan Falls
Pawlucket .
The results shown in Table 1 indicate
that ESP control technology is capable
of limiting emissions to the values well
below the 0.18 g/dscm (0.08 gr/dscf)
level at 12 percent COj. Specifically, the
results from 11 tests performed at 9
facilities employing electrostatic
precipitators showed results ranging
from 041 to 0.14 g.dscm (0.018 to 0.06 gr/
dscf) at 12 percent CO2; 10 of the 11
were below 0.114 g/dscm (0.05 gr/dscf)
The Baltimore Number 4 incinerator
emission control system meets the strict
Maryland standard for incinerators of
0.07 g/dscm (0.03 gr/dscf] at 12 percent
CO2. Similarly, the Saugus,
Massachusetts, facility was designed for
the State standard of 0.11 g/dscm (005
gr/dscf) at 12 percent CO-i and was
successfully tested at this level of
compliance.
The use of scrubbers on municipal
incinerators has met with mixed results
and an overall difficulty in complying
with the particulate emission standard
Although the data obtained from five
tests at three venturi scrubber-
controlled sources ranged from 0.015 to
0.166 g/dscm (0.046 to 0.0775 gr/dscf).
the scrubber performance results, which
are discussed in more detail in the
information document, indicate that
venturi scrubbers for control of
municipal waste particulate emissions
may involve considerable risk of
nonattainment of the current NSPS. The
150
600
360
280
150
200
400
300
300
300
200
200
30-90
200
FF
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
ESP
VS (15)
VS (15-18)
S(7-8|
VS (35-40)
(Gr/dscf at
12 pet CO,)
0024
0049
0016
005
0045
0 040/0 06
0 030/0 050
0025
0047
0046
0 046/0 049
005/006
011
0416
00775
Year
1975
1976
1976
1976
1974
1973
1971/75
1976
1977
1976
1974
1976
1977
1976
1976
Pawtucket facility venturi scrubber, for
example, operates at pressure drops
higher than the original design to barely
meet the standard of 0.18 g/dscm (0.08
gr/dscf) at 12 percent CO2.
The Sheboygan Falls, Wisconsin,
incinerator utilizes a spray chamber
with baffles. Although reportedly
designed to meet a 0.08 gr/dscf
standard, this type of control technology
would not normally be expected to
exhibit the control efficiency necessary
to obtain the standard.
Since 1971, only the East Bridgewater,
Massachusetts, facility has been tested
with a fabric filter control device. In
1975, that facility tested at 0.054 g/dscm
(0.024 gr/dscf) at 12 percent CO2, well
below the Massachusetts standard of
0.11 g/dscm (0.05 gr/dscf) at 12 percent
CO2. However, problems of bag and
baghouse corrosion and periodic high
opacity observations have persisted
Currently, Framingham,
Massachusetts, \a the only other
municipal incinerator facility with a
fabric filter control system. The
specially coated bags are designed to
prevent deterioration and to achieve
0.07 g/dscm (0.03 gr/dscf) at 12 percent
CO,.
Gaseous and Trace Metal Emissions
Gaseous and trace metal emissions
are not specifically controlled under the
present NSPS although the incinerator
and the particulate matter control
equipment do limit such emissions.
Among possible gaseous emissions, the
potential for high levels of hydrochloric
acid (HCL) from the increased
incineration of poly vinyl chlorides has
received particular attention. Similarly.
lead and cadmium have been subject to
several studies. Cadmium emissions are
reported to represent approximately 0.2
percent of all particulate emissions and
about 0.4 percent of emissions less than
2 microns. Lead concentrations are
reported to represent about 4 percent of
all particulate matter and 11 percent of
respirable particulates emitted from the
scrubber. Emission factors are 9X10~'
kg/Mg (18X10'Mb/ton) refuse for
cadmium and 1.9X10"'kg/Mg (3.8X10"'
Ib/ton) refuse for lead.
In this review of the current NSPS no
new findings were identified which
indicate the need for a specific,
nationally applicable limitation on the
gaseous or trace metal emissions. There
is, however, currently a program
underway within EPA to independently
look at the need to regulate cadmium
from incinerators and other sources.
Separate documents have been prepared
which examine emissions, resulting
atmospheric concentrations, and
population exposure. These documents
are part of an overall EPA program to
satisfy requirements of the 1977 Clean
Air Act to evaluate the need to regulate
emissions of cadmium to the air.
Opacity
The current NSPS does not contain a
standard for opacity because testing of a
limited number of incinerators priot to
promulgation of the standard in 1971 did
not indicate a consistent relationship
between emission opacity and
particulate mass concentrations.
However, a survey of current State
regulations shows that every State has
an opacity standard for new
incinerators of 20 percent or stricter
except Illinois (30 percent), Indiana (40
percent), and Delaware (no standard)
Maryland has a "no visible emissions"
standard and the District of Columbia
has a new source ban on the
incineration of municipal waste.
However, data were not found in this
review of the NSPS to determine
whether sources are consistently in
compliance with these limits.
Conclusions
Based upon a review of the current
NSPS and other available information as
summarized above, EPA concludes that
there is a need to undertake a program
to revise the standard. This program,
which is expected to begin in FY 1980,
will be directed toward:
V-E-3
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Federal Register / Vol. 44. No. 229 / Tuesday, November 27,1979 / Proposed Rules
(1) Investigation of a more restrictive
particulate matter limitation consistent
with the capabilities of the best
available technology. This is based upon
the available data which indicate that
the capability of electrostatic
precipitators applied to incinerators has
improved measurably since the standard
was developed in 1971. This
investigation will include analysis of the
costs associated with a more restrictive
standard.
(2) Establishment of an opacity
standard. Such a standard is considered
important by EPA as a means for
assessing proper operation and
maintenance of particulate matter
control equipment and is included in
most of the Agency's particulate matter
NSPS. Although a relationship between
particulate mass and opacity was not
established when the standard was
adopted in 1971, the additional number
of well controlled plants which are now
in operation and the widespread
existence of State opacity limits are
expected to provide a basis for
estalishment of an opacity standard.
Consistent with EPA policy, such a
standard would not be more restrictive
than the particulate mass standard.
(3) Establishment of a consistent basis
for the limitation of particulate
emissions from differing combustion
devices independent of the fuel or waste
material being fired. While a single
standard is probably not possible, there
is a need to investigate the possibility of
expressing standards for sludge
incinerators, and municipal incinerators
on a common basis, and of making the
standards more uniform. To do so, EPA
plans to closely coordinate the
development of the industrial and
waste-fired boiler standards which are
now underway, and the planned
revision of the sewage sludge
incinerator standard and the municipal
incinerator standard.
(4) In addition, if the need to reduce
cadmium emissions is indicated as a
result of the EPA program noted above,
appropriate action will be taken to limit
cadmium emissions.
Public Participation
All interested persons are invited to
comment on this review, the conclusions
and EPA's planned action.
Dated November 16, 1979.
Barbara Blum,
Acting Administrator
|FR Doc 79-36474 Filed 11-26-79 845 dm]
V-E-4
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ENVIRONMENTAL
PROTECTION
AGENCY
STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
PORTLAND CEMENT PLANTS
SWMRT F
-------
Federal Register / Vol. 44. No. 205 / Monday October 22. 1979 / Proposed Rules
40 CFR Part 60
Standards of Performance for New
Stationary Sources: Portland Cement
Plants; Review of Standards
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Review of Standards.
SUMMARY: EPA has reviewed the
standards of performance for portland
cement plants (40 CFR 60.60). The
review is required under the Clean Air
Act, as amended August 1977. The
purpose of this notice is to announce
that, based on an assessment of the
industry, applicable control technology,
and results of performance tests
conducted pursuant to the standard,
EPA has determined that no revision to
the particulate emission limitation is
needed but that the standard should be
revised to require continuous opacity
monitoring.
DATES: Comments must be received by
December 21,1979.
ADDRESS: Comments should be
submitted to the Central Docket Section
(A-130), U.S. Environmental Protection
Agency, 401 M Street, S.W.,
Washington, D.C. 20460, Attention:
Docket No. A-79-19.
The document, "A Review of
Standards of Performance for New
Stationary SourcesPortland Cement
Industry" (EPA-450/3-79-012), is
available upon request from Mr. Robert
Ajax (MD-13), Emission Standards and
Engineering Division, Environmental
Protection Agency, Research Triangle
Park, North Carolina 27711.
FOR FURTHER INFORMATION CONTACT:
Mr. Robert Ajax, telephone: (919) 541-
5271.
SUPPLEMENTARY INFORMATION:
Background
On August 17,1971, the Environmental
Protection Agency proposed a standard
under Section 111 of the Clean Air Act
to control particulate matter emissions
from portland cement plants. The
standard, promulgated on December 23,
1971, applies to any facility constructed
or modified after August 17,1971, which
manufactures portland cement by either
the wet or dry process. Specific affected
facilities are the: kiln, clinker cooler,
raw mill system, finish mill system, raw
mill dryer, raw material storage, clinker
storage, finished product storage,
conveyor transfer points, bagging, and
bulk loading and unloading and
unloading systems.
The standard prohibits the discharge
into the atmosphere from any kiln any
gases which:
1. Contain particulate matter in excess
of 0.15 kg/Mg (0.30 Ib/ton) feed to the
kiln, or
2. Exhibit greater than 20 percent
opacity.
The standard prohibits the discharge
into the atmosphere from any clinker
cooler any gases which:
1. Contain particulate matter in excess
of 0.050 kg/Mg (0.10 li/ton) feed (dry
basis) to the kiln, or
2. Exhibit 10 percent opacity or
greater.
The standard prohibits the discharge
into the atmosphere from any affected
facility other than the kiln and clinker
cooler any gases which exhibit 10
percent opacity, or greater.
The Clean Air Act Amendments of
1977 require that the Administrator of
the EPA review and, if appropriate,
revise established standards of
performance for new stationary sources
at least every 4 years [Section
lll[b)(l)(B)]. This notice announces that
EPA has undertaken a review of the
standard of performance for portland
cement plants. As a result of this review,
EPA has concluded that the present
particulate emission limit is appropriate,
and does not need revision. However, a
provision to require opacity monitoring
should be added. In addition, EPA is,
however, planning to undertake a
program, in its Office of Research and
Development, to investigate and
demonstrate methods such as
combustion modifications which could
reduce NO, emissions from combustion
used in process sources such as cement
plants. Positive results from this
program would form the basis for a
possible revision to the standard in 1982
or 1983. Comments on these findings and
plans are invited.
Findings
Industry Status
Capacity. There are currently 53
cement companies producing portland
cement in the U.S. The 53 companies
operate 158 cement plants throughout
the U.S. with single plant capacity
ranging from 50,000 Mg to 2,161,000 Mg
per year. The industry also includes 8
plants with only clinker grinding
facilities which use either an imported
or domestic clinker as feed material.
Cement plants are found in nearly every
State because of the high cost of
transportation. The actual clinker
capacity of these plants is also
distributed throughout the U.S., although
some regions have little capacity due to
a lack of demand; and although many
areas of the Country are presently
experiencing cement shortages and
delays, announced capacity increases in
these areas are still small.
Energy Considerations. The portland
cement industry is very energy intensive
with energy costs accounting for
approximately 40 percent of the cost of
cement. Accordingly, significant
emphasis in the industry is on increasing
energy efficiency. For this reason,
almost all new and planned construction
will use the dry process which can be
twice as energy efficient as the wet
process. Additional savings can be
realized by using preheaten, ptdaBy
suspension preheaten.
These process change* have both
positive and negative effect! on
particulate emissions. The replacement
of wet process units with dry process
units increases potential emissions,
particularly in the grinding, mixing,
blending, storage, and feeding of raw
materials to the kiln. The suspension
preheater, on the other hand, tends to
decrease particulate emissions due to its
multicyclone construction. It also
ensures more thorough contact of the
kiln exhaust gases with the feed
material which may increase sorption of
sulfur oxide from the exhaust on the
feed.
Economic Considerations. Almost aH
cement produced is utilized by the
construction industry. As a result, the
production of cement follows the
cyclical pattern of the construction
industry. Relatively high cement
production has occurred during periods
of growth in new home and other
construction markets, and production
has decreased in such periods of
recession as occurred in 1973-1975.
In contrast, over the short term,
production capacity has not closely
paralleled actual production. This is due
apparently to the lead time required to
add capacity, to the difficulty in
accurately predicting future demand,
and to economic and other factors
including the effect of pollution control
requirements on the closure of old,
marginal plants.
An examination of production and
capacity over the past 10 years suggests
the difficulty which the industry has
experienced in attempting to meet
demand while avoiding excess capacity.
In the early 1970's, utilization of
production capacity was greater than 90
percent. However, wage and price
controls were in effect from 1971 to 1973
during which time the industry
experienced its lowest profit margin
since the 1930's. New plant construction
was postponed while some older plants
were being closed. As a result, regional
cement shortages occurred in 1972-1973.
When price controls were removed in
V-F-2
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Federal Register / Vol. 44. No. 205 / Monday, October 22, 1979 / Proposed Rules
1973, the price of cement jumped 14
percent and some new capacity
construction was begun. Shortly
thereafter, the Country entered a
recession and cement production fell to
70 percent of capacity.
The cyclic occurrence of high demand
exceeding capacity has been evidenced
again in the past several years. The
rapid growth in the construction
industry since 1975 has increased the
demand for cement and parts of the U.S.
have seen shortages, particularly in the
West. At the »ame time, the industry has
not rapidly added new capacity.
although mt Bureau of Mines project*
high demand in the early 1980's.
In considering whether pollution
control costs influenced the recent lag in
capacity, die Council on Wage and Price
Stability concluded that:
... ttw added pollution control cost* do
change the way a firm would consider a new
investment decision by »«aHrig larger price
increases necessary for the expenditure* to
be committed, this does not mean that the
imposition of these controls has necessarily
cause any reduction in new capacity
expenditure* in the cement industry.
However, this analysis does leave open the
possibility that aa investment decision could
be changed for a marginal plant because of
pollution control cost* (particularly a plant
selling cement for $40 per ton and using a 12
percent rate of return). (Prices and Capacity
Expansion in the Cement Industry, Council
on Wage and Price Stability, Washington,
B.C., 1977.)
Since cement is already selling for as
high as $53 per ton on the West Coast, it
is very likely that capital investment
will not be stifled by pollution control
expenditures.
Emission Control Status
Fifty-one cement kilns and clinker
coolers have been identified which are
operating and are subject to the new
source performance standard. Of these,
49 are in compliance with 0.15 kg/Mg
kiln feed (kiln) and 0.05 kg/Mg kiln feed,
(cooler) emission limit*. One completed
kiln has only recently been tested and
data are not available; and one facility
has notified its State authority that it
cannot meet the standards. Also, five
cement kilns potentially subject to the
standard were identified for which data
were not available. The number of
sources with other NSPS-affected
facilities was not determined, although
there are none reported that are not in
compliance with the applicable 10
percent opacity standard.
For the 29 kilns and 20 clinker cooler*
which were in compliance, the kiln test
results averaged 0.073 kg/Mg and
ranged from a high of 0.142kg/Mg feed
to a low of 0.013kg/Mg feed. The range
for kilns with emissions controlled by
ESP is 0.142 to 0.020 kg/Mg, and for kilns
with fabric filter baghouses the range is
0.132 to 0.013 kg/Mg dry kiln feed. The
data indicate that neither the ESP nor
the baghouse is significantly better at
controlling cement kiln particulate
matter emissions.
Cement plant clinker coolers have
been tested at emission levels ranging
from a high of 0.061 kg/Mg to a low of
0.005 kg/Mg dry kiln feed with a mean
of 0.024 kg/Mg. Compliance test data on
a single wet scrubber show emissions
near the mean emission level for fabric
filter baghouse controls (0.022 kg/Mg).
Data for affected facilities using gravel
bed filters indicate a mean emission
level of 0.034 kg/Mg dry feed (0.023-
0.045kg/Mg).
The compliance test data were
analyzed to determine if the type of
control technology, the process type (i.e.,
wet or dry), or Interaction of process
type and control technology affected the
ability to control the emission of
particulate matter from portland cement
kilns or clinker coolers. This analysis
indicates that no control technology in
use today is more effective for
controlling particulate matter emissions.
Although comparison of mean values
Indicates that the possibility that
emissions from dry process kilns are
controlled slightly more effectively than
wet process kilns, the difference is not
statistically significant
Nitrogen Oxide Emissions
Cement kilns are a very large and
presently unregulated source of nitrogen
oxides (NO.) emissions. Based upon
estimated NO. emissions of 1.3 kg/Mg of
cement produced and 71.4 million Mg of
portland cement produced in 1977, an
estimated 93,000 Mg of NO, were
emitted by portland cement plants that
year. The main factors that result in the
production of NO. are the flame and kiln
temperature, the residence time that
combustion gases remain at this
temperature, the rate of cooling of these
gases, and the quantity of excess air in
the flame. Control of these factors may
permit the operator to sharply reduce
the emission of NOr but such practices
have not been demonstrated in cement
plants for NO, emissions.
Opacity Monitoring
When the NSPS for portland cement
plants was established in 1971 no
provisions were included to require
continuous monitoring of opacity. This
was, in part, because the presence of
water vapor in the exhaust gases from
wet-process facilities would affect
monitor accuracy. In addition,
monitoring systems had not been
demonstrated at baghouse controlieJ
facilities where stack gases are emitted
from roof monitors or multiple stub
stacks. However, since the standard
was adopted, a monitoring system has
been demonstrated at a steel plant
utilizing baghouse controls and stub
stacks.
Conclusions
On the basis of the findings which are
summarized above, EPA has concluded
that the current particulate matter
standards are appropriate and effective
and that no revision is needed. While
the compliance test data do show that
the mean results are well below the
standards, the range of data suggest that
the standard is set at a level which
reflects the performance of the best
systems of emission reduction.
However, it is concluded that the
standard should be revised to include
provisions requiring the continuous
monitoring of opacity. This conclusion is
based upon the demonstration of
opacity monitors on baghouse stub
(lacks and on the shift in the portland
cement industry toward the dry process,
as well as EPA's belief that continuous
monitoring represents an important and
effective means for assuring proper
operation and maintenance of
particulate matter control equipment.
Adoption of any opacity monitoring
requirement will be preceded by a
proposal and the opportunity for public
comment. The Agency expects to
undertake development and to propose
this revision during 1980.
It is also concluded that the lack of
demonstrated control technology and an
emission limitation for NO, is an
important deficiency. The Agency is
therefore planning to evaluate, develop,
and demonstrate means for limiting NO,
emissions. This program, which will
include other industrial process fuel
users, will be aimed at transferring
technology being employed to control
NO, emissions from steam generators If
this proves successful, the results will be
used as a basis for development of NO,
standards.
Public Participation
All interested persons are invited to
comment on this review, the
conclusions, and EPA's planned action.
Dated October 16, 1979
Douglas M. Costle.
Administrator
|FR Doc 79-32M6 Fifed !0-l<»-?» 8 45 am]
V-F-3
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ENVIRONMENTAL
PROTECTION
AGENCY
STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
NITRIC ACID PLANTS
SUBPART G
-------
Federal Register / Vol. 44, No. 119 / Tuesday, June 19, 1979 / Proposed Rules
[40 CFR Part 60]
[FRL 1095-1]
Review of Standards of Performance
for New Stationary Sources: Nitric
Acid Plants
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Review of standards.
SUMMARY: EPA has reviewed the
standard of performance for nitric acid
plants. The review is required under the
Clean Air Act, as amended August 1977.
The purpose of this notice is to
announce EPA's intent not to undertake
revision of the standards at this time.
DATES: Comments must be received on
or before August 20,1979.
ADDRESSES: Send comments to the
Central Docket Section (A-130), U.S.
Environmental Protection Agency, 401 M
Street, S.W., Washington, D.C. 20460,
Attention: Docket No. A-79-08. The
document "A Review of Standards of
Performance for New Stationary
SourcesNitric Acid Plants" (EPA
report number EPA-450/3-79-013) is
available upon request from Mr. Robert
Ajax (MD-13), Emission Standards and
Engineering Division, U.S.
Environmental Protection Agency,
Research Triangle Park, North Carolina
27711.
FOR FURTHER INFORMATION CONTACT:
Mr. Robert Ajax, (919) 541-5271.
SUPPLEMENTARY INFORMATION:
Background
Prior to the promulgation of the NSPS
in 1971, only 10 of the existing 194 weak
nitric acid (50 to 60 percent acid)
production facilities were specifically
designed to accomplish NO, abatement.
V-G-2
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Federal Register / Vol. 44, No. 119 / Tuesday, June 19, 1979 / Proposed Rules
Without control equipment, total NO,
emissions are approximately 3,000 ppm
in the stack gas, equivalent to a release
of 21.5 kg/Mg (43 Ib/ton) of 100 percent
acid produced.
At the time of the NO, New Source
Performance Standard (NSPS)
promulgation there were no State or
locat NO, emission abatement
regulations in effect in the U.S. which
applied specifically to nitric acid
production plants. Ventura County,
California, had enacted a limitation of
250 ppm NO, to govern nitric acid plants
as well as steam generators and other
sources.
In August of 1971, the EPA proposed a
regulation under Section 111 of the
Clean Air Act to control nitrogen oxides
emissions from nitric acid plants. The
regulation, promulgated in December
1971, requires that no owner or operator
of any nitric acid production unit (or
"train") producing "weak nitric acid"
shall discharge to the atmosphere from
any affected facility any gases which
contain nitrogen oxides, expressed as
NOj, in excess of 1.5 kg per metric ton of
acid produced (3.0 Ib per ton), the
production being expre*sed as 100
percent nitric acid; and any gases which
exhibit 10 percent opacity or greater.
The Clean Air Act Amendment* of
1977 require that the Administrator of
the EPA review and, if appropriate,
revise established standards of
performance for new stationary sources
at least every 4 years [Section
lll(b)(l)(B)]. This notice announces that
EPA has completed a review of the
standard of performance for nitric acid
plants and invites comment on the
results of this review.
Findings
Industry Growth Rate
The average rate of production
increase for nitric acid fell from 9
percent/year in the 1960-1970 period to
0.7 percent from 1971 to 1977. The
decline in,demand for nitric acid
parallels that for nitrogen-based
fertilizers during the same period.
Nitric acid production shows an
increasing trend toward plant/unit
location and growth in the southern tier
of States. In 1971,48 percent of the
national production was in the south.
This figure increased to 54 percent in
1976.
About 50 percent of plant capacity in
1972 consisted of small to moderately
sized units (50 to 300-ton/day capacity).
Because of the economies of scale some
producers are electing to replace their
existing units with new, larger units.
New nitric acid production units have
been built as large as 910 Mg/day (1000
tons/day). The average size of new units
is approximately 430 Mg/day (500 tons/
day).
Control Technology
A mixture of nitrogen oxides (NO,) is
present in the tail gas from the ammonia
oxidation process for the production of
nitric acid. In modern U.S. single
pressure process plants producing 50 to
60 percent acid, uncontrolled NO,
emissions are generated at the rate of
about 21 kg/Mg of 100 percent acid (42
Ib/ton) corresponding to approximately
3000 ppm NO, (by volume) in the exit
gas stream. The catalytic reduction
process which was considered the best
demonstrated control technology at the
time the present standard was
established has been largely supplanted
by the extended absorption process as
the preferred control technology for NO,
emissions from new nitric acid plants.
The latter control system appears to
have become the technology of choice
for the nitric acid industry due to the
increasing cost and danger of shortages
of natural gas us«d in the catalytic
reduction process. Since the energy
crisis of the mid-1970's, over 50 percent
of the nitric acid plants that had come
on stream through mid-1978 and almost
90 percent of the plants scheduled to
come on stream through 1979 use the
extended absorption process for NO,
control.
Levels Achievable with Demonstrated
Control Technology
All 14 of the new or modified
operational nitric acid production units
subject to NSPS and tested showed
compliance with the current standard of
1.50 kg/Mg (3 Ib/ton). The average of
seven sets of test data from catalytic
reduction-controlled plants is 0.22 kg/
Mg (0.44 Ib/ton), and the average of six
sets of test data from extended
absorption-controlled plants is 0.91 kg/
Mg (1.82 Ib/ton). All of the plants tested
were in compliance with the opacity
standard. It appears that the extended
absorption process, while it has become
the preferred control technology for NO,
control, cannot control these emissions
as efficiently as the catalytic reduction
process. In fact, over half of the test
results for extended absorption were
within 20 percent of the NO, standard.
The extended absorption process thus
appears to have limitations with respect
to NO, control, and compares
unfavorably with catalytic reduction in
its ability to reduce NO, emissions much
below the present NSPS level.
Economic Considerations Affecting the
t NSPS
The anhualized costs of the extended
absorption process and the catalytic
reduction NO, control methods appear
to be quite comparable. Capital cost for
the extended absorption process is
appreciably higher than that for
catalytic reduction. However, this is
offset by the higher operating cost of the
latter system which requires
increasingly costly natural gas.
Conclusions
Based on the above findings, EPA
concludes that the existing standard of
performance is appropriate at this time,
While lower emission levels are
attainable, the energy penalty and
shortages of natural gas are concluded
to be a basis for retaining the current
standard of performance under Section
111 of the Clean Air Act. However, the
recent deregulation will alter the price
nd availablity of natural gas, and
provides a basis for optimism about its
future availability for process and
pollution control purposes. The Agency,
therefore, plans to continue to assess the
standard as, the effect of deregulation
materializes. Moreover, it should be
noted that for the purpose of attaining
and maintaining national ambient air
quality standards and prevention of
significant deterioration requirements,
State Implementation Plan new source
reviews may in come cases require
greater emission reductions than those
required by the standards of
performance for new sources.
Public participation
All interested persons are invited to
comment on this review, the
conclusions, and EPA's planned action.
Comments should be submitted to: Mr.
Don Goodwin (MD-13), Emission
Standards and Engineering Division,
U.S. Environmenal Protection Agency,
Research Triangle Park, North Carolina
27711.
Dated: June 11, 1979.
Douglas M. Costle,
Administrator.
[FR Doc. 78-19002 Filed 6-18-79; 8:45 am]
BILLING CODE (MO-01-M
V-G-3
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ENVIRONMENTAL
PROTECTION
AGENCY
STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
SULFUBIC ACIO PLANTS
SUBPART H
-------
PROPOSED RULES
NEW STATIONARY SOURCES: SULFURIC ACID
PLANTS
Review of Performance Standard!
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Review of Standards.
SUMMARY: EPA has reviewed the
standards of performance for sulfuric
acid plants (40 CFR 60.80). The review
is required under the Clean Air Act, as
amended August 1977. The purpose of
this notice is to announce EPA's deci-
sion to not revise the standards at this
time and to solicit comments on this
decision.
DATES: Comments must be received
by May 14,1979.
ADDRESS: Send comments to: Mr.
Don Goodwin (MD-13), Emission
Standards and Engineering Division,
Environmental Protection Agency, Re-
search Triangle Park, North Carolina
27711.
FOR FURTHER
CONTACT:
INFORMATION
Mr. Robert Ajax. telephone: (919)
641-5271. The document "A Review
of Standards of Performance for
New Stationary SourcesSulfuric
Acid Plants" (EPA report number
EPA-450/3-79-003) is available upon
request from Mr. Robert Ajax (MD-
13), Emission Standards and En-
gineering Division, Environmental
Protection Agency, Research Trian-
gle Park, North Carolina 27711.
SUPPLEMENTARY INFORMATION:
BACKGROUND
Prior to the proposal of the standard
of performance in 1971, almost all ex-
isting contact process sulfuric acid
plants were of the single-absorption
design and had no SO* emission con-
trols. Emissions from these plants
ranged from 1500 to 6000 ppm SO, by
volume, or from 10.8 kg of SO2/Mg of
100 percent acid produced (21.5 lb/
ton) to 42.5 kg of SO,/Mg of 100 per-
cent acid produced (85 Ib/ton). Several
State and local agencies limited SO,
emissions to 500 ppm from new sulfu-
ric acid plants, but few such facilities
had been put into operation (EPA,
1971).
In August of 1971, the Environmen-
tal Protection Agency (EPA) proposed
a regulation under Section 111 of the
Clean Air Act to control SOa and sul-
furic acid mist emissions from sulfuric
acid plants. The regulation, promul-
gated in December 1971, requires that
no owner or operator of any new sul-
furic acid production unit producing
sulfuric acid by the contact process by
burning elemental sulfur, alkylation
acid, hydrogen sulfide, organic sul-
fides, mercaptans, or acid sludge shall
discharge into the atmosphere any
gases which contain sulfur dioxide in
excess of 2 kg/Mg (4 Ib/ton); any gases
which contain acid mist, expressed as
H^SO,. in excess of 0.075 kg/Mg of
acid produced (0.15 Ib/ton), expressed
as 100 percent HjSO4; or any gases
which exhibit 10 percent opacity or
greater. Facilities which produce sul-
furic acid as a means of controlling
SOj emissions are not'included under
this regulation.
The Clean Air Act Amendments of
1977 require that the Administrator of
the EPA review and, if appropriate,
revise established standards of per-
formance for new stationary sources
at least every 4 years [Section
lll(bXlXB)]. This notice announces
that EPA has completed a review of
the standard of performance for sulfu-
ric acid plants and invites comment on
the results of this review.
FINDINGS
INDUSTRY GROWTH
Since the proposal, 32 contact proc-
ess sulfuric acid units have been con-
structed. Of these, at least 24 units
result from growth in the phosphate
fertilizer industry and are dedicated to
the acidulation of phosphate rock,
mainly in the Southern U.S.
In 1976, over 70 percent of the total
national production of new sulfurio
acid was in the South. It is projected
that three of the four units predicted
to be coming on line each year will
most probably be located in the South.
BEST DEMONSTRATED CONTROL
TECHNOLOGY
Sulfur dioxide and acid mist are
present in the tail gas from the con-
tact process sulfuric acid production
unit. In modern four-stage converter
contact process plants burning sulfur
with approximately 8 percent SO2 in
the converter feed, and producing 98
percent acid, SOa and acid mist emisi-
sions are generated at the rate of 13 to
28 kg/Mg of 100 percent acid (26 to 56
Ib/ton) and 0.2 to 2 kg/Mg of 100 per-
cent acid (0.4 to 4 Ib/ton), respectively.
The dual absorption process is the
best demonstrated control technology
for SOj emissions from sulfuric acid
plants, while the high efficiency acid
mist eliminator is the best demonstrat-
ed control technology for acid mist
emissions. These two emission control
systems have become the systems of
choice for sulfuric acid plants built or
modified since the promulgation of
the NSPS. Twenty-eight of the 32 sul-
furic acid production plants subject to
the standard incorporate the dual ab-
sorption process; all 32 plants use the
high efficiency acid mist eliminator.
COMPLIANCE TEST RESULTS
All 32 sulfuric acid production units
subject to the standard showed com-
pliance with the current SO, standard
of 2 kg/Mg (4 Ib/ton). The 29 compli-
ance test results for dual absorption
plants ranged from a low of 0.16 kg/
Mg (0.32 Ib/ton) to a high of 1.9 kg/
Mg (3.7 Ib/ton) with an average of 0.9
kg/Mg (1.8 Ib/ton). Information re-
ceived on the performance of several
sulfuric acid plants indicates that low
SO, emission results achieved in NSPS
compliance tests apparently do not re-
flect day-to-day SO, emission levels.
These levels appear to rise toward the
standard as the conversion catalyst
ages and its activity drops. Additional-
ly, there may be some question about
the validity of low SO, NSPS values,
i.e., less than 1 kg/Mg (2 Ib/ton), due
to errors in the application of the
original EPA Method 8. This method
was revised on August 18, 1977, to in-
clude more detailed procedures to pre-
vent such errors.
All 32 affected sulfuric acid produc-
tion units also showed compliance
with the current acid mist standard of
0.075 kg/Mg of 100 percent acid (0.15
Ib/ton). The compliance test data are
all from plants with acid mist emission
control provided by the high efficien-
KDERAL REGISTER, VOL 44, NO. 52THURSDAY, MARCH 15, 1979
V-H-2
-------
cy acid mist eliminator. The data
showed a range with a low of 0.008 kg/
Mg (0.016 Ib/ton) to a high of 0.071
kg/Mg (0.141 Ib/Con), and an overall
average value of 0.04 kg/Mg (0.081 lb/
ton). Acid mist emission (and related
opacity) levels are unaffected by fac-
tors affecting SO, emissions, i.e., con-
version efficiency and catalyst aging.
Rather, acid mist emissions are pri-
marily a function of moisture levels in
the sulfur feedstock and air fed to the
sulfur burner, and the efficiency of
the final absorber operation. The
order-of-magnitude spread observed in
compliance test values is probably a
result of variation in these factors. Ad-
ditionally, the potential for impreci-
sion in the application of the original
EPA Method 8 may have contributed
to this spread.
POSSIBLE REVISION TO STANDARD
The compliance test data indicate
that the available control technology
could possibly meet both lower sulfur
dioxide and sulfuric acid mist emission
standards. However, the available test
data indicate that variability in indi-
cated emission rates occurspossibly
as a result of process variables, and
test method precision. Therefore, to
meet a tighter standard designers and
operators would need to design for at-
tainment of a lower average emission
rate in order to retain a margin of
safety needed to accommodate emis-
sion variability. The available compli-
ance data do not provide a basis for
concluding that this is possible.
In contrast, the effect of catalyst
aging is controllable by more frequent
replacement. As an outside limit, com-
plete replacement of catalyst in the
first 3 beds of a four-bed converter 3
times as frequently as is normally
practiced could potentially maintain
emissions in the range of 1 to 1.5 kg/
Mg and would result in a net emission
reduction of approximately 0.3 kg/Mg
(0.6 Ib/ton).
Based on an estimated sulfuric acid
plant growth rate of four new produc-
tion lines per year between 1981 and
1984, a 50 percent reduction of the
present SO, NSPS levelfrom 2 kg/
Mg (4 Ib/ton) to 1 kg/Mg (2 Ib/ton)
would result in a drop in the estimated
SO, contribution to these new sulfuric
acid plants to the total national SO,
emissions, from 0.04 percent to 0.02
percent (8,000 tons to 4,000 tons).
CONCLUSIONS
Based upon the above findings, EPA
concludes that the current best dem-
onstrated control technology, the duel
absorption process and the acid mist
-eliminator are identical in basic design
to that used as the rationale for the
r;6riginal SO, standard. Therefore, from
*he standpoint of control technology,
and considering costs, and the small
PROPOSED RULES
quantity of emissions in question, it
does not appear necessary or appropri-
ate to revise the present standard of
performance adopted under Section
111 of the Clean Air Act. It should be
noted that for the purpose of attain-
ing national ambient air quality stand-
ards and prevention of significant de-
terioration, State Implementation
Plan new source reviews may in some
cases require greater emission reduc-
tions than those required by standards
of performance for new sources.
PUBLIC PARTICIPATION
All interested persons are Invited to
comment on this review, the conclu-
sions, and EPA's planned action. Com-
ments should be submitted to: Mr.
Don Goodwin (MD-13), Emission
Standards and Engineering Division,
Environmental Protection Agency, Re-
search Triangle Park, N.C. 27711.
(Section 11U6X1XB) of the Clean Air Act,
as amended (42 U.S.C. 741K6X1XB)).
Dated: March 9, 1979.
DOUGLAS M. COSTLE,
Administrator.
[PR Doc. 79-7926 Filed 3-14-79; 8:45 am]
FEDERAL REGISTER, VOL 44, NO. 52THURSDAY, MARCH 15, 1979
V-H-3
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ENVIRONMENTAL
PROTECTION
AGENCY
STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
PETROLEUM REFINERY
SUBPART)
-------
Federal Register / Vol. 44, No. 205 / Monday October 22, 1979 / Proposed Rules
40 CFR Part 60
[FRL 1295-1]
Standards of Performance for New
Stationary Sources: Petroleum
Refineries Review of Standards
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Review of Standards.
SUMMARY: EPA has reviewed its
standard of performance for petroleum
refineries (40 CFR 60.1130, Subpart J). The
review is required under the Clean Air
Act, as amended August 1977. The
purpose of this notice is to announce
EPA's intent to undertake the
development of a revised standard
which would limit SO» emissions from
catalyst regenerators.
DATE: Comments must be received by
December 21,1979.
ADDRESS: Send comments to: Central
Docket Section (A-130), U.S.
Environmental Protection Agency, 401 M
Street, S.W., Washington, D.C. 20460,
Attention: Docket A-79-09.
The document "A Revie\v of
Standards of Performance for New
Stationary SourcesPetroleum
Refineries" (EPA-450/3-79-008) is
available upon request from Mr. Robert
Ajax (MD-13), Emission Standards and
Engineering Division, U.S.
Environmental Protection Agency,
Research Triangle Park, North Carolina
27711,
FOR FURTHER INFORMATION CONTACT:
Mr. Robert Ajax, Telephone: (919) 541-
5371.
SUPPLEMENTARY INFORMATION:
Background
New Source Performance Standards
(NSPS) for petroleum refineries were
promulgated by the Environmental
Protection Agency on March 8, 1974. (40
CFR 60.100, Subpart J). These standards
regulate the emission of particulate
matter and carbon monoxide, and the
opacity of flue gases from fluid catalytic
cracking unit (FCCU) catalyst
regenerators and FCCU regenerator
incinerator-waste heat boilers. They
also regulate the emission of sulfur
dioxide from fuel gas combustion
devices. These regulations apply to any
affected facility which commenced
construction or modification afier June
11,1973.
The Clean Air Act Amendments of
197? require that the Administrator of
the EPA review and, if appropridte,
revise established standards of
performance for new stationary sources
at least every 4 years [Section
lll(b)(l)(B)]. This notice announces that
EPA has completed a review of thn
standard of performance for petroleum
refineries and invites comment on the
results of this review.
Findings
On the basis of a review of
compliance data available in EFA's
Regional Offices and a review of
literature describing recent control
technology applicable to cataljst
regenerators and fuel gas combustion
devices, EPA has made the following
conclusions regarding the need to rexise
the existing standard.
Particulate Matter
The available data indicate that the
current limitation on particulate matter
emissions accurately reflects the
performance capability of best available
control systems. It is, therefore,
concluded that no revision should be
made to'the particulate standard. New
technologies such as high efficiency
separators, high temperature
regenerators, and new catalysts have
reduced the tojal quantity of
uncontrolled particulate matter emitted.
However, the method established in the
standard for calculating the allowable
emissions effectively corrects for the
reduction due to changes in catalysts
and operating procedures.
While it is concluded that the
particulate matter standard should not
be revised, a question has been raised
as to the validity of Reference Method 5
when high concentrations of
condensible sulfur compounds are
present. This test method, which is used
to measure compliance with the
particulate standard, operates at a
nominal temperature of 120°C and, as
such, is capable of collecting
condensible matter which exists in
gaseous form at stack temperature. If
significant quantities of such
condensible material exist which are not
controllable by the best systems of
emission reduction, then a facility
employing such systems could be found
to be in non-compliance with the
standard. An analysis of data available
when the standard was established
indicated this was not a problem at that
time. However, with high sulfur content
feed, there is evidence that condensible
sulfur oxides may exist at
concentrations sufficient to affect
compliance.
EPA is currently studying this
question. Depending on the results of
this study, EPA may revise the standard
or the test method.
Carbon Monoxide
The present standard for carbon
monoxide emissions was established at
a level which would permit regenerator
in situ combustion. This method of
controlling carbon monoxide emissions
offers production and energy efficiencies
but is recognized to be less effective
than a carbon monoxide boiler. No new
data were obtained during this review to
alter the original finding that it is not
practical to control CO emissions to less
than 500 ppm by in situ regeneration
and, therefore, no revision in the
standard is planned at this time.
However, it should be noted that the
recent advent and increased use of CO
oxidation catalysts and additives may
provide data showing that
concentrations lower than 500 ppm are
achievable. If such data become
available, the Agency will consider
revision of the standard. It should be
further noted that for the purpose of
attaining and maintaining the national
ambient air quality standards, State
Implementation Plan new source
reviews may,-in some cases, require
greater CO emission reductions than
those required by the standards of
performance for new sources.
At the time the standard was
established, EPA concluded that CO
emissions should be continuously
monitored. A requirement for such
monitoring was, therefore, included in
the standard. This requirement is
applicable to all catalyst regenerators
subject to the standard. However, the
effective date of the monitoring
requirement was deferred until EPA
develops performance specifications for
CO monitoring systems. EPA has found
no basis for revising this monitoring
requirement and performance
specifications are currently under
development and evaluation. It is
planned to issue an advanced notice of
proposed rulemaking in 1979 setting
forth the specifications which have been
developed and which will be assessed
in field studies.
Sulfur Dioxide
The present standard currently limits
SO> emissions resulting from the
combustion of fuel gas. The catalyst
regenerator is also a significant source
of SO? emissions but is not subject to
the standard. The review considered
both the need to revise the current
limitation and the need to include
limitations on SOi emissions from the
catalyst regenerator-
Available compliance test data
indicate that the current standard
limiting sulfur to 230 mg HaS/dscm from
combustion of fuel gas is being met and,
in some cases, exceeded by a wide
margin. Six tests showed an average of
107 mg H5S/dscm and a range of 7 to 229
mg HiS/dscm. While these data indicate
t-hat a reduction in the present limitation
V-J-2
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Federal Register / Vol. 44. No. 265 / Monday, October 22. 1979 / Proposed Rules
is possible, the range exhibited is
consistent with the control device
performance documented at the time the
standard was established. On the basis
of this, along with the increased sulfur
content of feedstock expected with
increased imports and the variable
crude oil supply conditions now
existing, it is concluded that the fuel gas
sulfur limitation is appropriate and that
no revision is needed,
A deficiency in the current standard
limiting sulfur in fuel gas relates to the
lack of a continuous monitoring method.
EPA recognized the need for continuous
monitoring at the time the standard was
adopted. However, at that time, no
monitoring systems had been
demonstrated to be adequate for this
purpose and EPA had not established
performance specifications for such
systems. Consequently, application of
the monitoring requirement was
deferred until performance
apecifications could be adopted. Since
the adoption of the standard, EPA has
pursued a program to develop and
assess the performance of an HtS
monitoring system. On this basis,
performance specifications are now
being developed. It is planned to issue
an advanced notice of proposed
rulemaking in 1979 setting forth the
specifications which have been
developed and which will be assessed
in field studies,
During the review of the standard, an
ambiguity was identifed in the current
limitation on sulfur in fuel gas
concerning the applicability of this
limitation to fuel gas burned in waste-
heat boilers. To clarify this, an
amendment was prepared which was
published in the Federal Register on
March 12,1979. This amendment makes
clear that fuel gas fired in waste-heat
boilers is not exempt from the standard.
Sulfur dioxide emissions from fluid
catalytic cracking unit (FCCU) catalyst
regenerators are not regulated by the
standard. However, sulfur dioxide
scrubber technology is available and
being used to control steam generator
emissions and a limited number of
FCCU regenerators. Also, Amoco Oil
Company has developed a new cracking
process which reduces sulfur oxide
emissions from FCCU regenerators. The
process uses a new catalyst that retains
sulfur oxides and returns them to the
reactor where they are removed with the
product stream. If a low sulfur product '.s
required, the sulfur will be removed by
amine stripping or hydrotreating and
eventually recovered in a sulfur
recovery unit. Pilot tests indicate that
the new catalyst is capable of reducing
sulfur oxide emissions 80 to 90 percent
and commercial tests are planned to
confirm these data.
The potential uncontrolled emissions
from new, modified, or reconstructed
catalyst regenerators are significant.
Uncontrolled emission rates from
catalyst regenerators are typically 5 to
10 Mg/day and range up to 100 Mg/day
from the largest units. The growth rate
in terms of new catalyst regenerators is
uncertain due to the present uncertainty
of petroleum supplies and demand.
However, for perspective a growth rate
of 0.5 percent in capacity from 1979
through 1985 would result in additional
emissions from uncontrolled new
sources of 23 Mg per day in 1986; a
growth rate of 0.75 percent would result
in additional uncontrolled emissions of
58 Mg SO,/day. Emissions from
modified or reconstructed sources would
add to this total.
Based on the existence of these SOi
control technologies, EPA plans to
initiate a program later this year to
assess the applicability, cost,
performance, and non-air environmental
impacts of these technologies. If
supported by the findings of this
program EPA will propose a limit on
FCCU SO, emissions.
Volatile Organic Compounds
The emission of volatile organic
compounds (VOC) from FCC unit
regenerators is not limited in the present
NSPS. These are, however, of concern,
both because of their role as oxidant
precursors and as potentially hazardous
compounds. Of particular concern are
the polynuclear aromatic compounds
(PNA) because of their potential
carcinogenic effects. The most abundant
PNA measured in regenerator flue gas is
benzo-a-pyrene (BAP) with a
concentration of 0.218 kg BAP/1,000
barrels of feed. The concentration of
BAP can effectively be reduced in a
carbon monoxide boiler to 1.41 X 10''
kg BAP/1,000 barrels of feed. However,
there are no data indicating the
concentration of BAP in the flue gas
from high temperature (in situ)
regeneration nor from regenerators using
CO oxidation promoting catalyst. This,
therefore, has been identified as an area
for future study by EPA's Office of
Research and Development.
Public Participation
All interested persons are invited to
comment on this review, the
conclusions, and EPA's planned action.
Douglas M. Costle,
Administrator.
Dated. October 15, 1979.
|FR Doc 79-32567 Filed 10-l»-78. 8 45 am)
V-J-3
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Federal Register / Vol. 45. No. 43 / Monday. March 3.1980 / Proposed Rules
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Part 60
[FRL 1423-2]
Standards of Performance for New
Stationary Sources; Petroleum
Refineries; Clarifying Amendment
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Proposed Rule.
SUMMARY: This proposed action clarifies
which gaseous fuels used at petroleum
refineries are covered by the existing
standards of performance for petroleum
refineries (40 CFR 60.100). This action
will not change the environmental,
energy, and economic impacts of the
existing standards.
DATE: Comments must be received on or
before May 2,1980.
ADDRESSES: Comments. Comments
should be submitted (in duplicate if
possible) to: Central Docket Section (A-
130), Attention: Docket Number A-79-
56, U.S. Environmental Protection
Agency, 401 M Street, S.W.,
Washington, D.C. 20460. Docket. The
Docket, Number A-79-56, is available
for public inspection and copying at
EPA's Central Docket Section, Room
2902 Waterside Mall, Washington, D.C.
20460.
FOR FURTHER INFORMATION CONTACT:
Susan R. Wyatt, Emission Standards
and Engineering Division (MD-13),
Environmental Protection Agency,
Research Triangle Park, North Carolina
27711, telephone number (919) 541-5477.
SUPPLEMENTARY INFORMATION: On
March 12,1979, EPA published in the
Federal Register (44 PR 13480) a
clarifying amendment intended to
"reduce confusion concerning the
applicability of the sulfur dioxide
standard to incinerator-waste heat
boilers installed on fluid or Thermofor
catalytic cracking unit catalyst
regenerators and fluid coking unit coke
burners." That action included a change
in the definition of "fuel gas." it now
appears the revised definition of "fuel
gas" could easily be interpreted to
include natural gas as a fuel gas. This
would mean that refineries using natural
gas would be subject to the expense of
performance testing, monitoring, and
reporting requirements even though the
natural gas contained essentially no
sulfur and did not result in emissions of
sulfur dioxide when combusted.
The intent of the existing standards of
performance for refinery fuel gas has
always been to prevent emissions of
sulfur dioxide resulting from the burning
of gaseous fuels containing hydrogen
sulfide. Generally, natural gas used in
refineries is purchased from outside
sources and delivered to the refinery via
pipelines. This natural gas contains only
trace amounts of hydrogen sulfide due
to specifications established to protect
the pipelines from corrosion. It would
impose an unnecessary burden on
refineries to require performance testing,
monitoring, and reporting where this
natural gas is burned by itself.
In a few cases, however, a refinery
may generate natural gas. There may be
no legal or technical requirement that
this gas be desulfurized before
combustion. If this gas contains
appreciable hydrogen sulfide and other
sulfur constituents, significant emissions
of sulfur dioxide would result when it is
burned. The existing standards of
performance for petroleum refineries
were intended to cover these types of
gases. Consequently, the definition of
"fuel gas" is rewritten to clarify that
only natural gas generated at a
petroleum refinery is to be considered
fuel gas. The effective date of the
revised definition would be March 12,
1979.
Miscellaneous: Under Executive
Order 12044, EPA is required to judge
whether a regulation is "significant" and
therefore subject to the procedural
requirements of the Order or whether it
may follow other specialized
development procedures. EPA labels
these other regulations "specialized." I
have reviewed this regulation and
determined that it is a specialized
regulation not subject to the procedural
requirements of Executive Order 12044.
Dated: February 26,1980.
Douglas M. Costle,
Administrator.
It is proposed to amend Part 60 of
Chapter I, Title 40 of the Code of Federal
Regulations by revising paragraph (d) as
follows:
60.101 Definitions,
*****
(d) "Fuel gas" means natural gas
generated at a petroleum refinery, or
any gas generated by a refinery process
unit, which is combusted separately or
in any combination with any type of
natural gas. Fuel gas does not include
gases generated by catalytic cracking
unit catalyst regenerators and fluid
coking burners.
*****
(Sec. Ill, 301(a) of the Clean Air Act as
amended (42 U.S.C. 7411, 7601(a))
|FR Doc. ao-«9M Filed 2-29-ao: 8:45 «n|
V-J-4
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ENVIRONMENTAL
PROTECTION
AGENCY
STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
SECONDARY BRASS OR BRONZE INGOT PRODUCTION PLANTS
SUBPART M
-------
Federal Register / Vol. 44, No. 119 / Tuesday, June 19,1979 / Proposed Rules
ENVIRONMENTAL PROTECTION
AGENCY
[40 CFR Part 60]
[FRL-1231-1]
Review of Standards of Performance
for New Stationary Sources:
Secondary Brass and Bronze Ingot
Production
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Review of Standards.
SUMMARY: EPA has reviewed the
standard of performance for secondary
brass and bronze ingot production
plants (40 CFR 60.130, Subpart M). The
review is required under the Clean Air
Act, as amended August 1977. The
purpose of this notice is to announce
EPA's intent not to undertake revision of
the standards at this time.
DATES: Comments must be received on
or before August 20,1979.
ADDRESSES: Comments should be sent
to the Central Docket Section (A-130).
U.S. Environmental Protection Agency,
401 M Street, SW., Washington, D.C.
20460, Attention: Docket No. A-79-10.
The Document "A Review of Standards
of Performance for New Stationary
SourcesSecondary Brass and Bronze
Plat Plants" (EPA-450/3-79-011) is
available upon request from Mr. Robert
Ajax (MD-13), Emission Standards and
Engineering Division, U.S.
Environmental Protection Agency,
Research Triangle Park, North Carolina
27711.
FOR FURTHER INFORMATION CONTACT:
Mr. Robert Ajax, telephone: (919) 541-
5271.
SUPPLEMENTARY INFORMATION:
Background
In June of 1973, the EPA proposed a
standard under Section 111 of the Clean
Air Act to control participate matter
emissions from secondary brass and
bronze ingot production plants (40 CFR
60.230, Subpart M). The standard,
promulgated in March 1974, limits the
discharge of any gases into the
atmosphere from a reverberatory
furnace which;
1. Contain particulate matter in excess
of 50 mg/dscm (0.022 gr/dscf).
2. Exhibit 20 percent opacity or
greater.
In addition, any blast (cupola) or
electric furnace may not emit any gases
which exhibit 10 percent opacity or
greater.
The Clean Air Act Amendments of
1977 require that the Administrator of
the EPA review and, if appropriate,
revise established standards of
performance for new stationary sources
at least every 4 years (Section
lll(b)(l)(B)]. This notice announces that
EPA has completed a review of the
standard of performance for secondary
brass and bronze ingot production
plants and invites comment on the
results of this review.
Findings
Industry Statistics
In 1969, there were approximately 60
brass and bronze ingot production
facilities in the United States. Currently,
only 35 facilities are operational, and
only one facility has become operational
since the promulgation of the NSPS in
1974. No new facilities or modifications
are know to be currently planned or
under construction.
Ingot production has shown a steady
decline from the 1966 peak year
production of 315,000 Mg (347,000 tons)
to a low of 160,000 Mg (186,000 tons) in
1975, the last year for which nationwide
statistics were published. The decline
has been caused by a decline in the
demand for products made with brass or
bronze and large scale substitution of
other materials or technologies for the
previously used braae or bronze. No
information has been reported which
would indicate a reversal of the decline
in brass and bronze ingot production or
in the number of operating plants.
Emissions and Control Technology
The current best demonstrated control
technology, the fabric filter, is the same
as when the standards were originally
promulgated. No major improvements in
this technology have occurred during the
intervening period.
High-pressure drop venturi scrubbers
are used, to some extent, in the brass
and bronze industry, but their overall
control efficiency is lower than that of
fabric filters. Electrostatic precipitators
have not been used in the industry due
to both the low gas flow rates and high
resistivity of metallic fumes.
Only one facility has become subject
to the standard since its original
promulgation. This facility was tested in
February 1978. The average test result of
16.9 milligrams/dry standard cubic
meters (mg/dscm), or 0.0074 grains/dry
standard cubic feet (gr/dscf), is lower
than most of the test data used for
justification of the current standard of
50 mg/dscm (0.022 gr/dscf), but this
single test is not considered sufficient to
draw any overall conclusion about
improved control technology.
Fugitive emissions continue to be a
problem in the brass and bronze
industry. In most cases, these emissions
are very difficult to capture and equally
difficult to measure during testing. It
was primarily for the former reason that
the current particulate standard does
not apply during pouring of the ingots.
This overall situation has not changed in
that only complete enclosure of the
furnace can result in full control of
fugitive emissions. However,
information is available indicating that
there may be additives capable of
reducing fugitive emissions during
pouring. Also, improved control of
fugitive emissions may be possible
through improved hood design.
Conclusions
Based on the above findings, EPA
concludes that the existing standard of
performance is appropriate and no
revision is needed. While extension of
the standard to include fugitive
emissions would be possible, the lack of
anticipated growth in the industry does
not justify such action.
PUBLIC PARTICIPATION: AH interested
persons are invited to comment on this
review and the conclusions.
Dated: June 12,1979.
Douglas M. Costle,
Administrator.
(PR Doc. 79-19003 Filed 0-18-79, 8.15 am|
BHJ-ING CODE 6560-01-M
V-M-2
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ENVIRONMENTAL
PROTECTION
AGENCY
BASIC OXYGEN PROCESS
FURNACES
Standards of Performance For New
Stationary Sources
SUBPART N
-------
PROPOSED RULES
ENVIRONMENTAL PROTECTION
AGENCY
[40 CFR Port 60]
[PRL 1012-1]
STANDARDS OF PERFORMANCE FOR NEW
STATIONARY SOURCES: IRON AND STEEL
PLANTS, BASIC OXYGEN FURNACES
Review of Slandardi
AGENCY: Environmental Protection
Agency (EPA).
ACTION. Review of standards.
SUMMARY: EPA has reviewed the
standards of performance for basic
oxygen process furnaces (BOPFs) used
at iron and steel plants. The review is
required under the Clean Air Act, as
amended in August 1977. The purpose
of this notice is to announce EPA's
intent to propose amendments to the
standards at a later date.
DATES: Comments must be received
by May 21, 1979.
ADDRESS: Send comments to: Mr.
Don Goodwin (MD-13), Emission
Standards and Engineering Division,
U.S. Environmental Protection
Agency, Research Triangle Park, N.C.
27711.
FOR FURTHER INFORMATION
CONTACT:
Mr. Robert Ajax, telephone: (919)
541-5271.
The document "A Review of Stand-
ards of Performance of New Station-
ary SourcesIron and Steel Plants/
Bassic Oxygen Furnaces" (report
number EPA-450/3-78-116) is availa-
ble upon request from Mr. Robert
Ajax (MD-13), Emission Standards
and Engineering Division, U.S. Envi-
ronmental Protection Agency, Re-
search Triangle Park, N.C. 27711.
SUPPLEMENTARY INFORMATION:
BACKGROUND
Paniculate matter emissions from
BOPFs fall in two categories, primary
and secondary. Emissions associated
with the oxygen blow portion of the
BOPF are termed "primary" emis-
sions. These emissions are generated
at the rate of 25 to 28 kg/Mg (50 to 55
Ib/ton) of raw steel. Emissions gener-
ated during ancillary operations, such
as charging and tapping, are termed
"secondary" or fugitive emissions.
These emissions are generated at a
lower rate in the range of 0.5 to 1 kg/
Mg (1 to 2 Ib/ton) of raw steel.
In June of 1973, EPA proposed a reg-
ulation under Section 111 of the Clean
Air Act to control primary particulate
emissions from basic oxygen process
furnaces at iron and steel plants. The
regulation, promulgated in March
1974, requires that no owner or opera-
tor of any furnace producing steel by
charging scrap steel, hot metal, and
flux materials into a vessel and intro-
ducing a high volume of an oxygen-
rich gas shall discharge into the at-
mosphere any gases which contain
particulate matter in excess of 50 mg/
dscm (0.022 gr/dscf).
The Clean Air Act Amendments of
1977 require that the Administrator of
the EPA review and, if appropriate,
revise established standards of per-
formance for new stationary sourcs at
least every 4 years (Section
HKbXlxB)). This notice announces
that EPA has completed a review of
the standard of performance for basic
oxygen process furnaces at iron and
steel plants and invites comment on
the results of this review.
FINDINGS
INDUSTRY GROWTH RATE
The present economic conditions in
the United States and worldwide steel
industry have created a significant
excess U.S. BOPF capacity and a
tightening of the availablitly of capital
for future expansion. Since the pro-
mulgation of the BOPF standard, new
BOPF construction has declined sig-
nificantly. For example, three of the
four units scheduled for startup in
1978 were originally scheduled to
begin production in 1974. This coupled
with the lack of any additional indus-
try announcements of new U.S. BOPF
contruction, indicates that construc-
tion of new BOPFs which would be
subject to a revised new source per-
formance standard (NSPS) is not
likely to commence before 1980, if
then. Construction of new plants
beyond 1980 will be dictated by domes-
tic economic conditions and interna-
tional competition, and is, therefore,
uncertain.
PRIMARY EMISSION CONTROL
Review of the literature and per-
formance test data indicates that the
use of a closed hood in conjunction
with a scrubber or an open hood in
conjunction with either a scrubber or
electrostatic precipitator currently
represents the best demonstrated con-
trol technologies for controlling BOPF
primary emissions. All BOPFs that
have been installed since 1973 incorpo-
rate closed hood systems for particu-
late emission control. The closed hood
control system in combination with a
venturi scrubber has become the
system of choice of the U.S. steel in-
dustry because this system saves
energy and has generally lower main-
tenance requirements compared with
the older open-hood electrostatic pre-
cipitator system. Use of the closed
hood system requires that approxi-
mately 80 percent less air be cleaned
than with the open hood system. The
potential* also exists with the closed
hood system for using the carbon
monoxide off-gas as a fuel source.
As of early 1978, no NSPS compli-
ance tests had been carried out since
the promulgation of the standard. Per-
tinent data are available, however,
from emission tests on a limited
number of new BOPFs. These tests.
carried out using EPA Method 5, indi-
cate that primary particulate emission
levels of between 32 and 50 mg/dscf
(0.014 and 0.022 gr/dscf) are being
achieved using the same control tech-
nology as that existing at the time the
standard for primary emissions was es-
tablished for BOPFs. The rationale
for the current NSPS level of 50 mg/
dscm (0.022 gr/dscf) for primary stack
emissions, as described in 1973, is
therefore, still considered to be valid.
SECONDARY EMISSION CONTROL
TECHNOLOGY
Secondary or fugitive emissions not
captured by the BOPF primary emis-
sions control system during various
BOPF ancillary operations currently
amount to more than 100 tons annual-
ly. One of the principal sources of
these emissions, the hot metal charg-
ing cycle, can generate amounts of fu-
gitive emissions on the order of 0.25
kg/Mg (0.5 Ib/ton) of charge. These
emissions are presently uncontrolled
in most of the older BOPFs and only
partially controlled in most BOPFs
that have come on stream during the
past 5 years.
Control of secondary emissions in-
volves a developing technology that
requires in-depth study to determine
the most effective methods of fume
capture. Although potentially expen-
sive to construct, the complete furnace
enclusure equipped with several auxil-
iary hoods is currently the only dem-
onstrated technology exhibiting the
potential for effectively minimizing fu-
gitive emissions from a new BOPF.
Seven new BOPFs installed in the
U.S. in the past 7 years ha\e incorpo-
rated partial or full furnace enclosures
as part of the original particulate
emission control system. Since these
designs had deficiencies, these systems
are operating with varying degrees of
success;. Six new furnace enclosure in-
stallations due to commence oper-
ations in 1978, including four on new
BOPFs and two retrofit installations.
will incorporate a secondary hood
Inside the furnace enclosure with suf-
ficient volume for fugitive emission
control.
CLARIFICATION OF WORDING OF NSPS
STANDARD
Review of the existing standard re-
vealed possible ambiguity in the word-
ing of the NSPS with regard to the
FEDERAL REGISTER, VOL. 44, NO. 56WEDNESDAY, MARCH 21, 1979
V-N-2
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ENVIRONMENTAL
PROTECTION
AGENCY
STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
SEWAGE TREATMENT PLANTS
SUBPART 0
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Federal Register / Vol. 44. No. 229 / Tuesday, November 27,1979 / Proposed Rules
40 CFR Part 60
1FRL 1310-3]
Standards of Performance for New
Stationary Sources: Sewage
Treatment Plants; Review of Standards
AGENCY: Environmental Protection
Agency (EPA).
ACTION Review of standards.
SUMMARY: EPA has reviewed the
standards of performance for sewage
treatment plant sludge incinerators (40
CFR 60.150). The review is required
under the Clean Air Act, as amended
August 1977. The purpose of this notice
is to announce EPA's plan to defer
decision on the need to revise the
standards and to undertake a program
to further assess emission rates, control
technology, and the current standard.
DATES: Comments must be received by
January 28,1980.
ADDRESS: Comments should be
submitted to the Central Docket Section
(A-130). U.S. Environmental Protection
Agency. 401 M Street, S.W.,
Washington, D.C. 20460, Attention:
Docket No. A-79-17.
FOR FURTHER INFORMATION CONTACT:
Mr. Robert Ajax, telephone: (919) 541-
5271 The document "A Review of
Standards of Performance for New
Stationary SourcesSewage Sludge
Incinerators" (EPA-450/3-79-010) is
available upon request from Mr. Robert
Ajax (MD-13), Emission Standards and
Engineering Division, Environmental
Protection Agency, Research Triangle
Park. North Carolina 27711.
SUPPLEMENTARY INFORMATION:
Background
Prior to the promulgation of the NSPS
in 1974, most sewage sludge incinerators
utilized low pressure scrubbers (2 to 8
in WG) to reduce emissions to the
atmosphere. These scrubbers were
designed to meet State and local
standards that were on the order of 0.2
to 0.9 grams/dry standard cubic meter
(dscm) or 0.1 to 0.4 grains/dry standard
cubic foot (dscf) at 50 percent excess air
Incineration standards, for the most
part, reflected general incineration of all
types with emphasis on municipal solid
waste. A separate standard for sewage
sludge incineration emissions was
unusual. Control efficiencies, based on
an uncontrolled rate of 0.9 grains/dscf,
were between 50 and 90 percent.
In June of 1973, the Environmental
Protection Agency proposed a standard
under Section 111 of the Clean Air Act
to control particulate matter emissions
from sewage sludge incinerators. The
standard, promulgated in March 1974
and amended in November 1977, applies
to any incinerator constructed or
modified after June 11,1973, that burns
wastes containing more than 10 percent
sewage sludge (dry basis) produced by
municipal sewage treatment plants, or
charges more than 1000 kg (2205 Ib/day)
municipal sewage sludge (dry basis).
The standard prohibits the discharge of
particulate matter at a rate greater than
0.65 grams/kg of dry sludge input (1.30
Ib/ton) and prohibits the discharge of
any gases exhibiting 20 percent opacity
or greater.
The Clean Air Act Amendments of
1977 require that the Administrator of
the EPA review and, if appropriate,
revise established standards of
performance for new stationary sources
at least every 4 years [Section
lll(b)(l)(B)J. This notice announces that
EPA has undertaken a review of the
standard of performance for sewage
sludge incinerators and sets forth initial
findings based on this review. EPA is
however, deferring a final decision on
the need to revise the standard until
further data can be obtained and
analyzed pertaining to the form of the
standard, parameters affecting emission
rates, and coincineration. Comments on
these findings and this action are
invited.
Findings
Status of Sen-age Sludge Incinerators
It is estimated that approximately 240
municipal sludge incinerator units are
presently in operation. A large number
of incinerators were built in the 1967-
1972 period and this growth has
continued, although at a somewhat
slower rate since 1972. A compilation of
incinerator units subject to the
construction grants program indicated
that 92 new units were either in the
contruction or planning stages in mid-
1977. A total of 23 sludge incinerators
have been identified which are subject
to the standard and which have been
tested for compliance.
Emission Rates and Control Technology
Particulate matter from the inert
material in sludge is present in the flue
gas of sewage sludge incinerators.
Uncontrolled emissions may vary from
as low as 4 g/kg (8 Ib/ton) dry sludge
input to as high as 110 g/kg (220 Ib/ton)
dry sludge input depending upon the
incinerator type and the sludge
composition (e.g., percent volatile solids,
percent moisture, and source treatment).
Since adoption of the standard, wet
scrubbers operating with pressure drops
in the range of 7 to 32 in. WG and a
mean of 20 in. WG have been employed
exclusively and have been successful for
controlling emissions to the level
required by the standard. The average
emission from tests of 26 facilities since
1974 was 0.55 g/kg with a standard
deviatin of 0.35 g/kg (1.1 ±0.7 Ib/ton)
dry sludge input. When tests from one
obviously underdesigned facility and
three facilities not subject to the
standard were deleted, the average
emission was 0.45 g/kg with a standard
deviation of 0.17 g/kg (0.91 ± 0.33 lb/
tori) dry sludge input or about 30 percent
below the standard. The scrubber
configurations which were employed
included three-stage perforated plate
impingment scrubbers operating at 7 to 9
in WG and venturi scrubbers, or venturi
scrubbers in series with various
impingment plate scrubbers operating in
the 9 to 32 in. WG range.
While these test results are consistent
with the standard, an analysis of the test
results shows an inconsistent
relationship between scrubber pressure
drop and emissions as expressed in
units of the standard. This appears to be
due to both the facility type and input
sludge composition, particularly solids
content. Moreover, experimental data
from some of the tested units suggest
that incinerators burning sludge below
20 percent solids may have difficulty
complying with the NSPS. Because
combustion air requirements per unit of
dry sludge increase with increasing
sludge moisture, actual stack volume
concentrations of 0.01 grains/dry
standard cubic meter or less are needed
to meet the standard when high
moisture sludges are incinerated. For
example, two incinerators burning
sludges of 16 percent solids achieved
only marginal compliance and low
volume concentrations of 0 009 and 0.010
grains/acf.
An additional finding based on an
analysis of the test data which are now
available concerns the relationship
between emissions expressed in terms
of grain loading on a dry basis and
emissions per weight of dry sludge
burned. As initially proposed, the
standard was expressed as a volume
concentration standard equal to 0.031
grains/dscf. Due to comments received
relative to the use of dilution air and the
difficulties involved in measuring and
correcting to dry volume, the
promulgated standard was established
at 1.3 Ib/dry ton sludge input. This was
based on data available at the time of
promulgation showing that the
promulgated and proposed standards
were equivalent. However, an analysis
V-0-2
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Federal Register / Vol. 44. No. 229 / Tuesday. November 27, 1979 / Proposed Rules
of the. data which are now available
indicate a nominal equivalence between
1.8 Ib/ton dry sludge and 0.031 grains/
dscf for typical sludges.
One factor at least partially
responsible for the difference in
equivalent emission factors, in addition
to affecting the relationship between
pressure drop and mass emissions, is
the moisture content in the input sludge.
The average solids content of the sludge
associated with the data cited above is
24 percent. However, tests of two other
facilities with input sludge having a
relatively high solids content of between
27 and 33 percent showed an
equivalence similar to that found by
EPA in 1973 (e.g., 0.03 grains/dscf
equivalent to 1.3 Ib/ton dry sludge
input).
Opacity levels from successful
emissions tests never exceeded 15
percent and were most often either 0 or
5 percent. These results are similar to
those found when the standard was first
proposed as a 10 percent value with
exceptions allowed during 2 minutes of
a 60 minute test cycle. This standard
was changed to 20 percent with no
exemptions except during startup, shut
down, or malfunctions. The current data
indicate that the rationale used to arrive
at the 20 percent opacity level till
applies. This rationale, in addition to
field observations obtained with Method
9, involved instrumental data and
theoretical projections of the opacity
which could, under extreme conditions,
occur at a facility complying with the
particulate matter standard. A
reevaluation of this standard was
undertaken and reaffirmation was
announced in the Federal Register on
February 18,1976.
Application of the Standard to
Coincineration
The coincineration of municipal solid
waste and sewage sludge has been
practiced in Europe for several years,
and on a limited scale in the U.S.
However, as energy resources become
scarce and more costly, and where land
disposal is economically or technically
unfeasible, the recovery of the heat
content of dewatered sludge as an
energy source will become more
desirable. Due to this and the
institutional commonality of these
wastes and advances in the
preincineration processing of municipal
refuse to a waste fuel, many
communities may find joint incineration
in energy recovery incinerators an
economically attractive alternative to
their waste disposal problems.
Coincineration of municipal solid
waste and sewage sludge, as described
above, is not explicitly covered in 40
CFR 60. The particulate standard for
municipal solid waste described in
Subpart E (0.18 g/dscm or 0.08 g/dscf at
12 percent COa) applies to the
incineration of municipal solid waste in
furnaces with a capacity of at least 45
Mg/day (50 tons/day). Subpart O, the
particulate standard for sewage sludge
incineration (0.65 g/kg dry sludge input
or 1.3 Ib/ton dry sludge), applies to any
incinerator that burns sewage sludge,
with the exception of small communities
practicing coincineration.
To clarify the situation when
coincineration is involved, EPA adopted
the policy that when an incinerator with
a capacity of at least 45 Mg/day (50
tons/day) burns at least 50 percent
municipal solid waste, then the Subpart
E applies regardless of the amount of
sewage sludge burned. When more than
50 percent sewage sludge and more than
45 Mg/day (50 tons) is incinerated, the
standard is based upon Subpart O or,
alternatively, a proration between
Subparts O and E. The proration
scheme, however, has a discontinuity
when a municipal incinerator burns 50
percent solid waste.
The alternative of prorating the
Subparts E and O is not straight-
forward, since the two standards are
stated in different units. The proration
scheme requires a transformation of the
municipal incineration standard
(Subpart E) from grams per dry standard
cubic meter (grains per dry standard
cubic foot) at 12 percent COj to grams
per kilograms (pounds per dry ton)
refuse input, or a transformation of the
sewage sludge standard (Subpart O)
from grams per dry kilograms (pounds
per dry ton) input to grams per dry
standard cubic meter at 12 percent CO*
Such transformations are dependent on
the percent CO, in the flue gas stream,
the stoichiometric air requirements,
excess air, the volume of combustion
products to require air, and percent
moisture in refuse or sludge, and the
heat content of the sludge and solid
waste.
Other Pollutants
Incineration of sewage sludge results
in the emission to the atmosphere of
trace elements and compounds, some of
which are hazardous or potentially
hazardous. Substances of concern
include mercury, lead, cadmium,
pesticides, and organic matter. Among
these, mercury emissions from sewage
sludge incinerators are specifically
limited under the National Emission
Standards for Hazardous Air Pollutants
(40 CFR 61.50 et seq.).
The emission of other trace
compounds and elements, while not
subject to specific limitations is
controlled by particulate matter control
equipment or directly by the high
temperatures in the combustion process
and with the exception of cadmium, no
data were obtained during this review to
indicate a need for specific limitations
on emissions of these materials resulting
from incineration of typical sludges.
Tests have shown high destruction
efficiencies for pesticides, and organics
in sewage sludge incinerators. Similarly,
test data suggest that high pressure
scrubbers of the type normally
employed to meet the particulate
standards also reduce lead emissions to
below the level required to meet
ambient standards. In contrast, data
suggest that cadmium emissions may
not be adequately controlled. A separate
program is underway in EPA to
independently assess the need to
regulate cadmium. Final decisions on
this will be announced in a separate
action. In the event that the need to limit
cadmium emissions from sewage sludge
incinerators is indicated, appropriate
action will be taken.
Conclusions
The available test data support the
validity of the standard. However, the
marginal compliance of several facilities
operating with high pressure drops, the
apparent relationship between sludge
moisture content and emission rates,
and the inconsistent relationship
between pressure drop and scrubber
performance as measured in terms of the
standard are matters which require
further study. Such a study will be
undertaken later and will include further
analysis of data regarding sludge
dewatering, incinerator types, control
technology, and the relationship
between control device operating
parameters, sludge solids content,
emission rates, and alternative forms for
expression of emission rates. This will
also include an analysis of alternativp
means for establishment of standards
applicable to coincineration. A final
conclusion on the need for revision of
the standard will not be made until this
study is complete.
Dated: November 16. 1979.
Barbara Blum,
Acting Administrator.
|FR Doc 79-36473 Filed 11-26-79, 845 urn]
V-0-3
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PROPOSED RULES
definitions of a BOPP. Also, the defi-
nition of the operating cycle during
which sampling is performed requires
clarification. Specifically, the stack
emissions averaged over the oxygen
blow part of the cycle could be signifi-
cantly different from the emissions av-
eraged over a period or periods that
Includes scrap preheating and turn-
down for vessel sampling. The current
standard is unclear as to which averag-
ing time should be used. Since no tests
to date have come under the NSPS,
averaging time has not been an issue;
however, Interpreting the standard
will be a problem until this matter is
resolved.
CONCLUSIONS
Based upon the above findings, the
following conclusions have been
reached by EPA:
(1) The best demonstrated systems
of emissions control at the time the
standard for primary emissions was es-
tablished for BOPF have not changed
in the past 5 years. (See APTD-1352c
(EPA/2-74-003), Background Informa-
tion for New Source Performance
Standards, Volume 3, Promulgated
Standards.) These technologies con-
trol emissions to a level consistent
with the current standard; therefore,
revision to the existing standard is not
required, if only primary emissions are
to be controlled.
(2) Secondary or fugitive emissions
from BOPFs represent a major air pol-
lution emission source. EPA, there-
fore, intends to initiate a project to
revise the existing standard of per-
formance to include fugitive emissions.
This development project is planned
to begin during 1979 and lead to a pro-
posal 20 months after initiation. In ad-
dition, an assessment of foreign tech-
nology, which ahs been initiated by
the Agency, will be included in the
basis for the revised standard. The as-
sessment may lead to further conclu-
sions about the allowable emissions
from the primary gas cleaning stack
due to the interdependence of primary
and secondary control technologies.
(3) The ambiguities in the present
standard concerning definition of a
BOPF and the operating cycle to be
measured should be clarified, and a
project to do so has been initiated.
PUBLIC PARTICIPATION
All interested persons are invited to
comment on this review, the conclu-
sions, and EPA's planned action. Com-
ments should be submitted to: Mr.
Don Goodwin (MD-13), Emission
Standards and Engineering Division,
U.S. Environmental Protection
Agency, Research Triangle Park, N.C.
27711.
Dated: March 9, 1979.
BARBARA BLUM,
Acting Administrator.
[FR Doc. 79-8360* Filed 3-20-79; 8:45 am]
FEDERAL REGISTER, VOL. 44, NO. 56WEDNESDAY, MARCH 21, >979
V-N-3
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ENVIRONMENTAL
PROTECTION
AGENCY
STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
GLASS MANUFACTURING PLANTS
SUBPART CC
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Federal Register / Vol. 44, No. 117 / Friday, June 15,1979 / Proposed Rules
ENVIRONMENTAL PROTECTION
AGENCY
[40 CFR Part 601
[FRL 1203-7]
Standards of Performance for New
Stationary Sources; Glass
Manufacturing Plants
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Proposed rule and notice of
public hearing.
SUMMARY: The proposed standards
would limit emissions of participate
matter from new, modified, and
reconstructed glass manufacturing
plants. The standards implement the
Clean Air Act and are based on the
Administrator's determination that glass
manufacturing plants contribute
significantly to air pollution. The
intended effect is to require new,
modified, and reconstructed glass
manufacturing plants to use the best
demonstrated system of continuous
emission reduction, considering costs,
nonair quality health and environmental
impact, and energy impacts.
A public hearing will be held to
provide interested persons an opportuity
for oral presentation of data, views, or
arguments concerning the proposed
standards.
DATES: Comments. Comments must be
received on or before August 14,1979,
Public Hearing. The public hearing
will be held on July 9,1979 beginning at
9:30 a.m. and ending at 4:30 p.m.
Request to Speak at Hearing. Persons
wishing to present oral testimony at the
hearing should contact EPA by June 29,
1979.
ADDRESSES: Comments. Comments
should be submitted to Central Docket
Section (A-130), United States
Environmental Protection Agency, 401M
Street, S.W., Washington, D.C. 20460,
Attention: Docket No. OAQPS 79-2.
Public Hearing. The public will be
held at Office of Administration
Auditorium, Research Triangle
Park, North Carolina 27771. Persons
wishing to present oral testimony should
notify Mary Jane Clark, Emission
Standards and Engineering Division
(MD-13), Environmental Protection
Agency, Rsearch Triangle Park, North
Carolina 27711, telephone (919) 541-
5271.
Standards Support Document. The
support document for the proposes
tandards may be obained from the U.S.
EPA Library (MD-35), Research Triangle
Park, North Carolina 27711, telephone
number (919) 541-2777. Please refer to
"Glass Manufacturing Plants,
Background Information: Proposed
Standards of Performance," EPA-450/3-
79-005a.
Docket. A docket, number OAQPS 79-
2, containing information used by EPA
in development of the proposed
standard, is available for public
inspection between 8:00 a.m. and 4:00
p.m. Monday through Friday, at EPA's
Central Docket Section (A-130), Room
2903 B, Waterside Mall, 401 M Street.
S.W., Washington, D.C. 20460.
FOR FURTHER INFORMATION CONTACT:
Mr. Don R. Goodwin, Director, Emission
Standards and Engineering Division
(MD-13), Environmental Protection
Agency, Research Triangle Park, North
Carolina 27711, telephone number (919)
541-5271.
SUPPLEMENTARY INFORMATION:
Proposed Standards
The standards would apply to glass
melting furnaces with glass
manufacturing plants with two
exceptions: day pot furnaces (which
melt two tons or less of glass per day)
and all-electric melting furnaces. No
existing plants would be covered unless
they were to undergo modification or
reconstruction. Change of fuel from gas
to fuel oil would be exempt from
consideration as a modification and
rebricking of furnaces would be exempt
from consideration as reconstruction.
Specifically, the proposed standards
would limit exhaust emissions from gas-
fired glass melting furnaces to 0.15
grams of particulate matter per kilogram
of glass produced for flat glass
production; 0.1 g/kg (0.2 Ib/ton) for
container glass production; 0.2 g/kg (0.4
Ib/ton) for wool fiberglass production;
0.1 g/kg (0.2 Ib/ton) for pressed and
blown glass production of soda-lime
formulation; and 0.25 g/kg (0.5 Ib/ton)
for pressed and blown glass production
of borosilicate, opal, and other
formulations. A15 percent allowance
above the emission limits for gas-fired
furnaces is proposed for fuel oil-fired
glass melting furnaces and an additional
proportionate allowance is proposed for
furnaces simultaneously firing gas and
fuel oil.
Summary of Environmental and
Economic Impacts
Environmental Impacts
The proposed standards would reduce
projected 1983 emissions from new
uncontrolled glass melting furnaces from
about 5,200 megagrams (Mo)/year (5,732
ton/year) to about 400 Mg/year (441
ton/year). This is a reduction of about
92 percent of uncontrolled emissions.
Meeting a typical State Implementation
Plan (SIP), however, would reduce
emissions from new uncontrolled
furnaces by about 3,700 Mg/year (4,079
ton/year), or by about 70 percent. The
proposed standard would exceed the
reduction achieved under a typical SIP
by about 1,100 Mg/year (1,213 ton-year).
This reduction in emissions would result
in a reduction of ambient air
concentrations of particulate matter in
the vicinity of new glass manufacturing
plants.
The proposed standards are based on
the use of electrostatic precipitators
(ESP's) and fabric filters, which are dry
control techniques; therefore, no water
discharge would be generated and there
would be no adverse water pollution
impact.
The solid waste impact of the
proposed standards would be minimal.
Less than 2 Mg (2.2 ton) of particulate
would be collected for every 1,000 Mg
(1,102 ton) of glass produced. These
dusts can generally be recycled, or they
can be landfilled if recycling proves to
be unattractive. The current solid waste
disposal practice among most controlled
plants surveyed is landfilling. Since
landfill operations are subject to State
regulation, this disposal method would
not be expected to have an adverse
environmental impact. The additional
solid material collected under the
proposed standard would not differ
chemically from the material collected
under a typical SIP regulation; therefore,
adverse impact from landfilling should
be minimal. Also, recycling of the solids
has no adverse environmental impact.
For typical plants in the glass
manufacturing industry, the increased
'energy consumption that would result
from the proposed standards ranges
from about 0.1 to 2 percent of the energy
consumed to produce glass. The energy
required in excess of that required by a
typical SIP regulation to control all new
glass melting furnaces constructed by
1983 to the level of the proposed
standards would be about 2,500
kilowatt-hours per day in the fifth year
and is considered negligible. Thus, the
proposed standards would have a
minimal impact on national energy
consumption.
Economic Impacts
The economic impact of the proposed
standards is reasonable. Compliance
with the standards would result in
annualized costs in the glass
manufacturing industry of about $8.5
million by 1983. For typical plants
constructed between 1978-1983 capital
costs associated with the proposed
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Federal Register / Vol. 44, No. 117 / Friday. June 15. 1979 / Proposed Rules
standards would range from about
$235,000 for a small furnace in the
pressed and blown glass sector which
melts formulations other than soda-lime
to about $770,000 for a large pressed and
blown glass furnace which melts soda-
lime formulations. Annualized costs
associated with the proposed standards
would range from about $70,000/year to
about $235,000/year for the furnaces
mentioned above. Cumulative capital
costs of complying with the proposed
standards for the glass manufacturing
industry as a whole would amount to
about $28 million between 1978-1983.
The percent price increase necessary to
offset costs of compliance with the
proposed standards would range from
about 0.3 percent in the wool fiberglass
sector to about 1.8 percent in the
container glass sector. Industry-wide,
the price increase would amount to
about 0.7 percent.
The economic impact of the proposed
standards may vary depending on the
size of the glass melting furnace being
considered. EPA is requesting comments
specifically on the economic impact of
the proposed standards with regard to a
possible lower cut-off size for glass
melting furnaces.
Rationale
Selection of Source and Pollutants
The proposed Priority List, 40 CFR
60.16, identifies various sources of
emissions on a nationwide basis in
terms of the quantities of emissions from
source categories, the mobility and
competitive nature of each source
category, and the extent to which each
pollutant endangers health or welfare.
The sources on this proposed list are
ranked in decreasing order. Class
manufacturing ranks 38th on the
proposed list, and is therefore of
considerable importance nationwide.
The production of glass is projected to
increase at compounded annual growth
rates of up to 7 percent through the year
1983. In 1975, over 17 million megagrams
(18.8 million ton} of glass were
produced; by 1983 this production rate is
expected to increase by nearly 2.9
million Mg/year (3.2 million ton/year).
Geographically, the glass manufacturing
industry is relatively concentrated with
plants currently located in 17 states.
Total particulate emissions in the United
States in 1975 were estimated to be
about 12.4 million Mg/year (13.7 million
ton/year); by the year 1983 new glass
manufacturing plants would cause
annual nationwide particulate matter
emissions to increase by about 1,500
Mg/year (1.620 ton/year) with emissions
controlled to the level of a typical SIP
regulation.
On March 18,1977, the Governor of
New Jersey petitioned EPA to establish
standards of performance for glass
manufacturing plants. The petition was
primarily motivated by the Governor's
concern that the glass manufacturing
industry might locate plants in other
States rather than comply with New
Jersey's air pollution regulations limiting
emissions of particulate matter. The
glass manufacturing industry is not
geographically tied to either markets or
resources. Only a few States have
specialized air pollution standards for
glass manufacturing plants in their SIP's,
and these standards vary in the level of
control required. Therefore, new glass
manufacturing operations could be
located in States which do not have
stringent SIP regulations.
Glass manufacturing plants are
significant contributors to nationwide
emissions of particulate matter,
especially when viewed as contributors
to emissions in the limited number of
States in which they are located. They
rank high with regard to potential
reduction of emissions. Since they are
free to relocate in terms of both markets
and required resources, the possibility
exists that operations could be moved or
relocated to avoid stringent SIP
regulations, thereby generating
economic dislocations. For these
reasons, emissions of particulate matter
from new glass manufacturing plants
have been selected for control by NSPS.
Glass manufacturing plants also emit
other criteria pollutants: sulfur oxides
(SO,), nitrogen oxides (NOJ, carbon
monoxide, and hydrocarbons. Carbon
monoxide and hydrocarbon emissions
from efficiently operated glass
manufacturing plants, however, are
negligible.
Nationwide, the largest aggregate
emissions from glass manufacturing
plants are NO,. The techniques
generally applicable to control NO,
produced by combustion are staged
combustion, off-stoichiometric
combustion, or reduced-temperature
combustion. To date none of these
techniques has been applied to the
control of NO, emissions from glass
melting furnaces. Accordingly, there is
no way of determining how effective
they might be in such applications.
Consequently, NO, was not selected for
control by standards of performance.
SOt emissions result from combustion
of sulfur-containing fuels and from
chemical reactions of raw materials. In
general there are two alternatives for
control of SO, emissions: (1) scrubbing
of exhaust gases containing SO,, and (2)
reducing the sulfur content of fuel and
raw materials. SO* emissions from glass
melting furnaces are in most cases
already less than the emission limits of
applicable SIP's for fuel burning sources.
Flue-gas scrubbing for control of SO*
emissions from glass melting furnaces is
not considered economically
reasonable.
There are difficulties as well with the
use of low-sulfur fuels or reduction of
sulfur content of raw materials. Using
low-sulfur fuel would not adequately
address the problem of SOj control for
two reasons. Natural gas is the preferred
fuel for glass melting furnaces. The only
alternative fuel currently in use or
projected for future use by the glass
manufacturing industry is distillate fuel
oil, which normally contains more sulfur
than natural gas. The elimination of
sulfur-containing fuel oil is not
considered reasonable. Alternatively,
standards of performance based solely
on combustion of low-sulfur fuels could
distort existing fuel distribution
patterns, since low-sulfur fuels could be
diverted to new facilities to meet NSPS
in areas that have no difficulty attaining
or maintaining the National Ambient Air
Quality Standards (NAAQS) for SO,.
This would reduce the supply of low-
sulfur fuels for existing facilities in areas
that have great difficulty attaining or
maintaining the NAAQS for SO,.
Consequently, standards of performance
for SO, emissions based on use of low-
sulfur fuels do not seem reasonable.
Use of reduced-sulfur raw materials
has not been demonstrated as a means
of reducing SO, emissions from glass
melting furnaces. There is a wide variety
of formulations, most of which are
considered by the industry to be trade
secrets. The present state of glass
making is such that formula alterations
of the type envisioned here would lead
to glass of unpredictable quality. For
these reasons, standards of performance
for SO, emissions from glass melting
furnaces based on reduced-sulfur raw
materials, or any other approach, do not
seem reasonable and have not been
proposed.
Selection of Affected Facility
Ninety-eight percent of the particulate
matter emitted from glass manufacturing
plants is emitted in gaseous exhaust
streams from glass melting furnaces.
Only two percent of the particulate
matter emitted from glass manufacturing
plants is emitted from raw material
handling and glass forming and
finishing. Therefore, the glass melting
furnace has been selected as the
affected facility.
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The proposed standards would apply
to all glass melting furnaces within glass
manufacturing plants with two
exceptions: day pot furnaces and all-
electric melters. A day pot furnace is a
glass melting furnace which is capable
of producing no more than two tons of
glass per day. These small glass melting
furnaces constitute an extremely small
percentage of total glass production and
their control is not considered
economically reasonable. Therefore, the
regulation exempts day pot furnaces
from the proposed standards.
Well operated and maintained all-
electric furnaces have particulate
emissions only slightly higher than
fossil-fuel fired furnaces controlled to
meet the proposed standards. Most of
these furnaces are open to the
atmosphere and do not have stacks.
Thus, control and measurement of
emissions from all-electric furnaces does
not appear to be economically
reasonable. Therefore, all-electric
melting furnaces are not regulated by
the proposed standards.
Selection of Format
Two alternative formats were
considered for the proposed standards:
mass standards, which limit emissions
per unit of feed to the glass furnace or
per unit of glass produced by the glass
furnace; and concentration standards,
which limit emissions per unit volume of
exhaust gases discharged to the
atmosphere.
Enforcement of concentration
standards requires a minimum of data
and information, decreasing the costs of
enforcement and reducing chances of
error. Furthermore, vendors of emission
control equipment usually guarantee
equipment performance in terms of the
pollutant concentration in the discharge
gas stream.
There is a potential for circumventing
concentration standards by diluting the
exhaust gases discharged to the
atmosphere with excess air, thus
lowering the concentration of pollutants
emitted but not the total mass emitted.
This problem can be overcome,
however, by correcting the
concentration measured in the gas
stream to a reference condition such as
a specified oxygen percentage in the gas
stream.
Concentration standards would
penalize energy-efficient furnaces, since
a decrease in the amount of fuel
required to melt glass decreases the
volume of gases released but not the
quantity of particulate matter emitted.
As a result, the concentration of
particulate matter in the exhaust gas
stream would be increased even though
the total mass emitted remained the
same. Even if a concentration standard
were corrected to a specified oxygen
content in the gas stream, this penalizing
effect of the concentration would not be
overcome.
Primary disadvantages of mass
standards, as compared to concentration
standards, are that their enforcement Is
more costly and that the more numerous
calculations required increase the
opportunities for error. Detemining mass
emissions requires the development of a
material balance on process data
concerning the operation of the plant,
whether it be input flow rates or
production flow rates. Development of
this balance depends on the availability
and reliability of production figures
supplied by the plant. Gathering of these
data increases the testing or monitoring
necessary, the time involved, and,
consequently, the costs. Manipulation of
these data increases the number of
calculations necessary; e.g., the
conversion of volumetric flow rates to
mass flow rates, thus compounding error
inherent in the data and increasing the
chance for error.
Although concentration standards
involve lower resource requirements
than mass standards, mass standards
are more suitable for regulation of
particulate emissions from glass melting
furnaces because of their flexibility to
accommodate process improvements
and their direct relationship to quantity
of particulate emitted to the atmosphere.
These advantages outweigh the
drawbacks associated with creating and
manipulated a data base. Consequently,
mass standards are selected as the
format for expressing standards of
performance for glass melting furnaces.
The proposed standards express
allowable particulate emissions in
grams of particulates per kilogram of
glass pulled. While emissions data
referring to raw material input as well
as data referring to glass pulled were
used in the development of the
standards, an examination of the
several sectors of the glass
manufacturing industry indicated that
an emission rate based on quantity of
glass pulled would be more
representative of industry practice.
Further, emissions are more dependent
on pull rate than on rate of raw material
input. Accordingly, the mass of glass
pulled is used as the denominator in the
proposed standards. Raw material input
data could be employed to estimate
glass pulled from a furnace if a
quantitative relationship between raw
material input and glass pulled were
developed following good engineering
methods.
Selection of the Best System of Emission
Reduction and Emission Limits
Introduction
Particulate emissions from glass
melting furnaces can be reduced
significantly by the use of the following
emission control techniques:
electrostatic precipitators, fabric filters,
and verituri scrubbers. Since these
emission control techniques do not
achieve the same level of control for
glass melting furnace emissions within
all sectors of the glass manufacturing
industry, they are discussed separately
for each sector.
Process modifications such as batch
formulation alteration and electric
boosting also may be capable of
reducing particulate emissions from
glass melting furnaces. The test data
available for furnaces where process
modifications are used as emissions
reduction techniques indicate that
emission, reduction by process
modification is indifmite with respect to
the effectiveness of the techniques.
Accordingly, the selection of the best
system of emission reduction is based
on the use of add-on emission reduction
techniques of known effectiveness.
However, there is nothing in this
proposal nor is it the intent of this
proposal to preclude the use of process
modifications to comply with the
proposed standards.
The glass manufacturing industry is
divided into four principal sectors
designated by Standard Industrial
Classifications (SIC's). The container
glass sector (SIC 3221] manufactures
containers for commercial packing and
bottling and for home canning by
pressing (stamping) and/or blowing (air-
forming) molten glass usually of soda-
lime recipe. The pressed and blown
glass, not elsewhere classified, sector
(SIC 3229) includes such diverse
products as: table, kitchen, art and
novelty glassware; lighting and
electronic glassware; scientific,
technical, and other glassware; and
textile glass fibers. Based on the
differing rates of particulate matter
emissions, it is necessary to subdivide
the pressed and blown glass sector into
plants producing glass from soda-lime
formulations and plants producing glass
from other formulation (primarily
borosilicate, opal and lead). Glass
manufacturing plants in the wool
fiberglass sector are classified under
mineral wool (SIC 3296); fiberglass
insulation is a major product. The flat
glass sector (SIC 3211) uses continuous
glass forming processes, and materials
almost exclusively of soda lime
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formulation, to manufacture sheet, plate,
float, rolled, and wire glass.
Each of the glass manufacturing
sectors is unique both from a technical
and an economic standpoint. Thus,
uncontrolled participate emission rate,
furnace size, and the applicability of
emission control techniques vary from
one sector to another. Since the products
manufactured by the different sectors of
the glass manufacturing industry serve
different markets, each sector is working
in a different economic environment. For
these reasons it was apparent that no
single model furnace could adequately
characterize the glass manufacturing
industry. Accordingly, several model
furnaces were specified in terms of the
following parameters: production rate,
stack height, stack diameter, exhaust
gas exit velocity, exhaust gas flow rate,
and exhaust gas temperature. The
evaluation, of these parameters may be
found in the Background Information
document. The model furnace
production rate specified for the
container glass sector was 225 Mg/day
(250 ton/day). For pressed and blown
glass furnaces melting soda-lime and
other formulations two model furnace
production rates were specified: 45 Mg/
day (50 ton/day) and 90 Mg/day (100
ton/day). Model furnace production
rates for the wool fiberglass and flat
glass sector were 180 Mg/day (200 ton/
day) and 635 Mg/day (700 ton/day),
respectively.
Review of the performance of the
emission control techniques led to the
identification of two regulatory options
for each sector. These options specify
numerical emission limits for glass
melting furnaces in each sector of the
glass manufacturing industry. The
environmental impacts, energy impacts,
and cost and economic impacts of each
regulatory option were compared with
those associated with a typical SIP
regulation and those associated with no
control.
Container Glass
Uncontrolled particulate emissions
from container glass furnaces are
generally about 1.25 g/kg (2.5 Ib/ton) of
glass pulled. Emission tests (using EPA
Method 5) on three container glass
furnaces equipped with ESP's indicate
an average particulate emission of 0.06
g/kg (0.12 Ib/ton) of glass pulled.
Emission test data for container glass
furnaces equipped with fabric filters are
not available. However, emission test
results for a pressed and blown glass
furnace melting a soda-lime formulation
essentially identical to that used for
container glass indicate that emissions
can be reduced to 0.12 g/kg (0.24 Ib/ton)
of glass pulled with a fabric filter. This
fabric filter installation was tested with
the Los Angeles Air Pollution Control
District particulate matter test method
(LAAPCD Method), which considers the
combined weight of the particulate
matter collected in water-filled
impmgers and of that collected on a
filter. EPA Method 5 also uses impingers
and a filter, but considers only the
weight of the particulate matter
collected on the filter. The LAAPCD
Method collects a larger amount of
particulate matter than does EPA
Method 5, and, consequently, greater
mass emissions would be reported for
comparable tests. An emission level of
0.1 g/kg (0.2 Ib/ton) as determined by
EPA Method 5, could be achieved by a
container glass furnace equipped with a
properly designed and operated fabric
filter.
EPA Method 5 tests of four furnaces
equipped with venturi scrubbers
indicated an average particulate
emission of 0.21 g/kg (0.42 Ib/ton) of
glass pulled.
Based on the data cited above, an
emission level of 0.1 g/kg (0.2 Ib/ton) of
glass pulled from container glass
furnaces can be achieved with ESFs or
fabric filters. An emission level of 0.2 g/
kg (0.4 Ib/ton) of glass pulled can
reasonably be achieved with a venturi
scrubber when operated at a pressure
drop somewhat higher than the average
of those scrubbers tested. ESP's and
fabric filters could also be designed to
achieve an emission level of 0.2 g/kg (0.4
Ib/ton) of glass pulled.
On the basis of these conclusions, two
regulatory options for reducing
particulate emissions from container
glass furnaces were formulated. Option I
would set an emission limit of 0.1 g/kg
(0.2 Ib/ton), requiring a particulate
emission reduction of somewhat over 90
percent as compared with an
uncontrolled furnace. Option II would
set an emission limit of 0.2 g/kg (0.4 lb/
ton), requiring a particulate emission
reduction of about 85 percent.
By 1983 approximately 1900 gigagrams
(Ggj/year (2.1 million ton/year) of
additional production is anticipated in
the container glass sector. About 25 new
container glass furnaces of about 225
Mg/day (250 ton/day) production
capacity (the size of the model furnace)
would be built in order to provide this
additional production. If uncontrolled,
these new container glass furnaces
would add about 2,400 Mg/year (2,646
ton/year) to national particulate
emissions by 1983. Compliance with a
typical SIP regulation would reduce this
impact to about 1,000 Mg/year (1,102
ton/year). Under Option I, emissions
would be reduced to about 19 percent of
those emitted under a typical SIP
regulation. Under Option II, emissions
would be reduced to about 38 percent of
those emitted under a typical SIP
regulation.
Ambient dispersion modeling
indicates that under worst case
conditions the annual maximum ground-
level particulate concentration near an
uncontrolled container glass furnace
producing 225 Mg/day of glass would be
less than 1 fig/ms. The annual maximum
ground-level concentration resulting
from compliance with a typical SIP
regulation. Option I, or Option II would
also be less than 1 pg/m'. The
calculated maximum 24-hour ground-
level particulate concentration near an
uncontrolled container glass furnace
producing 225 Mg/day of glass would be
approximately 10 jig/m*. The
corresponding concentration for
complying with a typical SIP regulation
would be 5 fig/m1. Under Option I, with
an ESP or a fabric filter being employed
for control, the maximum 24-hour
ground-level concentration would be
reduced to 1 jig/m". Under Option II,
with the same techniques being
employed, the concentration would be
reduced to 2 fig/ms. Use of a venturi
scrubber to meet the Option II emissions
limit would only reduce the
concentration to 6 jig/m*due to the
decreased stack height of a scrubber-
controlled plant and the resulting
increased building wake effects.
With one exception, standards of
performance for container glass
furnaces would have no water pollution
impact. The exception would be the use
of a venturi scrubber to comply with a
standard based on Option II. Such a
system, applied to a furnace producing
225 Mg/day of glass, would discharge
about 0.5 m'/hr of waste water
containing about 5 percent solids. The
waste water would probably be
discharged directly to an available
waste water treatment system. To date,
however, only a few container glass
furnaces have been controlled with
venturi scrubbers; dry collection
techniques have been preferred.
Consequently, few container glass
manufacturers would be expected to
install venturi scrubbers on their
furnaces to comply with a standard
based on Option II. The overall water
pollution impact would then be
negligible.
The potential solid waste impacts of
the regulatory options would result from
collected particulate matter. Solid waste
from container glass furnaces, other
than collected particulate matter, is
minimal since cullet is normally
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recycled back into the glass melting
process. Under a typical SIP regulation,
about 1.400 Mg/year (1,543 ton/year) of
particulate matter would be collected
from the 25 new 225 Mg/day container
glass furnaces projected to come on-
stream during the 1978-1983 period.
Compliance with standards based on
Option I and Option II would add about
800 Mg/year (882 ton/year) and about
600 Mg/year (661 ton/year),
respectively, to the solid waste collected
under a typical SIP regulation. Option I
would increase the mass of solids for
disposal by about 60 percent over that
resulting from compliance with a typical
SIP regulation, and Option n would
increase it by about 45 percent. The
additional solid material collected under
Option I or Option II would not differ
chemically from the material collected
under a typical SIP regulation. Collected
solids either are recycled back into the
glass melting process or are disposed of
in a landfill. Recycling of the solids has
no adverse environmental impact, and,
since landfill operations are subject to
State regulation, this disposal method
also would not be expected to have an
adverse environmental impact.
The potential energy impacts of the
regulatory options would be due to the
energy used to drive the fans in
emission control systems and the energy
used to charge the electrodes in ESP's.
Since ESP's have been the predominant
control system use'd in the industry, the
energy requirements estimated for a
typical SIP regulation, Option I, and
Option II were based on the use of
ESP's. The energy required to control
particulate emissions from the 25 new
container glass furnaces would be about
40 million kWh (22 thousand barrels of
oil/year) for a typical SIP regulation for
the new furnaces equipped with ESP's.
This required energy would be about 0.2
percent of the total energy use in the
container glass sector. There would be
no energy impact associated with either
Option I or Option II because the energy
required to operate an ESP for Option I
or Ogtion II is essentially the same as
the energy required to operate an ESP
for a typical SIP regulation.
Incremental installed cost (cost in
excess of a typical SIP regulation cost)
in January 1978 dollars associated with
Option I for controlling particulate
emissions from a 225 Mg/day container
glass furnace would be about $700
thousand for an ESP and about $1.2
million for a fabric filter. Incremental
installed cost associated with Option II
would be about $450 thousand for an
ESP, and about $1 million for a fabric
filter. The incremental installed cost of
control equipment associated with
Option I level of control would be about
1.6 times the incremental installed cost
associated with Option II if ESP's were
selected. If fabric filters were selected,
the incremental installed cost associated
with the Option I level of control would
be about 1.2 times the incremental
installed cost associated with Option II.
Incremental annualized costs
associated with Option I for a 225 Mg/
day furnace would be about $200
thousand/year and about $350
thousand/year for an ESP and a fabric
filter, respectively. Incremental
annualized costs associated with Option
II would be about $130 thousand/year
for an ESP, and about $300 thousand/
year for a fabric filter. The incremental
annualized cost associated with Option
I would be about 1.5 times the
incremental annualized cost associated
with Option II if ESP's were used. If
fabric filters were used the incremental
annualized cost associated with Option
I would be about 1.2 times the
incremental annualized cost associated
with Option II.
Based on the use of control equipment
with the highest annualized cost (worst
case conditions), a price increase of
about 1.8 percent would be necessary to
offset the cost of installing control
equipment on a 225 Mg/day container
glass furnace to meet the emissions limit
of Option I. A price increase of a~bout 1.5
percent would be necessary to comply
with the emission limit of Option II.
Incremental cumulative capital costs
for the 25 new 225 Mg/day container
glass furnaces during the 1978-1983
period associated with Option I would
be about $17 million if ESP's were used.
Use of ESP's to comply with a standard
based on Option II would require
incremental cumulative capital costs of
about $11 million for the same period.
Fifth-year annualized costs for
controlling container glass melting
furnaces to comply with Option I would
be about $5 million/year. To comply
with Option II, fifth-year annualized
costs would be about $3 million/year.
A summary of incremental impacts (in
excess of impacts of a typical SIP
regulation] associated with Option I and
Option II is shown in Table 1. Air
impacts, expressed in Mg/year of
particulate matter emissions reduced,
would approximate the quantity of
particulate matter collected and
disposed of as solid waste.
Tabto \.Summary of Incremental Impacts
Associated With Regulatory Options
Impacts
A»' Water Energy' Economic"
Regulatory
option:
1 800 None Negligible ... -1.8
II 600 Negligible ....Negligible ... ~1.!>
'Mg/Yr reduced.
'Barrels of oil/day
' Percent price Increase.
Consideration of the beneficial impact
on national particulate emissions, the
degree of water pollution impact, the
small potential for adverse solid waste
impact, the lack of energy impact, the
reasonableness of cost impact, and the
general availability of demonstrated
emission control technology leads to the
selection of Option I as the basis for
standards for glass melting furnaces in
the container glass sector.
Pressed and Blown GlassSoda-Lime
Formulation
Because the glass production rates,
the furnace configurations, and the glass
formulations melted in furnaces in this
sector are very similar to those in
container glass sector, the quantity and
chemical composition of particulate
emissions approximate those of
container glass furnaces. On the basis of
this similarity of process and emissions,
the emission reduction techniques which
have been shown to be effective for
container glass furnaces would also be
effective in reducing particulate
emissions from furnaces in this sector.
Uncontrolled particulate emissions
from pressed and blown glass furnaces
melting soda-lime formulations are
generally about 1.25 g/kg (2.5 Ib/ton) of
glass pulled from the furnace. Test data
for a pressed and blown glass furnace
melting a soda-lime formulation and
equipped with a fabric filter indicate
particulate emissions of 0.12 g/kg (0.24
Ib/ton) of glass pulled using the
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LAAPCD Method. No emissions data for
pressed and blown glass furnaces
equipped with ESP'8 are available.
However, emission tests- using EPA
Method 5 on three container-glass
furnaces equipped with ESP's indicate
an average particulate emission rate of
0.06 g/kg (0.12 Ib/ton) of glass pulled.
Because of the similarities between this
sector and the container glass sector,
both ESP's and fabric filters would be
expected to be capable of reducing
emissions to about 0.1 g/kg (0.2 Ib/ton)
of glass pulled.
Based on the similarity of pressed and
blown glass production methods in this
sector to those of the container glass
sector, as well as on test data available
on container glass furnace emissions,
two regulatory options were formulated.
The regulatory options are identical to
those formulated for container glass
furnaces. Option I would set an
emission limit of 0.1 g/kg (0.2 Ib/ton) of
glass pulled, which would require a
particulate emission reduction of about
90 percent. Option II would set an
emission limit of 0.2 g/kg (0.4 Ib/ton) of
glass pulled, which would require about
85 percent particulate emission
reduction.
By 1983 approximately 310 Mg/year
(342 ton/year) of additional production
is anticipated in this glass
manufacturing sector. About four new 45
Mg/day (50 ton/day] (small) and six
new 90 Mg/day (100 ton/day) (large)
furnaces would be built in order to
provide this production. Emissions from
the large furnaces would have to be
reduced in order to comply with a
typical SIP regulation, while small
furnaces would meet a typical SIP
regulation without reducing emissions. If
uncontrolled, the four new small
furnaces would add about 80 Mg/year
(88 ton/year) to national particulate
emissions by 1983, while the six new
large furnaces would add about 230 Mg/
year (254 ton/year). Compliance with a
typical SIP regulation would reduce the
impact of the new large furnaces to
about 70 Mg/year (77 ton/year). Under
Option I, these furnace emissions would
be reduced to about 26 percent of those
emitted under a typical SIP regulation.
Under Option II, large furnace emissions
would be reduced to about 53 percent of
those emitted under a typical SIP
regulation.
The small furnaces would be in
compliance with a typical SIP regulation
without control. Under Option I,
emissions would be reduced to about 8
percent of uncontrolled emissions.
Under Option II, emissions would be
reduced to about 16 percent of
uncontrolled emissions.
The effect of a typical SIP regulation
for both 90 Mg/day (100 ton/day) and 45
Mg/day (50 ton/day) furnaces would be
a reduction of about 48 percent of
uncontrolled emissions. Under Option I,
emissions would be reduced to about 16
percent of those emitted under a typical
SIP regulation. Under Option II,
emissions would be reduced to about 33
percent of those emitted under a typical
SIP regulation.
Ambient dispersion modeling
indicates that under worst case
conditions the annual maximum ground-
level particulate concentration near an
uncontrolled pressed and blown glass
furnace producing 45 Mg/day of glass
would be less than 1 /ig/mj, as would
the concentrations resulting from
compliance with Option I or Option II.
Corresponding annual maximum
ground-level concentrations near an
uncontrolled pressed and blown glass
furnace producing 90 Mg/day of glass
would also be less than 1 pg/m*.
Emissions from uncontrolled furnaces of
either size in this sector would result in
calculated maximum 24-hour ground-
level concentrations of 3 WJ/m3. Under
Option I this concentration would be
reduced to below 1 wj/ms. Under Option
II it would be reduced to about 1 ji£/m>-
Since fabric filters and electrostatic
precipitators are likely to be the control
systems installed on furnaces in this
sector to comply with standards, there
would be no water pollution impact
associated with standards based on
either Option I or Option IL
Under a typical SIP regulation, no
particulate matter would be collected
from the four new 45 Mg/day pressed
and blown glass furnaces projected to
come on-stream during the 1978-1983
period. The six new 90 Mg/day furnaces
would collect about 160 Mg/year (176
ton/year) under a typical SIP regulation.
For the six 90 Mg/day furnaces the
amounts collected in addition to those
collected through compliance with a
typical SIP regulation would be about 50
Mg/year (55 ton/year) for Option I and
about 33 Mg/year (36 ton/year) for
Option II. Compliance with standards
based on Option I and Option n would
result in the collection of about 72 Mg/
year (79 ton/year) and about 68 Mg/year
(75 ton/year), respectively, of solid
waste from the four 45 Mg/day furnaces.
Option I would increase the mass of
solids for disposal by 100 percent and by
about 31 percent over that required by a
typical SIP regulation for 45 Mg/day and
90 Mg/day furnaces, respectively.
Option II would increase the mass of
solids for disposal by 100 percent and 21
percent over that required by a typical
SIP regulation for 45 Mg/day and 90 Mg/
day furnaces, respectively. The total
masses of solids for disposal collected
from all new furnaces would be about
122 Mg/year (135 ton/year) and 101 Mg/
year (111 ton/year) for Option I and
Option II, respectively.
The additional solid material
collected under Option I and Option II
would not differ chemically from the
material collected under a typical SIP
regulation. Collected solids either are
recycled back into the glass melting
process or are disposed of in a landfill.
Recycling of the solids has no adverse
environmental impact, and, since
landfill operations are subject to State
regulation, this disposal method also
would not be expected to have an
adverse environmental impact.
Since the four new 45 Mg/day
furnaces would be in compliance with a
typical SIP regulation without add-on
controls, there would be no associated
energy requirement. The estimated
energy required to control particulates
emissions from the four new 45 Mg/day
furnaces projected to come on-stream in
the 1978-1983 period to the levels
required by both Option I and Option II
would be about 1.5 million kWh (900
barrels of oil/year). The energy required
to control particulate emissions from the
six new 90 Mg/da-y furnaces would be
4.4 million kWh (2,500 barrels of oil/
year) for a typical SIP regulation, Option
I, or Option H if ESFs were installed.
The energy required to comply with
the emission limits of the regulatory
options would be about 0.5 percent of
the total energy use in this glass
manufacturing sector. The energy
impacts of both Option I and Option II
are negligible (~3 barrels of oil/day) for
the new 45 Mg/day furnaces. There
would be no energy impact associated
with either Option I or Option FI for the
new 90 Mg/day furnaces beyond the
impact associated with the requirements
to meet a typical SIP regulatioa
incremental installed costs in January
1978 dollars associated with Option I for
controlling particular emissions from a
45 Mg/day pressed and blown glass
furnace melting soda-lime formulations
would be about $740 thousand for an
ESP and about $710 thousand for a
fabric filter. Incremental installed costs
associated with Option II would be
about $645 thousand for an ESP, and
bout $675 thousand for a fabric filter.
The incremental installed costs of
control equipment associated with the
Option I level of control would be about
1.1 times the incremental installed costs
associated with Option 0 if ESP's were
selected If fabric filters were selected
the incremental installed cosfi
associated with the Option I level of
V-CC-7
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Federal Register / Vol. 44. No. 117 / Friday, June 15. 1979 / Proposed Rule8
control would be about 1.1 times the
incremental installed costs associated
with Option II.
Incremental annualized costs for a 45
Mg/day furnace associated with Option
I would be about $230 thousand/year for
both ESP's and fabric filters.
Incremental annualized costs associated
with Option II would be about $205
thousand/year for an ESP, and about
$215 thousand/year for a fabric filter.
The incremental annualized costs
associated with Option I would be about
1.1 times the incremental annualized
costs associated with Option II if ESP's
were used. If fabric filters were used,
the incremental annualized costs
associated with Option I would be about
1.1 times the incremental annualized
costs associated with Option II.
Based on the use of control equipment
with the highest annualized costs (worse
case conditions), a price increase of
about 0.6 percent would be necessary to
offset the costs of installing control
equipment on a 45 Mg/day pressed and
blown glass furnace melting soda-lime
formulations to meet the emission limits
of Option I. A price increase of about 0.5
percent would be necessary to comply
with the emission limits of Option II.
Incremental cumulative capital costs
for the 1978-1983 period associated with
Option I for the four new 45 Mg/day
furnaces would be about $2.8 million if a
fabric filter were used. Use of an ESP to
comply with Option II would require
incremental cumulative capital costs of
about $2.6 million for the same period.
Fifth-year annualized costs for
controlling the furnace to comply with
Option I would be about $910 thousand.
To comply with Option II, fifth-year
annualized costs would be about $815
thousand.
Incremental installed costs in January
1978 dollars associated with Option I for
controlling particulate emissions from a
90 Mg/day pressed and blown glass
furnace melting soda-lime formulations
would be about $615 thousand for an
ESP and about $770 thousand for a
fabric filter. Incremental installed costs
associated with Option II would be
about $450 thousand for an ESP, and
about $680 thousand for a fabric filter.
The incremental installed costs of
control equipment associated with the
Option I level of control would be about
1.4 times the incremental installed costs
associated with Option II, if ESP's were
selected. If fabric filters were selected
the incremental installed costs
associated with the Option I level of
control would be about 1.1 times the
incremental installed costs associated
with Option II.
Incremental annualized costs for a 90
Mg/day furnace associated with Option
I would be about $175 thousand/year
and about $235 thousand/ year for an
ESP and a fabric filter, respectively.
Incremental annualized costs associated
with Option II would be about $130
thousand/year for an ESP, and about
$205 thousand/year for a fabric filter.
The incremental annualized costs
associated with Option I would be about
1.3 times the incremental annualized
costs associated with Option II if ESP's
were used. If fabric filters were used the
incremental annualized costs associated
with Option 1 would be about 1.1 times
the incremental annualized costs
associated with Option II.
Based on the use of control equipment
with the highest annualized cost, a price
increase of about 0.6 percent would be
necessary to offset the costs of installing
control equipment on the large pressed
and blown glass furnace melting soda-
lime formulations to meet the emission
limits of Option I. A price increase of
about 0.5 percent would be necessary to
comply with the emission limits of
Option II.
Incremental cumulative capital costs
for the 1978-1983 period associated with
Option I for the six new 90 Mg/day
furnaces would be about $3.7 million if
ESP's were used. Use of ESP's to comply
with Option II would require
incremental cumulative capital costs of
about $2.7 million for the same period.
Fifth-year annualized costs for
controlling these glass melting furnaces
to comply with Option I would be about
$1.1 million. To comply with Option II,
fifth-year annualized costs would be
about $790 thousand.
A summary of incremental impacts (in
excess of impacts of the typical SIP
regulation) associated with Option I and
Option II is shown in Table II for both
small and large furnaces. Air impacts,
expressed in Mg/year of particulate
matter emissions reduced, would
approximate the quantity of particulate
matter collected and disposed of as
solid waste.
Tabto II.Summary of Incremental Impacts
Associated With Regulatory Options
Impacts
Air1 Water Energy* Economic1
I 122 None
II 101 None
-3.0
-3.0
-0.6
-0.5
'Mg/Yr. reduced
'Barrel, of oil/day.
Ptrcent pric* iocrnM.
Consideration of the beneficial impact
on national particulate emissions, the
lack of water pollution impact, the small
potential for adverse solid waste impact,
the reasonableness of energy and costs
impacts, and the general availability of
demonstrated emission control
technology leads to the selection of
Option I as the basis for standards for
pressed and blown glass furnaces
melting soda-lime formulations.
Pressed and Blown GlassOther Than
Soda-Lime Formulations
Uncontrolled particulate emissions
from furnaces in this sector are about 5
g/kg (10 Ib/ton) of glass pulled.
Emission tests using EPA Method 5 on
four furnaces melting borosilicate
formulations and equipped with ESP's
yielded a representative emission rate of
about 0.50 g/kg (l.Olb/ton) of glass
pulled. A single emission test using EPA
Method 5 on an ESP-controlled furnace
melting fluoride/opal formulations
yielded an emission rate of 0.17 g/kg
(0.34 Ib/ton) of glass pulled. EPA
Method 5 tests of six ESP-controlled
furnaces melting lead glass yielded a
representative emission rate of 0.12 g/kg
(0.24 Ib/ton) of glass pulled. A single
EPA method 5 emission test of an ESP-
controlled furnace melting potash-soda-
lead glass yielded an emission rate of
0.03 g/kg (0.06 Ib/ton) of glass pulled.
An EPA method 5 emission test on a
furnace equipped with a fabric filter and
melting soda-lead-borosilicate glass
produced an emission rate of 0.17 g/kg
(0.34 Ib/ton) of glass pulled.
Upon consideration of the data cited
above, an emission limit of 0.25 g/kg (0.5
Ib/ton) of glass pulled was identified as
a reasonable limit for control for
pressed and blown glass furnaces
melting other than soda-lime
formulations. This limit was selected for
Option I; it provides for about 95 percent
particulate removal. Option II would set
an emission limit of 0.5 g/kg (1.0 Ib/ton)
of glass pulled, which provides for a
particulate removal of about 90 percent.
Fabric filters and ESP's could be
designed to achieve the levels of
emission reduction required by either
regulatory option.
By 1983 approximately 70 Gg/year
(77,200 ton/year) of additional.
production is anticipated in this sector.
One 45 Mg/day (50 ton/day) (small)
furnace and two 90 Mg/day (100 ton/
day) (large) furnaces would be built in
order to provide this production. If
uncontrolled, emissions from the one
new small pressed and blown glass
furnace melting formulations other than
soda-lime would add about 90 Mg/year
(100 ton/year) to national particulate
V-CC-8
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Federal Register / Vol. 44, No. 117 / Friday. June 15. 1979 / Proposed Rules
emissions by 1963, while the emissions
from the two new large furnaces would
add about 260 Mg/year (287 ton/year)
during the same period.
Compliance with a typical SIP
regulation would reduce the impact from
the small furnace to about 27 Mg/year
(30 ton/year). Control to the Option I
emissions limit would reduce the
emissions to about 17 percent of those
emitted under a typical SIP regulation.
With Option II emissions would be
reduced to about 33 percent of those
emitted under a typical SIP regulation.
Compliance with a typical SIP
regulation would reduce the impact of
the large furnances to about 47 Mg/year
(52 ton/year). Under Option I, these
emissions would be reduced to about 28
percent of those emitted under a typical
SIP regulation. Under Option II, the large
furnace emissions would be reduced to
about 56 percent of those emitted under
a typical SIP regulation.
The effect of a typical SIP regulation
for both large and small furnaces would
be a reduction of about 79 percent.
Under Option I, emissions would be
reduced to about 25 percent of those
emitted under a typical SIP regulation.
Under Option II, emissions would be
reduced to about 50 percent of those
emitted under a typical SIP regulation.
Ambient dispersion modeling
indicates that under worst case
conditions the annual maximum ground-
level particulate concentration near an
uncontrolled 45 Mg/day pressed and
blown glass furnace melting
formulations other than soda-lime would
be less than 1 p.g/m9, as would be the
concentrations resulting from
compliance with a typical SIP
regulation, Option I, or Option II.
Corresponding annual maximum
ground-level concentrations near a 90
Mg/day furnace also would be less than
1 /Ag/m»
The calculated maximum 24-hour
ground-level concentration near an
uncontrolled 45 Mg/day furnace in this
sector would be 11 w?/ms. This
concentration would be reduced to 3 p.g/
ms with a typical SIP regulation. With
Options I and II, the concentrations
would be reduced to 1 fig/m* or less.
The calculated maximum 24-hour
ground-level concentration near an
uncontrolled 90 Mg/day fumance would
be 14 u£/ms. This concentration would
be reduced to 3 ng/m* with a typical SIP
regulation and to below 1 fig/m* with
Option I; with Option II it would reach 2
M8/m>-
Since fabric filters and ESP's are
likely to be the control systems installed
on furnaces in this sector to comply with
standards, there would be no water
pollution impact associated with
standards based on either Option I or
Option II.
Under a typical SIP regulation, about
64 Mg/year (71 ton/year) of particulate
matter would be collected from the one
new 45 Mg/day furnace projected to
come on-stream in the 1978-1983 period.
Compliance with standards based on
Option I and Option II would add about
23 Mg/year (25 ton/year] and 18 Mg/
year (20 ton/year), respectively, to the
solid waste collected under a typical SIP
regulation. Option I would increase the
mass of solids by about 36 percent over
that resulting from compliance with a
typical SIP regulation, and Option II
would increase it by about 28 percent.
Under a typical SIP regulation, about
210 Mg/year (232 ton/year) of
particulate matter would be collected
from the two new 90 Mg/day furnaces
projected to come on-stream in the 1978-
1983 period. Compliance with standards
based on Option I and Option II would
add about 34 Mg/year (38 ton/year) and
21 Mg/year (23 ton/year), respectively,
to the solid waste collected under a
typical SEP regulation. Option I would
increase the mass of solids by about 16
percent over that resulting from
compliance with a typical SIP
regulation, and Option II would increase
it by about 10 percent. The total mass of
solids for disposal collected from all
three new furnaces in this sector,
associated with Option I and Option n,
would be about 57 Mg/year (63 ton/
year) and about 39 Mg/year (43 ton/
year), respectively.
The additional solid material
collected under Option I or Option II
would not differ chemically from the
material collected under the typical SIP
regulation. Collected solids either are
recycled back into the glass melting
process or are disposed of in a landfill.
Recycling of the solids has no adverse
environmental impact, and, since
landfill operations are subject to State
regulation, this disposal method also is
not expected to have an adverse
environmental impact.
Since ESP's have been the
predominant control system used in the
industry and are anticipated as the
predominant system to be used for new
plants coming on-stream between 1978-
1983 regardless of which regulatory
option is selected, energy requirements
estimated for the typical SIP regulation,
Option I, and Option n are based on the
use of ESP's.
The energy required to control
particulate emissions from the new 45
Mg/day pressed and blown glass
furnace malting formulations other than
soda-lime to the level required by the
typical SIP regulation would be about
2.7 million kWh (1,500 barrels of oil/
year). The energy required to comply
with the Option I and Option II
emissions limits would be essentially
the same as that required for meeting a
typical SIP regulation.
Control to the level required by a
typical SIP regulation of the two new 90
Mg/day pressed and blown glass
furnaces melting formulations other than
soda-lime and projected to come on-
stream during the 1978-1983 period
would require about 6.6 million kWh
(3,700 barrels of oil/year) if an ESP were
used. The energy requirements to
achieve the Option I and Option II
emission limits would be essentially the
same as the requirements for meeting a
typical SIP regulation.
The energy required to comply with
the emission limits of the regulatory
options would be about 0.1 percent of
total energy use for all new furnaces in
this glass manufacturing sector.
Considering the small amounts of
additional oil and electricity required
and the slight increase in total energy
use in this sector, the energy impacts of
either Option I or Option II would be
negligible.
Incremental installed costs in January
1978 dollars associated with Option I for
controlling particulate emissions from a
45 Mg/day pressed and blown glass
furnace melting formulations other than
soda-lime would be about $760 thousand
for an ESP and about $235 thousand for
a fabric filter. Incremental installed
costs associated with Option n would
be about $320 thousand for an ESP, and
about $190 thousand for a fabric filter.
The incremental installed costs of
control equipment associated with the
Option I level of control would be about
2.4 times the incremental installed costs
associated with Option II if ESP's were
selected. If fabric filters were selected
the incremental installed costs
associated with the Option I level of
control would be about 1.2 times the
incremental installed costs associated
with Option n level of control.
Incremental annualized costs for a 45
Mg/day furnace assoicated with Option
I would be about $230 thousand/year
and about $70 thousand/year for an ESP
and a fabric filter, respectively.
Incremental annualized costs associated
with Option n would be about $95
thousand/year for an ESP, and about
$60 thousand/year for a fabric filter. The
Incremental annualized costs associated
with Option I would be about 2.4 times
the incremental annualized costs
associated with Option II if ESP's were
used. If fabric filters were used the
incremental annualized costs associated
V-CC-9
-------
with Option I would be about 1.2 time*
the incremental annnalized costs
associated with Option IL
Based on die nee of control equipment
with the highest annualized costs (worse
case conditions), a price increase of
about 0.4 percent would be necessary to
offset the costs of installing control
equipment on a 45 Mg/day pressed and
blown glass furnace melting other than
soda-lime formulations to meet the
emission limits of Option I. A price
increase of about 0.3 percent would be
necessary to comply with the emission
limits of Option n.
Incremental cumulative capita! costs
for the 1976-1963 period associated with
Option I for the 45 Mg/day furnace
would be about $235 thousand if an ESP
were used. Use of an ESP to comply
with Option H would require
incremental cumulative capital costs of
about $190 thousand for the same
period. Fifth-year annualized costs for
controlling this furnace in this sector to
comply with Option I would be about
$70 thousand. To comply with Option II,
fifth-year annnalized costs would be
about $60 thousand.
Incremental Installed costs in January
1978 dollars associated with Option I for
controlling participate emissions from a
90 Mg/day pressed and blown glass
furnace melting other than soda-lime
formulations would be about $800
thousand for an ESP and about $260
thousand for a fabric filter. Incremental
installed costs associated with Option II
would be about $140 thousand for an
ESP, and about $180 thousand for a
fabric filter. The incremental installed
costs of control equipment associated
with the Option I level of control would
be about 5.7 times the incremental
installed costs associated with Option n
if ESFs were selected. If fabric filters
were selected the incremental installed
costs associated with the Option I level
of control would be about 1.4 times the
incremental installed costs associated
with Option n.
Incremental annualized costs for a 90
Mg/day furnace associated with Option
I would be about $245 thousand per year
and about $85 thousand per year for an
ESP and a fabric filter, respectively.
Incremental annualized costs associated
with Option 0 would be about $45
thousand per year for an ESP, and about
$55 thousand per year for a fabric filter.
The incremental annualized costs
associated with Option I would be about
5.4 times the incremental annualized
costs associated with Option H if ESFs
were used. If fabric filters were used the
incremental annualized costs associated
with Option I would be about LS times
the incremental annualized costs
associated with Option II.
Based on the use of control equipment
with the highest annualized costs, a
price increase of about 0.8 percent
would be necessary to offset the costs of
installing control equipment on the 90
Mg/day pressed and blown glass
furnace melting formulations other than
soda-lime to meet the emission limits of
Option I. A price increase of about 0.5
percent would be necessary to comply
with the emission limits of Option II.
Incremental cumulative capital costs
for the 1878-1963 period associated with
Option I for the two new 90 Mg/day
furnaces would be about $500 thousand
if fabric filters were used. Use of ESP's
to comply with Option II would require
incremental cumulative capital costs of
about $300 thousand for the same
period. Fifth-year annualized costs for
controlling these glass melting furnaces
to comply with Option I would be about
$160 thousand. To comply with Option
Q, fifth-year annualized costs would be
about $85 thousand
A summary of incremental impacts (in
excess of impacts of the typical SIP
regulation) associated with Option I and
Option II is shown in Table III for both
small and large furnaces. Air impacts,
expressed in Mg/year of paniculate
matter emissions reduced, would
approximate the quantity of participate
matter collected and disposed of as
soild waste.
T*te HI.Summary of Incremental Impact
Associated tHth fboutotory Opt/ons
A*' Water Enemy* Eoonomc1
ReguMovy
option:
67 No
-Negligible..
M Nora Nagkgtote..
-0.7
-04
Mg/Yr
'P«OM* price
Consideration of the beneficial impact
on national particulate emissions, lack
of water pollution impact, the small
potential for adverse solid waste impact.
the lack of energy impact, the
reasonableness of cost impacts, and the
general availability of demonstrated
emission control technology leads to the
selection of Option I as the basis for
standards for pressed and blown glass
furnaces melting formulations other than
soda-lime.
Wool Fiberglass
Uncontrolled particulate emissions
from wool fiberglass furnaces are
generally about £ g/kg (10 Ib/tonj of
glass pulled. The average emission from
three furnaces in the wool fiberglass
sector equipped with ESP's was 0.18 g/
kg (0.36 Ib/ton) of glass pulled. EPA
Method 5 tests of three furnaces
equipped with fabric filters indicated
emissions of 0.2 g/kg (0.4 Ib/ton), 0.26 g/
kg (0.52 Ib/ton). and 0.55 g/kg (1.1 lb/
ton) of glass pulled. The test data cited
indicate that an emission limit of 0.2 g/
kg (0.4 Ib/ton) of glass pulled could be
met through the use of an ESP and that a
limit of 0.4 g/kg (0.8 Ib/ton) of glass
pulled could be met through the use of
either an ESP or a fabric filter.
On the basis of these conclusions, two
regulatory options for reducing
particulate emissions from wool
fiberglass furnaces were formulated.
Option 1 would set an emission limit of
O-2 g/kg (0.4 Ib/ton) of glass pulled,
which would provide for about 95
percent particulate removal Option II
would set an emission limit of 0.4 g/kg
(0.8 Ib/ton) of glass pulled, which would
provide for about 90 percent removal of
particulates.
By 1983 approximately 360 Gg/year
(397,000 ton/year) of additional
production is anticipated in the wool
fiberglass sector. About six new wool
fiberglass furnaces of about 180 Mg/day
(200 ton/day production capacity (the
size of the model furnace) would be
built in order to provide this additional
production. If uncontrolled, these new
wool fiberglass furnaces would add
about 1,800 Mg/year (1,984 ton/year) to
national particulate emissions by 1983.
Compliance with a typical SIP
regulation would reduce this impact to
about 210 Mg/year (232 ton/year).
Under Option I, emissions would be
reduced to about 33 percent of those
emitted under a typical SIP regulation.
Under Option II, emissions would be
reduced to about 66 percent of those
emitted under a typical SIP regulation.
Ambient dispersion modeling
indicates that under worst case
conditions the annual maximum ground-
level particulate concentration near an
uncontrolled wool fiberglass furnace
producing 180 Mg/day of glass would be
about 2 fig/ms. The annual maximum
ground-level concentrations resulting
from compliance with a typical SIP
regulation, Option I, or Option II would
be less than 1 jig/m*. The calculated
maximum 24-hour ground-level
particulate concentration near an
uncontrolled wool fiberglass furnace
producing 180 Mg/day of glass would be
about 29 fig/m'. The corresponding
concentration for complying with a
typical SIP regulation would be about 3
ug/ms. Under Option I with an ESP
employed for control, the maximum 24-
V-CC-10
-------
Federal Register
44, No
F:sda> ]une 15, 1979 /
Rales
.-. ,i'i; gr und ieve; concentration wnu'1
be redu ,ec 'o - ^g, rr* Under Option i]
it would oe reduced to 3 end 4 ng/m*
with the fabric filter and ESP,
respectively
Since fabric Alters and ESP's ar«
.ike;v to ye '.T- control systems ms*al!<-'d
:; A'tjoi fiberglass fun'Hcee t comp;y
*:! Mipnua"d!> Ihprp would ';"! no ',V>'D'
M; po"1 lr':r)ii,;! aghOt.'ited With
nd for a-: ESP and a fabric filter,
-«8pectiveiy The incremental installed
costs of control equipment associated
with the Option I level of control would
be nearly 5 times the incremental
installed costs associated with Option 11
if ESP's were selected !f fabric filters
were 8eifj.'!pd, the incremental installed
osts i -., i;u: about S:.:X!
T«W« IV.6 jmma/y o< incremental Impacts
Associated With iagu/atory Options
Impact*
Energy' Economic'
'tegutatcry
option
OJ
0.1
jnc» **»§
m "
10
>'<>!: if >he beneficial impact
~>ar»!cuia'e emission*, the
r ->oOutiin impact the small
i'-versi-' wid wa^te impact,
~- .-* f e~,?rg\ md cost
^ t'. 'ier-.«, ava-i-ibillty of
- - -S nn '";t,''}1
, c ^P!^, -. in of
< - « j.'.'j-jrds for
"s. f ,\ . . -
; ,- »t "! i j
1 - 'U;C "1O! c;rf(T ''".;:,'
' i , H )"" CC'llf% '-C '.' =!tj '
T1 '!/>; 'n' ; )' it J"e Jisp'.^e'l c! " i
v- 'fii «'- ',- ->a ';: ,' f sou'Js rnu
-. i. H .-("» ,1 .f'Tjentai TH-act an'1
'- e ',;!'!."'!' '"^rations ai'f *ii'nc
v ' -( :.; ; ;": 'his oi8p<>8. TIP'" ''
t> , » :,lt -pr-pQ r,, >;i-.,c- " a-" *
i ' "f1: , .T.r/aci
1 ;- ,: .i '>.: .''servj , et. d '>,
I'linc fi't- erri'Si'OCF '"rr i,^
,>(! - -.fj- on-sf^ar" It;' >* '
' ; T:-!\- 'A'.th 3 ' "-;:8' '-'
-A . ':ui be aoci1! '*. 1 n:!'1 :
' 4 J , -r- * si! jf OH \ , ' .f
' n 'i iv n)ta"):« >,»" i , 3-"
v! . , '-.' ; ri -ft tor r'it* -;"-3'T?
11 ! f >! <;T- , 'r-tion or.'sri*? -1 -
vc1 i1" ')e n 'g'.g'.ble onjy .irc-it N'
m-rf-la r^f oil year
Incremental .retailed nos's ; [an irv
:97fi doliam essoriated with Option > li-r
jon':o''iae pf-rticulate emissions f^orn 3
*flO Mj?,'duy '.von fiberglass fumare
vcuic be airut S500 thobsano for ->-
7-SP and dbo; ' $-1 thousand for a :;.; -
liter IncreTi-'nta, installed "ost(>
.issoc;ate i wth "'ption il woui-i v-'
ioo'.jr SI1 } th ?nsnnd ann abet* $3<'
1 ' " ' --t I *,.'. 1J J. 2-'0 '-OS'- dSSO^ia Ml
a ' K~-'J -vere asec ,f
;; ::, 'i "*< * ? -Si-c 'h^ .ncrementa;
, ,,- ; nzej -.'.s astii^; ateo with Option
. ntiii (i Tf- auu,.! "wo fitnes the
t r*""f'pfd; annuajzea costs associated
-v.:h :pi:onil.
^a,tf»ii <\ 'he uee of contro. equipment
<\!tn 'tie "igfjes' prirmazea costs (worst
case 'nnaitions., a price increase of
so ,u; U: T,t'rr;ent would bfc lecessary to
.ufset ;ritj ccs!« oi T.std.lmg control
"cuipnent on j '80 Mg/day wool
'';*,(;.'H.-iSS urnace "c meet tne emission
imitf -jf Oo"oi' i A ance ;ncrease of
i'Xiu ). 1 oev- fit would be necessary to
:cirnr >vin« witn 'he rtmsssion limits of
.'DUi 11 U
nr"^rri ".« am native capital costs
' " '_!r - ?s< .lew 1wi Mg, day wool
" *'.-4 338 furnaces rinng the 1978-1983
" "]" : -sssocia1- a wr.h Option I would
ar i>u( S3 mii icr: f F.SP's were asea
"^e f i fr>hnc ^''ers -n comply with
'tjtirn ;' wouj'1 rt-nsnre mcrementa!
\ni: Jti.t> -a; ta, -JOB'S o! about S185
' ^usinc'or r.-spi-,' oenoa ;'iftr. yeiir
r u -azeu rosis icr contromng A joi
:~erg!;M9 rumdoes compiy.ng with
Option 1 woijjd be aoout $930 thousand.
To comply with Option 0, fifth-year
ii.nuaiized costs would be about $60
thousand.
A summary of incremental impacts
associated with Option I and Option Q
is shown in Table IV. Air impacts.
expressed in Mg/year of participate
matter emissions reduced, wouid
loproximate the quantity of participate
natter collected and disposed of as
jriid waste.
"' -* - !?»'-'-iJate emissions
*mn' rfe' "l >-:» ^s-nares an.- about 1.5 g/
*g 13.0 T*.in] oi glass pulled Iliere are
?,o emissions tes' oata for flat glass
furnaces eouippea ^ith control devices
available for evaluation. However, the
soda-limp formulations melted in these
furnaces HH? quite simila^ TO those
aaeited "n container glass furnaces-, as
are 'i-e caetmnal composition and
physical haractenstics of the
oarticuiate emissions The pnmary
lifference between t on;.uner glass and
flat giaBs ^irnaces :s that the
inconrroilen emission rates of flat glass
''urnaces are greater Given the
-Mmjlarrv of processes, niass
rmuiations. and emissions it is
ixpecipn 'hat the percentage reduction
i n«r»,. i-.'au. emissions acnievedby
con'roi of Container glass '"umaces also
be a-:oieved with flat glass
This conclusion :s supported
-------
Federal Register / Vol. 44. No. 117 / Friday. June 15. 1979 / Proposed Rules
consistency, therefore. Option II would
set an emission limit of 0.3 g/kg (0.6 lb/
ton) of glass pulled, which would
provide about 80 percent control.
By 1983 approximately 240 Gg/year
(264,555 ton/year) of additional
production is expected in the flat glass
sector. One new flat glass furnace of
about 635 Mg/day (700 ton/day)
capacity (the size of the model" furnace)
would be built in order to provide this
additional production.
If uncontrolled, this new flat glass
furnace would add about 380 Mg/year
(397 ton/year) to national participate
emissions by 1983. Compliance with a
typical SIP regulation would reduce this
impact to about 90 Mg/year (100 ton/
year). Under Option I, emissions would
be reduced to about 40 percent of those
emitted under a typical SIP regulation.
Under Option D. emissions would be
reduced to about 80 percent of those
emitted under a typical SIP regulation.
Ambient dispersion modeling
indicates that under worst case
conditions the annual maximum ground-
level particulate concentration near an
uncontrolled flat glass furnace
producing 635 Mg/day of glass would be
about 1 fig/m*. The annual maximum
ground-level concentrations resulting
from compliance with a typical SIP
regulation, Option L or Option II, would
be less than 1 jig/ml The calculated
maximum 24-hour ground-level
particulate concentration near an
uncontrolled flat glass furnace
producing 635 Mg/day of glass would be
about 21 ug/m3. The corresponding
concentration for complying with a
typical SIP regulation would be about 5
Ug/m3. Under Option I, this
concentration would be reduced to
about 2 jig/ms. Under Option n it would
be reduced to about 5 >ig/ms.
Since the ESP is likely to be the
emission control system installed on flat
glass furnaces to comply with standards,
there would be no water pollution
impact associated with standards based
on either Option I or Option IL
Under a typical SIP regulation, about
270 Mg/year (298 ton/year) of
particulate matter would be collected
from the one new 635 Mg/day flat glass
furnace projected to come on-stream in
the 1978-1983 period. Compliance with
standards based on Option I and D
would add about 50 Mg/year (55 ton/
year) and about 20 Mg/year (22 ton/
year), respectively, to the solid waste
collected under a typical SIP regulation.
Option I would increase the mass of
solids for disposal by about 20 percent
over that resulting from compliance with
a typical SIP regulation, and Option D
would increase it by about 7 percent.
The additional solid material collected
under Option 1 or Option n would not
differ chemically from the material
collected under a typical SIP regulation.
Collected solids either are recycled back
into the glass melting process or are
disposed of m a landfill. Recyling of the
solids has no adverse environmental
impact, and, since landfill operations are
subject to State regulations, this
disposal method also is not expected to
have an advene environmental impact.
Since the energy requirements for an
electrostatic pretipitator do not vary
significantly over the range of emission
reductions considered here, the estimate
of energy required to control particulate
emissions from the one new flat glass
furnace would be about the same for
compliance with a typical SIP
regulation, Option I. or Option nabout
7.8 million kWh (4,300 barrels of oil/
year). The energy required to comply
with the emission limits of the
regulatory options would be about 0.2
percent of the total energy use in the flat
glass sector. There would be no
incremental energy impact associated
with either Option I or Option n as
compared with a typical SIP regulation.
The incremental installed cost in
January 1978 dollars associated with
Option I for controlling particulate
emissions from a 635 Mg/day flat glass
furnace would be about $605 thousand.
Incremental installed cost associated
with Option n would be about $140
thousand. The incremental installed cost
of control equipment associated with the
Option I level of control would be
somewhat more than four times the
incremental installed cost associated
with the Option II level of control
Incremental annualized cost
associated with Option I for a 635 Mg/
day flat glass furnace would be about
$190 thousand/year; the corresponding
incremental annualized cost for Option
II would be about $45 thousand/year.
The incremental annualized cost
associated with Option I would be more
than four times the incremental
annualized cost associated with Option
n.
A price increase of about 0.4 percent
would be necessary to offset the cost of
installing as ESP on a 635 Mg/day flat
glass furnace to meet the emission limit
of Option I. A price increase of about 0.1
percent would be necessary to comply
with the emission limit of Option n.
Incremental cumulative capital cost
for the one new 635 Mg/day flat glass
furnace during the 1978-1983 period
associated with Option I would be about
$605 thousand. Compliance with Option
II would require an incremental
cumulative capital cost of about $145
thousand for the same period. Fifth-year
annualized costs for controlling the one
new flat glass furnace to comply with
Option I would be about $190 thousand.
To meet the Option II emissions limit,
fifth-year annualized costs would be
about $45 thousand.
A summary of incremental impacts
associated with Option I and Option II
is shown in Table V. Air impacts,
expressed in Mg/year of particulate
matter emissions reduced, would
approximate the quantity of particulate
matter collected and disposed of as
solid waste.
Tcbte V.Summary of Incremental Impacts
Afsooated With Regulatory Options
Mr1
Enogy* Economic'
Regulatory
option
I S20 None NegtgM* - -0.4
U 290None.-_._Nagtgibto-_ 0.1
'Mg/Yr. reduced
Barrels of oil/itojr.
'fmvtmt pnoe IOITMW.
.Consideration of the beneficial impact
on national particulate emissions, the
lack of water pollution impact, the small
potential for adverse solid waste impact,
the lack of energy impact, the
reasonableness of cost impacts, and the
general availability of demonstrated
emission control technology leads to the
selection of the Option I as the basis for
standards for glass melting furnaces in
the flat glass sector.
Summary
If uncontrolled, total particulate
emissions from the 45 new glass melting
furnaces projected to come on-etream
between 1978 and 1983 would be about
5,200 Mg/year (5,732 ton/year).
Compared to a typical SIP regulation,
Option I would reduce particulate
emissions by an additional 1,100 Mg/
year (1,213 ton/year).
Ambient dispersion modeling
indicates that the annual maximum
ground-level particulate concentrations
near uncontrolled glass melting furnaces,
would be 2 fig/m' or less. Both a typical
SIP regulation and the Option I emission
limits would reduce the annual
maximum ground-level particulate
concentrations to under 1 /ig/m.The 24-
maximum ground-level particulate
concentrations near uncontrolled glass
melting furnaces would be less than 30
Ug/m3, with a median concentration of
about 11 fig/ms. Under a typical SIP
regulation these concentrations would
be reduced to 5 /ig/msor less. Control to
the Option I emission limits would
V-CC-12
-------
Federal Register / Vol. 44, No. 117 / Friday. June 15. 1979 / Proposed Rules
reduce the 24-hour maximum ground-
level concentrations near glass melting
furnaces to about 2 pg/m* or less.
The glass manufacturing process has
minimal water pollution potential.
Complying with a standard based on
Option I would have a negligible water
pollution impact, because control
systems installed to meet Option I
would not discharge waste water
streams.
The amounts of solid waste generated
in the control of particulates from glass
melting furnaces would approximate the
amount of particulate removed from
exhaust gases. Compliance with a
typical SIP regulation would produce
3,700 Mg (4,080 tons) of solid waste per
year. Meeting the Option I emission
limits would generate an additional
1,100 Mg/year (1,213 ton/year). Either
recycling or landfilling would present
minimal adverse environmental impact.
Totally recycling the collected solids
would have no adverse impact.
Landfilling operations must meet State
regulations, and therefore this disposal
method would have limited potential for
adverse environmental impact.
Implementing Option I would require
about 1.6 million kWh of electricity to
power the emission control equipment
installed above the requirements for
implementing a typical SIP regulation.
To meet this power requirement electric
utilities would require about 950 barrels
of oil/year, or about 3 barrels/day. The
energy that would be required to
operate emission reduction sytems to
meet a standard based on the Option I
limits would be 2 percent or less of the
total energy used in glass production.
Incremental cumulative capital costs
to the glass manufacturing industry for
controlling emissions from new glass
melting furnaces projected to come on-
stream during the 1978-1983 period to
comply with a standard based on the
Option I emission limits would be about
$27.9 million. The fifth-year annualized
costs to the glass manufacturing
industry associated with compliance
with the Option I emission limits would
be about $8.4 million. An industry-wide
price increase of about 0.7 percent
would be necessary to offset the costs of
installing control equipment to meet the
emission limits of Option L
Modification, Reconstruction, and Other
Considerations
An exemption from provisions of the
modification section (40 CFR § 60.14] is
proposed for those plants which convert
to fuel-oil firing, even though particulate
emissions would more than Likely be
increased. The primary objective of the
proposed standards is to control
emissions of particulates from glass
melting furnaces. The data and
information supporting the standards
consider essentially only those
emissions arising from the basic melting
process, not those arising from fuel
combustion. It is not the prime purpose
of these standards, therefore, to control
emissions from fuel combustion per se.
Consequently, since emissions from fuel
combustion are small in comparison
with those from the basic melting
process, and a conversion of glass
melting furnaces to firing oil rather than
natural gas will aid in efforts to
conserve natural gas resources, the
standards proposed herein include a
provision exempting fuel switching in
glass melting furnaces from
consideration as a modification. The
proposed increment in emissions
allowed fuel oil-fired glass melting
furnaces is 15 percent, a small
allowance; however, without this
exemption there would be a large
economic impact on the industry.
An exemption from reconstruction
provisions (40 CFR § 60.15) is proposed
for the cold refining (rebricking) of the
melter of an existing furnace. Under 40
CFR § 60.15 the Administrator must be
notified of intent to conduct such a
procedure 60 days in advance of
commencement, and will determine
whether or not the rebricking constitutes
a reconstruction. This rebricking
procedure has been a routine operation
in the glass manufacturing industry and
would not generally be considered an
opportunity to evade the provisions of
the standard by unduly extending the
useful life of an existing glass melting
furnace. Therefore, the exemption of
rebricking from reconstruction provision
has been proposed.
Glass melting furnaces fired with
number 2 fuel oil would be expected to
exhibit a 10 percent increase in
particulate emissions over those
produced in gas-fired furnaces since
particulates are formed by the
combustion of oil. Similarly, furnaces
fired with numer 4, 5, or 6 fuel oil would
show a 15 percent increase in
particulate emissions over those
produced in gas-fired furnaces. This
effect of fuel oil on furnace emissions
being recognized, it is proposed that the
emission limits for furnaces fired with
fuel oil be the limits for gas-fired
furnaces multiplied by 1.15. It is
additionally proposed that
simultaneously liquid and gas-fired
furnaces have emission limits based on
an equation, taking into consideraton
the relative proportions of the fuels
being fired.
Selection of Performance Test Methods
The use of EPA Reference Method 5
"Determination of Particulate Emissions
from Stationary Sources" (Appendix A,
40 CFR § 60, Federal Register, December
23,1971) is required to determine
compliance with the mass standards for
particular matter emissions. Emission
test data used in the development of the
proposed standard were obtained either
by the LAAPCD sampling method or by
EPA Method 5. However, results of
performance tests using Method 5
conducted by EPA on existing glass
melting furnaces comprise a major
portion of the data base used in the
development of the proposed standard.
EPA Reference Method 5 has been
shown to provide a respresentative
measurement of particulate matter
emissions. Therefore, it has been
included for determining compliance
with the proposed standards.
Calculations applicable under Method
5 necessitate the use of data obtained
from three other EPA test methods
conducted previous to the performance
of Method 5. Method 1"Sample and
Velocity Traverse for Stationary
Sources" must be conducted in order to
obtain representative measurements of
pollutant emissions. The average gas
velocity in the exhaust stack is
measured by conducting Method 2
"Determination of Stack Gas Velocity
and Volumetric Flow Rate (Type S Pilot
Tube)." The analysis of gas composition
is measured by conducting Method 3
"Gas Analysis for Carbon Dioxide,
Oxygen, Excess Air and Dry Molecular
Weight." These three tests provide data
necessary in Method 5 for converting
volumetric flow rate to mass flow rate.
In addition, Method 4"Determination
of Moisture Conent in Stack Gases" is
suggested as an accurate mode of
predetermination of moisture content.
Since the proposed standards are
expressed as mass of emissions per unit
mass of glass pulled, it will be
neccessary to quantify glass pulled in
addition to measuring particulate
emissions. Glass production in Mg shall
be determined by direct measurement or
computed from materials balance data
using good engineering practices. The
materials balance computation may
consist of a process relationship
between feed material input rate and the
glass pull rate. In all materials balance
computations, glass pulled from the
furnace shall include product, cullet, and
any waste glass. The hourly glass pull
rate for a furnace shall be determined
by averaging the glass pull rate over the
time of the performance test.
V-CC-13
-------
iposed Rules
Selection -T': Mon'to.-n;. Requirements
To provide a convenient means for
enforcemen! personnel to ensure that
installed emission control systems
comply with standards >f performance
through proper operation and
maintenance, monitoring requirements
are generally included :r «tandards of
performancp For glass melting furnaces
the most strniRhtJorwar -nears of
ensuring prou* t -:nj i « *. -ior;n
released to Hn" t'Tiosp""'" EPXna-,
established o< ,' -,;<';* r:','*
3
acrm«i working hours d> EPA 3 Centra'
Docket Section -,n Washington I) C. .'See
ADDRESSES section of this preamble]
Miscellaneous
Thf- JocKe' IB an organized and
;omp,cte fre or all '.he 'niormation
considered bv EPA in the development
ji '.hi,- rjiem.su Tig The pnnc;oai
if ; .! 'he -K ke! d-e '"i ',: a.ic-w,
. ; '-.e'-sons -n laeitm ana lor.it-
ietfii r
-rrussi
scvin
c tn
7i a -i;!tt
ire hp
So'-' .
f -,-ii;
inly play as prominent a roll- "
iming the "lowest achievable
n rate" for new or modified
"i .ocating in nonattainmert areas
rsp areas where statutorily-
en nealth and welfare stand. ir^
y violated. In this resper".,
T3 of the Act reqmrt s 'ha: n<''-
,f ed sources construr/po n an
^::h 8 in violation of "he \AA(J-
' ?ro ssions to -" --vei
, -s *hp ""-owe"! - <-'<-.\ .j":'
AER: ,P -
1 ' " 9 hr^ =-.
mt-iV ,> 'i>m«{:e-. '" ,'.- . > j sampling
information on <>;),
there are no continu"!
monitors oppratn.y ir.
cor.squfiiu!
> tie \ c'
emission rate rplur: >,'«
available R»snlu'!-, r;
prob.ems, den-!,); '"err
stars,ards *V rTstiii. ssicn rate
reiat or
dpvp,r,pment orogrh T' F-ir these
reasons, continuous nor.i'ormg of
particuiate emissions f"rom gia.se melting
furna'ps would no' ^r iquirec '">y the
pror.'Sec standard -
Public Hearing
A public hearing wslj 'oe leid fo
discuss these proposed standards 'n
accordance with Section 307fd)(5i of the
Clean \ir Act, Persons wishing 'o maxe
oral presentations sho'iid contact EPA
at the address given in the ADDRESSES
section of this preamble, Oral
presentations will be limited So 15
minutes each. Any member of the public
may file a written statement with EPA
before, during, or within 30 days after
the hearing. Written statements should
be addressed to the Docket address
given in the ADDRESSES section of this
preamble.
A verbatim transcript of »he hearing
and written statement!) will be available
for public inspection and copying during
,."Jv ,, . - .-p. , ,
xpei's 3' ' <'.:e
.'.- ,ia ir.ng
lear ».r At.'. -pfl
,jjr-
.aoac.f -t rpi'-'C'rvs "-JOISSKJUS :x- ow
'hose .f, e:3 requ.ied o corni \ =/\if. Lit;
jtanOdras of pt-!crm>
mpos'Mon of a more stringent emission
standard in several situations For
axampie, applicable costs do not
" on ,' signifi ,d i
- -* iif quality ."
' i ^* "hese ': >-
^: ",i n sourit > ,:"
' *-v;r ; employ L< '
' oo 169! Ji"' . ' -
: ." .r^o under '".
" ' '^cnnoi-,,, ,
~ .r. r-d on d b i->e
'-, f. fi^v, «?fi\:r ci'i'
i"~ n ::; and otrir < '
. ;jy an ,j ,'..,
« i r>dt-M.r.r
? ..IP * .
- -.' i i inainl>-.' . ,
''' r.r quant ' '
v, :t-n o proiPf!
v-jif.3fu for this p
SF'-i - ,. r soT.c cases "(-LI .re grec.-.
;rn>.s,,u -nuctujns than those reouirc
0- itd-i i',]s of ."if'rformann- * i1" Tirw
sources
rina:!', f idles, are free under Section
IW of t);,; ,\ci to establish even more
:" limits than those estaolisheii
i': son 111 of those necessary U
attain or "tminta-n the NAAQS -jnoer
ipctior. 10 Accordingly, new source;
7. ,v '.'; #or i> ^asts be suoject ;t
imitai u,i.s ,nore stringent tnan £PA >
*irtr.d«n:s (jf jerformanct; unuer aei.tio.
-------
Federal Register / Vol. 44. No. 117 / Friday, June 15, 1979 / Proposed Rules
111, and prospective owners and
operators of new sources should be
aware of this possibility in planning for
such facilities.
EPA will review this regulation four
years from the date of promulgation.
This review will include an assessment
of such factors as the n^ed for
integration with other f rograms, the
existence of alternative methods,
enforceability, and improvements in
emission control technology.
An economic impact assignment has
been prepared as required under Section
317 of the Act and is included in the
Background Information Document.
Dated- May 22, 1979
Douglas M. Costle,
Administrator.
It is proposed to amend Part 60 of
Chapter I, Title 40 of the Code of Federal
Regulations as follows:
Subpart CCStandards of
Performance for Glass Manufacturing
Plants
Sec.
00.290 Applicability and designation of
affected facility
60.291 Definitions.
00.292 Standards lor participate matter
60.293 Test methods and procedures.
Authority: Sections 111 and 301(a) of the
Clean Air Act, as amended [42 U.S.C. 7411,
7601(a)], and additional authority as noted
below.
§ 60.290 Applicability and designation of
affected facility.
The affected facility to which the
provisions of this subpart apply is each
glass melting furnace within a glass
manufacturing plant.
§ 60.291 Definitions.
As used in this subpart, all terms not
defined herein shall have the meaning
given them in the Act and in Subpart A.
(a) "Glass manufacturing plant"
means any plant which produces glass
or glass products.
(b] "Glass melting furnace" means a
unit comprising a refractory vessel in
which raw materials are charged,
melted at high temperature, refined, and
conditioned to produce molten glass.
The unit includes foundations,
superstructure and retaining walls, raw
material charger systems, heat
exchangers, melter cooling system,
exhaust system, refractory brick work,
fuel supply and electrical boosting
equipment, integral control systems and
instrumentation, and appendages for
conditioning and distributing molten
glass to forming apparatuses.
(c) "Day pot" means any glass melting
furnace designed to produce less than
1800 kilograms of glass per day.
(d) "All-electric melter" means a glass
melting furnace in which all the heat
required for melting is provided by
electric current from electrodes
submerged in the molten glass, although
some fossil fuel may be charged to the
furnace as raw material.
(e) "Glass" means flat glass, container
glass; pressed and blown glass; and
wool fiberglass.
(f) "Flat glass" means glass made of
soda-lime recipe and produced into
continuous flat sheets and other
products listed in Standard Industrial
Classification 3211 (SIC 3211).
(g) "Container glass" means glass
made of soda-lime recipe, clear or
colored, which is pressed and/or blown
into bottles, jars, ampoules, and other
products listed in SIC 3211.
(h) "Pressed and blown glass" means
glass which is pressed and/or blown,
including textile fiberglass,
noncontinuous process flat glass,
noncontainer glass, and other products
listed in SIC 3229. It is separated into:
(1) Glass of soda-lime recipe; and
(2) Glass of borosilicate, opal, lead
and other recipes.
(i) "Wool fiberglass" means fibrous
glass of random texture, including
fiberglass insulation, and other products
listed in SIC 3296.
[}) "Recipe" means formulation of raw
materials.
(k) "Glass production" means the
weight of glass pulled from a glass
melting furnace.
(1) "Rebricking" means cold
replacement of damaged or worn
refractory parts of the glass melting
furnace. Rebricking includes
replacement of the refractories
comprising the bottom, sidewalls, or
roof of the melting vefssel; replacement
of refractory work in the heat
exchanger; replacement of refractory
portions of the glass conditioning and
distribution system.
(m) "Soda-lime recipe" means raw
material formulation of the following
approximate proportions: 72 percent
silica; 15 percent soda; 10 percent lime
and magnesia; 2 percent alumina; and 1
percent miscellaneous materials.
{ 60.292 Standards for paniculate matter.
(a) On or after the date on which the
performance test required to be
conducted by § 60.8 is completed, no
owner or operator of a glass melting
furnace subject to the provisions of this
subpart shall cause to be discharged
into the atmosphere, except as provided
in paragraph (d) of this section:
(1) From any glass melting furnace,
fired with a gaseous fuel, particulate
matter at emission rates exceeding those
specified in Table CC-1.
(2) From any glass melting furnace.
fired with a liquid fuel, particulate .
matter at emission rates exceeding 1.15
times those specified in Table CC-1.
(3] From any glass melting furnace,
simultaneously fired with gaseous and
liquid fuel, particulate matter at
emission rates exceeding those specified
by the following equation:
STD = X[1.15 (Y) + (Z)]
where:
STD = Particulate matter emission limit
X = Emission rate specified in Table CC-1
Y = Decimal percent of liquid fuel heating
value to total [gaseous and liquid) fuel
"Tieating value
kilojoules
kilojoules
Z - (1 - Y)
(b) Conversion of a glass melting
furnace to use of liquid fuel shall not be
considered a modification for purposes
of 40 CFR 60.14.
(c) Rebricking and the cost of
rebricking shall not be considered
reconstruction for the purposes of 40
CFR 60.15.
(d) This subpart shall not apply to day
pots and all-electric melters.
Tabte CC-1Emsaion dates
Gins category
00*
pmcutate/kg
of glass
produced
(1) Flat Glass o 15
12) Container Glass 10
(3) Pressed and Blown Glass
(a) Other than wda-Hme reopes (i.e.
borosKicate, opal, lead, and other recipes,
including textile fiberglass) K
(b) Soda-lime recipes 10
(4) Wool Ffcergtass .20
§ 60.293 Test methods and procedures.
(a) Reference methods in Appendix A
of this part, except as provided under
§ 60.8(b), shall be used to determine
compliance with § 60.292 as follows:
(1) Method 5 shall be used to
determine the concentration of
particulate matter and the associated
moisture content.
(2) Method 1 shall be used for sample
and velocity traverses, and
(3) Method 2 shall be used to
determine velocity and volumetric flow
rate.
(4) Method 3 shall be used for gas
analysis.
(b) For Method 5, the sample probe
and filter holder shall be heated to 121'C
(250°F). The sampling time for each run
V-CC-15
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Federal Register / Vol. 44. No. 117 / Friday. }une 15, 1979 / Proposed Rules
shall be at least 60 minutes and the
volume shall be at least 4.25 dscm.
(c) The particulate emission rate, E.
shall be computed as follows:
E = V x C
where:
(1) E is the particulate emission rate
lg/hr),
(2) V is the average volumetric flow
rate (dscm/hr) as found from Method 2:
and
(3) C is the average concentration (g/
dscm) of particulate matter as found
from Method 5.
(d) the rate of glass production, P (kg/
hr) shall be determined by dividing the
weight of glass pulled in kilograms (kg)
from the affected facility during the
performance test by the number of hours
(hr) taken to perform the performance
test. The glass pulled in kilograms shall
be determined by direct measurement or
computed from materials balance by
good engineering practice.
(e) The furnace emission rate shall be
computed as follows:
R = E/P
where:
(1) R is the furnace emission rate (g/
kg);
(2) E is the particulate emission rate
(g/hr) from (c) above; and
(3) P is the rate of glass production
(kg/hr) from (d) above.
[Sec. 114 of Clean Air Act as amended (42
U.S.C. 7414).]
|FR Doc 7»-18602 Filed 6-14-79. 8:45 am|
Federal Register / Vol 44. No. 159 / Wednesday. August IS, 1979 / Proposed Rules
[40 CFR Part 60]
IFRL 1297-3]
Standards of Performance for New
Stationary Sources; Glass
Manufacturing Plants
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Extension of Comment Period.
SUMMARY: The deadline for submittal of
comments on the proposed standards of
performance for glass manufacturing
plants, which were proposed on June 15,
1979 (44 FR 34640), is being extended
from August 14,1979, to September 14,
1979.
DATES: Comments must be received on
or before September 14,1979.
ADDRESSES: Comments should be
submitted to Central Docket Section (A-
130), United States Environmental
Protection Agency, 401 M Street, S.W.,
Washington, D.C. 20460, Attention:
Docket No. OAQPS 79-2.
FOR FURTHER INFORMATION CONTACT:
Mr. Don R. Goodwin, Director, Emission
Standards and Engineering Division
(MD-13), Environmental Protection
Agency, Research Triangle Park, North
Carolina 27711, telephone number (919)
541-5271,
SUPPLEMENTARY INFORMATION: On June
15,1979 (44 FR 34840), the
Environmental Protection Agency
proposed standards of performance for
the control of emissions from glass
manufacturing plants. The notice of
proposal requested public comments on
the standards by August 14,1979. Due to
delay in the shipping of the Background
Information Document sufficient copies
of the document have not been available
to all interested parties in time to allow
their meaningful review and comment
by August 14.1979. EPA has received a
request from the industry to extend the
comment period by 30 days through
September 14,1979. An extension of thia
length is justified since the shipping
delay has resulted in approximately a
three-week delay in processing requests
for the document.
Dated: August 8, 1979.
David G. Hawkins,
Assistant Administratarfor Aif. Noise, and
Radiation.
[FR Doc. 7B-ZS23J FiM (-14-7* MS un]
V-CC-16
-------
ENVIRONMENTAL
PROTECTION
AGENCY
STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
STATIONARY INTERNAL
COMBUSTION ENGINES
SUBPART FF
-------
Federal Register / Vol. 44. No. 142 / Monday, July 23.1979 / Proposed Rules
[FRL 10M-5]
[40 CFR Part 60]
Stationary Internal Combustion
Engines; Standards of Performance
for New Stationary Sources
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Proposed rule.
SUMMARY: The proposed standards,
which would apply to facilities that
commence construction 30 months after
today's date, would limit emissions of
nitrogen oxides (NO,) from new,
modified, and reconstructed stationary
gas, diesel, and dual-fuel internal
combustion (1C) engines to 700 parts per
million (ppm), 600 ppm, 600 ppm,
respectively at 15 percent oxygen (02)
on a dry basis. A revision to Reference
Method 20 for determining the
concentration of nitrogen oxides and
oxygen in the exhaust gases from large
stationary 1C engines is also proposed.
The standards implement the Clean
Air Act and are based on the
Administrator's determination that
stationary 1C engines contribute
significantly to air pollution. The intent
is to require new, modified, and
reconstructed stationary 1C engines to
use the best demonstrated system of
continuous emission reduction,
considering costs, non-air quality health,
and environmental and energy impacts.
A public hearing will be held to
provide interested persons an
opportunity for oral presentation of
data, views, or arguments concerning
the proposed standards.
DATES: Comments. Comments must be
received on or before September 21,
1979.
Public Hearing The public hearing
will be held on August 22,1979
beginning at 9:30 a.m. and ending at 4:30
p.m.
Request to Speak at Hearing. Persons
wishing to attend the hearing or present
oral testimony should contact EPA by
August 15, 1979.
ADDRESSES: Comments. Comments
should be submitted to Mr. Jack R.
Farmer. Chief, Standards Development
Branch (MD-13), Emission Standards
and Engineering Division,
Environmental Protection Agency,
Research Triangle Park, North Carolina
27711.
Public Hearing. The public hearing
will be held at the Environmental
Research Center Auditorium, Room
B101, Research Triangle Park, N.C.
27711. Persons wishing to attend or
present oral testimony should notify
Mary Jane Clark, Emission Standards
and Engineering Divison (MD-13),
Environmental Protection Agency,
Research Triangle Park, North Carolina
27711, telephone number (919) 541-5271.
Standards Support Document. The
support document for the proposed
standards may be obtained from the
EPA Library {MD-35), Research Triangle
Park, North CaroKna 27711, telephone
number (919) 541-2777. Please refer to
"Standards Support and Environmental
Impact Statement: Proposed Standards
of Performance for Stationary Internal
Combustion Engines," EPA-450/3-78-
125a.
Docket. The Docket, number OAQPS-
79-5, is available for public inspection
and copying at the EPA's Central Docket
Section, Room 2903 B, Waterside Mall,
Washington, D.C. 20460.
FOR FURTHER INFORMATION CONTACT:
Mr. Don R. Goodwin, Director, Emission
Standards and Engineering Division
(MD-13), Environmental Protection
Agency, Research Triangle Park, North
Carolina 27711, telephone (919) 541-
5271.
SUPPLEMENTARY INFORMATION:
Proposed Standards
The proposed standards, which are
summarized in Table A, would apply to
all new, modified, and reconstructed
stationary internal combustion engines
as follows:
1. Diesel and dual-fuel engines greater
than 560 cubic inch displacement per
cylinder (CID/cyl).
2. Gas engines greater than 350 cubic
inch displacement per cylinder (CID/
cyl) or equal to or greater than eight
cylinders and greater than 240 cubic
inch displacement per cylinder (CID/
cyl).
3. Rotary engines greater than 1500
cubic inch displacement per rotor.
The proposed standards,.which would
go into effect 30 months after the date of
proposal (i.e., today's date), would limit
the concentration of NO, in the exhaust
gases from stationary gas, diesel and
dual-fuel 1C engines to 0.0700 percent by
volume (700 ppm), 0.600 percent by
volume (600 ppm), and 0.0600 percent by
volume 600 ppm, respectively, at 15
percent oxygen (O2) on a dry basis.
These emission limits are adjusted
upward linearly for 1C engines with
thermal efficiencies greater than 35
percent.
Table 1^.Summary of Internal Combustion Engine New Source Performance Standard
internal combustion engine size and fuel type NO, emission hmrt' (rtxn) ApplicaMity dale
Gas Engines > 350 CID/cyl or ^ 8 cylinders and > 240 CID/
cyl or 1500 > CID/rotor
600
600
700
30 months from date of
proposal (> e , today's date)
30 months from date of
proposal (i e , today's date)
30 months from date of
proposal 0 e . today's date)
NO, emission limit adjusted upward lor internal combustion engines with thermal efficiencies greater than 35 percent
Measured NO, emissions adtusted to standard atmospheric conditions of 1013 Kilopascals (29 92 inches mercury). 29 4 de-
grees Centigrade (85 degrees Farhenheit), and 17 grams moisture per kilogram dry aid (75 grains moisture per pound of dry air|
n determining compliance with the NO, emission limit
The proposed standards would be
referenced to standard atmospheric
conditions of 101.3 kilopascals (29.92
inches mercury), 29.4 degrees centigrade
(85 degrees Fahrenheit), and 17 grams
mositure per kilogram dry air (75 grains
moisture per pound of dry air).
Measured NO, emission levels,
therefore, would be adjusted to standard
atmospheric conditions by use of
ambient'correction factors included in
the standard. Manufacturers, owners, or
operators may also elect to develop
custom ambient condition correction
factors, in terms of ambient temperature,
and/or humidity, and/or ambient
pressure. All correction factors would
have to be substantiated with data and
approved for use by EPA before they
could be used for determining
compliance with the proposed
standards.
Emergency-standby 1C engines and all
one- and two-cylinder reciprocating gas
engines would be exempt from the NO,
emission standard.
Summary of Environmental and
Economic Impacts
The proposed standards would reduce
uncontrolled NO, emissions levels from
stationary 1C engines by about 40
percent. Based on industry growth
projections, a reduction in national NO,
emissions of about 145,000 megagrams
per year (160,000 tons per year) would
V-FF-2
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Federal Register / Vol. .44. No. 142 / Monday. July 23. 1979 / Proposed Rules
be reahzed in the fifth year after the
standards go into effect. Except for a
few local areas (e.g^ Los Angeles), there
are currently no state standards
limintmg NO, emissions from 1C
engines.
The proposed standards, however,
would increase uncontrolled CO and HC
emissions levels from stationary 1C
engines. Based on industry growth
projections, an increase in national CO
emissions of about 216,000 megagrams
(238,OOCftons) annually would be
realized in the fifth year after the
standards go into effect. Similarly, an
increase in national total HC emissions
of about 4600 megagrams (5000 tons)
annually would be realized in the fifth
year after the standards go into effect.
The large increase in CO emissions is
chie primarily to carbureted or naturally
aspirated gas engines. These engines
operate closer to stoichiometric
conditions under which a small change
in the air-to-fuel ratio results in a large
increase in CO emissions.
Though total national CO emissions
would increase significantly, ambient air
CO concentrations in the immediate
vicinity of these carbureted or naturally
aspirated gas engines would not be
adversely affected. As a result of the
proposed standards of performance, the
CO emissions from a naturally aspirated
engine would increase about 160
percent. NO, emissions from the same
engine, however, would decrease
concurrently about 40 percent.
Thus, there exists a trade-off between
NO,-emissions reduction and CO
emissions increase, particularly for
carbureted or naturally aspirated gas
engines. It should be noted though that
CO emissions are considered to be a
local problem since CO readily reacts to
form COj. Additionally, moat naturally
aspirated gas engines are operated in
remote locations where CO is not a
problem. NO, emissions, however, are
linked to the formation of photochemical
oxidants and are subject to long range
transport. Also, NO, emission control
techniques are essentially design
modifications, not add-on equipment.
therefore. NO, emissions reductions are
much harder to achieve than CO or HC
emissions reductions which may be
achieved more easily from other
sources.
One alternative is to propose a CO
emissions limit based on the use of
oxidizing catalysts. These catalysts can
provide CO and HC emissions
reductions on the order of 90 percent.
Initial capital costs are high, however,
averaging about $7500 for a typical 1000
horsepower naturally aspirated gas
engine, or about 15 percent of the
purchase price of this engine. EPA feels
these costs for control of CO emissions
are unreasonable.
The trade-off between NO, and CO
emissions appears reasonable.
However, EPA invites comments from
state and local air pollution control
agencies, environmental groups, the
industry, and other interested
individuals concerning all aspeds of the
attractiveness of these standards which
reduce NO, emissions at the expense of
CO emissions.
Industry has requested a waiver from
the national mobile source standards for
diesel engines used in light duty
vehicles. Based on their tests, industry
believes that the application of NO,
control techniques to these mobile diesel
engines causes increased particulate
(smoke) emissions. The plumes from
most well maintained large-bore
stationary 1C engines, however, are
virtually invisible when the engine is
operating at steady state. Though
excessive retard will cause diesel,and
dual fuel units to emit smoke, the NO,
control results used in the development
of this standard were only considered if
the plume did not exceed ten percent
visibility. Therefore, EPA feels the NO,
control technique* used to meet the
proposed standards for large stationary
1C engines will not cause excessive
visible and/or particulate emissions.
However, EPA invites comments on the
aspects of the proposed standards
which reduce NO, emissions at the
expense of visible and/or particulate
emissions.
There would be essentially no advene
water pollution, solid waste, or noise
impact resulting from the proposed
standards.
The energy impact of the proposed
standards would be small.
Turbocharged gas 1C engine fuel
consumption would be increased about
two percent. Dual-fuel 1C engine fuel
consumption would be increased about
three percent. Diesel 1C engine fuel
consumption would be increased about
seven percent. Naturally aspirated gas
1C engine fuel consumption would be
increased by about eight percent. The
fifth year energy impact of the proposed
standards would be equivalent to an
increase in fuel oil consumption of about
1.5 million barrels of oil per year (4,300
barrels of oil per day). This represents
an increase of only 0.03 percent of the
oil projected to be imported in the
United States five years after the
standards go into effect In addition,
these estimates are based on "worse-
case" assumptions which yield the
greatest energy impacts, and actual
impacts are expected to be lower.
The economic impacts of the proposed
standards are considered reasonable.
The proposed standards, would increase
1C engine manufacturers' total capital
investment requirements for
developmental testing of engine models
by about $5 million. These expenditures
would be made over a two year period
Analysis of financial reports and other
public financial information indicates
that the manufacturers' overhead
budgets are sufficient to support these
requirements without adverse impact on
their financial positions. The proposed
standards would not give rise to a
significant sales advantage for one or
two manufacturers over competing
manufacturers. The maximum intra-
industry sales losses, based on "worst-
case" assumptions, would be abou4 six
percent.
The proposed standards would
increase the total annualized costs to
users of a large stationary 1C engines of
all fuel types by about two to seven
percent. The capital cost or purchase
price of a large stationary 1C engine
would increase by about two percent.
The proposed standards would
increase the total annualized costs for
all engine users by about $32 million in
the fifth year after standards go into
effect. The total capital investment
requirements for all users would equal
about 9.6 million on a cumulative basis
over the first five years the standards
are in effect.
These impacts would result in price
increases for the end products or
services provided by the industrial and
commercial users of large stationary 1C
engines. The electric utility industry
would pass on a price increase after five
years of 0.02 percent. After five years,
delivered natural gas prices would
increase 0.04 percent. Even after a full
phase-in period of 30 years, during
which new controlled engines would
replace all existing uncontrolled
engines, the electric utility industry
would pass on a price increase of only
0.1 percent. Delivered natural gas prices
would increase only 0.3 percent.
RationaleSelection of Source for
Control
Stationary 1C engines are sources of
NO,, hydrocarbons (HC), particulates,
sulfur dioxide (SO,), and carbon
monoxide (CO) emissions. NO,
emissions from 1C engines, however, are
of more concern than emissions of these
other pollutants for two reasons. First,
compared to total U.S. emissions for
each pollutant, NO, is the primary
pollutant emitted by stationary engines.
Second, EPA has assigned a high
priority to development of standards of
V-FF-3
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Federal Register / Vol. 44, No. 142 / Monday, July 23, 1979 / Proposed Rules
performance limiting NO, emissions. A
study by Argonne National Laboratory,
"Priorities and Procedures for
Development of Standards of
Performance for New Stationary
Sources of Atmospheric Emissions"
(EPA-450/3-76-020), concluded that
national NO, emissions from stationary
sources would increase by more than 40
percent between 1975 and 1990 in the
absence of additional emission controls.
Applying best technology to all sources
would reduce this increase but would
not prevent it from occurring. This
unavoidable increase in NO, emissions
is attributable largely to the fact that
current NO, emission control techniques
are based on combustion redesign. In
addition, few NO, emission control
techniques can achieve large (i.e., in the
range of 90 percent) reductions in NO,
emissions. Consequently, EPA has
assigned a high priority to the
development of standards of
performance for major NO, emission
sources wherever significant reductions
in NO, can be achieved. Studies have
shown that 1C engines are significant
contributors to total U.S. NO, emissions
from stationary sources. Internal
combustion engines account for 16.4
percent of all stationary source NO,
emissions, exceeded only by utility and
packaged boilers.
Studies have investigated the effect
that standards of performance would
have on nationwide emissions of
particulates, NO,, SO,, HC, and CO
from stationary sources. The "Priority
List for New Source Performance
Standards under the Clean Air Act
Amendments of 1977," which was
proposed in the August 31,1978, Federal
Register, ranked sources according to
the impact, in tons per year, that
standards promulgated in 1980 would
have on emissions in 1990. This ranking
placed spark ignition 1C engines second
and compression ignition 1C engines
third on a list of 32 stationary NO,
emission sources. Consequently,
stationary 1C engines have been
selected for development of standards of
performance.
Selection of Pollutants
Nitrogen oxides, hydrocarbons, and
carbon monoxide.Stationary 1C
engines emit the following pollutants:
NO,, CO. HC, particulates, and SO,. The
primary pollutant emitted by stationary
1C engines is NO,, accounting for over
six percent (or 16 percent of all
stationary source*) of the total U.S.
inventory of NO, emissions.
Stationary 1C engines also emit
substantial quantities of CO and HC.
Numerous small (1-100 hp) spark
ignition engines, which are similar to
automotive engines, account for about
20 percent of the uncontrolled HC
emissions and about 80 percent of the
uncontrolled CO emissions. The large
annual production of these small spark
ignition engines (approximately 12.7
million), however, makes enforcement of
a new source performance standard for
this group difficult.
Large-bore engines, which account for
three-quarters of NO, emissions from
stationary 1C engines, contribute
relatively small amounts to nationwide
HC and CO emissions, especially if one
considers that 80 percent of the HC
emissions from large-bore 1C engines are
methane. An additional factor in
considering CO and HC control is that
inherent engine characteristics result in
a trade-off between NO, control and
control of CO and HC.
As mentioned before, in some cases,
particularly naturally aspirated gas
engines, the application of NO, emission
control techniques could cause
increases in CO and HC emissions. This
increase in CO and HC emissions is
strictly a function of the engine
operating position relative to
stoichiometric conditions, not the NO,
control technique. These engines
operate closer to stoichiometric
conditions under which a small change
in the air-to-fuel ratio results in a large
increase in CO emissions. Any increase
in CO and HC emissions, however,
represents an increase in unbumed fuel
and hence a loss in efficiency. Since 1C
engines manufacturers compete with
one another on the basis of engine
operating costs, which is primarily a
function of engine operating efficiency,
the marketplace will effectively ensure
that CO and HC emissions are as low as
possible following application of NO,
control techniques.
Though total national CO emissions
would increase significantly, ambient air
CO concentrations in the immediate
vicinity of these carbureted or naturally
aspirated gas engines would not be
adversely affected. As a result of the
proposed standards of performance, the
CO emissions from a natually aspirated
engine would increase about 160
percent. NO, emissions from the same
engine, however, would decrease
concurrently about 40 percent.
Thus, there exists a trade-off between
NO, emissions reduction and CO
emissions increase, particularly for
carbureted or naturally aspirated gas
engines. It should be noted though that
CO emissions are considered to be a
local problem as CO readily reacts to
form CO,. Additionally, most naturally
aspirated gas engines are operated in
remote locations where CO is not a
problem. NO, emissions, however, are
linked to the formation of photochemical
oxidants and are subject to long range
transport. NO, emissions reductions are
also much harder to achieve than CO or
HC emissions reductions which may be
achieved more easily from other
sources.
In addition, promulgation of CO
standard of performance could, in effect,
preclude significant NO, control. NO,
emissions are primarily a function of
combustion flame temperature.
Decreasing the air-to-fuel ratio of a gas
engine lowers the flame temperature
and consequently reduces NO,
formation. As will be discussed later,
this technique is the most effective
means of reducing NO, emissions from
gas engines. CO emissions, however, are
primarily a function of oxygen
availability. Decreasing the air-to-fuel
ratio reduces oxygen availability and
consquently increases CO emissions.
Hence naturally aspirated gas engines
show a pronounced rise in CO emissions
as the air-to-fuel mixture becomes richer
(i.e., decreasing air-to-fuel ratio). Thus,
placing a limit on CO emissions from
internal combustion engines could
effectively limit the decrease in the air-
to-fuel ratio which would be applied to
reduce NO, emissions from naturally
aspirated gas engines and,
consequently, could limit the amount of
NO, emissions reduction achievable.
One alternative is to propose a CO
emissions limit based on the use' of
oxidizing catalysts. These catalysts can
provide CO and HC emissions
reductions on the order of 90 percent.
Initial capital costs are high, however,
averaging about $7500 for a typical 1000
horsepower naturally aspirated gas
engine, or about 15 percent of the
purchase price of this engine. EPA feels
these costs for control of CO emissions
are unreasonable.
The trade-off between NO, and CO
emissions appears reasonable, and
consequently, only NO, emissions from
large stationary 1C engines were
selected for control by standards of
performance.
EPA, however, invites comments from
state and local air pollution control
agencies, environmental groups, the
industry, and interested individuals
concerning all aspects of the
attractiveness of these standards which
reduce NO, emissions at the expense of
CO emissions.
Paniculate.Virtually no data are
available on particulate emission rates
from stationary 1C engines. It is
believed, however, that particulate
emissions from stationary 1C engines are
V-FF-4
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Federal Register / Vol. 44, No. 142 / Monday, July 23, 1979 / Proposed Rules
very low because the plumes from most
of these engines are not visible.
Therefore, neither particulate emissions
nor visible emissions (plume opacity)
were selected for control by standards
of performance.
Sulfur oxides.Sulfur oxides (SO,)
emissions from an 1C engine depend on
the sulfur content of the fuel and the fuel
consumption of the engine. Scrubbing of
1C engine exhausts to control SO,
emissions does not appear to be
reasonable from an economic viewpoint.
Therefore, the only viable means of
controlling SOX emissions would be
combustion of low sulfur fuels. 1C
engines, however, currently burn low-
sulfur fuels and will likely continue to
do so because of the lower operating
and maintenance costs associated with
combustion of these fuels. Therefore,
SO, emissions were not selected for
control by standards of performance.
Selection of Affected Facilities
A relatively small number of large-
bore 1C engines account for over 75
percent of all NOX emissions from
stationary engines. The remaining
smaller bore 1C engines, which make up
the majority of all engine sales, are,
from a NOX emission standpoint, a
considerably less significant segment of
the industry. These engines have
different emission characteristics due to
thpir size, design, and operating
parameters. The NO, reduction
technology developed for use on the
largp-bore 1C engines may not be
directly applicable to these smaller
engines Therefore, at this time, only
Ittrgp-bore engines have been selected
for control by standards of performance.
Diesel engines.The primary high
usdge (Idrge emissions impact) domestic
application of large-bore diesel engines
during the past five years has been for
oil nnd gas exploration and production.
The market for prime (continuous)
ele< trie generation and other industrial
Hpphcations all but disappeared after
the 1973 oil embargo, but was quickly
replaced by sales of standby electric
units for building services, utilities, and
nuclear power stations. The rapid
growth in the oil and gas production
market occurred because diesel units
are being used on oil drilling rigs of
various sizes. Sales of engines to export
applications have also grown steadily
since 1972, and are now a major
segment of the entire sales market.
Medium-bore as well as large-bore
engines are sold for oil.and gas
exploration, standby service, and other
industrial applications. Applying
standards of performance to medium-
bore engines serving the same
applications as large-bore designs
would increase the number of affected
facilities from about 200 to about 2,000
units per year (based on 1976 sales
information) but consequently further
reduce national NO, emissions.
Medium-bore sales accounted for
significant NO, emissions in 1976
(approximately 12,500 megagrams). It is
estimated that approximately 25
percent, or about 500 of these units in
high usage applications, accounted for
most of the medium/bore NO,
emissions, since most of the remainder
of these units were sold as standby
generator sets. Though the potential
achievable NO, reduction is significant,
this alternative causes the standard to
apply to lower power engine models
with fewer numbers of cylinders
competing with other unregulated
engines in different stationary markets
Additionally, considering this large
number, and the remoteness and
mobility of petroleum applications, this
alternative would create serious
enforcement difficulties. Consequently.
a definition is required that
distinguishes large-bore engines
competing with medium-bore high
power engines used for baseload
electrical generation from large-bore
engines competing solely with other
large-bore engines.
One approach would be to define
diesel engines covered by standards of
performance as those exceeding 560
cubic inch displacement per cylinder
(ie., CID/cyl). 1C engines below this size
are generally used for different
applications than those above it.
Considering the sizes and displacements
offered by each diesel manufacturer and
the applications served by diesel
engines, this definition was selected as
a reasonable approach for separating
large-bore engines that compete with
medium-bore engines from large-bore
engines that compete solely with each
other.
Dual-fuel engines.The concept of
dual-fuel operation was developed to
take advantage of both compression
ignition performance and inexpensive
natural gas. These engines have been
used almost exclusively for prime
electric power generation. Shortages of
natural gas and the 1973 oil embargo
have combined to significantly reduce
the sales of these engines in recent
years. The few large-bore units that
were sold (11 in 1976) were all greater
than 350 CID/cyl.
Although a greater-than-350-CID/cyl
limit would subject nearly all new dual-
fuel sources to standards of
performance, the criterion chosen to
define affected diesel engines (i.e..
greater than 560 CID/cyl) has also been
elected for dual-fuel engines. The
primary reason is that supplies of
natural gas are likely to become even
more scarce; thus dual-fuel engines will
likely operate as diesel engines.
Cos engines.The primary
application of large-bore gas engines
during the past five years has been for
oil and gas production. The primary uses
are to power gas compressors for
recovery, gathering, and distribution.
About 75 to 80 percent of all gas engine
horsepower sold during the past five
years was used for these applications.
During this time, sales to pipeline
transmission applications declined.
Pipeline applications combined with
standby power, electric generation, and
other services (industrial and sewage
pumping) accounted for the remaining 20
to 25 percent of horsepower sales. The
growth of oil and gas production
applications during this period
corresponds to the increasing efforts to
find new, or to recover marginal. gas
reserves and distribute them to the
existing pipeline transmission network
It is estimated that the 400,000
horsepower of large-bore gas engine
capacity sold for oil and gas production
applications in 1976 emitted 35,000
megagrams of NO, emissions, or nearly
three times more NO, than was emitted
by the 200,000 horsepower of large-bore
diesel engine capacity sold for the same
application in that year. Thus, large-bore
gas engines are primary contributors of
NO, emissions from new stationary 1C
engines, and standards of performance
should be directed particularly at these
sources.
If affected engines were defined as
those greater than 350 CID/cyl, then all
competing manufacturers of large-bore
gas engines except one would be
affected by the proposed standards of
performance. This one manufacturer
produces primarily medium-bore
engines. Therefore, a 350 CID/cyl limit
would give this one manufacturer an
unfair competitive advantage over other
large-bore engine manufacturers.
Consequently, this definition should be
lowered, or another definition adopted.
to include the manufacturer in question.
Either of the following two definitions
would subject this manufacturer's gas
engine to standards of performance:
Greater than 240 CID/cyl
Greater than 350 CID/cyl or greater
than or equal to 8-cylinder and greater
than 240 CID/cyl
Both measures would essentially
include only this manufacturer's gas
engines which compete with other
manufacturer's large-bore gas engines.
The second definition has a slight
V-FF-5
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Federal Register / Vol. 44, .No. 142 ^Mondayjuly 23, 1979 / Proposed Rules
advantage over the first since it includes
only gas engines produced by all
manufacturers that have competitor
counterparts-of about the came power.
Therefore, this second definition of
affected gas'engines was selected.
Rotary engines.Rotary or wankel
type engines >have only recently been
introduced as power sources in package
Stationary applications. These internal
combustion engines convert energy in
the fuel directly to rotary motion rather
than through reciprocating pistons and a
crankshaft. These engines consist of a
triangular rotor rotating eccentrically
inside an epitrochoidal housing.
Until recently the largest rotary engine
in production was 90 cubic inches per
rotor. Now, however, one manufacturer
is producing a rotary engine with a
displacement of 2,500 cubic inches per
rotor. This engine is being offered as a
one rotor model rated at 550 horsepower
and a two rotor unit rated at 1,100
horsepower.
The displacement of the rotary engine
is defined as the volume contained in
the chamber, bordered by one flank of
the rotor and the housing, at the instant
the inlet port closes. These engines are
presently sold as naturally aspirated
gaseous fueled units primarily for fuel
gathering compressors and power
generation on offshore platforms.
NO, emissions from these large rotary
engines are similar to NO, emissions
from naturally aspirated four stroke,
gaseous fuel reciprocating engines.
Further sales of these engines are
estimated to be 50,000 horsepower per
year over the next five years. Since
these large rotary engines contribute to
NO, emissions, standards of
performance for new stationary 1C
engines should include these sources.
Due to design differences, rotary
engines develop more power per cubic
inch displacement than reciprocating
engines. If the lower cutoff limit for
affected rotary engines were 350 CID/
rotorin an attempt to equate
displacement per cylinder and also use
the same limit as for gaseous fueled
enginesthen rotary engines of
approximately 100 horsepower would be
regulated by standards of performance.
Thus rotary engine manufacturers would
be at a competitive disadvantage with
unregulated reciprocating engine
manufacturers in this power range. To
ensure that the standards of
performance do not alter the competitive
position of the two types of engines, the
lower size limit for affected rotary
engines should correspond to an engine
whose power output is the same as the
smallest affected reciprocating unit.
Based on this criterion of equivalent
horsepower, it is estimated that rotary
engines greater'than 1,500 CID/rotor
would compete with reciprocating
engines greater than 360 CID/cyc.
Therefore, a greater than 1,500 CID/
rotor definition of affected rotary
engines -is selected to subject these
engines to standards of performance.
The definition applies to rotary engines
of all fuel types.
Exemptions.One and two cylinder
reciprocating engines could be covered
by the above definitions. These engines,
however, account for less than 10
percent of all engine horsepower and
therefore are less significant NO,
emitters. Additionally, the engines
operate at a small fraction of their
power output and probably have lower
NO, emissions than the larger, high
rated engines. Therefore, all one and
two cylinder reciprocating engines were
exempted from standards of
performance.
Emergency standby engines also
require special consideration. These
engines operate less than 200 hours per
year under all but very unusual
circumstances. Consequently, they add
relatively little to regional or national
total NO, emissions. The largest
category of emergency standby units is
for nuclear power plants, where these
engines provide power for the pumps
used for cooling the reactors. These
engines must attain a set speed in ten
seconds and must assume full rated load
in 30 seconds. In some cases,
application of the demonstrated NO,
control technique limits the
responsiveness of these engines in
emergency situations. Therefore, all
emergency standby engines are
exempted from standards of
performance.
Selection of Best System of Emission
Reduction
Four emission control techniques, or
combinations of these techniques, have
been identified as demonstrated NO,
emission reduction systems for
stationary large-bore 1C engines. These
techniques are: (1) Retarded ignition or
fuel injection, (2) air-to-fuel ratio
changes, (3) manifold air cooling, and (4)
derating power output (at constant
speed). In general, all four techniques
are applied by changing an engine
operating adjustment.
Fuel injection retard is the most
effective NO, control technique for
diesel engines. Similarly, air-to-fuel ratio
change is the most effective NO, control
technique for gas engines. Both retard
and air-to-fuel ratio changes are
effective in reducing ItfQ, emissions
from dual-fuel engines.
Other NO, emission control
techniques exist but are not considered
feasible alternatives. Of these other
techniques, catalytic reduction of NO,
emissions through the use of systems
similar to automobile catalyst systems is
probably the first to come to mind. Most
large stationary 1C engines operate at
air-to-fuel ratios that are typically much
greater than stoichiometric, and
consequently the engine exhaust is
characterized by high oxygen (O,)
concentrations. Existing automobile
catalytic converters, however, operate
near stoichiometric conditions (i.e., low
exhaust O, concentrations). These
automobile catalysts are not effective in
reducing NO, in the presence of high Ot
concentrations.
Consequently, entirely different
catalyst systems would be needed to
reduce NO, emissions from large
stationary 1C engines. Although such
catalyst systems are currently under
development and have been
demonstrated for one very narrow
application (i.e., fuel-rich naturally
aspirated gas engines), they have not
been demonstrated for the broad range
of 1C engines manufactured, such as
turbocharged engines, fuel-lean gas
engines, or diesel engines. For these
engines the reduction of NO, by
ammonia injection over a precious metal
(e.g., platinum) catalyst appears
promising with NO, reductions of
approximately 90 percent having been
reported; however, the cost of such a
system is high.
For a typical 1000 horsepower engine
approximately two cubic feet of
honeycomb catalyst (platinum based)
would be required to ensure proper
operation of the system. The cost of the
catalyst was estimated at Sl.500/cubic
foot (in 1973). Assuming that the engine
costs $150/hp and that the cost of the
catalyst accounts for about one-half the
cost of the whole system (container,
substrate, and catalyst), the capital
investment for this control system
represents approximately four percent
of the engine purchase price.
The amount of ammonia required for
an ammonia/catalyst NO, reduction
system will depend on the NO, emission
rate (g/hp-hr). Based on uncontrolled
NO, emission rates of 9 to 22 g/hp-hr,
and the cost of $150/ton for the
ammonia, the cost impact of injecting
ammonia is approximately 5 to 15
percent of the total annual operating
costs ($/hp-hr) for natural gas engines.
When this operating cost is combined
with the capital cost of the catalytic
system discussed above, the total cost
V-FF-6
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Federal Register / Vol. 44, No. 142 / Monday, July 23. 1979 / Proposed Rules
increase is about 25 percent. Therefore,
in continuous service applications this
system is expensive compared to control
techniques such as retard or air-to-fuel
changes.
It is also important to note that the
consumption of ammonia can be
expressed as a quantity of fuel since
natural gas is generally used to produce
ammonia. Assuming a conservative NO,
emission rate of 20 g/hp-hr, and engine
heat rate of 7500 Btu/hp-hr, a heating
value of 21,800 Btu/lb for natural gas,
and a requirement for approximately 900
Ibs of gas per ton of ammonia produced,
then the ammonia necessary for the
catalytic reduction has the same effect
on the supply of natural gas as a two
percent increase in fuel consumption.
Additional fuel is required to operate
the plant which produces the ammonia.
Catalytic reduction, therefore, is
currently not a demonstrated NO,
emission control technique which could
be used by all 1C engines. Consequently,
although catalytic reduction of NO,
emissions could be used in a few
isolated cases to comply with standards
of performance, it could not be used as
the basis for developing standards of
performance which are applicable to all
1C engines.
The data and information presented in
the Standards Support and
Environmental Impact Statement clearly
indicate that the four demonstrated
control techniques mentioned above will
reduce NO, emissions from 1C engines.
Due to inherent differences in the
uncontrolled emission characteristics of
various engines, it is difficult to draw
conclusions from this data and
information concerning the ability of
these emission control techniques to
reduce NO, emissions from all 1C
engines to a specific level. In general,
engines with high uncontrolled NO,
emissions levels have relatively high
controlled NO, emissions levels and
engines with low uncontrolled NO,
emissions levels have relatively low
contolled NO, emissions levels. To
eliminate these inherent differences in
NO, emission characteristics among
various engines, the data were analyzed
in terms of the degree of reduction in
NO, emissions as a function of the
degree of application of each emission
control technique.
Ignition retard in excess of eight
degrees in diesel engines frequently
leads to unacceptably high exhaust
temperatures, resulting in exhaust value
and/or turbocharger turbine damage.
Similarly, changes in the air-to-fuel ratio
in excess of five percent in gas engines
frequently lead to excessive misfiring or
detonation which could lead to a serious
explosion in the exhaust manifold. Eight
degrees of ignition retard in diesel
engines and five percent change in air-
to-fuel ratios in gas engines yield about
a 40 percent reduction in NO, emissions.
Consequently, in light of these
limitations to the application of these
emission control techniques, it is
apparent that a 40 percent reduction in
NO, emissions is the most stringent
regulatory option which could be
selected as the basis for standards of
performance. An alternative of 20
percent NO, emission reduction was
also considered a viable regulatory
option which could serve as the basis
for standards of performance.
Environmental impacts.Standards
of performance based on alternative I
(20 percent reduction) would reduce
national NO, emissions by 72,500
megagrams annually in the fifth year
after the standards went into effect. In
contrast, standards of performance
based on alternative II (40 percent
reduction) would reduce national NO,
emissions by about 145,000 megagrams
annually in the fifth year after the
standards went into effect. Thus,
standards of performance based on
alternative II would have a much greater
impact on national NO, emissions than
standards based on alternative I.
Standards of performance based on
either alternative would, with the
exception of naturally aspirated gas
engines, result in a small increase in
carbon monoxide (CO) and hydrocarbon
emissions (HC) from most engines. A
typical diesel engine with a sales-
weighted average uncontrolled CO
emission level of approximately 2.9 g/
hp-hr would experience an increase in
CO emissions of about 0.75 g?hp-hr to
comply with standards of performance
based on alternative I, and an increase
of about 1.5 g/hp-hr to comply with
standards of performance based on
alternative II. Total hydrocarbon
emissions would increase a sales-
weighted average uncontrolled emission
level of 0.3 g/hp-hr by about 0.06 g/hp-hr
to comply with standards based on
alternative I, and would increase by
about 0.1 g/hp-hr to comply with
standards of performance based on
alternative II.
Similarly, a typical dual-fuel engine
with a sales-weighted average
uncontrolled CO emission level of
approximately 2.7 g/hp-hr would
experience an increase in CO emissions
of about 1.2. g/hp-hr and about 2.7 g/hp-
hr to comply with standards of
performance based on alternatives I and
II, respectively. Total HC emissions,
however, would increase by about 0.3 g/
hp-hr from a sales-weighted average
uncontrolled level of approximately 2.8
g/hp-hr to comply with standards of
performance based on alternative I. To
comply with standards of performance
based on alternative II total
hydrocarbon emissions would decrease
by 0.6 g/hp-hr.
A typical turbocharged or blower
scavenged gas engine with a sales-
weighted average uncontolled CO
emission level of approximately 7.7 g/
hp-hr would experience an increase in
CO emissions of about 1.9 g/hp-hr to
comply with standards of performance
based on alternative I and about 3.8 g/
hp-hr to comply with standards of
performance based on alternative II.
Total hydrocarbon emissions would
increase a sales-weighted average
uncontrolled level of approximately 1.9
g/hp-hr by about 0.2 g/hp-hr to comply
with standards of performance based on
alternative I. To comply with standards
of performance based on alternative II
total hydrocarbon emissions would
increase by about 0.4 g/hp-hr.
A typical naturally aspirated gas
engine with a sales-weighted average
uncontrolled CO emission level of
approximately 7.7 g/hp-hr would
experience an increase in CO emissions
of about 3.9 g/hp-hr to comply with
standards of performance based on
alternative I and about 17 g/hp-hr to
comply with standards of perfomance
based on alternative II. Total
hydrocarbon emissions would increase
a sales-weighted average uncontrolled
level of approximately 1.8 g/hp-hr by
about 0.04 g/hp-hr to comply with
standards of performance based on
alternative I. To comply with standards
of performance based on alternative II
total hydrocarbon emissions would
increase by about 0.08 g/hp-hr
As noted earlier, the increase in
ambient air CO levels resulting from
compliance with NO, standards of
performance based on either alternative
would be insignificant compared to the
NAAQS of 10 mg/m3 for CO.
Additionally, CO emissions are a local
problem as CO readily reacts to form
CO* Additionally, most naturally
aspirated engines are operated in
remote or sparcely populated areas, CO
emissions will not present a problem.
Currently, national stationary CO
emissions are approximately 33 million
megagrams per year. Standards of
performance based on alternative I
would increase these emissions by
approximately 63,000 megagrams
annually in the fifth year after the
standards went into effect. In contrast,
standards of performance based on
alternative II would increase national
CO emissions by about 216,000
V-FF-7
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Federal Register / Vol. 34. Nc. 342 // iManday. July 23, 1979 / Proposed Rules
megqgrams annually,in the fifth year
after doe standards went into effect.
.'Standards of'performance based on
alternative 1 would 'increase national
total HC emissions by about .2,300
megagrams annually .in,the fifth year
after the standards went into effect
compared to an increase of f
approximately 216 megagrams .annually
associated .with alternative II.
Stationary 1C engines are sources .of
NO,, HC. and CO emissions, with .bath
NO. and HC contributing to oxidant
formation. With regard to regulation of
emissions from 1C engines, NO,
emissions are of more concern .than
.emissions of HC for two .reasons. First.
NO, .is emitted in greater quantities from
stationary 1C engines ihan HC. Second,
as mentioned earlier, aihigh priority JMS
been assigned 'to development of
standards of ;perfomance limiting "NO,
emissions. A study by-Axgonne National
Laboratory, "Priorities and Procedures
for development of Standards of
Perfomancelor New Stationary Sources
of Atmospheric Emissions," concluded
that national NO, emissions from
Stationary sources would increase by
more than 40 percent between IflTSand
1990 in the absence of additional
emission controls. The sJight increase in
HC emissions from 1C engines
associated with control of NO, can .be
offset in most cases from other sources
more easily than NQ, emissions can be
reduced from other sources. Therefore,
the adverse environmental impact of
increased HC emissions because of the
reduction in NO, emissions is
considered small.
There would be essentially no water
pollution, solid waste, or noise impact of
standards of performance based on
either .alternative I or alternative II.
Thus, as reflected in Table 1. the
environmental impacts of standards of
performance Abased on either alternative
are small and reasonable
V-FF-8
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Federal Register / Vol. 44. No. 142 / Monday. July 23.1979 / Proposed Rules
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V-FF-9
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Federal Register / Vol. 44, No. 142 / Monday, July 23, 1979 / Proposed Rules
Energy impacts. The potential energy
impact of standards of performance
based on either alternative is small.
Standards of performance based on
alternative.I would increase the fuel
consumption of a typical blower-
scavenged or turbocharged gas engine
by approximately one percent, whereas
standards of performance based on
alternative II would increase the fuel
consumption by approximately two
percent.
Standards of performance based on
alternative I would increase the fuel
consumption of a typical dual-fuel
engine by about one percent. Standards
of performance based on alternative II,
however, would increase the fuel
consumption by three percent.
Standards of performance based on
alternative I would increase the fuel
consumption of a typical naturally
aspirated gas engine by approximately
six percent. Standards of performance
based on alternative II, however, would
increase the fuel consumption by
approximately eight percent.
Standards of performance based on
alternative I would increase the fuel
consumption of a typical diesel engine
by approximately three percent.
Standards of performance based on
alternative II, however, would increase
the fuel consumption by approximately
seven percent.
The potential energy impact in the
fifth year after the standards go into
effect, based on alternative I, would be
equivalent to an increase in fuel
consumption of approximately 1.03
million barrels of oil per year compared
to the uncontrolled fuel consumption of
1C engines affected by the standards of
31 million barrels per year. The potential
energy impact in the fifth year after the
standard goes into effect, based on
alternative II, would be equivalent to
approximately 1.5 million barrels of oil
per year.
It should be noled that the largest
increase represents only 0.02 percent of
the 1977 domestic consumption of crude
oil and natural gas. The largest increase
also represents only 0.03 percent of the
projected total oil imported to the U.S.
five years after the standards go into
effect.
Thus, the energy impacts of standard
of performance based on either
alternative are small and reasonable.
Economic impact of alternatives.
Manufacturers of stationary 1C engines
would incur additional costs due to-
standards of performance. These costs,
however, would be small. It is estimated
that the total cost to the manufacturers
for each engine model family, including
development, durability tests, and
retooling, would be approximately: (1)
$125,000 for retard and air-to-fuel
change; (2) $150,000 for manifold air
temperature reduction; and (3) $25,000
for derate. For each manufacturer
therefor, total costs would vary
depending on-(l) the number of engine
model families produced; (2) their
degree of advancement in emission
testing; (3) the uncontrolled emission
levels of their engines; (4) the
development and durability testing
required to produce engines that can
meet proposed standards of
performance; and (5) the emission
control technique selected for NO,
emission reduction.
The manufacturer's total capital
investment requirements for
developmental testing of engine models
is estimated to be about $4.5 million to
comply with standards of performance
based on alternative I and about $5
million to comply with standards of
performance based on alternative II.
These expenditures would be made over
a two year period. Analyses of the
financial statements and other public
financial information of engine
manufacturers or their parent companies
indicate that the manufacturer's
overhead budgets are sufficient to
support the development of these
controls without adverse impact on their
financial position.
Manufacturers would not experience
significant differential cost impacts
among competing engine model families.
Consequently, no significant sales
advantages or disadvantages would
develop among competing
manufacturers as a result of standards
of performance based on either
alternative. Based on "worst-case"
assumptions, the maximum intra-
industry sales losses would be about six
percent as a result of standards of
performance based on either alternative.
Thus, the intra-industry impacts would
be moderate and not cause any major
dislocations within the industry.
The total annualized cost penalities
imposed on 1C engines by standards of
performace would also have very little
impact with regard to increasing sales of
gas turbines. Standards of performance
based on alternative I would result in no
loss of sales to gas turbines whereas
standards of performance based on
alternative II could result in the possible
loss of sales for one diesel
manufacturer.
It should be noted that this conslusion
is based on limited data. It is quite
likely, however, that this manufacturer's
line of diesel engines, through minor
combustion modifications, could reduce
its NO, emissions as discussed in the
SSEIS to levels comparable to those of
other manufacturers. Further, due to
technical limitations, economic
considerations, and customer
preference, it is unlikely that 1C engine
users would switch to gas turbines.
Thus, the impact on sales would be
minimal.
Therefore, the economic impacts on
the manufacturers of standards of
performance based on either alternative
are considered small and reasonable.
The application of NO, controls will
also increase costs to the engine user.
The magnitude of this increase will
depend upon the amount and type of
emission control applied. Fuel penalties
are the major factor affecting this
increase.
The following four end uses represent
the major applications of diesel, dual-
fuel, and natural gas engines: (1) Diesel
engine, electrical generation; (2) dual-
fuel engine, electrical generation; (3) gas
engine, oil and gas transmission and (4)
gas engine, oil and gas production.
The manufacturers' capital budget
requirements to develop and test engine
NO, control techniques would be
regarded as an added expense and most
likely passed on to the engine users in
the form of higher prices. Therefore,
users of 1C engines would have to
expend additional capital to purchase
more expensive engines. This capital
cost penalty, however, is small. A two
percent increase in engine price would
be expected on the average as the result
of standards of performance based on
either alternative. Typical initial costs
for uncontrolled diesel and dual-fuel,
electrical generation engines, and
natural gas oil and gas transmission
engines are about $150/hp. Initial costs
for gas, gas production engines are
about $50/hp.
The total additional capital cost for all
users would equal about $9.6 million on
a cumulative basis over the first five
years to comply with standards of
performance based on either alternative.
As mentioned earlier, fuel penalties
are the major factor affecting the total
annualized cost of high usage engines.
The total annualized cost of a typical
uncontrolled diesel, electrical generation
engine is about 2.5C/hp-hr. As a result of
standards of performance based on
alternative I this total annualized cost
would increase by about 0.04
-------
Federal Register / Vol. 44, No. 142 / Monday. July 23, 1979 / Proposed Rules
base on alternative II this total
annualized cost would increase by
about 0.07
-------
Federal Register / Vol. 44. No. 142 / Monday. July 23,1979 / Proposed Rules
TA8LE II
ECONOMIC IMPACTS OF ALTERNATIVES
lapact
Uncontrolled
level of Cost
Alternative I
Alternative II
I»oact on Manufacturer
Capital budget requirements
Intra-industry competition
Competition froa gas turbines
Inpact on End-Use Applications
Total annualized costa
D'esel fuel, electrical
generation
Dual-fuel, electrical gen-
eration
Natural gas fuel, oil and
gas transaission
Natural gas fuel, oil and
gas production
Totals of all new engines
after 5 years
Capital Cast Penalty*
Diesel fuel, electrical
generation or dual fuel,
electrical generation or
natural gas fuel, oil and
gas transmission
Natural gas fuel, oil and
gas production
Totals etc.
laoact on "roquet Pr'ees and
users
Electricity prices
prices
2.5C/hp-hr
2.8C/hp-hr
2.2t/hp-hr
2.2?/hp-hr
$£80 nf11 ion
S150/hp
S SO/hp
$450 Billion
$4.5 Billion over two years;
bit to generate Internally
froa profits.
Maximum sales loss unlikely to
exceed 62 of internal comous-
tion engine sales for any fin.
No losses.
Base increased by 0.04t/hp-hr
Increased by 0.07£/hp-nr
Increased by 0.02t/hp-hr
Increased by 0.144/hp-hr
Increased by S2S pillion
Increased by $3.00/hp
Increased by Sl.OO/hp
$9 S million on a emulative
basis over first 5 years after
jtanoarfls go into effect.
U.S. electric bill uo 0.025
after 5 years. U.S. electric
bill up 0.IS after full phasa-
in.
Delivered natural gas prices up
0.025 after 5 years. Delivered
natural gas prices up 0.15
after full phasetn.
Assumed typical 2000 horsepower engine operating 8000 hours per year in all cases
Full pnase-in implies replacement of a'l existing engines
S5 Billion over two years; able
to generate internally froa
profits.
6S Baximua loss for any fim
Possible sales loss for one
diesel Banufacturer.
Increased by 0. HC/hp-hr
Increased by O.C9
-------
Federal Register / Vol. 44. No. 142 / Monday, July 23. 1979 / Proposed Rules
Based on the assessment of the
impacts of each alternative, and since
ahernative I] achieves a greater degree
of NO, reduction, it is selected as the
best technological system of continuous
emission reduction of NO, from
stationary large-bore 1C engines,
considering the cost of achieving such
emission reduction, any nonair quality
health and environmental impact, and
energy requirements.
Selection of Format for the Proposed
Standards
A number of different formats could
be used to limit NO, emissions from
large stationary 1C engines. Standards
could be developed to limit emissions in
terms of: (1) Percent reduction; (2) mass
emissions per unit of energy (power]
output; or (3) concentration of emissions
in the exhaust gases discharged to the
atmosphere.
Analysis of the effectiveness of the
various NO, emission control techniques
clearly shows that the ability to achieve
a percent reduction in NO, emissions is
what has been demonstrated. However,
a percent reduction format is highly
impractical for two reasons. First, a
reference uncontrolled NO, emission
level would have to be established for
each manufacture's engine, a difficult
task since some manufacturers produce
as many as 25 models which are sold
with several ratings. Second, a reference
uncontrolled NO, emission level would
have to be established for any new
engines developed after promulgation of
the standard. This would be quite simple
for engines that employed NO, control
techniques such as ignition retard or air-
to-fuel ratio change to comply with
standards of performance. Emissions
could be measured without the use of
these techniques. For engines designed
to comply with the standards through
the use of combustion chamber
modifications, however, this would not
be possible Thus, new engines would
receive no credit for the NO, emission
reduction achieved by combustion
chamber redesign and this would
effectively preclude the use of this
approach to comply with the standards.
A mass-per-unit-of-energy-output
format, typically referred to as brake-
specific emissions (g/hp-hr), relates the
total mass of NO, emissions to the
engine's productivity. Although brake-
specific mass standards (g/hp-hr)
appear meaningful becasue they relate
directly to the quantity of emissions
discharged into the atmosphere, there
are disadvantages in that enforcement
of mass standards would be costly and
complicated in practice. Exhaust flow
and power output would have to be
determined in addition to NO,
concentration. Power output can be
determined from an engine
dynamometer in the laboratory, but
dynamometers cannot be u»ed in the
field. Power output could be determined
by; (1) Inferring the power from engine
operating parameters (fuel flow, rpm,
manifold pressure, etc.); or (2) inferring
engine power from the output of the
generator or compressor attached to the
engine. In practice, however, these
approaches are time consuming and are
less accurate than dynamometer
measurements.
Another possible format would be to
limit the concentration of NO, emissions
in the exhaust gases discharged to the
atmosphere. Concentrations would be
specified in terms of parts-per-million
volume (ppm) of NO». The major
advantage of this format is its simplicity
of enforcement. As compared to the
formats discussed previously, only a
minimum of data and calculations are
required, which decreases testing costs
and minimizes errors in determining
compliance with an emission standard
since measurements are direct.
The primary disadvantages associated
with concentration standards are: (1) A
standard could be circumvented by
dilution of exhaust gases discharged
into the atmosphere, which lowers the
concentration of pollutant emissions but
does not reduce the total pollutant mass
emitted; and (2) a concentration :
standard could penalize high efficiency
engines. Both these problems, however,
can be overcome through the use of
appropriate "correction" factors.
Since the percent reduction format is
impractical, and the problems
associated with the enforcement of mass
standards (mass-per-unit energy output)
appear to outweigh the benefits, the
concentration format was selected for
standards of performance for large
stationary 1C engines.
As mentioned above, because a
concentration standard can be
circumvented by dilution of the exhaust
gases, measured concentrations must be
expressed relative to some fixed dilution
level. For combustion processes, this
can be accomplished by correcting
measured concentrations to a reference
concentration of O2. The Oj
concentration in the exhaust gases is
related to the excess (or dilution) air.
Typical Oj concentrations in large-bore
1C engines can range from 8 to 16
percent but are normally about 15
percent. Thus, referencing the standard
to a typical level of 15 percent O2 would
prevent circumvention by dilution.
As also mentioned above, selection of
a concentration format could penalize
high efficiency 1C engines. These highly
efficient engines generally operate at
higher temperature and pressures and,
as a result, discharge gases with higher
NO, concentrations than less efficient
engines, although the brake-specific
mass emissions from both engines could
be the same. Thus, a concentration
standard based on low efficiency
engines could effectively require more
stringent controls for high efficiency
engines. Conversely, a concentration
standard based on high efficiency
engines could allow such high NOX
concentrations that less efficient engines
would require no controls.
Consequently, selecting a concentration
format for standards of performance
requires an efficiency adjustment factor
to permit higher NO, emissions from
more efficient engines.
The incentive for manufacturers to
increase engine efficiency is to lower
engine fuel consumption. Therefore, the
objective of an efficiency adjustment
factor should be to give an emissions
credit for the lower fuel consumption ol
more efficient 1C engines. Since the fuel
consumption of 1C engines varies
linearly with efficiency, a linear
adjustment factor is selected to permit
increased NO, emissions from highly
efficient 1C engines.
The efficiency adjustment factor
needs to be referenced to a baseline
efficiency. Most large existing stationary
1C engines fall in the range of 30 to 40
percent efficiency. Therefore, 35 percent
is selected as the baseline efficiency
The efficiency adjustment factor
included in the proposed standards
permits a linear increase in NO,
emissions for engine efficiencies above
35 percent. This adjustment would not
be used to adjust the emission limit
downward for 1C engines with
efficiencies of less than 35 percent. This
efficiency adjustment factor also applies
only to the 1C engine itself and not the
entire system of which the engine may
be a part. Since Section 111 of the Clean
Air Act requires the use of the besl
system of emission reduction in all
cases, this precludes the application of
the efficiency adjustment factor to an
entire system. For example, 1C engines
with waste heat recovery may have a
higher overall efficiency than the 1C
engine alone. Thus, the application of
the efficiency adjustment factor to the
entire system would permit greater NO,
emissions because of the system's
higher overall efficiency, and would not
necessarily require the use of the best
demonstrated system emission
reduction on the 1C engine.
V-FF-13
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Federal Register / Vol. 44, No. 142 / Monday. July 23. 1979 / Proposed Rules
Selection of Numerical Emission Limits
Overall approach.As mentioned
earlier it is difficult to select a specific
NO, emission limit which all 1C engines
could meet primarily through the use of
ignition retard or air-to-fuel ratio
change. Because of inherent differences
among various 1C engines with regard to
uncontrolled NO, emission levels, there
exists a rather large variation within the
data and information included in the
Standards Support and Environmental
Impact Statement concerning controlled
NO, emission levels. Generally
speaking, engines with relatively low
uncontrolled NO, emissions levels
achieved low controlled NO, emissions
levels and engines with high
uncontrolled NO, emissions levels
achieved relatively high controlled NO,
emissions levels. Consequently, the
following alternatives were considered
for selecting the numerical
concentration emission limits based on
a 40 percent reduction in NO, emissions:
1. Apply the 40 percent reduction to
the highest observed uncontrolled NO,
emission level.
2. Apply the 40 percent reduction to a
sales-weighted average uncontrolled
NO, emission level.
3 Apply the 40 percent reduction to
this sales-weighted average
uncontrolled NO, emission level plus
one standard deviation.
The highest observed uncontrolled
NO, emission levels for gas, dual-fuel
and diesel engines are as follows: (1)
Gas. 29 g/hp-hr |2| dual-fuel, 15 g/hp-hr,
and 131 diesel. 19 g/hp-hr.
Sales-weighted uncontrolled NO,
emission levels were determined by
applying a sales weighting to each
manufacturer s average uncontrolled
NO, emissions for engines of each fuel
type The sales weighting, based on
horsepower sold gives more weight to
those engine models which have the
highest sales The sales-weighted
average uncontrolled NO, emission
level for each engine fuel type are as
follow 111 Gas 15 g/hp-hr. (2) dual-fuel,
8 g/hp-hr and 131 diesel. 11 g/hp-hr.
The third alternative incorporates a
"margin for engine variability" by
adding one standard deviation to the
sales-weighted average uncontrolled
NO, emission level and then applying
the 40 percent reduction. Standard
deviations were calculated from the
uncontrolled NO, emission data
included in the Standards Support and
Environmental Impact Statement,
assuming the data had normal
distribution. A subsequent statistical
evaluation of the data indicated that this
assumption was valid: The standard
deviations -for each engine fuel type are
as follows: (1) Gas. 4 g/hp-hr. (2) dual-
fuel, 3.2 g/hp-hr. and (3) diesel, 3.7 g/hp-
hr.
The standard deviation of the
uncontrolled NO, emission data base is
relatively large compared to the sales-
weighted average uncontrolled NO,
emission level for each engine type. This
indicates that the distribution of
uncontrolled NO, emissions levels is
quite broad. In addition, the standard
deviation is of the same magnitude as
the 40 percent reduction in NO,
emissions that can be achieved. Thus.
regardless of which atlernative
approach is followed to select the
numerical NO, concentration emission
limit, a significant portion of the 1C
engine population may have to achieve
more or less than a 40 percent reduction
in NO, emissions to comply with the
standards.
It is important to note that the 40
percent reduction in NO, emissions is
based on the application of a single
control technique, such as ignition
retard, or air-to-fuel ratio change. Other
emission control techniques, however,
such as manifold air cooling and engine
derate, exist, although they are generally
not as effective in reducing NO,
emissions. Since emission control
techniques are additive to some extent.
it is possible in a number of cases to
reduce NO, emissions by greater than 40
percent.
The following factors were examined
for each engine type to choose the
alternative for selecting the numerical
NO, concentration emission limit: (1)
The percentage of engines that would
have to reduce NO, emissions by 40
percent or less to meet the standards; (2)
the percentage of engines that would be
required to do nothing to meet the
standards; and (3) the percentage of
engines that would be required to
reduce NO, emissions by more than 40
percent to meet the standards. The
normal distribution curve presented in
Figure I illustrates the trade-offs among
the three alternatives for selecting the
numerical NO, concentration emission
limit.
The first alternative is to apply the 40
percent reduction to the highest
uncontrolled NO, emission level within
a fuel category. For example, 29 g/hp-hr
is the highest uncontrolled NO, emission
level for gas engines. The application of
a 40 percent reduction would lead to an
emission level of about 17 g/hp-hr. As
illustrated in Figure I, if this level were
selected as a standard of performance,
99 percent of production gas engines
could easily meet the emission limit by
reducing emissions by 40 percent or less.
However. 69 percent of production
engines would not have to reduce NO,
emissions at all. Only one percent of
production engines would have to
reduce NO, emissions by more than 40
percent.
V-FF-14
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Federal Register / Vol. 44. No. 142 / Monday, July 23,1979 / Proposed Rules
ALTERNATIVE I
ALTERNATIVE II
7%
STD
i
»~i
ALTERNATIVE III
<-.
-^
18%
STD
1
84%'
^-
50%
.16%.
FIGURE 1. Statistical effects of alternative emission limits on gas engines.
V-FF-15
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Federal Register / Vol. 44. No. 142 / Monday. July 23, 1979 / Proposed Rules
The second alternative is.to apply 40
percent reduction to the sales-weighted
average uncontrolled NO, emission
level. For example, the sales-weighted
avergage uncontrolled NO, level for gas
engines is 15 g/hp-hr. The application of
a 40 percent reduction would lead to a
NO. emission level of 9 g/hp-hr. As
illustrated in Figure I, if this level were
selected as a standard of performance,
SO percent of production gas engines
could meet the standard with 40 percent
or less reduction in NO, emissions.
However, 50 percent of production gas
engines would be required to reduce
NO, emissions by greater than 40
percent. Only seven percent of
production gas engines would not have
to reduce NO. emissions at all.
The third alternative is to base the
standards on a 40 percent reduction in
NO, emissions from the sales-weighted
average uncontrolled NO, emission
level plus one standard deviation. For
example, the sales-weighted average
uncontrolled NO, emission level for gas
production gas engines is 15 g/hp-hr and
the standard deviation of the production
gas engine data base is 4 g/hp-hr. Thus,
the application of a 40 percent reduction
to the sum of these two values would
lead to an emission level of 11 g/hp-hr.
As illustrated in Figure I, if this level
were selected as a standard of
performance, 84 percent of the
production gas engines could easily
meet the emission limit by reducing
emissions by 40 percent or less.
However, IB percent of the production
gas engines would not have to reduce
NO, emission at all. Only'16 percent of
the production gas engines would have
to reduce NO, emissions by more than
40 percent.
This same analysis applied to dual-
fuel and diesel engines leads to the
results summarized in Table III. If
standards of performance were based
on Alternative I, essentially all engines
could achieve the emission limit by
reducing NO, emissions 40 percent or
less. A significant reduction in NO,
emissions would not be achieved,
however, since 50 to 70 percent of the 1C
engines would not have to reduce NO,
emissions at all. If the standards of
performance were based on Alternatve
II. about 50 percent of the 1C engines (in
all categories) would have to reduce
NO, emissions by greater than 40
percent. Less than 10 percent would not
have to reduce NO, emissions at all.
Thus this alternative would achieve a
significant reduction in NO, emissions
from new sources. If standards of
performance were based on Alternative
III. the results would be similar to those
achieved with Alternative I. About 85
percent of engines could easily meet the
standards by reducing NO, emissions by
less than 40 percent. About 20 to 30
percent of 1C engines would not have to
reduce NO. emissions at all, and about
15 percent of 1C engines would have to
reduce NO. emissions by more than 40
percent.
In light of the high priority which has
been given to standards directed toward
reducing NO, emissions and the
significance of 1C engines in terms of
their contribution to NO, emissions from
stationary sources, the second
alternative was chosen for selecting the
NO, emission concentration limit. This
approach will achieve the greatest
reduction in NO. emissions from new 1C
engines.
V-FF-16
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Federal Register / Vol. 44. No. 142 / Monday. July 23,1979 / Proposed Rules
TABLE III
SUMMARY Of STATISTICAL ANALYSES OF ALTERNATE EMISSION LIMITS
GAS ENGINES
Alternative
Standard
Percent required to apply
less than or equal to
40 percent control
Percent required to do
nothing
Percent required to apply
more than 40 percent con-
trol
I
17
99
69
1
II
9
50
7
50
III
11
84
18
16
DUAL-FUEL ENGINES
Alternative
Standard
Percent required to apply
less than or equal to
40 percent control
Percent required to do
nothing
Percent required to apply
acre than 40 percent con-
trol
I
9
98
62
2
II
5
54
18
4E
III
7
37
48
13
DIESEL ENGINES
Alternative
Standard
Percent required to apply
less than or equal to
40 percent control
Percent required to do
nothing
Percent required to apply
ore than 40 percent con-
I
11
98
50
2
trol j
II
7
56
4
44
III
9
86
29
14
V-FF-17
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Federal Register / Vol. 44. No. 142 / Monday, July 23. 1979 / Proposed Rules
Selection of limits.A concentration
(ppm) format was selected for the
standards. Consequently, the brake-
specific NO, emission limits
corresponding to the second alternative
for selecting numerical emission limits
(i.e., gas - 9 g/hp-hr; dual-fuel - 5 £/hp-
hn diesel - 7 g/hp-hr) must be converted
to concentration limits (corrected to 15
percent O. on a dry basis). This may be
done by dividing the brake-specific
volume of NO, emissions by the brake-
specific total exhaust gas volume.
Determining the brake-specific volume
of NO, emissions is straight-forward.
Determining the brake-specific total
exhaust gas volume is more complex, in
that the brake-specific exhaust flow and
the exhaust gas molecular weight are
unknown. Knowing the fuel heating
value and composition, the brake-
specific fuel consumption, and assuming
15 percent excess air, however, defines
these unknowns. (The complete
derivation is explained in detail in the
Standards Support and Environmental
Impact Statement.) Combining these
factors leads to the following conversion
factor:
/16.6 + 3.29
\12.0 + 2
x (BSFC)
where:
NO, = NO, concentration (ppm) corrected to
15 percent Oi.
BSNO, = Brake-specific NO, emissions, g/
hp-hr.
BSFC = Brake-specific fuel consumption, g/
hp-hr.
Z = Hydrogen/Carbon ratio of the fuel.
For natural gas, a hydrogen-to-carbon
(H/C) ratio of 3.5 and a lower heat value
(LHV) of 20,000 Btu/lb was assumed.
Diesel ASTM-2 has a H/C ratio of 1.8
and a LHV of 18,320 Btu/lb.
Applying this conversion factor to the
brake-specific emission limits
associated with the second alternative
for selecting NO, emissions limits leads
to the NO, concentration emission limits
included in the proposed standards:
Engme NOB emission Hmit
Gas _ 700 ppm.
Duat-Hiel/Dtesel 600 ppm.
These emission limits have been
rounded upward to the nearest 100 ppm
to include a "margin" to allow for source
variability. The standard for diesel
engines has also been applied to dual-
fuel engines. If a separate emission limit
has been selected for dual-fuel engines,
the corresponding numerical NO,
concentration emission limit would be
400 ppm. Sales of dual-fuel engines,
however, have ranged from 17 to 95
units annually over the past five years,
with a general trend of decreasing sales.
Dual-fuel engines serve the same
applications as diesel engines, and new
dual-fuel engines will likely operate
primarily as diesel engines because of
increasingly limited natural gas
supplies. Thus, the combining of dual-
fuel engines with diesel engines for
standards of performance will have little
adverse impact and will simplify
enforcement of the standards of
performance.
The effect of ambient atmospheric
conditions on NO, emissions from large
stationary 1C engines can be significant.
Therefore, to enforce the standards
uniformly, NO, emissions must be
determined relative to a reference set of
ambient conditions. All existing ambient
correction factors were reviewed that
could potentially be applied to large
stationary 1C engines to correct NO,
emissions to standard conditions.
The correction factors that were
selected for both spark ignition (SI) and
compression ignition (CI) engines are
included in the proposed standards. For
the compression ignition engines (i.e.,
diesel and dual-fuel), a single correction
factor for both temperature and
humididty was selected. For spark
ignition engines (i.e., gas), separate
correction factors were selected for
humidity and temperature, and
measured NO, emissions are corrected
to reference ambient conditions by
multiplying these two factors together.
No correction factor was selected for
changes in ambient pressure because no
generalized relationship could be
determined from the very limited data
that are available. These correction
factors represent the general effects of
ambient temperature and relative
humidity on NO, emissions, and will be
used to adjust measured NO, emissions
during any performance test to
determine compliance with the
numerical emission limit.
Since the recommended factors may
not be applicable to certain engine
models, as an alternative to the use of
these correction factors, engine
manufacturers, owners, or operators
may elect to develop their own ambient
correction factors. All such correction
factors, however, must be substantiated
with data and then approved by EPA for
use in determining compliance with NO,
emission limits. The ambient correction
factor will be applied to all performance
tests, not only those in which the use of
such factors would reduce measured
emission levels.
As discussed in "Standards Support
and Environmental Impact Statement:
Proposed Standards of Performance for
Stationary Gas Turbines," EPA-450/2-
77-017a, the contribution to NO,
emissions by the conversion of fuel-
bound nitrogen in heavy fuel to NO, can
be significant for stationary gas
turbines. The organic NO, contribution
to total gas turbine NO, emissions is
complicated by the fact that the
percentage of fuel-bound nitrogen
converted to NO, decreases as the fuel-
bound nitrogen level increases. Below a
fuel-bound nitrogen level of about 0.05
percent, essentially 100 percent of the
fuel-bound nitrogen is converted to NO,
Above a fuel-bound nitrogen level of
about 0.4 percent, only about 40 percent
is converted to NO,.
As discussed in the Standards
Support and Environmental Impact
Statement, Volume I for Stationary Gas
Turbines, assuming a fuel with 0.25
percent weight fuel-bound nitrogen
(which allows approximately 50 percent
availablility of domestic heavy fuel oil),
controlled NO, emissions would
increase by about 50 ppm due to the
contribution to NO, emissions of fuel-
bound nitrogen. In gas turbines, this
contribution was significant when
compared to the proposed emission limit
of 75 ppm. However, for large 1C
engines, the contribution of fuel-bound
nitrogen to NO, emissions is likely to be
small (approximately 10 percent). Sales
of 1C engines firing heavy fuels is
insignificant and not expected to
increase in the near future. Given that
the emission limits have been rounded
upward to the nearest 100 ppm and the
potential contribution of fuel-bound
nitrogen to NO, emissions is very small,
no allowance has been included for the
fuel-bound nitrogen content of the fuel
in determining compliance with the
standards of performance.
Selection of Compliance Time Frame
Manufacturers of large-bore 1C
engines are generally committed to a
particular design approach and,
therefore, conduct extensive research,
development, and prototype testing
before releasing a new engine model for
sale. Consequently, these manufacturers
will require some period of time to alter
or reoptimize and test 1C engines to
meet standards of performance. The
estimated time span between the
decision by a manufacturer to control
NO, emissions from an engine model
and start of production of the first
controlled engine is about 15 months for
any of the four demonstrated emission
control techniques. With their present
facilities, however, testing can typically
V-FF-18
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Federal Register / Vol. 44, No. 142 / Monday, July 23, 1979 / Proposed Rules
be conducted on only two to three
engine models at a time. Since most
manufacturers produce a number of
engine models, additional time is
required before standards of
performance become effective. In
addition, a number of manufacturers
produce their most popular engine
models at a fairly steady rate of
production and satisfy fluctuating
demands from inventory. Consequently,
additional time in necessary to allow
manufacturers to sell their current
inventory of uncontrolled 1C engines
before they must comply with standards
of performance.
It is estimated that about 30 months
delay in the applicability date of the
standard is appropriate to allow
manufacturers time to comply with the
proposed standards of performance. In
addition, in light of the stringency of the
standards (i.e., many engine models will
have to reduce NO, emissions by more
than 40 percent) this time period
provides the flexibility for
manufacturers to develop and use
combinations of the control techniques
upon which the standards are based or
other control techniques. Consequently,
30 months from today's date is selected
as the delay period for implementation
of these standards on large stationary 1C
engines.
Selection of Monitoring Requirements
To provide a means for enforcement
personnel to ensure that an emission
control system installed to comply with
standards of performance is properly
operated and maintained, monitoring
requirements are generally included in
standards of performance. For
stationary 1C engines, the most
straightforward means of ensuring
proper operation and maintenance
would be to monitor NO, emissions
released to the atmosphere.
Installed costs, however, for
continuous monitors are approximately
$25,000. Thus the cost of continuous NO,
emission monitoring is considered
unreasonable for 1C engines since most
large stationary 1C engines cost from
$50,000 to $3,000,000 (i.e., 1000 hp gas
production engine and 20,000 hp
electrical generation engine).
A more simple and less costly method
of monitoring is measuring various
engine operating parameters related to
NO, emissions. Consequently,
monitoring of exhaust gas temperature
was considered since this parameter
could be measured just after the
combustion process during which NO, is
formed. However, a thorough
investigation of this approach showed
no simple correlation between NO,
emission and exhaust gas temperature.
A qualitative estimate of NO,
emissions, however, can be developed
by measuring several engine operating
parameters simultaneously, such as
spark ignition or fuel injector timing,
engine speed, and a number of other
parameters. These parameters are
typically measured at most installations
and thus should not impose an
additional cost impact. For these
reasons, the emission monitoring
requirements included in the proposed
standards of performance require
monitoring various engine operating
parameters.
For diesel and dual-fuel engines, the
engine parameters to be monitored are:
(1) Intake manifold temperature; (2)
intake manifold pressure; (3) rack
position; (4) fuel injector timing; and (5)
engine speed. Gas engines would require
monitoring of (1) intake manifold
temperature; (2) intake manifold
pressure; (3) fuel header pressure; (4)
spark timing; and (5) engine speed.
Another parameter that could be
monitored for gas engines is the fuel
heat value, since it can affect NO,
emissions significantly. Because of the
high costs of a fuel heating value
monitor, and the fact that many facilities
can obtain the lower heating value
directly from the gas supplier,
monitoring of this parameter would not
be required.
The operating ranges for each
parameter over which the engine could
operate and in which the engine could
comply with the NO, emission limit
would be determined during the
performance test. Once established,
these parameters would be monitored to
ensure proper operation and
maintenance of the emission control
techniques employed to comply with the
standards of performance.
For facilities having an operator
present every day these operating
parameters would be recorded daily. For
remote facilities, where an operator is
not present every day, these operating
parameters would be recorded weekly.
The owner/operator would record the
parameters and, if these parameters
include values outside the operating
ranges determined during the
performance test, a report would be
submitted to the Administrator on a
quarterly basis identifying these periods
as excess emissions. Each excess
emission report would include the
operating ranges for each parameter as
determined during the performance test,
the monitored values for each
parameter, and the ambient air
conditions.
Selection of Performance Test Method
A performance test method is required
to determine whether an engine
complies with the standards of
performance. Reference Method 20,
"Determination of Nitrogen Oxides,
Sulfur Dioxide, and Oxygen emissions
from Stationary Gas Turbines," which
was proposed in the October 3,1977
Federal Register, is proposed as the
performance test method for 1C engines.
Reference Method 20 has been shown to
provide valid results. Consequently,
rather than developing a totally new
reference test method, Reference
Method 20 would be modified for use on
1C engines.
The changes and additions to
Reference Method 20 required to make it
applicable for testing of internal
combustion engines include (by section):
1. Principle and Applicability. Sulfur
dioxide measurements are not
applicable for internal combustion
engine testing.
6.1 Selection of a sampling site and
the minimum number of traverse points.
6.11 Select a sampling site located at
least five stack diameters downstream
of any turbocharger exhaust, crossover
junction, or recirculation take-offs and
upstream of an dilution air inlet. Locate
the sample site no closer than one meter
or three stack diameters (whichever is
less) upstream of the gas discharge to
the atmosphere.
6.1.2 A preliminary Oi traverse is not
necessary.
6.1.2.2 Cross-sectional layout and
location of traverse points use a
minimum of three sample points located
at positions of 16.7, 50 and 83.3 percent
of the stack diameter.
6.2.1 Record the data required on the
engine operation record on Figure 20.7 of
Reference Method 20. In addition, record
(a) the intake manifold pressure; (b) the
intake manifold temperature; (c) rack
position; (d) engine speed; and (e)
injector or spark fuming. (The water or
steam injection rate is not applicable to
internal combustion engines.)
NO, emissions measured by
Reference Method 20 will be affected by
ambient atmospheric conditions.
Consequently, measured NO, emissions
would be adjusted during any
performance test by the ambient
condition correction factors discussed
earlier, or by custom correction factors
approved for use by EPA.
The performance test may be
performed either by the manufacturer or
at the actual user operating site. If the
test is performed at the manufacturer's
facility, compliance with that
performance test will be sufficient proof
V-FF-19
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Federal Register / Vol. 44, No. 142 / Monday, July 23, 1979 / Proposed Rules
of compliance by the user as long as the
engine operating parameters are not
varied during user operation from the
settings under which testing was done.
Public Hearing
A public hearing will be held to
discuss these proposed standards in
accordance with section 307(d)(5) of the
Clean Air Act. Persons wishing to make
oral presentations should contact EPA
at the address given in the ADDRESSES
Section of this preamble. Oral
presentations will be limited to 15
minutes each. Any member of the public
may file a written statement with EPA
before, during, or within 30 days after
the hearing. Written statement should
be addressed to Mr. Jack R. Fanner (see
ADDRESSES Section).
The docket is an organized and
complete file of all the information
considered by EPA in the development
of this rulemaking. The principal
purposes of the docket are (1) to allow
interested parties to identify and locate
documents so that they can intelligently
and effectively participate in the
rulemaking process, and (2) to serve as
the record for judicial review. The
docket requirement is discussed in
ection 307(d) of the Clean Air Act.
Miscellaneous
As prescribed by Section 111 of the
Act, this proposal is accompanied by the
Administrator's determination that
emissions from stationary 1C engines
contribute to air pollution which causes
or contributes to the endangerment of
public health or welfare, and by
publication of this determination in this
issue of the Federal Register. In
accordance with section 117 of the Act,
publication of these standards was
preceded by consultation with
appropriate advisory committees,
independent experts, and federal
department and agencies. The
Administrator welcomes comments on
all aspects of the proposed regulations,
including the designation of stationary
1C engines as a significant contributor to
air pollution which causes or contributes
to the endangerment of public health or
welfare, economic and technological
issues, monitoring requirements and the
proposed test method.
Comments are specifically invited on
the severity of the economic and
environmental impact of the proposed
standards on stationary naturally
aspirated carbureted-gas 1C engines
since some parties have expressed
objection to applying the proposed
standards to these engines. Comments
are also invited on the selection of
rotary engines for control by standards
of performance. These engines were
included because they are expected to
be contributors to NO, emissions from
stationary sources and can be controlled
by demonstrated NO, emission control
techniques. Any comments submitted to
the Administrator on these issues,
however, should contain specific
information and data pertinent to an
evaluation of the magnitude of this
impact, its severity, and its
consequences.
It should be noted that standards of
performance for new sources
established under section 111 of the
Clean Air Act reflect:
The degree of emission limitation and the
percentage reduction achievable through
application of the best technological system
of continuous emission reduction which
(taking into consideration the cost of
achieving such emission reduction, any
nonair quality health and environmental
impact and energy requirements) the
Administrator determines has been
adequately demonstrated [section lll(a)(l)).
Although there may be emission
control technology available that can
reduce emissions below those levels
required to comply with standards of
performance, this technology might not
be seclected as the basis of standards of
performance because of costs
associated with its use. Accordingly,
standards of performance should not be
viewed as the ultimate in achievable
emission control. In fact, the Act may
require the imposition of a more
stringent emission standard emission in
several situations.
For example, applicable costs do not
necessarily play as prominent a role in
determining the "lowest achievable
emission rate" for new or modified
sources located in nonattainment areas
(i.e., those areas where statutorily
mandated health and welfare standards
are being violated). In this respect,
section 173 of the Act requires'that new
or modified sources constructed In an
area which exceeds the National
Ambient Air Quality Standard (NAAQS)
must reduce emissions to the level
which reflects the "lowest achievable
emission rate" (LAER), as defined in
section 171(3). The statute defines LAER
as that rate of emissions which reflects:
(A) The most stringent emission limitation
which is contained in the implementation
plan of any state for such class or category of
source, unless the owner or operator of the
proposed source demonstrates that such
limitations are not achievable or
(B) The most stringent emission limitation
which is acheved in practice by such class or
category of source, whichever is more
stringent.
In no event can the emission rate exceed
any applicable new source performance
standard.
A similar situation may arise under
the prevention-of-significant-
deterioration-of-air-quality provisions of
the Act. These provisions require that
certain sources employ "best available
control technology" (BACT) as defined
in section 169(3) for all pollutants
regulated under the Act. Best available
control technology must be determined
on a case-by-case basis, taking energy.
environmental and economic impacts,
and other costs into account. In no event
may the application of BACT result in
emissions of any pollutants which will
exceed the emissions allowed by any
applicable standard established
pursuant to section 111 (or 112) of the
Act.
In all cases, State Implementation
Plans (SIP's) approved or promulgated
under section 110 of the Act must
provide for the attainment and
maintenance of NAAQS designed to
protect public health and welfare. For
this purpose, SIP's must in some cases
require greater emission reduction than
those required by standards of
performance for new sources.
Finally, states are free under section
116 of the Act to establish even more
stringent emission limits than those
established under section 111 or those
necessary to attain or maintain the
NAAQS under section 110. Accordingly
new sources may in some cases be
subject to limitations more stringent
than standards of performance under
section ill, and prospective owners and
operators of new sources should be
aware of this possibility in planning for
such facilities.
Under EPA's "new" sunset policy for
reporting requirements in regulations.
the reporting requirements in this
regulation will automatically expire five
years from the date of promulgation
unless EPA takes affirmative action to
extend them.
EPA will review this regulation four
years from the date of promulgation
This review will include an assessment
of such factors as the need for
integration with other programs, the
existence of alternative methods,
enforceability, and improvements in
emissions control technology.
An economic impact assessment has
been prepared as required under section
317 of the Act and is included in the
Standards Support and Environmental
Impact Statement.
V-FF-20
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Federal Register / Vol. 44, No. 142 / Monday. ]uly 23. 1979 / Proposed Rules
Dated: July 11.1979.
Douglas M. Costle.
Administrator.
It is proposed to amend Part 60 of
Chapter I, Title 40 of the Code of Federal
Regulations as follows:
1. By adding Subpart FF as follows:
Subpart FFStandards of Performance for
Stationary Internal Combustion Engine*
Sec.
60.320 Applicability and designation of
affected facility.
60.321 Definitions.
60.322 Standards for nitrogen oxides.
60.323 Monitoring of operations.
60.324 Test methods and procedures.
Authority: Sees. Ill and 301(a) of the Clean
Air Act, as amended, (42 U.S.C. 1857c-7,
1857g(a)), and additional authority as noted
below.
Subpart FFStandards of
Performance for Stationary Internal
Combustion Engines
$60.320 Applicability am) designation of
affected facility.
The provisions of this subpart are
applicable to the following affected
facilities which commence construction
beginning 30 months from today's date:
(a) All gas engines that are either
greater than 350 cubic inch displacement
per cylinder or equal to o,r greater than 8
cylinders and greater than 240 cubic
inch displacement per cylinder.
(b) All diesel or dual-fuel engines that
are greater than 560 cubic inch
displacement per cylinder.
(c) All rotary engines that are greater
than 1500 cubic inch displacement per
rotor.
$ 60.321 Definitions.
As used in this subpart, all terms not
defined herein shall have the meaning
given them in the Act or in subpart A of
this part.
(a) "Stationary internal combustion
engine" means any internal combution
engine, except gas turbines, that is not
self propelled. It may, however, be
mounted on a vehicle for portability.
(b) "Emergency standby engine"
means any stationary internal
combustion engine which operates as a
mechanical or electrical power source
only when the primary power source for
a facility has been rendered inoperable
during an emergency situation.
(c) "Reference ambient conditions"
means standard air temperature (29.4°C,
or 85°F), humidity (17 grams H,O/kg dry
air, or 75 grains H»O/lb dry air), and
pressure (101.3 kilopascals, or 29.92 in.
Hg.).
(d) "Peak load" means operation at
100 percent of the manufacturer's design
capacity.
(e) "Diesel engine" means any
stationary internal combustion engine
burning a liquid fuel.
(f) "Gas enine" means any stationary
internal combustion engine burning a
gaseous fuel.
(g) "Dual-fuel engine" means any
stationary internal combustion engine
that is burning liquid and gaseous fuel
simultaneously.
(h) "Unmanned engine" means any
stationary internal combustion engine
installed and operating at a location
which does not have an operator
regularly present at the site for some
portion of a 24-hour day.
(i) "Non-remote operation" means any
engine installed and operating at a
loction which has an operator regularly
present at the site for some portion of a
24-hour day.
(j) "Brake-specific fuel consumption"
means fuel input heat rate, based on the
lower heating value of the fuel,
expressed on the basis of power output
(i.e., (kj/w-hr).
(k) "Weekly basis" means at seven
day intervals.
(1) "Daily basis" meahs at 24 hours
intervals.
(m) "Rotary engine" means any
Wankel type engine where energy from
the combustion of fuel is converted
directly to rotary motions instead of
reciprocating motion,
(n) "Displacement per rotor" means
the volume contained in the chamber of
a rotary engine between one flank of the
rotor and the housing at the instant the
inlet port is closed.
§ 60.322 Standards for nitrogen oxides.
(a) On and after the date on which the
performance test required to be
conducted by § 60.8 is completed, no
owner or operator subject to the
provisions of this subpart shall cause to
be discharged into the atmosphere,
except as provided in paragraphs (b)
and (c) of this section
(1) From any gas engine, with a brake-
specific fuel consumption at peak load
more than or equal to 10.2 kilojoules/
watt-hour any gases which contain
nitrogen oxides in excess of 700 parts
per million volume, corrected to 15
percent oxygen on a dry basis.
(2) From any diesel or dual-fuel engine
with a brake-specific fuel consumption
at peak load more than or equal to 10.2
kilojoules/watt-hour any gases which
contain nitrogen oxides in excess of 600
parts per million volume, corrected to 15
percent oxygen on a dry basis.
(3) From any stationary internal
combustion engine with a brake-specific
fuel consumption at peak load of less
than or equal to 10.2 kilojoules/watt-
hour any gases which contain nitrogen
oxides in excess of:
(i) STO = 700 Y- for any gas engine,
(11) STO = 600 i^2 for any diesel or
dual-fuel engine
where:
STD = allowable NO, emissions (parts-per-
million volume corrected to 15 percent
oxygen on a dry basis).
Y = manufacturer's,rated brake-specific fuel
consumption at peak load (kilojoules per
watt-hour) or owner/operator's brake-
specific fuel consumption at peak load a«
determined in the field.
{b) All one and two cylinder
reciprocating gas engines are exempt
from paragraph (a) of this section.
(c) Emergency standby engines are
exempt from paragraph (a) of this
section.
$60.323 Monitoring of operations.
(a) The owner or operator of any
stationary internal combustion engine,
subject to the provisions of this subpart
must, on a weekly basis for unmanned
engines and on a daily basis for manned
engines, monitor and record the
following parameters. All monitoring
systems shall be accurate to within five
percent and shall be approved by the
Administrator.
(1) For diesel and dual-fuel engines:
(i) Intake manifold temperature
(ii) Intake manifold pressure
(iii) Engine speed
(iv) Diesel rack position (fuel flow)
(v) Injector timing
(2) For gas engines:
(i) Intake manifold temperature
(ii) Intake manifold pressure
(iii) Fuel header pressure
(iv) Engine speed
(v) Spark ignition timing
(b) For the purpose of reports required
under § 60.7(c), periods of excess
emissions that shall be reported are
defined as any daily (for manned
engines) or weekly (for unmanned
engines) period during which any one of
the parameters specified under
paragraph (a) of this section falls
outside the range identified for that
parameter udner § 60.324(a)(3). Each
excess emission report shall include the
range identified for each operating
parameter under § 60.324(a)(4), the
monitored value for each operating
parameter specified under § 60.323(a),
V-FF-21
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Federal Register / Vol. 44, No. 142 / Monday, July 23, 1979 / Proposed Rules
the ambient air conditions during the
period of excess emissions, and any
graphs and/or figures developed under
i 60.324{a)(4)
(Sec. 114 of the Clean Air Act. as amended
(42 U.S.C. 1857C-S))
} 60.324 Test methods and procedures.
The reference methods in Appendix A
to this part, except as provided in
{ 60.8(b), shall be used to determine
compliance with the standards
prescribed in $ 60.322 as follows:
(a) Reference Method 20 for the
concentration of nitrogen oxides and
oxygen. The span for the nitrogen oxides
analyzer used in this method shall be
1500 ppm.
(1) The following changes and
additions [by section] to Reference
Method procedures should be followed
when determining compliance with
$ 60.322:
1. Principle and Applicability. Sulfur
dioxide measurements are not
applicable for internal combustion
engine testing.
6.1 Selection of a sampling site and the
minimum number of traverse points.
6.11 Select a sampling site located at least
five stack diameters downstream of any
turbocharger exhaust, crossover junction, or
recirculation take-offs and upstream of any
dilution air inlet Locate the sample site no
closer than one meter or three stack
diameters (whichever is leas) upstream of the
gas discharge to the atmosphere.
6.1.2 a preliminary Ot traverse is not
necessary.
6.2 Cross-sectional layout and location of
traverse points. Use a minimum of three
sample points located at positions of 16.7,50
and 83.3 percent of the stack diameter.
6.2.1 Record the data required on the
engine operation record on Figure 20.7 of
Reference Method 20. In addition, record (a)
the intake manifold pressure; (b) the intake
manifold temperature; (c) rack position, fuel
header pressure or carburetor position; (d)
engine speed; and (e) injector or spark timing.
(The water or steam injection rate is not
applicable to internal combustion engines.)
(2) The nitrogen oxides emission level
measured by Reference Method 20 shall
be adjusted to reference ambient
conditions by the following ambient
condition correction factors:
NO, corrected = (K) NO. observed
where K is determined as follows:
Fuel
Diesel and
Dual-Fuel
Gas
Correction Factor
K = 1/{1 * 0.00235(H - 75) + 0.00220 (T - 85))
K =
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Federal Register / Vol. 44, No. 142 / Monday, July 23,1979 / Notices
[FRL 1099-6]
Air Pollution Prevention and Control;
Addition to the List of Categories of
Stationary Sources
Section 111 of the Clean Air Act (42
U.S.C. 1857c-6) directs the
Administrator of the Environmental
Protection Agency to publish, and from
time to time revise, a list of categories of
stationary sources which he determines
may contribute significantly to air
pollution which causes or contributes to
the endangerment of public health or
welfare. Within 120 days after the
inclusion of a category of stationary
sources in such list, the Administrator is
required to propose regulations
establishing standards of performance
for new and modified sources within
such category. At present standards of
performance for 27 categories of sources
have been promulgated.
The Administrator, after evaluating
available information, has determined
that stationary internal combustion
engines are an additional category of
stationary sources which meets the
above requirements. The basis for this
determination is discussed in the
preamble to the proposed regulation that
is published elsewhere in this issue of
the Federal Register. Evaluation of other
stationary source categories is in
progress, and the list will be revised
from time to time as the Administrator
deems appropriate. Stationary internal
combustion engines are included on the
proposed NSPS priority list (published
August 31, 1978) required by section
I1l(f)(l), but since the priority list is not
final, stationary internal combustion
engines are also being listed as
indicated below at this time. Once the
priority list is promulgated, all source
categories on the promulgaled list are
considered listed under section
lll(hj(l)(A), and separate listings such
HS this will not be made for those source
categories
Accordingly, notice is given that the
Administrator, pursuant to section
lll(b)(l)(A) of the Act. and after
consultation with appropriate advisory
committees, experts and Federal
departments and agencies in accordance
with section 117(0 of the Act. effective
July 23, 1979 amends the list of
categories of stationary sources to read
as follows:
List of Categories of Stationary Sources
and Corresponding Affected Facilities
Source Category
*~ * * * *
Affected Facilities
Internal combustion engines
Proposed standards of performance
applicable to the above source category
appear elsewhere in this issue of the
Federal Register.
Dated: July 11.1979.
Douglas M. Costle,
Administrator./
(FR Doc 7S-Z2225 Filed 7-20-79. 8 45 am|
Federal Register / Vol. 44, No. 182 / Tuesday, September 18, 1979
[40 CFR Part 60]
[FRL 1321-5]
Standards of Performance for New
Stationary Sources; Stationary Internal
Combustion Engines
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Extension of Comment Period.
SUMMARY: The deadline for submittal of
comments on the proposed standards of
performance for stationary internal
combustion engines, which were
proposed on July 23,1979 (44 FR 43152),
is being extended from September 21,
1979, to October 22,1979.
DATES: Comments must be received on
or before October 22,1979.
ADDRESSES: Comments should be
submitted to Mr. David R. Patrick, Chief,
Standards Development Branch (MD-
13), Emission Standards and Engineering
Division, Environmental Protection
Agency, Research Triangle Park, North
Carolina 27711.
FOR FURTHER INFORMATION CONTACT:
Mr. Don R. Goodwin, Director, Emission
Standards and Engineering Division
(MD-13), Environmental Protection
Agency, Research Triangle Park, North
Carolina 27711, telephone number (919)
541-5271.
SUPPLEMENTARY INFORMATION: On July
23, 1979 (44 FR 43152), the
Environmental Protection Agency
proposed standards of performance for
the control of emissions from stationary
internal combustion engines. The notice
of proposal requested public comments
on the standards by September 21,1978.
Due to a delay in the shipping of the
Standards Support Document, sufficient
copies of the document have not been
available to all interested parties in time
to allow their meaningful review and
comment by September 21,1979. EPA
has received a request from the industry
to extend the comment period by 30
days through October 22,1979. An
extension of this length is justified since
the shipping delay has resulted in
approximately a three-week delay in
processing requests for the document.
Additionally, page 9-75 of the
Standards Support Document was
inadvertently omitted. Persons wishing
to obtain copies of this page should
contact Mr. Doug Bell, Emission
Standards and Engineering Division,
Research Triangle Park, North Carolina
27711, telephone number (919) 541-5477.
Dated: September 12,1979.
David G. Hawkins,
Assistant Administrator for Air, Noise, and
Radiation.
[FR Doc. Tt-Oea Filed «-17-7ft 6.45 imj
V-FF-23
-------
ENVIRONMENTAL
PROTECTION
AGENCY
STANDARDS OF
PERFORMANCE FOR
NEW STATIONARY
SOURCES
SECONDARY LEAD SMELTERS
SUBPART L
-------
Federal Register / Vol. 45. No. 76 / Thursday. April 17. 1980 / Proposed Rules
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Part 60
[FRL 1415-3]
Standards of Performance for New
Stationary Sources: Secondary Lead
Smelters; Review of Standards
AGENCY: Environmental Protection
Agency.
ACTION: Review of standards.
SUMMARY: EPA has reviewed the
standards of performance for secondary
lead smelters (40 CFR 60.120). The
review is required under the Clean Air
Act, as amended August 1977. The
purpose of this notice is to announce
EPA's plans to undertake a program
which will be designed, depending upon
its findings, to develop fugitive
particulate matter emission standards
and SO, standards applicable to
secondary lead smelters.
DATE: Comments must be received by
June 16,1980.
ADDRESS: Comments should be
submitted to the Central Docket Section
(A-130), U.S. Environmental Protection
Agency, 401 M Street, S.W.,
Washington, D.C. 20460, Attention:
Docket No. A-79-20.
FOR FURTHER INFORMATION CONTACT:
Mr. Robert Ajax, telephone: (919) 541-
5271. The document "A Review of
Standards of Performance for New
Stationary SourcesSecondary Lead
Smelters," EPA-450/3-79-015, is
available upon request from Mr. Robert
Ajax (MD-13), Emission Standards and
Engineering Division, Environmental
Protection Agency, Research Triangle
Park, North Carolina 27711.
SUPPLEMENTARY INFORMATION:
Introduction
On June 11,1973, the Environmental
Protection Agency proposed a standard
under Section 111 of the Clean Air Act
to control particulate matter emissions
from secondary lead smelters. The
standard, promulgated on March 8,1974,
and amended on April 17 and October 6,
1975, applies to any secondary lead
smelter under construction,
modification, or reconstruction on or
after June 11,1973. The specific lead
smelter facilities subject to the standard
are reverberatory furnaces (stationary,
rotating, rocking, or tilting), blast
(cupola) furnaces and pot furnaces of
more than 550-lb charging capacity.
Furnaces for smelting lead alloy for
newspaper linotype are subject to the
standards if they meet the same size
requirement as applied to pot furnaces.
The Clean Air Act Amendments of
1977 require that the Administrator of
EPA review and, if appropriate, revise
established standards of performance
for new stationary sources at least every
4 years (Section lll(b)(l)(B)). Following
the adoption of the amendments, EPA
contracted with the MITRE Corporation
to undertake a survey of available
literature and information pertaining to
secondary lead processes, emissions
and control technologies, including
results from tests of new lead smelters
to assess the need for revision of the
standard. The survey involved visits to
each EPA Regional Office as well as
review of recent literature and study
results, but did not include visits to
plants. Based principally on this review,
EPA plans to begin a program to
develop standards which would limit
the emission of fugitive particulate
matter, and sulfur dioxide from
secondary lead smelters. This program
will include an extensive technical
investigation and assessment. Final
decisions pertaining to whether
standards should be adopted and the
level of any such standards will not be
made until after these investigations and
assessments are completed. The time
required to develop these standards for
proposal will be approximately 2 years.
Industry Review
Secondary lead produced by smelting
of scrap accounts for roughly half of all
lead produced in the United States.
After a record output of over 626,000
tons in 1976, secondary lead output
declined in 1977 to between 588,000 and
600,000 tons. However, production of
lead from both primary and secondary
sources is expected to grow at an annual
rate of slightly under 2 percent or by
about 50 percent between 1976 and 2000.
This compares with an average annual
increase in demand for lead from 1967 to
1976 of about 3 percent. It is expected
that the relative share of the market
held by secondary lead production will
remain near the 50 percent level.
It is estimated, based on an assumed
secondary smelter capacity of 50 ton/
day, that on the average, two new plants
and one to two modified smelters will
become subject to NSPS each year. This
estimate is consistent with the latest
Bureau of Mines data (1978) which show
six plants completed or scheduled for
completion in the 1977-1979 period
(including major expansions of existing
plants). Through 1978, six plants have
been identified which have come on line
subject to the standard.
The secondary lead market is
dominated by a few companies. In
addition, the trend is toward fewer and
larger plants as evidenced by the
decrease in the total number of smelters
from 160 in 1967 to about 115 in 1975.
Overall, the average annual output per
smelter is in the range of 5,700 to 6,000
tons. Geographically, the industry is
somewhat dispersed with secondary
lead smelters located in all of the ten
EPA regions.
Emissions and Control Technology
Process Particulate Emissions. The
present standard of performance limits
the emission of particulate matter from
blast or reverberatory furnaces to 50
mg/dscm (0.022 gr/dscf) and to less than
20 percent opacity. In addition, the
standard limits the opacity of emissions
from pot furnaces to less than 10 percent
opacity. For a typical reverberatory or
blast furnace with uncontolled
emissions of 147 Ibs/ton and 193 Ibs/ton
of feed material respectively, the
standard limits emissions to one and 2
Ibs/ton. This compares to an estimated
controlled emission level of 21 and 28
Ibs/ton in the absence of the new source
standard. In this review, results from
four compliance tests were obtained.
The results from reverberatory and blast
furnace tests were 0.015 gr/dscf and
0.0135 gr/dscf respectively.
Lead Emissions. The present standard
of performance does not specifically
limit the atmospheric emission of lead
from secondary lead furnaces. However,
lead is controlled by the same devices
employed to limit particulate matter
emissions. Reported lead emission data,
although variable, indicate uncontrolled
lead emissions to be approximately 23
percent of the total particulate matter
emissions. Controlled lead emissions
measured in six tests conducted on
emissions from seven furnaces were
found to range in concentration from
0.009 to 0.0846 Ib/ton with five of the six
below 0.04 Ib/ton. In another survey of
11 controlled secondary lead smelters in
the Chicago area, an emission rate of
0.002 Ibs lead/ton of product was
reported. Results of a further test at a
baghouse controlled reverberatory
furnace indicated particulate matter and
lead concentrations of 0.016 and 0.001
gr/dscf, respectively. The variability in
these data and the lack of other
simultaneous inlet and outlet data do
not allow a precise statement of relative
control effectiveness. However, the data
do consistently indicate that the ratio of
lead to particulate emissions from
controlled furnaces is not higher than
the ratio (i.e., 23 percent) for
uncontrolled furnaces.
Fugitive Emissions. In addition to the
material discharged through the stack of
a secondary lead furnace, particulate
V-L-2
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Federal Register / Vol. 45, No. 76 / Thursday, April 17,1980 / Proposed Rules
and gaseous matter may be emitted into
the atmosphere in and around a plant
from other operations. Some of these
fugitive emissions are process-related,
e.g., when materials escape from the
hoods provided around potential outlet
points of a furnace. Others result from
auxiliary operations. No fugitive
emission points, whether related to
processing or to auxiliary operations at
the site, are currently subject to specific
control under NSPS for secondary lead
smelters.
In some situations, fugitive emissions
may be high. For example, the high
concentration of lead, particularly in the
soil, close to two Toronto smelters was
ascribed by Canadian investigators to
"low-level, dust-producing operations
rather than * * * stack fumes." In
apparently extreme situations, fugitive
particulate emissions from processing
may amount to over 15 Ib/ton of charge
from reverberatory furnaces and as
much as 12 Ib/ton from blast furnaces.
These rates, although much lower than
uncontrolled emission rates from
furnace stacks, are substantially higher
than rates from stacks meeting the
NSPS.
Several techniques have been applied
to reduce fugitive emission rates and
recently significant improvements in the
technology for controlling fugitive
emissions from both process- and site-
related operations in secondary smelting
of lead have been reported in Denmark.
The methodology uses improved
furnaces that minimize the escape of
dusts during smelting and also enable
baghouse contents to be recharged as
collected, thereby eliminating the
accumulation of these fines in storage
piles where they are subject to transport
into the environment. Specialized waste
management and housekeeping
procedures are used in conjuction with
the furnaces to reduce the opportunity
for emissions from storage of raw
materials and other sources on the site.
The technology has been investigated by
the EPA Industrial Environmental
Research Laboratory in Cincinnati in
connection with the National Institute of
Occupational Safety and Health
(NIOSH). Testing of the furnaces has
been conducted under the joint auspices
of EPA and NIOSH at a plant in
Denmark. Initial reports indicate the
technology as having high potential for
application in reducing fugitive
emissions from secondary lead smelters
in the United States.
Sulfur Dioxide. The rate of
uncontrolled emissions of SO, from
secondary lead smelters is
approximately 76 Ib/ton of lead
produced for blast furnaces and of 114
Ib/ton for reverberatory furnaces. A
reverberatory furnace of 50 tons/day
(2.08 tons/hr) would emit about 2.8 tons
of SOj each day and a blast furnace of
the same capacity about 1.9 tons.
Assuming an equal mix between blast
and reverberatory furnace production,
the total secondary lead production in
1975 of 658,500 tons would have resulted
in about 31,000 tons of SOj. Currently,
no NSPS for SO» from secondary lead
smelters are in effect.
SO2 control is not normally practiced
at lead smelters. However, both
regenerative SOi control systems which
are used in the primary smelting
industry to control SOi and produce
sulfuric acid, and non-regenerative
scrubbing systems used to control SOj
emissions from steam generators are
potentially applicable to SO2 control at
secondary lead smelters. A more
detailed engineering assessment is
needed to further assess the
applicability of these technologies to
determine the best demonstrated control
technology and an appropriate level for
any standard. In addition, the cost of
SO2 control and the associated
economic impact require further study
as these may be the primary
consideration in analyzing the feasibility
of control.
Conclusions
EPA believes that the Information
obtained in this review of the secondary
lead industry does not provide a basis
for determining conclusively that the
standard should be revised nor at what
level any revised standard should be
set. However, the available data show
that a project should be undertaken to
further assess the need for and, as
appropriate to develop standards
limiting fugitive particulate matter
(including lead) and sulfur dioxide
emissions from secondary lead plants.
The available particulate matter
compliance test data obtained in this
review are consistent with the test data
used by EPA in establishing the present
standard and, although very limited,
these data, added to the data used in
developing the present standard support
the validity of the present standard.
Similarly, the data available on lead
emissions from furnace stacks suggest
that the particulate matter standard is
adequate to require installation of
control systems which represent best
available control technology for both
particulate matter and lead. Therefore, a
separate standard for lead is considered
unnecessary. EPA will welcome any
additional data pertaining to this
decision on the particulate matter
standard and on lead emissions. In
addition, EPA in the planned standards
development discussed below, will seek
to obtain additional recent compliance
test data and will assess this in terms of
the current standard.
The project to assess the need for and,
as appropriate, to develop fugitive'
particulate matter and sulfur dioxide
standards will be undertaken by EPA's
Emission Standards and Engineering
Division. This project is expected to
begin early in 1980 and will follow a
standardized approach which involves
detailed engineering and economic
assessments proceeding proposal of any
standards. Standards resulting from this
project would be proposed for comment
in early 1982.
Dated: April 9,1980.
Douglas M. Costie,
Administrator.
|FR Doc. 80-11666 Filed 4-16-60; 8.45 am)
BILLING CODE 6560-01-*!
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ENVIRONMENTAL
PROTECTION
AGENCY
STANDARDS OF
PERFORMANCE FOR
NEW STATIONARY
SOURCES
ELECTRIC ARC FURNACES
(STEEL INDUSTRY)
SUBPART AA
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Federal Register / Vol. 45, No. 78 / Monday, April 2J, 1980 / Proposed Rules
ENVIRONMENTAL PROTECTION.
AGENCY
40 CFR Part 60
[FRL 1415-2]
Review of Standards of Performance
for New Stationary Sources; Electric
Arc Furnaces (Steel Industry)
AGENCY: Environmental Protection
Agency.
ACTION: Proposed Rule.
SUMMARY: EPA has reviewed its
standards of performance for electric
arc furnaces in the steel industry (40
CFR 60.270, Subpart AA) as required
under the Clean Air Act, as amended
August 1977. EPA intends to explore
revising the standards to reflect
demonstrated best available control
technology for electric arc furnaces and
would add argon-oxygen
decarbonization (ADD) furnaces to the
standard. Visible emission limitations
would be reduced to be consistent with
improved control technology.
DATES: Comments must be received by
June 20,1980.
ADDRESSES: Send comments to: Central
Docket Section (A-130), U.S.
Environmental Protection Agency, 401 M
Street, S.W., Washington, D.C. 20460,
Attention: Docket A-79-33. Comments
should be submitted in duplicate if
possible.
FOR FURTHER INFORMATION CONTACT:
Mr. Stanley T. Cuffe, Telephone: (919)
541-5295. The document "A Review of
Standards of Performance for Electric
Arc Furnaces in the Steel Industry" is
available upon request from Mr. Stanley
T. Cuffe, (MD-13), Chief, Industrial
Studies Branch, Emission Standards and
Engineering Division, U.S.
Environmental Protection Agency,
Research Triangle Park, N.C. 27711.
SUPPLEMENTARY INFORMATION:
Background
On October 21,1974, EPA proposed a
standard under Section 111 of the Clean
Air Act to control particulate matter
emissions from electric arc furnaces
(EAF) in the steel industry. The
standard, promulgated on September 23,
1975, applies to any facility constructed
or modified after October 21,1974. The
standard for particulate matter under
§ 60.272 limits the discharge to
atmosphere from an electric arc furnace
of any gases that:
1. Contain particulate matter in excess
of 12 mg/dscm (0.0052 gr/dscf).
2. Exhibit 3 percent opacity or greater
from a control device.
3. Exhibit greater than zero opacity
from a shop, due solely to operation of
any EAF(sj, except:
a. Shop opacity greater than zero
percent, but less than 20 percent, may
occur during charging periods.
b. Shop opacity greater than zero
percent, but less than 40 p_ercent, may
occur during tapping periods.
c. Zero opacity from a shop shall
apply only during periods when process
flow rates and pressures are being
monitored.
d. Where the capture system is
operated such that the roof of the shop
is closed during the charge and the tap,
and emissions to the atmosphere are
prevented until the roof is opened after
completion of the charge or tap, the shop
opacity standards shall apply when the
roof is opened and shall continue to
apply for the length of time defined by
the charging and/or tapping periods.
The standard for particulate matter
also limits the discharge to atmosphere
from dust handling equipment any gases
which exhibit 10 percent opacity or
greater.
The Clean Air Act Amendments of
1977 that require the Administrator of
EPA review, establish standards of
performance for new stationary sources
(NSPS) at least every 4 years, and revise
them as appropriate [Section
lll(b)(l)(B)]. EPA has completed such a
review of the standard of performance
for electric arc furnaces in the steel
industry and has decided to begin a
project to revise the standard. EPA
invites comments on this decision and
on the findings on which it is based.
Findings
Industry Statistics
In 1972, there were approximately 299
EAF's in the United States. In 1977, there
were approximately 303 EAF's being
operated in the United States. However,
about 30 EAF's were being installed
between 1974 and 1979, which indicates
that some older furnaces were probably
shutdown and replaced. Only five of the
new furnaces were subject to the
standards.
Information on planned new facilities
or modifications is limited by the
reluctance of industry to state future
plans because of current economic
uncertainties. Nevertheless, EAF
production should continue to increase.
An EAF is flexible, can operate wholly
on steel scrap, is adapted to ultrarapid
melting, can make specialty steels, and
can be quickly brought on line or taken
off production. In addition, an EAF is
relatively low in pollution potential, and
emission controls are well
demonstrated. These EAF advantages
are substantiated by industry statistics
showing that production in 1977 was
about 25.4 Mg (27.9 million tons) and 29
Mg (31.9 million tons) in 1978 versus 21.5
Mg (23.7 million tons) in 1972, when the
NSPS document was being developed.
Emissions and Control Technology
The current best demonstrated control
technology, the fabric filter, is the same
as that used when the standards were
promulgated. No major improvements in
this technology have occurred during the
intervening period; however, one
company has installed a proprietary wet
scrubber, which appears to be almost as
effective as a fabric filter and meets the
standards.
Although the fabric filter technology
has not changed, the effectiveness of
pickup systems for various process and
fugitive emissions has improved
significantly.
Some EAF shops are now operating
with closed roofs and a controlled
fugitive emission pickup system in the
roof to draw any indoor emissions into
the control device. This system may
utilize small openings in the ductwork to
draw emissions slowly out of the roof
area, or it may include dampers in the
openings that can be opened or closed
to remove these rooftop emissions. The
roof emissions include charging and
tapping emissions, and those that
escape the direct furnace evacuation
system and the canopy hoods above the
furnace. The closed-roof and fugitive
emission pickup system was designed to
meet some local agencies no-visible-
emission requirements from an EAF
shop.
Other recent technology includes total
enclosure of the furnace within the EAF
building. The system is designed to
capture all emissions of the furnace
operation cycle (meltdown, charging,
tapping, and slagging). Hoods are
strategically located for capture of the
charging, tapping, and slagging
emissions. Additionally, during the
charging operation, a curtain of air is
blown across the roof opening to direct
the emissions into the intake duct of the
control device. This system theoretically
prevents almost all emissions from
escaping the enclosure and building.
Another new concept for containing
emissions from the EAF is a partial
enclosure around the furnace. The
furnace itself may be equipped with the
conventional direct shell evacuation and
canopy hood system, but the partial
enclosure around the furnace acts as a
stack to direct fugitive furnace
emissions upward into the emission
capture system. Separate hoods are
used to capture emissions during the
tapping and slagging operation. The EAF
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Federal Register / Vol. 45, No. 78 / Monday, April 21, 1980 / Proposed Rules
shop roof is closed and the area above
the furnace and below the canopy hood
must be kept clear so that the furnace
can be charged normally by a crane. The
partial enclosure is large enough to
allow the furnace cover to be swung
over the tapping area, where it can
capture emissions from the ladle pouring
spout and tapping hoods. This total
system is reported to be virtually 100
percent effective in capturing all
emissions from the furnace shop during
normal operations.
Although about 30 furnaces were
reported to have started operation from
1974 to 1979, only 5 commenced
construction after the proposal of NSPS
and therefore were subject to regulation.
Only one of these five furnaces has been
tested for visible emissions because the
others have not completed their startup.
Although the latter met the NSPS for
visible emissions, the furnace shop did
create an enforcement issue. The
furnace shop has a closed roof;
however, some visible emissions from
charging or tapping operations drifted
out the material access doors of the
shop when they were open. Also, these
charging and tapping emissions became
intermingled and were emitted
simultaneously due to other furnaces
operating in the shop. The enforcement
issue arose when it became unclear how
to enforce NSPS when charging, tapping,
and other shop emissions became mixed
and escaped from the doors instead of
the roof. These problems are expected to
be recurring, as other new furnaces start
operation and the NSPS may require
further study to clarify the visible
emission standard to cover this
situation.
Four other recently constructed EAF's
were required by local agencies to at
least meet NSPS even though their
construction started before NSPS
proposal. One shop with two partially-
enclosed furnaces using canopy hoods
and sealed roof was tested for
particulate and visible emissions. The
local agency concluded that the system
would meet NSPS based on their source
tests. However, the control system uses
a pressure baghouse, and the testing
was conducted by company personnel in
the presence of local agency observers.
In tests of various compartments of the
baghouse with a Hi-Vol sampler, the
results show that the emissions ranged
from 0.0097 mg/dscm (0.0000042 gr/dscf)
to 0.08 mg/dscm (0.0000346 gr/dscf)
during twelve 4- to 5-hour tests.
However, this is not an official EPA
testing method and further investigation
by EPA will be necessary to
substantiate this data.
The current standard does not cover
several types of electric furnaces. The
unregulated electric furnaces are:
vaccum-arc remelting (VAR), vacuum
induction melting (VIM), electro-slag
remelting (ESR), and consumable
electrode melting (GEM) which are
primarily used to produce small
tonnages of specialty steels.
Investigation by EPA during this review
revealed that the VAR, VIM, CEM. and
ESR furnaces do not produce any
significant emissions; therefore, they
should not be considered for NSPS.
Furthermore, these low polluting
specialty furnaces are not capable of
being replacements for the much larger
conventional electric arc furnace which
has a higher pollution potential.
Argon-oxygen decarbonization
furnaces were found to be a highly
significant emitter of particulate and
visible emissions, and these furnaces
are becoming an integral part of EAF
shops that produce stainless steels.
AOD furnaces are economical and
flexible to operate; therefore, their use is
expected to increase. Because AOD
furnaces operate within an EAF shop,
produce significant amounts of
particulate and visible emissions, and
use similar air pollution control devices,
AOD furnaces should be included in the
NSPS study for the EAF. One AOD
furnace with canopy hood and baghouse
was tested for particulate emissions.
The average test result of 6.9 mg/dscm
(0.0030 gr/dscf) for the AOD furnace is
lower than the current EAF standard of
12 mg/dscm (0.0052 gr/dscf). Hence, the
NSPS review for EAF should include
AOD furnaces.
Conclusions
Based upon the review of the current
NSPS previously summarized, a program
to revise the standard is needed. This
program, which is expected to begin in
fiscal year 1980, will be directed toward:
1. Reviewing new particulate emission
data based on the capabilities of the
best available technology today. The
investigation will include analysis of
costs associated with this technology.
2. Reviewing new opacity data from
recently designed efficient exhaust
techniques, closed roofs for fugitive
emissions, and improved hood collection
for charging, tapping, arid slagging
emissions. These systems, where
installed, appear to significantly
reduced visible emissions from EAF
shops.
3. Consideration of including the AOD
furnace emissions in the revised EAF
standard, or development of a separate
standard for these furnaces. They are a
highly visible source of particulate
emissions.
All interested parties are invited to
comment on this review, the
conclusions, and EPA's planned course
of action.
Dated April 11.1980.
Douglas M. Costle,
Administrator.
(FR Doc. 80-11284 Filed 4-18-80: 8:45 am]
BILLING CODE 656O-01-M
V-AA-3
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ENVIRONMENTAL
PROTECTION
AGENCY
STANDARDS OF
PERFORMANCE FOR
NEW STATIONARY
SOURCES
ORGANIC SOLVENT CLEANERS
SUBPART JJ
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Federal Register / Vol. 45, No. 114 / Wednesday, June 11, 1980 / Proposed Rules
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Part 60
FRL 1375-3]
Standards of Performance for New
Stationary Sources Organic Solvent
Cleaners
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Proposed rule and notice of
public hearing.
SUMMARY: The proposed standards
would limit emissionsof volatile organic
compounds (VOC) and trichloroethylene
1,1,1-trichloroethane, perchloroethylene,
methylene chloride, and
trichlorotrifluoroethane from new,
modified, and reconstructed organic
solvent cleaners (degreasers) in which
solvents are used to clean (degrease)
metal, plastic, fiberglass, or any other
type of material. The proposed
standards would specify several
equipment designs and work practices
for controlling emissions from cold
cleaners, open top vapor degreasers,
and conveyorized degreasers. When
carbon adsorber control systems are
used, a performance standard would
also apply. To determine the emissions
from carbon adsorbers, a new test
method, Reference Method 23, is
proposed to measure the concentration
of the above mentioned halogenated .
compounds, and Reference Method 25
which was proposed on October 5,1979
(44 FR 57792) would be used to measure
emissions of VOC.
The proposed standards implement
the Clean Air Act and are based on the
Administrator's determination that
organic solvent cleaners contribute
significantly to air pollution. The intent
is to require new, modified, and
reconstructed organic solvent cleaners
to use the best demonstrated system of
continuous emission reduction,
considering costs, nonair quality health,
and environmental and energy impacts.
It is also proposed that standards be
developed under section lll(d) of the
Clean Air Act, as amended, for the
control of emissions from existing
facilities of the five halogenated organic
solvents listed above. EPA is not
committed to developing section lll(d)
standards unless, after review of public
comments, standards for one or more of
these five solvents are promulgated for
new, modified, or reconstructed
facilities. If such standards were
promulgated, EPA would develop a
guideline document that would require
States to develop emission control
regulations for existing organic solvent
cleaners which use any of the five
halogenated solvents to which the
promulgated regulations would apply.
A public hearing will be held to
provide interested persons an
opportunity for oral presentation of
data, views, or arguments concerning
the proposed standards.
DATES: Comments. Comments must be
received on or before August 25,1980.
Public Hearing. The public hearing
will be held on July 24,1980, beginning
at 9:00 a.m.
Request to Speak at Hearing. Persons
wishing to present oral testimony should
contact EPA by July 17,1980.
ADDRESSES: Comments. Comments
should be submitted (in duplicate if
possible) to the Central Docket Section
(A-130), U.S. Environmental Protection
Agency, 401 M Street, S.W.,
Washington, D.C. 20460, Attention:
Docket No. OAQPS-78-12.
Public Hearing, The public hearing
will be held at Research Triangle Park,
North Carolina, in the EPA
Environmental Research Center
auditorium (Room B-102). Persons
wishing to present oral testimony should
notify Deanna Tilley, Standards
Development Branch (MD-13), U.S.
Environmental Protection Agency,
Research Triangle Park, North Carolina
27711. telephone number: (919) 541-5421.
Background Information Document.
The Background Information Document
(BID) for the proposed standards may be
obtained from the U.S. EPA Library
(MD-35), Research Triangle Park, North
Carolina 27711, telephone number (919)
541-2777. Please refer to Organic
Solvent CleanersBackground
Information for Proposed Standards
(EPA-450/2-78-045a).
Docket. Docket number OAQPS-78-
12, containing supporting information
used by EPA in development of the
proposed standards, is available for
public inspection between 8:00 a.m. and
4:00 p.m., Monday through Friday, at
EPA's Central Docket Section, Room
2903B, Waterside Mall, 401 M Street,
S.W., Washington, D.C. 20460.
FOR FURTHER INFORMATION CONTACT:
Mr. John D. Crenshaw, Standards
Development Branch, Emission
Standards and Engineering Division
(MD-13), Environmental Protection
Agency, Research Triangle Park, North
Carolina 27711, telephone number (919)
541-5421.
SUPPLEMENTARY INFORMATION:
Proposed Standards
The proposed standards would limit
the emissions of organic solvents from
new, modified, and reconstructed
degreasers in which solvents are used to
clean and degrease metal, plastic,
fiberglass, or any other type of material.
Three types of degreasers would be
regulated: cold cleaners, open top vapor
degreasers, and conveyorized
degreasers. The proposed regulations
consist of a combination of design,
equipment, work practice, and
operational standards that allow for the
best emission control and enforceability.
Each type of degreaser would be
required to have specific features for
effectively reducing emissions. Pollution
control devices for degreasers would
include covers, raised freeboards,
refrigerated freeboard devices and
carbon adsorption systems. Work
practices and operational procedures
would also be required for each type of
degreaser. These practices and
proceduies would assure the maximum
effectiveness of a specific piece of
control equipment, and would require
use of techniques that reduce solvent
emissions.
An inspection and maintenance
program would also be required to
prevent and correct solvent losses from
leaks and equipment malfunctions. An
operator training program is a proposed
requirement because proper equipment
operation and work practices play a
significant role in effective control of
solvent emissions from degreasers.
Finally, owners and operators would be
required to keep records on the amount
and type of solvent purchased for a
period of two years.
Summary of Environmental, Economic,
and Energy Impacts
Environmental Impact. The proposed
standards would reduce emissions of
organic solvents (i.e., volatile organic
compounds, trichloroethylene, 1,1,1-
trichloroethane, perchloroethylene,
methylene chloride, and
trichlorotrifluoroethane) from all
degreasing units for which construction
was commenced after (date of proposal).
Affected facilities that come on-line
between 1980 and 1985 would emit an
estimated 332,000 megagrams (366,000
tons) of organic solvents in 1985, if the
degreaser units are uncontrolled. With
implementation of the proposed
regulations, controlled emissions from
these facilities would be 120,000
megagrams (132,000 tons) in 1985, which
constitutes a reduction of 64 percent.
The only potentially adverse impact
on water quality of the proposed
regulation would derive from the solvent
dissolved in the steam condensate from
regeneration (solvent desorption) of
carbon adsorbers. Because the solubility
of solvent in the condensate is very
small, the amount of dissolved solvent is
V-JJ-2
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Federal Register / Vol. 45, No. 114 / Wednesday, June 11, 1980 / Proposed Rules
slightly greater than one-tenth of one
percent (0.1%) of the amount which
would be discharged into the air if the
proposed controls were not
implemented. In a typical system, the
carbon adsorber has a solvent capacity
of 95 kilograms (210 pounds), and
requires 3 kilograms (6.6 pounds) of
steam to desorb each kilogram of
solvent. Although desorption generates
approximately 283 liters (10 cubic feet)
of steam condensate per cycle, most
solvent would be recovered by a water
separator. Only 74 grams (0.16 pound) of
solvent per day is expected to be lost in
the waste stream from a typical carbon
adsorber. The environmental impact of
the disposal of this small amount of
condensate is insignificant. Alternatives
are under consideration by EPA for
controlling the solvent in the effluent
from desorption of a carbon adsorber.
EPA may establish regulations
pertaining to these effluents in the
future.
The only solid waste impact due to
implementation of the proposed
standards would be disposal of the
spent carbon from the carbon adsorbers
used as air pollution control devices on
certain types of degreasers. With
replacement of spent carbon every 10
years, disposal of spent carbon from
carbon adsorbers on affected facilities
would amount to 243 megagrams (268
tons) nationwide starting in 1989 and
would increase to 271 megagrams (299
tons) in 1995. Therefore, the solid waste
impact from spent carbon would be
minimal.
Economic Impact. The costs of
compliance with the proposed standards
are based on control equipment
currently in use and commercially
available. Economic analysis indicates
that, under most conditions, the capital
and annualized costs for the control
equipment can be fully recovered by
credits for the recovered solvent.
Consequently, no adverse economic
impact is anticipated to result from
implementation of the proposed
standards. The economic impact, may,
in fact, be positive in the sense that net
credits lead to lower production costs in
most, if not all, industries. Methods to
reduce solvent consumption and save
money generally have not been
accomplished in the past since
degreasing costs generally average less
than four-tenths of one percent of
industry output.
Energy Impact. Energy consuming
emission control devices for degreasing
operations would include (1)
refreigerated freeboard devices, (2)
carbon adsorption systems, and (3)
distillation equipment. Operation of
these control devices in 1985 is
estimated to require about 0.27 million
kWh per day (equivalent to 440 barrels
of oil per day); however, the proposed
standards would result in the prevention
or capture of degreaser emissions. Based
upon the amount of energy that would
have been required to manufacture
replacement solvent, use of the required
control devices on new organic solvent
cleaners would conserve an estimated
3800 barrels of oil per day. Thus, the
proposed standards in 1985 would result
in a net conservation of energy
equivalent to an estimated 3350 barrels
of oil per day.
RationaleSelection of Source for
Control
Organic solvent cleaners (degreasers)
have been identified as significant
sources of air pollutant emissions which
cause or contribute to the endangerment
of the public health or welfare.
Degreasing is not an industry but is an
integral part of many manufacturing,
repair, and maintenance operations.
Volatile organic compounds, as well as
1,1,1-trichloroethane,
trichlorotrifluoroethane, methylene
chloride, trichlorethylene, and
perchloroethylene constitute the
emissions from organic solvent cleaners.
There were an estimated 725,000
megagrams (800,000 tons) of organic
solvents emitted from organic solvent
cleaning operations in 1975. This
represents about 4 percent of the total
national volatile organic emissions from
stationary sources, making organic
solvent cleaners the fifth largest
stationary source category for organic
emissions. There are over 1,500,000
organic solvent cleaners currently in
operation. If the current growth rate of
4.1 percent per year continues as
expected, over 300,000 new organic
solvent cleaners would be subject to
these standards of performance by 1985.
Degreasing emissions include losses
due to evaporation from the solvent
bath, convection, carryout, leaks, and
waste solvent disposal. Thus, the
emissions from a degreaser are fugitive
in nature. Many of the degreasers
currently in use are operated without
proper control emissions to the
atmosphere. Emissions from degreasers
may be controlled by the use of various
equipment options (including a cover,
extended freeboard, refrigerated
freeboard device, and carbon adsorber)
and specific work practices (involving
parts handling, proper use and
maintenance of equipment, preventing
drafts, and controlling the rate of the
degreasing operation).
Based on the large number of sources
and their wide geographic distribution
across the United States, the current
sales and projected growth rate in the
"industry" and the possible reduction in
adverse environmental and health
impacts which can be achieved, organic
solvent cleaners have been selected for
control through the development of
standards of performance.
Selection of Affected Facilities
Organic solvent cleaning is not a
specific industry but is an integral part
of many manufacturing, repair, and
maintenance operations. Practically
every business that works metal or has
maintenance or repair operations does
some type of degreasing. Degreasing
operations are often concentrated in
urban areas where there are a large
number of manufacturing facilities.
The solvents used in degreasing
operations include halogenated
hydrocarbons, petroleum distillates,
ketones, ethers, and alcohols. These
solvents are emitted as fugitive
emissions from each of the three types
of degreasers which would be regulated:
(1) a cold cleaner, in which the article to
be cleaned is immersed, sprayed or
otherwise washed in a solvent at or
about room temperature; (2) an open top
vapor degreaser, in which the article is
suspended in solvent vapor over a pool
of boiling solvent and the solvent vapors
condense on the article and dissolve or
wash soil and grease from it; and (3) a
conveyorized degreaser, in which
articles are conveyed on a chain, belt or
other conveying system either through a'
spray or pool of cold solvent, or through
the vapor of a boiling solvent. In order
to achieve significant reduction in
volatile organic compound emissions
from degreasing operations, all types of
new, modified, or reconstructed
degreasers would subject to control.
The mode of disposal of waste solvent
can also contribute significantly to
solvent emissions. In the past, disposal
has generally been handled by the
owners of organic solvent cleaners. If
waste solvent disposal in 1985 were to
follow the pattern of waste solvent
disposal in 1974, about 43 percent of the
waste solvent from new sources would
be reclaimed, incinerated, landfilled and
the remaining 57 percent could be an
immediate source of air or water
emissions.
A number of alternatives for
regulating waste disposal have been
considered. These include requiring
incineration or reclamation, and
establishment of standards under the
Resource Conservation and Recovery
Act (RCRA). Because of the impact on
these small sources of requiring
reclamation or incineration, regulation
here is not now planned. Rather, the
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Administrator is deferring at this time
on waste disposal requirements and is
pursuing this matter under RCRA. The
section on waste disposal is being
reserved, however, pending completion
of the evaluation and resolution of the
issues.
Selection of Pollutants and Regulatory
Approach
Among the solvents used in
degreasing operations, approximately 40
percent are non-halogenated
hydrocarbons and 60 percent are
halogenated hydrocarbons. Most of
these solvents are also reactive volatile
organic compounds (VOC), defined by
this proposal as organic compounds
which participate in atmospheric
photochemical reactions or which may
be measured by the applicable reference
method specified under any subpart of
40 CFR Part 60. The proposed standards
of performance apply to reactive VOC
(ozone precursors) used as cleaning
solvents and to five halogenated
compounds for which there is a
reasonable anticipation of public health
endangerment.
Reactive Volatile Organic Compounds
(VOC).
The proposed standards require
control of any VOC demonstrated to be
precursors to the formation of ozone and
other photochemical oxidants in the
atmosphere. While not all compounds
are equally reactive, analysis of
available data indicates that very few
VOC are of such low photochemical
reactivity that they can be ignored in
oxidant control programs. EPA's
"Recommended Policy on Control of
Volatile Organic Compounds" (42 FR
35314; July 8,1977) affirmed that many
compounds which produced negligible
oxidant concentrations during initial
smog chamber tests were found to
contribute appreciably to ozone levels
when exposed to multiday irradiations
in urban atmospheres. In those
geographical areas where industrial and
automotive emissions are subjected to
long hours of sunlight, or where air
stagnation occurs frequently, such low
reactivity compounds may become
significant source of photochemical
oxidant.
EPA is developing standards of
performance under section lll(b) for a
number of categories of sources which
emit these volatile organic compounds,
which are ozone precursors. Ozone air
pollution endangers the public health
and welfare, as reflected in the
Administrator's promulgation of a
National Ambient Air Quality Standard
for ozone (44 FR 8202; February 8,1979).
Emissions of ozone precursors from
these source categories cause or
contribute significantly to ozone air
pollution. Trichloroethylene and, to a
lesser extent, perchloroethylene react to
form ozone and therefore would be
subject to new source performance
standards for reactive VOC.
The Administrator is also concerned
about certain other possible health
effects of perchloroethylene and
trichloroethylene, apart from their role
in ozone formation, and he believes that
regulation of existing emission sources
is necessary. Both substances have been
found to induce a high incidence of
hepatocellular carcinomas (liver tumors)
in mice and have shown positive results
in bacterial mutagencity assays (a
screening technique for potential
carcinogens). The Agency's initial
evaluation of this information is that it
presents "substantial evidence" (41 FR
21402; May 25,1976) that both
substances are human carcinogens.
Consistent with EPA's proposed rules
for regulating airborne carcinogens (44
FR 58642; October 10,1979), if these
initial evaluations are sustained after
consideration of comments by EPA's
Science Advisory Board, it is likely that
perchloroethylene and trichloroethylene
will be classified as high-probability
carcinogens and, in light of the
significant emissions of each, regulated
as hazardous air pollutants under
section 112 of the Act. This regulation
would include both new and existing
emission sources.
It is also possible that the
Administrator will ultimately conclude
that one or both of these chemicals is a
moderate-probability carcinogen rather
than a high-probability carcinogen. As
the proposed airborne carcinogen rules
explain, under the circumstances
presented here, EPA could then
"designate" the substance for regulation
of existing organic solvent cleaners by
the States under section lll(d) of the
Clean Air Act. The Act provides for the
designation of such substances for
regulation under section lll(d) if the
substances themselves have not been
listed previously under section 108 or
section 112. Because the evidence is
clearly sufficient for the Administrator
to conclude that both substances are at
least moderate-probability carcinogens
and that their emission by organic
solvent cleaners causes air pollution
which endangers public health and
welfare, he is proposing designation of
these two substances under section
lll(d) at this time. Although a final
determination by the Agency of the
evidence of carcinogenicity would
normally precede the selection of a
regulatory alternative, the Administrator
is proposing designation of
perchloroethylene and trichloroethylene
today for two reasons. First, this will put
existing sources within the industry on
notice that perchloroethylene and
trichloroethylene would not be
unregulated substitutes for the other
three solvents for which designation is
proposed today. Second, in the event
that the Administrator ultimately
concludes that perchloroethylene and
trichloroethylene are moderate-
probability rather than high-probability
carcinogens, it will enable the section
lll(d) process to proceed without delay
as part of a coordinated regulatory
program for the organic solvent cleaning
industrj. The Administrator intends to
make a final carcinogenicity assessment
for these two chemicals before
promulgating today's proposals.
Negligibly Reactive Halogenated
Compounds.
In addition to reactive halogenated
compounds, the proposed new source
regulations would apply to three
additional halogenated solvents: 1,1,1-
trichlorethane, methylene chloride, and
trichlorotrifluoroethane. Since these
chemicals are acknowledged by EPA to
be negligibly reactive, they are not
ozone precursors and must be
designated under section lll(d) of the
Act. As described above, the
designation for the purpose of obtaining
coverage under new source standards
also requires the development under
section lll(d) of standards for existing
sources.
Both raethylene chloride and 1,1,1-
trichlorethane have scored positive as
well as negative results in short-term
mutagenicity and cell transformation
tests. The weight of evidence has led the
EPA Carcinogen Assessing Assessment
Group to conclude in preliminary
assessments that both chemicals exhibit
suggestive evidence of human
carcinogenicity. Under EPA's proposed
airborne carcinogen policy, this finding
would establish 1,1,1-trichlorethane and
methylene chloride as candidates for
regulation under section 111 as air
pollutants "reasonably anticipated to
endanger public: health or welfare." In
addition, trichlorotrifluoroethane and
1,1,1-trichlorethane have been
implicated in the depletion of the
stratospheric ozone layer, a region of the
upper atmosphere which shields the
earth from harmful wavelengths of
ultraviolet radiation that increase skin
cancer risks in humans.
The judgments of whether and to
what extent 1,1,1-trichlorethane and
methylene chloride are human
carcinogens, and 1,1,1-trichlorethane
and trichlorotrifluoroethane deplete the
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ozone layer, are issues of considerable
debate. While the scientific literature
has been previously reviewed and
summarized in the docket prepared for
this rulemaking, more detailed health
assessments are currently in preparation
by EPA's Office of Research and
Development. These assessments will
be completed and submitted for external
review, including review by the Science
Advisory Board, prior to the
piomalgation of the regulations and the
proposal of EPA guidance to States in
developing existing source control
measures. The extent to which the
preliminary findings are affirmed by the
review process may affect the final
rulemaking for new as well as existing
sources.
While the measure of concern is less
for these latter three solvents than for
perchloroethylene and trichloroethylene,
the Administrator has chosen to proceed
with the designation of 1,1,1-
trichlorethane, methylene chloride, the
trichlorotrifluoroethane at this time
because emissions from these sources
and the associated health risks can be
reduced at a very low cost. This
decision reflects EPA's concern that
continued growth in uncontrolled
emissions of 1,1,1-trichlorethane,
methylene chloride, and
trichlorotrifluoroethane from solvent
cleaners may endanger public health,
and is reinforced by projections that,
were these chemicals exempted from
regulation, the resulting substitution of
exempt for non-exempt solvents could
result in large increases in the emissions
of these pollutants.
The designation of 1,1,1-
trichlorethane, methylene chloride, and
trichlorotrifluoroethane incorporates
these chemicals under today's proposed
new source standards and invokes
section lll(d) which requires States to
develop controls for existing sources. As
described in detail below, the new
source standards do not place
unreasonable economic costs on the
industry. While the impact of similar
controls on existing sources could be
more significant due to the technological
problems associated with retrofit, this
factor would be an important
consideration in determining the
appropriate control level for existing
sources. In view of the substantial
reduction in emissions which can be
achieved at low cost, and the potential
for substitution between these five
compounds, the Administrator is
persuaded that the present approach
represents a prudent policy to protect
public health. It should be emphasized
that the health assessments discussed
here are not final. The Administrator is
aware of other relevant information that
may become available. All applicable
information will be carefully evaluated
prior to making the final regulatory
decision.
Summaries of the health basis for
designating perchloroethylene,
trichloroethylene, 1,1,1-trichloroethane,
methylene chloride, and
trichlorotrifluorethane are available in
the public rulemaking docket described
at the beginning of this notice.
Selection of Format for the Proposed
Standards
Under the Clean Air Act, as amended,
there are two regulatory alternatives
available for establishing standards of
performance for new stationary sources.
Section lll(b) provides for establishing
emission limitations or percentage
reductions in emissions. However, when
such standards are not feasible to
prescribe or enforce, section lll(h) of
the Clean Air Act provides that EPA
may instead promulgate a design,
equipment, work practice, or operational
standard, or combination thereof. In
either event, the standards prescribed
would require new, modified, and
reconstructed organic solvent cleaners
to use the best demonstrated system of
continuous emission reduction
considering costs, nonair quality health
and environmental impacts, and energy
impacts. The emissions from organic
solvent cleaners are unconfined
(fugitive). Although techniques have
been developed to measure the solvent
lost from degreasing equipment (such as
mounting entire organic solvent cleaners
on scales), these methods are
impractical for enforcement of
regulations due to the length of time
needed to accurately determine the
solvent losses and because of the
disruption this would cause in degreaser
operations. For this reason, an
equipment and work practice standard
has been selected since it is not feasible
to enforce emission limitations or
percentage reductions in emissions for
organic solvent cleaning operations.
Selection of the Best System of Emission
Reduction
Emissions of volatile organic
compounds from degreasers would be
reduced significantly by the use of
various pollution control devices, singly
or in combination, as would \>e
appropriate for each method of
degreasing. These controls would
include: cover, drain rack, raised
freeboard, refrigerated freeboard device,
downtime port covers, hanging flaps,
and drying tunnel or lip exhaust in
conjunction with a carbon adsorber.
Degreaser emissions would be reduced
further through the implementation of
prescribed work practices. These work
practices would include: closing the
cover when work is not being lowered
into or removed from the degreaser,
storing solvent in covered containers,
not exposing open degreasers to steady
drafts with velocities exceeding 40m/
min (131 ft/min), and not overloading
the degreaser.
The best system of emission'control
for each type of degreaser was selected
on the basis of EPA tests of the
effectiveness of various controls used on
degreasers operating under different
conditions and using different solvents.
These are described as follows:
Cold Cleaners.The emission control
system selected for cold cleaners (CC)
would consist of both control equipment
and a series of work practices. These
controls used in combination would
reduce solvent emissions from cold
cleaners by about 80 percent. The
equipment requirements would include a
cover, a drain rack, and a visible fill
line. The cover would be designed to be
readily opened and closed at any time.
External drain racks would lead the
drainage back to the tank. If the CC is
equipped with a parts basket, internal
hooks to permit suspension of the
basket above the solvent could be
substituted for the drain rack. One of the
work practices would require that the
solvent level not exceed the visible
internal maximum fill line. The proposed
standards would require that the
freeboard ratio for CC would be at least
0.7 if the solvent vapor pressure is
greater than 4.3 kPa (33 mm Hg or 0.6
psi) measured at 38° C (100' F). The
purpose for this is to prevent excessive
volatilization, i.e. vaporization. Higher
freeboard ratios impede excess
vaporization of highly volatile solvents
under normal operating conditions.
However, many solvents used in cold
cleaning operations do not volatilize as
rapidly as others. For solvents with a
vapor pressure of less than or equal to
4.3 kPa measured at 38° C (100° F), the
proposed standards would require a
freeboard ratio of 0.5.
The economic analysis for this
emission control system for cold
cleaners was based on a typical unit.
The uncontrolled cold cleaner was
assumed to be uncovered all the time,
whereas the controlled unit had a cover
that was used all but 2 hours per
working day (20 loads cleaned per day).
Based on these assumptions, the cover
would reduce emissions by 349
kilograms (769 pounds) per year at a
savings of $69.80. The drain rack would
reduce emissions by 36 kilograms (79
pounds) per year with a savings of $7.92.
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Remote Reservoir Cold Cleaner.The
emission control system selected for
remote reservoir cold cleaners (RRCC) is
less stringent than that proposed for
conventional cold cleaners. During non-
use periods, the solvent is enclosed in a
reservoir and not subject to evaporation
loss to the atmosphere. While parts are
being cleaned, solvent is pumpted
through a sink-like work area which
drains back-into the enclosed contaier.
Because the reservoir is remote from the
work area, this type of organic solvent
cleaner is not subject to the evaporation
losses suffered by conventional cold
cleaners. Therefore, the proposed
standards for remote reservoir cold
cleaners would not require closable
covers, provided the solvent used has a
vapor pressure of less than or equal to
4.3 kPa (33 mm Hg or 0.6 psi) measured
at 38° C (100° F), but would require
covers if the solvent volatility was
greater than 4.3 kPa.
Open Top Vapor Degreaser,The
emission control systems would be
required for all new, modified, or
reconstructed open top vapor degreasers
(OTVD) consists of covers, raised
freebacks, and refrigerated freeboard
devices or carbon adsorption systems.
EPA and industry tests have shown that
covers are the most effective control
device in reducing solvent emissions
during nonoperating conditions. Raised
freeboards have also been show to be
effective at reducing these emissions. By
raising the freeboard ratio from 0.5 to
0.75, solvent emissions are generally
reduced 25-30 percent during idling
conditions. Emission reductions are less
during actual operating conditions due
to the transference of loads through
vapor/air interface. Freeboard ratios
larger than 0.75 may yield greater
emission reductions, however, higher
freeboards tend to icrease the difficulty
of transferring loads into and out of the
degreaser. The demonstrated ability of
covers and raised freeboards to reduce
olvent emissions, and the minimal cost
of these two control devices have been
the primary reasons for requiring the use
of covers during nonoperating periods
and freeboards ratios of at least 0.75 for
all new, modified, and reconstructed
open top vapor degreasers.
Emission tests have also shown that
refrigerated freeboard devices and lip
exhausts connected to carbon adsorbers
are more effective at reducing solvent
emissions than raised freeboards.
During operating conditions, emission
reductions as high as 65 percent have
been demonstrated with the use of
carbon adsorbers, while refrigerated
freeboard devices have been
demonstrated to reduce solvent
emissions by at least 40 percent. A
raised freeboard ratio of 1.0 has also
shown promise (55 percent reduction),
but its effectiveness under cross-draft
conditions has not been adequately
evaluated. It is expected that the cold
air blanket produced by a refrigerated
freeboard device would provide greater
control of cross-draft induced vapor
losses. For these reasons, all new,
modified, and reconstructed OTVD with
vapor/air interface areas greater than
one square meter would be required to
use refrigerated freeboard devices, or
have lip exhausts connected to carbon
adsorbers.
Reference Method 23, "Determination
of Halogenated Organics from
Stationary Sources," would be the
required test method to measure
emissions of the regulated halogenated
compounds from carbon adsorbers. The
principle of the method is an integrated
bag sample of stack gas that is subjected
to gas chromatographic analysis, using
flame ionization detection. The range of
this method is 0.1 to 200 ppm. The
emission limitation proposed by these
standards of performance would be 25
ppm of any regulated halogenated
organic compound measured over the
length of the carbon adsorber cycle, or
for three hours, whichever is less. The
Administrator specifically requests
comments on this proposed test method
and emission limitation.
A cut-off size of one square meter was
determined to be the most effective for
OTVD, taking into consideration the
absolute reduction in solvent emissions
and economic analyses. Although the
capital expenditures for refrigerated
freeboard devices are greater than for
raised freeboards, solvent savings
would completely offset the added
capital expenditures, provided the
degreasers were operated properly.
However, for small OTVD (less than 1
m2in open top area), refrigerated
freeboard devices would not be a cost-
effective alternative. Taking into
consideration the small reduction in
solvent emissions and economics, small
open top vapor degreasers would not be
required to have refrigerated freeboard
devices.
EPA realizes that refrigerated
freeboard devices with sub-zero (0°C)
refrigerant temperatures are patented. If
any degreaser manufacturer is unable to
demonstrate alternative methods of
control, and certifies that the licensing
terms for sub-zero refrigerated
freeboard devices are unreasonable,
relief under section 308 of the Clean Air
Act, as amended can be sought.
Although the proposed standards
require specific control technologies,
they do not preclude the use of other
control options which are demonstrated
to be equally effective in reducing
solvent emissions. After proposal of
these regulations, any person may
request an equivalency determination.
EPA expects to approve other methods
of continuous emission reduction when
they have been demonstrated to be as
effective in reducing emissions as
refrigerated freeboard devices. The
Administrator will also welcome any
additional data and information
concerning the control efficiencies of
raised freeboards and refrigerated
freeboard devices. Tests are currently
being conducted to investigate the
effectiveness of refrigerated freeboard
devices and increased freeboard ratios
under cross-draft conditions.
Preliminary results of these tests have
shown varying test results for different
solvents. Because of possible variation
in test outcomes, additional tests are
planned. Tests are also being conducted
to evaluate the effectiveness of
automated covers which close after the
workload enters the degreaser. These
test results and any additional
information and data submitted to EPA
during the public comment period will
be used to further evaluate the
appropriateness of the proposed
emission control options. Expansion or
deletion of these options will be
evaluated prior to promulgation. All
information obtained during the course
of this investigation and received during
the public comment period would be
placed in the docket for public review
and considered by EPA before taking
final action to promulgate standards for
new, modified, and reconstructed
degreasers.
Conveyorized Degreasers.There are
two major types of conveyorized
degreasers: conveyorized vapor
degreaser (CVD) and conveyorized cold
cleaners (CCC). Conveyorized vapor
degreasers use the vapors of boiling
solvent to clean and degrease surfaces,
while conveyorized cold cleaners use
non-boiling solvent in the liquid phase
to clean surfaces. The emission control
system selected for conveyorized
degreasers consists of both control
equipment and a series of work
practices. Using these controls in
combination will reduce solvent
emissions from conveyorized degreasers
by 60 percent.
The two major emission control
requirements for CVD are carbon
adsorbers or refrigerated freeboard
devices, provided the CVD is greater
than 2 square.meters (21.6 ft2) in vapor/
air interface area. This cutoff size was
determined to be the most effective,
taking into consideration the absolute
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reduction in solvent emission and
economic analyses. For larger crossrod
and monorail CVD, carbon adsorbers
produce greater emission reductions at
higher savings than do refrigerated
freeboard devices. For owners or
operators of small crossrod and
monorail degreasers, the capital costs of
a carbon adsorber could be prohibitive.
Because of this, a refrigerated freeboard
device may be used instead of a carbon
adsorber. As with OTVD, the type of
conveyorized vapor degreaser, the type
of work being processed, and ambient
conditions would determine which
emission control system should be used.
For conveyorized cold cleaners, the
major emission control requirement
would be a carbon adsorber, provided
the CCC is greater than 2 square meters
(21.6 ft2) in solvent/air interface area.
Like CVD, this cutoff was determined to
be the most effective, taking into
consideration the absolute reduction in
solvent emissions and economic
analyses. Refrigerated freeboard devices
would not be an option for CCC since
they are only effective in reducing
emissions of warm solvent vapors.
Equivalent Systems of Emission
Reduction
These standards of performance do
not preclude the use of other degreaser
emission control equipment or
procedures of operation which can be
demonstrated to be equivalent, in terms
of reducing solvent emissions, to those
prescribed in the proposed regulation.
For determination of equivalency, any
person may write the Administrator of
EPA and request approval of a test plan
for demonstrating equivalency. The test
plan must propose the use of specific
equipment, test procedures, a date, and
a U.S. location at which the person
making the request wishes to
demonstrate equivalency. In order to
determine equivalency, the
Administrator must find a substantial
likelihood that the control technology
used in normal operations would
produce equivalent emission reductions
as the standards would require, at
approximately the same or less
economic, energy, or environmental
cost. An alternate equipment design
would not be considered equivalent to
the proposed requirements if it placed a
greater burden upon the personnel
operating the degreaser to manually
operate the emission capture device
(e.g., use of an automated cover could
potentially be found equivalent to use of
refrigerated freeboard devices, but a
manually operated cover would not
qualify). Automated operation of the
emission control system is required
because manual operation would be
burdensome due to the frequency with
which work enters and exits open top
vapor degreasers (cycle times of only 8
minutes are not unusual) and because
enforcement of these standards would
primarily depend upon equipment
certifications. Although work practices
could not be substituted for equipment
design requirements, alternatives to the
work practices contained in the
proposed standards could also be
included in an equivalency
determination.
Selection of Enforcement Methods
More than 325,000 new degreasers are
expected to be in operation by 1985. The
large number of degreasers precludes
the inspection of all units on a periodic
basis. Therefore, enforcement must be
achieved through a combination of
degreaser manufacturer certifications
and EPA random inspections. Because
EPA cannot inspect all degreasers that
will be in operation, adherence to the
work practices will basically depend
upon voluntary compliance. Although
the work practices are important, the
equipment design requirements will be
the primary mechanism for ensuring the
control of organic solvent emissions
from degreasing operations. A random
inspection program would be designed
to inspect all degreaser design types
produced, but would cover only a
sample of shops using degreasing
equipment. To facilitate this program,
the primary reporting burden would be
place upon the manufacturers of
degreasing equipment
Under section lll(a)(5) of the Clean
Air Act, as amended, manufacturers of
degreasers would be considered owners
until the degreasers are sold. Thus, the
original manufacturer of a newly
constructed degreaser would be
responsible for making the proposed
reports. Section 114(a)(l) of die Act
specifies that the Administrator can
require owners or operators to report
information to EPA as may be
reasonably required. Manufacturers of
cold cleaners, remote reservoir cold
cleaners, open top vapor degreasers,
and conveyorized degreasers would be
required to notify the Administrator of
the date construction began on a new
degreaser, certain equipment features,
and the name, date and location to
whom the ownership of the degreaser
was transferred. This information would
be reported once for each degreaser
constructed, modified, or reconstructed
and the reports would be submitted
each quarter. If any manufacturer or
other owner or operator feels that the
information to be submitted is
proprietary in nature, a request for
confidential treatment can be submitted
with the report. On September 1,1976,
EPA promulgated regulations (40 CFR
part 2) which govern the treatment of
confidential business information,
including that obtained under section
114 of the Clean Air Act.
Under certain circumstances, the
operator of the degreaser rather than the
original manufacturer would be
responsible for making the report. This
would occur when a modification or
reconstruction to an existing degreaser
was made by any person other than the
original manufacturer or when any
affected degreaser is resold.
Certification would be supplemented
by an EPA inspection program of
representative types of models of
degreasers from owners and operators
selected at random. This program would
determine compliance with the design
requirements for all new degreasing
equipment, and would determine
compliance with the work practice and
operational requirements by a random
sample of degreasing operations.
Inspection would include a visual check
of the operation and an examination of
the methods of waste solvent disposal.
This method of enforcement has been
selected as the best option considering
the savings in time and money for
effective enforcement. As mentioned
previously, the large number of new
sources expected within the next five
years prohibits inspection of each unit
Effort has been made to reduce the
proposed reporting and recordkeeping
burdens to the minimum needed to
administer an effective enforcement
program. EPA also considered requiring
each degreaser operator to report
directly to EPA upon installation of a
new degreaser and to periodically report
work practice methods in use. However,
the reporting requirements would have
caused an excessive burden to be
placed on each degreaser operator and
would have caused the generation of a
large number of reports. For these
reasons, the proposed reporting
requirements are minimized to include a
one-time report per degreaser of a few
basic items. In addition, spot checks of
representative types and models of
degreasers in operation were selected as
the best available option. Operators of
degreasing equipment would only be
required to keep records of solvent
usage and disposition and would not be
required to make written reports. These
records can be discarded after a two
year period. To further reduce the
impact of these requirements, operators
of small cold cleaners (less than 1 m2),
such as are commonly used in gasoline
service stations, would be exempt from
any recordkeeping or reporting except
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for maintaining a simple record of the
disposition of waste solvent.
Public Hearing
A public hearing will be held to
discuss these proposed standards in
accordance with section 307(d)(5) of the
Clean Air Act. Persons wishing to make
oral presentations should contact EPA
at the address given in the ADDRESSES
Section of this preamble. Oral
presentations will be limited to 15
minutes each. Any member of the public
may file a written statement with EPA
before, during, or within 30 days after
the hearing. Written statements should
be addressed to the Central Docket
Section (A-130), U.S. Environmental
Protection Agency, 401 M Street, SW.,
Washington, D.C. 20460, Attention:
Docket No. OAQPS-78-12.
A verbatim transcript of the hearing
and written statements will be available
for public inspection and copying during
normal working hours at EPA's Central
Docket Section, Room 2903B, Waterside
Mall, 401 M Street, SW., Washington,
D.C. 20460.
Docket
The docket is an organized and
complete file of all the information
submitted to or otherwise considered by
EPA in the development of this proposed
rulemaking. The principal purposes of
the docket are: (1) to allow interested
parties to readily identify and locate
documents so that they can intelligently
and effectively participate in the
rulemaking process, and (2) to serve as
the record in case of judicial review
(section 307(d)(7)].
Miscellaneous
As prescribed by section 111 of the
Clean Air Act, as amended,
establishment of standards of
performance for organic solvent
cleaners was preceded by the
Administrator's determination (40 CFR
60.16, 44 FR 49222, dated August 21.
1979) that these sources contribute
significantly to air pollution which may
reasonably be anticipated to endanger
public health or welfare. In accordance
with section 117 of the Act, publication
of this proposal was preceded by
consultation with appropriate advisory
committees, independent experts, and
Federal departments and agencies. The
Administrator will welcome comments
on all aspects of the proposed
regulation, including economic and
technological issues on the proposed
test methods.
It should be noted that standards of
performance for new sources
established under section 111 of the
Clean Air Aqt reflect:
... application of the best technological
system of contunuous emission reduction
which (taking into consideration the cost of
achieving such emission reduction, any
nonair quality health and environmental
impact and energy requirements) the
Administrator determines has been
adequately demonstrated [section lll(a)(l)].
Although there may be emission
control technology available that can
reduce emissions below those levels
required to comply with standards of
performance, this technology might not
be selected as the basis of standards of
performance due to costs associated
with its use. Accordingly, standards of
performance should not be viewed as
the ultimate in achievable emission
control. In fact, the Act requires (or has
the potential for requiring) the
imposition of a more stringent emission
standard in several situations.
For example, applicable costs do not
necessarily play as prominent a role in
determining the "lowest achievable
emission rate" for new or modified
sources locating in nonattainment areas,
i.e., those areas where statutorily-
mandated health and welfare standards
are being violated. In this respect,
section 173 of the Act requires that new
or modified sources constructed in an
area which exceeds the National
Ambient Air Quality Standard (NAAQS)
must reduce emissions to the level
which reflects the "lowest achievable
emission rate" (LAER), as defined in
section 171(3) for such category of
source. The statute defines LAER as that
rate of emissions based on the
following, whichever is more stringent:
(A) the most stringent emission limitation
which is contained in the implementation
plan of any State for such class or category of
source, unless the owner or operator of the
proposed source demonstrates that such
limitations are not achievable, or
(B) the most stringent emission limitation
which is achieved in practice by such class or
category of source.
In no event can the emission rate exceed
any applicable new source performance
standard [section 171(3)].
A similar situation may arise under
the prevention of significant
deterioration of air quality provisions of
the Act (Part C). These provisions
require that certain sources [referred to
in section 169(1)] employ "best available
control technology" (BACT) as defined
in section 169(3) for all pollutants
regulated under the Act. Best available
control technology must be determined
on a case-by-case basis, taking energy,
environmental and economic impacts
and other costs into account. In no event
may the application of BACT result in
emissions of any pollutants which will
exceed the emissions allowed by any
applicable standard established
pursuant to section 111 (or 112) of the
Act.
In all events, State implementation
plans (SIP's) approved or promulgated
under section 110 of the Act must
provide for the attainment and
maintenance of NAAQS designed to
protect public health and welfare. For
this purpose SIP's must in some cases
require greater emission reduction than
those required by standards of
performance for new sources.
Finally, States are free under section
116 of the Act to establish even more
stringent emission limits than those
established under section 111 or those
necessary to attain or maintain the
NAAQS under section 110. Accordingly,
new sources may in some cases be
subject to limitations more stringent
than standards of performance under
section 111, and prospective owners and
operators of new sources should be
aware of this possibility in planning for
such facilities.
In order to prevent duplicative
regulatory reuirements, and in order to
avoid conflicts in standard setting, EPA
has been in contact with representatives
of the Interagency Regulatory Liaison
Group (1RLG). This group, composed of
members from EPA, the Occupational
Safety and Health Administration
(OSHA), the Food and Drug
Administration (FDA), and the
Consumer Product Safety Commission
(CPSC) was formed in August, 1977, to
ensure that the agencies work closely
together in areas of common interest
and responsibility. In particular, EPA
has been in contact with OSHA to
ensure that the requirements for the
proposed standard do not conflict with
OSHA's requirements for ventilation of
open surface tank operations (29 CFR
1910.94).
Under EPA's sunset policy for
reporting requirements in regulations,
the reporting requirements in this
regulation will automatically expire five
years from the date of promulgation
unless EPA takes affirmative action to
extend them. To accomplish this, a
provision automatically terminating the
reporting requirements at that time will
be included in the text of the final
regulations.
EPA will review this regulation four
years from the date of promulgation as
required by the Clean Air Act. This
review will include an assessment of
such factors as the need for integration
with other programs, the existence of
alternative methods, enforceability, and
improvements in emission control
technology.
Section 317 of the Clean Air Act
requires the Administrator to prepare an
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economic impact assessment for any
new source standard of performance
promulgated under section lll(b) of the
Act. An economic impact assessment
was prepared for the proposed
regulations and for other regulatory
alternatives. All aspects of the
assessment were considered in the
formulation of the proposed standards
to insure that the proposed standards
would represent the best system of
emission reduction considering costs.
The economic impact assessment is
included in the Background Information
Document.
Dated: April 17,198D.
Douglas M. Costle,
Administrator.
It is proposed to amend Part 60 of
Chapter I, Title 40 of the Code of Federal
Regulations as follows:
1. By adding alphabetically a
definition of the term "volatile organic
compound" to § 60.2 of Subpart A
General Provisions as follows:
§ 60.2 Definitions
*****
"Volatile organic compound" means
any organic compound which
participates in atmospheric
photochemical reactions or is measured
by the applicable reference methods
specified under any subpart.
2. By adding Subpart JJ as follows:
Subpart JJStandards of Performance for
Organic Solvent Cleaners
Sec.
60.360 Application and designation of
affected facility.
60.361 Definitions.
60.362 Standards for volatile organic
compounds, trichloroethylene, 1,1,1-
trichloroethane, perchloroethylene,
methylene chloride, and
trichlorotrifluoroethane.
60.363 Equivalent method of control.
60.364 Reporting and Recordkeeping.
60.365 Waste disposal, (reserved).
60.366 Test method.
Authority: Sec. Ill, 301(a) of the Clean Air
Act as amended [42 U.S.C. 7411, 7601(a)], and
additional authority as noted below.
Subpart JJStandards of
Performance for Organic Solvent
Cleaners
§ 60.360 Applicability and designation of
affected facility.
The provisions of this subpart are
applicable to all organic solvent
cleaners for which construction was
commenced after (date of proposal)
which are used for organic solvent
cleaning (degreasing) of any materials.
§ 60.361 Definitions.
All terms used in this subpart, but not
specifically defined in this Section shall
have the meaning given them in the Act
and in Subpart A of this part.
"Adsorption cycle" means a solvent
recovery process which begins when
solvent laden air is directed through an
activated carbon bed, resulting in the
capture of solvent vapors. An
adsorption cycle shall be considered
complete when the activated carbon bed
becomes saturated with solvent,
resulting in breakthrough of solvent
vapors.
"Carbon adsorber" means a device in
which an organic compound is brought
into contact with activated carbon and
is retained.
"Certification" means a written
statement signed by the owner or
operator of the affected facility.
"Cold cleaner" means any device or
piece of equipment which contains and
uses an organic solvent in the liquid
phase to clean surfaces.
"Conveyorized cold cleaner" means
any conveyorizer degreaser which uses
an organic solvent in the liquid phase to
clean surfaces.
"Conveyorized degreaser" means any
device which uses an integral,
continuous, mechanical system for
moving materials or parts to be cleaned
into and out of an organic solvent liquid
or vapor cleaning zone.
"Conveyorized vapor degreaser"
means any conveyorizer degreaser
which uses an organic solvent in the
vapor phase to clean surfaces.
"Drain rack" means any basket, tray,
or sink located in, on, or exterior to a
degreaser, which permits excess or
condensed solvent to drain from the
parts after degreasing and to return to
the solvent bath.
"Drying tunnel" means an enclosed
extension of the exit from a
Conveyorized degreaser.
"Equivalent method of control" means
any method that can be demonstrated to
the Administrator to provide at least the
same degree of emission control as the
specified control.
"Extended freeboard" means an
addition to the sides of a degreaser to
increase the freeboard height.
"Fill line" means a permanent mark in
a degreaser tank that indicates the
maximum operating liquid level
recommended by the manufacturer.
"Freeboard height" means, for a cold
cleaner, the distance from the liquid
solvent level in the degreaser tank to the
lip of the tank. For an open top vapor
degreaser it is the distance from the
solvent vapor level in the tank during
idling to the lip of the tank. For a
Conveyorized cold cleaner it is the
distance from the liquid solvent level to
the bottom of the entrance or exit
opening, whichever is lower. For a
Conveyorized vapor degreaser, it is the
distance from the vapor level to the
bottom of the entrance or exit opening,
whichever is lower.
"Freeboard ratio" means a ratio of the
freeboard height to the smaller interior
dimension (length, width, or diameter) of
the degreaser.
"Lip exhaust" means a device
installed around the lip of a degreaser
that draws in air and solvent vapor
emissions and ducts them away from
the degreaser area.
"Open top vapor degreaser" means
any open top device or piece of
equipment that contains and uses an
organic solvent, at the boiling point of
the solvent, and solvent vapor to clean
equipment surfaces.
"Organic solvent" means any liquid
substance which contains carbon and
has the power to dissolve, causing
solution.
"Organic solvent cleaner" or
"degreaser" means any cold cleaner,
remote reservoir cold cleaner, open top
vapor degreaser, and Conveyorized
degreaser equipment and their ancillary
components.
"Organic solvent cleaning" or
"degreasing" means those processes
using organic solvents to clean and
remove soils from the surfaces of
materials being processed.
"Refrigerated freeboard device"
means a device which is mounted above
the water jacket and the primary
condenser coils, consisting of secondary
coils which carry a refrigerant to
provide a chilled air blanket above the
solvent vapor to reduce emissions from
the degreaser bath. The chilled air
blanket temperature, measured at the
centroid of the degreaser at the coldest
point, shall be no greater than 30 percent
of the solvent's boiling point (°F).
"Remote reservoir cold cleaner"
means any device in which liquid
solvent is pumped through a sink-like
work area which drains back into an
enclosed container while parts are being
cleaned and in which the solvent in the
enclosed container is not subject to
evaporation losses to the atmosphere
during non-use periods.
§ 60.362 Standards for volatile organic
compounds, trichloroethylene, 1,1,1-
trichloroethane, perchloroethylene,
methylene chloride, and
trichlorotrifluoroethane.
(a) Except as provided in paragraph
(d) of this section, an owner or operator
shall operate a cold cleaner, or a remote
reservoir cold cleaner only if it has a
cover that may be readily opened and
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closed. A fusible link shall not interfere
with cover operation.
(b) An owner or operator shall
operate a cold cleaner only if it
conforms to the following design
requirements:
(1) A drain rack. If an external drain
rack is used, it must allow the drained
solvent to return to the solvent bath in
the cold cleaner. If the cold cleaner is
equipped with a parts basket, internal
hooks to permit suspension of the
basket above the solvent may be
substituted for the drain rack.
(2) A freeboard ratio of at least 0.5. If
the solvent used has a volatility greater
than 4.3 kPa (33 mm Hg or 0.8 psi),
measured at 38°C (100°F), the freeboard
ration shall be at least 0.7.
(3) A visible fill line.
(c) Except as provided in paragraph
(d) of this section, an owner or operator
shall not operate a cold cleaner without
meeting the following work and
operational practices:
(1) The solvent level shall not exceed
the fill line.
(2) When a flexible hose or flushing
device is used, the pressure of solvent
delivered by the pump may not exceed
69 kPa (10 psi), measured at the pump
outlet, and the pumped solvent shall be
delivered in a continuous stream and
not a droplet spray. Flushing shall be
performed only within the confines of
the cold cleaner.
(3) When an air- or pump-agitated
solvent bath is used, the agitator shall
be operated so as to produce a rolling
motion of the solvent but not observable
splashing against tank walls or parts
being cleaned.
(4) The cover shall be closed when the
cold cleaner is not in use and when
parts are being cleaned by solvent
agitation.
(5) When the cover is open, the cold
cleaner may not be exposed to drafts
greater than 40 m/min (131 ft/min), as
measured between 1 and 2 meters
upwind and at the same elevation as the
tank lip.
(6) Solvent cleaned parts shall be
drained for 15 seconds or until dripping
has stopped, whichever is longer. Parts
having cavities or blind holes shall be
tipped or rotated while draining.
(7) Waste solvent, still, and sump
bottoms shall be collected and stored in
closed containers. The closed containers
may contain a device that would allow
pressure relief, but would not allow
liquid solvent to drain from the
container prior to disposal.
(8) Each owner shall provide a
permanent label for each cold cleaner
which states the required work and
operating practices. If the freeboard
ratio on a cold cleaner is less than 0.7,
the label shall state the types of solvents
which may be used in the cold cleaner.
Such solvents include xylenes, mineral
spirits, stoddard solvents, or other
solvents with a volatility less than or
equal to 4.3 kPa. The label shall be
placed near the front of the degreaser in
full view of the degreaser operator and
written in English, and any other
language that may be necessary for
comprehension by personnel operating
the degreaser. The label must be kept
visible and legible at all times. The plant
owner or operator shall ensure that each
person who operates a cold cleaner
understands the instructions on the
label.
(9) Spills during solvent transfer shall
be wiped up immediately. The wipe rags
shall be stored in covered containers.
(d)(l) An owner or operator who
operates a remote reservoir cold cleaner
which uses solvent with a volatility of
less than or equal to 4.3 kPa (0.6 psi or
33 mm Hg] measured at 38°C (100'F),
and which has a drain area less than 100
cm2 (15.5 in2) shall be subject to the
provisions of paragraph (c)(2), (c)(5),
(c)(6), (c)(7), (c)(8), and (c)(9).
(2) An owner or operator who
operates a remote reservoir cold cleaner
which uses solvent with a volatility
greater than 4.3 kPa (0.6 psi or 33 mm
Hg) measured at 38° C (100° F), or has a
drain area greater than or equal to 100
cm2 (15.5 in2) shall be subject to the
provisions of paragraphs (d)(l), (c)(4),
and (a).
(e) An owner or operator shall operate
an open top vapor degreaser only if it
conforms to the following design
requirements:
(1) Each open top vapor degreaser
shall be equipped with a cover that may
be readily opened or closed. If the open
top vapor degreaser is equipped with a
lip exhaust, the cover shall be located
below the lip exhaust.
(2) Each open top vapor degreaser
shall have a freeboard ratio of at least
0.75.
(3) Each open top vapor degreaser
shall be equipped with the following
devices:
(i) A device which shuts off sump heat
if sump liquid solvent level drops down
to the height of sump heater coils, and
(ii) A vapor level control device which
shuts off sump heat if the vapor level
rises above the height of the primary
condenser.
(4) Each open top vapor degreaser
greater than 1.0 square meter (10.8 ft2)
shall be equipped with one or more of
the following equipment controls:
(i) A refrigerated freeboard device, or
(ii) A lip exhaust connected to a
carbon adsorber. The concentration of
organic solvent in the exhaust from this
device shall not exceed 25 ppm of any
regulated halogenated organic
compound as measured by Method 23
for the length of the carbon adsorber
cycle or three hours, whichever is less. If
other volatile organic compounds are
used, then the emissions shall not
exceed an average of 25 ppm as carbon,
measured by Method 25 for the length of
the carbon adsorber cycle or three
hours, whichever is less.
(f) An owner or operator shall not
operate an open top vapor degreaser
without meeting the following required
work and operational practices:
(1) The cover shall be closed when
parts are not being degreased.
(2) When the cover is open, the open
top vapor degreaser shall not be
exposed to drafts greater than 40 m/min
(131 ft/min), as measured between 1 and
2 meters upwind and at the same
elevation as the tank lip.
(3) For any open top vapor degreaser
equipped with a lip exhaust, the exhaust
shall be turned off when the degreaser is
covered.
(4) Parts being degreased shall not
occupy more than 50 percent of the
vapor-air interface area.
(5) The vertical speed of a powered
hoist, if one is used, shall not be more
than 3.3 m/min (10.8 ft/min) when
lowering and raising the parts.
(6) Spraying operations shall be done
within the vapor layer.
(7) Work shall not be lifted from the
vapor layer until condensation or
dripping has stopped. Parts having
cavities or blind holes shall be tipped or
rotated before being raised from the
vapor layer.
(8) During start up, the primary
condenser and the refrigerated
freeboard device, if one is used, shall be
turned on before the sump heater.
During shutdown, the sump heater shall
be turned off, and the solvent vapor
layer allowed to collapse before the
condenser water and refrigerated
freeboard device are turned off.
(9) Porous or absorbent material shall
not be degreased in an open top vapor
degreaser.
(10) A routine inspection and
maintenance program shall be
implemented to reduce or prevent
solvent losses from dripping drain taps,
cracked gaskets and malfunctioning
equipment. Leaks must be repaired as
soon as they are discovered.
(11) Waste solvent, still, and sump
bottoms shall be collected and stored in
closed containers. The closed containers
may contain a device that would allow
pressure relief, but would not allow
liquid solvent to drain from the
container prior to disposal.
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(12) Each owner shall provide a
permanent label for each open top vapor
degreaser which states the required
work and operating practices. The label
shall be placed near the front of the
degreaser in full view of the degreaser
operator and written in English, and in
any other language that may be
necessary for comprehension by
personnel operating the degreaser. The
label must be kept visible and legible at
all times. The plant owner or operator
shall ensure that each person who
operates a degreaser understands the
instructions on the label.
(13) When sumps are drained, solvent
shall be transferred using threaded or
other leakproof couplings.
(14) The carbon absorber bed shall
not be bypassed during desorption.
(g) An owner or operator subject to
the provisions of this subpart shall
operate a conveyorized degreaser only if
it conforms to the following design
requirements:
(1) Each conveyorized degreaser shall
have a freeboard ratio of at least 0.75.
(2) Each conveyorized degreaser shall
be equipped with a drying tunnel, a
rotating (tumbling) basked, hanging
flaps, or other device to prevent cleaned
parts from carrying out solvent liquid or
vapor. When a drying tunnel is used, the
air which moves through the tunnel to
enhance drying shall be exhausted to a
carbon adsorber. The concentration of
organic solvent in the exhaust from this
device may not exceed 25 ppm of any
regulated halogenated organic
compound as measured by Method 23
for the length of the carbon adsorber
cycle or three hours, whichever is less. If
other volatile organic compounds are
used, then the emissions shall not
exceed an average of 25 ppm as carbon,
measured by Method 25 for the length of
the carbon adsorber cycle or three
hours, whichever is less.
(3) Each conveyorized degreaser shall
be equipped with downtime port covers
at the entrance and exit openings.
(4) Each conveyorized cold cleaner
with a solvent-air interface area of 2.0m*
(21.6 ftj) or greater shall be equipped
with a carbon adsorber. The
concentration of organic solvent in the
exhaust from this device may not
exceed 25 ppm of any regulated
halogenated organic compound as
measured by Method 23 for the length of
the carbon adsorber cycle or three
hours, whichever is less. If other volatile
organic compounds are used, then the
emissions shall not exceed an average
of 25 ppm as carbon, measured by
Method 25 for the length of the carbon
adsorber cycle or three hours,
whichever is less.
(5) Each conveyorized vapor
degreaser with a solvent-air interface of
2.0m2 (21.6 ft2) or greater shall be
equipped with one or more of the
following equipment controls:
(i) A refrigerated freeboard device, or
(ii) A carbon adsorber. The
concentration of organic solvent in the
exhaust from this device shall not
exceed 25 ppm of any regulated
halogenated organic compound as
measured by Method 23 for the length of
the carbon adsorber cycle or three
hours, whichever is less. If other volatile
organic compounds are used, then the
emissions shall not exceed an average
of 25 ppm as carbon, measured by
Method 25 for the length of the carbon
adsorber cycle or three hours,
whichever is less.
(6) Each conveyorized vapor
degreaser shall be equipped with the
following devices:
(i) A device which shuts off sump heat
if sump liquid level drops down to the
height of sump heater coils, and
(ii) A vapor level control device which
shuts off sump heat if the vapor level
rises above the height of the primary
condenser coils.
(7) Each owner shall provide a
permanent label for each conveyorized
degreaser which states the required
work and operating practices. The label
shall be placed near the front of the
degreaser in full view of the degreaser
operator and written in English and in
any other language that may be
necessary for comprehension by
personnel operating the degreaser. The
label must be kept visible and legible at
all times. The plant owner or operator
shall ensure that each person who
operates a degreaser understands the
instructions on the label.
(8) Waste solvent, still, and sump
bottoms shall be collected and stored in
closed containers. The closed containers
may contain a device that would allow
pressure relief, but would not allow
liquid solvent to drain from the
container prior to disposal.
(9) The carbon adsorber bed shall not
be bypassed during desorption.
§ 60.363 Equivalent methods of control.
Upon written application, the
Administrator may approve the use of
equipment or procedures after they have
been demonstrated to his satisfaction to
be equivalent, in terms of reducing
solvent emissions to the atmosphere, to
those prescribed for compliance within
a specified paragraph of this subpart.
The application must contain a complete
description of the proposed testing
procedure and the date, time, and
location scheduled for the equivalency
demonstration.
§ 60.364 Reporting and recordkeeplng.
(a) The owner or operator of any
degreaser affected by this subpart shall
furnish the Administrator with a single
report for each degreaser. These reports
shall be submitted each quarter for all
degreasers which were newly
constructed, modified, or reconstructed
and which were placed in operation or
for which ownership was transferred in
the previous quarter. Each report shall
contain written notification
(certification) of the following:
(1) Date construction, modification, or
reconstruction of each degreaser was
commenced.
(2) Make and model of degreaser
(including the serial number if
applicable).
(3) Name, date, and location to whom
the ownership of the degreaser was
transferred.
(4) Dimensions of the solvent-air
interface area and the freeboard ratio.
(5) Specify whether a refrigerated
freeboard device or carbon adsorber has
been installed (if applicable) and certify
that the required controls (design
parameters), under section 60.362, are
part of the degreaser for which this
notification is required.
(6) The name, title, and signature of
the individual making the certification.
(b) Each owner or operator of an
affected facility subject to the provisions
of this subpart, except as provided in
paragraph (c) of this section, shall
maintain records for a period of 2 years
of the following:
(1) The amount and date of each
purchase of new solvent.
(2) The name and/or type of solvent
purchased.
(3) The amount, date, and method of
disposal for spent solvent, sump
bottoms, and/or still bottoms, as
applicable.
(c) Each owner or operator of a cold
cleaner with a solvent-air interface area
of less than 1.0 m* (10.8 ft2) is not
subject to the requirements of paragraph
(b) of this section, but is required to
maintain for a period of 2 years a record
of the method of waste solvent disposal.
(d) The reporting and recordkeeping
requirements under this section will
automatically expire 5 years from the
date of promulgation of this regulation
unless affirmative action to extend them
is taken by EPA. (Section 114 of the
Clean Air Act as amended (42 U.S.C.
7414))
§60.365 Waste disposal [Reserved]
§60.366 Test method.
(a) Reference Method 23 or 25 of
Appendix A, as applicable, shall be
used to determine compliance with the
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requirements under § 60.382 when
carbon adsorbers are used. The results
shall be reported as ppm of organics
(Method 23) or ppm or carbon {Method
25). Each performance test shall consist
of 3 separate samples, and the
arithmetic mean of the 3 samples shall
be used to determine compliance.
(Section 114 of the Clean Air Act as amended
(U.S.C. 7414))
3. Appendix A to part 60 is amended
by adding reference method 23 as
follows:
Appendix AReference Methods
* * * * *
Method 23. Determination of Halogenated
Organics From Stationary Sources
Introduction
Performance of this method should not be
attempted by persons unfamiliar with the
operation of a gas chromatograph. nor by
those who are unfamiliar with source
sampling because knowledge beyond the
scope of this presentation is required. Care
must be exercised to prevent exposure of
sampling personnel to hazardous emissions.
1. Applicability and Principle
1.1 Applicability. This method applies to
the measurement of halogenated organics
such as carbon tetracholoride, ethylene
dichloride, perchloroethylene,
trichloroethylene, Methylene chloride, 1,1,1-
trichloroethane, and trichlorotrifluoroethane
in stack gases from sources as specifiedd in
the regulations. It does not apply when the
halogenated organics are contained in
particulate matter.
1.2 Principle. An integrated bag sample of
stack gas containing one or more halogenated
organics is subjected to gas chromatographic
(CC) analysis, using a flame ionization
detector (FID).
2. Range and Sensitivity. The range of this
method is 0.1 to 200 ppm. The upper limit may
be extended by extending the calibration
range or by diluting the sample.
3. Interferences. The chromatograph
column with the corresponding operating
parameters herein described normally
provides an adequate resolution of
halogenated organics; however, resolution
interferences may be encountered in some
sources. Therefore, the chromatograph
operator shall select the column best suited
to his particular analysis problem, subject to
the approval of the Administrator. Approval
is automatic provided that confirming data
are produced through an adequate
supplemental analytical technique, e.g.
analysis with a different column or GC/mass
'spectroscopy. This confirming data must be
available for review by the Administrator.
4. Apparatus.
4.1 Sampling (see Figure 23-1). The
sampling train consists of the following
components:
4.1.1 Probe. Stainless steel, Pyrex* glass.
or Teflon* tubing (as stack temperature
Mention of trade names or specific products
does not constitute endorsement by the
Environmental Protection Agency
permits), each equipped with a glass wool
plug to remove particulate matter.
4.1.2 Sample Line. Teflon,' 6.4-mm outside
diameter, of sufficient length to connect
probe to bag. Use a new unused piece for
each series of bag samples that constitutes an
emission test, and discard upon completion of
the test.
4.1.3 Quick Connects, Stainless steel,
male (2) and female (2), with ball checks (one
pair without), located as shown in Figure 23-
1.
4.1.4 Tedlar or Aluminized Mylar Bags.
100-liter capacity, to contain sample.
4.1.5 Bag Containers. Rigid leakproof
containers for sample bags, with covering to
protect contents from sunlight.
4.1.6 Needle Valve. To adjust sample flow
rate.
4.1.7 Pump. Leak-free, with minimum of 2-
liters/min capacity.
4.1.8 Charcoal Tube. To prevent
admission of halogenated organics to the
atmosphere in the vicinity of samplers.
4.1.9 Flow Meter. For observing sample
flow rate; capable of measuring a flow range
from 0.10 to 1.00 liter/mm.
4.1.10 Connecting Tubing. Teflon. 6.4-mm
outside diameter, to assemble sampling train
(Figure 23-1).
4.2 Sample Recovery. Teflon tubing, 6.4-
mm outside diameter, to connect bag to gas
chromatograph sample loop is required for
sample recovery. Use a new unused piece for
each series of bag samples that constitutes an
emission test and discard upon conclusion of
analysis of those bags.
4.3. Analysis. The following equipment is
needed:
4.3.1 Gas Chromatograph. With FID,
potentiometric strip chart recorder, and 1.0-
to 2.0-mI sampling loop in automatic sample
valve. The chromatographic system shall be
capable of producing a response to 0.1 ppm of
the halogenated organic compound that is at
least as great as the average noise level.
(Response is measured from the average
value of the baseline to the maximum of the
waveform, while standard operating
conditions are in use.)
4.3.2 Chromatographic Column. Stainless
steel, 3.05 m by 3.2 mm, containing 20 percent
SP-2100/0.1 percent Carbowax 1500 on 100/
120 Supelcoport. The analyst may use other
columns provided that the precision and
accuracy of the analysis of standards are not
impaired and he has available for review
information conforming that there is
adequate resolution of the halogenated
organic compound peak. (Adequate
resolution is defined as an area overlap of
not more than 10 percent of the halogenated
organic compound peak by an interferent
peak. Calculation of area overlap is
explained in Appendix E, Supplement A:
"Determination of Adequate
Chromatographic Peak Resolution."
4.3.3 Flow Meters (2). Rotameter type. 0-
to-100-ml/min capacity.
4.3.4 Gas Regulators. For required gas
cylinders.
4.3.5 Thermometer. Accurate to 1°C. to
measure temperature of heated sample loop
at time of sample injection.
4.3.6 Barometer. Accurate to 5 mm Hg, to
measure atmospheric pressure around gas
chromatograph during sample analysis.
4.3.7 Pump. Leak-free, with a minimum of
100-ml/min capacity.
4.3.8 Recorder. Strip chart type, optionally
equipped with either disc or electronic
integrator.
4.3.9 Planimeter. Optional, in place of disc
or electronic integrator (4.3.8). to measure
chromatograph peak areas.
4.4 Calibration. Sections 4.4.2 through
4.4.6 are for the optional procedure in Section
7.1.
4.4.1 Tubing. Teflon, 6.4-mm outside
diameter, separate pieces marked for each
calibration concentration.
4.4.2 Tedlar or Aluminized Mylar Bags.
50-liter capacity, with valve; separate bag
marked for each calibration concentration.
4.4.3 Syringe. 25-pl, gas tight, individually
calibrated, to dispense liquid halogenated
organic solvent.
4.4.4 Syringe. 50-fil, gas tight, individually
calibrated to dispense liquid halogenated
organic solvent.
4 4.5 Dry Gas Meter, with Temperature
and Pressure Gauges. Accurate to ±2
percent, to meter nitrogen in preparation of
standard gas mixtures, calibrated at the flow
rate used to prepare standards.
4.4.6 Midget Impinger/Hot Plate
Assembly. To vaporize solvent.
5. Reagents. It is necessary that all
reagents be of chromatographic grade.
5.1 Analysis. The following are needed
for analysis:
5.1.1 Helium Gas or Nitrogen Gas. Zero
grade, for chromatographic carrier gas.
5.1.2 Hydrogen Gas. Zero grade.
5.1.3 Oxygen Gas or Air. Zero grade, as
required by the detector.
5.2 Calibration. Use one of the following
options: either 5.2.1 and 5.2.2, or 5.2.3.
5.2.1 Halogenated Organic Compound, 99
Mol Percent Pure. Certified by the
manufacturer to contain a minimum of 99 Mol
percent of the particular halogenated organic
compound; for use in the preparation of
standard gas mixtures as described in
Section 7.1.
5.2.2 Nitrogen Gas. Zero grade, for
preparation of standard gas mixtures as
described in Section 7.1.
5.2.3 Cylinder Standards (3). Gas mixture
standards (200,100, and 50 ppm of the
halogenated organic compound of interest, in
nitrogen) The tester may use these cylinder
standards to directly prepare a
chromatograph calibration curve as
described in Section 7.2.2, if the following
conditions are met: (a) The manufacturer
certifies the gas composition with an
accuracy of ±3 percent or better (see Section
5.2.3.1). (b) The manufacturer recommends a
maximum shelf life over which the gas
concentration does not change by greater
than ±5 percent from the certified value, (c)
The manufacturer affixes the date of gas
cylinder preparation, certified concentration
of the halogenated organic compound, and
recommended maximum shelf life to the
cylinder before shipment from the gas
manufacturer to the buyer.
5.2.3.1 Cylinder Standards Certification.
The manufacturer shall certify the
concentration of the halogenated organic
compound in nitrogen in each cylinder by (a)
directly analyzing each cylinder and (b)
V-JJ-12
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Federal Register / Vol. 45, No. 114 / Wednesday, June 11, 1980 / Proposed Rules
calibrating his analytical procedure on the
day of cylinder analysis. To calibrate his
analytical procedure, the manufacturer shall
use, as a minimum, a three-point calibration
curve. It is recommended that the
manufacturer maintain (1) a high-
concentration calibration standard (between
200 and 400 ppm) to prepare his calibration
curve by an appropriate dilution technique
and (2) a low-concentration calibration
standard (between 50 and 100 ppm) to verify
the dilution technique used. If the difference
between the apparent concentration read
from the calibration curve and the true
concentration assigned to the low-
concentration calibration standard exceeds 5
percent of the true concentration, the
manufacturer shall determine the source of
error and correct it, then repeat the three-
point calibration.
5.2.3.2 Verification of Manufacturer's
Calibration Standards. Before using, the
manufacturer shall verify each calibration
standard by (a) comparing it to gas mixtures
prepared (with 99 Mol percent of the
halogenated organic compounds) in
accordance with the procedure described in
Section 7.1 or by (b) having it analyzed by the
National Bureau of Standards, if such
analysis is available. The agreement belween
the initially determined concentration value
and the verification concentration value must
be within ±5 percent. The manufacturer must
reverify all calibration standards on a time
interval consistent with the shelf life of the
cylinder standards sold.
5.2.4 Audit Cylinder Standards (2). Gas
mixture standards with concentrations
known only to the person supervising the
analysis samples. The audit cylinder
standards shall be identically prepared as
those in Section 5.2.3 (the halogenated
organic compounds of interest, in nitrogen).
The concentrations of the audit cylinders
should be: one low-concentration cylinder in
the range of 25 to 50 ppm, and one high-
concentration cylinder in the range of 200 to
300 ppm. When available, the tester may
obtain audit cylinders by contacting:
Environmental Protection Agency,
Environmental Monitoring and Support
Laboratory, Quality Assurance Branch (MD-
77), Research Triangle Park, North Carolina
27711. If audit cylinders are not available at
the Environmental Protection Agency, the
tester must secure an alternative source.
6. Procedure
6.1 Sampling. Assemble the sampling
train as shown in Figure 23-1. Perform a bag
leak check according to Section 7.3.2. Join the
quick connects as illustrated, and determine
that all connections between the bag and the
probe are tight. Place the end of the probe at
the centroid of the stack and start the pump
with the needle valve adjusted to yield a flow
that will more than half fill the bag in the
specified sample period. After allowing
sufficient time to purge the line several times,
connect the vacuum line to the bag and
evacuate the bag until the rotameter indicates
no flow At all times, direct the gas exiting
the rotameter away from sampling personnel.
V-JJ-13
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Federal Register / Vol. 45, No. 114 / Wednesday, June 11, 1980 / Proposed Rules
Stack Wall
Filter
(Glass Wool)
Teflon
Sample Line
Vacuum Line
Quick
Connects
Female
Rigid Leak-Proof
Container
Figure 23-1. Integrated-bag sampling train. (Mention
of trade names or specific products does not con-
stitute endorsement by the Environmental Protection
Agency.)
V-JJ-14
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Federal Register / Vol. 45, No. 114 / Wednesday, June 11, 1980 / Proposed Rules
Then reposition the sample and vacuum
lines and begin the actual sampling, keeping
the rate constant. At the end of the sample
period, shut off the pump, disconnect the
sample line from the bag, and disconnect the
vacuum line from the bag container. Protect
bag container from sunlight.
6.2 Sample Storage. Keep the sample bags
out of direct sunlight and protect from heat.
Perform the analysis within 1 day of sample
collection for methylene chloride, ethylene
dichloride, and trichlorotrifluoroethane, and
within 2 days for perchloroethylene,
trichloroethylene, 1,1,1-trichloroethane, and
carbon tetrachloride.
6.3 Sample Recovery. With a new piece of
Teflon tubing identified for that bag, connect
a bag inlet valve to the gas chromalograph
sample valve. Switch the valve to receive gas
from the bag through the sample loop.
Arrange the equipment so the sample gas
passes from the sample valve to a O-to-100-
ml/min rotameter with flow control valve
followed by a charcoal tube and a 0-tol-in.
HjO pressure gauge. The tester may maintain
the sample flow either by a vacuum pump or
container pressurization if the collection bag
remains in the rigid container. After sample
loop purging is ceased, allow the pressure
guage to return to zero before activating the
gas sampling valve.
6.4 Analysis. Set the colum temperature
to 100"C and the detector temperature to
225°C. When optimum hydrogen and oxygen
flow rates have been determined, verify and
maintain these flow rates during all
chromatograph operations. Using zero helium
or nitrogen as the carrier gas, establish a flow
rate in the range consistent with the
manufacturer's requirements for satisfactory
detector operation. A flow rate of
approximately 20 ml/min should produce
adequate separations. Observe the base line
periodically and determine that the noise
level has stabilized and that base-line drift
has ceased. Purge the sample loop for 30 sec
at the rate of 100 ml/min, then activate the
sample valve. Record the injection time (the
position of the pen on the chart at the time of
sample injection), the sample number, the
sample loop temperature, the column
temperature, carrier gas flow rate, chart
speed, and the attenuator setting. Record the
barometric pressure. From the chart, note the
peak having the retention time corresponding
to the halogenated organic compound, as
determined in Section 7.2.1. Measure the
halogenated organic compound peak area,
Am, by use of a disc integrator, electronic
integrator, or a planimeter. Record Am and
the retention time. Repeat the injection at
least two times or until two consective values
for the total area of the peak do not vary
more than 5 percent. Use the average value
for these two total areas to compute the bag
concentration.
6.5 Determination of Bag Water Vapor
Content. Measure the ambient temperature
and barometric pressure near the bag. From a
water saturation vapor pressure table.
determine and record the water vapor
content of the bag as a decimal figure.
(Assume the relative humidity to be 100
percent unless a lesser value is known.)
7. Preparation of Standard Cos Mixtures,
Calibration, and Quality Assurance.
7.1 Preparation of Standard Gas Mixtures.
(Optional proceduredelete if cylinder
standards are used.) Assemble the apparatus
shown in Figure 23-2. Check that all fittings
are tight. Evacuate a 50-liter Tedlar or
aluminized Mylar bag that has passed a leak
check (described in Section 7.3.2) and meter
in about 50 liters of nitrogen. Measure the
barometric pressure, the relative pressure at
the dry gas meter, and the temperature at the
dry gas meter. Refer to Table 23-1. While the
bag is filling, use the 50-jil syringe to inject
through the septum on top of the impinger,
the quantity required to yield a concentration
of 200 ppm. In a like manner, use the 25-/il
syringe to prepare bags having approximately
100- and 50-ppm concentrations. To calculate
the specific concentrations, refer to Section
8.1. (Tedlar bag gas mixture standards or
methylene chloride, ethylene dichloride, and
trichlorotrifluoroethane may be used for 1
day, trichloroethylene and 1,1,1-
trichloroethane for 2 days, and
perchloroethylene and carbon tetrachloride
for 10 days from the date of preparation.
(Caution: If the new gas mixture standard is a
lower concentration than the previous gas
mixture standard, contamination may be a
problem when a bag is reused.)
BILLING CODE 8560-01-M
V-JJ-15
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Federal Register / Vol. 45, No. 114 / Wednesday, June 11, 1980 / Proposed Rules
Syringe
Nitrogen Cylinder
Dry Gas Meter
Boiling
Water
Bath
Tedlar Bag
Capacity
50 Liters
Figure 23-2. Preparation of Standards.
(optional)
V-JJ-16
-------
Federal Register / Vol. 45, No. 114 / Wednesday, June 11, 1980 / Proposed Rules
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V-JJ-17
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Federal Register / Vol. 45, No. 114 / Wednesday, June 11, 1980 / Proposed Rules
7 2 Calibration.
7.2.1 Determination of Halogenated
Organic Compound Retention Time. (This
section can be performed simultaneously
with Section 7.2.2.) Establish chromatograph
conditions identical with those in Section 6.4.
above. Determine proper attenuator position.
Flush the sampling loop with zero helium or
nitrogen and activate the sample valve.
Record the injection time, the sample loop
temperature, the column temperature, the
carrier gas flow rate, the chart speed, and the
attenuator setting. Record peaks and detector
responses that occur in the absence of the
halogenated organic. Maintain conditions
(with the equipment plumbing arranged
identically to Section 6.3), flush the sample
loop for 30 sec. at the rate of 100 ml/min with
one of the halogenated organic compound
calibration mixtures, and activate the sample
valve. Record the injection time. Select the
peak that corresponds to the halogenated
organic compound. Measure the distance on
the chart from the injection time to the time
at which the peak maximum occurs. This
distance divided by the chart speed is
defined as the halogenated organic
compound peak retention time. Since it is
possible that there will be other organics
present in the sample, it is very important
that positive identification of the
Halogenated organic compound peak be
made.
7.2.2 Preparation of Chromatograph
Calibration Curve. Make a gas
chromatographic measurement of each
Standard gas mixture (described in Section
5.2.3 or 7.1) using conditions identical with
those listed in Sections 6.3 and 6.4. Flush the
sampling loop for 30 sec at the rate of 100 ml/
min with one of the standard gas mixtures
and activate the sample valve. Record Cc, the
concentration of halogenated organic
injected, the attenuator setting, chart speed,
peak area, sample loop temperature, column
temperature, carrier gas flow rate, and
retention time. Record the laboratory
pressure. Calculate A., the peak area
multipled by the attenuator setting. Repeat
until two consecutive injection areas are
within 5 percent, then plot the average of
those two values versus Cc. When the other
standard gas mixtures have been similarly
analyzed and plotted, draw a straight line
through the points derived by the least
squares method. Perform calibration daily, or
before and after each set of bag samples.
whichever is more frequent.
7.3 Quality Assurance.
7.3.1 Analysis Audit. Immediately after
the preparation of the calibration curve and
prior to the sample analyses, perform the
analysis audit described in Appendix E,
Supplement B: "Procedure for Field Auditing
GC Analysis."
7.3.2 Bag Leak Checks. While
performance of this section is required
subsequent to bag use, it is also advised that
it be performed prior to bag use. After each
use, make sure a bag did not develop leaks
by connecting a water manometer and
pressurizing the bag to 5 to 10 cm HaO (2 to 4
in. HiO). Allow to stand for 10 min. Any
displacement in the water manometer
indicates a leak. Also, check the rigid
container for leaks in this manner. (Note: An
alternative leak check method is to pressurize
the bag to 5 to 10 cm HjO (2 to 4 in, HjO) and
allow to stand overnight. A deflated bag
indicates a leak.) For each sample bag in its
rigid container, place a rotameter in line
between the bag and the pump inlet.
Evacuate the bag. Failure of the rotameter to
register zero flow when the bag appears to be
empty indicates a leak.
8. Ca/cu/ations.
8.1 Optional Procedure Standards
Concentrations. Calculate each halogenated
organic standard concentration (Ce inppm)
prepared in accordance with Section 7.1 as
follows-
BILLING CODE C560-01-M
V-JJ-18
-------
Federal Register / Vol. 45, No. 114 / Wednesday, June 11, 1980 / Proposed Rules
P. (24.055 x 103) . BD
c = * = 6.240 x 10*
c p w'"u * 1W M Vm Y Pm
u v 293 JL m
m ' Tm 760
Eq. 23-1
Where:
8 = Volume of halogenated organic injected, pi.
D = Density of compound at 293°K, g/ml.
M = Molecular weight of compound, g/g-mole.
V = Gas volume measured by dry gas meter, liters.
Y = Dry gas meter calibration factor, dimensionless.
'P = Absolute pressure of dry gas meter, mm Hg.
T = Absolute temperature of dry gas meter, °K.
24.055 = Ideal gas molal volume at 293° K and 760 mm Hg,
liters/g-mole.
10 = Conversion factor. [(ppm)(ml)]/yl.
8.2 Sample Concentrations. From the calibration curve
described in Section 7.2.2 above, select the value of C that
corresponds to A . Calculate C , the concentration of
halogenated organic in the sample (in ppm), as follows:
cc * D~TTiT?T Eq. 23-2
Where:
C = Concentration of the halogenated organic
indicated by the gas chromatograph, ppm.
P = Reference pressure, the laboratory pressure
recorded during calibration, mm Hg.
T. s Sample loop temperature at the time of
analysis, °K.
P. » Laboratory pressure at time of analysis, mm Hg.
T a Reference temperature, the sample loop temperature
recorded during calibration, °K.
Swb = Water vapor content of the bag sample, volume fraction.
V-JJ-19
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Federal Register / Vol. 45, No. 114 / Wednesday, June 11, 1980 / Proposed Rules
9. References.
\. Feairheller, W. K, A M. Kemmer. B J
Warner, and D. Q. Douglas. Measurement of
Caseous Organic Compound Emissions by
Gas Chromatography EPA Contract No 68-
02-1404, Task 33 and 68-02-2818. Work
Assignment 3. January 1978. Revised by EPA
August 1978.
2. Supelico, Inc. Separation of
Hydrocarbons. Bulletin 747 Belleforte.
Pennsylvania. 1974.
3. Communication from Joseph E. Knoll
Percholoroethylene Analysis by Gas
Chromatography. March 8,1978.
4. Communication from Joseph E. Knoll
Test Method for Halogenated Hydrocarbons
December 20.1978.
*****
(Sections lll(b), lll(d), 114, and 301(a) of the
Clean Air Act as amended (42 U.S.C 7411
7414. and 7601(a)J)
|FR Out 80-130>H Piled 6-10-00. 845 ..m|
V-JJ-20
-------
ENVIRONMENTAL
PROTECTION
AGENCY
STANDARDS OF
PERFORMANCE FOR
NEW STATIONARY
SOURCES
LEAD-ACID BATTERY MANUFACTURE
SUBPART KK
-------
Federal Register / Vol. 45, No. 9 / Monday, January 14, 1930 / Proposed Rules
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Part 60
[FRL 1315-4]
Standards of Performance for New
Stationary Sources; Lead-Acid Battery
Manufacture
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Proposed rule and notice of
public hearing.
SUMMARY: The proposed standards of
performance would limit atmospheric
emissions of lead from new, modified,
and reconstructed facilities at lead-acid
battery plants. This source was listed
August 21,1979 (44 FR 49222) in
accordance wilh section li:i(b)(l)(A) of
the Clean Air Act as contributing
significantly to air pollution, which may
reasonably be anticipated to endanger
public health or welfare. The intended
effect of this proposal is to require new,
modified, and reconstructed lead-acid
battery manufacturing facilities to
control lead emissions within the
specified limits, which can be achieved
through the use of the best demonstrated
system of continuous emission
reduction. A new reference method for
determining compliance with lead
standards is also proposed.
DATES: CommentsComments must be
received on or before March 14,1980.
Public HearingThe public hearing will
be held on Wednesday, February 13,
1980 beginning at 9:30 a.m. Request to
Speak at HearingPersons wishing to
present oral testimony must contact EPA
by February 7,1980.
ADDRESSES: CommentsComments
should be submitted (in duplicate if
possible) to the Central Docket Section
(A-130), U.S. Environmental Protection
Agency. 401 M Street S.W., Washington,
D.C. 20460, Attention: Docket No.
OAQPS-79-1. Public HearingThe
public hearing will be held at EPA
Environmental Research Center
Auditorium, Rm B102, Research Triangle
Park, N.C. 27711. Persons wishing to
present oral testimony should notify
Shirley Tabler, Emission Standards and
Engineering Division (MD-13).
Environmental Protection Agency,
Research Triangle Park, North Carolina
27711, telephone number (919) 541-5421.
Background Information Document
The background information document
for the proposed standards may be
obtained from the U.S. EPA Library
(MD-35), Research Triangle Park, North
Carolina 27711, telephone number (919)
541-2777. Specify "Lead-Acid Battery
Manufacture, Background Information
for Proposed Emission Standards" (EPA
450/3-79-02Ga). DocketThe docket
number OAQPS-79-1, is available for
public inspsction and copying between
8:00 a.m. arid 4:00 p.m. at EPA's Central
Docket Section, Room 2903B, Waterside
Mall. 401 M Street S.W., Washington,
D.C. 20460.
F03 FURTHER INFORMATION CONTACT:
Don R. Goodwin, Director, Emission
Standards and Engineering Division
(MD-13), Environmental Protection
Agency, Research Triangle Park, North
Carolina 27711, telephone number (919)
541-5271.
SUPPLEMENTARY INFORMATION:
Proposed Standards
Ths proposed standards would limit
atmospheric lead emissions from new,
modified, or reconstructed facilities at
any lead-acid battery manufacturing
plant which has a production capacity
equal to or greater than 500 batteries per
day (bpd). The facilities which would be
affected by the standards, and the
proposed emission limits for these
facilities are listed below:
Facdity
Lead omde production.. 5 0 mg/kg (0 010 Ib/ton)
Gnd casfcng .. 005 mg/m1(0? x 10~*gr/dscf).
Paste rpixing 1.00 mg/m' (4 4 x 10 4gr/(Sscf)
Three-process . ... 1 00 mo,'m'(< 4 x 10 'B"'db-0
Lead reda/natiorc 2 00 i^g/m5 (8 8 x 10'' g//aicf)
Otner tea3 ftmittmg 1.00 mg/rrr (44x10 * y1 dscf)
operations.
The emission limit for lead oxide
manufacture is expressed in terms of
lead emissions per kilogram of lead
processed, while those for other
facilities are expressed in terms of lead
concentrations in exhaust air.
A standard of 0 percent opacity is
proposed for emissions from any of
these facilities. The proposed standards
would also require continuous
monitoring of the pressure drop across
the control system for any affected
facility, to help insure proper operation
of the system. Performance tests would
be required to determine compliance
with the proposed standards. A new
reference method, Method 12, would be
used to measure the amount of lead in
exhaost gases, and Method 9 would be
used to measure opacity. Process
monitoring would be required during all
tests.
Summary of Environmental, Energy, and
Economic Impacts
There are approximately 190 lead-acid
battery manufacturing plants in the
United States, of which about 100 have
been estimated to have capacities
greater than or equal to 500 batteries per
day (bpd). These plants are scattered
throughout the country and are generally
located in urban areas near the market
for their batteries. Projections of the
growth rate of the lead-acid battery
manufacturing industry range from 3 to 5
percent per year over the next 5 years.
Most of the projected increase in
manufacturing capacity is expected to
take place by the expansion of large
plants (producing over 2000 batteries per
day).
New, modified, and reconstructed
facilities coming on-line over the next 5
years will emit about 95 Mg (104 tons) of
lead to the atmosphere in the fifth year,
if their emissions are controlled only to
the extent required by current State
paniculate regulations. At some existing
plants, emissions are controlled to a
greater extent than State particulate
regulations require. This practice might
be continued at new plants in the
absence of the proposed standards of
performance. The proposed standards
would reduce potential lead emissions
from facilities coming on-line during the
next 5 years to about 2.8 Mg (3.1 tons) in
the fifth year. This is approximately 97
percent lower than the emission level
which would be allowed under State
particu'.ate regulations. The proposed
standards would also result in
decreased nonlead particulate emissions
from new plants, since equipment
installed for the purpose of controlling
lead-btaring particulate emissions
would also control nonlead bearing
particulate emissions.
The results of dispersion modeling
calculations indicate that the ambient
impact of lead emissions from a new
plant complying with the proposed
standards would be less than the
national ambient air quality standard
for lead of 1.5/xg/m3 (averaged over
calendar quarter). This is an important
consideration, since most lead-acid
battery plants ore located in urban
areas. Results of EPA dispersion
modeling calculations indicate that the
ambient lead standard will not be met in
the vicinities of plants controlling
emissions only to the extent required by
existing State regulations.
The impact of the proposed standards
on the wastewater and solid waste
emissions of a lead-acid battery plant
would depend on the technique used by
that plant to comply with the proposed
standards. The best demonstrated
system for reduction of lead emissions is
the use of fabric filters. High energy
impingement scrubbers could also be
used, but would have higher energy
requirements and operating costs than
fabric filters. At plants using
impingement scrubbing to control
emissions, lead-bearing wastewater
would be generated. This would be
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treated along with other plant
wastewater prior to being disposed from
the plant. The fractional increase in the
lead content of wastewater discharged
from a plant using impingement
scrubbing to control atmospheric lead
emissions would be about 0.5 to 4.5
percent. At plants using fabric filtration
to comply with the proposed standards,
the captured pollutant would be
reclaimed, and there would be no
increase in wastewater or solid waste
emissions due to the proposed
standards.
The energy needed to operate control
equipment required to meet the
proposed standards at a new plant
would be approximately 2 percent of the
total energy needed to run the plant. The
incremental energy demand resulting
from the application of the proposed
standards to the battery manufacturing
facilities expected to come on-line over
the next five years would be about 2.8
Gigawatt hours of electricity in the fifth
year. Approximately 4.8 thousand
barrels of oil would be required to
generate this electricity.
The capital cost of the installed
emission control equipment necessary to
meet the proposed standards on all new
facilities coming on-line nationwide
during the first five years of the
standards would be approximately $8.6
million. The total annualized cost of
operating this equipment in the fifth
year of the proposed standards would
be about $4 million.
These costs and energy and
environmental impacts are considered
reasonable, and are not expected to
prevent or hinder expansion of the lead-
acid battery manufacturing industry.
Economic analysis indicates that, for
plants with capacities larger than or
equal to 500 bpd, the costs attributable
to the proposed standards could be
passed on with little effect on sales. The
average incremental cost associated
with the proposed standard would be
about 30< per battery. This is about 1.6
percent of the wholesale price of a
battery.
Modification and Reconstruction of
Existing Sources
In accordance with provisions
applicable to all standards of
performance, the proposed standards for
the lead-acid battery manufacturing
industry would apply to modified and
reconstructed facilities, as well as to
new facilities.
Under the modification provisions of
40 CFR 60.14, except in certain cases, an
existing facility would be affected by
the proposed standards if some physical
or operational change is made to that
facility which results in an increase in
atmospheric lead emissions from that
facility. Actions which would not be
considered modifications, and thus
would not cause an existing facility to
become subject to the standards,
regardless of any emission increase are:
1. Routine maintenance, repair, and
replacement of components.
2. An increase in the production rate
of a facility which is accomplished with
an expenditure on the source containing
the facility of less than 5.5 percent of the
value of the facility. (This is the Internal
Revenue Service annual asset guideline
repair allowance for a facility at a lead-
acid battery plant.)
3. An increase in the number of
operating hours of a facility.
4. The use of an alternative raw
material if the facility was designed to
accommodate such material prior to this
proposal.
5. The addition or use of any system
or device whose primary function is the
reduction of air pollutants, except when
an emission control system is removed
or is replaced by a system which the
Administrator determines to be less
environmentally beneficial.
6. The relocation or change in
ownership of an existing facility.
Under the reconstruction provisions
applicable to all standards of
performance (40 CFR 60.15), an existing
facility might become subject to the
standards if its components were
replaced to such an extent that the fixed
capital cost of the new components
exceeded 50 percent of the fixed capital
cost that would be required to construct
a comparable new facility. The
standards would not apply, however, if
the Administrator determined that it
would not be technologically or
economically feasible to meet the
standards. Such determinations would
be made on a case-by-case basis.
Rationale for the Proposed Standards
Selection of Source and Pollutant for
Control
The manufacture of lead-acid
batteries begins with the casting of lead
grids and the production of lead oxide
powder. The lead oxide powder is
mixed with water and sulfuric acid to
form a stiff paste, which is then pressed
onto the lead grids. The pasted grids
(plates) are cured, stacked, and
connected (burned) into groups that
form the individual elements of a lead-
acid battery. The battery plates are
converted to active electrodes by the
formation process. In this process, the
battery elements are immersed in dilute
sulfuric acid, and direct current is
passed between the plates to form
active electrodes. Formation can take
place either in an open acid bath (dry
formation), or after the battery elements
have been assembled into battery cases
(wet formation). At some plants, scrap
lead is recycled in a lead reclamation
process.
Most of the operations discussed
above are independent of one another.
For instance, most small plants do not
have lead oxide production or lead
reclamation facilities, and some large
companies sell lead oxide. However,
stacking and burning of battery plates
and assembly of elements into battery
cases are generally accomplished in a
single operation, called the three-
process operation.
Most lead-acid battery plants are
located near residential or urban areas.
These plants emit lead-bearing
particulate matter to the atmosphere.
Sources of atmospheric lead emissions
at lead-acid battery plants include lead
oxide production, grid casting, paste
mixing, three-process operation, and
lead reclamation facilities. A National
Ambient Air Quality Standard has been
established for lead. The health and
welfare effects of lead are presented in
the document, "Air Quality Criteria for
Lead" (EPA-600/8-77-017). Based on the
results of EPA emission tests and the
current required level of control, it is
estimated that emissions from lead-acid
battery plants could result in ambient
lead concentrations which exceed the
National Ambient Air Quality Standard,
These emissions may reasonably be
anticipated to endanger public health or
welfare. Therefore, standards are
proposed for lead emissions from lead-
acid battery plants. Standards are not
proposed for nonlead particulate
emissions because such emissions are
slight when compared with particulate
emissions from other sources. Also,
control of lead emissions would result in
the reduction of other particulate
emissions as well.
In addition to lead-bearing particulate
matter, plants using dry formation
techniques emit sulfuric acid mist. This
mist results from the entrainment of
sulfuric acid in hydrogen bubbles which
are generated during the formation
process. Wet formation usually takes
place in covered battery cases.
Therefore, acid mist emissions from wet
formation are small.
Sulfuric acid mist has been previously
determined to be a health related
pollutant for the purposes of section
lll(d) of the Clean Air Act. Therefore.
the Administrator considered proposing
standards for the lead-acid battery
manufacturing industry which would
limit acid mist emissions from the dry
formation process. The setting of
standards requiring control of acid mist
emissions from new, modified, and
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reconstructed formation facilities would
require States to limit acid mi^t
emissions from existing plants as well,
under section lll(d).
EPA tests on dry formation at one
plant indicate that the uncontrolled
sulfuric acid mist emission rate from this
facility is low (1.1 kg/1000 batteries).
Dispersion modeling studies based on
this emission rate indicate that the
maximum ambient impact of sulfuric
acid mist emissions from the dry
formation process at a plant as large as
6500 batteries per day would be less
than 1 fig/ms on an annual basis.
Therefore, standards for acid mist are
not being proposed at this time.
In contrast, two literature sources
indicate that the acid mist emission rate
from dry formation may be much higher
(up to 19 k/1000 batteries) than the rate
measured by EPA. However, EPA is
unable to determine the reliability of the
data contained in these sources because
neither the test methods used nor the
process operating conditions during
testing are known. Therefore, although
these sources indicate that acid mist
emissions from the formation process
may be significant, they do not provide
a sufficient basis for an acid mist
standard for the formation process.
It is of concern to the Administrator
that the decision not to regulate acid
mist emissions from formation is based
on the results of tests at only one plant
The public is specifically invited to
submit comments with supporting data
on the issue of acid mist control. Based
on the information received, EPA may
take action regarding control of acid
mist emissions from the formation
process.
Applicability
The proposed standards of
performance would apply to new,
modified, or reconstructed facilities at
any lead-acid battery plant that has the
capacity to produce 500 or more
batteries in a day (24 hours). Plnnts with
capacities less than 500 bpd are
exempted from the proposed standards
for several reasons. First, projections of
the economic impact of standards on
existing small plants (100 and 250 bpd)
undergoing reconstruction or
modification indicated that standards
would have a severe negative impact on
such plants. Also, although almost 50
percent of the lead-acid battery plants in
the United States produce fewer than
500 bpd, these plants account for only
about 2 percent of tolal lead-acid
battery production. Finally, industry
representatives do not forecast
construction or expansion of small
plants. In fact there has been a trend in
recent years of small plants closing due
to unprofitability. Increased demand for
batteries in the future is expected to be
accommodated by expansion of existing
p'.ants producing over 2000 bpd.
Selection of Affected Faciliiies
Lead emitting process operations
selected as affected facilities are lead
oxide production, grid casting, paste
mixing, three-process operation, lead
reclamation, and other lead emitting
operations. These process operations
often consist of several machines or
production lines which perform the
same function and which are located in
the same area and ducted to the same
control device. Therefore, for each of the
process operations mentioned above,
the affected facility is the entire
operation. For example, at a plant with
more than one three-process line, all of
the lines together would be the affected
facility.
Lead Oxide ManufacturingIn the
lead-acid battery industry, lead oxide is
produced either by the ball mill process,
or by the Barton process. In the ball mill
process, which is used more frequently,
lead pigs or balls are tumbled in a mill,
and the frictional heat generated by the
tumbling action causes the formation of
lead oxide. The lead oxide is removed
from the mill by an air stream. In the
Barton process, molten lead is atomized
to form small droplets in an air stream.
These droplets arc then oxidized by the
air nround them.
Thus, in both the Barton process and
the ball mill process, lead oxide product
must be recovered from an air stream. In
both processes, fabric filtration is used
to accomplish this separation. It is
estimated that lead emissions from a
typical lead oxide manufacturing facility
including product recovery are about
0 05 kg (0.116 Ib) per 1,000 batteries, or
about 10 g/Mg (0.02 Ib/ton) of lead
processed, Although these lead
emissions are low, source tests have
indicated that a well controlled lead
oxide manufacturing facility would emit
only about half as much lead as one
designed only for economical recovery
of lead oxide. Therefore, the lead oxide
production process is designated an
affected facility.
Grid CastingAlthough lead
emissions from grid casting are
generally low, most grid casting work
areas would be ventilated to comply
with the in-plant OSHA lead
concentration stanard of 50 fig/m8. EPA
tests detected an uncontrolled lead
emission rate of 0.4 kg (0.9 Ib) per 1,000
batteries (4.37 mg/m3 or 19.1 X 10"4gr/
dscf of exhaust air), which was about 3.2
percent of the overall plant uncontrolled
lead emission rate. Therefore, grid
casting is designated an affected facility.
The gr.d casting facility is defined to
include both the grid casting machines,
and the lead melting pots associated
with these machines.
Paste MixingPaste mixing is
generally a batch operation consisting of
two phases: a charging phase, in which
lead oxide is fed to the paste mixer, and
a mixing phase, in which the lead oxide
is mixed with water and sulfuric acid.
Most emissions from paste mixing occur
during the charging phase. However,
lead emissions are also ducted from the
paste mixer during the mixing phase.
Uncontrolled lead emissions from paste
mixing have been determined to be
approximately 5.1 kg (11.2 Ib) per 1,000
batteries (77.4 mg/m3 or 338 X 10~4gr/
dscf of exhaust). This is about 40
percent of the total estimated
uncontrolled lead emission rate for a
lead-acid battery plant. The paste
mixing facility is, therefore, selected as
an affected facility.
Three-process OperationThe Three-
process operation facility is defined to
include all processes involved with plate
stacking, burning, and assembly of
elements into battery cases. Average
uncontrolled lead emissions from three-
process operations tested by EPA were
6.7 kg (14.7 Ib) per 1,000 batteries (26
mg/m3 or 115 X 10~4gr/dscf of exhaust
air). This is over 50 percent of the
estimated lead erri-ssions from a lead-
acid battery plar.t. Therfore, the three-
process operation is designated an
affected facility.
Lead ReclamationLead reclamation
is often a sporadic operation, on stream
only when larga quantities of defective
small parts, grids, and plates are
available. EPA measured lead emissions
from this process to be 0.35 kg (0.77 Ib)
per 1000 batteries, 3.0 kg/Nig (5.9 Ib/ton)
of lead charged, or 227 mg/m3 (990X10^
gr/dscf) of exhaust air. Lead emissions
can be very high duiing operation. For
example, a 4000-bpd plant at which the
lead reclamation facility is run for an 8-
hour shift every 2 weeks would etnit
approximately 1.7 kg/hr (3,8 Ib/hr)
during operation. This is comparable
with the lead emission rate from the
three-process operation at the same
plant. Therefore, the Adniinistrator
designates lead reclamation as an
affected facility. Reverberatory
furnances which are used for lead
reclamation but which are affected by
standards of performance for secondary
lead smelters (40 CFR 60.120), would not
be affected under the proposed
standards.
Other Lead-Emitting Opercitions
Any lead-acid battery plant facility from
which lead emissions are collected and
ducted to the atmosphere but which is
not considered part of the lead oxide
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pniductv.in grid casting, paste mixing,
three-process operation, or lead
reclamation facilities is considered an
"other lead emitting operation." An
example is slitting, a process whereby
lead grids, cast in doublets, are slit (with
an enclosed saw) into separate plates.
The Administrator has selected other
If .id emitting operations as affected
facilities to ensure the control of lead
emissions from these processes.
Selection of the Best System of
Emissions Reduction Considering Costs
Section 111 of the Clean Air Act
requires that standards of performance
reject the degree of emission control
achievable through application of the
bt!it de-ncji&'rated technological system
of continuous emission reduction which
(taking into consideration the cost of
achieving such emission reduction, any
nonair quality health and environmental
impact, and energy requirements) has
been adequately demonstrated. The
proposed standards were developed
based on information derived from (1)
a\ arable technical literature on the
lead-acid battery manufacturing
industry and applicable emission control
technology, (2) technical studies
performed for EPA by independent
research organizations, (3) information
obtained from the industry during visits
to lead battery plants and meetings with
various representatives of the industry,
(4) comments and suggestions solicited
from experts, and (5) results of emission
measurements conducted by EPA.
Techniques currently used to control
atmospheric lead emissions from
facilities at lead-acid battery plants
include fabric filtration and
impingement scrubbing of exhaust
gases. Low energy scubbers are
currently used to control emissions
entrained in hot gases, or in gases
containing moisture or possible spark
hazards. Fabric filters can be used to
control all atmospheric lead emissions
from lead-acid battery manufacturing,
provided that proper maintenance
procedures are followed and that
necessary precautions are taken to
prevent condensation or sparks when
necessary. They are commonly used in
other industries to control emissions
from sources having similar moisure
problems and spark problems.
Several emission control alternatives
were studied in the development of the
proposed standards. One of these
alternatives consists of fabric filter
control for all affected facilities. The
others consist of fabric filler control for
Rome affected facilities and low energy
impingement scrubber control for other
affected facilities. The alternative which
would achieve the best degree of
emission control is fabric filter control
of atmospheric lead emissions from all
affected facilities. The other alternatives
make use of low energy scrubbers to
varying extents, and represent varying
degrees of emission reduction. Economic
analysis has shown that, for plants with
capacities greater than or equal to 500
batteries per day, none of the control
alternatives which were studied would
impose an unreasonable cost. Also, the
cost of any alternative is not viewed as
being detrimental to industry expansion.
The proposed standards are based on
the control of all lead emissions from
lewd-acid battery plants by fabric
filtration. This basis was chosen
because fabric filters can achieve a
better degree of emission reduction than
low energy scrubbers at a reasonable
cost.
The use of control techniques other
than fabric filtration would not be
precluded by the proposed standards.
High energy impingement scrubbers
could be used to meet the emission
limits. However, these would have
higher operating costs and energy
requirements than fabric filters.
Sciubbers would also generate lead
contaminated water, which would
probably require treatment prior to
disposal.
Selection of the Format for the Proposed
Standard
In general, lead-acid battery
manufacturing facilities may be
considered independent of one another
in that there is no continuous flow of
materials. Lead oxide production
operations, grid casting operations,
paste mixing operations, lead
reclamation operations, and three-
process operations are independent.
Also, not all plants have lead
reclamation and lead oxide production
operations, and some plants sell lead
oxide.
Because of the independent nature of
the facilities, two different forms were
chosen for the proposed standards. The
format of the proposed standards
applicable to grid casting, paste mixing.
three-process operation, lead
reclamation, and other lead-emitting
operations, is a concentration standard.
The format of the standard for lead
oxide manufacturing is mass per unit of
lead input.
A concentration standard is proposed
for three-process facilities because
emissions from these facilities depend
more on number of plates processed and
the method of burning than on the
weight of material processed. Since
emissions from grid casting, paste
mixing, and lead reclamation are often
controlled by the control device which
controls three process operation
emissions, concentration standards are
also proposed for these facilities, A
mass per unit lead input standard is
proposed for lead oxide production
facilities because these facilities
generally have different emission
control devices from three-process
operation facilities and because
emissions fiom lead oxide production
are generally proportional to lead input.
Selection of Emission Limits
The proposed limits for lead emissions
from lead oxide production, grid casting,
paste mixing, three-process operation,
lead reclamation, and other lead
emitting facilities are based on
emissions levels attainable using fabric
filtration. In the development of
background data for the proposed
standards, atmospheric lead emissions
from facilities at four lead-acid battery
plants were measured using the
proposed Method 12. In a previous
study, lead emissions from facilities at
two lead-acid battery manufacturing
plants and one lead oxide
manufacturing plant were measured
using a similar test method.
The emission limits for three-process
operation facilities, lead oxide
production facilities, and other lead
emitting facilities are based on lead
levels measured in exhausts from fabric
filters controlling emissions from such
facilities. Fabric filters are not currently
used in the lead-acid battery industry to
control emissions from grid casting or
lead reclamation and are not generally
used to control emissions from the
mixing phase of paste mixing. The
emission limits for grid casting, paste
mixing, and lead reclamation are,
therefore, based on lead levels found in
uncontrolled emissions from such
facilities, and on the demonstrated
emission reduction capabilities of fabric
filters.
Tests of controlled and uncontrolled
emissions from three-process facilities
controlled by fabric filters indicated ,
fabric filter lead collection efficiencies
of about 99 percent. This control
efficiency is consistent with efficiencies
achieved by well maintained fabric
filters in other applications. Because
paniculate emissions from all lead
emitting facilities at battery plants are
similar in composition and particle size.
the Administrator has determined that
comparable collection efficiencies can
be achieved for emissions from grid
casting, paste mixing, and lead
reclamation.
Lead Oxide ManufacturingThe
proposed standard for lead oxide
production is 5 milligrams of lead per
kilogram of lead processed (10 Ib/ton).
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This limit is based on results of tests of
emissions from a ball mill lead oxide
production facility with a fabric filter
control system. The tests showed an
average controlled emission rate of 4.2
mg/Kg (8.4 Ib/ton) for this facility. EPA
has not conducted tests of emissions
from a well controlled Barton process.
However, in both the ball mill process
and the Barton process, lead oxide
product must be removed from an air
stream. Also, EPA tests on a Barton
process indicated that Barton and ball
mill processes have similar air flow
rates per unit production rate. Therefore,
it has been determined that a similar
level of emission control could be
achieved for a Barton process as has
been demonstrated for the ball mill
process.
Grid CastingImpingement
scrubbing, rather than fabric filtration, is
currently used in the lead-acid battery
manufacturing industry to control
emissions from grid casting. Emissions
from grid casting facilities were
measured at two plants. At one of these
plants, grid casting emissions were
controlled by an impingement scrubber.
At the other, grid casting'emissions were
not controlled. The average lead
concentration in exhaust from the
uncontrolled facility was 4.37 mg/m3
(19.1 X10"4 gr/dscf). Average
uncontrolled and controlled lead
emissions from the scrubber controlled
facility were 2.65 mg/m3 (11.6xiO"4gr/
dscf) and 0.32 mg/m' (1.4Xl(T4gr/dscf),
respectively. Thus the lead collection
efficiency of the scrubber was about 90
percent.
Fabric filtration can be used to control
these emissions if spark arresters are
used and the exhaust gas is kept above
the dew point. The lead standard for
grid casting, 0.05 mg/m3(0.2XlO~4gr/
dscf), is based on the exhaust
concentration achievable using a fabric
filter with about 99 percent collection
efficiency to control emissions.
Paste MixingLead emissions from a
paste mixing facility equipped with an
impingement scrubber were measured.
Average uncontrolled and controlled
lead concentrations from this facility
were 77.4 mg/m3(338X10~4gr/dscf) and
10.8 mg/m3 (47.0xlO-4gr/dscf),
respectively.
Fabric filtration is not generally used
to control emissions from the entire
paste mixing cycle because of the high
moisture content of paste mixer exhaust
during the mixing cycle. However, fabric
filtration can be used to control
emissions from the entire cycle if the
exhaust gas is kept above the dew point.
The proposed lead emission standard
for paste mixing, 1 mg/m3 {4.4X!0~4gr/
dscf), is based on the level achievable
using a fabric filter with about 99
percent collection efficiency for the
entire cycle.
In developing data for the proposed
standards, EPA conducted tests at a
plant where paste mixing emissions
were controlled by two separate
systems. At this plant, paste mixing
required a total of 21 to 24 minutes per
batch. During the first 14 to 16 minutes
of a cycle (the charging phase), exhaust
from the paste mixer was ducted to a
fabric filter which also controlled
emissions from the grid slitting
(separating) operation. During the
remainder of the cycle (mixing), paste
mixer exhaust was ducted to an
impingement scrubber which also
controlled emissions from the grid
casting operation. Uncontrolled or
controlled emissions for the paste mixer
alone were not tested. The average
concentration of lead in emissions from
the fabric filtration system used to
control charging emissions was 1.3 mg/
m3 (5.5X10~4 gr/dscf). The average lead
content of exhaust from the scrubber
used to control mixing emissions was
0.25 mg/m3 (1.1 X ID'4 gr/dscf). The
average lead concentration in controlled
emissions from this facility was about
0.95 mg/m3 (4.2 X10~4 gr/dscf) which is
slightly below the proposed emission
limit of 1 mg/m3 (4.4 x 10" 4gr/dscf). A
lower average emission concentration
could be achieved by using fabric
filtration to control emissions from all
phases of paste mixing.
Three-Process OperationThe
proposed lead concentration limit for
three-process operation emissions is 1
mg/m3 (4.4 X10"4 gr/dscf). This limit is
based on the results of EPA tests
conducted at four plants where fabric
filtration was used to control three-
process operation emissions. All of
these tests showed lead concentration
below the proposed limit in controlled
emissions from the three-process
operation facilities.
Lead ReclamationLead emissions
from a lead reclamation facility where
emissions are controlled by an
impingement scrubber were measured.
The average lead concentrations in the
inlet and outlet streams of the scrubber
were 227 mg/m3 (990 X10~4 gr/dscf} and
3.7 mg/m3 (16 x 10"4 gr/dscf),
respectively. The collection efficiency of
the scrubber was, therefore, about 98
percent.
Fabric filtration is not currently used
to control emissions from lead
reclamation facilities because of the
high temperature of lead reclamation
exhaust. However, fabric filters have
been applied to hot exhaust systems at
secondary lead smelters and in other
industries. Therefore, the proposed
standard for lead reclamation facilities
of 2 mg/m3 (8.8 X10"4 gr/dscf), is based
on the emission level attainable using a
fabric filter with a collection efficiency
of about 99 percent.
Other Lead Emitting Operations
Emissions from other lead emitting
operations are generally collected and
ducted to minimize worker exposure.
These emissions are similar in
composition and concentration to
emissions from non-automated three-
process operations. The proposed
standard for other lead emitting
operations is 1 mg/m3 (4.4 X10~4 gr/dscf)
because lead emissions from those
operations can be controlled to the same
extent as lead emissions three-process
operation facilities.
EPA measured emissions from a
slitting facility, which would be
classified as an "other lead emitting
operation," controlled by a fabric filter.
The controlled emissions from the
facility had an average lead content of
0.938 mg/m3 (4.1 X10~4 gr/dscf), which is
below the proposed concentration limit
for other lead emitting operations.
Opacity Standards
A standard of 0 percent opacity is
proposed for emissions from all affected
facilities. Grid casting, paste mixing,
three-process operation, and lead oxide
manufacturing facilities were observed
by EPA to have emissions with 0 percent
opacity during observation periods of 7
hours and 16 minutes, 1 hour and 30
minutes, 3 hours and 51 minutes, and 3
hours and 19 minutes, respectively.
Emissions ranging from 5 to 20 percent
opacity were observed for a total of 11
minutes and 15 seconds during 3 hours
and 22 minutes of observation at the
lead reclamation operation source
tested by EPA, which was controlled by
a low-energy scrubber. However, the
proposed standard is based on control
of this process by a fabric filter, similar
to three-process operations and paste
mixers for which emissions with 0
percent opacity have been observed. A
standard of 0 percent opacity is,
therefore, also proposed for emissions
from lead reclamation furnaces.
Under the proposed standards,
opacity would be determined by taking
the average opacity over a 6-minule
period using EPA Test Method 9, and
rounding the average to the nearest
whole percentage. The rounding
procedure is specified in the proposed
standards in order to allow occasional
brief emissions with opacities greater
than 0 percent. When a fabric filter is
used to control emissions, the outlet
concentration from the filter may
increase immediately after a component
filter bag is cleaned. In the case of a
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Federal Register / Vol. 45, No. 9 / Monday, January 14, 1980 / Proposed Rules
lead-acid battery plant, filter cleaning
may result in occasional emissions with
opacities greater than 0 percent. If the
roundir.g off procedure were not
specified, any reading of greater than 0
percent opacity during a 6-minute period
could be considered as indicative of a
vio'.iaon of the proposed 0 percent
opacity standard. However, the
Administrator does not intend for
occasional emissions greater than 0
percent opacity occurring during filter
cleaning to be considered violations of
the proposed standards. Therefore, the
standards would specify that the
average opacity bt rounded to the
nearest whole percentage. With this
specification, 6-minut8 average opacities
less than 0.5 percent would not be
considered violations of the proposed
standards. Emissions which result in 6-
minute average opacities of 0.5 percent
or g'ca'.rr are expected to be indicative
of fabric filter malfunctions rather than
filter cleaning emissions.
Testing and Recordkceping
Performance tests would be required
to determine compliance with the
proposed standards. A new Reference
Method 12 would be used to measure
lead emissions. In addition, the
following methods would be used to
determine the necessary emission data:
Mtthod 1 for sample and velocity
traverses, Method 2 for velocity and
volumetric flow rate, Method 4 for stack
gas moisture and Method 9 for stack
opacity.
A measurement of the mass rate of
feed would also be required during
performance tests for lead oxide
inariifacturing because the units of the
standards for this facility are milligrams
of lead per kilogram of lead feed. Lead
ingnts of constant weight can be
counted as they are fed to the lead oxide
manufacturing process. The mass rate of
feed measurements must be accurate
uithin ±5 percent.
To determine compliance when two or
mort facilities at the same plant are
ducted to a common control device, the
exhaust rate from each source and the
controlled lead concentrations must be
measured. An equivalent standard for
the applicable facilities is calculated by
multiplying each applicable standard by
the fractional exhaust flow rate of that
facility and adding the numbers. This
equivalent standard can then be
compared with the measured
concentration to determine compliance.
The proposed standards would
require continuous monitoring of the
pressure drop across the fabric filter or
scrubber as applicable. A decrease in
p-esp'.ire drop of about 50 percent could
indicate a decrease in lead removal
efficiency because of either a fabric
filter bag failure or a decrease in liquid-
to-gas ratio.
EPA Reference Method 12 was
developed to determine inorganic lead
emissions from stationary sources.
Particulate and gaseous lead emissions
are withdrawn isokinetically from the
source. The collected samples are then
digested in acid solution and analyzed
by atomic absorption spectrometry
using an air acetylene flame. For a
minimum analysis accuracy of ±10
percent, a minimum lead mass of lOpg
should be collected. The typical
sensitivities for a 1 percent change in
absorption (0.0044 absorbance units) are
0.2 and 0.5 fjg Pb/ml for the 217.0 and
2P3 3 nm lines, respectively.
The laboratory precision for Method
12, as measured by the coefficient of
variation, was determined at a gray iron
foundry, a lead battery manufacturing
plant, a secondary lead smelter, and a
lead recovery furnace at an alkyl lead
manufacturing plant. The concentrations
encountered during these tests ranged
from 0.61 to 123.3 jig/Pb/m s. The
coefficient of variation for each run,
which is the standard deviation of the
run expressed as a percentage of the run
mean concentration, ranged from 0.2 to
9.5 percent.
High copper concentrations may
interfere with the analysis of lead at
217.0 nm. This interference can be
avoided by analyzing the samples for
lead using the 283.3 nm lead line. This
problem should not occur, however,
when analyzing samples from lead-acid
battery facilities.
Records of performance tests and
continuous monitoring system
measurements would have to be
retained for at least 2 years following
the date of the measurements by owners
and operators subject to this subpart.
This requirement is included under
§ 60.7(d) of the general provisions of
Pert 60.
Public Hearing
A public hearing will be held to
discuss these proposed standards in
accordance with Section 307(d)(5) of the
Clean Air Act. Persons wishing to make
oral presentations should contact EPA
at the address given in the ADDRESSES
Section of this preamble. Oral
presentations will be limited to 15
minutes each. Any member of the public
may file a written statement with EPA
before, during, or within 30 days after
the hearing Written statements should
be addressed to the Central Docket
Section (A-130), U.S. Environmental
Protection Agency, 401 M Street, S.W.,
Washington, D.C. 20450, Attention:
Docket No. OAQPS-79-1.
A verbatim transcript of the hearing
and written statements will be available
for public inspection and copying during
normal working hours at EPA's Central
Docket Section, Room 2903B, Waterside
Mall, 401 M Street, S.W., Washington,
D.C. 20460.
Docket
The docket, containing all supporting
information used by EPA to date, is
available for inspection and copying
between 8:00 a.m. and 4:00 p.m., Monday
through Friday, at EPA's Central Docket
Section, room 2903B, Waterside Mall,
401 M Street, S.W., Washington, D.C.
20460.
The docket is an organized and
complete file of all the information
submitted to or otherwise considered by
EPA in the development of the
rulemaking. The docket is a dynamic
file, since material is added throughout
the rulemaking development.
The docketing system is intended to
aiiow members of the public and
industries involved to readily identify
and locate documents so that they can
intelligently and effectively participate
in the rulemaking process. On judicial
review, the record will consist of all
materials in the docket except for
certain interagency review materials
(section 307(d)(7)(A) of the Act).
Miscellaneous
In accordance with section 117 of the
Act, publication of these proposed
standards was preceded by consultation
with appropriate advisory committees,
independent experts, and Federal
departments and agencies. The
Administrator will welcome comments
on all aspects of the proposed
regulation, including economic and
technological issues, and on the
proposed test method.
It should be noted that standards of
performance for new sources
established under section 111 of the
Clean Air Act reflect:
* * * application of the best adequately
demonstrated technological system of
continuous emission reduction which (taking
into consideration the cost of achieving such
emission reduction, any nonair quality health
and environmental impact, and energy
requirements) the Administrator determines
has been adequately demonstrated (section
Although there may be emission
control technology available that can
reduce emissions below those levels
required to comply with standards of
performance, this technology might not
be selected as the basis of standards of
performance because of costs
associated with its use. Accordingly,
standards of performance should not be
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Federal Register / Vol. 45, No. 9 / Monday, January 14, 1980 / Proposed Rules
viewed as the ultimate in achievable
emission control. In fact, the Act
requires (or has the potential for
requiring) the imposition of a more
stringent emission standard in several
situations.
For example, applicable costs do not
necessarily play as prominent a role in
determining the "lowest achievable
emissions rate" for new or modified
sources located in nonattainment areas,
i.e., those areas where statutorily
mandated health and welfare standards
are being violated.
In this respect, section 173 of the Act
requires that a new or modified source
constructed in an area that exceeds the
National Ambient Air Quality Standards
(NAAQS) must reduce emissions to the
level which reflects the "lowest
achievable emission rate" (LAER), as
defined in section 171(3), for such
category of source. The statute defines
LAER as that rate of emissions based on
the following, whichever is more
stringent:
(A) the most stringent emission limitation
which is contained in the implementation
plan of any State for such class or category of
source, unless the owner or operator of the
proposed source demonstrates that such
limitations are not achievable, or
(B) the most stringent emission limitation
which is achieved in practice by such class or
category of source.
In no event can the emission rate exceed
any applicable new source performance
standard [section 171(3)].
A similar situation may arise under
the prevention of significant
deterioration of air quality provisions of
the Act (Part C). These provisions
require that certain sources [referred to
in section 169(1)] employ "best available
control technology" [as defined in
section 163(3)] for all pollutants
regulated under the Act. Best available
control technology (BACT) must be
determined on a case-by-case basis,
taking energy, environmental and
economic impacts, and other costs into
account. In no event may the application
of BACT result in emissions of any
pollutants that will exceed the emissions
allowed by any applicable standard
established pursuant to section 111 (or
112) of the Act.
In all events, State Implementation
Plans (SIP's) approved or promulgated
under section 110 of the Act must
provide for the attainment and
maintenance of NAAQS designed to
protect public health and welfare. For
this purpose, SIP's must in some cases
required greater emission reductions
than those require by standards of
performance of new sources.
Finally, States are free under section
116 of the Act to establish even more
stringent emission limits than those
established under section 111 or those
necessary to attain or maintain the
NAAQS under section 110. Accordingly,
new sources may in some cases be
subject to limitations more stringent
than EPA's standards of performance
under section 111, and prospective
owners and operators of new sources
should be aware of this possibility in
planning for such facilities.
EPA will review this regulation 4
years from the date of promulgation.
This review will include an assessment
of such factors as the need for
integration with other programs, the
existence of alternative methods,
enforceability, and improvements in
emission control technology.
Section 317 of the Clean Air Act
requires the Administrator to prepare an
economic impact assessment for any
new source standard of performance
promulgated under section lll(b) of the
Act. An economic impact assessment
was prepared for the proposed
regulations and for other regulatory
alternatives. All aspects of the
assessment were considered in the
formulation of the proposed standards
to insure that the proposed standards
would represent the best system of
emission reduction considering costs.
The economic impact assessment is
included in the background information
document.
Dated: December 19,1979.
Douglas M. Costle,
Administrator.
It is proposed that 40 CFR Part 60 be
amended by adding a new Subpart KK
and by adding a new reference method
to Appendix A as follows:
1. A new subpart KK is added as
follows:
Subpart KKStandards of
Performance for Lead-Acid Battery
Manufacturing Plants
Sec.
60.370 Applicability and designation of
affected facility.
60 371 Definitions.
60.372 Standards for lead.
60.373 Monitoring of emissions and
operations.
60.374 Test methods and procedures.
Authority: Sec. Ill, 301(a), Clean Air Act
as amended [42 U.S.C. 7411, 7601(a)], and
additional authority as noted below.
Subpart KKStandards of
Performance for Lead-Acid Battery
Manufacturing Plants
§ 60.370 Applicability and designation of
affected facility.
(a) The provisions of this subpart are
applicable to the affected facilities listed
in paragraph (b) of this section at any
lead-acid battery manufacturing plant
that has the capacity to produce 500 or
more batteries per day (24 hours).
(b) The provisions of this subpart are
applicable to the following affected
facilities used in the manufacture of
lead-acid storage batteries:
(1) Grid casting facility
(2) Paste mixing facility
(3) Three-process operation facility
(4) Lead oxide manufacturing facility
(5) Lead reclamation facility
(6] Other lead-emitting operations
§ 6Q.371 Definitions.
As used in this subpart, all terms not
defined herein shall have the meaning
given them in the Act and in Subpart A
of this part.
(a) "Grid casting facility" means the
facility which includes both lead melting
pots and machines used for casting the
grids used in battery manufacturing.
(b) "Lead-add battery manufacturing
plant" means any plant that produces a
storage battery using lead and lead
compounds for the plates and sulfuric
acid for the electrolyte.
(c) "Lead oxide manufacturing
facility" means the facility that produces
lead oxide from lead, including product
recovery.
(d) "Lead reclamation facility" means
the facility that remelts lead scrap and
casts it into lead ingots for use in the
battery manufacturing process, and
which is not a furnace affected under
Subpart L of this part.
(e) "Other lead-emitting operation"
means any lead-acid battery
manufacturing plant operation from
which lead emissions are collected and
ducted to the atmosphere and which is
not part of a grid casting, lead oxide
manufacturing, lead reclamation, paste
mixing, or three-process operation
facility, or a furnace affected under
Subpart L of this part.
(f) "Paste mixing facility" mesns the
facility including charging and blending
of the ingredients to produce a lead
oxide paste.
(g) "Three-process operation facility"
means the facility including those
processes involved with plate stacking,
burning or strap casting, and assembly
of elements into the battery case.
§ 60.372 Standards for lead.
(a) On and after the date on which the
performance test required to be
conducted by § 60.8 is completed, no
owner or operator subject to the
provisions of this subpart shall cause to
be discharged into the atmosphere:
(1) From any grid casting facility any
gases that contain lead in excess of 0.05
milligram of lead per dry standard cubic
meter of exhaust (0.00002 gr/dscf)-
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(2) From any paste mixing facility any
g-isrs that contain in excess of 1.00
nv.lligiam of lead per dry standard cubic
meter of exhaust (0.00044 gr/dscf).
(3) From any three-process operation
facility any gases that contain in excess
of 1.00 milligram of lead per dry
standard cubic meter of exhaust (0.00044
gr/dscf).
(4) From any lead oxide
manufacturing facility any gases that
contain in excess of 5.0 milligrams of
lead per kilogram of lead feed (0.010 lb/
ton).
(5) From any lead reclamation facility
any gases that contain in excess of 2.00
milligrams of lead per dry standard
cubic meter of exhaust {0.00088 gr/dscf).
(6) From any other lead-emitting
operation any gases that contain in
excess of 1.00 milligram per dry
standard cubic meter of exhaust (0.00044
gr/dscf).
(7) From any affected facility any
gases with greater than 0 percent
opacity (measured according to Method
9 and rounded to the nearest whole
percentage).
(b) When two or more facilities at the
same plant (except the lead oxide
manufacturing facility) are ducted to a
common control device, and equivalent
standard for the total exhaust from the
commonly controlled facilities shall be
determined as follows:
S, =
Where:
Se is the equivalent standard for the total
exhaust stream.
S, 18 the actual standard for each exhaust
stream ducted to the control device.
N is the total number of exhaust streams
ducted to the control device.
Qsd|) is t!:e dry standard volumetric flow rate
of the e'f.uent gas stream from each
facility ducted to the control device.
Qhdr is the total dry standard volumetric flow
rate of all effluent gas streams dueled to
the control device.
§ 60.373 Monitoring of emissions and
operations.
The owner or operator of any lead-
acid battery manufacturing plant subject
to the provisions of this subpart shall
install, calibrate, maintain, and operate
a monitoring device(s) that continuously
measures and premanently records the
toted pressure drop across the process
emissions control system. The
monitoring device shall have an
r is the lead emission concentration for
the entire facility.
N is the number of control devices to which
separate operations in the facility are
ducted.
C|.b is the emission concentration from each
conlroi device.
QKlt(i is the dry standard volumetric flow rate
of tf.e effluent gas stream trom each
control device.
Qsdl is the total dry standard volumetric flow
rate from all of the control devices.
(e] For lead oxide manufacturing
facilities, the average lead feed rate to a
facility, expressed in kilograms per hour,
shall be determined for each test run as
follows:
(1) Calculate the total amount of lead
charged to the facility during the run by
multiplying the number of lead pigs
(ingots) charged during the run by the
average mass of a pig in kilograms or by
another suitable method.
(2) Divide the total amount of lead
charged to the facility during the run by
the duration of the run in hours.
(f) Lead emissions from lead oxide
manufacturing facilities, expressed in
milligrams per kilogram of lead charged.
shall be determined using the following
equation:
£ = CwCVF
Where:
£,. is the lead emission rate from the facility
in milligrams per kilogram of lead
charged.
Cn is the concentration of lead in the exhaust
stream in milligrams per dry standard
cubic meter as determined according to
paragraph (a)(l) of this section.
Qsd is the dry standard volumetric flow rate
in dry standard cubic meters per hour as
determined according to paragraph (a)(3)
of this section.
F is the lead feed rate to the facility in
kilograms per hours as determined
according to paragraph (e) of this section.
(Section 114 of the Clean Air Act as amended
(42 U.S.C. 7414))
2. Appendix A to Part 60 is amended
by adding new Reference Method 12 as
follows:
Appendix AReference Methods
*****
Method 12. Determination of Inorganic Lead
Emissions from Stationary Sources
1. Applicability and Principle
11 Applicability. This method applies to
the determination of inorganic lead (Pb)
emissions from specified stationary sources
only.
1.2 Principle. Particulate and gaseous Pb
emissions are withdrawn isokinetically from
the source and coliected on a filter and in
dilute nitric acid. The collected samples are
digested in acid solution and analyzed by
atomic absorption spectrometry using an air
acetylene flame.
2 Range. Sensitivity, Precision, and
interferences
2.1 Flange. For a minimum analytical
accuracy of ±10 percent, the lower limit of
the range is 100 ng. The upper limit can be
considerably extended by dilution.
2.2 Analytical Sensitivity. Typical
sensitivities for a 1-percent change in
absorption (0.0044 absorbance units) are 0.2
and 0.5 fig Pb/ml for the 217.0 and 283.3 nm
lines, respectively.
2.3 Precision. The within-laboratory
precision, as measured by the coefficient of
variation ranges from 0.2 to 9.5 percent
relative to a run-mean concentration. These
values were based on tests condufed at a
gray iron foundry, a lead storage b.'.'u-ry
manufacturing plant, a secondary k;,d
smelter, and a lead rivoxerv furnace of an
alk\l lead manufacturing pl:.n! Iht:
concentrations encountered during these
tests ranged from 0.61 to 123.3 mg Pli/ms.
2.4 Interferences. Sample matrix effects
may interfere with the analysis for Pb by
flume atomic absorption. If this interference
is suspected, the analjst may confirm the
presence of these matrix effects and
frequently eliminate the interference by using
the Method of Standard Additions.
High concentrations of copper may
interfere with the analysis of Pb at 217.0 nm.
This interference can be avoided by
analyzing the samples at 2B3.3 nm.
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3. Appoiatus
3.1 Sampling Train. A schematic of the
sampling tram is shown in Figure 12-1; it is
similar to the Method 5 train. The sampling
train consists of the following components:
3.1.1 Probe Nozzle, Probe Liner, Pilot
Tube, Differential Pressure Gauge, Filter
Holder, Filter Heating System, Metering
System, Barometer, and Gas Density
Determination Equipment. Same as Method
5, Sections 2.1.1 to 2.1.6 and 2.1,8 to 2.1.10,
respectively.
3.1.2 Jmpingers. Four impingers connected
in series with leak-free ground glass fittings
or any similar leak-free noncontaminating
fittings. For the first, third, and fourth
impingers, use the Greenburg-Smith design,
modified by replacing the tip with a 1.3 cm
('/s in.) ID ghss tube extending to about 1.3
cm ('/a in.) from the bottom of the flask. For
the second impinger, use the Greenburg-
Smith design with the standard tip. Place a
thermometer, capable of measuring
temperature to within 1'C (2°F) at the outlet
of the fourth impinger for monitoring
purposes.
TEMPERATURE SENSOR
PROBE
TEMPERATURE
SENSOR
PROBE /\
HEATED AREA THERMOMETER
THERMOMETER
PITOTTUBE
REVERSE TYPE j
PITOTTUBE I
IMPINGERS ICE BATH
BY-PASS VALVE
CHECK
VALVE
VACUUM
LINE
PITOT MANOMETER
ORIFICE
VACUUM
GAUGE
THERMOMETERS
MAIN VALVE
DRY GAS METER
AIRTIGHT
PUMP
Figure 12-1. Inorganic lead sampling train.
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3.2 Sample Recovery. The following items
are needed:
3.2.1 Probe-Liner and Probe-Nozzle
Brushes, Petri Dishes, Plastic Storage
Containers, and Funnel and Rubber
Policeman. Same 88 Method 5, Sections 2.2.1,
2.2.4, 2.2.6, and 2.2.7, respectively.
3.2.2 Wash Bottles. Glass (2).
3.2.3 Sample Storage Container.
Chemically resistant, borosilicate glass
bottles, for 0.1 N nitric acid (HNO9) impinger
and probe solutions and washes, 1000-ml.
Use screw-cap liners that are either rubber-
backed Teflon ' or leak-free and resistant to
chemical attack by 0.1 N HNO.. (Narrow
mouth glass bottles have been found to be
less prone to leakage.)
3.2.4 Graduated Cylinder and/or Balance.
To measure condensed water to within 2 ml
or 1 g. Use a graduated cylinder that has a
minimum capacity of 500 ml, and
subdivisions no greater than 5 ml. (Most
laboratory balances are capable of weighing
to the nearest 0.5 g or less.)
3.2.5 Funnel. Glass, to aid in sample
recovery.
3.3 Analysis, The following equipment is
needed:
3.3.1 Atomic Absorption
Spectrophotometer. With lead hollow
cathode lamp and burner for air/acetylene
flame.
3.3.2 Hot Plate.
3.3.3 Erlenmeyer Flasks. 1 25-ml, 24/40 $.
3.3.4 Membrane Filters. Millipore SCWPO
4700 or equivalent.
3.3.5 Filtration Apparatus. Millipore
vacuum filtration unit, or equivalent, for use
with the above membrane filter.
3.3.6 Vomumetric Flasks. 100-ml, 250-ml,
and 1000-ml.
4. Reagents
4.1 Sampling. The reagents used in
sampling are as follows:
4.1.1 Filter. Gelman Spectro Grade, Reeve
Angel 934 AH, MSA 1106 BH, all with lot
assay for Pb, or other high-purity glass fiber
filters, without organic binder, exhibiting at
least 99.95 percent efficiency (<0.05 percent
penetration) on 0.3 micron dioctyl phthalate
smoke particles. Conduct the filter efficiency
test using ASTM Standard Method D 2986-71
or use lo?t data from the supplier's quality
control program.
4.1.2 Silica Gel, Crushed Ice, and
Stopcock Grease. Same as Method 5, Section
3.1.2, 3.1.4, and 3.1.5, respectively.
4.1.3 Water. Deionized distilled, to
conform to ASTM Specification D1193-74,
Type 3. If high concentrations of organic
matter are not expected to be present, the
analyst may delete the potassium
permanganate test for oxidizable organic
matter.
4.1.4 Nitric Acid, 0.1 N. Dilute 6.5 ml of
concentrated HNO, to liter 1 with deionized
distilled water. (It may be desirable to run
blanks before field use to eliminate a high
blank on test samples.)
4.2 Pretest preparation. 6 HNOS is
needed. Dilute 390 ml of concentrated HNO,
to 1 liter with deionized distilled water.
1I.isntion of trade names or specific products
does not constitute endorsement by the U.S.
Environmental Protection Agency.
4.3 Sample Recovery. 0.1 N HNOi (same
as 4.1.4 above) is needed for sample recovery.
4.4 Analysis. The following reagents are
needed for analysis (use ACS reagent grade
chemicals or equivalent, unless otherwise
specified):
4.4.1 Water. Same as 4.1.3 above.
4.4.2 Nitric Acid. Concentrated.
4.4.3 Nitric Acid, 50 percent (V/V). Dilute
500 ml of concentrated HNO, to 1 liter with
deionized distilled water.
4.4.4 Stock Lead Standard Solution, 1000
tig Pb/ml. Dissolve 0.1598 g of lead nitrate
[Pb(NO,)»] in about 60 ml of dionized distilled
water, add 2 ml concentrated HNOs, and
dilute to 100 ml with deionized distilled
water.
4.4.5 Working Lead Standards. Pipet 0.0,
1.0, 2.0, 3.0, 4.0. and 5.0 ml of the stock lead
standard solution (4.4.4) into 250-ml
volumetric flasks. Add 5 ml of concentrated
HNO, to each flask and dilute to volume with
deionized distilled water. These working
standards contain 0.0,4.0, 8.0,12.0,16.0, and
20.0 u.g Pb/ml, respectively. Prepare, as
needed, additional standards at other
concentrations in a similar manner.
4.4.6 Air. Suitable quality for atomic
absorption analysis.
4.4.7 Acetylene. Suitable quality for
atomic absorption analysis.
4.4.8 Hydrogen Peroxide, 3percent (V/V).
Dilute 10 ml of 30 percent H»O, to 100 ml with
deionized distilled water.
5. Procedure
5.1 Sampling. The complexity of this
method is such that, in order to obtain
reliable results, testers should be trained and
experienced with the test procedures.
5.1.1 Pretest Preparation. Follow the same
general procedure given in Method 5, Section
4.1.1, except the filter need not be weighed.
5.1.2 Preliminary Determinations. Follow
the same general procedure given in Method
5, Section 4.1.2.
5.1.3 Preparation of Collection Train.
Follow the same general procedure given in
Method 5, Section 4.1.3, except place 100 ml
of 0.1 HNOs in each of the first two
impingers, leave the third impinger empty,
and transfer approximately 200 to 300 g of
preweighed silica gel from its container to the
fourth impinger. Set up the train as shown in
Figure 12-1.
5.1.4 Leak-Check Procedures. Follow the
general leak-check procedures given in
Method 5, Sections 4.1.4.1 (Pretest Leak-
Check), 4.1.4.2 (Leak-Checks During the
Sample Run), and 4.1.4.3 (Post-Test Leak-
Check).
5.1.5 Sampling Train Operation. Follow
the same general procedure given in Method
5, Section 4.1.5. For each run, record the data
required on a data sheet such as the one
shown in EPA Method 5, Figure 5-2.
5.1.8 Calculation of Percent Isokinetic.
Same as Method 5, Section 4.1.6.
5.2 Sample Recovery. Begin proper
cleanup procedure as soon as the probe is
removed from the stack at the end of the
sampling period.
Allow the probe to cool. When it can be
safety handled, wipe off all external
particulate matter near the tip of the probe
nozzle and place a cap over it. Do not cap off
the probe tip tightly while the sampling train
is cooling down as this would create a
vacuum in the filter holder, thus drawing
liquid from the impingers into the filter.
Before moving the sampling train to the
cleanup site, remove the probe from the
sampling train, wipe off the silicone grease,
and cap the open outlet of the probe. Be
careful not to lose any condensate that might
be present. Wipe off the silicone grease from
the glassware inlet where the probe was
fastened and cap the inlet Remove the
umbilical cord from the last impinger and cap
the impinger. The tester may use ground-glaH
stoppers, plastic caps, or serum caps to close
these openings.
Transfer the probe and filter-impinger
assembly to a cleanup area, which is clean
and protected from the wind so that the
chances of contaminating or losing the
sample is minimized.
Inspect the train prior to and during
disassembly and note any abnormal
conditions. Treat the samples as follows:
5.2.1 Container No. 1 (Filter). Carefully
remove the filter from the filter holder and
place it in its identified petri dish container. If
it is necessary to fold the filter, do so such
that the sample-exposed side is inside the
fold. Carefully transfer to the petri dish any
visible sample matter and/or filter fibers that
adhere to the filter holder gasket by using a
dry Nylon bristle brush and/or a sharp-edged
blade. Seal the container,
6.2.2 Container No. 2 (Probe). Taking can
that dust on the outside of the probe or other
exterior surfaces does not get into the
sample, quantitatively recover sample matter
or any condensate from the probe nozzle,
probe fitting, probe liner, and front half of the
filter holder by washing these components
with 0.1 N HNO. and placing the wash into a
glass sample storage container. Measure and
record (to the nearest 2-ml) the total amount
of 0.1 N HNO. used for each rinse. Perform
the 0.1 N HNO. rinses as follows:
Carefully remove the prebe nozzle and
rinse the inside surfaces with 0.1 N HNO.
from a wash bottle while brushing with a
stainless steel, Nylon-bristle brush. Brush
until the 0.1 N HNO, rinse shows no visible
particles, then make a final rinse of the inside
surface.
Brush and rinse with 0.1 N HNO. the inside
parts of the Swagelok fitting in a similar way
until no visible particles remain.
Rinse the probe liner with 0.1 N HNO..
While rotating the probe so that all inside
surfaces will be rinsed with 0.1 N HNO,, tilt
the probe and squirt 0.1 N HNO. into its
upper end. Let the 0.1 N HNO. drain from the
lower end into the sample container. The
tester may use a glass runnel to aid in
transferring liquid washes to the container.
Follow the rinse with a probe brush. Hold the
probe in an inclined position, squirt 0.1 N
HNO, into the upper end of the probe as the
probe brush is being pushed with a twisting
action through the probe; hold the sample
container underneath the lower end of the
probe and catch any 0.1 N HNO. and sample
matter that is brushed from the probe. Run
the brush through the probe three times or
more until no visible sample matter is carried
out with the 0.1 N HNO, and none remains on
the probe liner on visual inspection. With
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Federal Register / Vol. 45, No. 9 / Monday, January 14, 1980 / Proposed Rules
stainless steel or other metal probes, run the
brush through in the above prescribed
manner at least six times, since metal probes
have small crevices in which sample matter
can be entrapped. Rinse the brush with 01 N
HNOj and quantitatively collect these
washings in the sample container. After the
brushing make a final rinse of the probe as
described above.
it is recommended that two people clean
the probe to minimize loss of sample.
Between sampling runs, keep brushes clean
and picitected from contamination.
After insuring that all joints are wiped
clean of siiicone grease, brush and rinse with
0.1 N HNO> the inside ot the front half of the
filter holder. Brush and rinse each surface
three times or more, if needed, to remove
visible sample matter. Make a final rinse of
the brush and filter holder. After ail 01 N
HNO» washings and sample matt are
collected in the sample container, tighten the
lid on the sample container so that the fluid
will not leak out when it is shipped to the
laboratory. Mark the height of the fluid level
to determine whether leakage occurs during
transport. Label the container to clearly
identify its contents.
5.2.3 Container No. 3 (Silica Cell. Check
the color of the indicating silica gel to
determine if it has been completely spent and
make a notation of its condition. Transfer the
silica gel from the fourth impinger to the
original container and seal. The tester may
use a funnel to pour the silica gel and a
rubber policeman to remove the silica gel
from the impinger. It is not necessary to
remove the small amount of particles that
may adhere to the walls and are difficult to
remove. Since the gain in weight is to be used
for moisture calculations, do not use any
water or other liquids to transfer the silica
gel. If a balance is available in the field, the
tester may follow procedure for Container
No. 3 under Section 5 4 (Analysis).
5.2.4 Container No, 4 (Impingers) Due to
the large quantity of liquid involved, the
tester may place the impinger solutions in
several containers. Clean each of the first
three impir.gers and connecting glassware in
the following manner:
1. Wipe the impinger bdll joints free of
siiicone grease and cap the joints.
2. RMcile and agitate each impinger, so that
the irr.pifisjer contents might serve as a rinse
solution.
3. Transfer the contents of the impingers to
a 500-ml graduated cylinder. Remove the
outlf.-t ball joint cap and drain the contents
through this opening. Do not separate the
impinger parts (inner and outer tubes) while
transferring their contents to the cylinder.
Measure the liquid volume to within ± 2 ml.
Alternatively, determine the weight of the
liquid to within ± 0.5 g Record in the log the
volume or weight of the liquid present, along
with a notation of any color or film observed
in the impinger catch. The liquid volume or
weight is needed, along with the silica gel
data, to calculate the stack gas moisture
content (see Method 5, Figure 5-3).
4. Transfer the contents to Container No. 4.
5. Note: In steps 5 and 6 below, measure
and record the total amount of O.I N H.\'O3
used for rinsing. Pour approximately 30 mi of
0.1 N HNOi into each of the first three
impingers and agitate the impingers. Drain
the 0.1 N HN'Oj through the outlet arm of
each impinger into Container No. 4. Repeat
this operation a second time; inspect the
irn; :ngers for any abnormal conditions.
6. Wipe the ball joints of the glassware
connecting the impingers free of siiicone
grtjse and rinse each piece of glassware
twice with 0.1 N HNOa: transfer this rinse
into Container No. 4. (Do not rinse or brush
the gloss-fritted filter support.} Mark the
height of the fluid level to determine whether
leakage occuis during transport Label the
container to clearly identify its contents.
5.2.5 Blanks. Save 200 ml of the 0.1 N
HXOj used for sampling and cleanup as a
bhnk. Take the solution directly from the
bottle being used and place into a glass
Scimp'e container labeled "0.1 N HNOa
blank."
5 3 Sample Preparation.
5.3.1 Container No. 1 (Filter). Cut the filter
into strips and transfer the strips and all
loose pailiculatc matter into an 125-ml
E'ienmeyer flask. Rinse the petri dish with 10
ml of 50 percent HNO3 to insure a
quantitative transfer and add to the flask.
(\'ote. If the total volume required in Section
5 3.3 is expected to exceed 80 ml, use a 250-ml
Erlenmej er flask in place of the 125-nil Husk.)
5 3.2 Containers No, 2 and No. 4 (Probe and
ImpingiTs). (Check the liquid level in
Containers No. 2 and/or No. 4 and confirm as
to whether or not leakage occurred during
transport; note observation on the analysis
sheet. If a noticeable amount of leakage had
occurred, either void the sample or take
steps, subject to the approval of the
Administrator, to adjust the final results.)
Combine the contents of Containers No. 2
and \o. 4 and take to diyncss on a hot plate.
5.3.3 Sample Extraction for Lead. Based
on the approximate stack gas parliculdte
concentration and the total volume of stack
gas sampled, estimate the total weight of
pnriicula'.e sample collected. Then transfer
the residue from Containers No. 2 and No. 4
to the 12Vml Erlenmeyer flask tlut contains
the filter using rubber policeman and 10 mi of
50 percent HNOS for every 100 mg of sample
co'lectfd in the train or a minimum of 30 ml
of &0 percent HNO3. whichever is laiger.
Place the Erlenmeyer fl«isk on a hot plate
and heat with periodic stirring for 30 roin at a
tempprature just below boiling l! the s.trrtple
voUur,^ falls below 15 ml, add more 50
pr-cenl HNO3. Add 10 ml of 3 percent I (2O2
and continue heating for 10 mm. Add 50 ml of
hot (30°C) deionized distilled water and heat
foi 20 min. Remove the flask from the hot
plate and allow to cool. Filter the sample
through a Millipore membrane filter or
equivalent and transfer the filtrate to a 250-
ml volumetric flask. Dilute to volume wish
de.om/t-d distilled water.
534 filter Blank. Determine a filter bltmk
ur.in« two filters from each lot of filters used
in the sampling tram. Cut each filter into
stiips and place efioh filter in a separate 125-
m! Erlenrnpypt fljsk. Add 15 ml of 50 percent
H.\O3 and Ue.it as described in Section 5.3 3
us;ne 10 ml of 3 percent li,Q: and 50 ml of
hot, deuiMxed distilled water. Filter and
dilute In a total volume of 10U ml using
di.inni7<;d distilled water.
5/3.5 0.1 A' W.'vOa Blank. Take the entire
200 ml of 0 1 N HNOj to drvni ss on a steam
bath, ddd 15 ml of 50 percent HNO3, and (rent
as described in Section 5.3 3 using 10 m! of 3
percent }i,O, and 50 ml of hot, deionized
distilled water. Dilute to a total volume of 100
ml using deionized distilled water.
5.4 Analysis.
5.4 1 Lead Determination. Calibrate the
Epectrophotomcter as described in Section 6.2
and determine the absorbance for each
source sample, the filter blank, and 0.1 N
Hf\O3 blank. Analyze each sample three
times in this manner. Make appropriate
dilutions, as required, to bring all sample Pb
concentrations into the linear absorbance
range of the spectrophotometer.
If the Pb concentration of a sample is at the
low end of the calibration curve and high
accuracy is required, the sample can be taken
to dryness on a hot plate and the residue
dissolved in the appropriate volume of water
to bnr.g it into the optimum range of the
calibration curve.
5.4.2 Mandatory Check for Matrix Effects
on the Lead Results. The analysis for Pb by
atomic absorption is sensitive to the chemical
composition and to the physical properties
(viscosity, pH) of the sample (matrix effects).
Since the Pb procedure described here will be
applied to many different sources, many
sample matiices will be encountered. Thus,
check (mandatory'} at least one sample from
each souice using the Method of Additions to
ascertain that the chemical composition and
physical properties of the sample did not
cause erroneous analytical results.
Three acceptable "Method of Additions"
procedures are described in the General
Procedure Section of the Perkin Elmer
Corporation Manual (see Citation 9.1). If the
results of the Method of Additions procedure
on the source sample do not agree within 5
percent of the value obtained by the
conventional atomic absorption analysis,
then the tester nvjst reanalyze all samples
from the source using the Method of
Additions procedure.
5.4.3 Container No. 3 (Silica Get). The
tester may conduct this step in the field.
Weigh the spent silica gel (or silica gel plus
ipipinjji '.') to the nearest 0.5 g; record this
weight.
6. Calit'iolJon
Maintain a laboratory log of all
cahura'ions.
6.1 Sampling Train Calibration. Calibrate
the sampling train components according to
the indicated sections of Method 5. Probe
Nozrle (Section 5.1); Pilot Tube (Sec!;on 5.2);
Mtter'pg S>>tem (Section 5.3); Probe Heater
(Section 5.4): Temperature Gauges (Section
5.:); Lenk-Check of the Metering System
(Section 5 6); and Barometer (Section 5.7).
6.2 Spec.tropliolomp'ur. Measure the
alisoibance of the standard solutions using
the instrument settings recommended by the
specUophotometer manufacturer. Repeat
until good agreement (± 3 percent) is
obtained between two consecutive readings
Plot the dbsoibane.e (y-axis) versus
concentration in ng Pb/m! (x-axis). Draw or
compute a straight line through the linear
portion of the cm vi:. Do no! force the
calibration curve ilirouyi 1'fro, but if the
curve does not pass thrcn-gli the origin or at
IfKst he closer to the origin than ± 0.003
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Federal Register / Vol. 45, No. 9 / Monday, January 14, 1980 / Proposed Rules
absorbance units, check for incorrectly
prepared standards and for curvature in the
calibration curve.
To determine stability of the calibration
curve, run a blank and a standard after every
five samples and recalibrate, as necessary.
7. Calculations
7.1 Dry Gas Volume. Using the data from
this test, calculate Vm, the total volume of
dry gas metered corrected to standard
conditions (20 °C and 760 mm Hg), by using
Equation 5-1 of Method 5. If necessary, adjust
Vm(,Ki) for leakages as outlined in Section 6.3
of Method 5. See the field data sheet for the
average dry gas meter temperature and
average orifice pressure drop.
7.2 Volume of Water Vapor and Moisture
Content. Using data obtained in this test and
Equations 5-2 and 5-3 of Method 5, calculate
the volume of water vapor V^,^ and the
moisture content Bw, of the stack gas.
7.3 Total Lead in Source Sample. For
each source sample correct the average
absorbance for the contribution of the filter
blank and the 0.1 N HMO, blank. Use the
calibration curve and this corrected
absorbance to determine the ng Pb
concentration in the sample aspirated into
the spectrophotometer. Calculate the total Pb
content C°Pb ('n Hg) in the original source
sample; correct for all the dilutions that were
made to bring the Pb concentration of the
sample into the linear range of the
spectrophotometer.
7.4 Lead Concentration. Calculate the
stack gas Pb concentration Cn in mg/dscm
as follows:
Cn,=K
c-rb
Eq.12-1
Where:
K=0.001 mg/ng for metric units.
= 2.205 lb/fig for English units.
7.5 Isokinetic Variation and Acceptable
Results. Same as Method 5, Sections 6.11 and
6.12, respectively. To calculate v,, the average
stack gas velocity, use Equation 2-9 of
Method 2 and the data from this field test.
A Alternative Test Methods for Inorganic
Lead
8.1 Simultaneous Determination of
Particulate and Lead Emissions. The tester
may use Method 5 to simultaneously
determine Pb provided that (1) he uses 0.1 N
HNO3 in the impingers, (2) he uses a glass
fiber filter with a low Pb background, and (3)
he treats and analyzes the entire train
contents, including the impingers, for Pb as
described in Section 5 of this method.
8.2 Filter Location. The tester may use a
filter between the third and fourth impinger
provided that he includes the filter in the
analysis for Pb.
8.3 In-stock Filter. The tester may use an
in-stack filter provided that (1) he uses a
glass-lined probe and at least two impingers,
each containing 100 ml of 0.1 N HNO3, after
the in-stack filter and (2) he recovers and
analyzes the probe and impinger contents for
Pb.
ft Bibliography
9.1 Perkin Elmer Corporation. Analytical
Methods for Atomic Absorption
Spectrophotometry. Norwalk, Connecticut.
September 1976.
9.2 American Society for Testing and
Materials. Annual Book of ASTM Standards.
Part 31; Water, Atmospheric Analysis.
Philadelphia, Pa. 1974. p. 40-42.
9.3 Klein. R. and C. Hack. Standard
AdditionsUses and Limitations in
Spectrophotometric Analysis. Amer. Lab.
9:21-27.1977.
9.4 Mitchell, W. J. andM. R. Midgett.
Determining Inorganic and Alkyl Lead
Emissions from Stationary Sources. U.S.
Environmental Protection Agency, Emission
Monitoring and Support Laboratory. Research
Triangle Park, NC. (Presented at National
APCA Meeting. Houston. June 26,1978.)
9.5 Same as Method 5, Citations 2 to 5
and 7 of Section 7.
*****
(Sections 111, 114, and 301(a) of the Clean Air
Act as amended (42 U.S.C. 7411, 7414, and
7601(a)))
(FR Doc. 80-1078 Filed 1-11-80; &45 am)
BILLING CODE 6560-01-M
V-KK-13
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ENVIRONMENTAL
PROTECTION
AGENCY
STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
AUTOMOBILE AND LIGHT-DUTY TRUCK
SURFACE COATING OPERATIONS
SUBMRTMM
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Federal Register / Vol. 44, No. 195 / Friday. October 5.1979 / Proposed Rules
40 CFR Part 60
[FRL-1285-4]
Automobile and Light-Duty Truck
Surface Coating Operations;
Standards of Performance
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Proposed rule.
SUMMARY: Standards of performance are
proposed to limit emissions of volatile
organic compounds (VOC) from new,
modified, and reconstructed automobile
and light-duty truck surface coating
operations within assembly plants.
Three new test methods are also
proposed. Reference Method 24
(Candidate 1 or Candidate 2) would be
used to determine the VOC content of
coating materials, and Reference
Method 25 would be used to determine
the percentage reduction of VOC
emissions achieved by add-on emission
control devices.
The standards implement the Clean
Air Act and are based on the
Administrator's determination that
automobile and light-duty truck surface
coating operations within assembly
plants contribute significantly to air
pollution. The intent is to require new,
modified, and reconstructed automobile
and light-duty truck surface coating
operations to use the best demonstrated
system of continuous emission
reduction, considering costs, nonair
quality health, and environmental and
energy impacts.
A public hearing will be held to
provide interested persons an
opportunity for oral presentation of
data, views, or arguments concerning
the proposed standards.
DATES: Comments. Comments must be
received on or before December 14,
1979
Public Hearing. The public hearing
will be held on November 9. 1979, at 9
a.m.
Request to Speak at Hearing. Persons
wishing to present oral testimony should
contact EPA by November 2,1979
ADDRESSES: Comments. Comments
should be submitted to: Central Docket
Section (A-130), Attention: Docket
Number A-79-05, U.S. Environmental
Protection Agency, 401 M Street SW.,
Washington, D.C. 20460.
Public Hearing. The public hearing
will be held at National Environmental
Resource Center (NERC), Rm. B-102,
R.T.P., N.C. Persons wishing to present
oral testimony should notify Ms. Shirley
Tabler, Emission Standards and
Engineering Division (MD-13),
Environmental Protection Agency,
Research Triangle Park, North Carolina
27711, telephone number (919) 541-5421.
Background Information Document.
The Background Information Document
(BID) for the proposed standards may be
obtained from the U.S. EPA Library
(MD-35), Research Triangle Park. North
Carolina 27711, telephone number (919)
541-2777. Please refer to "Automobile
and Light-Duty Truck Surface Coating
OperationsBackground Information
for Proposed Standards," EPA-450/3-
79-030.
Docket. The Docket, number A-79-05.
is available for public inspection and
copying at the EPA's Central Docket
Section, Room 2903 B, Waterside Mall,
Washington, D.C. 20460.
FOR FURTHER INFORMATION CONTACT:
Mr. Don R. Goodwin, Director, Emission
Standards and Engineering Division
(MD-13), Environmental Protection
Agency, Research Triangle Park, North
Carolina 27711, telephone number (919)
541-5271.
SUPPLEMENTARY INFORMATION:
Proposed Standards
The proposed standards would apply
to new automobile and light-duty truck
surface coating operations. Existing
plants would not be covered unless they
undergo modifications resulting in
increased emissions or reconstructions.
The proposed standards would apply to
each prime coat operation, each guide
coat operation, and each topcoat
operation within an assembly plant.
Emissions of VOC from each of these
operations would be limited as follows:
0.10 kilogram of VOC (measured as
mass of carbon) per liter of applied
coating solids from prime coat
operations. 0.84 kilogram of VOC
(measured as mass of carbon) per liter
applied coating solids from guide coat
operations, 0.84 kilogram of VOC
(measured as mass of carbon) per liter
of applied coating solids from topcoat
operations.
These proposed emission limits are
based on Method 24 (Candidate 1)
which determines VOC content of
coatings expressed as the mass of
carbon. At the time the standards were
developed, it was believed that VOC
emissions should be determined from
carbon measurements. Method 24
(Candidate 1) was developed to measure
carbon directly and thus improve the
accuracy of the previously used ASTM
procedure D 2369-73, which measures
the mass of volatile organics indirectly.
However, questions have been raised
concerning the validity of using the
carbon method since the ratio of mass of
carbon to mass of VOC in solvents used
in automotive coatings varies over a
wide range. The effect which this
variation might have on the standards is
still being investigated. Method 24
(Candidate 2) was developed as a test
method for determining VOC emissions
from coating materials in terms of mass
of volatile organics and is also derived
from ASTM procedure D 2369-73. The
proposed emission limits, based on
Method 24 (Candidate 2) which
measures volatile organics, are. 0.16
kilogram of VOC per liter of applied
coating solids from prime coat
operations, and 1.36 kilogram of VOC
per liter of applied coating solids for
guide coat operations, and 1.36 kilogram
of VOC per liter of applied coating
solids from top coat operations. In order
to provide an opportunity for public
comment on both test methods, both are
being proposed, and the final selection
of a test method will be made before
promulgation, based on the comments
received.
Although the emission limits are
based on the use of water-based coating
materials in each coating operation, they
can also be met with solvent-based
coating materials through the use of
other control techniques, such as
incineration. Exemptions are included in
the proposed standards which
specifically exclude annual model
changeovers from consideration as
modifications.
Summary of Environmental, Energy, and
Economic Impacts
Environmental, energy, and economic
impacts of standards of performance are
normally expressed as incremental
differences between the impacts from a
facility complying with the proposed
standard and those for one complying
with a typical State Implementation
Plan (SIP) emission standard. In the case
of automobile and light-duty truck
surface coating operations, the
incremental differences will depend on
the control levels that will be required
by revised SIP's. Revisions to most SIP's
are currently in progress.
Most existing automobile and light-
duty truck surface coating operations
are located in areas which are
considered nonattainment areas for
purposes of achieving the National
Ambient Air Quality Standard (NAAQS)
for ozone. New facilities are expected to
locate in similar areas. States are in the
process of revising their SIP's for these
areas and are expected to include
revised emission limitations for
automobile and light-duty truck surface
coating operations in their new SIP's. In
V-MM-2
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Federal Register / Vol. 44, No. 195 /Friday, October 5, 1979 / Proposed Rules
revising their SIP'S the States are relying
on the control techniques guideline
document, "Control of Volatile Organic
Emissions from Existing Stationary
SourcesVolume II: Surface Coating of
Cans, Coil, Paper, Fabrics, Automobiles
and Light-Duty Trucks" (EPA-450/2-77-
088 [CTG]).
Since control technique guidelines are
not binding, States may establish
emission limits which differ from the
guidelines. To the extent Spates adopt
the emission limits recommended in the
control techniques guideline document
as the basis for their revised SIFs, the
proposed standards of performance
would have little environmental, energy,
or economic impacts. The actual
incremental impacts of the proposed
standards of performance, therefore,
will be determined by the final emission
limitations adopted by the States in
their revised SIP'S. For the purpose of
this rulemaking, however, the
environmental, energy, and economic
impacts of the proposed standards have
been estimated based on emission limits
contained in existing SIP'S.
In addition to achieving further
reductions in emissions beyond those
required by a typical SIP, standards of
performance have other benefits. They
establish a degree of national uniformity
to avoid situations in which some States
may attract industries by relaxing air
pollution standards relative to other
States. Further, standards of
performance improve the efficiency of
case-by-case determinations of best
available control technology (BACT) for
facilities located in attainment areas,
and lowest achievable emission rates
(LAER) for facilities located in
nonattainment areas, by providing a
starting point for the basis of these
determinations. This results from the
process for developing a standard of
performance, which involves a
comprehensive analysis of alternative
emission control technologies and an
evaluation and verification of emission
test methods. Detailed cost and
economic analyses of various regulatory
alternatives are presented in the
supporting documents for standards of
performance.
Based on emission control levels
contained in existing SIFs, the proposed
standards of performance would reduce
emissions of VOC from new, modified,
or reconstructed automobile and light-
duty truck surface coating operations by
about 80 percent. National emissions of
VOC would be reduced-by about 4,800
metric tons per year by 1983.
Water pollution impacts of the
proposed standards would be relatively
small compared to the volume and
quality of the wastewater discharged
from plants meeting existing SIP levels.
The proposed standards are based on
the use of water-based coating
materials. These materials would lead to
a slight increase in the chemical oxygen
demand (COD) of the wastewater
discharged from the surface coating
operations within assembly plants. This
increase in COD, however, is not great
enough to require additional wastewater
treatment capacity beyond that required
in existing assembly plants using
solvent-based surface coating materials.
The solid waste impact of the
proposed standards would be negligible
compared to the amount of solid waste
generated by existing assembly plants.
The solid waste generated by water-
based coatings, however, is very sticky,
and equipment cleanup is more time
consuming than for solvent-based
coatings. Solid wastes from water-based
coatings do not present any special
disposal problems since they can be
disposed of by conventional landfill
procedures.
National energy consumption would
be increased by the use of water-based
coatings to comply with the proposed
standards. The equivalent of an
additional 18,000 barrels of fuel oil
would be consumed per year at a typical
assembly plant. This is equivalent to an
increase of about 25 percent in the
energy consumption of a typical surface
coating operation. National energy
consumption would be increased by the
equivalent of about 72,000 barrels of fuel
oil per year in 1983. This increase is
based on the projection that four new
assembly plants will be built by 1983.
The proposed standards would
increase the capital and annualized
costs of new automobile and light-duty
truck surface coating operations within
assembly plants. Capital costs for the
four new facilities planned by 1983
would be_increased by approximately
$19 million as a result of the proposed
standards. The incremental capital costs
for control represent about 0.2 percent of
the $10 billion planned for capital
expenditures. The corresponding
annualized costs would be increased by
approximately $9 million in 1983. The
price of an automobile or light-duty
truck manufactured at a new plant
which complies with the proposed
standards of performance would be
increased by less than 1 percent. This is
considered to be a reasonable control
cost.
Modifications and Reconstructions
During the development of the
proposed standards, the automobile
industry expressed concern that changes
to assembly plants made only for the
purpose of annual model changeovers
would be considered a modification or
reconstruction as defined in the Code of
Federal Regulations, Title 40, Parts 60.14
and 60.15 (40 CFR 60.14 and 60.15). A
modification is any physical or
operational change in an existing facility
which increases air pollution from that
facility. A reconstruction is any
replacement of components of an
existing facility which is so extensive
that the capital cost of the new
components exceeds 50 percent of the
capital cost of a new facility. In general,
modified and reconstructed facilities
must comply with standards of
performance. According to the available
information, changes to coating lines for
annual model changeovers do not cause
emissions to increase significantly.
Further, these changes would normally
not require a capital expenditure that
exceeds the 50 percent criterion for
reconstruction. Hence, it is very unlikely
that these annual facility changes would
be considered either modifications or
reconstructions. Therefore, the proposed
standards state that changes to surface
coating operations made only to
accommodate annual model
changeovers are not modifications or
reconstructions. In addition, by
exempting annual model changeovers,
enforcement efforts are greatly reduced
with little or no adverse environmental
impact.
Selection of Source and Pollutants
VOC are organic compounds which
participate in atmospheric
photochemical reactions or are
measured by Reference Methods 24
(Candidate 1 or Candidate 2) and 25.
There has been some confusion in the
past with the use of the term
"hydrocarbons." In addition to being
used in the most literal sense, the term
"hydrocarbons" has been used to refer
collectively to all organic chemicals.
Some organics which are photochemical
oxidant precursors are not
hydrocarbons (in the strictest definition)
and are not always used as solvents. For
purposes of this discussion, organic
compounds include all compounds of
carbon except carbonates, metallic
carbides, carbon monoxide, carbon
dioxide and carbonic acid.
Ozone and other photochemical
oxidants result in'a variety of adverse
impacts on health and welfare, inducing
impaired respiratory function, eye
irritation, deterioration of materials such
as rubber, and necrosis of plant tissue.
Further information on these effects can
be found in the April 1978 EPA
document "Air Quality Criteria for
Ozone and Other Photochemical
Oxidants," EPA-600/8-78-004. This
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document can be obtained from the EPA
library (see Addresses Section),
Industrial coating operations are a
major source of air pollution emissions
of VOC. Most coatings contain organic
solvents which evaporate upon drying of
the coating, resulting in the emission of
VOC. Among the largest individual
operations producing VOC emissions in
the industrial coating category are
automobile and light-duty truck surface
coating operations. Since the surface
coating operations for automobiles and
light-duty trucks are very similar in
nature, with line speed being the
primary difference, they are being
considered together in this study.
Automobile and light-duty truck
manufacturers employ a variety of
surface coatings, most often enamels
and lacquers, to produce the protective
and decorative finishes of their product.
These coatings normally use an organic
solvent base, which is released upon
drying.
The "Priority List for New Source
Performance Standards under the Clean
Air Act Amendments of 1977," which
was promulgated in 40 CFR 60.16, 44 FR
49222. dated August 21,1979, ranked
sources according to the impact that
standards promulgated in 1980 would
have on emissions in 1990. Automobile
and light-duty truck surface coating
operations rank 27 out of 59 on this list
of sources to be controlled.
The surface coating operation is an
integral part of an automobile or light-
duty truck assembly plant, accounting
for about one-quarter to one-third of the
total space occupied by a typical
assembly plant. Surface coatings are
applied in two main steps, prime coat
and topcoat. Prime coats may be water-
based or organic solvent-based. Water-
based coatings use water as the main
carrier for the coating solids, although
these coatings normally contain a small
amount of organic solvent. Solvent-
based coatings use organic solvent as
the coating solids carrier. Currently
about half of the domestic automobile
and light-duty truck assembly plants use
water-based prime coats.
Where water-based prime coating is
used, it is usually applied by EDP. The
EDP coat is normally followed by a
"guide coat," which provides a suitable
surface for application of the topcoat.
The guide coat may be water-based or
solvent-based.
Automobile and light-duty truck
topcoats presently being used are
almost entirely solvent-based. One or
more applications of topcoats are
applied to ensure sufficient coating
thinkness. An oven bake may follow
each topcoat application, or the coating
may be applied wet on wet.
In 1976, nationwide emissions of VOC
from automobile and light-duty truck
surface coating operations totaled about
135,000 metric tons. Prime and guide
coat operations accounted for about
50,000 metric tons with the remaining
85,000 metric tons being emitted from
topcoat operations. This represents
almost 15 percent of the volative organic
emissions from all industrial coating
operations.
VOC comprise the major air pollutant
emmitted by automobile and light-duty
truck assembly plants. Technology ia
available to reduce VOC emissions and
thereby reduce the formation of ozone
and other photochemical oxidants.
Consequently, automobile and light-duty
truck surface coating operations have
been selected for the development of
standards of performance.
Selection of Affected Facilities
The prime coat, guide coat, and
topcoat operations usually account for
more than 80 percent of the VOC
emissions from autombile and light-duty
truck assembly plants. The remaining
VOC emissions result from final topcoat
repair, cleanup, and coating of various
small component parts. These VOC
emission sources are much more
difficult to control than the main surface
coating operations for several reasons.
First, water-based coatings cannot be
used for final topcoat repair, since the
high temperatures required to cure
water-based coatings may damage heat
sensitive components which have been
attached to the vehicle by this stage of
production. Second, the use of solvents
is required for equipment cleanup
procedures. Third, add-on controls, such
as incineration, cannot be used
effectively on these cleanup operations
because they are composed of numerous
small operations located throughout the
plant. Since prime coat, guide coat, and
topcoat operations account for the bulk
of VOC emissions from autombile and
light-duty truck assembly plants, and
control techniques for reducing VOC
emissions from these operations are
demonstrated, they have been selected
for control by standards of performance.
The "affected facility" to which the
proposed standards would apply could
be designated as the entire surface
coating line or each individual surface
coating operation. A major
consideration in selecting the affected
facility was the potential effect that the
modification and reconstruction
provisions under 40 CFR 60.14 and 60.15,
which apply to all standards of
performance, could have on existing
assembly plants. A modification is any
physical or operational change in an
existing facility which increase* air
pollution from that facility. A
reconstruction is any replacement of
components of an existing facility which
is so extensive that the capital cost of
the new coraponensts exceeds 50
percent of the capital cost of a new
facility. For standards of performance to
apply, EPA must conclude that it is
technically and economically feasible
for the reconstructed facility to meet the
standards.
Many automobile and light-duty truck
assembly plaiTts that have a spray prime
coat system will be switching to EDP
prime coat systems in the future to
reduce VOC emissions to comply with
revised SIP's. The capital cost of this
change could be greater than 50 percent
of the capital cost of a new surface
coating line. If the surface coating line
were chosen as the affected facility, and
if this switch to an EDP prime coat
system were considered a
reconstruction of the surface coating
line, all surface coating operations on
the line would be required to comply
with the proposed standards. Most
plants would be reluctant to install an
EDP prime coat system to reduce VOC
emissions if, by doing so, the entire
surface coating line might then be
required to comply with standards of
performance. By designating the prime
coat, guide coat, and topcoat operations
as separate affected facilities, this
potential problem is avoided. Thus, each
surface coating operation (i.e., prime
coat, guide coat, and topcoat) has been
selected as an affected facility in the
proposed standards.
Selection of Best System of Emission
Reduction
VOC emissions from automobile and
light-duty truck surface coating
operations can be controlled by the use
of coatings having a low organic solvent
content, add-on emissions control
devices, or a combination of the two.
Low organic solvent coatings consist of
water-based enamels, high solids
enamels, and powder coatings. Add-on
emission control devices consist of such
techniques as incineration and carbon
adsorption.
Control Technologies
Water-based coating materials are
applied either by conventional spraying
or by EDP. Application of coatings by
EDP involves dipping the automobile or
truck to be coated into a bath containing
a dilute water solution of the coating
material. When charges of opposite
polarity are applied to the dip tank and
vehicle, the coating material deposits on
the vehicle. Most EDP systems presently
in use are anodic systems in which the
vehicle is given a positive charge.
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Cathodic EDP. in which the vehicle is
negatively charged, is a now technology
which is expanding rapidly in the
automotive industry. Cathodic EDP
provides better corrosion resistance and
requires lower cure temperatures than
anodic systems. Cathodic EDP systems
are also capable of applying better
coverage on deep recesses of parts.
The prime coat is usually followed by
a spray application of an intermediate
coat, or guide coat, before topcoat
application. The guide coat provides the
added film thickness necessary for
sanding and a suitable surface for
topcoat application. EDP can only be
used if the total film thickness on the
metal surface does not exceed a limiting
value. Since this limiting thickness is
about the same as the thickness of the
prime coat, spraying has to be used for
guide coat and topcoat application of
water-based coatings.
Currently, nearly half of domestic
automobile and light-duty truck
assembly plants use EDP for prime coat
application, but only two domestic
plants use water-based coating for guide
coat and topcoat applications.
Coatings whose solids content is
about 45 to 60 percent are being
developed by a number of companies.
When these coatings are applied at high
transfer efficiency rates, VOC emissions
are significantly less than emissions
from existing solvent-based systems.
While these high solids coatings could
be used in the automotive industry,
certain problems must be overcome. The
high working viscosity of these coatings
makes them unsuitable for use in many
existing application devices. In addition,
this high viscosity can produce an
"orange peel," or uneven, surface. It also
makes these coatings unsuitable for use
with metallic finishes. Metallic finishes,
which account for about 50 percent of
domestic demand, are produced by
adding small metal flakes to the paint.
As the paint dries, these flakes become
oriented parallel to the surface. With
high solids coatings, the viscosity of the
painf prevents movement of the flakes.
and they remain randomly oriented,
producing a rough surface. However.
techniques such as heated application
are being investigated to reduce these
problems, and it is expected that by 1982
high solids coatings will be considered
technically demonstrated for use in the
automotive industry.
Powder coatings are a special class of
high solids coatings (hat consist of
solids only. They are applied by
electrostatic spray and are being used
on a limited basis for topcoating
automobiles, both foreign and domestic.
The use of powder coatings is severely
limited, however, because metallic
finishes cannot be appbed using
powder. As with other high solids
coatings, research is continuing in the
use of powder coatings for the
automotive industry.
Thermal incineration has been used to
control VOC emissions from bake ovens
in automobile and light-duty truck
surface coating operations because of
the fairly low volume and high VOC
concentration in the exhaust stream.
Incineration normally achieves a VOC
emission reduction of over 90 percent.
Thermal incinerators have not, however,
been used for control of spray booth
VOC emissions. Typically, the spray
booth exhaust stream is a high volume
stream [95,000 to 200,000 liters per
second) which is very low in
concentration of VOC (about 50 ppm).
Thermal incineration of this exhaust
stream would require a large amount of
supplemental fuel, which is its main
drawback for control of spray booth
VOC emissions. There are no technical
problems with the use of thermal
incineration.
Catalytic incineration permits lower
incinerator operating temperatures and,
therefore, requires about 50 percent less
energy than thermal incineration.
Nevertheless, the energy consumption
would still be high if catalytic
incineration were used to control VOC
emissions from a spray booth. In
addition, catalytic incineration allows
the owner or operator less choice in
selecting a fuel; it requires the use of
natural gas to preheat the exhaust gases,
since oil firing tends to foul the catalyst.
While catalytic incineration is not
currently being employed in automobile
and light-duty truck surface coating
operations for control of VOC
emissions, there are no technical
problems which would preclude its use
on either bake oven or spray booth
exhaust gases. The primary limiting
factor is the high energy consumption of
natural gas, if catalytic incineration is
used to control emissions from spray
booths.
Carbon adsorption has been used
successfully to control VOC emissions
in a number of industrial applications.
The ability of carbon adsorption to
control VOC emissions from spray
booths and bake ovens in automobile
and light-duty truck surface coating
operations, however, is uncertain. The
presence of a high volume, low VOC
exhaust stream from spray booths
would require carbon adsorption units
much larger than any that have ever
been built. For bake ovens in automobile
and light-duty truck surface coating
operations, a major impediment to the
use of carbon adsorption is beat. The
high temperature of the bake oven
exhaust stream would require the use of
refrigeration to cool the gas stream
before it passes through the carbon bed.
Carbon adsorption, therefore, is not
considered a demonstrated technology
at this time for controlling VOC
emissions from automobile and light-
duty truck surface coating operations.
Work is continuing within the
automotive industry on efforts to apply
carbon adsorption to the control of VOC
emissions, however, and it may become
a demonstrated technology in the near
future.
Regulatory Options
Water-based coatings and
incineration are two well-demonstrated
and feasible techniques for controlling
emissions of VOC from automobile and
light-duty truck surface coating
operations. Based upon the use of these
two VOC emission control techniques.
the following two regulatory options
were evaluated.
Regulatory Option I includes two
alternatives which achieve essentially
equivalent control of VOC emissions
Alternative A is based on the use of
water-based prime coats, guide coats.
and topcoats. The prime coat would be
applied by EDP. Since the guide coat is
essentially a topcoat material, guide
coat emission levels as low as those
achieved by water-based topcoats
should be possible through a transfer of
technology from topcoat operations to
guide coat operations. Alternative B is
based on the use of a water-based prime
coat applied by EDP and solvent-based
guide coats and topcoats. Incineration of
the exhaust gas stream from the topcoat
spray booth and bake oven would be
used to control VOC emissions under
this alternative.
Regulatory Option II is based on the
use of a water-based prime coat applied
by EDP and solvent-based guide coa'.s
and topcoats. In this option, the exhnust
gas streams from both the guide r.oat
and topcoat spray booths and bake
ovens would be incinerated !o control
VOC emissions
Environmental. Energy, and Economic
Impacts
Standards based on Reprl.ilory
Option I would lead to a reduction in
VOC emissions of about 80 percent, am!
standards based on Regulatory Option II
would lead to a reduction in emissions
of about 90 percent, compared to VOC
emissions from automobile and light-
duty truck surface coating operations
controlled to meet current SIP
requirements. Growth projections
indicate there will be four new
automobile and light-duty truck
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assembly lines constructed by 1983.
Very few, if any, modifications or
reconstructions are expected during this
period. Based on these projections,
national VOC emissions in 1983 would
be reduced by about 4,800 metric tons
with standards based on Regulatory
Option I and about 5,400 metric tons
with standards based on Regulatory
Option II. Thus, both regulatory options
would result in a significant reduction in
VOC emissions from automobile and
light-duty truck surface coating
operations.
With regard to water pollution,
standards based on Regulatory Option II
would have essentially no impact.
Similarly, standards based on
Regulatory Option I(B) would have no
water pollution impact. Standards based
on Regulatory Option I(A), however,
would result in a slight increase in the
chemical oxygen demand (COD) of the
wastewater discharged from automobile
and light-duty truck surface coating
operations within assembly plants. This
increase is due to water-miscible
solvents in the water-based guide coats
and topcoats which become dissolved in
the wastewater. The increase in COD of
the wastewater, however, would be
small relative to current COD levels at
plants using solvent-based surface
coatings and meeting existing SIP's. In
addition, this increase would not require
the installation of a larger wastewater
treatment facility than would be built for
an assembly plant which used solvent-
based surface coatings.
The solid waste impact of the
proposed standards would be negligible.
The volume of sludge generated from
water-based surface coating operations
is approximately the same as that
generated from solvent-based surface
coating operations. The solid waste
generated by water-based coatings,
however, is very sticky, and equipment
cleanup is more time consuming than for
solvent-based coatings. Sludge from
either type of system can be disposed of
by conventional landfill procedures
without leachate problems.
With regard to energy impact,
standards based on Regulatory Option
I(A) would increase the energy
consumption of surface coating
operations at a new automobile or light-
duty truck assembly plant by about 25
percent. Regulatory Option I(B) would
cause an increase of about 150 to 429
percent in energy consumption.
Standards based on Regulatory Option
II would result in an increase of 300 to
700 percent in the energy consumption
of surface coating operations at a new
automobile or light-duty truck assembly
plant. The range in energy consumption
for those options which are based on
use of incineration reflects the
difference between catalytic and
thermal incineration.
The relatively high energy impact of
standards based on Regulatory Option
I(B) and Regulatory Option II is due to
the large amount of incineration fuel
needed. Standards based on Regulatory
Option II would increase energy
consumption at a new automobile and
light-duty truck assembly plant by the
equivalent of about 200,000 to 500,000
barrels of fuel oil per year, depending
upon whether catalytic or thermal
incineration was used. Standards based
on Regulatory Option I(B) would
increase energy consumption by the
equivalent of about 100,000 to 300,000
barrels of fuel oil per year.
Standards based on Regulatory
Option 1(A) would increase the energy
consumption of a typical new
automobile and light-duty truck
assembly plant by the equivalent of
about 18,000 barrels of fuel oil per year.
Approximately one-third of this increase
in energy consumption is due to the use
of air conditioning, which is necessary
with the use of water-based coatings,
and the remaining two-thirds are due to
the increased fuel required in the bake
ovens for curing water-based coatings.
Growth projections indicate that four
new automobile and light-duty truck
assembly lines (two automobile and two
truck lines) will be built by 1983. Based
on these projections, standards based
on Regulatory Option I(A) would
increase national energy consumption in
1983 by the equivalent of about 72,000
barrels of fuel oil. Standards based on
Regulatory Option I(B) would increase
national energy consumption in 1983 by
the equivalent of 400,000 to 1,200,000
barrels of fuel oil, depending on whether
catalytic or thermal incineration were
used. Standards based on Regulatory
Option II would increase national
energy consumption in 1983 by the
equivalent of 800,000 to 2,000,000 barrels
of fuel oil, again depending on whether
catalytic or thermal incineration were
used.
The economic impacts of standards
based on each regulatory option were
estimated using the growth projection of
four new assembly lines by 1983.
Incremental control costs were
determined by calculating the difference
between the capital and annualized
costs of new assembly plants controlled
to meet Regulatory Options I(A), I(B),
and II, respectively, with the
corresponding costs for new plants
designed to comply with existing SIP's.
Of the four assembly plants protected by
1983, two were assumed to be lacquer
lines and the other two enamel line*.
There are basic design differences
between these two types of surface
coatings which have a substantial
impact on the magnitude of the costs
estimated to comply with standards of
performance. Lacquer surface coating
operations, for example, require much
larger spray booths and bake ovens than
enamel surface coating operations.
Water-based systems also require large
spray booths and bake ovens; thus, the
incremental capital cost of installing a
water-based system in a plant which
would otherwise have used a lacquer
system is relatively low. The
incremental capital costs differential,
however, would be much larger if the
plant would have been designed for an
enamel system.
Tables 1 and 2 summarize the
economic impacts of the proposed
standards on plants of typical sizes.
Table 1 presents the incremental costs
of the various control options for a plant
which would have used solvent-based
lacquers. Table 2 presents similar costs
for plants which would have been
designed to use solvent-based enamels.
Though these tables present incremental
costs for passenger car plants, light-duty
truck plants would have similar cost
differentials. In all cases, it is assumed
the plants would install a water-based
EDP prime system in the absence of
standards of performance. Therefore, no
incremental costs associated with EDP
prime coat operations are included in
the costs presented in Tables 1 and 2. A
nominal production rate of 55 passenger
cars per hour was assumed for both
plants. Tables 1 and 2 show incremental
capitalized and annualized costs per
vehicle produced at each new facility.
The manufacturers would probably
distribute these incremental costs over
their entire annual production to arrive
at purchase prices for the automobiles
and light-duty trucks.
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Table 1 iMCRLHENTAL CONTROL COSTS"
(Compa-ed to the Costs of a Lacquer Plant)
Regulatory Options
KB)
II
Water-Based Coatings Thermal
Catalytic
Thermal
Capital Cost of Control
Alternative
Annualized Cost of Control
Alternative
Incremental Cost/Vehicle
Produced at this Facility
$ 720,000
$1,550,000
$7 34
$68 66
$50 66
$73.39
Assumes a line speed of 55 vehicles per hour and an annual production of 211,200 vehicles
Table 2 INCREMENTAL CONTROL COSTS
(Compared to the Costs of an Enamel Plant)
Catalytic
$11.800,000 $15.000,000 $12,800,000 $16,200,000
$14.500.000 $10,700.000 $15,500.000 $11.500.000
4S
I (A)
Regulatory Options
KB)
Water-Based Coatings Thermal
Catalytic
II
Thermal
Capital Cost of Control
Alternative
Annualized Cost of Control
Alternative
Incremental Cost/Vehicle
Produced at this Facility
$10,300,000
$ 3,640,000
$17 23
$26.61
$19 65
$31.30
Catalytic
$ 4,630.000 $ 5,850,000 $ 5,640,000 $ 7.000.000
$ 5,620,000 $ 4,150,000 $ 6,610.000 $ 4,890.G',J
$?3 IS
Assumes a line speed of 55 vehicles per hour and an annual production of 211,200 vehicles.
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Incremental capital costs for suing
incineration to reduce VOC emissions
from solvent-based lacquer plants to
levels comparable to water-based plants
are much larger than they are for using
incineration on a solvent-based enamel
plant. This large difference in costs
occurs because lacquer plants have
larger spray booth and bake oven areas
than enamel plants and, therefore, a
larger volume of exhaust gases. Since
larger incineration units are required,
the incremental capital costs of using
incineration to control VOC emissions
from a solvent-based lacquer plant are
about 15 to 25 times greater than they
are for using water-based coatings.
Similarly, energy consumption is much
greater; hence, the annualized costs of
using incineration are about 10 times
greater than they are for using water-
based coatings.
On the other hand, the incremental
capital costs of controlling VOC
emissions from new solvent-based
enamel plants by the use of incineration
are only about one-half the incremental
capital costs between a new solvent-
based enamel plant and a new water-
based plant. Due to the energy
consumption associated with
incinerators, however, the incremental
annualized costs of using incineration
with solvent-based enamel coatings
could vary from as little as 15 percent
more to as much as 90 percent more
than the annualized costs of using
water-based coatings.
While the incremental capital costs of
building a plant to use water-based
coatings can be larger or smaller than
the costs of using incineration,
depending upon whether a solvent-
based lacquer plant or a solvent-based
enamel plant is used as the starting
point, the annualized costs of using
water-based coatings are always less
than they are for using incineration. This
is due to the large energy consumption
of incineration units compared to the
energy consumption of water-based
coatings.
Since the incremental annualized
costs are less with Regulatory Option
I(A) than with Regulatory Option 1(B), it
is assumed in this analysis that
Regulatory Option 1(A) would be
incorporated at any new, modified, or
reconstructed facility to comply with
standards based on Regulatory Option I.
As noted, four new assembly plants are
expected to be built by 1983. The
incremental capital cost to the industry
for these plants to comply with
standards based on Regulatory Option I
would be approximately $19 million. The
corresponding incremental annualized
costs would be about $9 million in 1983.
If standards are based on Regulatory
Option II, it is expected that the industry
would choose catalytic incineration
because its annualized costs are lower
than those for thermal incineration.
Based this assumption, the incremental
capital costs for the industry under
Regulatory Option II would be
approximately $42 million, and the
incremental annualized costs by 1983
would be about $30 million. For
standards based on either Regulatory
Option I or Regulatory Option II, the
increase in the price of an automobile or
light-duty truck that is manufactured at
one of the new plants would be less
than 1 percent of the base price of the
vehicle.
Best System of Emission Reduction
Both Regulatory Options I and II
achieve a significant reduction in VOC
emissions compared to automobile and
light-duty truck assembly plants
controlled to comply with existing SIP's,
and neither option creates a significant
adverse impact on other environmental
media. In terms of energy consumption,
standards based on Regulatory Option II
would have as much as 10 to 25 times
the adverse impact on energy
consumption as standards based on
Regulatory Option I, while only
achieving 10 to 15 percent more
reductions in VOC emissions. The costs
of standards based on Regulatory
Option II range from two to three times
the costs of standards based on
Regulatory Option I. Thus, Regulatory
Option I(A), water-based coatings, was
selected as the best system of
continuous emission reduction,
considering costs and nonair quality
health, and environmental and energy
impacts.
Although water-based coatings are
considered to be the best system of
emission reduction at the present time, it
is very likely that plants built in the
future will use other systems to control
VOC emissions, such as high solids
coatings and powder coatings. High
solids coatings applied at high transfer
efficiencies are capable of achieving
equivalent emission reductions and are
expected to be less costly and require
less total energy than water-based
systems. These high solids coatings are
expected to be available by 1982 and
will probably be used by most new
sources to comply with the VOC
emission limitations. Powder coatings
are also expected to be available in the
future but are not demonstrated at this
time.
Selection of Format for the Proposed
Standards
A number of different formats could
be selected to limit VOC emissions from
automobile and light-duty truck surface
coating operations. The format
ultimately selected must be compatible
with any of the three different control
systems that could be used to comply
with the proposed standards. One
control system is the use of water-based
coating materials in the prime coat,
guide coat, and topcoat operations.
Another control system is the use of
solvent-based coating materials and
add-on VOC emission control devices
such as incineration. The third control
system consists of the use of high solids
coatings. Although the coatings to be
used in this system are not
demonstrated at this time, research is
continuing toward their development;
hence, they may be used in the future.
The formats considered were
emission limits expressed in terms of (1)
concentration of emissions in the
exhaust gases discharged to the
atmosphere; (2) mass emissions per unit
of production; or (3) mass emissions per
volume of coating solids applied.
The major advantage of the
concentration format is its simplicity of
enforcement. Direct emission
measurements oould be made using
Reference Method 25. There are,
however, two significant drawbacks to
the use of this format. Regardless of the
control approach chosen, emission
testing would be required for each stack
exhausting gases from the surface
coating operations (unless the owner or
operator could demonstrate to the
Administrator's satisfaction that testing
of representative stacks would give the
same results as testing all the stacks).
This testing would be time consuming
and costly because of the large number
of stacks associated with automobile
and light-duty truck surface coating
operations. Another potential problem
with this formal is the ease of
circumventing the standards by the
addition of dilution air. It would be
extremely difficult to determine whether
diluted air was being added
intentionally to reduce the concentration
of VOC emissions in the gases
discharged to the atmosphere, or
whether the air was being added to the
application or drying operation to
optimize performance and maintain a
safe working space.
A format of mass VOC emissions per
unit of production relates emissions to
individual plant production on a direct
basis. Where water-based coatings are
used, the average VOC content of the
coating materials cou]d be determined
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by using Reference Method 24
(Candidate 1 or Candidate 2). The
volume of coating materials used and
the percent solids could be determined
from purchase records. VOC emissions
could then be calculated by multiplying
the VOC content of the coating
materials by the volume of coating
materials used in a given time period
and by the percentage of solids, and
dividing the result by the number -of
vehicles produced in that time period.
This would provide a VOC emission
rate per unit of production.
Consequently, procedures to determine
compliance would be direct and
straightforward, although very time
consuming. This procedure would also
require data collection over an
excessively long period of time.
Where solvent-based coatings were
used with add-on emission control
devices, stack emission tests could be
performed to determine VOC emissions.
Dividing VOC emissions by the number
of vehicles produced would again yield
VOC emissions per unit of production.
This format, however, would not
account for differences in surface
coating requirements for different
vehicles caused by size and
configuration. In addition,
manufacturers of larger vehicles would
be required to reduce VOC emissions
more than manufacturers of smaller
vehicles.
A format of mass of VOC emissions
per volume of coating solids applied
also has the advantage of not requiring
itack emission testing unless add-on
emission control devices rather than
water-based coatings are used to
comply with the standards. The
introduction of dilution air into the
exhaust stream would not present a
problem with this format. The problem
of varying vehicle sizes and
configurations would be eliminate since
the format is in terms of volume of
applied solids regardless of the surface
area or number of vehicles coated. This
format would also allow flexibility in
selection of control systems, for it is
usable with any of the control methods.
Since this format overcomes the varying
dilution air and vehicle size problems
inherent with the other formats, it has
been selected as the format for the
proposed standards. In order to use a
format which is in terms of applied
solids, the transfer efficiency of the
application devices must be considered.
Transfer efficiency is defined as the
fraction of the total sprayed solids
which remain on the vehicle. Transfer
efficiency is an important factor because
as efficiency decreases, more coating
material is used and VOC emissions
increase. Equations have been
developed to use this format with water-
based coating materials as well as with
solvent-based coating materials in
combination with high transfer
efficiences and/or add-on emission
controls devices. These equations are
included in the proposed standards.
Selection of Numerical Emission Limits
Numerical Emission Limits
The numerical emission limits
selected for the proposed standard are:
0.10 kilogram of VOC per liter of
applied coating solids from prime coat
operations
0.84 kilogram of VOC per liter of
applied coating solids from guide coat
operations
O.B4 kilogram of VOC per liter of
applied coating solids from topcoat
operations .
In all three limits, the mass of VOC is
measured as carbon in accordance with
Reference Methods 24 (Candidate 1) and
25. These emission limits are based on
the use of water-based coating materials
in the prime coat, guide coat, and
topcoat operations. Water-based coating
data were obtained from plants which
were using these materials as well as
from the vendors who supply them.
These data were used to calculate VOC
emission limits using a procedure
similar to proposed Method 24
(Candidate 1). A transfer efficiency of 40
percent was then applied to the values
obtained for guide coat and top-coat
emissions. This efficiency was
determined to be representative of a
well-operated air-atomized spray
system. The CTG-recommended limits
are based on the use of the same coating
materials as the proposed standards.
The limits in the CTG are expressed in
pounds of VOC per gallon of coating
(minus water) used in the EDP system or
the spray device. The limits in these
proposed standards, however, are
referenced to the amount of coating
solids which adhere to the vehicle body.
Therefore, to compare the limits in the
CTG to those proposed here, it is
necessary to account for the solids
content of the coating and the efficiency
of applying the guide coat and topcoat
to the vehicle body. Consideration of
transfer efficiency is significant because
the proposed standards can be met by
using high solids content coating
materials if the amount of overspray is
kept to a minimum. Since this format
provides equivalency determinations for
systems using solvent-based coating
materials in combination with high
transfer efficiencies and/or add-on
control devices, it allows flexibility in
selection of control systems.
As discussed in previous sections,
there are two types of EDP systems.
Anodic EDP was the first type
developed for use in automobile surface
coating operations. Cathodic EDP is the
second type and is a recent technology
improvement which results in greater
corrosion resistance. Consequently,
nearly 50 percent of the existing EDP
operations use cathodic systems, and
continued changeovers from anodic to
cathodic EDP are expected. Since
cathodic EDP produces a coating with
better corrosion resistance, the proposed
standards are based on the best
available cathodic EDP systems.
The coating material on which the
EDP emission limit is based is presently
in production use. Although this low
solvent content material is currently
available only in limited quantities, it is
expected to be available in sufficient
quantities for use in all new or modified
sources before promulgation of the
standard. The final promulgated
standards will be based on this low
solvent content material, rather than the
EDP material commonly used now, if it
is determined to be widely available at
that time.
The emission limit for guide coat
operations is based on a transfer of
technology from topcoat operations. The
guide coat is essentially a topcoat
material, without pigmentation, and
water-based topcoats are available
which can comply with the proposed
limits. Hence, the same emission limit is
proposed for the guide coat operation as
for the topcoat operation.
Because of the elevated temperatures
present in the prime coat, guide coat,
and topcoat bake ovens, additional
amounts of "cure volatile" VOC may be
emitted. These "cure volatile" emissions
are present only at high temperatures
and are not measured in the analysis
which is used to determine the VOC
content of coating materials. Cure
volatile emissions, however, are
believed to constitute only a sma!!
percentage of total VOC emissions
Consequently, because of the
complexity of measuring and controlling
cure volatile emissions, they will not be
considered in determining compliance
with the proposed standards.
A large number of coating materials
are used in topcoat operations, and each
may have a different VOC content.
Hence, an average VOC content of all
the coatings used in this operation
would be computed to determine
compliance with the proposed
standards. Either of two averaging
techniques could be used for computing
this average. Weighted averages provide
very accurate results but would require
keeping records of the total volume and
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percent solids of each different coating
used. Arithmetic averages are not
always as accurate; however, they are
much simpler to calculate. In the case of
topcoat operations, normally 15 to 20
different coatings are used, end the
VOC content for most of these coatings
Is in the same general range. Therefore,
an arithmetic average would closely
approximate the values obtained from a
weighted average. An arithmetic
average would be calculated by
summing the VOC content of each
surface coating material used in a
surface coating operation (i.e., guide
coat or topcoat), and dividing the sum
by the number of different coating
materials used. Arithmetic averages are
also consistent with the approach being
incorporated into some revised SIP's.
For the EDP process, however, an
arithmetic average VOC content is not
appropriate to determine compliance
with the proposed standards. In an EDP
system, the coating material applied to
an automobile or light-duty truck body
is replaced by adding fresh coating
materials to maintain a relatively
constant concentration of solids,
solvent, and fluid level in the EDP
coating lank. Three different types of
materials are usually added in separate
streamsclear resin, pigment paste, and
solvent.
The clear resin and pigment paste are
very low in VOC content (i.e., 10 percent
or less), while the solvent is very high in
VOC content (i.e.. 90 percent or more).
The solvent additive stream is only
about 2 percent of the total volume
added. Consequently, an arithmetic
average of the three streams seriously
misrepresents the actual amount of VOC
added to the EDP coating tank.
Weighted averages, therefore, were
selected for determining the average
VOC content of Boating materials
applied by EDF.
If an automobile or light-duty truck
manufacturer chooses to use a control
technique other than water-based
coatings, the transfer efficiency of the
application devices used becomes very
important. As transfer efficiency
decreases, more coating material is used
and VOC emissions increase. Therefore
transfer efficiency must be taken into
account to determine equivalency to
water-based costings.
Electrostatic spraying, which applies
surface coatings at high transfer
efficiences, can in many industries be
used with water-based coatings if the
entire paint handling system feeding the
atomizers is insulated electically from
ground Otherwise, the high conductivity
of the water involved would ground out
and make ineffective the electrostatic
effect. In the case of the coating of
automobiles, however, because of the
larger number of colors involved, the
high frequency and speed of color
changes required, the large volume of
coatings consumed per shift, and the
large number of both automatic and
manual atomizers involved, it is not
technically feasible to combine water-
based coatings and electrostatic
methods for reasons of complexity, cost,
and personnel comfort. Consequently,
water-based surface coatings are
applied by air-atomized spray systems
at a transfer efficiency of about 40
percent. The numerical emission limits
included in the proposed standards were
developed based on the use of water-
based surface coatings applied at a 40
percent transfer efficiency. Therefore, if
surface coatings are apphed to a greater
than 40 percent transfer efficiency,
surface coatings with higher VOC
contents may be used with no increase
in VOC emissions to the atmosphere.
Transfer efficiencies for various means
of applying surface coatings have been
estimated, based on information
obtained from industries and vendors,
as follows:
Transtor
efficiency
Application method (percent)
An Atomued Spray ._.._..-. 40
Manuil Electrostatic Spray 75
Automatic Electrostatic Spray ... . ..... 95
ElectrodeposDion (EDP) . 106
These values are estimates which
reflect the high side of expected transfer
efficiency ranges, and therefore, are
intended to be used only for the purpose
of determining compliance with the
proposed standards.
Frequently, more than one application
method is used within a single surface
coating operation. In these cases, a
weighted average transfer efficiency,
based on the relative volume of coating
sprayed by each method, will be
estimated. These situations are likely to
vary among the different manufacturers
and the estimates, therefore, will be
subject to approval by the Administrator
on a case-by-case basis.
Method of Determining Compliance
The procedure for determining
compliance with the proposed standards
is complicated due to the number of
different control systems which may be
used. The following multistep procedure
would be used.
1. Determine the average VOC content
per liter of coating solids of the prime
coat guide coat, and topcoat materials
being used. This would require
analyzing all coating materials used in
each coating operation using the
proposed Reference Method 24
(Candidate 1 or Candidate 2) and
calculating an average VOC content for
each coating operation.
2. Select the appropriate transfer
efficiency for each surface coating
operation from the table included in the
proposed standards.
3. Calculate the mass of VOC
emissions per volume of applied solids
for each surface coating operation by
dividing the appropriate average VOC
content of the coatings (Step 1) by the
transfer efficiency of the surface coating
operation (Step 2). If the value obtained
is lower than the emission limit included
in the proposed standards, the surface
coating operation would be in
compliance. If the value obtained is
higher than the emission limit, add-on
VOC emission control would be
required to comply with the proposed
standards.
4. If add-on emission control is
required, calculate the emission
reduction efficiency in VOC emissions
which is required using the equations
included in the proposed standards.
5. In cases where all exhaust gases
are not vented to an emission control
device, determine the percentage of total
VOC emissions which enter the add-on
emission control device by sampling all
the stacks and using the equations
included in the proposed standards.
Representative sampling, however,
could be approved by the Administrator,
on a case-by-case basis, rather than
requiring sampling of all stacks for this
determination.
6. Calculate the actual efficiency of
the control device by determining VOC
emissions before and after the device
using the proposed Reference Method
25.
7. Calculate the VOC emission
reduction efficiency achieved by
multiplying the percentage of VOC
emissions which enter the add-on VOC
emission control device (Step 5) by the
add-on control device efficiency (Step
6). If the resulting value of the emission
reduction efficiency achieved were
greater than that required (Step 4), then
the surface coating operation would be
in compliance.
Detailed instructions, as well as the
equations to be used for these
calculations, are contained in the
proposed standards.
Selection of Monitoring Requirements
Monitoring requirements are generally
included in standards of performance to
provide a means for enforcement
personnel to ensure that emission
control measures adopted by a facility
to comply with standards of
performance are properly operated and
maintained. Surface coating operations
which have achieved compliance with
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the proposed standards without the use
of add-on VOC emission control devices
would be required to monitor the
average VOC content (weighted
averages for EDP and arithmetic
averages for guide coat and topcoat) of
the coating materials used in each
surface coating operation. Generally,
increases in the VOC content of the
coating materials would cause VOC
emissions to increase. These increases
could be caused by the use of new
coatings or by changes in the
composition of existing coatings.
Therefore, following the initial
performance test, increases in the
average VOC content of the coating
materials used in each surface coating
operation would have to be reported on
a quarterly basis.
Where add-on control devices, such
as incinerators, were used to comply
with the proposed standards,
combustion temperatures would be
monitored. Following the initial
performance test, decreases in the
incinerator combustion temperature
would be reported on a quarterly basis.
Performance Test Methods
Reference Method 24, "Determination
of Volatile Organic Compound Content
of Paint, Varnish, Lacquer, or Related
Products," is proposed in two forms
Candidate 1 and Candidate 2. Candidate
1 leads to a determination of VOC
content expressed as the mass of
carbon. Candidate 2 yields a
determination of VOC content measured
as mass of volatile organics. The
decision as to which Candidate will be
used depends on the final format
selected for the proposed standards.
Reference Method 25, "Determination of
Total Gaseous Nonmethane Volatile
Organic Compound Emissions," is
proposed as the test method to
determine the percentage reduction of
VOC emissions achieved by add-on
emission control devices.
Public Hearing
A public hearing will be held to
discuss the proposed standards in
accordance with Section 307(d)(5) of the
Clean Air Act. Persons wishing to make
oral presentations should contact EPA
at the address given above (see
Addresses Section). Oral presentations
will be limited to 15 minutes each. Any
member of the public may file a written
statement before, during, or within 30
days after the hearing. Written
statements should be addressed to
"Docket" (see Addresses Section).
A verbatim transcript of the hearing
and written statements will be available
for public inspection and copying during
normal working hours at EPA's Central
Docket Section, Room 2903B, Waterside
Mall, 401 M Street, S.W., Washington,
D.C. 20460.
Docket
The docket, containing all supporting
information used by EPA to date, is
available for public inspection and
copying between 8:00 a.m. and 4:00 p.m.,
Monday through Friday, at EPA's
Central Docket Section, Room 2903B,
Waterside Mall, 401 M Street, S.W.,
Washington, D.C. 20460.
The docket is an organized and
complete file of all the information
submitted to or otherwise considered by
EPA in the development of the
rulemaking. The docket is a dynamic
file, since material is added throughout
the rulemaking development. The
docketing system is intended to allow
members of the public and industries
involved to readily identify and locate
documents so that they can intelligently
and effectively participate in the
rulemaking process. Along with the
statement of basis and purpose of the
promulgated rule and EPA responses to
significant comments, the contents of
the Docket will serve as the record in
case of judicial review [Section
307(d)(a)J.
Miscellaneous
As prescribed by Section 111,
establishment of standards of
performance for automobile and light-
duty truck surface coating operations
was preceded by the Administrator's
determination (40 CFR 60.16, 44 FR
49222, dated August 21,1979) that these
sources contribute significantly to air
pollution which may reasonably be
anticipated to endanger public health or
welfare. In accordance with Section 117
of the Act, publication of these
standards was preceded by consultation
with appropriate advisory committees,
independent experts, and Federal
departments and agencies. The
Administrator welcomes comments on
all aspects of the proposed regulations,
including the technological issues,
monitoring requirements, and the
proposed test methods. Comments are
requested specifically on Method 24
(Candidate 1 and Candidate 2) and the
coating material used as the basis for
the prime coat emission limit.
It should be noted that standards of
performance for new sources
established under Section 111 of the
Clean Air Act reflect:
. . . application of the best technological
system of continuous emission reduction
which (taking into consideration the cost of
achieving such emission reduction, and any
nonair quality health and environmental
impact and energy requirements) the
Administrator determines has been
adequately demonstrated [Section lll(a](l)|
Although emission control technology
may be available that can reduce
emissions below those levels required to
comply with standards of performance,
this technology might not be selected as
the basis of standards of performance
because of costs associated with its use.
Accordingly, standards of performance
should not be viewed as the ultimate in
achievable emission control. In fact, the
Act may require the imposition of a
more stringent emission standard in
several situations.
For example, applicable costs do not
necessarily play as prominent a role in
determining the "lowest achievable
emission rate" for new. or modified
sources locating in nonattainment areas
(i.e., those areas where statutorily
mandated health and welfare standards
are being violated). In this respect,
section 173 of the Act requires that new
or modified sources constructed in an
area which exceeds the NAAQS must
reduce emissions to the level which
reflects the LAER, as defined in section
171(3). The statute defines LAER as the
rate of emissions based on the
following, whichever is more stringent:
(A) the most stringent emission limitation
which is contained in the implementation
plan of any State for such class or category of
source, unless the owner or operator of the
proposed source demonstrates that such
limitations are not achievable, or
(B) the most stringent emission limitation
which is achieved in practice by such class or
category of source.
In no event can the emission rate exceed
any applicable new source performance
standard.
A similar situation may arise under
the prevention-of-significant-
deterioration-of-air-quality provisions of
the Act. These provisions require that
certain sources employ BACT as defined
in section 169(3) for all pollutants
regulated under the Act. BACT must be
determined on a case-by-case basis,
taking energy, environmental and
economic impacts, and other costs into
account. In no event may the application
of BACT result in emissions of any
pollutants which will exceed the
emissions allowed by any applicable
standard established pursuant to section
111 (or 112) of the Act.
In all cases, SIP's approved or
promulgated under section 110 of the
Act must provide for the attainment and
maintenance of NAAQS designed to
protect public health and welfare. For
this purpose. SIP's must, in some cases,
require greater emission reduction than
those required by standards of
performance for new sources-
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Finally, States are free under section
116 of the Act to establish even more
stringent emission limits than those
established under section 111 or those
necessary to attain or maintain the
NAAQS under section 110. Accordingly,
new sources may in some cases be
subject to limitations more stringent
than standards of performance under
section 111, and prospective owners and
operators of new sources should be
aware of this possibility in planning for
such facilities.
Under EPA's sunset policy for
reporting requirements in regulations,
the reporting requirements in this
regulation will automatically expire 5
years from the date of promulgation
unless EPA takes affirmative action to
extend them.
Section 317 of the Clean Air Act
requires the Administrator to prepare an
economic impact assessment for any
new source standard of performance
under section lll(b) of the Act. An
economic impact assessment was
prepared for the proposed regulations
and for other regulatory alternatives. All
aspects of the assessment were
considered in the formulation of the
proposed standards to ensure that the
proposed standards would represent the
best system of emission reduction
considering costs. The economic impact
assessment is included in the
Background Information Document.
Dated: September 27, 1979.
Douglas M. Costle,
Administrator.
This proposed amendment to Part 60
of Chapter I, Title 40 of the Code of
Federal Regulations would
1. Add a definition of the term
"volatile organic compound" to § 60.2 of
Subpart AGeneral Provisions as
follows:
$60.2 Definitions.
* * * t *
(dd) "Volatile Organic Compound"
means any organic compound which
participates in atmospheric
photochemical reaction or is measured
by the applicable reference methods
specified under any subpart.
2. Add Subpart MM as follows:
Subpart MMStandards of Performance
for Automobile and Light-Duty Truck
Surface Coating Operations
Sec
60.390 Applicability and designation of
affected facility.
60.391 Definitions.
60.392 Standards for volatile organic
compounds.
60.393 Monitoring of operations.
60.394 Test methods and procedures.
60.395 Modifications.
Authority: Sees. Ill and 301 (a) of the Clean
Air Art, as amended. [42 U.S.C. 7411,
7601(a)]. and additional authority as noted
below.
Subpart MMStandards of
Performance for Automobile and
Light-Duty Truck Surface Coating
Operations
§60.390 Applicability and designation of
affected facility.
(a) The provisions of this subpart
apply to the following affected facilities
in an automobile or light-duty truck
surface coating line: each prime coat
operation, each guide coat operation,
and each topcoat operation.
(b) The provisions of this subpart
apply to any affected facility identified
in paragraph (aj of this section that
begins construction or modification after
(date of publication in the
Federal Register).
§60.391 Definitions.
All terms used in this subpart that are
not defined below have the meaning
given to them in the Act and in Subpart
A of this part.
(a) "Automobile" means a motor
vehicle capable of carrying no more
than 12 passengers.
(b) "Automobile and light-duty truck
body" means the body section rearward
of the windshield and the front-end
sheet metal or plastic exterior panel
material forward of the windshield of an
automobile or light-duty truck.
(c) "Bake oven" means a device which
uses heat to dry or cure coatings.
(d) "Electrodeposition (EDP)" means a
method of applying prime coat. The
automobile or light-duty truck body is
submerged in a tank filled with coating
material, and an electrical field is used
to deposit the material on the body.
(e) "Electrostatic spray application"
means a spray application method that
uses an electrical potential to increase
the transfer efficiency of the coating
solids. Electrostatic spray application
can be' used for prime coat, guide coat,
or topcoat operations.
(f) "Flash-off area" means the
structure on automobile and light-duty
truck assembly lines between the
coating application system (EDP tank or
spray booth) and the bake oven.
(g) "Guide coat operation" means the
guide coat spray booth, flash-off area
and bake oven(a) which are used to
apply and dry or cure a surface coating
on automobile and light-duty truck
bodies between the prime coat and
topcoat operation.
(h) "Light-duty truck" means any
motor vehicle rated at 3,850 kilograms
(ca. 8,500 pounds) gross vehicle weight
or less designed mainly to transport
property.
(i) "Prime coat operation" means the
prime coat application system (spray
booth or dip tank), flash-off area, and
bake oven(s) which are used to apply
and dry or cure the initial coat on the
surface of automobile or light-duty truck
bodies.
(j) "Spray application" means a
method of applying coatings by
atomizing the coating material and
directing this atomized spray toward the
part to be coated. Spray applications
can be used for prime coat, guide coat,
and topcoat operations.
(k) "Spray booth" means a structure
housing or manual spray application
equipment where prime coat guide coat,
or topcoat is applied to automobile or
light-duty truck bodies.
(1) "Surface coating operation" means
any prime coat, guide coat, or topcoat
operation on an automobile or light-duty
truck surface coating line.
(m) "Topcoat operation" means the
topcoat spray booth(s), flash-off area(s),
and bake oven(s) which are used to
apply and dry or cure the final coating(s)
on automobile and light-duty truck
bodies (i.e., those which give an
automobile or light-duty truck body its
color and surface appearance).
(n) "Transfer efficiency" means the
fraction of the total applied coating
solids which remains on the part.
(o) "Volatile organic compound"
(VOC) means any organic compound
which is measured by Method 24
(Candidate 1 or Candidate 2) and
Method 25.
(p) "VOC emissions" means the mass
of volatile organic compounds,
expressed as kilograms of carbon per
liter of applied coating solids, emitted
from a surface coating operation.
(q) "VOC content" means the volatile
organic compound content, in kilograms
of carbon per liter of coating solids, of a
coating material used in spray
applications or coating make-up stream
to an EDP tank.
§60.392 Standards for volatile organic
compounds.
After the performance test required by
§ 60.8 has been completed, no owner or
operator subject to the provisions of this
subpart shall discharge or cause of the
discharge into the atmosphere of VOC
emissions which exceed the following
limits:
(a) 0.10 kilogram of VOC (measured as
mass of carbon) per liter of applied
coating solids from each prime coat
operation.
(b) 0.84 kilogram of VOC (measured
as mass of carbon) per liter of applied
coating solids from each guide ooat
operation.
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(c) 0.84 kilogram of VOC (measured as
mass of carbon) per liter of applied
coating solids from each topcoat
operation,
§60.3*3 Monitoring of operation*.
(a) Any owner or operator subject to
the provisions of this subpart shall(1)
Install, calibrate, operate, and maintain
a monitoring device which records the
combustion temperature of any effluent
gases which are emitted from any
surface coating operation and which are
incinerated to comply with J 60.392. TTie
manufacturer must certify that the
monitoring device is accurate to within
±2°C(±3.6°F).
(2) Determine the weighted average
VOC content of the coating materials
used in any EDP prime coat operation
whenever a change occurs in the
composition of any of these coating
materials. The owner or operator shall
compute the weighted average by the
fallowing equation:
I CS. x VOLS. « SC
VOLS. x SC
where:
C = Jhe weighted averaged VOC content of
all the coating materials used in an EDP
system.
CS, = the VOC content of the material in
each coating makeup stream.
VOLSi = the volume (cubic meter*) of each
makeup stream added to the EDP tank
during the previous month.
SC, = the solid content of the material in
each coating makeup stream expressed
as a volume fraction.
n = the number of makeup streams.
(3) Determine the average VOC
content of the coating materials in any
surface coating operation which uses
spray application whenever a change
occurs in the composition of any of
these coating materials. The owner or
operator shall determine and record the
arithmetic average of the VOC content
of all coating materials in a coating
operation which uses more than one
coating material.
(b) Any owner or operator subject to
the provisions of this subpart shall
report for each calendar quarter all
measurement results as follows:
(1) Where compliance with § 60.392 is
achieved without the use of add-on
control devices, any month during
which
(i) The weighted average VOC content
of the makeup materials used in any
prime coat operation employing EDP
exceeds the most recent value which
demonstrated compliance with
{ 60.392(a) by the performance test
required in j 60.8.
(ii) The arithmetic average VOC
content of the coating materials used in
any surface coating operation employing
spray application exceeds the most
recent value which demonstrated
compliance with $ 60.392 by the
performance test required in $ 60.8.
(2) Where compliance with $ 60.392 is
achieved by the use of incineration, all
periods in excess of 5 minutes during
which the temperature in any
incinerator used to control the emission
from a surface coating operation
remains below the most recent level
which demonstrated compliance with
§ 60.392 by the performance tests
required in $ 60.8. The report required
under § 60.7(c) shall identify each such
occurrence and its duration.
(3) The reporting requirements in this
regulation will automatically expire five
years from the date of promulgation
unless EPA takes affirmative action to
extend them.
§ 60.394 Test method* and procedures.
(a) The reference methods in
Appendix A to this part, except as
provided for in 5 60.8(b), shall be used to
determine compliance with § 60.392 as
follows:
(1) The owner or operator shall use
Reference Method 24 (Candidate 1 or
Candidate 2) to measure the VOC
content of every coating or makeup
material used in each surface coating
operation of an automobile or light-duty
truck surface coating line. The coating
sample shall be a 1 liter sample taken at
a point where the sample will be
representative of the coating material as
applied to the vehicle surface. The 1 liter
sample shall be divided into three
aliquots for triplicate determinations by
Method 24 (Candidate 1 or Candidate 2).
(2) The owner or operator shall
compute the arithmetic average VOC
content of all coating materials used in
each surface coating operation that uses
spray application.
(3) The owner or operator shall use
the calculation procedures given in
§ 60.393(a)(2J to compute the weighted
average VOC content of all makeup
materials added to an EDP tank during a
selected one month period for each
prime coat operation that uses EDP.
(4) The owner or operator shall
determine the VOC emissions by the
equation:
E =
where
E = the VOC emissions
C = the average VOC content of all the
coating or makeup materials used in that
operation. The owner or operator shall
use an arithmetic average for systems
using spray application and a weighted
average for systems using EDP.
TE=the appropriate transfer efficiency as
determinetHn paragraph (a)(5) of this
section.
(5] The owner or operator shall select
the appropriate transfer efficiency from
the following table for each surface
coating operation.
Apphcsbon method
Tiwwfcr
efficiency (TE)
Air /Men**) Spray -
Manual BectraeUbc Spray
Automatic Electrostatic Spray _
EtoctrodefXMWon _
9.40
ars
toe
If the owner or operator can justify to
the Administrator's satisfaction that
other values for transfer efficiencies are
appropriate, the Administrator will
approve their use on a case-by-case
basis. Where more than one application
method is used on an individual surface
coating operation, the owner or operator
shall perform an analysis to determine
the relative volume of solids coating
materials applied by each method. The
owner or operator shall use these
relative volumes of solids to compute a
weighted average transfer efficiency for
the operation. The Administrator will
review and approve this analysis on a
case-by-case basis.
(bj For each surface coating operation
which cannot achieve compliance with
§ 60.392 without the use ef add-on
control devices, the owner or operator
shall use the following procedures to
determine that the emission reduction
efficiency of the control device(s) is
sufficient to achieve compliance with
§ 60.392:
(1) The owner or operator shall
compute the emission reduction
efficiency required for each surface
coating operation by the following
equation:
EL
* 100
where:
ER = the required emission reduction
efficiency (in percent) for the applicable
surface coating operation to achieve
compliance with 5 60.392.
E =-- the VOC emissions from the applicable
surface coating operation.
EL - the numerical VOC emission limit in
§ 60.392 for the applicable surface
coating operation.
(2) The owner or operator shall
determine the emission reduction
efficiency achieved by the control
device(s) on each applicable surface
coating operation as follows:
(i) The owner or operator shall use
Reference Method 25 to determine the
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Federal Register / Vol. 44. No. 195 / Friday. October 5,1979 / Proposed Rules
VOC concentration in the effluent gas
before and after the emission control
device for each stack that is equipped
with an emission control device. The
owner or operator shall use Reference
Method 2 to determine the volumetric
flowrate of the effluent gas before and
after the emission control device on
each stack. The Administrator will
approve testing of representative stacks,
on a case-by-case basis, if the owner or
operator can show to the
Administrator's satisfaction that testing
of representative stacks yields results
comparable to those that would be
obtained by testing all stacks.
(ii) For Method 25, the sampling time
for each run shall be at least 60 minutes
and the minimum sample volume shall
be at least 0.003 dscm (0.106 dscf) except
that shorter sampling times or smaller
volumes, when necessitated by process
variables or other factors, may be
approved by the Administrator.
(iii) The owner or operator shall
determine the efficiency of each
emission control device by the following
equation:
EFF = (CB x VOLB) - (CA x VOLA) x m
(CB x VOLB)
where:
EFF=the emission control device efficiency,
in percent.
CB=the concentration of VOC in the effluent
gas before the emission control device, in
parts per million by volume.
CA = the concentration of VOC in the effluent
gas after the emission control device, in
parts per million by volume.
VOLA = the volumetric flow rate of the
effluent gas after the emission control
device, in dry standard cubic meters per
second.
VOLB = the volumetric flow rate of the
effluent gas before the emission control
device, in dry standard cubic meters per
second,
If an emission control device controls
the emissions from more than one stack,
the owner or operator shall measure CB
and VOLB at a location between the
manifold that receives all the exhausts
from the applicable surface coating
operation and the control device. If a
manifold is not used, the product
CBxVOLB shall be replaced by the sum
of the individual products for each stack
on the applicable surface coating
operation controlled by this device.
(iv) The owner or operator shall
determine the fraction of the total VOC
discharged from an applicable surface
coating operation which enters each
emission control device on that
operation by the following equation:
CB. x VOLB
i n
I (CBt x VOLB,)
k=l * "
where:
F, = the fraction of the total VOC discharged
from the applicable surface coating
operation which enters the emission
control device.
CB,=the value of CB for stack (k) on the
applicable surface coating operation.
CBk = the value of CB for each stack (k) on
the applicable surface coating operation.
VOLB,-the value of VOLB for each emission
control device (i).
VOLBi = the value of VOLB for each stack (k)
on the applicable surface coating
operation.
n = the number of stacks on the applicable
surface coating operation.
The owner or operator shall use the
procedures contained in clause (ii) of
this subparagraph for any emission
control device (i) that controls the
emissions from more than one stack.
(v) The owner or operator shall
determine the emission reduction
efficiency achieved by the control
device(s) on the applicable surface
coating operation using the equation:
EA = I (F x EFF )
where:
EA=the emission reduction efficiency
achieved, in percent.
EFF, = the emission reduction efficiency (in
percent) of each control device on the
applicable surface coating operation.
m = the number of control devices on the
applicable surface coating operation.
(3) If EA is greater than or equal to
ER, the applicable surface coating
operation will be in compliance with
§ 60.392.
§60.395 Modifications.
(a) The following physical or
operational changes are not, by
themselves, considered modifications of
existing facilities:
(1) Changes as a result of model year
changeovers or switches to larger cars.
(2) Changes in the application of the
coatings to increase paint film thickness.
Appendix A Reference Methods
3. Method 24 (Candidate 1), Method 24
(Candidate 2), and Method 25 are added
to Appendix A as follows:
Method 24 (Candidate 1)Determination of
Volatile Content (as Carbon) of Paint,
Vamish, Lacquer, or Related Products
1 Applicability and Principle
1.1 Applicability. This method is
applicable for the determination of volatile
content (as carbon) of paint, varnish, lacquer,
and related products listed in Section 2.
1.2 Principle. The weight of volatile
carbon per unit volume of solids is calculated
for paint, varnish, lacquer, or related surface
coating after using standard methods to
determine the volatile matter content, density
of the coating, density of the solvent, and
using the oxidation-nondispersive infrared
(NDIR) analysis for the carbon content.
2. Classification of Surface Coating
For the purpose of this method, the
applicable surface coatings are divided into
two classes. They are:
2.1 Class I: General Solvent- Type Paints
and Water Thinned Paints. This class
includes white linseed oil outside paint, white
soya and phthalic alkyd enamel, white
linseed o-phthalic alkyd enamel, red lead
primer, zinc chromate primer, flat white
inside enamel, white epoxy enamel, white
vinyl toluene, modified alkyd, white amino
modified baking enamel, and other solvent-
type paints not included in class II. It also
includes emulsion or latex paints and colored
enamels.
2.2 Class II: Varnishes and Lacquers. This
class includes clear and pigmented lacquers
and varnishes.
3 Applicable Standard Methods
Use the apparatus, reagents, and
procedures specified in the standard methods
below:
3.1 ASTMD1644-59 Method A Standard
Methods of test for Non-volatile Contents of
Varnishes. Do not use Method B.
3.2 ASTMD 1475-60. Standard Method of
Test for Density of Paint, Lacquer, and
Related Products.
3.3 ASTM D 2369-73: Standard Method
of Test for Volatile Content of Paints.
3.4 ASTM D 3272-76: Standard
Recommended Practice for Vacuum
Distillation of Solvents from Solvent-Base
Paints for Analysis.
4. Apparatus (Oxidation/NDIR Procedure)
4.1 Electric Furnace. Capable of
maintaining a temperature of 800+50° C.
4.2 Combustion Chamber. Stainless steel
tubing, 13 mm (Vi in ) internal diameter and
46 cm (18 in.) in length. Pack the tube loosely
with 3 mm (Ve in.) alumina pellets coated
with 5 percent palladium. Place plugs of
stainless steel wool at either end Other
catalytic systems which can demonstrate 95
percent efficiency as described in Section
65.4 are considered equivalent
4.3 Septum. Teflon '-coated rubber
septum.
4.4 Condenser. Ice bath condenser
4.5 Analyzer. Nondispersive infrared
analyzer (NDIR) to measure COi TO WITHIN
<>S PERCENT OF THE CALIBRATION GAS
CONCENTRATION.
4.6 Recorder. Capable of matching the
output of the NDIR.
4.7 Collection Tank. A collection tank of
at least 6 liters in volume. See procedure in
Section 6.5 1 for calibrating the volume of the
tank. The tank should be capable of
1 Mention of trade names or specific products
does not constitute endorsement by the
Environmental Protection Agency.
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withstanding a pressure of 2000 mm (80 in.)
Hg (gauge).
4.8 Pressure Gauge for Collection Tank.
Capable of measuring positive pressure to
1100 mm (42 in.) Hg and vacuum pressure to
700±5 mm (28±0.25 in.) Hg.
4.9 Vacuum Pump. Capable of evacuating
the collection tank to an absolute pressure of
51 mm (2 in.) Hg.
4 10 Analytical Balance. To measure to
within ±0.5 mg.
4.11 Syringes. 100±1.0 f»l. S00±1.0 /il.
and 1000 ±5 pi syringe, with needles long
enough to inject sample directly into the
carrier gas stream.
4.12 Mixer. Vortex-mixer to ensure
homogeneous mixing of solvent.
4.13 Flow Regulators. Rotameters. or
equivalent, to measure to 500 cc/min in flow-
rate.
4.14 Temperature Gauge. A thermometer
graduated in 0.1° C. with range from 0° C to
100° C.
4 15 Tank Calibration Equipment. A
balance to weigh collection tank to ±30 g or
a graduated glass cylinder to measure tank
volume within ±30 ml.
5. Reagents (Oxidation/NDIR Procedure)
5 1 Calibration Gases.
5.1.1 Zero Gas. Ni trogen.
5.1.2 CO, Cas. A range of concentration
to allow at least a 3-poinl calibration of each
measuring range of the instrument.
5.1.3 Carrier Gas. Air containing less than
1 ppm hydrocarbon as carbon, as certified by
the manufacturer.
5.2 Catalyst. Alumina (3 mm pellets)
coated with 5 percent palladium, or
equivalent (commercially available).
5.3 Acetone. Reagent grade.
5.4 Nitric Acid Solution. Dilute 70 percent
nitric acid 1:1 by volume with distilled water.
5.5 1-Butanol. -Ninety-nine molecular
percent pure.
5.6 Methane Gas 0.5 percent methane in
air
6 Procedure
6 1 Classification of Samples. Assign the
coating to one of the two classes discussed in
Section 2 above. Assign any coating not
clearly belonging to Class II to Class I.
6 2 Volatile Content. Use one of the
following methods to determine the volatile
content according to the class of coating
82 1 Class I. Use the Procedure in ASTM
D 2369-73 Record the following information:
W, = Weight of dish and sample, g.
Wj = Weight of dish and sample after heating,
8
S = Sample we:ght, g
Repeat the procedure for a total of three
determinations for each coating Calculate
the weight fraction of volatile matter W for
each analysis as follows.
"1
Report the arithmetic average weight fraction
W of the three determinations.
6.2.2 Class II. Use the procedure in ASTM
D 1644-59 Method A: record the following
information:
A = Weight of dish. g.
B=Weight of sample used, g.
C=Weight of dish and sample after heating.
g
Repeat the procedure for a total of three
determinations for each coating. Calculate
the weight fraction W of volatile content for
each analysis as follows:
u . (A * B - C)
6.5.3 Assemble the oxidation system as
shown in Figure 1. Heat the catalyst until the
temperature reaches equilibrium at 800 ±50'
C. Add ice to the condenser and remove
excess water to maintain the temperature at
O'C.
B
Report the arithmetic average weight fraction
W of three determinations.
6.3 Coating Density. Determine the
density Dm (in g/cm^ of the paint, varnish,
lacquer, or related product of either class
according to the procedure outlined in ASTM
D 1475-60. Make a total of'three
determinations for each coating. Report the
density Dm as the arithmetic average of the
three determinations.
6.4 Solvent Density.
6.4.1 Perform .the solvent extraction
according to the procedure outlined in ASTM
D 3272-76. For aqueous paint, use a
collection-rube m an ice-bath prior to the
collection-tube in the acetone and dry-ice
mixture to prevent water from freezing in the
collection-tube Combine the contents of both
tubes before analysis. If excessive foaming
occurs during distillation, discard the sample.
and repeat with a new sample treated with
an anti-foam spray (e.g Dow Coming's "Anti-
foam A Spray) before distillation. Anti-foam
spray must be nonorganic and nonflammable.
Use spray sparingly.
6.4.2 Determine the density D,(ing/cm*)
of the solvent according to the procedure
outlined in ASTM D 1475-60 Make a total of
three determinations for the solvent, and
report the average density D, as the
arithmetic average of the three
determinations.
6.5 Carbon Content of the Solvent.
Analyze the solvent within 24 hours after
distillation; keep it under refrigeration when
not in use. To determine the carbon content.
follow the procedure below:
6.5.1 Clean and calibrate the collection
tank as follows Rinse the inside of the tank
once with acetone, twice with tap water.
thrice with the nitric acid solution, and twice
with tap water. Weigh the tank when empty
and when full of water. Measure the
temperature of the water, and calculate the
volume as follows
Where
t = Temperature of the water. °C (°F)
V = Volume of the tank. nil.
We = Weight of the empty tank. g.
W,=Weight of the full tank, g.
D, = Density of water at temperature t. g/ml
Alternatively, measure the volume of water
necessary to fill the tank. The volume of the
tank connections and pressure gauge are
negligible for a tank volume of at least 6
liters
6.5.2 Calibrate the NDIR according to the
manufacturer's instruction. Use at least a 3-
point calibration. Introduce the COa
calibration gas through the analysis line.
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6.S.4 Determination of Conversion
Efficiency. Pass O.S percent methane gas In
ir through carrier gas line; 0.5 percent CO.
should be generated within ±5 percent error.
Using a 100 n\ sample of 1-butanol. follow the
procedure in 6.5.5 to 6.5.13. Calculate the
theoretical COi volume percent as in Section
7.3. This value should equal the value as
measured by the NDIR, within ±5 percent
error. If conversion efficiency is 100 ±5
percent, analyze the solvent extracted from
the paint according to procedure in Sections
6.5.5 to 6.5.14.
6.5.5 Purge the collection tank twice with
Ni. then evacuate the tank to at least 50.8 mm
(2 in.) Hg absolute pressure. Connect the
cylinder to the collection line.
6.5.6 Mix the solvent sample thoroughly
on a vortex-mixer. Then, draw a sample
(0.100 to 0.300 ml) into the syringe. Record the
volume of sample used.
6.5.7 Turn analysis valve to "sample"
position, and turn the sample valve to "vent"
position. Then turn on the carrier gas at a
rate of 500 cc/min to flush the system for 2
minutes.
6.5.8 With gas flowing at 500 cc/min
(maintain this rate throughout the test
procedure), turn sample valve to "sample"
position. Open the tank valve and inject the
sample into the gas stream through the
injection septum. Continue to draw the
ample into the tank until the NDIR'reads
lero. (Note. On replicate samples, a
decrease in peak value indicates that the
catalyst or sample has deteriorated, assuming
that other factors, such as leaks, cell
contamination, mechanical defects of the
instruments, etc., have not occurred.)
6.5.9 At completion of collection, close the
tank valve, and turn sample valve to "vent"
position. Let the carrier gas flush the system
for 2 minutes, then turn off the carrier gas.
6.5.10 Disconnect the tank and pressurize
it with N. to about 1016 mm (40 in.) Hg gauge
pressure. Record the final tank pressure after
pressurization, the atmospheric pressure, and
the room temperature.
6.5.11 Connect the tank to the analysis
line and turn the analysis valve to "analysis"
position.
6.5.12 Pass the CO, sample gas at the
tame rate as the calibration gas. Keep the
rite constant by adjusting the rotameter as
tank pressure falls.
6.5.13 Record the CO, concentration when
the peak value is reached. This peak value
will remain constant as long as the sample
gas continues to flow at a constant rate.
6.5.14 Repeat steps 6.5.5 through 6.5.13
until three consecutive results are obtained
which differ from one another in value by no
more than ±5 percent. At the end of the third
test, check the catalyst function by passing
the collected sample gas through the catalyst
and into the NDIR No increase in
concentration value should occur. If the
concentration is higher, invalidate the test
series, replace the catalyst and repeat the
test.
6.5.15 Report the results as an arithmetic
average of the three determinations.
7. Calculations. Carry out the calculations,
retaining at least one extra decimal figure
beyond that of the acquired data. Round off
figures after decimal calculation.
7.1 Nomenclature.
C,» Volatile matter content as carbon per
unit volume of paint solids, g/1 (Ib/gal).
Dt-Density of 1-ButanoI, g/cm>.
D.Average coating density, g/cm* (See
Section 6.3).
D,=Average solvent density, g/cm' (See
Section 6.4).
L*» Volume of 1-Butanol used in the test cm*.
UVolume of paint solvent used in the test,
cm'.
74.12=Molecular weight of 1-BuIanol.
Mc^Mass of carbon, g.
4=Number of carbon atoms in 1-Butanol.
f*i=Absolute standard pressure, 760 mm Hg
(29.92 in. Hg):
P,=Absolute final tank pressure after
pressurization, mm Hg (in. Hg).
TMa= Absolute standard temperature, 293° K
(528' R).
T,-Absolute tank temperature, 'K (°R).
%Solv.«= Volume percent of solvent in paint
coating.
Vco,=Volume of CO, in liters, at standard
temperature and pressure.
VB=Total gas volume, corrected to standard
conditions, in liters.
V,c=Volume percent of CO..
V,=Volume of tank, liters.
W=Weight fraction of volatile matter
content.
7.2 Total Gas Volume, Corrected to
Standard Conditions.
Where:
K,=17.65 for English units.
Ki=0.3855 for Metric units.
73 Volume Percent of COf From 1-
Butanol:
*pc ' V " Equation 2
9*
7.4 Mss of Carbon
"c ' V V,» 2TBT OT «*«« 3
7.5 Ptrctnt Volunt Solvtnt In P«!nt.
ff
Bol». U J- (100) Equation 4
7.6 VolttUt Katttr Content as Carbon.
[((nation 5
Where:
K.-8.3445 for English units.
Ki-lOOQ for Metric units.
& Bibliography.
6.1 Standard Methods of Test for
Nonvolatile Content of Varnishes. In: 1974
Book of ASTM Standards. Part 27.
Philadelphia, Pennsylvania, ASTM
' Designation D 1644-59.1974. p. 285-286.
A2 Standard Method of Test for Volatile
Content of Paints. In: 1978 Book of ASTM
Standards, Part 27. Philadelphia,
Pennsylvania. ASTM Designation D 2360-73.
1978. p. 431-432.
A3 Standard Method of Test for Density
of Paint. Varnish, lacquer, and Related
Products. In: 1974 Book of ASTM Standards.
Part 25. Philadelphia, Pennsylvania. ASTM
Designation D 1476-60.1974. p. 231-233.
8.4 Standard Recommended Practice for
Vacuum Distillation of Solvents from
Solvent-Base Paints for Analysis. In: 1978
Annual Book of ASTM Standards, Part 27.
Philadelphia. Pennsylvania, ASTM
Designation D 3272076.1978. p. 612-614.
8.S So/o, Albert E., William L. Oaks, and
Robert D. MacPhee. Total Combustion
Analysis. Air Pollution Control District-
County of Los Angeles. August 1974.
Method 24 (Candidate 2)
Determination of Volatile Organic
Compound Content (as Mass) of Paint.
Varnish, Lacquer, or Related Products
I. Applicability and Principle.
1.1 Applicability. This method applies to
the determination of volatile organic
compound content (as mass) of paint,
varnish, lacquer, and related products listed
in Section 2.
1.2 Principle. Standard methods are used
to determine the volatile matter content,
density of the coating, volume of solid, and
water content of the paint, varnish, lacquer.
and related surface coating. From this
information, the mass of volatile organic
compounds per unit volume of solids is
calculated.
2. Classification of Surface Coating. For the
purpose of this method, the applicable
surface coatings are divided into three
classes. They are:
2.1 Class I: General Solvent Reducible
Paints. This class includes white linseed oil
outside paint, white soya and phthalic alkyd
enamel, white linseed o-phthalic alkyd
enamel, red lead primer, zinc chroma te
primer, flat white inside enamel, white epoxy
enamel, white vinyl toluene, modified alkyd,
white amino modified baking enamel, and
other solvent-type paints not included in
Class II.
2.2 Class II: Varnishes and Lacquers. This
class includes clear and pigmented lacquers
and varnishes.
2.3 Class III. This class includes all water
reducible paints.
3. Applicable Standard Methods. Use the
apparatus, reagents, and procedures specified
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Federal Register / Vol. 44, No. 195 /Friday, October 5. 1979 / Proposed Rule8
4.2 Non-Aqueous Volatile Content. Use
one of the following methods to determine
the non-aqueous volatile content according to
the class of coating.
4.2.1 Class 1. Use the procedure in ASTM
D 2369-73; record the following information:
W, = Weight of dish and sample, g.
W>=Weight of dish and sample after heating
g
S = Sample of weight, g.
Repeat the procedure for a total of three
determinations for each coating. Calculate
the weight fraction of non-aqueous volatile
matter Wv for each analysis as follows:
l
Report the arithmetic average weight
fraction Wv of the three determifiations.
4.2.2 Class II. Use the procedure in ASTM
D 1644-75 Method A, record the following
information:
A = Weight of dish. g.
B=Weight of sample used, g.
C = Weight of dish and sample after heating,
g
Repeat the procedure for a total of three
determinations-for each coating. Calculate
the weight fraction W, of non-aqueous
volatile content for each analysis as follows:
w . (* * B - C)
Report the arithmetic average weight
fraction Wv of the three determinations
4.2.3 Class III.
4.231 Water Content. Determine the
water content (in % HjO) of the coating
according to either "Provisional Method of
Test for Water in Water Reducible Paint by
Direct Injection into a Gas Chromatograph"
or "Provisional Method of Test for Water in
Paint or Related coatings by the Karl Fischer
Titration Method." Repeat the procedure for
a total of three determinations for each
coating. Report the arithmetic average weight
percent % HjO of the three determinations.
4232 Volatile Content (Including Water).
Use the procedure in ASTM D 2369-73;
record the following information:
Wi = Weight of dish and sample, g.
Wj=Weight of dish and sample after heating,
g
S = Sample weight, g.
Repeat the procedure for a total of three
determinations for each coating. Calculate
the weight fraction of volatile matter as
follows
Report the arithmetic average weight
fraction V of the three determinations.
4.2.3.3 Non-Aqueous Volatile Matter.
Calculate the average non-aqueous volatile
mailer Wv as follows:
4.3 Coating Density. Determine the
density D. (in g/cm3) of the paint, varnish,
lacquer, or related product of any class
according to the procedure outlined in ASTM
D 1475-60. Make a total of three
determinations for each coating. Report the
density Dm as the arithmetic average of the
three determinations.
4.4 Non-Volatile Content. Determine the
volume fraction of the non-volatile matter of
the coating of any class according to the
procedure outlined in ASTM D 2697-73.
Calculate the volume fraction Pn of non-
volatile matter as follows
* Volume Nonvolatile Matter
res
"TOT
Make a total of three determinations for
each coating. Report the arithmetic average
volume fraction Pr of the three
determinations.
5. Volotile Organic Compounds Content.
Calculate the volatile organic compound
content Cm in terms of mass per volume of
solids (g/liter) as follows
U 0
v m
To convert g/liter to Ib/gal. multiply Cm by
8.3455 X 10"'.
6. Bibliography
61 Standard Methods of Test of
Nonvolatile Content of Varnishes. In. 1974
Book of ASTM Standards, Part 27.
Philadelphia. Pennsylvania, ASTM
Designation D 1644-75. 1978. p 288-289.
6.2 Standard Method of Test for Volatile
Content of Paints. In: 1978 Book of ASTM
Standards, Part 27. Philadelphia,
Pennsylvania. ASTM Designation D 2369-73.
1978 p. 431-432.
6.3 Standard Method of Test for Density
of Paint Varnish. Lacquer, and Related
Products. In. 1974 Book of ASTM Standards,
Part 25 Philadelphia, Pennsylvania. ASTM
Designation D 1476-60. 1974. p. 231-233.
6.4 Standard Method of Test for Water in
Water Reducible Paint by Direct Injection
into a Gas Chromatograph. Available from:
Chairman. Committee D-l on Paint and
Related Coatings and Materials, American
Society for Testing and Materials, 1916 Race
St., Philadelphia, PA 19103. ASTM
Designation D 3792.
6.5 Draft method of Test for Water in
Paint or Related Coatings by the Karl Fischer
Titration Method. Available from: Chairman,
Committee D-l on Paint and Related
Coatings and Materials. American Society for
Testing and Materials. 1916 Race St.,
Philadelphia, PA 19103.
Method 25Determination of Total
Gaseous Nonmethane Organic
Emissions as Carbon: Manual Sampling
and Analysis Procedure
1. Principle and Applicability.
1.1 Principle. An emission sample is
anisokmetically drawn from the stack
through a chilled condensate trap by means
of an evacuated gas collection tank. Total
gaseous nonmethane organics (TGNMO) are
determined by combining the analytical
results obtained from independent analyses
of the condensate trap and evacuated tank
fractions. After sampling is completed, the
organic contents of the condensate trap are
oxidized to carbon dioxide which is
quantitatively collected in an evacuated
vessel; a portion of the carbon dioxide is
reduced to methane and measured by a flame
ionization detector (FID) A portion of the
sample collected in the gas sampling tank is
injected into a gas chromatographic (GC)
column to achieve separation of the
nonmethane organics from carbon monoxide,
carbon dioxide and methane; the nonmethane
organics are oxidized to carbon dioxide,
reduced to methane, and measured by a FID
1.2 Applicability. This method is
applicable to the measurement of total
gaseous nonmethane organics in source
emissions.
2. Apparatus.
2.1 General. TGNMO sampling equipment
can be constructed by a laboratory from
commercially available components and
components fabricated in a machine shop
The primary components of the sampling
system are a condensate trap, flow control
system, and gas sampling lank (Figure 1). The
analytical system consists of two major
subsystems, an oxidation system for recovery
of the sample from the condensate trap and a
TGNMO analyzer. The TGNMO analyzer is a
FID preceded by a reduction catalyst.
oxidation catalyst, and GC column with
backflush capability (Figures 2 and 3). The
system for the removal and conditioning of
the organics captured in the condensate trap
consists of a heat source, oxidation catalyst.
nondispersive infrared (ND1R) analyzer and
an intermediate gas collection tank (Figure 4).
V-MM.-18
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Federal Register / Vol. 44. No. 195 / Friday. October 5.1979 / Proposed Rules
tn
3
*-<
CD
CO
Q.
Q.
CD
o.
E
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cn
2 UJ
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Federal Register / Vol. 44. No. 195 / Friday. October 5,1979 / Proposed Rules
CARRIER GAS
CALIBRATION STANDARDS
SAMPLE TANK
INTERMEDIATE
COLLECTION
VESSEL
(CONDITIONED TRAP SAMPLE)
NON-METHANE
ORGANICS
REDUCTION
CATALYST
1
FLAME
IONIZATION
DETECTOR
HYDROGEN
COMBUSTION
AIR
Figure 2. Simplified schematic of total gaseous non-methane
organic (TGNMO) analyzer.
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2
5
O
5
Z
5
3
3)
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Federal Register / Vol. 44, No. 195 / Friday, October 5, 1979 / Proposed Rules
FLOW
METERS
t, CONTROL
II *rV VALVES \
SWITCHING
VALVES
CONNECTORS
CATALYST
BYPASS
CARRIER
15 percent
02/N2
SAMPLE
CONDENSATE
TRAP
OXIDATION
CATALYST
HEATED
CHAMBER
REGULATING
ROTAMETER
NDIR
ANALYZER
FOR MONITORING PROGRESS
OF COMBUSTION ONLY
QUICK
CONNECT
V
H20
TRAP
INTERMEDIATE
COLLECTION
VESSEL
VACUUM*'
PUMP
MERCURY *»FOR EVACUATING COLLECTION
MANOMETER VESSELS AND SAMPLE TANKS
Figure 4. Condensate recovery and conditioning apparatus.
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Federal Register / Vol. 44, No. 195 /Friday, October 5, 1979 / Proposed Rules
2.2 Sampling.
2.2.1 Probe. V»" stainless steel tubing.
2.2.2 Condensate Trap. The condensate
trap shall be constructed of 316 stainless
steel; construction details of a suitable trap
are shown in Figure 5.
2.2.3 Flow Shut-off Valve. Stainless steel
control valve for starting and stopping
sample flow. -
2.2.4 Flow Control System. Any system
capable of maintaining the sampling rate to
within ±10 percent of the selected flow rate
(50100 cc/min. range).
2.2.S Vacuum Gauge. Vacuum gauge
calibrated in mm Hg. for monitoring the
vacuum of the evacuated sampling tank
during leak checks and sampling
2.2.6 Gas Collection Tank. Stainless steel
or aluminum lank with a volume of 4 to 8
liters. The tank is fitted with a stainless steel
female quick connect for assembly to the
sampling train and analytical system.
2.2.7 Mercury manometer. U-tube mercury
manometer capable of measureing pressure
to within 1.0 mm Hg in the 0/900 mm range.
2.2.8 Vacuum Pump. Capable of
pulling a vacuum of 700 mm Hg.
2.3 Analysis. For analysis, the
following equipment is needed.
2.3.1 Condensate Recovery and
Conditioning Apparatus (Figure 4).
2.3.1.1 Heat Source. A heat source
sufficient to heat the condensate trap to
a temperature just below the point
where the trap turns a "cherry red"
color is required. An electric muffle-type
furnace heated to 600" C is
recommended.
2.3.1.2 Oxidizing Catalyst. Inconel
tubing packed with an oxidizing catalyst
capable of meeting the catalyst
efficiency criteria of this method
(Section 4.4.2).
2.3.1.3 Water Trap. Any leak proof
moisture trap capable of removing
moisture from the gas stream may be
used.
2.3.1.4 NDIR Detector. A detector
capable of indicating COS concentration
in the zero to 5 percent range. This
detector is required for monitoring the
progress of combustion of the organic
compounds from the condensate trap.
2.3.1.5 Pressure Regulator. Stainless
steel needle valve required to maintain
the NDIR detector cell at a constant
pressure.
2.3.1.6 Intermediate Collection Tank.
Stainless steel or aluminum collection
vessel. Tanks with nominal volumes in
the 1 to 4 liter range are recommended.
The end of the tank is fitted with a
female quick connect.
2.3.2 Total Gaseous Nonmethane
Organic (TGNMO) Analyzer. Semi-
continuous GC/FID analyzer capable of:
(1) separating CO, COj, and CH4 from
nonmethane organic compounds, and (2)
oxidizing the non-methane organic
compounds to CO», reducing the CO2 to
methane, and quantifying the methane.
The analyzer shall be demonstrated
prior to initial use to be capable of
proper separation, oxidation, reduction,
and measurement. As a minimum, this
demonstration shall include
measurement of a known TGNMO
concentration present in a mixture that
also contains CH4, CO, and CO2 (see
paragraph 4.4.1).
2.3.2.1 The TGNMO analyzer
consists of the following major
components.
2.3.2.1.1 Oxidation Catalyst. Inconel
tubing packed with an oxidation
catalyst capable of meeting the catalyst
efficiency criteria of paragraph 4.4.1.2.
2.3.2.1.2 Reduction Catalyst. Inconel
tubing packed with a reduction catalyst
capable of meeting the catalyst
efficiency criteria of paragraph 4.4.1.3.
2.3.2.1.3 Separation Column. A gas
chromatographic column capable of
separating CO, COj, and CH, from
nonmethane organic compounds. The
specified column is as follows: Va inch
O.D. stainless steel packed with 3 feet of
10 percent methyl silicone, Sp 2100* (or
equivalent) on Supelcoport* (or
equivalent), 80/100 mesh, followed by
1.5 feet porapak Q* (or equivalent) 60/80
mesh. The inlet side is to the silicone.
Other columns may be used subject to
the approval of the Administrator. In
any event, proper separation shall be
demonstrated according to the
procedures of paragraph 4.4.1.4.
2.3.2.1.4 Sample Injection System. A
gas chromatographic sample injection
valve with sample loop sized to properly
interface with the TGNMO system.
2.3.2.1.5 Flame lonization Detector
(FID). A flame ionization detector
meeting the following specifications is
required:
2.3,2.1.5.1 Linearity. A linearity of
±5 percent of the expected value for
each full scale setting up to the
maximum percent absolute (methane or
carbon equivalent) calibration point is
required. The FID shall be demonstrated
prior to initial use to meet this
specification through a 5-point
(minimum) calibration. There shall be at
least one calibration point in each of the
following ranges: 5-10, 50-100, 500-1,000,
5,000-10,000, and 40,000-100,000 ppm
(methane or carbon equivalent).
Certification of such demonstration by
the manufacturer is acceptable. An
additional linearity performance check
(see Section 4.4.1.1) must be made
before each use (i.e., before each set of
samples is analyzed or daily whichever
occurs first).
2.3.2.1.5.2 Range. Signal attenuators
shall be available so that a minimum
'Mention of trade name does not constitute
endorsement.
signal response of 10 percent of full
scale can be produced when analyzing
calibration gas or sample.
2.3.2.1.5.3 Sensitivity. The detector
sensitivity shall be equal to or better
than 2.0 percent of the full scale setting.
with a minimum full scale setting of 10
ppm (methane or carbon equivalent)
2.3.2.1.6 Data Recording System
Analog strip chart recorder or digital
integration system for permanently
recording the analytical results.
2.3.3 Mercury Manometer L'-tube
mercury manometer capable of
measuring pressure to within 1.0 mm Hg
in the 0-900 mm range.
2.3.4 Barometer. Mercury, aneroid, or
other barometer capable of measuring
atmospheric pressure to within 1 mm.
2.3.5 Vacuum Pump. Laboratory
vacuum pump capable of evacuating the
sample tanks to an absolute pressure of
5 mm Hg.
3. Reagents.
3.1 Sampling.
3.1.1 Crushed Dry Ice.
3.2 Analysis.
3.2.1 TGNMO Analyzer.
3.2.1.1 Carrier Gas. Pure helium,
containing less than 1 ppm organics.
3.2.1.2 Fuel Gas. Pure Hydrogen,
containing less than 1 ppm organics.
3.2.2 Condensate Recovery and
Conditioning Apparatus.
3.2.2.1 Carrier Gas. Five percent O,
in N2, containing less than 1'ppm
organics.
3.3 Calibration For all calibration
gases, the manufacturer must
recommend a maximum shelf life for
each cylinder so that the gas
concentration does not change more
than ±5 percent from its certified value
The date of gas cylinder preparation,
certified organic concentration and
recommended maximum shelf life must
be affixed to each cylinder before
shipment from the gas manufacturer to
the buyer.
3.3.1 TGNMO Analyzer
3.3.1.1 Oxidation Catalyst Efficiency
Check. Gas mixture standard with
nominal concentration of 5 percent
methane and 5 percent oxygen in
nitrogen.
3.3.1.2 Reducation Catalyst
Efficiency Check. Gas mixture standard
with nominal concentration of 5 percent
CO2 in air.
3.3.1.3 Flame lonizafion Detector
Linearity Calibration Gases (3). Gas
mixture standards with known methane
(CH4) concentrations in the 5-10 ppm.
500-1,000 ppm, and 5-10 percent range.
in air. These gas standards are to be
used to check the FID linearity as
described in Section 4.4.1.1.
3.3.1.4 System Operation Standards
(2). These calibration gases are required
V-MM-23
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Federal Register / Vol. 44. No. 195 /Friday, October 5. 1979 / Proposed Rules
to check the total system operation as
specified in Section 4.4.1.4. Two gas
mixtures are required:
3.3.1.4,1 Gas mixture standard
containing (nominal) 50 ppm CO, 50 ppm
CH4. 2 percent CO2, and 15 ppm C3HS,
prepared in air.
3.3.1.4.2 Gas mixture standard
containing (nominal) 50 ppm CO, 50 ppm
CH,, 2 percent CO», and 1,000 ppm C3H,,
prepared in air.
3.3.2 Condensate Recovery and
Conditioning Apparatus. The calibration
gas specified in paragraph 3.3.1.1 is
required for performing an oxidation
catalyst check according to the
procedure of paragraph 4.4.2.
4. Procedure.
4.1 Sampling.
4.1.1 Sample Tank Evacuation.
Either in the laboratory or in the field,
evacuate the sample tank to 5 mm Hg
absolute pressure or less (measured by a
mercury U-tube manometer). Record the
temperature, barometric pressure, and
tank vacuum as measured by the
manometer.
4.1.2 Sample Tank Leak Check. Leak
check the gas sample tank immediately
after the tank is evacuated. Once the
tank is evacuated, allow the tank to sit
for 30 minutes. The tank is acceptable if
no change in tank vacuum (measured by
the mercury manometer) is noted.
4.1.3 Assembly. Just prior to
assembly, use a mercury U-tube
manometer to measure the tank vacuum.
Record this vacuum (Ptl), the ambient
temperature (Tti), and the barometric
pressure (Pb,) at this time. Assuring that
the flow control valve is in the closed
position, assemble the sampling system
as shown in Figure 1, Immerse the
condensate trap body in dry ice to
within 1 or 2 inches of the point where
the inlet tube joins the trap body.
4.1.4 Leak Check Procedures.
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Federal Register / Vol. 44. No. 195 / Friday, October 5, 1979 / Proposed Rules
PROBE, 3mm (1/8 m) 0.0.
INLET TUBE, gram (% in) 0.0.
CONNECTOR
EX IT TUBE. 6mm (X in) 0.0
CONNECTOR
CRIMPED AND WELDED GAS-TIGHT SEAL
^BARREL 19mm (* in) O.D. X 140mm (5-Vi in) LONG.
Urom (1/16 in) WALL
NO 40 HOLE
(THRU BOTH WALLS)
WELDED JOINTS
""-BARREL PACKING. 316 SS WOOL PACKED TIGHTLY
AT BOTTOM, LOOSELY AT TOP
HEAT SINK (NUT. PRESS-FIT TO BARREL)
WELDED PLUG
MATERIAL. TYPE 316 STAINLESS STEEL
Figure 5. Condensate trap2.
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Federal Register / Vol. 44. No. 195 / Friday, October S, 1079 / Proposed Rules
(A
2
to
CO
a
a
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Federal Register / Vol. 44. No. 195 / Friday, October 5,1979 / Proposed Rules
VOLATILE ORGANIC CARBON
FACILITY,
LOCATION.
DATE
SAMPLE LOCATION.
OPERATOR
RUN NUMBER
TANK NUMBER.
.TRAP NUMBER.
.SAMPLE ID NUMBER.
PRETEST (MANOMETER)
PQ$T TF$T (MANOMETER)
TANK VACUUM,
mm Hg
(GAUGE!
fRAiinn
BAROMETRIC
PRESSURE,
mm Hg
AMBIENT
TEMPERATURE,
"C
LEAK RATE, mm Hg/5 mm..
TANK
PRETEST.
POST TEST.
TRAP HALF
TIME
CLOCK/SAMPLE
GAUGE VACUUM,
mm Hg
FLOWMETER SETTING
COMMENTS
Figure 7. Example Field Data Form.
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Federal Register / Vol. 44, No. 195 / Friday. October 5. 1979 / Proposed Rules
4.1.4 1 Pretest Leak Check. A pretest
leak check is required. After the
sampling train is assembled, record the
tank vacuum as indicated by the
vacuum gauge. Wait a minimum period
of 15 minutes and recheck the indicated
vacuum. If, the vacuum has not changed,
the portion of the sampling train behind
the shut-off valve does not leak and is
considered acceptable. To check the
front portion of the sampling train,
attach the leak check apparatus (Figure
6) to the probe tip. Evacuate the front
half of the train (i.e., do not open the
sampling train flow control valve) to a
vacuum of at least 500 mm Hg. Close the
shut-off valve on the leak check
apparatus and record the vacuum
indicated by the manometer on the data
sheet (Figure 7). Allow the system to sit
for 5 minutes and then recheck the
vacuum. A change of less than 2 mm Hg
for the 5-minute leak check period is
acceptable Record the front half leak
rate (mm Hg/5-minute period) on the
data form. When an acceptable leak
rate has been obtained disconnect the
leak check apparatus from the probe tip.
4.1.4.2 Post Test Leak Check. A leak
check is mandatory at the conclusion of
each test run. After sampling is
completed, attach the U-tube manometer
to the probe tip; minimize the amount of
flexible line used. Open the sample train
flow control valve for a period of 2
minutes or until the vacuum indicated
on the manometer stabilizes, whichever
occurs first; shut off the sample train
flow control valve. Record the vacuums
indicated on the manometer (front half)
and on the tank vacuum gauge (back-
half)- After 5 minutes, recheck these
vacuum readings. A leak rate of less
than 2 mm Hg per 5-minute period is
acceptable for the front half; the back
half portion is acceptable if no visible
change in the tank vacuum gauge
occurs Record the post test leak rate
(mm Hg per 5 minutes), and then
disconnect the manometer from the
probe tip and seal the probe. If the
sampling train does not pass the post
test leak check, invalidate the run.
4.1 5 Sample Train Operation Place
the probe into the stack such that the
probe is perpendicular to the direction
of stack gas flow; locate the probe tip at
a single preselected point. For stacks
having a negative static pressure, assure
that the sample port is sufficiently
sealed to prevent air in-leakage around
the probe Check the dry ice level and
add ice if necessary. Record the clock
time and sample tank gauge vacuum. To
begin sampling, open and adjust (if
applicable) the flow control valve(s) of
the flow control system utilized in the
sampling train; maintain a constant flow
rate (± 10 percent) throughout the
duration of the sampling period. Record
the gauge vacuum and flowmeler setting
(if applicable) at 5-minute intervals.
Select a total sample time greater than
or equal to the minimum sampling time
specified in the applicable subpart of the
regulation; end the sampling when this
time period is reached or wh«n a
constant flow rate can no longer be
maintained. When the sampling is
completed, close the gas sampling tank
control valve. Record the final readings.
Note: If the sampling had to be stopped
before obtaining the minimum sampling
time (specified in the applicable
subpart) because a constant flow rate
could not be maintained, proceed as
follows: After removing the probe from
the stack, remove the evacuated tank
from the sampling train {without
disconnecting other portions of the
sampling train) and connect another
evacuated tank to the sampling train.
Prior to attaching the new tank to the
sampling train, assure that the tank
vacuum (measured on-site by the U-tube
manometer) has been recorded on the
data form and that the tank has been
leak-checked (on-site). After the new
tank is attached to the sample train,
proceed with the sampling-, after the
required minimum sampling time has
been exceeded, end the lest.
4.2 Sample Recovery. After sampling
is completed, remove the probe from the
stack and seal the probe end. Conduct
the post test leak check according to the
procedures of paragraph 4.1.4.2. After
the post test leak check has been
conducted, disconnect the condensate
trap at the flow metering system. Tightly
seal the ends of the condensate trap;
keep the trap packed in dry ice until
analysis. Remove the flow metering
system from the sample tank. Attach the
U-tube manometer to the tank (keep
length of flexible connecting line to a
minimum) and record the final tank
vacuum (PJ, record the tank
temperature (Ttl and barometric
pressure at this time. Disconnect the
manometer from the tank. Assure that
the test run number is properly
identified on the condensate trap and
evacuated tank(s)
4.3 Analysis
4.3.1 Preparation
4.3.1.1 TGNMO Analyzer. Set the
carrier gas, air, and fuel flow rates and
then begin heating the catalysts to their
operating temperatures. Conduct the
calibration linearity check required in
paragraph 4.4.1.1 and the system
operation check required in paragraph
4.4.1.4. Optional: Conduct the catalyst
performance checks required in
paragraphs 4.4.1.2 and 4.4.1.3 prior to
analyzing the test samples
4.3.1.2 Condensate Recovery and
Conditioning Apparatus. Set the carrier
gas flow rate and begin heating the
catalyst to its operating temperature.
Conduct the catalyst performance check
required in paragraph 4.4.2 prior to
oxidizing any samples.
4.3.2 Condensate Trap Carbon.
Dioxide Purge and Evacuated SampSe
Tank Pressurization. The first step in
analysis is to purge the condensate trap
of any COS which it may contain and to
simultaneously pressurize the gas
sample tank. This is accomplished as
follows: Obtain both the sample tank
and condensate trap from the test run to
be analyzed. Set up the condensn'e
recovery and conditioning apparatus so
that the carrier flow bypasses the
condensate trap hook-up terminals.
bypasses the oxidation catalyst, and is
vented to the atmosphere. Next, attach
the condensate trap to the apparatus
and pack the trap in dry ice. Assure that
the valve isolating the collection vessel
connection from the atmospheric vent is
closed and then attach the gas sample
tank to the system as if it were the
intermediate collection vessel Record
the tank vacuum on the laboratory data
form. Assure that the NDIR analyzer
indicates a zero output level and then
switch the carrier flow through the
condensate trap; immediately switch the
carrier flow from vent to collect and
open the valve to the tank. The
condensate trap recovery and
conditioning apparatus should now be
set up as indicated in Figure 8. Monitor
the NDIR; when CO. is no longer being
passed through the system, switch the
carrier flow so that it once again
bypasses the condensate trap Continue
in this manner until the gas sample tank
is pressurized to a nominal gauge
pressure of 800 mm mercury. At this
time, isolate the tank, vent the carrier
flow, and record the sample tank
pressure (P,f), barometric pressure (PM)
and ambient temperature (TM). Remove
the gas sample tank from the system
V-MM-28
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Federal Register / Vol. 44. Np._195 / Friday, Octobers, 1979 / Proposed Rules
(OPEN)
FLOW
METERS
FLOW
^CONTROL
(OPEN)
CARRIER
6 pcrccntj
02/N2
VENT
VALVE
(OPEN)
REGULATING
ROTAMETER
QUICK rJ-i
CONNECT^
VALVE
(CLOSED)
TRAP
BYPASS
CATALYST
BYPASS
OXIDATION
CATALYST
HEATED
CHAMBER
1
1
1
1
*. FOR MONITORING PROGRESS
OF COMBUSTION ONLY
INTERMEDIATE
COLLECTION
VESSEL
VACUUM*
PUMP
(OFF)
V
H20
TRAP
MERCURY
MANOMETER
**FOR EVACUATING COLLECTION
VESSELS AND SAMPLE TANKS
Figure 8. Condensate recovery and conditioning apparatus, carbon dioxide purge.
V-MM-29
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Federal Register / Vol. 44. No. 195 / Friday. October 5,1979 / Proposed Rules
FLOW
X" METERS ~>\
~^y M
*"^ FLOW
i -CONTROL
*fV VALVES N'T*
^h^ rV
-------
Federal Register / Vol. 44, No. 195 / Friday, October 5.1979 / Proposed Rules
4.3 3 Recovery of Condensate Trap
Sample. Oxidation and collection of the
sample in the condensate trap is now
ready to begin. From the step just
cor-pleted in paragraph 4.3.2 above, the
system should be set up so that the
carrier flow bypasses the condensate
irap. bypasses the oxidation catalyst
and is vented to the atmosphere. Attach
an evacuated intermediate collection
vessel to the system and then, switch
the carrier so that it flows through the
oxidation catalyst. Monitor the NDIR
and assure that the analyzer indicates a
zero output level. Switch the carrier
from vent to collect and open the
collection tank valve; remove the dry ice
from the trap and then switch the carrier
flow through the trap. The system
should now be set up to operate as
indicated in Figure 9.
Begin heating the condensate trap.
The trap should be heated to a
temperature at which the trap glows a
"dull red" (approximately 600° C) and
should be maintained at this
temperature for at least 5 minutes.
During oxidation of the condensate trap
sample, monitor the NDIR to determine
when all the sample has been removed
and oxidized (indicated by return to
baseline of NDIR analyzer output).
When complete recovery has been
indicated, remove the heat from the trap.
However, continue the carrier flow until
the intermediate collection vessel is
pressurized to a gauge pressure of 800
mm Hg (nominal). When the vessel is
pressurized, vent the carrier; measure
and record the final intermediate
collection vessel pressure (Pf) as well as
the barometric pressure (Pbv), ambient
temperature (Tv), and collection vessel
volume (Vv).
4.3.4 Analysis of Recovered
Condensate Sample. After the
preparation steps in paragraph 4.3.1
have been completed, the analyzer is
ready for conducting analyses. Assure
that the analyzer system is set so that
the carrier gas is routed through the
reduction catalyst to the FID (flow
through the separation column and
oxidation catalyst is optional). Attach
the intermediate collection vessel to the
tank inlet fitting of the TGNMO
analyzer. Purge the sample loop with
sample and then inject a preliminary
sample in order to determine the
appropriate FID attenuation. Inject
triplicate samples from the intermediate
collection vessel and record the values
(Gem)- When appropriate, check the
instrument calibration according to the
procedures of paragraph 4.4.1.4.
4.3.5 Analysis of Gas Sample Tank.
Assure that the analyzer is set up so that
the carrier flow is routed through the
separation column as well as both the
oxidation and reduction catalysts.
During analysis for the nonmethane
crganics the separation column is
operated as follows; First, operate the
column at 78° C (dry ice temperature)
lo elute the CO and CH4. After the CH.
peak, operate the column at 0° C to elute
the CO,. When the CO2 is completely
eluted, switch the carrier flow to
backflush the column and
simultaneously raise the column
temperature to 100° C in order to elute
all nonmethane organics. (Exact timings
for column operation are determined
from the calibration standard). Attach
the gas sample tank to the tank inlet
fitting of the TGNMO analyzer. Purge
the sample loop with sample and inject
a preliminary sample in order to
determine the appropriate FID
attenuation for monitoring the
backflushed non-methane organics.
Inject triplicate samples from the gas
sample tank and record the values
obtained for the nonmethane organics
(Ctm). When appropriate, check the
instrument calibration according to the
procedures of paragraph 4.4.1.4.
4.4 Calibration. Maintain a record of
performance of each item.
4.4.1 TGNMO Analyzer.
4.4.1.1 FID Calibration and linearity
check. Set up the TGNMO system so
that the carrier gas bypasses the
oxidation and reduction catalysts. Zero
and span the FID by injecting samples of
the high value (5-10 percent) calibration
gas (paragraph 3.3.1.3) and adjusting the
instrument output to the correct level.
Then check the instrument linearity by
injecting triplicate samples of the low
(5-10 ppm) and mid-range (500-1,000
ppm) calibration gases (paragraph
3.3.1.3). The system linearity is
acceptable if the results (average for
triplicate samples of each gas) are
within ±5 percent of the expected
values. This calibration and linearity
check shall be conducted prior to
analyzing each set of samples (i.e.,
samples from a given source test).
4.4.1.2 Oxidation Catalyst Efficiency
Check. This check should be performed
on a frequency established by the
amount of use of the analyzer and the
nature of the organic emissions to which
the catalyst is exposed. As a minimum,
perform this check prior to putting the
analyzer into service.
To confirm that the oxidation catalyst
is functioning in a correct manner, the
operator must turn off or bypass the
reduction catalyst while operating the
analyzer in an otherwise normal
fashion. Inject triplicate samples of the
methane standard gas (paragraph
3.3.1.1) into the system. If oxidation ia
adequate, the only gas that will then
reach the detector will be CO», to which
the FID has no response. If a response is
noted, the oxidation catalyst must be
replaced.
4.4.1.3 Reduction Catalyst Efficiency
Check. This check should be performed
on a frequency established by the
amount of use of the analyzer. As a
minimum, perform this check prior to
putting the analyzer into service. To
confirm proper operation of the
reduction catalyst, the operator must
bypass the oxidation catalyst while
operating the analyzer in an otherwise
normal manner. After setting the carrier
flow to bypass the oxidation catalyst
inject triplicate samples of the carbon
dioxide standard gas (Section 3.3.1.2).
The catalyst operation is acceptable if
the average response of the triplicate
CO2 sample injections is within ±2
percent of the expected value and no
one CO2 sample injection varies by more
than ±5 percent from the expected
value.
4.4.1.4 System Operation Check. This
system check should be conducted at a
frequency consistent with the amount of
use and the reliability of the particular
analyzer. As a minimum, this system
check shall be conducted before and
after each set of emission samples is
analyzed. If this system check is not
successfully completed at the conclusion
of the analyses, the results shall be
invalidated. Operate the TGNMO
analyzer in a normal fashion, passing
the carrier flow through the separation
column and both the oxidation and
reduction catalysts. Inject triplicate
samples of the two mixed gas standards
specified in Section 3.3.1.4. The system
operation is acceptable if, for each gas
mixture, the average non-methane
organic value for the triplicate samples
is within ±3 percent of the expected
value and no one sample analysis varies
by more than ±5 percent from the
average value for the triplicate samples.
4.4.2 Condensate Trap Recovery and
Conditioning Apparatus Oxidation
Catalyst Check. This catalyst check
should be conducted at a frequency
consistent with the amount of use of the
catalyst, as well as, the nature and
concentration level of the organics being
recovered by the system. As a minimum,
perform this check prior to and
immediately after conditioning each set
of emission sample traps.
Set up the condensate trap recovery
system so that the carrier flow bypasses
the trap inlet and is vented to the
atmosphere at the system outlet. Assure
that the tank collection valve is closed
and then attach an evacuated
intermediate collection vessel to the
system. Connect the methane standard
gas cylinder (Section 3.3.1.1] to the
V-MM-31
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Federal Register / Vol. 44, No. 195 / Friday, October 5. 1979 / Proposed Rules
system's condensate trap connector
(probe end, figure 4). Adjust the system
valving so that the standard gas cylinder
acts as the carrier gas; switch off the
carrier and use the cylinder of standard
gas to supply a gas flow rate equal to
the carrier flow normally used during
trap sample recovery. Now switch from
vent to collect in order to begin
collecting a sample. Continue collecting
a sample in the normal manner until the
intermediate vessel is filled to a nominal
pressure of 300 mm Hg. Remove the
intermediate vessel from the system and
vent the carrier flow to the atmosphere.
Switch the valving to return the system
to its normal carrier gas and normal
operating conditions. Set up the
TGNMO analyzer to operate with the
oxidation and reduction catalysts
bypassed. Inject a sample from the
intermediate collection vessel into the
analyzer. The operation of the
condensate trap recovery system
oxidation catalyst is acceptable if
oxidation of the standard methane gas
was 99.5 percent complete, as indicated
by the response of the TGNMO analyzer
FID.
4.4.3 Gas Sampling Tank. The
volume of the gas sampling tanks used
must be determined. Prior to putting
each tank in service, determine the tank
volume by weighting the tanks empty
and then filled with water; weight to the
nearest 0.5 gm and record the results.
4.4.4 Intermediate Collection Vessel.
The volume of the intermediate
collection vessels used to collect COa
during the analysis of the condensate
traps must be determined. Prior to
putting each vessel into service,
determine the volume by weighting the
vessel empty and then filled with water;
weigh to the nearest 0.5 gm and record
the results.
5. Calculations,
Note. All equations are written using
absolute pressure; absolute pressures are
determined by adding the measured
barometric pressure to the measured gauge
pressure.
5.1 Sample Volume. For each test
run, calculate the gas volume sampled:
0.386 V
5.2 Noncondensible Organics. For
each collection tank, determine the
concentration of nonmethane organics
(ppm C):
5.3 Condensible Organics. For each
condensate trap determine the
concentration of organics (ppm C):
0.386
A r c
U * v~
tf
r
x r
5.4 Total Gaseous Nonmethane
Organics (TGNMO). To determine the
TGNMO concentration for each test run,
use the following equation:
C=C, + CC
Where:
C=Total gaseous nonmethane organic
(TGNMO) concentration of the effluent,
ppm carbon equivalent.
Cc=Calcu!ated condensible organic
(condensate trap) concentration of the
effluent, ppm carbon equivalent.
COT = Measured concentration (TGNMO
analyzer) for the condensate trap
(intermediate collection vessel), ppm
methane.
C,=Calculated noncondensible organic
concentration of the effluent, ppm carbon
equivalent.
Ctm = Measured concentration (TGNMO
analyzer) for gas collection tank sample,
ppm methane.
Pf=Final pressure of intermediate collection
vessel, mm Hg , absolute.
Pu = Gas sample tank pressure prior to
sampling, mm Hg, absolute.
P,=Gas sample tank pressure after sampling,
but prior to pressurizing, mm Hg,
absolute.
Pt,=Final gas sample tank pressure after
pressurizing, mm Hg. absolute.
Tf=Fmal temperature of intermediate
Collection vessel, °K.
Ttl = Gas sample tank temperature prior to
sampling. °K.
T, = Cas sample tank temperature at
completion of sampling. °K.
Ttf=Gas sample tank temperature after
pressurizing. °K.
V = Gas collection tank volume, dscm.
V, = Intermediate collection tank volume.
dscm
V,=Gas volume sampled, dscm.
r=Total number of analyzer injections of
tank sample during analysis (where
j = injection number. 1 . . . r).
n = Total number of analyzer injections of
condensible intermediate collection
vessel during analysis (where
k = injection number, 1 . . . n).
Standard Conditions = Dry. 760 mm Hg.
293°K.
6. Bibliography.
6.1 Albert E. Salo, Samuel Witz, and
Robert D. MacPhee. "Determination of
Solvent Vapor Concentrations by Total
Combustion Analysis: A comparison of
Infrared with Flame lonization
Detectors." Presented at the 68th Annual
Meeting of the Air Pollution Control
Association, Boston, Ma. Paper No. 75-
33.2 June 15-20, 1975.
6.2 Albert E. Salo, William L. Oaks,
Robert D. MacPhee. "Measuring the
Organic Carbon Content of Source
Emissions for Air Pollution Control."
Presented at the 67th Annual Meeting of
the Air Pollution Control Association,
Denver, Colorado, Paper No. 74-190,
June 9-13,1974.
|FR Doc 78-30806 Fiied Ift-*-'9 8 45 ami
V-MM-32
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ENVIRONMENTAL
PROTECTION
AGENCY
STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
PHOSPHATE ROCK PLANTS
SUBMRTNN
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Federal Register / Vol. 44, No. 185 / Friday, September 21.1979 / Proposed Rules
140 CFR Part 60]
[FRL-1282-2]
Standards of Performance for New
Stationary Sources; Phosphate Rock
Plants
AGENCY: Environmental Protection
Agency.
ACTION: Proposed Rule and
Announcement of Public Hearing.
SUMMARY: This action is being proposed
to limit emissions of particulate matter
from new, modified, and reconstructed
phosphate rock plants. Reference
Method 5 would be used for determining
compliance with these standards. The
standards implement the Clean Air Act
and result from the Administrator's
determination on August 21, 1979 [44 FR
49222) that phosphate rock plant
emissions contribute significantly to air
pollution. The intended effect is to
require new, modified, and
reconstructed phosphate rock plants to
use the best demonstrated system of
emission reduction, considering costs,
nonair quality health and environmental
impact and energy impacts.
DATES: Comments. Deadline for
comments is November 26, 1979.
Public hearing A public hearing will
be held on October 25, 1979.
Requests to speak at hearing. Persons
wishing to speak at the hearing must
contact Shirley Tabler, Emission
Standards and Engineering Division
(MD-13), Environmental Protection
Agency, Research Triangle Park, North
Carolina 27711, telephone number (919)
541-5421 by October 18, 1979.
ADDRESSES: Comments. Comments
should be submitted to the Central
Docket Section (A-130), U.S.
Environmental Protection Agency. 401 M
Street, SW.. Washington, D.C. 20460.
Attention- Docket No. OAQPS-79-6.
Background Information. The
Background Information Document for
the proposed standards may be
obtained from the U.S. EPA Library
(MD-35), Research Triangle Park, North
Carolina 27711, telephone number: (919)
541-2777 Please refer to "Phosphate
Rock Plants. Background Information:
Proposed Standards of Performance"
(EPA-150/3-79-017).
Docket A docket (number OAQPS-
79-6) containing information used by
EPA in development of the proposed
standard is available for public
inspection between 8:00 a.m. and 4:00
p.m.. Monday through Friday, at EPA's
Central Docket Section, Room 2903B,
Waterside Mall, 401 M Street, SW.,
Washington, D.C. 20460.
FOR FURTHER INFORMATION CONTACT:
Don Goodwin, Director, Emission
Standards and Engineering Division,
Environmental Protection Agency,
Research Triangle Park, North Carolina
27711, telephone number: (919) 541-5271.
SUPPLEMENTARY INFORMATION!.
Summary of Proposed Standards
The proposed standards would apply
to new, modified, or reconstructed
phosphate rock dryers, calciners,
grinders, and ground rock handling and
storage facilities. The proposed
standards would limit emissions of
particulate matter to 0.02 kilogram [kg)
per megagram (Mg) of rock feed (0.04 lb"/
ton) from phosphate rock dryers, 0.055
kg/Mg (0.11 Ib/ton) from phosphate rock
calciners, and 0.006 kg/Mg (0.012 Ib/ton)
from phosphate rock grinders. An
opacity standard of zero percent opacity
is proposed for ground rock handling
system, dryers, calciners, and grinders.
The use of continuous opacity
monitoring systems would be required
for each affected facility. However,
when scrubbers are used for emission
control, continuous opacity monitoring
would not be required. Instead, the
pressure drop of the scrubber and the
liquid supply pressure would be
monitored as indicators of the scrubber
performance.
Summary of Environmental and
Economic Impacts
The proposed standards would impact
an estimated 110 teragrams (122 million
tons) of annual phosphate rock
production by 1995. About one half of
that would be due to construction of
new phosphate rock processing plants
and the remainder due to expansion of
industry capacity at existing plants.
The proposed standards would reduce
the particulate emissions from new
phosphate rock plants by about 99
percent below the levels that would
occur with no control and by about 85 to
98 percent below the levels allowed by
typical State standards, depending on
the type of facility. These emission
reductions would reduce nationwide
particulate emissions by about 19
gigagrams (21,000 tons) per year in 1985.
The maximum 24-hour average ambient
air concentration of particulate matter
due to emissions from a typical dryer
controlled to the level required by the
proposed standard would be about 88
fig/m3. Similarly, for a typical calciner,
imposition of the proposed emission
standard would result in a maximum
ambient level of 14 ^g/m3. and for a
typical grinder the ambient level could
reach a maximum of 1 fig/m3.
The annualized costs of operating
control equipment that would be needed
to attain the proposed standards were
estimated using model plants. Because
typical Florida phosphate rock plants
are larger than Western plants, the
control costs per ton of production are
lower.
The annualized cost of installing and
operating prevailing controls used to
meet existing State standards at typical
Florida phosphate rock plants is
estimated at $0.35 per metric ton. The
additional cost of employing control
technology to meet the proposed
standards at a new Florida plant is
estimated at $0.02/metric ton when
using baghouses and $0.07/metric ton
for scrubbers.
The annualized cost of using
prevailing controls to meet existing
State standards in a typical new
Western plant is $0.87/metric ton. The
additional cost of using control
technology to meet the proposed
standards at new Western plants is
estimated at $0 06/metric ton for
baghouse control and $0.21/metric ton
for scrubbers.
The additional costs of meeting the
proposed standards are relatively minor
when scrubbers or baghouses are used.
Electrostatic precipitators (ESP) could
also be used to meet the proposed
standards, but their use is not
anticipated because of their higher
annualized costs of operation. The
difference in cost between using the best
system of emission reduction to meet
the proposed standards level and using
prevailing controls to meet the State
Implementation Plan (SIP) levels would
have negligible impact on the
profitability of the plant and the future
growlh of the phosphate rock industry if
the proposed standards were
implemented. By the year 1985,
compliance with the proposed standards
would increase the industry cost of
production of phosphate rock by 01
percent (baghouse controls) to 0 2
percent (scrubber controls) above the
cost to meet existing State
Implementation Plan regulations A
more detailed discussion of the
economic analysis is discussed in the
Background Information Document.
Assuming baghouses are used to meet
the proposed standards, the total
industry capital cost for the first five
years after imposition of the proposed
standards would be about $8.5 million
greater than the capital costs incurred
meeting typical State standards. The
total industry annualized cost increase
to meet the proposed standards by the
fifth year would be about $0.8 million.
V-NN-2
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Federal Register / Vol. 44, No. 185 / Friday, September 21, 1979 / Proposed Rules
The incremental energy required to
meet the proposed standards depends
on the control utilized. If baghouses are
employed, total industry energy
consumption in the fifth year after
imposition of the proposed standards
will increase by about 1.7 percent over
the levels projected to occur under State
regulations. Total industry consumption
in the fifth year will increase by 2.6
percent when scrubbers are employed,
and about 0.1 percent should
electrostatic precipitators be used. This
corresponds to a fifth year total increase
in industry energy consumpton of 39 x
10* kWh/vr when baghouses are used,
60 x 10* kWh/yr when high energy
scrubbers are used, and .009 x 106 kWh/
yr when electrostatic precipitators are
used.
Utilization of any of the alternative
control technologies (baghouse,
crubber, or ESP) would result in
minimal adverse environmental impacts.
If high energy scrubbers or wet ESPs are
used to achieve the standards, this
would result in adverse impacts on solid
waste disposal, water pollution, and
energy consumption. However, the
incremental increase (over the
prevailing controls) of solid materials
and wastewaters produced during
control of emissions from phosphate
rock facilities is minor in comparison
with (1) the large volumes of process
wastewaters and solid wastes, and (2)
the total amounts of wastewaters and
solid waste already collected by
prevailing controls to meet existing
State standards. Utilization of baghouse
technology is marginally more
environmentally acceptable than other
control alternatives because no water
pollution and less solid waste is
produced.
Rationale for the Proposed Standards
Selection of Source for Control
Section 111 of the Act requires
establishment of standards of
performance for new, modified, or
reconstructed stationary sources that
cause or contribute significantly to air
pollution which may reasonably be
anticipated to endanger public health or
welfare. The EPA has determined that
sources which cause ambient suspended
particulate matter may cause adverse
health and welfare effects. Accordingly,
under the authority of Section 109 of the
Act, the Administrator has designated
particulate matter as a criteria pollutant
and has established national ambient
air quality standards for this pollutant.
Phosphate rock processing plants
have been shown to be a significant
source of particulate matter emissions.
The Priority List of sources for New
Source Performance Standards (40 CFR
60.16, 44 FR 49222, dated August 21,
1979) identified various sources of
emissions on a nationwide basis in
terms of the potential improvement in
emission reduction that could result
from their imposition. The sources on
this list are ranked based on decreasing
order of potential emission reduction.
Phosphate rock plants currently rank
16th of 59 sources on the list, and are,
therefore, of considerable importance
nationwide. In addition, a study
performed for EPA in 1975 by the
Argonne National Laboratory showed
phosphate rock dryers ranked 4th of the
nation's highest 18 particulate source
categories which require control
systems with moderate energy
consumption. The same study showed
phosphate rock grinders as ranking
fifteenth of the nation's 56 largest
particulate source categories. Finally,
results of dispersion modeling analysis
indicate that particulate emission
sources at phosphate rock plants
contribute significantly to the
deterioration of air quality.
Additional factors leading to the
selection of the phosphate rock industry
for the development of standards of
performance include the expected
growth rate of the industry and the
signficant reductions in particulate
matter emissions achievable with
application of available emissions
control technology. The United States is
the largest producer and consumer of
phosphate rock in the world. From 1959
to 1973, the production of phosphate
rock increased at an annual rate of
about six percent and production is
expected to increase at an annual rate
of about three percent per year through
the year 2000. By the year 1985 new and
modified phosphate rock plants would
cause an increase in nationwide
emissions of particulate matter of about
19 gigagrams per pear (21,000 tons/year)
above the level expected with
implementation of the proposed
standards. At most plants, the degree of
emissions control (imposed by State
Implementation plans) is considerably
less than that achievable with
application of the best technology for
emission control.
Selection of Affected Facility and
Pollutants
At phosphate rock installations, the
normal sequence of operation is: Mining,
beneficiation, conveying of wet rock to
and from storage, drying or calcining or
nodulizing, conveying and storage of dry
rock, grinding, and conveying and
storage of ground rock. Mining and
beneficiation are a minor source of
particulate emissions. Nodulizing. and
elemental phosphorous production are
not selected as affected facilities as
these sources are not expected to
exhibit growth potential. Dryers,
calciners, grinders and ground rock
handling systems account for nearly all
of the particulate matter emissions from
phosphate rock plants. Accordingly, the
proposed standards have been
developed for these sources.
Phosphate rock processing plants are
sources of emissions of participates.
fluorides, sulfur dioxide (SO,) and
certain radioactive substances.
Standards are being proposed only for
the control of particulate matter
emissions at this time. Based on
Tennessee Valley Authority research,
and emission measurements of fluorides
in calciner exhaust gases, it is unlikely
that significant quantities of fluorine
will be volatized at temperatures
experienced in dryers or calciners.
Emission of sulfur oxides generated by
oil-firing in dryers and calciners is
minimized by reaction with alkaline
materials naturally occurring in the
phosphate rock ore. Additional studies
of the radioactive materials in the
emissions are planned and EPA could, if
warranted, take additional action under
Section 112 of the Clean Air Act at a
future date.
Potential particulate emissions from
typical uncontrolled phosphate rock
facilities would amount to about 2.9 kg/
Mg (5.8 Ib/ton) of rock feed from the
dryer, 7.7 kg/Mg (15.4 Ib/ton) of rock
feed from the calciner. and about 0.8 kg/
Mg (1.6 Ib/ton) of rock feed from the
grinder. The typical State emission limit
for dryers is 0.13 kg/Mg (0.26 Ib/ton),
and the limit for calciners and grinders
is about 0.44 kg/Mg (0.88 Ib/ton).
Through application of alternative
control technology (e.g., the baghouse. or
high energy scrubber), the emissions
from these facilities could be further
reduced to 0.02 kg/Mg (0.04 Ib/ton) for
dryers, 0.055 kg/Mg (0.11 Ib/ton] for
calciners. and 0.006 kg/Mg (0 012 Ib/ton)
for grinders. Control limits for ground
rock handling and storage operations
are difficult to define owing to wide
variations jn system equipment and the
numerous fugitive emission sources
contained in these systems At most
installations, particulate emissions are
collected by an evacuation system and
vented through a baghouse. Greater
assurance that such control system are
installed, operated and maintained in
accordance with good practice can be
achieved by enforcing stringent opacity
standards.
V-NN-3
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Federal Register / Vol. 44. No. 185 / Friday, September 21. 1979 / Proposed Rules
Selection of Best System of Emission
Reduction Considering Costs
Based on potential environmental,
economic and energy impacts, EPA has
concluded that either a fabric filitration
system or a high energy venturi scrubber
system is the best technological system
of continuous particulate emissions
reduction from each of the affected
facilities. The fabric filtration system,
high energy scrubber and high efficiency
electrostatic precipitator are judged to
be equally effective in terms of
emissions reduction capability. The
proposed standards are, therefore,
based on the use of any of the three
alternative control methods, although
cost considerations would favor the use
of the baghouse or high energy scrubber
over the ESP.
The economic and environmental
adverse impacts associated with the
alternative controls would favor the use
of the baghouse controls. The eonomic
and environmental advantages of the
baghouse are most apparent at grinding
and material handling/storage facilities,
where baghouses are already the
prevailing control employed. In contrast
to the baghouse, wet collection systems
produce water pollution and more solid
waste, although the incremental adverse
environmental impact produced by
these systems is small in comparison
with adverse effects presently produced
by phosphate rock plant processes, and
would not preclude the use of these
systems as environmentally acceptable
control alternatives.
Selection of Format for Standard
The format of the proposed standard
could be either a concentration standard
or a mass-per-unit-of-feed standard. A
control efficiency format could not be
selected because of limited scope in the
data base and practical considerations
involving the complexity of performance
test requirements. An equipment
standard was not considered because
Section 111 of the Act requires
application of emission limits when
feasible. The mass-emission-per-unit-
feed standard was selected over the
concentration standard format because
this format: (1) Is related directly to the
total quantity of emissions discharged to
the atmosphere, (2) is more equitable in
that the degree of emissions permitted is
related to the amount of product
processed, (3) is consistent with the
format of existing applicable State
standards, (4) does not discourage use of
more efficient process systems which
reduce exhaust gas volumes, and (5)
provides that the standard is not
circumvented by dilution or high volume
flows in the exhaust system. The mass
emissions format is appropriate for the
dryers, calciners, and grinder facilities.
However, because of wide variations in
the designs of ground rock handling
systems, and because a substantial
portion of the potential emissions are
fugitive and difficult to measure, a
visible emission standard is the only
format appropriate for ground rock
handling systems.
Emission Standards for Dryers
Source tests were conducted on
dryers at two phosphate rock plants
processing pebble rock. The pebble rock
is considered to present the most
adverse conditions for control of
emissions from dryers because it
receives relatively little washing and
enters the dryer containing a substantial
percentage of clay. Hence, any control
level limit for dryers processing pebble
rock should also be capable of meeting
the limit for all other dryers as well.
Particulate emissions from the dryer
controlled by a venturi scrubber
operating at about 4.4 kilopascals
pressure drop (18 inches of water)
averaged 0.020 and 0.019 kg/Mg (0.039
and 0.038 Ib/ton) for separate EPA tests.
Particulate emissions from the dryer
controlled by an ESP averaged 0.012 and
0.027 kg/Mg (0.024 and 0.054 Ib/ton) for
EPA and operator tests, respectively.
The test results show that the venturi
scrubber was capable of achieving
emission levels of 0.02 kg/Mg or better
from phosphate rock dryers emitting
high levels of particulates. The tests also
revealed that the venturi scrubber was
achieving a control efficiency of 99.2
percent. This is nearly equivalent to that
estimated to be attainable by the best
system of emission reduction (99.4
percent by a baghouse) when treating
the same emission loading and particle
size distribution. Based on analysis
using a programmable EPA scrubber
model (the model is described in EPA
report No. EPA-600/7-78-026), it was
estimated that increasing the scrubber
energy to a pressure drop of 6.2
kilopascals (25 inches of water) would
achieve the degree of control equivalent
to the best system of emission reduction,
reducing emission levels only marginally
(about 20 percent) below that measured.
It is concluded, therefore, that an
emission limit of 0.02 kg/Mg (0.04 lb/
ton) represents the emission level
attainable by the best system of
emission reduction.
Opacity data were gathered during
particulate tests at the two dryers.
Approximately fourteen hours of
measurements on four separate dates
were obtained as specified in EPA
Reference Method 9. At one facility
where emissions were controlled by a
medium-energy venturi scrubber, the
observations revealed zero percent
opacity throughout the test periods. At
the other facility, where emissions were
controlled by an ESP, opacity
observations ranged from zero percent
to 7.7 percent. The difference between
the opacity levels observed for the two
types of control systems primarily
reflected differences in diameters of
discharge stacks rather than significant
differences in control performance. ESPs
typically require larger stacks due to
higher volumes of flow required during
operation. Setting separate opacity
standards for the two control systems
was rejected because ESPs are not
expected to be used in meeting the
proposed standards. Thus the proposed
opacity standard is based on the
performance of the scrubber-controlled
facility and is set at zero percent
opacity. Control systems reflecting best
emissions control capability (the high
energy scrubber or baghouse) which
meets the proposed emissions limit
should experience no difficulty meeting
the proposed opacity standard. Should
any affected dryer facility be controlled
with an ESP and comply with the
particulate limit of 0.02 kg/Mg but not
the opacity limits, a separate opacity
limit may be established for the facility
under 40 CFR 60.11(e). The provisions of
40 CFR 60.11(e) allow owners or
operators of sources which exceed the
opacity standard while concurrently
achieving the performance emissions
limit to request establishment of a
specific opacity standard for that
facility.
Emission Standards for Calciners
Source tests were conducted on
calciners at two phosphate rock plants
processing western phosphate rock. The
western rock is considered to present
the most adverse conditions for
emissions control from calciners
because it receives less cleaning during
beneficiation than other ore types. In
addition one of the calciners selected for
test also processes a mix of both
beneficiated and unbeneficiated rock,
leading to a still more adverse control
problem. Presumably, any control
system demonstrating an emissions
level for these facilities should also be
capable of meeting this level for all
other calciners as well.
Particulate emissions from a calciner
controlled by a high-energy scrubber
operating in the range of 4.9 to 7.4
kilopascals pressure drop (twenty to
thirty inches of water) averaged 0.04 and
0.05 kg/Mg (0.08 and 0.10 Ib/ton) for two
different tests by the operator.
Particulate emissions from a calciner
controlled by a venturi scrubber
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Federal Register / Vol. 44, No. 185 / Friday. September 21. 1979 / Proposed Rules
operating at 3.0 kilopascals pressure
drop (1Z inches of water) averaged 0.07
kg/Mg (0.14 Ib/ton) for EPA tests and
0.12 and 0.068 kg/Mg (0.24 amd 0.136 lb/
ton) for different operator tests. The
emission level which would have been
attained had best technology been used
by this facility is estimated by adjusting
the test results to reflect the venturi
scrubber performance at 6.6 kilopascals
(27 inches water) pressure drop using
the EPA programmable scrubber model
Section 8.5 of the Background
Information Document for Phosphate
Rock Plants summarizes the expected
emission levels when the scrubber
energy is increased from medium to high
level. The adjusted level of control is
equivalent to that which would be
expected if baghouses were employed to
control calciner emissions, or 0.055 kg/
Mg (0.11 Ib/ton). Accordingly, this
control level is proposed as the emission
limit for calciners.
Opacity data were obtained during
the performance testing of the two
calciners. Zero percent opacity was
recorded at both facilities throughout
the 13.75 hours of observations, Based
on these test data, plus the fact that
better control technology must be
installed to comply with the
performance limits, it is proposed that
the opacity limit for calciner facilities be
set at zero percent opacity.
Emission Standards for Grinders
Source tests were conducted on four
separate grinders representing a wide
variation of exhaust air rates, grinder
designs, capacities, and product feeds
Emissions from each of the facilities are
controlled with baghouses. Emissions
averaged 0.0044, 0.002, 0.0005, and 0.0005
kg/Mg for EPA tests and 0.0022 kg/Mg
for operator tests. The emission tests
demonstrate that an emission level of
0.005 kg/Mg (0.01 Ib/ton) can be
achieved by fabric filters for a variety of
grinder applications. Installation of
baghouse controls for grinders is
motivated by the recovery value of the
product collected as much as by existing
emission standards. Hence, it is
expected that baghouses will remain the
predominant means of compliances with
emission standards for grinder facilities
Nearly 17 hours of opacity
observations were gathered during
particulate tests at two of the grinder
facilities. The average opacity level
recorded throughout the measurement
periods was zero percent. The use of
baghouses as control devices on these
two facilities represents demonstrated
best technology, therefore, the
Administrator believes that the opacity
standard for phosphate rock grinding
processes should be zero percent
opacity.
Emission Standards for Ground Rock
Handling and Storage Systems
Particulate emissions from handling
and storage of ground rock are very
difficult to characterize due to the fact
that these systems vary greatly from
plant to plant. A substantial portion of
the potential emissions from handling
and storage operations is fugitive
emissions. Normal industrial practice is
to control dust from the various sources
by utilizing enclosures and air
evacuation or pressure systems ducted
to baghouses. Baghouses provide
recovery of the rock dust which is
subsequently returned to the rock
inventory. Emissions from the
enclosures have zero percent opacity
when the process equipment is properly
maintained. Consequently, emissions
from the ground rock transfer system are
manifested and monitored at the overall
collection device (e.g.. the baghouse).
Because of wide variations in handling
and storage facilities, an opacity
standard is the only standard
appropriate for these facilities.
Source tests were conducted on three
pneumatic systems employed in the
transfer of ground phosphate rock. The
exhaust from the baghouses of each of
the transfer systems was witnessed to
determine the opacity of emissions
during normal transfer operations for
two hours at one system, and one hour
at the others. The opacity level of the
baghouse emissions was observed to be
zero percent throughout the test period.
Based on these results, an opacity limit
of zero percent opacity is proposed for
ground phosphate rock handling
systems
Testing, Monitoring, and Recordkeeping
Performance tests to determine
compliance with the proposed standards
would be required. Reference Method 5
(40 CFR Part 60, Appendix A) would be
used to measure the amount of
particulate emissions.
The proposed standards would
require continuous monitoring of the
opacity of emissions discharged from
phosphate rock dryers, calciners.
grinders and ground rock handling
systems. When a scrubber is used to
control the emissions, entrained water
droplets prevent the accurate
measurement of opacity; therefore, in
this case the proposed standard would
require monitoring the pressure drop
across the scrubber and the scrubbing
fluid supply pressure to the scrubber
rather than opacity. If other controls are
employed which would also preclude
the use of a continuous monitoring
system for measuring opacity as
specified by the standard, the operator
may request establishment of
alternative monitoring requirements
under the provisions of 40 CFR 60.13(i).
Excess emissions for affected
facilities using opacity monitoring
equipment are defined as all six-minute
periods in which the average opacity of
the stack plume exceeds zero percent.
Reporting of any excess emissions is
required under 40 CFR 60 on a quarterly
basis. For those facilities which use a
wet scrubber as the particulate control
device, the owner or operator is instead
required to submit reports each calendar
quarter for all measurements of scrubber
pressure drops and liquid supply
pressures less than 90 percent of the
average levels maintained during the
most recent performance test in which
compliance with the proposed standards
was demonstrated
Public Hearing
A public hearing will be held to
discuss these proposed standards in
accordance with Section 307(d)(5) of the
Clean Air Act. Persons wishing to make
oral presentations should cont;>ct EPA
at the address given in the ADDRESSES
Section of this preamble Oral
presentations will be limited to 15
minutes each. Any member of the public
may file a written statement with EPA
before, during, or within 30 days after
the hearing
A verbatim transcript of the hearing
and written statements will be available
for public inspection and copying during
normal working hours at the address of
the Docket (see ADDRESSES Section)
Docket
The docket is an organized and
complete file of all the information
considered by EPA in the development
of this rulemaking. The principal
purposes of the docket are (1) to allow
interested persons to identify and locnte
documents so that they can intelligently
and effectively participate in the
rulemaking process, and (2) to serve as
the record for judicial review
Miscellaneous
As prescribed by Section 111 of the
Act, this proposal of standards was
preceded by the Administrator's
determination that emissions from
phosphate rock plants contribute
significantly to air pollution which
causes or contributes to the
endangerment of public health or
welfare. In accordance with Section 117
of the Act, publication of this proposal
was preceded by consultation with
appropriate advisory committees,
independent experts, and Federal
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Federal Register / Vol. 44. No. 185 / Friday, September 21. 1979 / Proposed Rules
departments and agencies. The
Administrator will welcome comments
on all aspects of the proposed
regulation.
Under EPA's sunset policy for
reporting requirements in regulations,
the reporting requirements in this
regulation will automatically expire 5
years from the date of promulgation
unless EPA takes affirmative action to
extend them. To accomplish this, a
provision automatically terminating the
reporting requirements at that time will
be included in the text of the final
regulations.
It should be noted that standards of
performance for new sources
established under Section 111 of the
Clean Air Act reflect the degree of
emission limitation achievable through
application uf the best technological
system of continuous emission reduction
which (taking into consideration the cost
of achieving such emission reduction,
any nonair quality health and
environmental impact and energy
requirements) the Administrator
determines has been adequately
demonstrated.
Although there may be emission
control technology available that can
reduce emissions below those levels
required to comply with the standards of
performance, this technology might not
be selected as the basis of standards of
performance because of costs
associated with its use. Accordingly,
standards of performance should not be
viewed as the ultimate in achievable
emission control. In fact, the Act
requires (or has the potential for
requiring) the imposition of a more
stringent emission standard in several
situations. For example, applicable costs
do not play as prominent a role in
determining the "lowest achievable
emission rate" for new or modified
sources locating in nonattainment areas;
i.e., those areas where statutorily-
mandated health and welfare standards
are being violated. In this respect,
Section 173 of the Act requires that new
or modified sources constructed in an
area which violates the National
Ambient Air Quality Standards
(NAAQS) must reduce emissions to the
level which reflects the "lowest
achievable emission rate" (LAER), as
defined in Section 171(3), for such
ategory of source. The statute defines
LAER as that rate of emissions based on
the following, whichever is more
stringent:
(A) The most stringent emission
limitation which is contained in the
implementation plan of any State for
such class or category of source, unless
the owner or operator of the proposed
source demonstrates that such
limitations are not achievable; or,
(B) The most stringent emission
limitation which is achieved in practice
by such class or category of source.
In no event can the emission rate
exceed any applicable new source
performance standard (Section 171(3)).
A similar situation may arise under
the prevention of significant
deterioration of air quality provisions of
the Act (Part C). These provisions
require that certain sources (referred to
in Section 169(1)) employ "best
available control technology" (as
defined in Section 169(3)) for all
pollutants regulated under the Act. Best
available control technology (BACT)
must be determined on a case-by-case
basis, taking energy, environmental and
economic impacts and other costs into
account. In no event may the application
of BACT result in emissions of any
pollutants which will exceed the
emissions allowed by any applicable
standard established pursuant to
Section 111 (or 112) of the Act.
In all events, State Implementation
Plans approved or promulgated under
Section 110 of the Act must provide for
the attainment and maintenance of
National Ambient Air Quality Standards
(NAAQS) designed to protect public
health and welfare. For this purpose,
SIPs must in some cases require greater
emission reductions than those required
by standards of performance for new
sources.
Finally, States are free under Section
116 of the Act to establish even more
stringent emission limits than those
established under Section 111 or those
necessary to attain or maintain the
NAAQS under Section 110. Accordingly,
new sources may in some cases be
subject to limitations more stringent
than EPA's standards of performance
under Section 111, and prospective
owners and operators of new sources
should be aware of this possibility in
planning for such facilities.
EPA will review this regulation 4
years from the date of promulgation.
This review will include an assessment
of such factors as the need for
integration with other programs, the
existence of alternative methods,
enforceability, and improvements in
emission control technology.
Executive Order 12044, dated March
24,1978, whose objective is to improve
government regulations, requires
executive branch agencies to prepare
regulatory analyses for regulations that
may have major economic
consequences. The screening criteria
used by EPA to determine if a proposal
requires a regulatory analysis under
Executive Order 12044 are: (1)
Additional national annualized
compliance costs, including capital
charges, which total $100 million within
any calendar year by the attainment
date, if applicable, or within five years,
(2) a major increase in prices or
production costs.
The impacts associated with the
proposal of performance standards for
phosphate rock plants do not exceed the
EPA screening criteria. Therefore,
promulgation of the proposed standard
does not constitute a major action
requiring preparation of a regulatory
analysis under Executive Order 12044.
However, an economic impact
assessment of alternative control
technologies capable of meeting the
proposed NSPS has been prepared as
required under Section 317 of the Clean
Air Act and is included in the
Background Information Document for
Phosphate Rock Plants EPA considered
all the information in the economic
impact assessment in determining the
cost of the proposed standard.
Dated. September 14. 1979
Douglas M. Costle,
Administrator.
It is proposed to amend Part 60 of
Chapter I of Title 40 of the Code of
Federal Regulations as follows:
1. By adding Subpart NN to the Table
of Sections as follows:
Subpart NNStandards of Performance for
Phosphate Rock Plants
Sec.
60.400 Applicability and designation of
affected facility
60.401 Definitions.
60.402 Standard for participate matter.
60.403 Monitoring of emissions and
operations.
60.404 Test methods and procedures.
Authority. Sec. Ill and 301(a), Clean Air
Act, as amended, (42 U.S.C. 7411, 7601(a)),
and additional authority as noted below:
2. By adding subpart NN as follows:
Subpart NNStandards of
Performance for Phosphate Rock
Plants
§ 60.400 Applicability and designation of
affected facility.
(a) The provisions of this subpart are
applicable to the following affected
facilities used in phosphate rock plants:
dryers, calciners, grinders, and ground
rock handling and storage facilities.
(b) Any facility under paragraph (a) of
this section which commences
construction, modification, or
reconstruction after September 21,1979,
is subject to the requirements of this
part.
V-NN-6
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Federal Register / Vol. 44, No. 185 / Friday, September 21. 1979 / Proposed Rules
{0.401 Definition*.
(a) "Phosphate rock plant" means any
plant which produces or prepares
phosphate rock product by any or all of
the following processes: mining,
beneficiation, crushing, screening,
cleaning, drying, calcining, and grinding.
(b) "Phosphate rock feed" means the
ore which is fed to phosphate rock
facilities, including, but not limited to
the following minerals: Fluorapatite,
hydroxylapatite, chlorapatite and
carbonate-apatite.
(c) "Dryer" means a unit in which the
moisture content of phosphate rock is
reduced by contact with a heated gas
stream.
(d) "Calciner" means a unit in which
the moisture and organic matter of
phosphate rock is reduced within a
combustion chamber.
(e) "Grinder" means a unit which is
used to reduce the size of dry phosphate
rock.
(f) "Ground phosphate rock handling
and storage system" means a system
which is used for the conveyance and
storage of ground phosphate rock.
§ 60.402 Standard for participate matter.
(a) On and after the date on which the
performance test required to be
conducted by § 60.8 is completed, no
owner or operator subject to the
provisions of this subpart shall cause to
be discharged into the atmosphere:
(1) From any phosphate rock dryer
any gases which:
(i) Contain particulate matter in
excess of 0.020 kilogram per megagram
of phosphate rock feed (0.04 Ib/ton), or
(ii) Exhibit greater than 0 percent
opacity.
(2) From any phosphate rock calciner
any gases which:
(i) Contain particulate matter in
excess of 0.055 kilogram per megagram
of phosphate rock feed (0.11 Ib/ton), or
(ii) Exhibit greater than 0 percent
opacity.
(3) From any phosphate rock grinder
any gases which:
(i) Contain particulate matter in
excess of 0.006 kilogram per megagram
of phosphate rock feed (0.012 Ib/ton), or
(ii) Exhibit greater than 0 percent
opacity.
(4) From any phosphate rock handling
and storage system any gases which
exhtbit greater than 0 percent opacity.
{ 60.403 Monitoring of emissions and
operations
(a) Any owner or operator subject to
the provisions of this subpart shall
install, calibrate, maintain, and operate
a continuous monitoring system, except
as provided in paragraph (b) of this
section, to monitor and record the
opacity of the gases discharged into the
atmosphere from any phosphate rock
dryer, calciner, grinder or ground rock
handling system. The span of this
system shall be set at 40 percent
opacity.
(b) The owner or operator of any
affected phosphate rock facility using a
wet scrubbing emission control device
shall not be subject to the requirements
in paragraph,(a) of this section, but shall
install, calibrate, maintain, and operate
the following continuous monitoring
devices:
(1) A monitoring device for the
continuous measurement of the pressure
loss of the gas stream through the
scrubber. The monitoring device must be
certified by the manufacturer to be
accurate within ±250 pascals (±1 inch
water) gauge pressure.
(2) A monitoring device for the
continuous measurement of the
scrubbing liquid supply pressure to the
control device. The monitoring device
must be accurate within ±5 percent of
design scrubbing liquid supply pressure.
(c) For the purpose of conducting a
performance test under § 60.8, the owner
or operator of any phosphate rock plant
subject to the provisions of this subpart
shall install, calibrate, maintain, and
operate a device for measuring the
phosphate rock feed to any affected
dryer, calciner, grinder, or ground rock
handling system. The measuring device
used must be accurate to within ±5
percent of the mass rate over its
operating range.
(d) For the purpose of reports required
under § 60,7(c), periods of excess
emissions that shall be reported are
defined as all six-minute periods during
which the average opacity of the plume
from any phosphate rock dryer, calciner,
grinder or ground rock handling system
subject to paragraph (a) of this section
exceeds 0 percent.
(e) Any owner or operator subject to
requirements under paragraph (b) of this
section shall report for each calendar
quarter all measurement results that are
less than 90 percent of the average
levels maintained during the most recent
performance test conducted under § 60.8
in which the affected facility
demonstrated compliance with the
standard under § 60.402.
(Sec. 114, Clean Air Act as amended (42
U.SC. 7414))
§ 60.404 Test methods and procedures
(a) Reference methods in Appendix A
of this part, except as provided under
§ 60.8(b) shall be used to determine
compliance with § 60.402 as follows:
(1) Method 5 for the measurement of
particulate matter and associated
moisture content,
(2) Method 1 for sample and velocity
traverses,
(3) Method 2 for velocity and
volumetric flow rates,
(4) Method 3 for gas analysis, and
(5) Method 9 for the measurement of
the opacity of emissions.
(b) For Method 5, the sampling time
for each run shall be at least 60 minutes
and the minimum sampled volume of
0.84 dscm (30'dscf) except that shorter
sampling times and smaller sample
volumes, when necessitated by process
variables or other factors, may be
approved by the Administrator.
(c) For each run, average phosphate
rock feed rate in megagrams per hour
shall be determined using a device
meeting the requirements of § 60.403(c).
(d) For each run, emissions expressed
in kilograms per megagram of phosphate
rock feed shall be determined using the
following equatjon:
(C,C)J10 '
Where:
E = Emissions of particulates in kilograms per
megagrams of phosphate rock feed.
C, = Concentration of particulates in mg/
dscm as measured by Method 5.
Qs = Volumetric flow rate in dscm/hr as
determined by Method 2.
10~6= Conversion factor for milligrams to
kilograms.
M = Average phosphate rock feed rate in
megagrams per hour.
(Sec. 114, Clean Air Act, as amended. (42
U.S.C. 7414))
[FRDoc 79-293
-------
Federal Register / Vol. 44, No. 213 / Thursday, November 1, 1979 / Proposed Rules
40 CFR Part 60
[FRL 1349-8]
Standards of Performance for New
Stationary Sources; Phosphate Rock
Plants; Extension of Comment Period
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Extension of Comment Period.
SUMMARY: The deadline for submittal of
comments on the proposed standards of
performance for phosphate rock plants,
which were proposed on September 21,
1979 (44 FR 54970), is being extended
from November 26, 1979 to December 26,
1979.
DATES: Comments must be received on
or before December 26,1979.
ADDRESSES: Comments should be
submitted to Mr. David R. Patrick, Chief,
Standards Development Branch (MD-
13), Emission Standards and Engineering
Division, Environmental Protection
Agency, Research Triangle Park, North
Carolina 27711.
FOR FURTHER INFORMATION CONTACT:
Mr. Don R. Goodwin, Director, Emission
Standards and Engineering Division
(MD-13), Environmental Protection
Agency, Research Triangle Park. North
Carolina 27711, telephone number (919)
541-5271.
SUPPLEMENTARY INFORMATION: On
September 21,1979 (44 FR 54970). the
Environmental Protection Agency
proposed standards of performance for
the control of particulate emissions from
phosphate rock plants. The notice of
proposal requested public comments on
the standards by November 26,1979.
Due to a delay in the shipping of the
Support Document, sufficient copies of
the document have not been available to
all interested parties in time to allow
their meaningful review and comment
by November 26,1979. EPA has received
a request from the industry to extend the
comment period by 30 days through
December 26,1979. An extension of this
length is justified since the shipping
delay has resulted in approximately a
three-week delay in processing requests
for the document.
Dated: October 26, 1979.
David G. Hawkins,
Assistant Administrator for Air, Noise, and
Radiation.
[FR Doc. 79-J3855 Flltd 10-31-79, SH6 am]
Federal Register / Vol. 45. No. 12 / Thursday,
January 17, 1980 / Proposed Rules
40 CFR Part 60
[FRL 1391-6]
Standards of Performance for New
Stationary Sources; Phosphate Rock
Plants
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Extension of Comment Period.
SUMMARY: The deadline for submittal of
comments on the proposed standards of
performance for phosphate rock plants,
which were proposed on September 21,
1979 (44 FR 54970), is being extended
from December 26,1979, to February 15,
1980. The extension is given because
there was about a six week delay in
distributing the document for review
DATES: Comments. Comments must be
received on or before February 15,1980.
ADDRESSES: Comments. Comments
should be submitted to Mr. David R.
Patrick Chief, Standards Development
Branch (MD-13), Emission Standards
and Engineering Division,
Environmental Protection Agency,
Research Trinagle Park, North Carolina
27711.
FOR FURTHER INFORMATION CONTACT:
Mr. Don R. Goodwin, Director, Emission
Stnadards and Engineering Division
(MD-13), Environmental Protection
Agency, Research Triangle Park, North
Carolina 27711, telephone number (919)
541-5271.
SUPPLEMENTARY INFORMATION: On
September 21,1979 (44 FR 54970), the
Environmental Protectioin Agency
proposed standards of performance for
the control of particulate emissions from
phosphate rock plants. The notice of
proposal requested public comments on
the standards by December 26,1979.
Due to a delay in the shipping of the
Support Document, sufficient copies of
the document have not been available to
all interested parties in time to allow
their meaningful review and comment
by December 26,1979. EPA has received
a request from the industry to extend the
comment period by 45 days through
February 15, 1980. An extension of this
length is justified since the shipping
delay has resulted in approximately a
six week delay in processing requests
for the document.
Dated: January 8, 1980.
David G. Hawkins,
Assistant Administrator for Air, Noise, and
Radiation
[FR Dm W>-lr>.ll Filed 1-16-80. 845 am|
-------
ENVIRONMENTAL
PROTECTION
AGENCY
STANDARDS OF
PERFORMANCE FOR
NEW STATIONARY
SOURCES
AMMONIUM SULFATE
MANUFACTURE
SUBPART PP
-------
Federal Register / Vol. 45, No. 24 / Monday, February 4, 1980 / Proposed Rules
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Part 60
[FRL 1353-3]
Standards of Performance for New
Stationary Sources; Ammonium
Sulfate Manufacture
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Proposed Rule and Notice of
Public Hearing.
SUMMARY: The proposed standards
would limit atmospheric emissions of
particulate matter from new, modified,
and reconstructed ammonium sulfate
manufacturing dryers. The standards
implement section 111 of the Clean Air
Act and are based on the
Administrator's determination that
ammonium sulfate manufacturing plants
contribute significantly to air pollution.
The intended effect is to require new,
modified, and reconstructed ammonium
sulfate manufacturing plants to use the
best demonstrated system of continuous
emission reduction, considering costs,
nonair quality health and environmental
impact, and energy impacts.
A public hearing will be held to
provide interested persons an
opportunity for oral presentation of
data, views, or arguments concerning
the proposed standards.
DATES: Comments. Comments must be
received on or before April 5,1980.
Public Hearings. The public hearing
will be held on March 6,1980 (about 30
days after proposal) beginning at 9 a.m.
Request to Speak at Hearing. Persons
wishing to present oral testimony at the
hearing should contact EPA by February
29,1980 (one week before hearing).
ADDRESSES: Comments. Comments
should be submitted (in duplicate if
possible) to Central Docket Section (A-
130), U.S. Environmental Protection
Agency, 401 M Street, SW., Washington.
D.C. 20460, Attention: Docket No. A-79-
31.
Public Hearing. The public hearing
will be held at The Environmental
Research Center Auditorium Rm B-102,
Research Triangle Park, N.C. Persons
wishing to present oral testimony should
notify Shirley Tabler, Emission
Standards and Engineering Division
(MD-13), U.S. Environmental Protection
Agency, Research Triangle Park, North
Carolina 27711, telephone number (919)
541-5421.
Background Information Document.
The background information document
for the proposed standards may be
obtained from the U.S. EPA Library
(MD-35), Research Triangle Park, North
Carolina 27711, telephone number (919)
541-2777. Please refer to "Ammonium
Sulfate ManufactureBackground
Information for Proposed Emission
Standards," EPA-450/3-79-034.
Docket. A docket, number A-79-31,
containing information used by EPA in
development of the proposed standards,
is available for public inspection
between 8:00 a.m. and 4:00 p.m., Monday
through Friday, at EPA's Centra! Docket
Section (A-130), Room 2903B, Waterside
Mall, 401 M Street, SW., Washington,
D.C. 20460.
FOR FURTHER INFORMATION CONTACT:
Mr. Don R. Goodwin, Director, Emission
Standards and Engineering Division
(MD-13), U.S. Environmental Protection
Agency, Research Triangle Park, North
Carolina 27711, telephone number (919)
541-5271.
SUPPLEMENTARY INFORMATION:
Proposed Standards
The proposed standards would limit
atmospheric particulate matter
emissions from new, modified, and
reconstructed ammonium sulfate dryers
at caprolactam by-product ammonium
sulfate plants, synthetic ammonium
sulfate plants, and coke oven by-product
ammonium sulfate plants.
Specifically, the proposed standards
would limit exhaust emissions from
ammonium sulfate dryers to 0.15
kilogram of particulate matter per
megagram of ammonium sulfate
production (0.30 Ib/ton). An opacity
emission standard is also proposed and
would limit emissions from the affected
facility to no more than 15 percent.
The proposed standards would
require continuous monitoring of the
pressure drop across the control system
for any affected facility to help ensure
proper operation and maintenance of
the system. Flow monitoring devices
necessary to determine the mass flow of
ammonium sulfate feed material to the
process would also be required.
Summary of Environmental, Energy, and
Economic Impacts
The proposed standards would reduce
projected 1985 particulate emissions
from new, modified, and reconstructed
ammonium sulfate dryers from about
670 megagrams (737 tons) per year, the
level of emissions under a typical State
Implementation Plan, to about 131
megagrams (144 tons) per year.
Compliance with the proposed
standards would amount to an 80
percent reduction of particulate
emissions under a State Implementation
Plan and would bring the overall
collection efficiency to near 99.9 percent
of the uncontrolled emissions. This
reduction in emission would result in
reduction of ambient air concentrations
of particulate matter in the vicinity of
new, modified, and reconstructed
ammonium sulfate plants. The proposed
standards are based on the use of
venturi scrubbing or fabric filtration to
control particulate matter. No water
discharge would be generated by the
control equipment required and all
captured particulate matter would be
reclaimed; therefore, the proposed
standards would have no adverse
impact on water quality or solid waste.
The proposed standards would not
significantly increase energy
consumption at ammonium sulfate
plants and would have a minimal impact
on national energy consumption. The
incremental energy needed to operate
control equipment to meet the standards
would range from 0.10 percent of the
total energy required to run a synthetic
or coke oven by-product ammonium
sulfate plant to 0.65 percent of the total
energy required to operate a
caprolactam by-product ammonium
sulfale plant.
Economic analysis indicates that the
impact of the proposed standards is
reasonable. Cumulative capital costs of
complying with the proposed standards
for the ammonium sulfate industry as a
whole would be about $1.0 million by
1985. Annualized cost to the industry in
the fifth year of the proposed standards
would be about $0.5 million. The
industry-wide price increase necessary
to offset the cost of compliance would
amount to less than 0.01 percent of the
wholesale price of ammonium sulfate.
Costs of emission control required by
the proposed standards are not expected
to prevent or hinder expansion or
continued production in the ammonium
sulfate industry.
Rationale
Selection of Source for Control
The Priority List (40 CFR 60.16, 44 FR
49222, August 21,1979) identifies various
sources of emissions on a nationwide
basis in terms of quantities of emission
from source categories, the mobility and
competitive nature of each source
category, and the extent to which each
pollutant endangers health and welfare.
The Priority List reflects the
Administrator's determination that
emissions from the listed source
categories contribute significantly to air
pollution and is intended to identify
major source categories for which
standards of performance are to be
promulgated. The ammonium sulfate
manufacturing industry is listed among
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those source categories for which new
source performance standards (NSPS)
must be promulgated.
Ammonium sulfate has been an
important nitrogen fertilizer for many
years. Its early rise to importance as a
fertilizer resulted from its availability as
a by-product from such basic industries
as steel manufacturing and petroleum
refining. By-product generation has
continued to dominate the industry. By-
product ammonium sulfate from the
caprolactam segment of the synthetic
fibers industry is now the single largest
source, accounting for more than 50
percent of ammonium sulfate
production.
Production of ammonium sulfate as a
by-product also ensures that it will
continue as an important source of
nitrogen fertilizer in the United States.
This is illustrated by the fact that, in
response to an increase in demand,
caprolactam production is expected to
increase at compounded annual growth
rates of up to 7 percent through the year
1985; and for every megagram of
caprolactam produced, 2.5 to 4.5
megagrams of ammonium sulfate are
produced as a by-product.
Over 90 percent of ammonium sulfate
is generated from three types of plants:
Synthetic, caprolactam by-product, and
coke oven by-product. Investigation has
shown that the impact of regulation and
potential for emission reduction is
significant only within these three
Industry sectors. Synthetic ammomium
sulfate is produced by the direct
combination of ammonia and sufuric
acid. Caprolactam ammomium sulfate is
produced as a by-product from streams
generated during caprolactam
manufacture. Ammonia recovered from
coke oven off-gas is reacted with
sulfuric acid to produce coke oven
ammonium sulfate. These three major
segments of the ammonium sulfate
industry would be regulated by the
proposed new source performance
standards.
Selection of Pollutant
Study of the ammonium sulfate
industry has shown that ammonium
sulfate emissions are the principal
pollutant emitted to the atmosphere
from ammonium sulfate plants. At
operating temperatures, the ammonium
sulfate emissions occur as solid
paniculate matter, a "criteria" pollutant
for which national ambient air quality
standards have been promulgated.
Currently, a variety of wet collection
systems are employed to control
ammonium sulfate particulate emissions
to levels of compliance with State and
local air pollution regulations (typically
reduction of 97 to 98 percent). Existing
State regulations range from a low of
0.71 kilogram of particulate per
megagram of ammonium sulfate
production to a high of 1.3 kilograms per
megagram. By the year 1985, new,
modified, and reconstructed ammonium
sulfate manufacturing dryers would
cause annual nationwide particulate
emissions to increase by about 670 Mg/
year (737 tons/year), with emissions
controlled to the level of a typical State
Implementation Plan (SIP) regulation.
(Estimate based on growth rate
demonstrated over past decade.)
Volatile organic compounds (VOC)
are also emitted from process dryers at
caprolactam by-product ammonium
sulfate plants. Test data indicate that
the caprolactam VOC mass emissions
are largely in the vapor phase and at
least two orders of magnitude lower
than ammonium sulfate particulate
emissions (110 kg/Mg for particulate
matter versus 0.78 kg/Mg for the VOC
emissions). In addition, wet collectors
currently in use as particulate control
systems have demonstrated an 88
percent removal efficiency of
uncontrolled caprolactam VOC
emissions. At this control level, new,
modified, and reconstructed
caprolactam ammonium sulfate plants
would add only about 76 megagrams per
year to nationwide VOC emissions by
1985. Therefore, the only pollutant
recommended for control by the
proposed standards is particulate
matter.
Selection of the Affected Facility
Ammonium sulfate crystals are
formed by continuously circulating a
mother liquor through a crystallizer.
When optimum crystal size is achieved,
precipitated crystals are separated from
the mother liquor (dewatered) usually
by centrifuges. Following dewatering,
the crystals are dried and screened to
product specifications.
Nearly all of the particnlate matter
emitted to the atmosphere from
ammonium sulfate manufacturing plants
is in the gaseous exhaust streams from
the process dryers. Other plant
processes, such as crystallization,
dewatering, screening, and materials
handling, are not significant emission
sources.
Ammonium sulfate dryers can be
either of the fluidized bed or the rotary
drum type. All fluidized bed units found
in the industry are heated continuously
with steam-heated air. The rotary units
are either direct-fired or steam heated.
Air flow rates for the ammonium sulfate
dryers at caprolactam plants range from
560 scm/Mg of product to 3,200 scm/Mg
of product. The lower value represents
direct-fired rotary drum units and the
higher value represents fluidized bed
drying units using steam-heated air. At
synthetic plants, air flow rates range
from 360 scm/Mg to 770 scm/Mg of
product. All drying units at synthetic
plants are of the rotary drum type.
One consequence of the wide range of
gas flow rates for the differing drying
systems is that particulate emission
rates, which are directly related to the
gas-to-product ratio, also vary
considerably for each drying unit
involved. (Gas-to-product ratio is
defined as the volume of dryer exhaust
gas per unit of production, e.g., dry
standard cubic meters per megagram of
ammonium sulfate produced.) Emission
tests using EPA Method 5 show an
uncontrolled ammonium sulfate
emission range of 0.44 kg/Mg to 76.7 kg/
Mg for rotary dryers. The one fluidized
bed dryer tested showed an
uncontrolled emission rate of 110 kg/Mg
of ammonium sulfate production.
Since the process dryer is the only
significant source of ammonium sulfate
particulate emissions, the ammonium
sulfate manufacturing industry can be
effectively controlled by specifying
emission limitations for the process
dryer. Therefore, the ammonium sulfate
dryer has been selected as the affected
facility for which particulate matter
regulations are proposed.
Selection of the Format of the
Recommended Standards
A number of regulatory formats are
available for standards limiting the
emission of particulate matter to the
atmosphere. Among the formats judged
as inappropriate for application in the
ammonium sulfate industry were a mass
per unit time performance standards
and such non-performance standards as
design, equipment, work practice, and
operational specifications. A standard
based on mass per unit time (e.g., kg/hr)
would require that a relationship be
constructed showing how the allowable
mass rate of emissions would vary with
both production and time. Such a
relationship could not be determined
without extensive source tests
performed at great expense.
Section lll(h) of the Clean Air Act
establishes a presumption against
design, equipment, work practice, and
operational standards. For example, a
standard based on a specific type of
drying equipment without add-on
controls or a standard limiting the dryer
air flow rate cannot be promulgated
unless a standard of performance is not
feasible. Performance standards for
control of ammonium sulfate dryer
particulate emissions have been
determined as practical and feasible;
therefore, design, equipment, work
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practice, or operational standards were
not considered as regulatory options.
Two additional formats for the
proposed standards were considered:
mass standards, which limit emissions
per unit of feed to the ammonium sulfate
dryer or per unit of ammonium sulfate
processed by the dryer; and
concentration standards, which limit
emissions per unit volume of exhaust
gases discharged to the atmosphere.
Mass standards, expressed as
allowable emissions per unit of
production, are related directly to the
quantity of participate matter
discharged to the atmosphere. They
regulate emissions based on units of
input or output, thereby denying any
dilution advantage. Mass standards also
allow for variation in process techniques
such as decreasing the air flow rate
through the dryer. A primary
disadvantage of mass standards, as
compared to concentration standards, is
that their enforcement may be more time
consuming and therefore more costly.
The more numerous measurements and
calculations required also increase the
opportunities for error. Determining
mass emissions requires the
development of a material balance on
process data concerning the operation of
the plant, whether it be input flow rates
or production flow rates. The need for
such a material balance is particularly
relevant in the case of ammonium
sulfate plants. The determination of
throughput in the ammonium sulfate
dryer is seldom direct. None of the
plants investigated during development
of the proposed standards made direct
measurements of the dryer input or
output. Process weights were
determined indirectly through
monitoring of input stream feed rates.
In general, enforcement of
concentration standards requires a
minimum of data and information.
thereby decreasing-the costs of
enforcement and reducing the chances
of error. However, in the ammonium
sulfate industry, enforcement of
concentration standards may be
complicated by use of two-stage
fluidized bed dryers which add ambient
air streams at the discharge end of the
dryer. There is a potential for
circumventing^ concentration standards
by diluting the exhaust gases discharged
to the atmosphere with excess air, thus
lowering the concentration of pollutants
emitted but not the total mass emitted.
For combustion operations, this problem
can usually be overcome by correcting
the concentration measured in the gas
stream to a reference condition such as
a specified oxygen or carbon dioxide
percentage in the gas stream. However.
in the ammonium sulfate industry the
drying process frequently does not
involve direct combustion operations.
The drying air may be heated by an
outside source; therefore, it is not
always possible to "correct" the amount
of exhaust air to account for dilution.
Since design dryer gas flow rates vary
from process to process, concentration
standards applied to the ammonium
sulfate industry would penalize those
plant operators who chose to use a low
air flow rate for the ammonium sulfate
dryer. A decrease in the amount of dryer
air decreases the volume of gases
released but not necessarily the quantity
of particulate matter emitted. As a
result, the concentration of particulate
matter in the exhaust gas stream would
increase even though the total mass
emitted might remain nearly the same.
Because mass standards directly limit
the amount of particulate matter emitted
into the atmosphere per megagram of
ammonium sulfate production, the same
emission limit can be applied to all
dryer types and sizes, production rates,
and air flow rates. The flexibility of
mass standards to accommodate
process variations, such as the wide
gange of gas-to-product ratios found in.
the industry, allows all segments of the
ammonium sulfate industry to be
regulated with a single mass emission
standard. These advantages outweigh
the drawbacks associated with the "
determination of process weight.
Consequently, mass standards were
judged more suitable for regulation of
particulate emissions from ammonium
sulfate dryers and were selected as the
format for expressing the standards of
performance for ammonium sulfate
manufacturing plants.
The mass limit proposed will apply to
the exhaust gas streams as they
discharge from control equipment. The
proposed standards express allowable
particulate emissions in kilograms per
megagram (kg/Mg) of ammonium sulfate
production.
Selection of the Best System of Emission
Reduction and the Numerical Emission
Limits
Section 111 of the Clean Air Act
requires that standards of performance
reflect the degree of emission control
achievable through application of the
best demonstrated technological system
of continuous emission reduction which
(taking into consideration the cost of
achieving such emission reduction, any
nonair quality health and environmental
impact, and energy requirements) has
been adequately demonstrated. The
proposed standards were developed
based on information derived from (1)
available technical literature on the
ammonium sulfate manufacturing
industry and applicable emission control
technology, (2) technical studies
performed for EPA by independent
research organizations, (3) information
obtained from the industry during visits
to ammonium sulfate plants and
meetings with various representatives of
the industry, (4) comments and
suggestions solicited from experts, and
(5) results of emission measurements
conducted by EPA.
Control Technology
Both venturi scrubbing and fabric
filtration represent the most efficient
add-on control techniques available to
abate particulate emissions. In
application to particulate collection from
ammonium sulfate dryers, both have the
potential to reduce ammonium sulfate
emissions from process dryers to less
than 0.15 kilogram per megagram of
ammonium sulfate production, although
energy requirements and costs may
differ considerably.
Venturi scrubbers are most suitable
for application to ammonium sulfate
dryers. In caprolactam by-product
ammonium sulfate plants, ammonium
sulfate feed streams are used as a
scrubbing liquor and in synthetic
ammonium sulfate plants the
condensate from the reactor/crystallizer
is used as the scrubbing liquor. This
allows the collected particulate to be
easily recycled to the system without
the addition of excess water. Because
medium-energy (25 to 33 centimeters
water guage (VV.G.) pressure drop)
venturi scrubbing with high liquid-to-gas
ratios achieves a high collection
efficiency and because venturi
scrubbing is compatible with and
complimentary to the processes
involved, it is considered the most
attractive add-on control system.
The fabric filter baghouse should also
be able to achieve the level of control
required by the standards based on
similar applications in other industries.
Normal operation of a baghouse for
ammonium sulfate particulate collection,
i.e., at temperatures above the dewpoint
of the exhaust gas, should be feasible.
However, in asseessing fabric filters as
an emission control option, the following
factors must be considered. For high gas
flow rates, capital and operating costs
as well as energy requirements are
higher for fabric filters than for medium
energy scrubbers of the same
construction material. For caprolactam
by-product plants using steam-heated
fluidized bed dryers, the ratio of gas
flow to product rate is at least an order
of magnitude higher than that of the
direct-fired rotary drum dryer operating
with fabric filters. As the size of a
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baghouse becomes larger, capital and
annual operating costs increase. For
example, maintaining the temperature of
the exhaust gas and baghouse surfaces
above the dewpoint may require more
energy than would ordinarily be
required to operate the dryer.
With caprolactam by-product
ammonium sulfate plants apparently
providing most of the anticipated growth
in the ammonium sulfate industry,
consideration should also be given to
caprolactam VOC mass emissions from
ammonium sulfate dryers. Available test
data indicate that most of the
caprolactam emissions associated with
the ammonium sulfate dryer are in the
vapor state. This suggests that the
caprolactam emissions would pass
through a fabric filter collection system.
On the other hand, a venturi scrubber
has demonstrated removal efficiency of
88 percent of the caprolactam from
ammonium sulfate dryers. Thus, use of
venturi scrubbers would, at a minimum,
maintain existing VOC control levels
now achieved by in-use wet collection
systems.
Emission Tests
Based on a survey of the ammonium
sulfate production industry, four plants
were selected for EPA Method 5
particulate emission testing. These four
ammonium sulfate manufacturing plants
were then tested by EPA in order to
evaluate control techniques currently
used for controlling particulate
emissions from ammonium sulfate
dryers,
Presently throughout the ammonium
sulfate industry, a variety of wet-
scrubbing systems are employed to
control ammonium sulfate particulate
emissions. The majority of these are
low-energy wet scrubbers, although
medium-energy venturi scrubbers are
being used with some ammonium sulfate
dryers. For wet scrubbing systems in
general, collection efficiency tends to
increase with increased energy input,
i.e., the higher the pressure drop, the
higher the removal efficiency of
particulates. This was borne out by
analysis of EPA test results. For
example, a synthetic ammonium sulfate
plant, with a rotary drum drying facility
controlled by a low-energy wet scrubber
operating at a pressure drop of 15
centimeters (6 inches) W.G., showed a
particulate collection efficiency of 97
percent. EPA test results from facilities
with increased energy inputs, e.g.,
venturi scrubbers operating at pressure
drops of 25.9 centimenters and 33
centimeters (10 and 13 inches) W.G.
showed typically higher control
efficiencies. In these latter cases, control
efficiencies of 99.8 and 99.9 percent by
weight were demonstrated with outlet
particulate emission rates of 0.158 kg/
Mg and 0.156 kg/Mg of ammonium
sulfate production, respectively, at a
synthetic ammonium sulfate plant using
a rotary dryer and a caprolactam by-
product ammonium sulfate plant using a
fluidized bed dryer.
Additional emission test data on wet
scrubbing control units have been
provided by ammonium sulfate plant
operators. At one facility, test results
using EPA Method 5 show an average
particulate emission rate of 0.135 kg/Mg
of ammonium sulfate production. The
facility, a caprolactam ammonium
sulfate plant with a fluidized bed dryer,
is controlled by a centrifugal scrubber
preceded by a series of cyclones. The
scrubber operates at 34 centimeters (13.4
inches) W.G. pressure drop.
Alternative emission control
techniques were also examined. The one
dry ammonium sulfate particulate
control system in use (a fabric filter unit)
was tested by EPA because it represents
a unique application of this control
method in the ammonium sulfate
industry. The facility, a synthetic
ammonium sulfate plant using a rotary
dryer, did achieve a low mass emission
rate, 0.007 kg/Mg (0.014 Ib/ton);
however, this emission rate is not
considered representative of a typical
ammonium sulfate facility. For example,
the baghouse in use was originally
designed for another application, and
the gas flow rate to this unit is
appreciably lower than normal direct-
fired gas flow. This constraint on gas
flow rate, by restricting the ratio of
dryer exhaust gas-to-product rate,
results in a significantly lower
uncontrolled inlet emission rate than
most other dryers used in the industry.
In fact, the fabric filter inlet
uncontrolled particulate emission rate
was 0.41 kg/Mg of production, while
those of facilities controlled by venturi
scrubbers were 110 kg/Mg and 77 kg/
Mg. This represents an uncontrolled
mass emission difference in the range of
two orders of magnitude. Thus,
comparison of the outlet mass emissions
for this facility with those of the other
facilities tested is, in this situation,
somewhat misleading.
Regulatory Options
Review of the performance of the
emission control techniques led to the
identification of two regulatory options.
The two options are based on emission
control techniques representative of two
distinct levels of control. Each option
specifies numerical emission limits for
ammonium sulfate dryers applicable to
the three major sectors of the
ammonium sulfate industry. Option I is
equivalent to no additional regulatory
action. For this option, particulate
emission levels would be set by existing
SIP regulations, typically in the range of
0.71 kg/Mg to 1.3 kg/Mg of ammonium
sulfate production. This option is
characterized by the use of a low energy
wet scrubber to meet the required
emission limit, a reduction of 97 to 98
percent. Option II, based on the use of a
venturi scrubber or fabric filter, would
set an emission limit of 0.15 kilogram of
particulate per megagram of ammonium
sulfate production. As applied to the
ammonium sulfate industry, both the
venturi scrubber and the fabric filter
control systems are capable of greater
than 99.9 percent control efficiency.
Option II therefore represents the most
stringent control level that can be met
by all segments of the ammonium
sulfate industry.
Using model plants for the new,
modified, and reconstructed ammonium
sulfate facilities, the environmental
impacts, energy impacts, and economic
impacts of each regulatory option were
analyzed and compared. Each
ammonium sulfate manufacturing sector
is unique from a technical standpoint.
Dryer types and sizes, gas-to-product
flow rates, and uncontrolled particulate
emission rates vary from one sector to
another and often within each sector.
For these reasons it was apparent that
no single model plant could adequately
characterize the ammonium sulfate
industry. Accordingly, several model
dryers were specified in terms of the
following parameters: Production rate.
dryer types, exhaust gas flow rates,
emission rates, stack height, stack
diameter, and exit gas temperatures.
The evaluation of these parameters may
be found in Chapters 6, 7, and 8 of the
document, "Ammonium Sulfate
ManufactureBackground Information
for Proposed Emission Standards."
Under Option I, annual nationwide
particulate emissions from new,
modified, and reconstructed ammonium
sulfate manufacturing plants would
increase by about 670 Mg/year (737
tons/year) between 1980 and 1985.
Under Option II, nationwide particulate
emissions would increase by 131 Mg/
year (144 tons/year) during the same
period. This represents a reduction of
about 80 percent in the particulate
emissions emitted under Option I, a
typical SIP regulation.
Dispersion analysis under "worst
case" atmospheric and meteorological
conditions shows that the maximum 24-
hour concentration of particulates in the
vicinity of a new, modified, and
reconstructed ammonium sulfate plan!
would be reduced by a factor of 80
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percent (from 224 to 47.4 micrograms per
cubic meter) by controlling to Option II
rather than the SIP emission limit. The
maximum annual average is reduced
from 29.1 to 6.15 micrograms per cubic
meter under Option II.
Effluent guidelines set forth in 40 CFR
418.60 limit water pollution from
synthetic and coke oven ammonium
sulfate plants. In the caprolactam by-
product ammonium sulfate plant, water
is removed in the crystallizer,
condensed and recycled to the principal
plant for plant use. The addition of a
scrubber for emission control would nol
create a water pollution problem since
all scrubbing liquor would be recycled
to the process. The use of a baghouse
would not create a water pollution
problem since it is a dry collection
system. Consequently, the water
pollution impact of Option II would be
zero.
The ammonium sulfate plants
generate no solid waste as part of the
process since all collected ammonium
sulfate is recycled to the process.
Furthermore, no significant increase in
noise level is anticipated under Option
II.
For typical plants in the ammonium
sulfate manufacturing industry, an
increase in energy consumption would
result from compliance with Option II.
The energy required, in excess of thai
required by a typical SIP regulation, to
control caprolactam by-product
ammonium sulfate plants to the level of
Option II would be 8.8 gigawatt hours of
electricity per year in 1985 using venturi
scrubbers. The overall energy increase
would amount to less than 0.65 percent
of the total energy required to operate a
typical caprolactam by-product
ammonium sulfate plant. For synthetic
and for coke oven by-product
ammonium sulfate plants, the 1985
incremental energy increase would be
0.61 and 0.14 gigawatt hours per year,
respectively, or less than a 0.1 percent
increase. The total industry-wide energy
increment would be 9.5 gigawatt hours
per year in 1985. This figure indicates
that Option II would not significantly
increase energy consumption at
ammonium sulfate plants and would
have minimal impact on national energy
consumption.
Economic analysis also indicates that
the impact of Option II is minimal. The
capital cost of the installed emission
control equipment necessary to meet
Option II, on all new, modified, and
reconstructed ammonium sulfate
facilities coming on line nationwide
during the period 1980 to 1985, would be
about $958,000. The total annualized
cost of operating this equipment during
the same period would be about
$480,200. These costs are considered
reasonable, and are not expected to
prevent or hinder expansion or
continued production in the ammonium
sulfate manufacturing industry. The
incremental cost necessary to offset the
cost of meeting Option II would be
about 0.01 percent of the wholesale
price of ammonium sulfate.
Consideration of the beneficial impact
on national particulate emissions; the
lack of water pollution impact or solid
waste impact; the minimal energy
impact; the reasonable cost impact; and
the general availability of demonstrated
emission control technology leads to the
selection of Option II as the basis for the
proposed standards of performance for
ammonium sulfate dryers.
Selection of Opacity Emission Limits
The best indirect method of ensuring
proper operation and maintenance of
emission control equipment is the
specification of exhaust gasopacity
limits. Determining an acceptable
exhaust gas opacity limit is possible
because opacity levels were evaluated
for ammonium sulfate dryers during EPA
tests; therefore, the data base for the
particulate standards includes
information on opacity. Ammonium
sulfate dryers were observed to have no
opacity readings greater than 15 percent
opacity, and a total of 90 minutes of
opacity of less than or equal to 15
percent but greater than 10 percent
during observation periods of 180,120.
438, and 408 minutes (1146 minutes
total). Therefore, a standard of 15
percent opacity is proposed for all
affected facilities to ensure proper
operation and maintenance of control
systems on a day-to-day basis.
Selection of Performance Test Methods
The use of EPA Reference Method 5
"Determination of Particulate Emissions
from Stationary Sources" would be
required to determine compliance with
the mass standards for particulate
matter emissions. Results of
performance tests using Method 5
conducted by EPA on existing
ammonium sulfate dryers comprise a
major portion of the data base used in
the development of the proposed
standards. EPA Reference Method 5 has
been shown to provide a representative
measurement of particulate matter
emissions. Therefore, it is included for
the purpose of determining compliance
with the proposed standards.
Method 5 calculations require imput
data obtained from three other EPA test
methods conducted previous to the
performance of Method 5. Method 1,
"Sample and Velocity Traverse for
Stationary Sources," must be used to
obtain representative measurements of
pollutant emissions. The average gas
velocity in the exhaust stack is
measured by conducting Method 2,
"Determination of Stack Gas Velocity
and Volumetric Flow Rate (Type S Pitot
Tube)." The analysis of gas composition
is measured by conducting Method 3,
"Gas Analysis for Carbon Dioxide,
Oxygen, Excess Air, and Dry Molecular
Weight," These three tests provide data
necessary in Method 5 for determining
concentration of particulate matter in
the dryer exhaust. All opacity
observations would be made in
accordance with the procedures
established in EPA Method 9 for stack
emissions.
Since the proposed standards are
expressed as mass of emissions per unit
mass of ammonium sulfate production, it
will be necessary to quantify production
rate in addition to measuring particulate
emissions. Ammonium sulfate
production in megagrams shall be
determined by direct measurement using
product weigh scales or computed from
a material balance. A material balance
computation based on the chemical
reactions used in the formation of
ammonium sulfate is an acceptable
method of determining production rate
since the formation reactions used in all
industrial sectors are quantitative and
irreversible.
If a material balance is used, the
ammonium sulfate production rate for
synthetic and coke oven by-product
ammonium sulfate plants shall be
calculated from the metered sulfuric
acid feed rate to the reactor/crystallizer.
For caprolactam by-product ammonium
sulfate plants, production rate shall be
determined from the oximation
ammonium sulfate solution flow rate
and the oleum flow to the caprolactam
rearrangement reaction.
Selection of Monitoring Requirements
To further ensure that installed
emission control systems continuously
comply with standards of performance
through proper operation and
maintenance, monitoring requirements
are generally included in standards of
performance. In the case of ammonium
sulfate dryers, the most straightforward
means of ensuring proper operation and
maintenance is to require monitoring of
actual particulate emissions released to
the atmosphere. Currently, however,
there are no continuous particulate
monitors in operation for ammonium
sulfate dryers; and resolution of the
sampling problems and development of
performance specifications for
continuous particulate monitors would
entail a major development program. For
these reasons, continuous monitoring of
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participate emissions from ammonium
sulfate dryers is not required by the
proposed standards.
The best indirect method of
monitoring proper operation and
maintenance of emission control
equipment is to continuously monitor
the opacity of the exhaust gas. The
proposed opacity limit for ammonium
sulfate dryers is 15 percent. However, in
the case of ammonium sulfate dryers,
the character of the exhaust gas when
wet scrubbers are used for emission
reduction precludes the use of
continuous in-stack opacity monitors.
Where condensed moisture is present in
the exhaust gas stream, in-stack
continuous monitoring of opacity is not
feasible; water droplets and steam can
interfere with operation of the
monitoring instrument. Since most
affected facilities are likely to use wet
scrubbers, continuous monitoring of
opacity is not required by the proposed
standards.
An alternative to participate or
opacity monitors is the use of a pressure
drop monitor as a means of ensuring
proper operation and maintenance of
emission control equipment For venturt
scrubbers, participate removal
efficiency is related directly to pressure
drop across the venturi; the higher the
pressure drop, the higher the removal
efficiency. For fabric filters, pressure
drop is used as an indicator of excessive
filter resistance or damaged filter media.
Therefore, in order to provide a
continuous indicator of emission control
equipment operation and maintenance,
the proposed standards would require
that the owner or operator of any
ammonium sulfate manufacturing plant
subject to the standards install,
calibrate, maintain, and operate a
monitoring device which continuously
measures and permanently records the
total pressure drop across the process,
emission control system. The monitoring
device shall have an accuracy of ±5
percent over its operating range.
The proposed standards would also
require the owner or operator of any
ammonium sulfate manufacturing plant
subject to the standards to install,
calibrate, maintain, and operate flow
monitoring devices necessary to
determine the mass flow of ammonium
Sulfate feed material to the process. The
flow monitoring device shall have an
accuracy of ±5 percent over its
operating range. The ammonium sulfate
feed streams are: for synthetic and coke
oven by-product ammonium sulfate
plants, the sulfuric acid feed stream to
the reactor/crystallizer; for caprolactam
by-product ammonium sulfate plants.
the oximation ammonium sulfate stream
to the ammonium sulfate plant and the
oleum stream to the caprolactam
rearrangement reaction.
Records of pressure drop and
calibration measurements would have to
be retained for at least 2 years following
the date of the measurements by owners
and operators subject to this subpart.
This requirement is included under
§ 60.7(d) of the general provisions of 40
CFR Part 60.
Public Hearing
A public hearing will be held to
discuss these proposed standards in
accordance with section 307(d}(5) of the
Clean Air Act Persons wishing to make
oral presentations should contact EPA
at the address given in the ADDRESSES
section of this preamble. Oral
presentations will be limited to 15
minutes each. Any member of the public
may file a written statement with EPA
before, during, or within 30 days after
the hearing. Written statements should
be addressed to the Docket address
given in the ADDRESSES section of this
preamble.
A verbatim transcript of the hearing
and written statements will be available
for public inspection and copying during
normal working hours at EPA's Central
Docket Section in Washington, D.C. (See
ADDRESSES section of this preamble.)
Docket
The docket is an organized and
complete file of all the information
considered by EPA in the development
of this rulemaking. The principal
purposes of the docket are: (1) To allow
interested persons to identify and locate
documents so that they can intelligently
and effectively participate in the
rulemaking process, and (2) to serve as
the record for judicial review. The
docket requirement is discussed in
section 307(d) of the Clean Air Act.
Miscellaneous
As prescribed by section 111 of the
Act, this proposal of standards has been
preceded by the Administrator's
determination that emissions from
ammonium sulfate manufacturing plants
contribute significantly to air pollution
which may reasonably be anticipated to
endanger public health or welfare (40
CFR 60.16. 44 FR 49222, August 21.1979).
In accordance with section 117 of the
Act, publication of these proposed
standards was preceded by consultation
with appropriate advisory committees,
independent experts, and Federal
departments and agencies. The
Administrator will welcome comments
on all aspects of the proposed
regulation, including economic and
technological issues.
It should be noted that standards of
performance for new stationary sources
established under section 111 of the
Clean Air Act reflect:
* * * application of the best technological
system of continuous emission reduction
which (taking into consideration the cost of
achieving such emission reduction, any
nonair quality health and environmental
impact and energy requirements) the
Administrator determines has been
adequately demonstrated, (section lll(a)(l))
Although there may be emission
control technology available that is
capable of reducing emissions below
those levels required to comply with
standards of performance, this
technology might not be selected as the
basis of standards of performance
because of costs associated with its use.
Accordingly, these standards of
performance should not be viewed as
the ultimate in achievable emission
control. In fact, the Act requires (or has
the potential for requiring) the
imposition of a more stringent emission
standard in several situations.
For example, applicable costs do not
necessarily play as prominent a role in
determining the "lowest achievable
emission rate" for new or modified
sources locating in nonattainment areas;
i.e., those areas where statutorily-
mandated health and welfare standards
are being violated. In this respect,
section 173 of the Act requires that new
or modified sources constructed in an
area which exceeds the national
ambient air quality standard (NAAQS)
must reduce emissions to the level
which reflects the "lowest achievable
emission rate" (LAER), as defined in
section 171(3), for such category of
source. The statute defines LAER as that
rate of emissions based on the
following, whichever is more stringent:
(A) The most stringent emission limitation
which is contained in the implementation
plan of any State for such class or category of
source, unless the owner or operator of the
proposed source demonstrates that such
limitations are not achievable, or
(B) The most stringent emission limitation
which is achieved in practice by such class or
category of source.
In no event can the emission rate
exceed any applicable new source
performance standard (section 171(3)).
A similar situation may arise under
the prevention of significant
deterioration of air quality provisions of
the Act (Part Q. These provisions
require that certain sources (referred to
in section 169(1)) employ "best available
control technology" (as defined in
section 169(3)) for all pollutants
regulated-ander the Act "Best available
control technology" (BACT) must be
determined on a case-by-case basis.
V-PP-7
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Federal Register / Vol. 45, No. 24 / Monday, February 4, 1980 / Proposed Rules
taking energy, environmental, and
economic impacts and other cost into
account. In no event may the application
of BACT result in emissions of any
pollutants which will exceed the
emissions allowed by any applicable
standard established pursuant to section
111 (or 112} of the Act.
In all events, State Implementation
Plans (SIPs) approved or promulgated
under section 110 of the Act must
provide for the attainment and
maintenance of the national ambient air
quality standards (NAAQS) designed to
protect public health and welfare. For
this purpose, SIP's must in some cases
require greater emission reductions than
those required by standards of
performance for new sources.
Finally, States are free under section
116 of the Act to establish even more
stringent emission limits than those
established under section 111 or those
necessary to attain or maintain the
NAAQS under section 110. Accordingly,
new sources may in some cases be
subject to limitations more stringent
than EPA's standards of performance
under section 111, and prospective
owners and operators of new sources
should be aware of this possibility in
planning for such facilities.
EPA will review this regulation four
years from the date of promulgation.
This review will include an assessment
of such factors as the need for
integration with other programs, the
existence of alternative methods,
enforceability, and improvements in
emission control technology.
Section 317 of the Clean Air Act
requires the Administrator to prepare an
economic impact assessment for any
new source standard of performance
promulgated under section ll(b) of the
Act. An economic impact assessment
was prepared for the proposed
regulations and for other regulatory
alternatives. All aspects of the
assessment were considered in the
formulation of the proposed standards
to ensure that the proposed standards
would represent the best system of
emission reduction considering costs.
The economic impact assessment is
included in the background information
document.
Dated: January 28,1980.
Douglas M. Costle,
Administrator.
PART 60STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
It is proposed that 40 CFR Part 60 be
amended by adding a new Subpart P as
follows:
Subpart PPStandards of Performance for
Ammonium Sulfate Manufacture
Sec.
60.420 Applicability and designation of
affected facilty.
60.421 Definitions.
60.422 Standards for particulate matter.
60.423 Monitoring of operations.
60.424 Test methods and procedures.
Authority: Sec. Ill, 301(a), Clean Air Act
as amended, (42 U.S.C. 7411, 7601(a)), and
additional authority as noted below.
Subpart PPStandards of
Performance for Ammonium Sulfate
Manufacture
§ 60.420 Applicability and designation of
affected facility.
The affected facility to which the
provisions of this subpart apply is each
ammonium sulfate dryer with an
ammonium sulfate manufacturing plant
in the caprolactam by-product,
synthetic, and coke oven by-product
sectors of the ammonium sulfate
industry.
§ 60.421 Definitions.
As used in this subpart, all terms not
defined herein shall have the meaning
given them in the Act and in Subpart A
of this part.
(a) "Ammonium sulfate manufacturing
plant" means any plant which produces
ammonium sulfate.
(b) "Ammonium sulfate dryer" means
a unit or vessel in which ammonium
sulfate is charged for the purpose of
reducing the moisture content of the
product using a heating gas stream. The
unit includes foundations,
superstructure, material charger
systems, exhaust systems, and integral
control systems and instrumentation.
(c) "Caprolactam by-product
ammonium sulfate manufacturing plant"
means any plant which produces
ammonium sulfate as a by-product from
process streams generated during
caprolactam manufacture.
(d) "Synthetic ammonium sulfate
manufacturing plant" means any plant
which produces ammonium sulfate by
direct combination of ammonia and
sulfuric acid.
(e) "Coke oven by-product ammonium
sulfate manufacturing plant" means any
plant which produces ammonium sulfate
by reacting sulfuric acid with ammonia
recovered as a by-product from the
manufacture of coke.
(f) "Ammonium sulfate feed material
streams" means the sulfuric acid feed
stream to the reactor/crystallizer for
synthetic and coke oven by-product
ammonium sulfate manufacturing
plants; and means the oximation
ammonium sulfate stream to the
ammonium sulfate manufacturing plant
and the oleum stream to the
caprolactam rearrangement reaction for
caprolactam by-product ammonium
sulfate manufacturing plants.
§ 60.422 Standards for particulate matter.
On or after the date on which the
performance test required to be
conducted by § 60.8 is completed, no
owner or operator of an ammonium
sulfate dryer subject to the provisions of
this subpart shall cause to be discharged
into the atmosphere, from any
ammonium sulfate dryer, particulate
matter at emission rates exceeding 0.15
kilogram of particulate per megagram of
ammonium sulfate produced [0.30 pound
of particulate per ton of ammonium
sulfate produced) and exhaust gases
with opacity of greater than 15 percent
opacity.
§ 60.423 Monitoring of operations.
(a) The owner or operator of any
ammonium sulfate manufacturing plant
subject to the provisions of this subpart
shall install, calibrate, maintain, and
operate flow monitoring devices which
can be used to determine the mass flow
of ammonium sulfate feed material
streams to the process. The flow
monitoring device shall have an
accuracy of ± 5 percent over its range.
(b) The owner or operator of any
ammonium sulfate manufacturing plant
subject to the provisions of this subpart
shall install, calibrate, maintain, and.
operate a monitoring device which
continuously measures and permanently
records the total pressure drop across
the emission control system. The
monitoring device shall have an
accuracy of ± 5 percent over its
operating range.
(Sec. 114, Clean Air Act as amended (42
U.S.C. 7414))
§ 60.424 Test methods and procedures.
(a) Reference methods in Appendix A
of this part, except as provided in
§ 60.8(b), shall be used to determine
compliance with § 60.422 as follows:
(1) Method 5 for the concentration of
particulate matter.
(2) Method 1 for sample and velocity
traverses.
(3) Method 2 for velocity and
volumetric flow rate.
(4) Method 3 for gas analysis.
(b) For Method 5, the sampling time
for each run shall be at least 60 minutes
and the volume shall be at least 1.50 dry
standard cubic meters (53 dry standard
cubic feet).
(c) for each run, the particulate
emission rate, E, shall be computed as
follows:
E = Q,d x C, -=-1000
V-PP-f
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Federal Register / Vol. 45, No. 24 / Monday, February 4, 1980 / Proposed Roles
(1) E is the participate emision rate
(kg/hr),
(2) Q HI is the average volumetric flow
rate (dscm/hr) as determined by Method
2; and
(3) C, is the average concentration (g/
dscm) of participate matter as
determined by Method 5,
(d) For each run, the rate of
ammonium sulfate production, P (Mg/
hr), shall be determined by direct
measurement using product weight
scales or computed from a material
balance. If production rate is determined
by material balance, the following
equations shall be used.
(1) For synthetic and coke oven by-
product ammonium sulfate plants, the
ammonium sulfate production rate shall
be determined using the following
equation:
P=AxBxCx 0.0808
where:
P = Ammonium sulfate production rate in
megagrams per hour.
A = Sulfuric acid flow rate to the reactor/
crystallizer in liters per minute averaged
over the time period taken to conduct the
run.
B = Acid density (a function of acid strength
and temperature) in grams per cubic
centimeter.
C = Percent acid strength in decimal form.
0.0808 ~ Physical constant for conversion of
time, volume, and mass units.
(2) For caprolactam by-product
ammonium sulfate plants the ammonium
sulfate production rate shall be
determined using the following equation:
P = [DxExFx (0.8612)] + [G X H X I
X (1.1620)]
where:
P = Production rate of caprolactam by-
product ammonium sulfate in megagrams
per hour.
D = Oximation ammonium sulfate process
stream flow rate in liters per minute
averaged over the time period taken to
conduct the run.
E = Density of the process stream solution in
grams per liter.
F = Percent ammonium sulfate in the process
solution in decimal form.
G = Oleum flow rate to the rearrangement
reaction in liters per minute averaged over
the time period taken to conduct the run
H = Density of oleum in grams per liter.
I = Equivalent sulfuric acid percent of the
oleum in decimal form.
0.8612 = Physical constant for conversion of
time and mass units.
1.1620 = Physical constant for conversion of
time and mass units.
(e) For each run, the dryer emission
rate shall be computed as follows:
R = E/P
where:
(1) R is the dryer emission rate (kg/
Mg):
(2) E is the particulate emission rate
(kg/hr) from (c) above; and
(3) P is the rate of ammonium sulfate
production (Mg/hr) from (d) above.
(Sec. 114 of the Clean Air Act as amended (42
U.S.C. 7414))
|FR Doo 80-3593 Filed 2-1-Bft 8:45 am)
BILLING CODE S5SO-01-M
V-PP-9
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ENVIRONMENTAL
PROTECTION
AGENCY
STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
CONTINUOUS MONITORING
PERFORMANCE SPECIFICATIONS
APPENDIX B
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Federal Register / Vol. 44. No. 197 / Wednesday. October 10.1979 / Proposed Rules
40 CFR Part 60
[FRL 1276-4]
Standards of Performance for New
Stationary Sources; Continuous
Monitoring Performance
Specifications
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Proposed Revisions.
SUMMARY: On October 6,1975 (40 FR
46250). the EPA promulgated revisions to
40 CFR Part 60, Standards of
Performance for New Stationary
Sources, to establish specific
requirements pertaining to continuous
emission monitoring. An appendix to the
regulation contained Performance
Specifications 1 through 3, which
detailed the continuous monitoring
instrument performance and equipment
specifications, installation requirements,
and test and data computation
procedures for evaluating the
acceptability of continuous monitoring
systems. Since the promulgation of these
performance specifications, the need for
a number of changes which would
clarify the specification test procedures,
equipment specifications, and
monitoring system installation
requirements has become apparent. The
purpose of the revisions is to
incorporate these changes into
Performance Specifications 1 through 3.
The proposed revisions would apply
to all monitoring systems currently
subject to performance specifications 1,
2, or 3. including source's subject to
Appendix P to 40 CFR Part 51.
DATES: Comments must be received on
or before December 10,1979.
ADDRESSES: Comments. Comments
should be submitted (in duplicate if
possible) to the Central Docket Section
(A-130). Attn: Docket No. OAQPS-79-4,
U.S. Environmental Protection Agency,
401 M Street, S.W., Washington, D.C.
20460.
Docket. Docket No. OAQPS-79-4.
containing material relevant to this
rulemaking. is located in the U.S.
Environmental Protection Agency,
Central Docket Section, Room 2903B, 401
M Street. S.W., Washington, D.C. The
docket may be inspected between 8
A.M. and 4 P.M. on weekdays, and a
reasonable fee may be charged for
copying,
FOR FURTHER INFORMATION CONTACT:
Don R. Goodwin, Director, Emission
Standards and Engineering Division
(MD-13), Environmental Protection
Agency, Research Triangle Park, North
Carolina 27711, telephone number (919)
541-5271.
SUPPLEMENTARY INFORMATION: Changes
common to all three of the performance
specifications are the clarification of the
procedures and equipment
specifications, especially the
requirement for intalling the continuous
monitoring sample interface and of the
calculation procedure for relative
accuracy. Specific changes to the
specifications are as follows:
Performance Specification
1. The optical design specification for
mean and peak spectral responses and
for the angle of view and projection
have been changed from "500 to 600 rim"
range to "515 to 585 nm" range and from
"5°" to "3°", respectively.
2. The following equipment
specifications have been added:
a. Optical alignment sight indicator
for readily checking alignment.
b. For instruments having automatic
compensation for dirt accumulation on
exposed optical surfaces, a
compensation indicator at the control
panel so that the permissible maximum
4 percent compensation can be
determined.
c. Easy access to exposed optical
surfaces for cleaning and maintenance.
d. A system for checking zero and
upscale calibration (previously required
in paragraph 60.13).
e. For systems with slotted tubes, a
slotted portion greater than 90 percent of
effluent pathlength (shorter slots are
permitted if shown to be equivalent).
f. An equipment specification for the
monitoring system data recorder
resolution of <5 percent of full scale.
3. A procedure for determining the
acceptability of the optical alignment
sight has been specified; the optical
alignment sight must be capable of
indicating that the instrument is
misaligned when an error of ±2 percent
opacity is caused by misalignment of the
instrument at a pathlength of 8 meters.
4. Procedures for calibrating the
attenuators used during instrument
calibrations have been added; these
procedures require the use of a
laboratory spectrophotometer operating
in the 400-700 nm range with a detector
angle view of <10 degrees and an
accuracy of 1 percent.
5. The following changes have been
made to the procedures for the
operational test period:
a. The requirement for an analog strip
chart recorder during the performance
tests has been deleted; all data are
collected on the monitoring system data
recorder.
b. Adjustment of the zero and span at
24-hour intervals during the drift tests is
optional; adjustments are required only
when the accumulated drift exceeds the
24-hour drift specification.
c. The amount of automatic zero
compensation for dirt accumulation
must be determined during the 24-hour
zero check so that the actual zero drift
can be quantified. The automatic zero
compensation system must be operated
during the performance test.
d. The requirement for offsetting the
data recorder zero during the
operational test period has been deleted.
e. Off the stack "zero alignment" of
the instrument prior to installation is
permitted.
Performance Specification 2
1. "Continuous monitoring system"
has been redefined to include the
diluent monitor, if applicable. The
change requires that the relative
accuracy of the system be determined in
terms of the emission standard, e.g..
mass per unit calorific value for fossil-
fuel fired steam generators.
2. The applicability of the test
procedures excludes single-pass, in-situ
continuous monitoring systems. The
procedures for determining the
acceptability of these systems are
evaluated on a case-by-case basis.
3. For extractive systems with diluent
monitors, the pollutant and diluent
monitors are required to use the same
sample interface.
4. The procedure for determining the
acceptability of the calibration gases
has been revised, and the 20 percent
(with 95 percent confidence interval)
criterion has been changed to 5 percent
of mean value with no single value being
over 10 percent from the mean.
5. For low concentrations, a 10 percent
of the applicable standard limitation for
the relative accuracy has been added.
6. An equipment specification for the
system data recorder requiring that the
chart scale be readable to within <0.50
percent of full-scale has been added.
7. Instead of spanning the instrument
at 90 percent of full-scale, a mid-level
span is required.
8. The response time test procedure
has been revised and the difference
limitation between the up-scale and
down-scale time has been deleted.
9. The relative accuracy test
procedure has been revised to allow
different tests (e.g., pollutant, diluent.
moisture) during a 1-hour period to be
correlated.
10. A low-level drift may be
substituted for the zero drift test.
V-Appendix B-2
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Federal Register / Vol. 44, No. 197 / Wednesday, October 10. 1979 / Proposed Rules
Performance Specification 3
1. The applicability of the test
procedures has been limited to those
monitors that introduce calibration
gases directly into the analyzer and are
used as diluent monitors. Alternative
procedures for other types of monitors
are evaluated on a case-by-case basis.
2. Other changes were made to be
consistent with the revisions under
Performance Specification 2.
The proposed revised performance
specifications would apply to all sources
subject (o Performance Specifications 1,
2, or 3. These include sources subject to
standards of performance that have
already been promulgated and sources
subject to Appendix P to 40 CFR Part 51.
Since the purpose of these revisions is to
clarify the performance specifications
which were promulgated on October 6,
1975, not to establish more stringent
requirements, it is reasonable to
conclude that most continuous
monitoring instruments which met and
can continue to meet the October 6,
1975, specifications can also meet the
revised specifications.
Under Executive Order 12044, the
Environmental Protection Agency is
required to judge whether a regulation is
"significant" and therefore subject to the
procedural requirements of the Order or
whether it may follow other specialized
development procedures. EPA labels
these other regulations "specialized". I
have reviewed this regulation and
determined that it is a specialized
regulation not subject to the procedural
requirements of Executive Order 12044.
Dated: October 1,1979.
Douglas M. Costle,
Administrator.
It is proposed to revise Appendix B,
Part 60 of Chapter I, Title 40 of the Code
of Federal Regulations as follows:
Appendix BPerformance
Specifications
Performance Specification 1
Specifications and Test Procedures For
Opacity Continuous Monitoring Systems
in Stationary Sources
1. Applicability and Principle
1.1 Applicability. This Specification
contains instrument design,
performance, and installation
requirements, and test and data
computation procedures for evaluating
the acceptability of continuous
monitoring systems for opacity. Certain
design requirements and test procedures
established in the Specification may not
be applicable to all instrument designs;
equivalent systems and test procedures
may be used with prior approval by the
Administrator.
1.2 Principle. The opacity of
particulate matter in stack emissions is
continuously monitored by a
measurement system based upon the
principle of transmissometry. Light
having specific spectral characteristics
is projected from a lamp through the
effluent in the stack or duct and the
intensity of the projected light is
measured by a sensor. The projected
light is attenuated due to absorption and
scatter by the particulale matter in the
effluent; the percentage of visible light
attenuated is defined as the opacity of
the emission. Transparent stack
emissions that do not attenuate light will
have a transmittance of 100 percent or
an opacity of zero percent. Opaque
stack emissions that attenuate all of the
visible light will have a transmittance of
zero percent or an opacity of 100
percent.
This specification establishes specific
design criteria for the transmissometer
system. Any opacity continuous
monitoring system that is expected to
meet this specification is first checked to
verify that the design specifications are
met. Then, the opacity continuous
monitoring system is calibrated,
installed, an operated for a specified
length of time. During this specified time
period, the system is evaluated to
determine conformance with the
established performance specifications.
2. Definitions
2.1 Continuous Monitoring System.
The total equipment required for the
determination of opacity. The system
consists of the following major
subsystems;
2.1.1 Sample Interface. That portion
of the system that protects the analyzer
from the effects of the stack effluent and
aids in keeping the optical surfaces
clean.
2.1.2 Analyzer. That portion of the
system that senses the pollutant and
generates a signal output that is a
function of the opacity.
2.1.3 Data Recorder. That portion of
the system that processes the analyzer
output and provides a permanent record
of the output signal in terms of opacity.
The data recorder may include
automatic data reduction capabilities.
2.2 Transmissometer. That portion of
the system that includes the sample
interface and the analyzer.
2.3 Transmittance. The fraction of
incident light that is transmitted through
an optical medium.
2.4 Opacity. The fraction of incident1
light that is attenuated by an optical
medium. Opacity (Op) and
transmittance (Tr) are related by:
Op = l-Tr.
2.5 Optical Density. A logarithmic
measure of the amount of incident light
attenuated. Optical density (D) is
related to the transmittance and opacity
as follows:
D=-log,.Tr=-log,oIl-Op).
2.6 Peak Spectral Response. The
wavelength of maximum sensitivity of
the transmissometer.
2.7 Mean Spectral Response. The
wavelength which bisects the total area
under the effective spectral response
curve of the transmissometer.
2.8 Angle of View. The angle that
contains all of the radiation detected by
the photodetector assembly of the
analyzer at a level greater than 2.5
percent of the peak detector response.
2.9 Angle of Projection. The angle
that contains all of the radiation
projected from the lamp assembly of the
analyzer at a level of greater than 2.5
percent of the peak illuminace.
2.10 Span Value. The opacity value
at which the continuous monitoring
system is set to produce the maximum
data display output as specified in the
applicable subpart.
2.11 Upscale Calibration Value. The
opacity value at which a calibration
check of the monitoring system is
performed by simulating an upscale
opacity condition as viewed by the
receiver.
2.12 Calibration Error. The
difference between the opacity values
indicated by the continuous monitoring
system and the known values "of a series
of calibration attenuators (filters or
screens).
2.13 Zero Drift. The difference in
continuous monitoring system output
readings before and after a stated period
of normal continuous operation during
which no unscheduled maintenance,
-repair, or adjustment took place and
when the opacity (simulated) at the time
of the measurements was zero.
2.14 Calibration Drift. The difference
in the continuous monitoring system
output readings before and after a stated
period of normal continuous operation
during which no unscheduled
maintenance, repair, or adjustment took
place and when the opacity (simulated)
at the time of the measurements was the
same known upscale calibration value.
2.15 Response Time. The amount of
time it takes the continuous monitoring
system to display on the data recorder
95 percent of a step change in opacity.
2.16 Conditioning Period. A period of
time (168 hours minimum) during which
the continuous monitoring system is
operated without unscheduled
maintenance, repair, or adjustment prior
to initiation of the operational test
period.
V-Appendix B-3
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Federal Register / Vol. 44, No. 197 / Wednesday. October 10. 1979 / Proposed Rules
2.17 Operational Test Period. A
period of time (168 hours) during which
the continuous monitoring system is
expected to operate within the
established performance specifications
without any unscheduled maintenance,
repair, or adjustment.
2.18 Pathlength. The depth of
effluent in the light beam between the
receiver and the transmitter of a single-
pass transmissometer, or the depth of
effluent between the transceiver and
reflector of a double-pass
transmissometer. Two pathlengths are
referenced by this Specification as
follows:
2.18.1 Monitor Pathlength. The
pathlength at the installed location of
the continuous monitoring system.
2.18.2 Emission Outlet Pathlength.
The pathlength at the location where
emissions are released to the
atmosphere.
3. Apparatus
3.1 Continuous Monitoring System.
Use any continuous monitoring system
for opacity which is expected to meet
the design specifications in Section 5
and the performance specifications in
Section 7. The data recorder may be an
analog strip chart recorder type or other
suitable device with an input signal
range compatible with the analyzer
output.
3.2 Calibration Attenuators. Use
optical filters with neutral spectral
characteristics or screens known to
produce specified optical densities to
visible light. The attenuators must be of
sufficient size to attenuate the entire
light beam of the transmissometer.
Select and calibrate a minimum of three
attenuators according to the procedures
in Sections 8.1.2. and 8.1.3.
3.3 Upscale Calibration Value
Attenuator. Use an optical filter with
neutral spectral characteristics, a
screen, or other device that produces an
opacity value (corrected for pathlength,
if necessary) that is greater than the sum
of the applicable opacity standard and
one-fourth of the difference between the
opacity standard and the instrument
span value, but less than the sum of the
opacity standard and one-half of the
difference between the opacity standard
and the instrument span value.
3.4 Calibration Spectrophotometer.
To calibrate the calibration attenuators
use a laboratory Spectrophotometer
meeting the following minimum design
specification:
Parameter
Specification
Wavelength range
Detector angle ol view
Accuracy
. 400-700 nrn
. S10°
.... S 0.5 pet. transmttance
4. Installation Specifications
Install the continuous monitoring
system where the opacity measurements
are representative of the total emissions
from the affected facility. Use a
measurement path that represents the
average opacity over the cross section.
Those requirements can be met as
follows:
4.1 Measurement Location. Select a
measurement location that is (a)
downstream from all particulate control
equipment; (b) where condensed water
vapor is not present; (c) accessible in
order to permit routine maintenance;"
and (d) free of interference from
ambient light (applicable only if
transmissometer is responsive to
ambient light).
4.2 Measurement Path. Select a
measurement path that passes through
the centroid of the cross section.
Additional requirements or
modifications must be met for certain
locations as follows:
4.2.1 If the location is in a straight
vertical section of stack or duct and is
less than 4 equivalent diameters
downstream or 1 equivalent diameter
upstream from a bend, use a path that is
in the plane defined by the bend.
4.2.2 If the location is in a vertical
section of stack or duct and is less than
4 diameters downstream and 1 diameter
upstream from a bend, use a path in the
plane defined by the bend upstream of
the transmissometer.
4.2.3 If the location is in a horizontal
section of duct and is at least 4
diameters downstream from a vertical
bend, use a path in the horizontal plane
that is one-third the distance up the
vertical axis from the bottom of the duct.
4.2.4 If the location is in a horizontal
section of duct and is less than 4
diameters downstream from a vertical
bend, use a path in the horizontal plane
that is two-thirds the distance up the
vertical axis from the bottom of the duct
for upward flow in the vertical section,
and one-third the distance up the
vertical axis from the bottom of the duct
for downward flow.
4.3 Alternate Locations and
Measurement Paths. Other locations and
measurement paths may be selected by
demonstrating to the Administrator that
the average opacity measured at the
alternate location or path is equivalent
(± 10 percent) to the opacity as
measured at a location meeting the
criteria of Sections 4.1 and 4.2. To
conduct this demonstration, measure the
opacities at the two locations or paths
for a minimum period of two hours. The
opacities of the two locations or paths
may be measured at different times, but
must be measured at the same process
operating conditions.
5. Design Specifications
Continuous monitoring systems for
opacity must comply with the following
design specifications:
5.1 Optics.
5.1.1 Spectral Response. The peak
and mean spectral responses will occur
between 515 nm and 585 nm. The
response at any wavelength below 400
nm or above 700 nm will be less than 10
percent of the peak spectral response.
5.1.2 Angle of View. The total angle
of view will be no greater than 4
degrees.
5.1.3 Angle of Projection. The total
angle of projection will be no greater
than 4 degrees.
5.2 Optical Alignment sight. Each
analyzer will provide some method for
visually determining that the instrument
is optically aligned. The system
provided will be capable of indicating
that the unit is misaligned when an error
of ± 2 percent opacity occurs due to
misalignment at a monitor pathlength of
eight (8) meters.
5.3 Simulated Zero and Upscale
Calibration System. Each analyzer will
include a system for simulating a zero,
opacity and an upscale opacity value for
the purpose of performing periodic
checks of the transmissometer
calibration while on an operating stack
or duct. This calibration system will
provide, as a minimum, a system check
of the analyzer internal optics and all
electronic circuitry including the lamp
and photodetector assembly.
5.4 Access to External Optics. Each
analyzer will provide a means of access
to the optical surfaces exposed to the
effluent stream in order to permit the
surfaces to be cleaned Without requiring
removal of the unit from the Source
mounting or without requiring optical
realignment of the unit.
5.5 Automatic Zero Compensation
Indicator. If the monitoring system has a
feature which provides automatic zero
compensation for dirt accumulation on
exposed optical surfaces, the system
will also provide some means of
indicating that a compensation of
4 ± 0.5 percent opacity has been
exceeded; this indicator shall be at a
location accessible to the operator (e.g.,
the data output terminal). During the
operational test period, the system must
provide some means for determining the
actual amount of zero compensation at
the specified 24-hour intervals so that
the actual 24-hour zero drift can be
determined (see Section 8.4.1).
5.6 Slotted Tube. For
transmissometers that use slotted tubes,
the length of the slotted portion(s) must
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be equal to or greater than 90 percent of
the monitor pathlength, and the slotted
tube must be of sufficient size and
orientation so as not to interfere with
the free flow of effluent through the
entire optical volume of the
transmissometer photodetector. The
manufacturer must also show that the
transmissometer uses appropriate
methods to minimize light reflections; as
a minimum, this demonstration shall
consist of laboratory operation of the
transmissometer both with and without
the slotted tube in position. Should the
operator desire to use a slotted tube
design with a slotted portion equal to
less than 90 percent of the monitor
pathlength, the operator must
demonstrate to the Administrator that
acceptable results can be obtained. As a
minimum demonstration, the effluent
opacity shall be measured using both
the slotted tube instrument and another
instrument meeting the requirement of
this specification but not of the slotted
tube design. The measurements must be
made at the same location and at the
same process operating conditions for a
minimum period of two hours with each
instrument. The shorter slotted tube may
be used if the average opacity measured
is equivalent (± 10 percent) to the
opacity measured by tfie non-slotted
tube design.
6. Optical Design Specifications
Verifciation Procedure.
These procedures will not be
applicable to all designs and will require
modification in some cases; all
modifications are subject to the
approval of the Administrator.
Test each analyzer for conformance
with the design specifications of
Sections 5.1 and 5.2 or obtain a
certificate of conformance from the
analyzer manufacturer as follows;
6.1 Spectral Response. Obtain
detector response, lamp emissivity and
filter transmittance data for the
components used in the measurement
system from their respective
manufacturers.
6.2 Angle of View. Set up the
receiver as specified by the
manufacturer's written instructions.
Draw an arc with radius of 3 meters in
the horizontal direction. Using a small
(less than 3 centimeters) non-directional
light source, measure the receiver
response at 4-centimeter intervals on the
arc for 24 centimeters on either side of
the detector centerline. Repeat the test
in the vertical direction.
6.3 Angle of Projection. Set up the
projector as specified by the
manufacturer's written instructions.
Draw an arc with radius of 3 meters in
the horizontal direction. Using a small
(less than 3 centimeters) photoelectric
light detector, measure the light
intensity at 4-centimeter intervals on the
arc for 24 centimeters on either side of
the light source centerline of projection.
Repeat the test in the vertical direction.
6.4 Optical Alignment Sight. In the
laboratory set up the instrument as
specified by the manufacturers written
instructions for a monitor pathlength of
8 meters. Assure that the instrument has
been properly aligned and that a proper
zero and span have been obtained.
Insert an attenuator of 10 percent
(nominal) opacity into the instrument
pathlength. Slowly misalign the
projector unit until a positive or negative
shift of two percent opacity is obtained
by the data recorder. Then, following
the manufacturer's written instructions,
check the alignment and assure that the
alignment procedure does in fact
indicate that the instrument is
misaligned. Realign the instrument and
follow the same procedure for checking
misalignment of the receiver or
retroreflector unit'.
6.5 Manufacturer's Certificate of
Conformance (Alternative to above).
Obtain from the manufacturer a
certificate of conformance which
certifies that the first analyzer randomly
sampled from each month's production
was tested according to Sections 6.1
through 6.3 and satisfactorily met all
requirements of Section 5 of this
Specification. If any of the requirements
were not met, the certificate must state
that the entire month's analyzer
production was resampled according to
the military standard 105D sampling
procedure (MIL-STD-105D) inspection
level II; was retested for each of the
applicable requirements under Section 5
of this Specification; and was
determined to be acceptable under MIL-
STD-105D procedures, acceptable
quality level 1.0, The certificate of
conformance must include the results of
each test performed for the analyzer(s)
sampled during the month the analyzer
being installed was produced.
7. Performance Specifications
The opacity continuous monitoring
system performance specifications are
listed in Table 1-1.
Table 1-1.Performance specifications
Table 1-1.Performance specificationsContinued
Parameter
Specifications
Parameter
Specification!
6 Calibration dnfl (24-hour)
7 Data recorder resolution
S pet opacity
: 0 50 pet ol full scale
span value
1 Calibration error . .
2 Response time
3 Conditioning period6
4 Operational test penod
5 Zero drift (24-hour) . ..
S 3 pet opacity
S 10 seconds
=f 168 hours
a 168 hours
S 2 pet opacity
Expressed as sum of absolute mean and the 95 percent
confidence interval
During the conditioning and operational test periods the
continuous monitonng system shall not require any corrective
maintenance, repair, replacement, or adjustment other than
that clearly specified as routine and required in the operation
and maintenance manuals
8. Performance Specification
Verification Procedure
Test each continuous monitoring
system that conforms to the design
specifications (Section 5) using the
following procedures to determine
conformance with the performance
specifications of Section 7.
8.1 Preliminary Adjustments and
Tests. Prior to installation of the system
on the stack, perform these steps or tests
at the affected facility or in the
manufacturer's laboratory.
8.1.1 Equipment Preparation. Set up
and calibrate the monitoring system for
the monitor pathlength to be used in the
installation as specified by the
manufacturer's written instructions. If
the monitonng system has automatic
pathlength adjustment, follow the
manufacturer's instructions to adjust the
signal output from the analyzer to
equivalent values based on the emission
outlet pathlength. Set the span at the
value specified in the applicable
subpart. At this time perform the zero
alignment by balancing the response of
the continuous monitoring system so
that the simulated zero check coincides
with the actual zero check performed
across the simulated monitor pathlength
Then, assure that the upscale calibration
value is within the required opacity
range (Section 3.3).
B.I.2 Calibrated Attenuator
Selection. Based on the span value
specified in the applicable subpart,
select a minimum of three calibrated
attenuators (low, mid, and high range)
using Table 1-2. If the system is
operating with automatic pathlength
compensation, calculates the attenuator
values required to obtain a system
response equivalent to the applicable
values shown in Table 1-2, use equation
1-1 for the conversion. A series of filters
with nominal optical density (opacity)
values of 0.1(20), 0.2(37), 0.3(50), 0.4(60).
0.5(68). 0.6(75), 0.7(80), 0.8(84). 0.9(88).
and 1.0(90) are commercially available
Within this limitation of filter
availability, select the calibrated
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attenuators having the values given in
Table 1-2 or having values closest to
those calculated by Equation 1-1.
Table 1-2.Required Calibrated Attenuator Values
(Nominal)
Span vaKje
(percent opacrty)
Calibrated attenuator
optical density
(equivalent opacrty
m parenthesis)
Low-range D, Mid-range High-range
50
60
70
80
90
100
0 1 (20)
1 (20)
1 (20)
1 (20)
1 (20)
1 (20)
02
2
.3
3
4
4
(37)
(37)
(50)
(50)
(60)
(60)
03
3
4
.6
7
9 (1
(50)
(50)
ISO)
(751
(80)
37';)
D, = D2 (L./L,)
Equation 1-1
Where:
Di = Nominal optical density value of
required mid. low. or high range
calibration attenuators.
Dz = Desired attenuator optical density
output value from Table 1-2 at the span
required by the applicable subpart.
L, = Monitor pathlength.
Lz = Emission outlet pathlength.
8.1.3 Attenuator Calibration.
Calibrate the required filters or screens
using a laboratory spectrophotometer
meeting the specifications of Section 3.4
to measure the transmittance in the 400
to 700 nm wavelength range; make
measurements at wavelength intervals
of 20 nm or less. As an alternate
procedure use an instrument meeting the
specifications of Section 3.4 to measure
the C.I E. Daylightc Luminous
Transmittance of the attenuators. During
the calibration procedure assure that a
minimum of 75 percent of the total area
of the attenuator is checked The
attenuator manufacturer must specify
the period of time over which the
attenuator values can be considered
stable, as well as any special handling
and storing procedures required to
enhance attenuator stability. To assure
stability, attenuator values must be
rechecked at intervals less than or equal
to the period of stability guaranteed by
the manufacturer. However, values must
be rechecked at least every 3 months. If
desired, testability checks may be
performed on an instrument other than
that initially used for the attenuator
calibration (Section 3.4). However, if a
different instrument is used, the
instrument shall be a high quality
laboratory transmissometer or
spectrophotometer and the same
instrument shall always be used for the
stability checks. If a secondary
instrument is to be used for stability
checks, the value of the calibrated
attenuator shall be measured on this
secondary instrument immediately
following calibration and prior to being
used. If over a period time an attenuator
value changes by more than ±2 percent
opacity, it shall be recalibrated or
replaced by a new attenuator.
If this procedure is conducted by the
filter or screen manufacturer or
independent laboratory, obtain a
statement certifying the values and that
the specified procedure, or equivalent,
was used.
8.1.4 Calibration Error Test. Insert
the calibrated attenuators (low, mid, and
high range) in the transmissometer path
at or as near to the midpoint as feasible.
The attenuator must be placed in the
measurement path at a point where the
effluent will be measured; i.e., do not
place the calibrated attenuator in the
instrument housing. While inserting the
attenuator, assure that the entire
projected beam will pass through the
attenuator and that the attenuator is
inserted in a manner which minimizes
interference from reflected light. Make a
total of five nonconsecutive readings for
each filter. Record the monitoring
system output readings in percent
opacity (see example Figure 1-1).
8.1.5 System Response Test. Insert
the high-range calibrated attenuator in
the transmissometer path five times and
record the time required for the system
to respond to 95 percent of final zero
and high-range filter values (see
example Figure 1-2).
8.2 Preliminary Field Adjustments.
Install the continuous monitoring system
on the affected facility according to the
manufacturer's written instructions and
perform the following preliminary
adjustments;
8.2.1 Optical and Zero Alignment.
When the facility is not in operation,
conduct the optical alignment by
aligning the light beam from the
transmissometer upon the optical
surface located across the duct or stack
(i.e., the retroflector or photodetector, as
applicable) in accordance with the
manufacturer's instructions. Under clear
stack conditions, verify the zero
alignment (performed in Section 8.1.1)
by assuring that the monitoring system
response for the simulated zero check
coincides with the actual zero measured
by the transmissometer across the clear
stack. Adjust the zero alignment, if
necessary. Then, after the affected
facility has been started up and the
effluent stream reaches normal
operating temperature, recheck the
optical alignment. If the optical
alignment has shifted realign the optics.
8.2.2 Optical and Zero Alignment
(Alternative Procedure). If the facility is
already on line and a zero stack
condition cannot practicably be
obtained, use the zero alignment
obtained during the preliminary
adjustments (Section 8.1.1) prior to
installation of the transmissometer on
the stack. After completing all the
preliminary adjustments and tests
required in Section 8.1, install the
system at the source and align the
optics, i.e., align the light beam from the
transmissometer upon the optical
surface located across the duct or stack
in accordance with the manufacturer's
instruction. The zero alignment
conducted in this manner shall be
verified and adjusted, if necessary, the
first time the facility is not in operation
after the operational test period has
been completed.
8.3 Conditioning Period. After
completing the preliminary field
adjustments (Section 8.2), operate the
system according to the manufacturer's
instructions for an initial conditioning
period of not less than 168 hours while
the source is operating. Except during
times of instrument zero and upscale
calibration checks, the continuous
monitoring system will analyze the
effluent gas for opacity and produce a
permanent record of the continuous
monitoring system output. During this
conditioning period there shall be no
unscheduled maintenance, repair, or
adjustment. Conduct daily zero
calibration and upscale calibration
checks, and, when accumulated drift
exceeds the daily operating limits, make
adjustments and/or clean the exposed
optical surfaces. The data recorder shall
reflect these checks and adjustments. At
the end of the operational test period,
verify that the instrument optical
alignment is correct. If the conditioning
period is interrupted because of source
breakdown (record the dates and times
of process shutdown), continue the 168-
hour period following resumption of
source operation. If the conditioning
period is interrupted because of monitor
failure, restart the 168-hour conditioning
period when the monitor becomes
operational.
8.4 Operational Test Period. After
completing the conditioning period
operate the system for an additional
168-hour period. It is not necessary that
the 168-hour operational test period
immediately follow the 168-hour
conditioning period. Except during times
of instrument zero and upscale
calibration checks, the continuous
monitoring system will analyze the
effluent gas for opacity and will produce
a permanent record of the continuous
monitoring system output. During this
period, there will be no unscheduled
maintenance, repair, or adjustment. Zero
and calibration adjustments, optical
surface cleaning, and optical
realignment may be performed
(optional) only at 24-hour intervals or at
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such shorter intervals as the
manufacturer's written instructions
specify. Automatic zero and calibration
adjustments made by the monitoring
system without operator intervention or
initiation are followable at any time. If
the operational test period is interrupted
because of source breakdown, continue
the 168-hour period following
resumption of source operation. If the
test period is interrupted because of
monitor failure, restart the 168-hour
period when the monitor becomes
operational. During the operational test
period, perform the following test
procedures:
8.4.1 Zero Drift Test. At the outset of
the 168-hour operational test period,
record the initial simulated zero and
upscale opacity readings (see example
Figure 1-3). After each 24-hour interval
check and record the final zero reading
before any optional or required cleaning
and adjustment. Zero and upscale
calibration adjustments, optical surface
cleaning, and optical realignment may
be performed only at 24-hour intervals
(or at such shorter intervals as the
manufacturer's written instructions
specify) but are optional. However,
adjustments and/or cleaning must be
performed when the accumulated zero
calibration or upscale calibration drift
exceeds the 24-hour drift specifications
(±2 percent opacity). If no adjustments
are made after the zero check the final
zero reading is recorded as the initial
reading for the next 24-hour period. If
adjustments are made, the zero value
after adjustment is recorded as the
initial zero value for the next 24-hour
period. If the instrument has an
automatic zero compensation feature for
dirt accumulation on exposed lens, and
the zero value cannot be measured
before compensation is entered then
record the amount of automatic zero
compensation for the final zero reading
of each 24-hour period. (List the
indicated zero values of the monitoring
system in parenthesis.)
6.4.2 Upscale Drift Test. At each 24-
hour interval, after the zero calibration
value has been checked and any
optional or required adjustments have
been made, check and record the
simulated upscale calibration value. If
no further adjustments are made to the
calibration system at this time, the final
upscale calibration value is recorded as
the initial upscale value for the next 24-
hour period. If an instrument span
adjustment is made, the upscale value
after adjustment is recorded as the
initial upscale for the next 24-hour
period.
During the operational test period
record all adjustments, realignments and
lens cleanings.
9. Calculation, Data Analysis, and
Reporting
9.1 Arithmetic Mean. Calculate the
mean of a set of data as follows:
- 1 n
X ; I X,
~° 1-1 1
Equation 2-1
Where:
x = mean value.
n = number of data points.
2x, = algebraic sum of the individual
measurements, x,
9.2 Confidence Interval. Calculate
the 95 percent confidence interval (two-
sided) as follows:
c.!.
95
Equation 2-!
Where:
C.I.,s = 95 percent confidence interval
estimate of the average mean value.
1 975 = '(1a/2).
Table 1-3 '.975 Values
2
3
4
i
6
12706
4303
3 <82
2776
2571
7
e
8
10
11
2447
2385
2306
2282
2228
12
13
t<
15
16
2201
2179
2160
2145
.2131
The values in this table are already
corrected for n-1 degrees of Freedom.
Use n equal to the number of data
points.
9.3 Conversion of Opacity Values
from Monitor Pathlength to Emission
Outlet Pathlength. When the monitor
pathlength is different than the emisson
outlet pathlength, use either of the
following equations to convert from one
basis to the other (this conversion may
be automatically calculated by the
monitoring system):
log(l-Opa)
,) Log (1-Op,) Equation 1-4
D3 = (L2/Li) Equation 1-5
Where:
Op, = opacity of the effluent based upon L,
Opi = opacity of the effluent based upon L,
Li = monitor pathlength
L2 = emission outlet pathlength
Di = optical density of the effluent based
upon L,
Dz = optical density of the effleunt based
upon Li
9.4 Spectral Response. Using the
spectral data obtained in Section 6.1,
develop the effective spectral response
curve of the transmissometer. Then
determine and report the peak spectral
response wavelength, the mean spectral
response wavelength, and the maximum
response at any wavelength below 400
nm and above 700 nm expressed as a
percentage of the peak response.
9.5 Angle of View. For the horizontal
and vertical directions, using the data
obtained in Section 6.2, calculate the
response of the receiver as a function of
viewing angle (21 centimeters of arc
with a radius of 3 meters equal 4
degrees), report relative angle of view
curves, and determine and report the
angle of view.
9.6 Angle of Projection. For the
horizontal and vertical directions, using
the data obtained in Section 6.3,
calculate the response of the
photoelectric detector as a function of
projection angle, report relative angle of
projection curves, and determine and
report the angle of projection.
9.7 Calibration Error. See Figure 1-1.
If the pathlength is not adjusted by the
measurement system, subtract the
actual calibrated attenuator value from
the value indicated by the measurement
system recorder for each of the 15
readings obtained pursuant to Section
8.1.4. If the pathlength is adjusted by the
measurement system subtract the "path
adjusted" calibrated attenuator values
from the values indecated by the
measurement system recorder the "path
adjusted" calibrated attenuator values
are calculated using equation 1-4 or 1-
5). Calculate the arithmetic mean
difference and the 95 percent confidence
interval of the five tests at each
attenuator value using Equations 1-2
and 1-3. Calculate the sum of the
absolute value of the mean difference
and the 95 percent confidence interval
for each of the three test attenuators;
report these three values as the
calibration error.
9.8 Zero and Upscale Calibration
Drifts. Using the data obtained in
Sections 8.4.1 and 8.4.2 calculate the
zero and upscale calibration drifts. Then
calculate the arithmetic means and the
95 percent confidence intervals using
Equations 1-2 and 1-3. Calculate the
sum of the absolute value of the mean
and the 95 percent confidence interval
and report these values as the 24-hour
zero drift and the 24-hour calibration
drift.
9.9 Response Time. Using the data
collected in Section 8.1.5, calculate the
mean time of the 10 upscale and
downscale tests and report this value as
the system response time.
9.10 Reporting. Report the following
(summarize in tabular form where
appropriate).
9.10.1 General Information.
a. Instrument Manufacturer.
b. Instrument Model Number.
c. Instrument Serial Number.
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d. Person(s) responsible for
operational and conditioning test
periods and affiliation.
e. Facility being monitored.
f. Schematic of monitoring system
measurement path location.
g. Monitor pathlength, meters.
h. Emission outlet pathlength, meters.
i. System span value, percent opacity.
j. Upscale calibration value, percent
opacity.
k. Calibrated Attenuator values (low,
mid, and high range), percent opacity.
9.10.2 Design Specification Test
Results
a. Peak spectral response, nm.
b. Mean spectral response, nm.
c. Response above 700 nm, percent of
peak.
d. Response below 400 nm, percent of
peak.
e. Total angle of view, degrees.
f. Total angle of projection, degrees.
9.10.3 Operational Test Period
Results.
a. Calibration error, high-range,
percent opacity.
b. Calibration error, mid-range,
percent opacity.
c. Calibration error, low-range,
percent opacity.
d. Response time, seconds.
e. 24-hour zero drift, percent opacity.
f. 24-hour calibration drift, percent
opacity.
g. Lens cleaning, clock time.
h. Optical alignment adjustment, clock
time.
9.10.4 Statements. Provide a
Statement that the conditioning and
operational test periods were completed
according to the requirements of
Sections 8.3 and 8.4. In this statement,
include the time periods during which
the conditioning and operational test
periods were conducted.
9.10.5 Appendix. Provide the data
tabulations and calculations for the
above tabulated results.
9.11 Retest. If the continuous
monitoring system operates within the
specified performance parameters of
Table 1-1, the operational test period
will be successfully concluded. If the
continuous monitoring system fails to
meet any of the specified performance
parameters, repeat the operational test
period with a system that meets the
design specifications and is expected to
meet the performance specifications.
10. Bibliograpny.
10.1 "Experimental Statistics,"
Department of Commerce, National
Bureau of Standards Handbook 91,1963,
pp. 3-31, paragraphs 3-3.1.4.
10.2 "Performance Specifications for
Stationary-Source Monitoring Systems
for Gases and Visible Emissions,"
Environmental Protection Agency,
Research Triangle Park, N. C., EPA-650/
2-74-013, January 1974. '
V-Appendix B-8
-------
Federal Register / Vol. 44, No. 197 / Wednesday, October 10,1979 / Proposed Rules
Person Con
Affiliation _
riurting Tp^t . , Analyzer Manufacturer
M^Hol/Qorial Mr,
DfltP 1 nratinn
Monitor Pal
Monitoring
Calibrated f
Actual C
Lou
Mid
Higl
Run
Number
1 Low
2 -Mid
3 - High
4 Low
5 -Mid
6 - High
7 Low
8 -Mid
9 - High
10-Low
11-Mid
12-High
13-Low
14-Mid
15-High
System Output Pathlength Corrected? Yes No
Meutral Density Filter Values
Jptical Density (Opacity): Path Adjusted Optical Density (opacity)
j Rangp { ) | ow RflPQP . , { )
Range ( , . ,_J Mid Rangp , ,_( .)
i Rangp (. _ ) H'gh Rf»nge .( )
Calibration Filter
Value
(Path Adjusted Percent Opacity)
Instrument Reading
(Percent Opacity)
Arithmetic Mean (Equation 1 - 2): A
Confidence Interval (Equation 1 - 3): B
Calibration Error |A| + JB|
Arithmetic Difference
(% Opacity)
Low
-
-
-
-
X
Mid
-
-
X
High
-
-
X
Figure 1 - 1. Calibration error determination
V-Appendix B-9
-------
Federal Register / Vol. 44, No. 197 / Wednesday, October 10, 1979 / Proposed Rules
Person Conducting Test Analyzer Manufacturer .
Affiliation Model/Serial No
Date Location
High Range Calibration Filter Value: Actual Optical Density (Opacity).
Path Adjusted Optical Density (Opacity).
Upscale Response Value ( 0.95 x filter value) percent opacity
Downscale Response Value (0.05 x filter value) percent opacity
Upscale 1
2 seconds
3 seconds
4 seconds
5 seconds
Downscale 1 seconds
2 seconds
3 seconds
4 seconds
5
Average response seconds
Figure 1-2. Response Time Determination
V-Appendix B-10
-------
Federal Register / Vol. 44, No. 197 / Wednesday, October 10,1979 / Proposed Rules
Person
Affilia
Date
Conducting Tes
tinn
t AD
Mir.
1 n,
alyzer Man
del/ Serial
atinn
jfacturpr .
Mr,
Monitor Pathlength, L
Monitoring System Oul
Upscale Calibration Va
Date
Time
Begin
End
F
tput Pathlength Corrected
ue : Actual Optical Den
Path Adjusted Opti
mission Ou
:? Yes
sity (Opac
cal Density
tlet Pathler
r>
tv)
(Opacity)
iqth Lo
Jn
I 1
( )
Percent Opacity
Zero Reading*
Initial
A
Final
B
Arithmetic Mean (Eq. 1-2)
Conf dence Interval (Eq. 1-3)
Zero Drift
'without automatic zero compensatic
**if zero was adjusted (manually or a
prior to upscale check, then use c =
Zero
Drift
C = B-A
zero adjusted?
Upscale Calibration
Reading
Initial
D
Final
E
Upscale
Drift
F = E-D
Calibration Drift
Cali-
bration
Drift
G = F-C**
span adjusted?
lens cleaned?
Align-
ment
checked?
adjusted?
n
jtomatically)
0.
Figure 1 3. Zero Calibration Drift Determination
V-Appendix B-ll
-------
Federal Register / Vol. 44. No. 197 / Wednesday, October 10. 1979 / Proposed Rules
Performance Specification 2
Specifications and Test Procedures for
SOi and NO, Continuous Monitoring
Systems in Stationary Sources
1. Applicability and Principle
1.1 Applicability. This Specification
contains (a) installation requirements,
(b) instrument performance and
equipment specifications, and (c) test
procedures and data reduction
procedures for evaluating the
acceptability of SOz and NO, continuous
monitoring systems, which may include,
for certain stationary sources, diluent
monitors. The test procedures in item
{c), above, are not applicable to single-
pass, in-situ continuous monitoring
systems; these systems will be
evaluated on a case-by-case basis upon
written request to the Administrator and
alternative test procedures will be
issued separately.
1.2 Principle. Any SO, or NO,
continuous monitoring system that is
expected to meet this Specification is
installed, calibrated, and operated for a
specified length of time. During this
specified time period, the continuous
monitoring system is evaluated to
determine conformance with the
Specification.
2. Definitions
2.1 Continuous Monitoring System.
The total equipment required for the
determination of a gas concentration or
a gas emission rate. The system consists
of the following major sub-systems:
2.1.1 Sample Interface. That portion
of a system that is used for one or more
of the following: sample acquisition,
sample transportation, sample
conditioning, or protection of the
monitor from the effects of the stack
effluent.
2.1.2, Pollutant Analyzer. That
portion of the system that senses the
pollutant gas and generates an output'
that is proportional to the gas
concentration.
2.1.3. Diluent Analyzer (if
applicable). That portion of the system
that senses the diluent gas (e.g., COa or
O2) and generates an output that is
proportional to the gas concentration.
2.1.4 Data Recorder. That portion of
the monitoring system that provides a
permanent record of the analyzer
output. The data recorder may include
automatic data reduction capabilities.
2.2 Types of Monitors. Continuous
monitors are categorized as "extractive"
or "in-situ," which are further
categorized as "point," "multipoint,"
"limited-path," and "path" type
monitors or as "single-pass" or "double-
pass" type monitors.
2.2.1 Extractive Monitor. One that
withdraws a gas sample from the stabk
and transports the sample to the
analyzer.
2.2.2 In-situ Monitor. One that
senses the gas concentration in the
stack environment and does not extract
a sample for analysis.
2.2.3 Point Monitor. One that
measures the gas concentration either at
a single point or along a path which is
less than 10 percent of the length of a
specified measurement line.
2.2.4 Multipoint Monitor. One that
measures the gas concentration at 2 or
more points.
2.2.5 Limited-Path Monitor. One that
measures the gas concentration along a
path, which is 10 to 90 percent of the
length of a specified measurement line.
2.2.6 Path Monitor. One that
measures the gas concentration along a
path, which is greater than 90 percent of
the length of a specified measurement
line.
2.2.7 Single-Pass Monitor. One that
has the transmitter and the detector on
opposite sides of the stack or duct.
2.2.8 Double-Pass Monitor. One that
has the transmitter and the detector on
the same side of the stack or duct.
2.3 Span Value. The upper limit of a
gas concentration measurement range
which is specified for affected source
categories in the applicable subpart of
the regulations.
2.4 Calibration Gases. A known
concentration of a gas in an appropriate
diluent gas.
2.5 Calibration Gas Cells or Filters.
A device which, when inserted between
the transmitter and detector of the
analyzer, produces the desired output
level on the data recorder.
2.6 Relative Accuracy. The degree of
correctness including analytical
variations of the gas concentration or
emission rate determined by the
continuous monitoring system, relative
to the value determined by the reference
method(s).
2.7 Calibration Error. The difference
between the gas concentration indicated
by the continuous monitoring system
and the known concentration of the
calibration gas, gas cell, or filter.
2.8 Zero Drift. The difference in the
continuous monitoring system output
readings before and after a stated period
of operation during which no
unscheduled maintenance, repair, or
adjustment took place and when the
pollutant concentration at the time of
the measurements was zero (i.e., zero
gas, or zero gas cell or filter).
2.9 Calibration Drift. The difference
in the continuous monitoring system
output readings before and after a stated
period of operation during which no
unscheduled maintenance, repair or
adjustment took place and when the
pollutant concentration at the time of
the measurements was a high-level
value (i.e., calibration gas, gas cell or
filter).
2.10 Response Time. The amount of
time it takes the continuous monitoring
system to display on the data recorder
95 percent of a step change in pollutant
concentration.
2.11 Conditioning Period. A
minimum period of time over which the
continuous monitoring system is
expected to operate with no
unscheduled maintenance, repair, or
adjustments prior to initiation of the
operational test period.
2.12 Operational Test Period. A
minimum period of time over which the
continuous monitoring system is
expected to operate within the
established performance specifications
with no unscheduled maintenance,
repair or adjustment.
3. Installation Specifications
Install the continuous monitoring
system at a location where the pollutant
concentration measurement* are
representative of the total emissions
from the affected facility and are
representative of the concentration over
the cross section. Both requirements can
be met as follows:
3.1 Measurement Location. Select an
accessible measurement location in the
stack or ductwork that is at least 2
equivalent diameters downstream from
the nearest control device or other point
at which a change in the pollutant
concentration may occur and at least 0.5
equivalent diameters upstream from the
effluent exhaust. Individual subparts of
the regulations may contain additional
requirements. For example, for steam
generating facilities, the location must
be downstream of the air preheater.
3.2 Measurement Points or Paths.
There are two alternatives. The tester
may choose either (a) to conduct the
stratification check procedure given in
Section 3.3 to select the point, points, or
path of average gas concentration, or (b)
to use the options listed below without a
stratification check.
Note.For the purpose of this section, the
"centroidal area" is defined as a concentric
area that is geometrically similar to the stack
cross section and is no greater than 1 percent
of the stack cross-sectional area.
3,2.1 SO2 and NO, Path Monitoring
Systems. The tester may choose to
centrally locate the sample interface
(path) of the monitoring system on a
measurement line that passes through
the "centroidal area" of the cross
section.
V-Appendix B-12
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Federal Register / Vol. 44, No. 197 / Wednesday, October 10, 1979 / Proposed Rules
3.2.2 SOi and NO, Multipoint
Monitoring Systems. The tester may
choose to space 3 measurement points
along a measurement line that passes
through the "centroidal area" of the
stack cross section, at distances of 16.7,
50.0, and 83.3 percent of the way across
it (see Figure 2-1).
POINT
NO.
DISTANCE
(% OF L)
16.7
500
833
"CENTROIDAL
AREA"
Figure 21. Location of an example measurement line (L) and measurement points.
V-Appendix B-13
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Federal Register / Vol. 44. No. 197 / Wednesday, October 10, 1979 / Proposed Rules
The following sampling strategies, or
equivalent, for measuring the
concentrations at the 3 points are
acceptable: (a) The use of a 3-probe or a
3-hole single probe arrangment,
provided that the sampling rate in each
of the 3 probes or holes is maintained
within 10 percent of their average rate
(This option requires a procedure,
subject to the approval of the
Administrator, to demonstrate that the
proper sampling rate is maintained); or
(b) the use of a traversing probe
arrangement, provided that a
measurement at each point is made at
least once every 15 minutes and all 3
points are traversed and sampled for
equal lengths of time within 15 minutes.
3.2.3 SOj Single-Point and Limited-
Path Monitoring Systems. Provided that
(a) no "dissimilar" gas streams (i.e.,
having greater than 10 percent
difference in pollutant concentration
from the average) are combined
upstream of the measurement location,
and (b] for steam generating facilities, a
COa or O2 cotinuous monitor is installed
in addition to the SO2 monitor,
according to the guidelines given in
Section 3.1 or 3.2 of Performance
Specification 3, the tester may choose to
monitor SO2 at a single point or over a
limited path. Locate the point in or
centrally locate the limited path over the
"centroidal area." Any other location
within the inner 50 percent of the stack
cross-sectional area that has been
demonstrated (see Section 3.4) to have a
concentration within 5 percent of the
concentration at a point within the
"centroidal area" may be used.
3.2.4 NO, Single-Point and Limited-
Path Monitoring Systems. For NO,
monitors, the tester may choose the
single-point or limited-path option
described in Section 3.2.3 only in coal-
burning steam generators (does not
include oil and gas-fired units) and nitric
acid plants, which have no dissimilar
gas streams combining upstream of the
measurement location.
3.3 Stratification Check Procedure.
Unless specifically approved in Section
3.2., conduct a stratification check and
select the measurement point, points, or
path as follows:
3.3.1 Locate 9 sample points, as
shown in Figure 2-2, a or b. The tester
may choose to use more than 9 points,
provided that the sample points are
located in a similar fashion as in Fgure
2-2.
3.3.2 Measure at least twice the
pollutant and, if applicable (as in the
case of steam generators), CO, or Oa
'concentrations at each of the sample
points. Moisture need not be determined
for this step. The following methods are
acceptable for the measurements: (a)
Reference Methods 3 (grab-sample), 6 or
7 of this part; (b) appropriate
instrumental methods which give
relative responses to the pollutant (i.e.,
the methods need not be absolutely
correct), subject to the approval of the
Administrator; or (c) alternative
methods subject to the approval of the
Administrator. Express all
measurements, if applicable, in the units
of the applicable standard.
3 3.3 Calculate the mean value and
select a point, points, limited-path, or
path which gives an equivalent value to
the mean. The point or points must be
within, and the limited-path or path
must pass through, the inner 50 percent
of the stack cross-sectional area. All
other locations must be approved by the
Administrator.
V-Appendix B-14
-------
1.9
2.8
C
3,7
4.6
Federal Register / Vol. 44, No. 197 / Wednesday, October 10,1979 / Proposed Rules
POINT DISTANCE
NO. (%OFD)
10.0
30.0
50.0
70.0
90.0
(a)
2
(b)
6
9
Figure 22. Location of 9 sampling points for stratification check.
V-Appendix B-15
-------
Federal Register / Vol. 44, No. 197 / Wednesday, October 10, 1979 / Proposed Rules
3.4 Acceptability of Single Point or
Limited Path Alternative Location. Any
of the applicable measurement methods
mentioned in Section 3.3.2, above, may
be used. Measure the pollutant and, if
applicable, CC>2 or O2 concentrations at
both the centroidal area and the
alternative locations. Moisture need not
be measured for this test. Collect a 21-
minute integrated sample or 3 grab-
samples, either at evenly spaced (7 ± 2
min.) intervals over 21 minutes or all
within 3 minutes, at each location. Run
the comparative tests either
concurrently or within 10 minutes of
each other. Average the results of the 3
grab-samples.
Repeat the measurements until a
minimum of 3 paired measurements
spanning a minimum of 1 hour of
process operation are obtained.
Determine the average pollutant
concentrations at the centroidal area
and the alternative locations. If
applicable, convert the data in terms of
the standard for each paired set before
taking the average. The alternative
sampling location is acceptable if each
alternative location value is within ± 10
percent of the corresponding centroidal
area value and if the average at the
alternative location is within 5 percent
of the average of the centroidal area.
4. Performance and Equipment
Specifications
The continuous monitoring system
performance and equipment
specifications are listed in Table 2-1. To
be considered acceptable, the
continuous monitoring system must
demonstrate compliance with these
specifications using the test procedures
of Section 6.
5. Apparatus
5.1 Continuous Monitoring System.
Use any continuous monitoring system
of SO, or NO, which is expected to meet
the specifications in Table 2-1. For
sources which are required to convert
the pollutant concentrations to other
emission units using diluent gas
measurements, the diluent gas
continuous monitor, as described in
Performance Specification 3 of this
Appendix, is considered part of the
continuous monitoring system. The data
recorder may be an analog strip chart
recorder type or other suitable device
with an input signal range compatible
with the analyzer output.
5.2 Calibration Gases. For
continuous monitoring systems that
allow the introduction of calibration
gases to the analyzer, the calibration
gases may be SO, in air or N,, NO in Na,
and NOs in air or N». Two or more
calibration gases may be combined in
the same gas cylinder, except do not
combine the NO and air. For NO,
monitoring systems that oxidize NO to
NOa, the calibration gases must be in the
form of NO. Use three calibration gas
mixtures as specified below:
5.2.1 High-Level Gas. A gas
concentration that is equivalent to 80 to
90 percent of the span value.
Table 2-1.Continuous Monitoring System
Performance and Equipment Specifications
Parameter
Specification
1 Conditioning
penod'
2 Operational lest
period-
3 Calibration error
4 Response time. ..
5 Zero drift 12-
hour) »
6 Zero dntt (24-
hour)"
7 Calibration drift
(2-hour)*.
6 Calibration drift
(24-hour)'
0 Relative
accuracy *
10 Calibration gas
cells or filters
1 \ Data recorder
chart resolution
12 Extractive
systems with diluent
monitors
3168 hours
9166 hours.
« 5 pet of each mid-level and high-
level calibration value
* 15 minutes (5 minutes for 3-pomt
traversing probe arrangement).
e 2 pet ol span value
«2 pet of span value.
« 2 pet of span value.
« 2 5 pet of span value.
* 20 pet of the mean value of
reference methodXs) test data in
terms of emission standard or 10
percent of the applicable :
standard, whichever is greater
Must provide a check of all analyzer
internal mirrors and lenses and aH
electronic circuitry including the
radiation source and detector
assembly which are normally us0
m sampling and analysts
Chart scales must be readable to
within « 0 50 pet of full-scale
Must use the same sample interface
to sample both the pollutant and
diluent gases Place m series
(diluent after pollutant analyzer) or
use a "T " Dunng the
conditioning and operational test
periods, the continuous momlonng
system shaH not require any
corrective maintenance, repair.
replacement, or adjustment other
than that clearly specified as
routine and required m the
operation and maintenance
manuals Expressed as the sum
of the absolute mean value plus
the 95 percent confidence interval
ol a series of tests divided by a
reference value * A low-level (5-
15 percent of span value) drift lest
may be substituted for the zero
Dnft tests
5.2.2 Mid-Level Gas. A gas
concentration that is equivalent to 45 to
55 percent of the span value.
5.2.3 Zero Gas. A gas concentration
of less than 0.25 percent of the span
value. Ambient air may be used for the
zero gas.
5.3 Calibration Gas Cells or Filters.
For continuous monitoring systems
which use calibration gas cells or filters,
use three certified calibration gas cells
or filters as specified below:
5.3.1 High-Level Gas Cell or Filter.
One that produces an output equivalent
to 80 to 90 percent of the span value.
5.3.2 Mid-Level Gas Cell or Filter.
One that produces an output equivalent
to 45 to 55 percent of the span value.
5.3.3 Zero Gas Cell or Filter. One
that produces an output equivalent to
zero. Alternatively, an analyzer may
produce a zero value check by
mechanical means, such as a movable
mirror.
5.4 Calibration GasGas Cell or
Filter Combination. Combinations of the
above may be used.
6. Performance Specification Test
Procedures.
6.1 Pretest Preparation.
6.1.1 Calibration Gas Certification.
The tester may select one of the
following alternatives: (a) The tester
may use calibration gases prepared
according to the protocol defined in
Citation 10.5, i.e. These gases may be
used as received without reference
method analysis (obtain a statement
from the gas cylinder supplier certifying
that the calibration gases have been
prepared according to the protocol); or
(b) the tester may use calibration gases
not prepared according to the protocol.
In case (b), he must perform triplicate
analyses of each calibration gas (mid-
level and high-level, only) within 2
weeks prior to the operational test
period using the appropriate reference
methods. Acceptable procedures are
described in Citations 10.6 and 10.7.
Record the results on a data sheet
(example is shown in Figure 2-3). Each
of the individual analytical results must
be within 10 percent (or 15 ppm,
whichever is greater) of the average;
otherwise, discard the entire set and
repeat the triplicate analyses. If the
average of the triplicate reference
method test results is within 5 percent of
the calibration gas manufacturer's tag
value, use the tag value; otherwise,
conduct at least 3 additional reference
method test analyses until the results of
6 individual runs (the 3 original plus 3
additional) agree within 10 percent or 15
ppm, whichever is greater, of the
average. Then use this average for the
cylinder value.
V-Appendix B-16
-------
Federal Register / Vol. 44, No. 197 / Wednesday, October 10. 1979 / Proposed Rules
Figure 2-3. Analysis of Calibration Gases
Date (Must be within 2 weeks prior to the
operational test period)
Reference Method Used
Sample Run
1
2
3
Werage
laximum % Deviation
Mid-lever
ppm
High-level0
PPm
used
a Not necessary if the protocol in Citation 10.5 is
to prepare the gas cylinders.
Average must be 45 to 55 percent of span value.
c Average must be 80 to 90 percent of span value.
-Must be < + 10 percent of applicable average or 15 ppm,
whichever" Ts greater.
6.1.2 Calibration Gas Cell or Filter
Certification. Obtain (a) a statement
from the manufacturer certifying that the
calibration gas cells or filters (zero, mid-
level, and high-level) will produce the
stated instrument responses for the
continuous monitoring system, and (b) a
description of the test procedure and
equipment used to calibrate the cells or
filters. At a minimum, the manufacturer
must have calibrated the gas cells or
filters against a simulated source of
known concentration.
6.2 Conditioning Period. Prepare the
monitoring system for operation
according to the manufacturer's written
instructions. At the outset of the
conditioning period, zero and span the
system. Use the mid-level calibration
gas (or gas cell or filter) to set the span
at 50 percent of recorder full-scale. If
necessary to determine negative zero
drift, offset the scale by 10 percent. (Do
not forget to account for this when using
the calibration curve.) If a zero offset is
not possible or is impractical, a low-
level drift mav be substituted for the
zero drift, by using a low-level (5 to 15
percent of span value) calibration gas
(or gas cell or filter). This low-level
calibration gas (or gas cell or filter) need
not be certified. Operate the continuous
monitoring system for an initial 168-hour
period in the manner specified by the
manufacturer. Except during times of
instrument zero, calibration checks, and
system backpurges, the continuous
monitoring system shall collect and
condition the effluent gas sample (if
applicable), analyze the sample for the
appropriate gas constituents,-and
produce a permanent record of the
system output. Conduct daily zero and
mid-level calibration checks and, when
drift exceeds the daily operating limits,
make adjustments. The data recorder
shall reflect these checks and
adjustments. Keep a record of any
instrument failure during this time. If the
conditioning period is interrupted
because of source breakdown (record
the dates and times of process
shutdown), continue the 168-hour period
following resumption of source
operation. If the conditioning period is
interrupted because of monitor failure,
restart the 168-hour conditioning period
when the monitor becomes functional.
6.3 Operational Test Period. Operate
the continuous monitoring system for an
additional 168-hour period. The
continuous monitoring system shall
monitor the effluent, except during
periods when the system calibration and
response time are checked or during
system backpurges; however, the system
shaTT produce a permanent record of all
operations. Record any system failure
during this time on the data recorder
output sheet.
It is not necessary that the 168-hour
operational test period immediately
follow the 168-hour conditioning period.
During the operational test period,
perform the following test procedures:
6.3.1 Calibration Error
Determination. Make a total of 15
nonconsecutive zero, mid-level, and
high-level measurements (e g., zero, mid-
level, zero, high-level, mid-range, etc.).
V-Appendix B-17
-------
Federal Register / Vol. 44, No. 197 / Wednesday. October 10, 1979 / Proposed Rules
This will result in a set of 5 each of zero,
mid-level, and high-level measurements.
Convert the data output to concentration
units, if necessary, and record the
results on a data sheet (example is
shown in Figure 2-4). Calculate the
differences between the reference
calibration gas concentrations and the
measurement system reading. Then
calculate the mean, confidence interval,
and calibration errors separately for the
mid-level and high-level concentrations
using Equations 2-1, 2-2, and 2-3. In
Equation 2-3, use each respective
calibration gas concentration for R.V.
Figure 2-4. Calibration Error Determination
Run
no.
i1
T_
"V
4
5
! 6
I
j 7
' 8
9
10
11
12
13
14
15
Calibration gas
concentration3
PPtn_
A
Measurement system
reading
ppm
B
Arithmetic Mean (Eq. 2-1) »
Confidence Interval (Eq. 2-?) =
Calibration
Error (Eq. 2-3)D =
Arithmetic
differences
.ppm
A-B
Mid
High
a Calibration Data from Section 6.1.1 or 6.1.2
Mid-level: C = ppm
High-level: D - ppm
b Use C or D as R.V. 1n Eq. 2-3
Date
Figure 2-5. Response Time
High-level
Average
Upscale
min.
Downscale
min.
..PPm
B =
System Response Time (slower of A and B)
min.
V-Appendix B-18
-------
Federal Register / Vol. 44, No. 197 / Wednesday, October 10, 1979 / Proposed Rules 58621
6.3.2 Response Time Test Procedure.
At a minimum, each response time test
shall provide a check of the entire
sample transport line (if applicable), any
sample conditioning equipment (if
applicable), the pollutant analyzer, and
the data recorder. For in-situ systems,
perform the response time check by
introducing the calibration gases at the
sample interface (if applicable), or by
introducing the calibration gas cells or
filters at an appropriate location in the
pollutant analyzer. For extractive
monitors, introduce the calibration gas
at the sample probe inlet in the stack or
at the point of connection between the
rigid sample probe and the sample
transport line. If an extractive analyzer
is used to monitor the effluent from more
than one source, perform the response
time test for each sample interface.
To begin the response time test,
introduce zero gas (or zero cell or filter)
into the continuous monitor. When the
system output has stabilized, switch to
monitor the stack effluent and wait until
a "stable value" has been reached.
Record the upscale response time. Then,
introduce the high-level calibration gas
(or gas cell or filter). Once the system
has stabilized at the high-level
concentration, switch to monitor the
stack effluent and wait until a "stable
value" is reached. Record the downscale
response time. A "stable value" is
equivalent to a change of less than 1
percent of span value for 30 seconds or 5
percent of measured average
concentration for 2 minutes. Repeat the
entire procedure three times. Record the
results of each test on a data sheet
(example is shown in Figure 2-5).
Determine the means of the upscale and
downscale response times using
Equation 2-1. Report the slower time as
the system response time.
6.3.3 Field Test for Zero Drift and
Calibration Drift. Perform the zero and
calibration drift tests for each pollutant
analyzer and data recorder in the
continuous monitoring system.
6.3.3.1 Two-hour Drift. Introduce
consecutively zero gas (or zero cell or
filter) and high-level calibration gas (or
gas cell or filter) at 2-hour intervals until
15 sets (before and after) of data are
obtained. Do not make any zero or
calibration adjustments during this time
unless otherwise prescribed by the
manufacturer. Determine and record the
amount that the output had drifted from
the recorder zero and high-level value
on a data sheet (example is shown in
Figure 2-6). The 2-hour periods over
which the measurements are conducted
need not be consecutive, but must not
overlap. Calculate the zero and
calibration drifts for each set. Then
calculate the mean, confidence interval,
and zero and calibration drifts (2-hour)
using Equations 2-1, 2-2, and 2-3. In
Equation 2-3, use the span value for R.V.
6.3.3.2 Twenty-Four Hour Drift. In
addition to the 2-hour drift tests, perform
a series of seven 24-hour drift tests as
follows: At the beginning of each 24-
hour period, calibrate the monitor, using
mid-level value. Then introduce the
high-level calibration gas (or gas cell or
filter) to obtain the initial reference
value. At the end of the 24-hour period,
introduce consecutively zero gas (or gas
cell or filter) and high-level calibration
gas (or gas cell or filter); do not make
any adjustments at this time. Determine
and record the amount of drift from the
recorder zero and high-level value on a
data sheet (example is shown in Figure
2-7). Calculate the zero and calibration
drifts for each set. Then calculate the
mean, confidence interval, and zero and
calibration drifts (24-hour) using
Equations 2-1, 2-2, and 2-3. In Equation
2-3, use the span value for R.V.
V-Appendix B-19
-------
Federal Register / Vol. 44, No. 197 / Wednesday, October 10,1979 / Proposed Rules
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V-Appendix B-20
-------
Federal Register / Vol. 44, No. 197 / Wednesday, October 10, 1979 / Proposed Rules
Note.Automatic zero and calibration
adjustment? made by the monitoring system
without operator intervention or initiation are
allowable a! any time Manual adjustments,
however, are allowable only at 24-hour
intervals, unless a shorter time is specified by
the manufacturer
6.4 System Relative Accuracy.
Unless otherwise specified in an
applicable subpart of the regulations,
the reference methods for SO2, NO,,
diluent (O2 or CO2), and moisture are
Reference Methods 6, 7, 3, and 4,
respectively. Moisture may be
determined along with SO2 using
Method 6. See Citation 10.8. Reference
Method 4 is necessary only if moisture
content is needed to enable comparison
between the Reference Method and
monitor values Perform the accuracy
test using the following guidelines:
641 Location of Pollutant Reference
Method Sample Points. The following
specifies the location of the Reference
Method sample points which are on the
same cross-sectional plane as the
monitor's. However, any cross-sectional
plane within 2 equivalent diameter of
straight runs may be used, by using the
projected image of the monitor on the
selected plane in the following criteria.
6 4.1.1 For point monitors, locate the
Reference Method sample point no
further than 30 cm (or 5 percent of the
equivalent diameter of the cross section,
whichever is less) from the pollutant
monitor sample point.
641.2 For multipoint monitors
locate each Reference Method sample
traverse point no further than 30 cm (or
5 percent of the equivalent diameter of
the cross section, whichever is less)
from each corresponding pollutant
monitor sample point.
64.1.3 For limited-path and path
monitors, locate 3 sample points on a
line parallel to the monitor path and no
further than 30 cm (or 5 percent of the
equi\alent diameter of the cross section,
whichever is less) from the centerlme of
the monitor path The three points of the
Reference Method shall correspond to
points in the monitor path at 16.7, 50 0,
and 83 3 percent of the effective length
of the monitor path
642 Location of Diluent and
Moisture Reference Method Sample
Pomls.
6421 For sources which require
diluent monitors in addition to pollutant
monitors, locate each of the sample
points for the diluent Reference Method
measurements within 3 cm of the
corresponding pollutant Reference
Method sample point as defined in
Sections 64.1.1. 6.4.1.2. or 6.4.1.3. In
addition, locate each pair of diluent and
pollutant Reference Method sample
points no further than 30 cm (or 5
percent of the equivalent diameter of the
cross secticr,, whichever is less) from
both the diluent and pollutant
continuous monitor sample points or
paths
6 4.2.2 If it is necessary to convert
pollutant and/or diluent monitor
concentrations to a dry basis for
comparison with the Reference data,
locate each moisture Reference Method
sample point within 3 cm of the
corresponding pollutant or diluent
Reference Method sarrlple point as
defined in Sections 6.4.1.1, 6.4.1.2, 6.4.1.3,
or 6 4 2.1.
6.4 3 Number of Reference Method
Tests.
6.4.3.1 For NO, monitors, make a
minimum of 27 NO, Reference Method
measurements, divided into 9 sets.
6.4.3.2 For SO2 monitors, make a
minimum of 9 SO2 Reference Method
tests.
6.4.3.3 For diluent monitors, perform
one diluent Reference Method test for
each SO2 and/or NO, Reference Method
test(s).
6 4.3.4 For moisture determinations,
perform one moisture Reference Method
test for each or each set of pollutant(s)
and diluent (if applicable) Reference
Method tests.
Note.The tester may choose to perform
more than 9 sets of NO, measurements or
more than 9 Sd reference method diluent, or
moisture tests If this option is chosen, the
tester ma>, at his discretion, reject up to 3 of
'the set or test results, so long as the total
number of set or test results used to
determine the relative accuracy is greater
than or equal to 9 Report all data including
rejected data.
6.4.4 Sampling Strategy for
Reference Method Tests. Schedule the
Reference Method tests so that they will
not be in progress when zero drift.
calibration drift, and response time data
are being taken, Within any 1-hour
period, conduct the following tests: (a)
one set, consisting of 3 individual
measurements, of NO, and/or one SO2;
(b) one diluent, if applicable; and (c) one
moisture (if needed). Whenever two or
more reference tests (pollutant, diluent,
and moisture) are conducted, the tester
may choose to run all these reference
tests within a 1-hour period. However, it
is recommended that the tests be run
concurrently or consecutively within a
4-minute interval if two reference tests
employ grab sampling techniques. Also
whenever an integrated reference test is
run together with grab sample reference
tests, it is recommended that the
integrated sample be started one-sixth
the test period before the first grab
sample is collected.
In order to properly correlate the
continuous monitoring system and
Reference Method data, mark the
beginning and end of each Reference
Method test period (including the exact
time of day) on the pollutant and diluent
(if applicable) chart recordings Use one
of the following strategies for the
Reference Method tests:
6.4.4.1 Single Point Monitors For
single point sampling, the tester may (a)
take a 21-minute integrated sample (e.g.
Method 6, Method 4, or the integrated
bag sample technique of Method 3); (b)
take 3 grab samples (e.g. Method 7 or
the grab sample technique of Method 3),
equally spaced at 7-minute (±2 min)
intervals (or one-third the test period);
or (c) take 3 grab samples over a 3-
minute test period.
6.442 Multipoint or Path Monitors.
For multipoint sampling, the tester may
either: (a) make a 21-mmute integrated
sample traverse, sampling for 7 minutes
(±2 min) (or one-third the test period) at
each point; or (b) take grab samples at
each traverse point, scheduling the grab
samples to that they are an equal
interval (7±2 minutes) of time apart (or
one-third the test period).
Note.If the number of sample points is
greater than 3, make appropriate adjustments
to the induidudl sampling time intervals At
times NSPS performance test data may be
used as part of the data base of the
continuous monitoring relative accuracy
tests In these cases, other test periods as
specified in the applicable subparts of the
regulations may be uspd
6.4.5 Correlation of Reference
Method and Continuous Monitoring
System Data. Correlate the continuous
monitoring system data with the
Reference Method test data, as to the
time and duration of the Reference
Method tests. To accomplish this, first
determine from the continuous
monitoring system chart recordings, the
integrated average pollutant and diluent
(if applicable) concentration(s) for each
Reference Method test period. Be sure to
consider system response time. Then,
compare each integrated average
concentration against the corresponding
average concentration obtained by the
Reference Method, use the following
guidelines to make these comparisons-
6.4.5.1 If the Reference Method is an
integrated sampling technique (e g ,
Method 6), make a direct comparison of
the Reference Method results and the
continuous monitoring system integrated
average concentration.
6452 If the Reference Method is a
grab-sampling technique (e.g.. Method
7), first average the results from all grab-
samples taken during the test period,
and then compare this average value
against the integrated value obtained
from the continuous monitoring system
chart recording.
V-Appendix B-21
-------
Federal Register / Vol. 44. No. 197 / Wednesday, October 10, 1979 / Proposed Rules
6.5 Data Summary for Relative
Accuracy Tests. Summarize the results
on a data sheet; example is shown in
figure 2-8. Calculate the arithmetic
differences between the reference
method and the continuous monitoring
output sets. Then calculate the mean,
confidence interval, and system relative
accuracy, using Equation 2-1, 2-2, and
2-3. In Equation 2-3, use the average of
the reference method test results for
R.V.
7. Equations
7.1 Arithmetic Mean. Calculate the
mean of a data set as follows:
-"I
Equation 1-2
Where:
x = arithmetic mean.
n = number of data points.
2x, = algebraic sum of the individual
values, x,.
When the mean of the differences of
pairs of data is calculated, be sure to
correct the data for moisture.
7.2 Confidence Interval. Calculate
the 95 percent confidence interval (two-
sided) as follows:
C.I.95 - -^ /HEX z - O )2 Equation 1-3
*
Where:
C.I.w = 95 percent confidence interval
estimate of mean value.
t tr. = t(,-./,) (see Table 2-2)
BILLING CODE 8S8O-01-M
Table 2-2.1= Values
rf '975 rf '975 n" '
2
3
4
5
6
12706
4303
3 182
2776
2571
7
e
9
10
11
2447
2365
2306
2262
2228
12
13
14
15
16
220t
2179
2160
2145
2131
' The values in this table are already corrected for n-1 de-
grees of freedom Use n equal to the number of ndwdual
values
V-Appendix B-22
-------
Federal Register / Vol. 44, No. 197 / Wednesday, October 10, 1979 / Proposed Rules
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-------
Federal Register / Vol. 44. No. 197 / Wednesday, October 10. 1979 / Proposed Rules
7.3 Relative Accuracy. Calculate the relative accuracy of a set of data as
follows:
R.A.
Where:
R. A.
1*1
|C.I.
R.V.
95'
« relative accuracy
«= absolute value^pf the arithmetic ««an
(from Equation 2-1).
- absolute value of the 95 percent confi-
dence Interval (from Equation 2-2).
* reference value, as defined in Sections
6.3.1, 6.3.3.1, 6.3.3.2, and 6.5.
8. Reporting _
At a minimum (check with regional
offices for additional requirements, if
any) summarize the following results in
tabular form: calibration error for mid-
level and high-level concentrations, the
slower of the upscale and downscale
response times, the 2-hour and 24-hour
zero and calibration drifts, and the
system relative accuracy. In addition.
provide, for the conditioning and
operational test periods, a statement to
the effect that the continuous monitoring
system operated continuously fjr a
minimum of 168 hours each, except
during times of instrument zero,
calibration checks, system backpurges,
and source breakdown, and that no
corrective maintenance, repair,
replacement, or adjustment other than
that clearly specified as routine and
required in the operation and
maintenance manuals were made. Also
include the manufacturer's certification
statement (if applicable) for the
calibration gas. gas cells, or filters.
Include all data sheets and calculations
and charts (data outputs), which are
necessary to substantiate that the
system met the performance
specifications.
9. Retest
If the continuous monitoring system
operates within the specified
performance parameters of Table 2-1.
the operational test period will be
successfully concluded. If the
continuous monitoring system fails to
meet any of the specifications, repeat
that portion of the testing which is
related to the failed specification.
10. Bibliography
10.1 "Monitoring Instrumentation for
the Measurement of Sulfur Dioxide in
Stationary Source Emissions,"
Environmental Protection Agency,
Research Triangle Park, N.C., February
1973.
10.2 "Instrumentation for the
Determination of Nitrogen Oxides
Content of Stationary Source
Emissions," Environmental Protection
Agency, Research Triangle Park, N.C.,
Volume 1, APTD-0847, October 1971;
Volume 2, APTD-0942, January 1972.
10.3 "Experimental Statistics,"
Department of Commerce, Handbook 91,
1963, pp. 3-31, paragraphs 3-3.1.4.
10.4 "Performance Specifications for
Stationary-Source Monitoring Systems
for Gases and Visible Emissions,"
Environmental Protection Agency,
Research Triangle Park, N.C., EPA-650/
2-74-013, January 1974.
10.5 Traceability Protocol for
Establishing True Concentrations of
Gases Used for Calibration and Audits
of Continuous Source Emission Monitors
(Protocol No. 1). June 15,1978.
Environmental Monitoring and Support
Laboratory; Dffice of Research and
Development, U.S. EPA, Research
Triangle Park, N.C. 27711.
10.6 Westlm. P. R. and J. W. Brown.
Methods for Collecting and Analyzing
Gas Cylinder Samples. Emission
Measurement Branch, Emission
Standards and Engineering Division,
Office of Air Quality Planning and
Standards, U.S. EPA, Research Triangle
Park. N.C.. July 1978.
10.7 Curtis. Foston. A Method for
Analyzing NOX Cylinder Gases
Specific Ion Electrode Procedure.
Emission Measurement Branch,
Emission Standards and Engineering
Division, Office of Air Quality and
Standards, U.S. EPA, Research Triangle
Park. N.C.. October 1978.
10.8 Stanley, Jon and P. R. Westlin.
An Alternative Method for Stack Gas
Moisture Determination. Emission
Measurement Branch, Emission
Standards and Engineering Division,
Office of Air Quality Planning and
Standards, U.S. EPA, Research Triangle
Park, N.C., August 1978.
Performance Specification 3
Specifications and Test Procedures for
COi and O, Continuous Monitors in
Stationary Sources
1. Applicability and Principle
1.1 Applicability. This Specification
contains (a) installation requirements,
(b) instrument performance and
equipment specifications, and (c) test
procedures and data reduction
procedures for evaluating the
acceptability of continuous CO2 and O»
monitors that are used as diluent
monitors. The test procedures are
primarily designed for systems that
introduce calibration gases directly into
the analyzer; other types of monitors
(e.g.. single-pass monitors, as described
in Section 2.2.7 of Performance
Specification 2 of this Appendix) will be
evaluated on a case-by-case basis upon
written request to the Administrator,
and alternative procedures will be
issued separately.
1.2 Principle. Any COi or O,
continuous monitor, which is expected
to meet this Specification, is operated
for a specified length of time. During this
specified time period, the continuous
monitor is evaluated to determine
conformance with the Specification.
2. Definitions
The definitions are the same as those
listed in Section 2 of Performance
Specification 2.
3. Installation Specifications
3.1 Measurement Location and
Measurement Points or Paths. Select and
install the continuous monitor at the
same sampling location used for the
pollutant monitor(s). Locate the
measurement points or paths as shown
in Figure 3-1 or 3-2.
3.2 Alternative Measurement
Location and Measurement Points or
Paths The diluent monitor may be
V-Appendix B-24
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Federal Register / Vol. 44, No. 197 / Wednesday, October 10, 1979 / Proposed Rules
installed at a different location from that
of the pollutant monitor, provided that
the diluent gas concentrations at both
locations differ by no more than 5
percent from that of the pollutant
monitor location for CO2 or the quantity,
20.9-percent O2, for O,. See Section 3.4
of Performance Specification 2 for the
demonstration procedure.
4. Continuous Monitor Performance and
Equipment Specifications
The continuous monitor performance
and equipment specifications are listed
in Table 3-1. To be considered
acceptable, the continuous monitor must
demonstrate compliance with these
specifications, using the test procedures
in Section 6.
5. Apparatus
5.1 CO2 or Oa Continuous Monitor.
Use any continuous monitor, which is
expected to meet this Specification. The
data recorder may either be an analog
strip-chart recorder or other suitable
device having an input voltage range
compatible with the analyzer output.
5.2 Calibration Gases. Diluent gases
shall be air or N2 for CO2 mixtures, and
shall be N2 for O2 mixtures. Use three
calibration gases as specified below
GEOMETRICALLY
SIMILAR
AREA
(<1%OF STACK
CROSS-SECTION)
(a)
GEOMETRICALLY
SIMILAR
AREA
( «t1%OF STACK
CROSS-SECTION)
(b)
Figure 3-1. Relative locations of pollutant (P) and diluent (D) measurement points in (a) circular
and (b) rectangular ducts. P is located at the centroid of the geometrically similar
area. Note: The geometrically similar area need not be concentric.
V-Appendix B-25
-------
Federal Register / Vol. 44. No. 197 / Wednesday, October 10,1979 / Proposed Rules
PARALLEL
MEASUREMENT
LINES
GEOMETRICALLY
SIMILAR
AREAS
( <1%OF STACK
CROSS-SECTION)
GEOMETRICALLY
SIMILAR
AREAS
( <1%OF STACK
CROSS-SECTION)
(a)
PARALLEL
MEASUREMENT
LINES
(b)
Figure 3-2. Relative locations of pollutant (P) and diluent (D) measurement paths for (a) circular
and (b) rectangular ducts. P is located at the centroid of both the geometrically simi
lar areas and the pollutant monitor path cross-sectional areas. D is located at the cen-
troid of the diluent monitor path cross-sectional area.
V-Appendix B-26
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Federal Register / Vol. 44, No. 197 / Wednesday, October 10, 1979 / Proposed Rules
Table 3-1.Performance and Equipment
Specifications
Parameter
Specification
1 Conditioning
period'
t Operational test \
penodv
1. Calibration error'...
4 ReponsetJme
f Zero dntt 12-
hour)"
6 Zero dntl (24-
hour)".
7 Calibration drift 12-
hour)».
t Calibration dntl
(24-hour) >.
Data recorder chart
mokitlon
10 Extractive monitors
» 168 hours
f 168 hours
C 5 pel of each (mid-range and
high-range, only) calibration ga»
value
« 15 minutes
* 0 4 pet CO, or 0,
< 10 5 pet CO, or O,
« 0 4 pet CO, or O,
« 0 5 pet CO, or O,
Chart scales must be readable to
within « 0 50 pet of M-scale
Must use the same interface as the
pollutant monitor Place m a series
(diluent after pollutant analyzer) or
use a "T"
Ounng the conditioning and operational test periods, the
contnuous monitor Shan not require any corrective mainte-
nance, repair, replacement, or adjustment other than thai
etearty specified as routine and required m the operation and
maintenance manuals.
* Expressed as the sum of the absolute mean value plus
(M 95 percent confidence interval of a series of tests
A low-level (5-)5 percent of span value) drift tests may b*
utxtrtuled for the zero dntt tests
B.2.1 High-Level Gas. A CO, or O,
concentration of 20.0 to 22.5 percent. For
Oi analyzers, ambient air (20.9 percent
Oi) may be used as the high-range
calibration gas; lower high-level O*
concentration may be used, subject to
the approval of the Administrator.
6.2.2 Mid-Level Gas. A CO, or O,
concentration of 11.0 to 14.0 percent; for
Oi analyzers, concentrations in the
operational range may be used.
5.2.3 Zero Gas. A CO, or Ot
concentration of less than 0.05 percent.
For CO, monitors, ambient air (0.03
percent CO2) may be used as the zero
gas.
8. Performance Specification Test
Procedures.
6.1 Calibration Gas Certification.
Follow the procedure as outlined in
Section 6.1.2 of Performance
Specification 2, except use 0.5 percent
CO, or O, instead of the 15 ppm. Figure
3-3 is provided as an example data
sheet.
6.2 Conditioning Period. Follow the
same procedure outlined in Section 6.2
of Performance Specification 2.
6.3 Operational Test Period. Follow
the same procedures outlined in Section
6.3 of Performance Specification 2, to
evaluate the calibration error, response
time, and the 2-hour and 24-hour zero
and calibration drifts. See example data
sheets (Figures 3-4 through 3-7).
6.4 System Relative Accuracy. (Note:
The relative accuracy is not determined
separately for the diluent monitor, but is
determined for the pollutant-diluent
system.) Unless otherwise specified in'
an applicable subpart of the regulations,
the Reference Methods for the diluent
concentration determination shall be
Reference Method 3 for CO2 or Oa. For
this test, Fyrite analyses may be used
for CO, and O, determinations. Perform
the measurements using the guidelines
below (an example data sheet is shown
in Figure 2-8 of Performance
Specification 2):
6.4.1 Location of Reference Method 3
Sampling Points. Locate the diluent
Reference Method sampling points
according to the guidelines given in
Section 6.4.2.1 of Performance
Specification 2.
6.4.2 Number of Reference Method
Tests. Perform one Reference Method 3
test according to the guideline in
Performance Specification 2.
6.4.3 Sampling Strategy for
Reference Method Tests. Use the basic
Reference Method sampling strategy
outlined in Section 6.4.4 (and related
sub-sections) of Performance
Specification 2.
6.4.4 Correlation of Reference
Method and Continuous Monitor Data.
Use the guidelines given in Section 6.4.5
of Performance Specification 2.
7. Equations, Reporting, Retest, and
Bibliography. The procedure and
citations are the same as in Sections 7
through 10 of Performance Specification
2.
|FR Doc 79-31033 Filed 10-9-79 8 45 am]
V-Appendix B-27
-------
Date
Federal Register / Vol. 44, No. 197 / Wednesday, October 10,1979 / Proposed Rules
Figure 3-3. Analysis of Calibration Gases*
(Must be within 2 weeks prior to the opera-
tional test period)
Reference Method Used
Sample run
Average
Maximum %
deviation£
Mid-range0
ppm
High-range
ppm
a Not necessary 1f the protocol in Citation 10.5 of Perfor-
mance Specification 2 is used to prepare the gas cylinders.
c Average must be 11.0 to 14.0 percent; for 09, see Section
5.2.2. e-
Average must be 20.0 to 22.5 percent; for 09, see Section
5.2.1. '
e Must be ^ + 10 percent of applicable average or 0.5 percent,
whichever Ts greater.
V-Appendix B-28
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Federal Register / Vol. 44, No. 197 / Wednesday. October 10.1979 / Proposed Rules
Figure 3-4. Calibration Error Determination
Run
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
Calibration Gas
Concentration8
ppm
A
Measurement System
Reading
ppm
B
Arithmetic Mean (Eq. 2-1 )b *
Confidence Interval (Eq. 2-2) =
Calibration Error (Eq. 2-3)b)C =
Arithmetic
D1 f f erences
pom
A-B
Mid
High
Calibration Data from Section 6.1
Mid-level: C = ppm
High-level: D = ppm
See Performance Specification 2
c Use C or D as R. V.
V-Appendix B-29
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Federal Register / Vol. 44. No. 197 / Wednesday. October 10,1979 / Proposed Rules
Figure 3-5. -Response Time
Date
High-Range =
ppm
Test Run
1
2
3
Average
Upscale
min
A =
Downscale
min
B =
System Response Time (slower of A and B) =
mm.
V-Appendix B-30
-------
Federal Register / Vol. 44. No. 197 / Wednesday, October 10,1979 / Proposed Rules
Data
set
no
Date
Time
Begin
End
Zero Rd.
Init.
A
Fin.
B
Arithmetic Mean (Eq. 2-l)a
Confidence Interval (Eq. 2-2)a
Zero drift
Zero
drift
C=B-A
Hi -Range
Rdq.
Init.
D
Fin.
E
Span
drift
F=E-D
Calibration driftb
Calib.
drift
G=F-C
From Performance Specification 2.
Use Equation 2-3 of Performance Specification 2 and 1.0 for R. V,
Figure 3-6. Zero and Calibration Drift (2 hour)
V-Appendix B-31
-------
Federal Register / Vol. 44. No. 197 / Wednesday, October 10.1979 / Proposed Rules
Data
set
no.
Date
Time
Begin
End
Zero Rdg
Init.
A
Fin.
B
Arithmetic Mean (Eq. 2-l)a
Confidence Interval (Eq. 2-2)a
Zero drift b
Zero
drift
C=BW\
Hi -Range
Rdq
Init.
D
Fin.
E
Span
drift
F=E-D
Calibration drift b
Calib.
drift
G=F-C
From Performance Specification 2.
Use Equation 2-3 of Performance Specification 2, with 1.0 for R. V.
Figure 3-7. Zero and Calibration Drift (24-hour)
V-Appendix B-32
-------
Federal Register / Vol. 44, No. 246 / Thursday, December 20, 1979 / Proposed Rules
40 CFR Part 60
[FRL 1378-3]
Standards of Performance for New
Stationary Sources Continuous
Monitoring Performance
Specifications; Extension of Comment
Period
AGENCY: Environmental Protection
Agency (EPA).
ACTION-. Extension of Comment Period.
SUMMARY: The deadline for submittal of
comment on the proposed revisions to
the continuous monitoring performance
specifications, which were proposed on
October 10,1S79 (44 FR 58G02), is being
extended from December 10,1979, to
February 11,1930.
DATES: Written comments and
information must be received on or
before February 11,1980.
ADDRESSES: Comments. Written
comments and information should be
submitted (in duplicate, if possible) to:
Central Docket Section (A-130),
Attention: Docket Number OAQPS-79-
4, U.S. Environmental Protection
Agency, 401 M Street, S.W.,
Washington, D.C. 204CO.
Docket. Docket Number OAQPS-79-4,
containing material relevant to this
rulemaking, is located in the U.S.
Environmental Protection Agency
Central Docket Section, Room 2903B, 401
M Street, S.W., Washington, D.C. 20460.
The docket may be inspected between
8:00 a.m. and 4:00 p.m. on weekdays,
and a reasonable fee may be charged for
copying.
FOR fljf. rKEH INFORMATION CONTACT:
Mr. Don R. Goodwin (MD-13), U.S.
Environmental Protection Agency,
Research Tiiangle Park, N.C. 27711;
telephone (919) 541-5271.
SUPPLEMENTARY INFORMATION: On
October 10,1979 (44 FR 58602), the
Environmental Protection Agency
proposed revisions to the Continuous
Monitoring Performance Specifications
1, 2, and 3. The notice of proposal
requested public comments on the
standards by December 10,1979. Due to
delay in the shipping of copies of the
performance specifications publication,
a sufficient number of copies have been
unavailable for distribution to all
interested parties in time to allow their
meaningful review and comment by
December 10,1979. An extension of this
period is justified as this delay has
resulted in about a 5-week delay in
processing requests for the document.
Dated: December 12,1979.
Edward F. Tuerk,
Acting Assistant Administrator for Air, Noise,
and Radiation.
[FR Doc 7»-39002 Filed 12-19-79, B 45 am]
V-Appendix B-33
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Federal Register / Vol. 45. No. 35 / Wednesday. February 20, 1980 / Proposed Rules
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Part 60
[FRL 1389-2}
Standards of Performance for New
Stationary Sources Continuous
Monitoring Performance
Specifications
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Advance notice of proposed
rulemaking.
SUMMARY: This notice sets forth draft
Performance Specification 4
Specifications and Test Procedures for
Carbon Monoxide Continuous
Monitoring Systems in Stationary
Sources, which EPA is considering to
propose as an addition to Appendix B of
40 CFR Part 60. The intent of this
advance notice is to solicit comments on
the specifications and testing
procedures EPA is considering
This advance notice of proposed
rulemaking is issued under the authority
of Sections 111, 114, and 301(a) of the
Clean Air Act as amended (42 U.S.C
7411, 7414, and 7601(a)).
DATES: Written comments and
information should be post-marked on
or before May 20,1980.
ADDRESSES: Comments. Written
comments and information should be
submitted (in duplicate, if possible) to-
Central Docket Section (A-130),
Attention: Docket Number A-79-03, U.S.
Environmental Protection Agency, 401 M
Street, SW., Washington, D.C. 20460
Docket. Docket Number A-7.9-03.
containing material relevant to this
rulemaking, is located in the U.S.
Environmental Protection Agency
Central Docket Section, Room 2903B, 401
M Street, SW., Washington, D.C. 20460
The docket may be inspected between
8:00 a.m. and 4:00 p.m. on weekdays,
and a reasonable fee may be charged for"
copying.
FOR FURTHER INFORMATION CONTACT:
Mr. Don Goodwin (MD-13), U.S
Environmental Protection Agency.
Research Triangle Park, N.C. 27711.
telephone (919) 541-5271.
SUPPLEMENTARY INFORMATION: EPA
promulgated standards of performance
for new stationary sources pursuant to
Section 111 of the Clean Air Act, as
amended, on March 8,1974 (39 FR 9308)
for petroleum refineries and six other
stationary sources. New or modified
sources in these categories are required
to demonstrate compliance with the
standards of performance by means of
performance tests that are conducted at
the rime a new source commences
operation orshortly thereafter. To
ensure that these sources are properly
operated and maintained so as to
remain in compliance, provisions were
included in the standards that esquire
sources to install and operate a
continuous emission monitoring system.
One such requirement was for carbon
monoxide (CO) from petroleum
refineries.
When the standards were initially
proposed, EPA had limited knowledge
about the operation of continuous
monitors on such sources; thus, the
continuous emission monitoring
requirements were specified in general
terms. Additional guidance on the
selection and use of such instruments
was to be provided at a later date-
On October 6,1975 (40 FR 46259), the
Environmental Protection. Agency
amended Part 60 of the regulations by
adding Appendix BPerformance
Specifications 1, 2, and 3 for continuous
monitoring of (1) opacity, (2) sulfur
dioxide and nitrogen oxide, and (3)
oxygen or carbon dioxide, respectively
Performance specifications for CO
monitors were not published at that
time.
EPA has conducted short-term
evaluations of the applicability of
several continuous monitoring
instruments and has published the
results in the following documents:
Guidelines for Development of a Quality
Assurance program: Volume VUI
Determination of CO Emissions from
Stationary Sources by NDIR
Spectrometry, EPA-650/4-74-OQ5-h
(February 1975); and Evaluation of
Continuous Monitors for Carbon
Monoxide in Stationary Sources. EPA-
600/2-77-063) March 1977). Both are
available through the National
Technical Information Service,
Springfield, Virginia 22161.
Based on the above documents,
specifications and test procedures were
drafted for continuous CO monitoring-
instruments, the format of the draft
Performance Specification 4 follows
closely that of the most recent proposed
revisions to Performance Specification 2
(44 FR 58602 dated Oct. 10,1979).
Several references are made in
Performance Specification 4 to>specific
sections of the Performance
Specification 2 revisions.
The Environmental Monitoring and
Support Laboratory of EPA is adso
presently conducting a laboratory and
long-term field study of CO continuous
monitoring systems. Results of this
study will provide essential background
and technical information in support of
or improvement to Performance
Specification 4. The completion date is
scheduled for mid-1981. For this reason.
Performance Specification 4 for CO is
published as an advance notice.
Specific Requests
EPA is requesting comments on the
attached draft Performance
Specification 4Specifications and Test
Procedures for CO Monitoring Systems
in Stationary Sources. EPA is interested
in comments on alternatives to the
performance specifications and is
particularly interested in information
that could lead to the development of
improved or alternative procedures. EPA
is also interested in comments on the
following aspects of CO continuous
monitoring and Performance
Specification 4: (1) Estimates of
installation and operation costs
including equipment costs, manpower
requirements, data reduction options,
and maintenance costs, (2) procedures
applicable for the evaluation of single-
pass, in-situ monitoring system; (3)
laboratory testing procedures that are
necessary for determining monitoring
system performance acceptability and
those laboratory tests that can be
recommended as indications of the
quality of equipment operation; (4) the
specifications and limits set forth in
Section 4; (5) the applicability of
Reference Method 10 or other methods
for determining relative accuracy of
continuous CO monitoring systems
Dated: February 12,1980.
Barbara Blum,
Acting Administrator.
Performance Specification 4
Specifications and Test Procedures for
Carbon Monoxide Continuous
Monitoring Systems in Stationary
Sources
I. Applicability and Principle
1.1 Applicability. This specification
contains (a) installation requirements.
(b) instrument performance and
equipment specifications, and (c) test
procedures and data reduction
procedures for evaluating the
acceptability of carbon monoxide (CO)
continuous monitoring systems. The test
procedures are not applicable to single-
pass, in-situ monitoring systems; these
systems will be evaluated on a case-by-
case basis upon application to the
Administrator, and alternative
procedures will be issued separately
1.2 Principle. A CO continuous
monitoring system that is expected to
meet this specification is installed,
calibrated, and operated for a specified
length of time. During the specified time
period, the continuous monitoring
V-Appendix B-34
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Federal Register / Vol. 45, No. 35 / Wednesday, February 20, 1980 / Proposed Rules
system is evaluated to determine
conformance with the specification.
2. Definitions
The definitions are the same as those
listed in Section 2 of Performance
Specification 2.
3. Installation Specifications
Install the continuous monitoring
system at a location where the pollutant
concentration-measurements are
representative of the total emissions
from the affected facility. Use a point,
points, or a path that represents the
average concentration over the cross
section. Both requirements can be met
as follows:
3.1 Measurement Location. Select an
accessible measurement location in the
stack or ductwork that is at least two (2)
equivalent diameters downstream from
the nearest CO control device or other
point at which a change in the pollutant
concentration may occur and at least 0.5
equivalent diameter upstream from the
exhaust. Individual subparts of the
regulations may contain additional
requirements.
3.2 Measurement Points»or Paths.
The tester may choose to use the
following measurement point, points, or
path without a stratification check or he
may choose to conduct the stratification
check procedure given in Section 3.3 of
Performance Specification 2 to select the
point, points, or path of average gas
concentration.
3.2.1 CO Path Monitoring Systems.
Same as in Performance Specification 2,
Section 3.2.2.
3.2.3 Single-Point and Limited-Path
Monitoring Systems. Same as in
Performance Specification 2, Section
3.2.3.
4. Performance and Equipment
Specifications
The continuous monitoring system
performance and equipment
specifications are listed in Table 4-1. To
be considered acceptable, the
continuous monitoring system must
demonstrate compliance with these
specifications using the test procedures
of Section 6.
5. Apparatus
5.1 Continuous Monitoring System.
Use any continuous monitoring system
for CO, which is expected to meet the
specifications in Table 4-1. The data
recorder may be an analog strip-chart
recorder or other suitable device with an
input signal range compatible with the
analyzer output.
Table 4-1.Continuous Monitoring System
Performance and Equipment Specifications
Parameter
Specrfication
1 Conditioning period
2 Operational test
period1.
3, Calibration error'
4 Response time
5 Zero drift, 2 hours ....
6 Zero dnrt. 24 hours ..
7 Calibration drift, 2
hours'
8 Calibration drift, 24
hours'
9 Relative accuracy'
10 Calibration gas cells
or filters.
11 Data recorder chart
resolution.
> 168 hours.
? 168 hours
< 5 percent of each mid-level and
high-level calibration value
< 10 minutes.
Z_ 1 percent of span value.
< 2 percent of span varue
< 2 percent of span value.
525 percent of span value.
< 10 percent of Mean Ref value.
Must provide a check of all ana-
lyzer internal mirrors and lenses,
and all electronic circuitry in-
cluding the radiation source and
detector assembly, which are
normally used in sampling and
analysis.
Chart scales must be readable to
within ± 0.5 percent of full-
scale
' During the conditioning and operational test periods, the
continuous monitoring system shall not require any corrective
maintenance, replacement, or adjustment other than that
clearly specified as routine and required in the operation and
maintenance manuals
* Expressed as sum of absolute mean value plus 95 per-
cent confidence interval of a series tests divided by a refer-
ence value
5.2 Calibration Gases. For
continuous monitoring systems that
allow the introduction of calibration
gases to the analyzer, the calibration
gases must be CO in N». Use three
calibration gas mixtures as specified
below;
5.2.1 High-Level Gas. A gas
concentration that is equivalent to 80 to
90 percent of the span value.
5.2.2 Mid-Level Gas. A gas
concentration that is equivalent to 45 to
55 percent of the span value.
5.2.3 Zero Gas. A gas concentration
of less than 0.25 percent of the span
value. Prepurified nitrogen should be
used.
5.3 Calibration Gas Cells or Filters.
For continuous monitoring systems
which use calibration gas cells or filters,
use three certified calibration gas cells
or filters as specified below:
5.3.1 High-Level Gas Cell or Filter.
One that produces an output equivalent
to 80 to 90 percent of the span value.
5.3.2 Mid-Level Gas Cell or Filter.
One that produces an output equivalent
to 45 to 55 percent of the span value.
5.3.3 Zero Gas Cell or Filter. One
that produces an output equivalent to
zero. Alternatively, an analyser may
produce a zero value check by
mechanical means, such as a movable
mirror.
6. Performance Specification Test
Procedures
6.1 Pretest Preparation.
6.1.1 Calibration Gas Analyses. Use
calibration gas prepared according to
the protocol defined in Reference 10.2.
6.1.2 Calibration Gas Cell or Filter
Certification. Obtain from the
manufacturer a statement certifying that
the calibration gas cells or filters (zero,
mid-level, and high-level) will produce
the stated instrument response for the
continuous monitoring system, and a
description delineating the test
procedure and equipment used to
calibrate the cells or filters. At a
minimum, the manufacturer must have
calibrated the gas cells or filters against
a simulated source of known
concentration.
6.2 Continuous Monitoring System
Preparation.
6.2.1 Installation. Install the
continuous monitoring system according
to the measurement location procedures
outlined in Section 3 of this
specification. Prepare the system for
operation according to the
manufacturer's written instructions.
6.2.2 Conditioning Period. Follow the
procedure in Performance specification
2, Section 6.2.
6.3 Operational Test Period. Follow
the procedure in Performance
Specification 2, Section 6.3 and the
following subsections:
6.3.1 Calibration Error
Determination. Follow the procedures in
Performance Specification 2, Section
6.3.1.
6.3.2 Response Time Test Procedure.
Follow the procedures in Performance
Specification 2, Section 6.3.2.
6.3.3 Field Test for Zero Drift and
Calibration Drift. Follow the procedures
in Performance specification 2, Section
6.3.3.
6.4 System Relative Accuracy.
Follow the procedures in Performance
Specification 2, Section 6.4 and all the
accompanying subsections. The
reference method is Reference Method
10.
6.5 Data Summary for Relative
Accuracy Tests. Follow the procedures
in Performance Specification 2, Section
6.5.
7. Equations and Reporting
Follow the procedures in Performance
Specification 2, Section 7 and all the
accompanying subsections.
8. Reporting
Follow the procedures in Performance
Specification 2, Section 8.
9. Retest
Follow the procedures in Performance
Specification 2, Section 9.
V-Appendix B-35
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Federal Register / Vol. 45, No. 35 / Wednesday, February 20, 1980 / Proposed Rules
10. Bibliography
10.1 Repp, Mark. Evaluation of
Continuous Monitors for Carbon
Monoxide in Stationary Sources. U.S.
Environmental Protection Agency.
Research Triangle park, NC. Publication
No. EPA-600/2-77-063. March 1977.
10.2 Traceability Protocol for
Establishing True Concentrations of
Gases Used for Calibration and Audits
of Continuous Source Emission Monitors
(Protocol No. 1). June 15,1978.
Environmental Monitoring and Support
Laboratory, Office of Research
Development, U.S. Environmental
Protection Agency. Research Triangle
Park, NC 27711.
10.3 Department of Commerce.
Experimental Statistics. Handbook 91.
Ubrary of Congress No. 63-60072. U.S.
Government Printing Office,
Washington, DC.
|FR Doc 80-5289 Filed 2-19-80: 8:45 am|
V-Appendix B-36
-------
TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO.
EPA-340/1-80-001 a
3 RECIPIENT'S ACCESSION NO.
4. TITLE AND SUBTITLE
Standard? of Performance for New Stationary Sources
A Compilation as of July 1, 1980
5 REPORT DATE
July 1980
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
8. PERFORMING ORGANIZATION REPORT NO.
PN 3570-3-S
9. PERFORMING ORGANIZATION NAME AND ADDRESS
10. PROGRAM ELEMENT NO.
PEDCo Environmental, Inc.
11499 Chester Road
Cincinnati, Ohio 45246
11 CONTRACT/GRANT NO.
68-01-4147, Task 136
12. SPONSORING AGENCY NAME AND ADDRESS
U.S. Environmental Protection Agency
Division of Stationary Source Enforcement
Washington, D.C. 20460
13. TYPE OF REPORT AND PERIOD COVERED
Supplement, Jan 80 to July 80
14. SPONSORING AGENCY CODE
15. SUPPLEMENTARY NOTES
DSSE Project Officer:
Kirk Foster, MD-7, Research Triangle Park, NC 27711;
(919) 541-4571
16. ABSTRACT
This document contains those pages necessary to update Standards of Performance for
New Stationary Sources - A Compilation, published by the U.S. Environmental Protec-
tion Agency, Division of Stationary Source Enforcement in November 1977 (EPA-340/1-
77-015) and other supplements published in 1979 and 1980. It is only an update and
must be used in conjunction with the original compilation and previous supplements.
Included in this update, with complete instructions for filing are: a title page
and table of contents; a new summary table; all rev.ised and new Standards of Per-
formance; the full text of all revisions and standards promulgated since January
1980; and all newly proposed standards or revisions.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.IDENTIFIERS/OPEN ENDED TERMS C. COSATI Field/Group
Air Pollution Control
Regulations; Enforcement
New Source Performance
Standards
13B
14B
18. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (ThisReport)
Unclassified
21. NO. OF PAGES
20. SECURITY CLASS (Thispage)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
U.S. GOVERNMENT PRINTING OFFICE 1981-735-000/3025 REGION NO. 4
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|