PA/340/1-75/002
Stationary Source Enforcement Series
INSPECTION MANUAL FOR ENFORCEMENT OF
NEW SOURCE PERFORMANCE STANDARDS
FOSSIL-FUEL-FIRED
STEAM GENERATORS
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Enforcement
Office of General Enforcement
Washington, D.C. 20460
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INSPECTION MANUAL FOR THE
ENFORCEMENT OF NEW SOURCE
PERFORMANCE STANDARDS:
FOSSIL-FUEL-FIRED STEAM GENERATORS
By
Timothy W. Devitt and Norman J. Kulujian
Contract No. 68-02-1073
EPA Project Officer
John Butler
Prepared for
U. S. ENVIRONMENTAL PROTECTION AGENCY
Division of Stationary Source Enforcement
Washington, D. C.
January 1975
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This report was furnished to the U.S. Environmental Pro-
tection Agency by PEDCo-Environmental Specialists, Inc.,
Cincinnati, Ohio, in fulfillment of Contract No. 68-02-1073
The contents of this report are reproduced herein as re-
ceived from the contractor. The opinions, findings, and
conclusions expressed are those of the author and not
necessarily those of the U.S. Environmental Protection
Agency
The Enforcement Technical Guideline series of reports is issued by the
Office of 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 Enforcement Technical
Guideline reports are available - as supplies permit - from Air Pollution
Technical Information Center, Environmental Protection Agency, 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 22161.
ll
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ACKNOWLEDGMENT
This report was prepared under the direction of Mr.
Timothy W. Devitt. Principal authors were Messrs. Norman J,
Kulujian and Timothy W. Devitt.
Project Officer for the U.S. Environmental Protection
Agency was Mr. John Butler. The authors appreciate the
contributions made to this study by Mr. Butler and other
members of the Division of Stationary Source Enforcement.
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TABLE OF CONTENTS
Page
ACKNOWLEDGMENT iii
LIST OF FIGURES vii
LIST OF TABLES viii
1.0 INTRODUCTION 1-1
2.0 SIP AND NSPS REQUIREMENTS 2-1
2.1 Existing Sources; State Implementation 2-1
Plans
2.2 Summary of NSPS 2-3
2.2.1 Emission Standards 2-3
2.2.2 Performance Testing 2-8
2.2.3 Stack and Process Monitoring 2-8
2.2.4 Recordkeeping and Reporting 2-10
3.0 PROCESS DESCRIPTION, ATMOSPHERIC EMISSIONS, 3-1
AND EMISSION CONTROL METHODS
3.1 Process Description 3-1
3.2 Atmospheric Emissions 3-4
3.3 Emission Control Methods 3-6
3.3.1 Particulate Emission Control 3-6
Methods
3.3.2 Sulfur Dioxide Control Methods 3-7
4.0 INSTRUMENTATION, RECORDS, AND REPORTS 4-1
4.1 Process Instrumentation 4-1
4.2 Control Device Instrumentation 4-2
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TABLE OF CONTENTS (continued)
Page
4.3 Emission Monitoring Instrumentation 4-3
4.3.1 Opacity Monitors 4-3
4.3.2 Sulfur Dioxide Instrumentation 4-4
4.3.3 Nitrogen Oxides Instrumentation 4-5
4.4 Fuel Analysis Procedure 4-5
4.5 Facility Recordkeeping Requirements 4-6
5.0 START-UP/SHUTDOWN/MALFUNCTIONS 5-1
5.1 Frequency of Occurrences 5-1
5.2 Types of Occurrences 5-1
6.0 PERFORMANCE TEST 6-1
6.1 Pretest Procedures 6-1
6.2 Process and Control Equipment Operating 6-2
Conditions
6.3 Emission Test Observations 6-3
6.4 Performance Test Checklist 6-6
7.0 INSPECTION PROCEDURES 7-1
7.1 Future Inspection Procedures 7-1
7.2 Inspection Checklist 7-3
7.3 Inspection Follow-Up Procedures 7-3
APPENDIX A STANDARDS OF PERFORMANCE FOR NEW A-l
STATIONARY SOURCES
CODE OF REGULATIONS
APPENDIX B VISIBLE EMISSION OBSERVATION FORM B-l
APPENDIX C SUGGESTED CONTENTS OF STACK TEST REPORTS C-l
APPENDIX D GAS CONVERSION GRAPHS D-l
VI
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LIST OF FIGURES
Figure Page
3.1 Simplified Diagram of a Large Indirect- 3-2
Fired Heat Exchanger System
3.2 Diagram of Coal-Fired Boiler 3-3
3.3 Emission Sources from a Steam Generating 3-5
Facility
4.1 Light Transmission System 4-4
5.1 Required Start-Up Time to Achieve On-Line 5-2
Load Demand for Fossil-Fuel-Fired Steam
Generators
Dl SO2 Conversion Graph: ppm to Ib/MM BTU D-2
Heat Input
D2 NO Conversion Graph: ppm to Ib/MM BTU D-3
Heat Input
vn
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LIST OF TABLES
Table Page
2.1 Power Plant Particulate Emission Regulations 2-2
by State
2.2 Power Plant Visible Emission Regulations by 2-4
State
2.3 Power Plant S02 Emission Limitations by State 2-5
2.4 Power Plant NO Emission Limitations 2-6
J\,
2.5 Summary of Emission Standards for New and 2-7
Modified Steam Generators
2.6 Summary of Test Methods for New and Modified 2-9
Steam Generators
2.7 Recordkeeping Requirements for Steam Generating 2-11
Facilities
4.1 Items to be Recorded by Power Plants Subject 4-7
to NSPS
4.2 NSPS Recordkeeping Data Sheets, Steam Gen- 4-9
erating Facilities
5.1 Frequency of Shutdowns of Steam Generating 5-1
Facilities
6.1 NSPS Inspection Checklist for Steam-Electric 6-7
Generators During Performance Test
7.1 NSPS Inspection Checklist for Steam-Electric 7-4
Generators After Performance Test
7.2 Follow-Up Procedures After Inspecting Steam 7-7
Generating Facility
viii
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1.0 INTRODUCTION
Pursuant to Section 111 of the Clean Air Act, the
Administrator of the U.S. Environmental Protection Agency
(EPA) promulgated particulate, sulfur dioxide, oxides of
nitrogen, and opacity standards of performance for new and
modified fossil-fuel-fired steam generators. These stan-
dards are applicable to each fossil-fuel-fired steam gen-
erating unit of more than 63 million Kcal (250 MM BTU) per
hour heat input which is, or has been, constructed or modi-
fied after August 17, 1971.
Each state may develop a program for enforcing new
source performance standards (NSPS) applicable to sources
within its boundaries. If this program is adequate, EPA
will delegate implementation and enforcement authority to
the state for all affected sources with the exception of
those owned by the U.S. Government. Coordination of activ-
ities between the state agency and the U.S. EPA, both
Regional Office and Division of Stationary Source Enforce-
ment, is thus essential for effective operation of the NSPS
program. To facilitate such state participation EPA has
established guidelines identifying the administrative
procedures states should adopt to effectively implement and
enforce the NSPS program.
The long-term success of the NSPS program depends
largely upon the adoption of an effective plant inspection
program. Primary functions of the inspection program are
monitoring the NSPS performance tests and routine field
surveillance. This manual provides guidelines for con-
ducting such field inspections. However the same basic
inspection procedures presented in this manual should also
be of use in enforcing emission regulations contained in
state air quality implementation plans. A summary of state
emission regulations, presented in Section 2.1, is available
for comparison to NSPS for steam generators.
1-1
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2.0 SIP AND NSPS REQUIREMENTS
Standards of air pollution control performance for new
and modified steam generators were originally proposed on
August 1, 1971. The standards promulgated on December 23,
1971 altered the particulate sampling method, but the emission
limits were adjusted to provide the same degree of particu-
late control as the originally proposed standards. New
source performance standards are subject to Federal regula-
tion code 40 CFR 60. The title 40 designates "Protection of
Environment"; the number 60 classifies new sources.
An amendment on May 2, 1973, recognized that opacity
levels during start-ups, shutdowns, and malfunctions are not
representative conditions of performance tests unless other-
wise specified. In addition, the amendment simplified
reporting requirements. On June 14, 1974, sampling time
requirements for particulate matter and gaseous pollutants
were reduced, because performance test results did not show
any decrease in the accuracy or precision using shorter
sampling times.
On November 12, 1974, significant changes were proposed
for new and modified sources. These amendments revised
methods for reading opacities from continuous sources
without time exceptions. EPA intends to propose opacity
standards for steam generators, because current regulations
allow time exceptions.
2.1 EXISTING SOURCES; STATE IMPLEMENTATION PLANS
Particulate emission standards promulgated by the
states for power plants range from a low of 0.02 Ib/MM BTU
in Arizona, District of Columbia, Nevada and Vermont for
plants larger than 10,000 MM BTU/hr to a high of 0.8 Ib/MM
BTU for small plants in Indiana, Iowa and North Dakota. The
emission standards of most states for larger facilities
range from 0.1 Ib/MM BTU to 0.3 Ib/MM BTU. Emission regula-
tions for smaller plants are generally between 0.2 Ib/MM BTU
and 0.6 Ib/MM BTU. Table 2.1 is a tabulation by state of
the regulations limiting particulate emissions from power
plants. The values, obtained from state regulations, are
only illustrative and should not be used for enforcement
2-1
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purposes since in many cases the states' regulations contain
a variety of qualifications and exceptions.
Forty-four states limit visible emissions from new
plants to below 20 percent opacity. Regulations range from
"no visible discharge" in Maryland and the District of
Columbia to 60 percent opacity for existing installations in
Minnesota and for short periods of time in Pennsylvania and
Vermont. Table 2.2 is a tabulation of opacity limitations
for the various states; the same limitations apply to this
listing as apply to Table 2.1.
SO,, control regulations limit either the sulfur content
expressed in weight percent or Ib S/MM BTU, or the S02
emissions expressed in Ib S02/MM BTU. Weight percent
limitations range from 0.2 percent for oil in Idaho to 3
percent for coal and oil in Georgia with the majority being
under 1.5 percent. Only three states limit sulfur content
in Ib S/MM BTU; the range is 0.28 percent to 2 percent.
S0~ emission limitations are the most prevalent, ranging
from a high of 6 Ib SO-/MM BTU in rural Indiana to a low of
0.3 Ib S02/MM BTU in New Jersey. The 0.3 Ib S02/MM BTU in
New Jersey is applied in conjunction with fuel sulfur con-
tent limitations. The general range of S0~ emission limits
is from 1.0 to 3.0 Ib S02/MM BTU. Table 273 is a tabulation
of S02 control limits by state; the same limitations apply
to this listing as apply to Table 2.1.
Twenty-eight states limit NO emissions from power
plants. The majority of the states limit gaseous fuels to
0.2 Ib NO /MM BTU and liquid fuels to 0.3 Ib NO /MM BTU.
Solid fue¥ limitations range from 0.3 Ib NO /MMXBTU in
Massachusetts and Delaware to 1.3 Ib NO /MMXBTU in North
Carolina. Table 2.4 lists the NO emislion limitations by
state; the same limitations applyxto this table as apply to
Table 2.1.
2.2 SUMMARY OF NSPS
The standards for new or modified steam generators are
summarized below. A complete copy of the regulations, plus
revisions through November, 1974, is presented in Appendix
A.
2.2.1 Emission Standards
Allowable limits for opacity, particulate matter,
sulfur dioxide, and oxides of nitrogen are presented in
Table 2.5.
2-3
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2-6
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Table 2.5 SUMMARY OF EMISSION STANDARDS FOR NEW AND
MODIFIED STEAM GENERATORS
Item
Opacity
Particulate
so2
S02
so2
N0x
NO
X
NO
X
NO
X
Standard
20%
0.18 gm/MM cal input
(0.10 Ib/MM BTU input)
1 . 4 gm/MM cal input
(0.8 Ib/MM BTU input)
2.2 gm/MM cal input
(1.2 Ib/MM BTU input)
0.36 gr/MM cal inputa
(0.20 Ib/MM BTU input)
0.54 gr/MM cal inputa
(0.30 Ib/MM BTU input
1.26 gr/MM cal inputa
(0.70 Ib/MM BTU input)
Prorated
Fuel
All
All
Oil
Coal
Combination
Gas
Oil
Coalb
Combination
a) Expressed as NO2,
b) Except lignite.
2-7
-------
2.2.2 Performance Testing
Testing of new or modified sources must be performed no
later than 60 days after achieving maximum production rate,
but no longer than 180 days after initial start-up. The
tests must be conducted at representative performance using
fuels representative of those used during normal operation.
The owner or operator has the following responsibilities:
0 To give a minimum of 30 days notification of scheduled
tests.
0 To give a minimum of 30 days notice of anticipated
start-up. EPA must be notified of the actual start-up
date within 15 days after such date.
0 To provide adequate sampling ports, safe sampling plat-
forms, safe access to the sampling sites, and utilities
for sampling and testing equipment.
0 To perform emission tests and furnish a written report
of test results to the Administrator.
The various testing methods and specified conditions
are listed in Table 2.6 for each pollutant. Descriptions of
the testing procedures are specified in 40 CFR 60. Each
test consists of three repetitions of the applicable test
method. Results of the repetitive tests are averaged to
determine compliance. EPA personnel may perform additional
tests at any reasonable time at any representative load condition.
The opacity revisions, promulgated on November 12, 1974,
clarify procedures for determining opacity of plumes con-
taining water vapor, define observational portions, and
delete the requirement for calculating average opacity.
2.2.3 Stack and Process Monitoring
Instrumentation required for monitoring stack emissions
and process variables are listed below.
0 Smoke detector to continuously monitor coal- and oil-
fired steam generators.
0 S02 detector to continuously monitor coal- and oil-
fired units. If low-sulfur fuel is used, only a daily
analysis record is required.
0 NO detector to continuously monitor all fuel systems.
As of September 11, 1974, generators fired with lignite
are exempt from nitrogen oxides standards.
2-8
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0 Fuel consumption instrumentation to continuously
monitor the quantity (tons, gallons, or cubic feet) of
fuel consumed by coal-, oil-, or gas-fired units.
0 Electrical output system to record daily average elec-
trical output and minimum and maximum hourly generation
rate.
Instrument accuracy must be within + 20 percent, with a
confidence level of 95 percent, and calibrated at least once
every 24 hours unless the instrument manufacturer specifies
more frequent calibration.
The September 11, 1974 proposed rules are significant
changes in monitoring requirements. These include the addi-
tion of an oxygen monitor, techniques for adjusting and
calibrating extractive and non-extractive monitoring de-
vices, and monitoring alternatives if gas stream inter-
ferences inhibit the use of conventional instruments.
2.2.4 Recordkeeping and Reporting
All records are to be kept by the facility for two
years following the date of measurement and summary. The
plant must be prepared to make available to EPA any records
necessary to determine performance. Emission data shall be
made available to the public.
Table 2.7 summarizes the items to be recorded, and fre-
quency of data to be recorded.
The promulgation of the September 11, 1974 additions
will revise the recordkeeping and reporting requirements.
Data reduction will be performed monthly rather than daily,
allowing the use of computerized data reduction techniques.
For coal- and oil-fired units, fuel analysis may be sub-
stituted for the previously mandatory SO- monitors. Con-
ditions for reporting excess emissions are defined for
opacity, SO_ and NO .
2-10
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3.0 PROCESS DESCRIPTION, ATMOSPHERIC EMISSIONS,
AND EMISSION CONTROL METHODS
A brief description of the steam generating operation
is presented below to familiarize the inspector with the
basic theory. Atmospheric emissions and their control are
also discussed.
3.1 PROCESS DESCRIPTION
Emission performance standards apply to steam gen-
erating units with heat inputs of 63 MM Kcal (250 MM BTU)
per hour, which are generally electrical power plant gen-
erators or large industrial units producing stean and/or
electricity. Although coal-, oil-, and gas-fired boilers
differ in design and operation, the basic processes are
similar. In every case the chemical energy in the fuel is
converted into heat, mechanical energy, or electrical
energy.
A simplified diagram of a large indirect-fired heat
exchange system is shown in Figure 3.1. The major com-
ponents of the combustion process are the fuel-burning
equipment, the steam-producing system, and the control or
instrumentation system. Figure 3.2 illustrates the layout
of a coal-fired boiler.
Fuel is introduced into the boiler furnace in one of
two ways; it is either fed by one of many grate systems, or
it is injected through a burner. In either case, the fuel
burns to form combustion gas products, which then flow
through or over the various heat transfer surfaces in the
steam generator. The feedwater is heated in the economizer
and heat exchanger areas to generate steam. The air leaving
the economizer and entering the air heater section contains
enough heat to raise the inlet temperature of the air going
to the firebox. This improves boiler efficiency and helps
dry the fuel (if solid fuel is used).
The water and steam are processed through a recircu-
latory system that includes a drum, downcomer tubes, and
riser tubes. The drum is located at a high elevation in
relation to the heat exchanger structure. It receives
3-1
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heated feedwater that flows to the base of the steam gen-
erator in the downcomer tubes, which in turn feed riser
tubes forming the inside walls of the generator. Feedwater
is converted to steam in the risers and returns to the upper
portion of the drum; the steam is then used in a process or
fed to high-pressure turbines to generate electricity.
After the exhaust gases leave the air heater, they are
ducted through an air pollution control system to the ex-
haust stack. The various emission control methods are
discussed in detail in Section 3.3.
More complete process descriptions of steam generators
are given in textbooks provided by equipment manufacturers.1'
Details of combustion chemistry and fuel characteristics are
also available.3/4
3.2 ATMOSPHERIC EMISSIONS
The points of emission from coal-, oil-, or gas-fired
steam generators are illustrated in Figure 3.3. NSPS limits
are applicable only to emissions that result from the com-
bustion process and exit through the stack. Furthermore,
processes using fuels other than the conventional variety
(i.e., coal, oil, or gas) are not subject to the NSPS for
steam generators. These include the burning of waste gases,
refuse, or any other materials capable of producing heat by
exothermic reaction.
Particulate emission rates vary with the type of fuel,
as well as with boiler design and operating factors. Opacity
and particulate matter are increased as the fuel ash content
increases. Correct air-to-fuel ratios help minimize par-
ticulate emissions. Either an excess or lack of air re-
stricts organic matter from being oxidized in the boiler.
Oil-fired units require proper oil preheat temperatures and
coal-fired steam generators must burn the proper size coal
to minimize emissions. Facilities using natural gas have no
problems with plume opacity or particulate emission rate
unless the unit is operated poorly. Factors that affect
particulate emissions are discussed in more detail in
References 5 and 6.
The amount of sulfur dioxide formed in the combustion
process is dependent on the sulfur content of the fuel.
Essentially all sulfur in the fuel is oxidized to S02 and
one to five percent of the S02 is oxidized to S0_ during
combustion. About 95 percent sulfur is emitted to the
atmosphere, the remainder reacting with the ash. Sulfur
emissions from combustion sources are discussed in detail in
Reference 7.
3-4
-------
CONTROL
DEVICE
CLEANOUT
EXHAUST GASES TO ATMOSPHERE
AIR POLLUTION
BOILER
WATER
DRUM
AIR HEATER
ECONOMIZER
SUPER HEATER
BLOWDOWN
LINE
DRY
SYSTEM j SYSTEM
ASH SLAG
HOPPER I DISCHARGE
WATER
POLLUTION
+>
SALINE WATER
SOLIDS
SLUDGE
LIQUID OR SOLID WASTE
TO WATER SEPARATING DEVICE FOR
TREATMENT OR TO DRAINAGE AREA
Figure 3.3 Emission source from
a steam generating facility.
3-5
-------
NO emissions from a steam generator are highly de-
pendentxupon the combustion characteristics of the partic-
ular unit. Nitric oxide (NO) is formed in the furnace at
temperatures above 2800°F. The main factors affecting the
amount of NO formed are the flame and furnace temperature,
the percentage of fuel-bound nitrogen, the length of time
the combustion gases are maintained at the flame tempera-
ture, the rate of gas cooling, and the amount of excess air
present in the flame. Reference 8 is a report of a field
study of NO boiler emissions.
j£.
3.3 EMISSION CONTROL METHODS
Methods of controlling atmospheric emissions include
installation of control devices, fuel substitution, and
boiler modification in the case of nitrogen oxide emissions.
3.3.1 Particulate Emission Control Methods
Natural gas and low-ash fuel oils (less than 0.5%) can
be used to meet the particulate emission standard. However,
such premium fuels are in short supply and will probably not
be available for use in new steam-electric generating
units.
Electrostatic precipitators are the most commonly used
particulate emission control device. In recent years,
various types of wet scrubbers have also been used, partic-
ularly in conjunction with flue gas desulfurization (FGD)
systems. Scrubbers offer some advantages over precipitators
in that they are relatively insensitive to variations in
fuel composition and boiler operating characteristics.
Fabric filters have been used to only a very limited extent
although their use may increase in the future because of
their ability to control fine particulate emissions. Fabric
filters are not discussed further in this report. The NSPS
inspector is expected to have a working knowledge of the
theory and capabilities of the commonly used control de-
vices; such information is readily available in several
references.9/10,11,12
Electrostatic precipitator collection efficiency, and
hence design, is affected by the coal sulfur content, ash
composition, and flue gas temperature, all of which in-
fluence fly ash resistivity. Fly ash resistivity increases,
and precipitator efficiency decreases, as the fuel sulfur
content decreases. One method of overcoming the high fly
ash resistivity is the use of a "hot" precipitator which
operates at temperatures in excess of 550°F where resis-
tivity is relatively low and independent of fuel sulfur
content. Because of the higher temperatures, the hot
precipitator handles a much larger flue gas volume than a
3-6
-------
"cold" precipitator on an equivalent sized boiler. Thus
most "hot" precipitators are being installed on new units,
where there are no space restrictions, or on relatively new
plants which also have adequate space. Sulfur trioxide,
S0_, injected into the gas stream will also lower particle
resistivity.
The amount of power input to the precipitator is re-
lated to its operating efficiency. High resistivity fly ash
can limit the amount of useful power that the power supply
(transformer-rectifier sets) can deliver to the precipitator,
even though the power supply is adequately sized. Thus
checking the delivered power to the unit (by reading the
secondary current and voltage inputs to each precipitator
section) is an easy check as to whether the precipitator is
performing adequately.
Many precipitators are designed to meet required col-
lection efficiencies with one or more electrical sections
out of service. Thus sections can be de-energized because
of a short or other electrical failure without requiring the
boiler to come off-line for precipitator repairs.
Wet scrubbing systems are being used for particulate
collection by several utilities, often in conjunction with
FGD systems. Efficient particulate removal usually requires
that some type of venturi scrubber be used, with pressure
drops on the order of 10 to 15 inches of water. Important
operating parameters influencing particulate collection
efficiency are the pressure drop and liquid-to-gas (L/G)
ratio, usually about 10 to 20 gallons/1000 acf of flue gas
for a venturi scrubber. Higher liquid volumes, up to 50
gallons per 1000 acf, are used to avoid scaling in the
hardware.
3.3.2 Sulfur Dioxide Control Methods
SC>2 emissions can be reduced by using low-sulfur fuel
or FGD systems. Many utilities have decided to use low-
sulfur coal although as mentioned earlier this can reduce
the particulate collection efficiency of electrostatic
precipitators by increasing fly ash resistivity. Further-
more, since utilities normally receive coal from several
different sources, it is necessary to install rather elabo-
rate coal-blending facilities to ensure that S02 emissions
on a two-hour average (or other short-term basis) do not
exceed applicable standards. The adequacy of the blending
system to store and then properly mix the various sulfur
content coals must be established by reviewing the system
design.
3-7
-------
There are several types of FGD systems either currently
in use or under development. The most widely used are
lime/imestone, magnesium oxide, and sodium solution scrub-
bing. These processes are briefly described below. Addi-
tional information is available from various FGD system
manufacturers.
Lime/Limestone Scrubbing
In this process lime or limestone is used to make an
alkaline slurry which is circulated through an absorber
where it reacts with the sulfur oxides in the flue gas.
Various calcium sulfite and sulfate salts are formed by the
reaction which are then removed in settlers or clarifiers.
The sludge produced by the system can be chemically sta-
bilized to produce a suitable landfill material or stored in
sludge ponds which have adequate barriers to prevent surface
and groundwater contamination.
Limestone-based systems operate with S02 removal ef-
ficiencies of approximately 85 to 90 percent. Use of lime,
which is more reactive than limestone, enables the system to
operate with efficiencies in excess of 90 percent.
Magnesium Oxide Scrubbing
The magnesium oxide scrubbing process is a regenerable
process producing sulfuric acid as a by-product. A slurry
of magnesium oxide is circulated through an absorber where
it reacts with the sulfur oxides to produce magnesium sul-
fites and some magnesium sulfates. These reaction products
are dewatered, dried and then transported to either an on-
or off-site sulfuric acid plant where they are calcined to
liberate the S02 which is used to produce the acid. The
process can also be adapted to produce elemental sulfur.
The regenerated MgO is shipped back for reuse in the system.
This system produces no waste sludge but requires that
a market be available for disposal of substantial quantities
of high-grade sulfuric acid. SO2 removal efficiencies in
excess of 90 percent are obtained.
Sodium Solution Scrubbing
A sodium sulfite solution is circulated through an
absorber where it reacts with SO- in the flue gases to
produce sodium bisulfite. This solution is fed to an
evaporator which drives off the S0_, forming a high con-
centration of S0~ steam and a slurry of sodium sulfite
crystals. The SO- gas stream can be used to produce either
sulfuric acid or elemental sulfur. The slurry of sodium
sulfite crystals is recirculated to the absorbing system.
S0 efficiencies in excess of 90 percent can be obtained.
3-8
-------
REFERENCES FOR CHAPTER 3
1. The Babcock and Wilcox Company. Steam: Its Generation
and Use, 1963.
2. Combustion Engineering. A reference book on Fuel
Burning and Steam Generation, 1967.
3. Zerban, A.H., and E.P. Nye. Power Plants, Interna-
tional Textbook Company, 1957.
4. Perry, J.H. Chemical Engineers Handbook, 1963.
5. Field Surveillance and Enforcement Guide for Combustion
and Incineration Sources. PEDCo-Environmental Spe-
cialists, Inc., EPA Contract No. 68-02-0606, 1972.
6. Smith, W.S., and C.W. Gruber. Atmospheric Emissions
from Coal Combustion - An Inventory Guide. PHS Pub-
lication No. 999-AP-24.
7. Control Techniques for Sulfur Oxide Air Pollutants.
Office of Air Quality Planning and Standards, EPA,
1972.
8. Bartok, W., A.R. Crawford, and G.J. Piegari. Sys-
tematic Field Study of NO Emission Control Methods for
Utility Boilers, Esso Research and Engineering Company
under EPA Contract No. CPA 70-90, 1971.
9. Control Techniques for Particulate Air Pollutants, PHS,
National Air Pollution Control Administration Pub-
lication No. AP-51, 1969.
10. A Manual of Electrostatic Precipitator Technology, Part
II, Southern Research Institute under Contract No. CPA
22-69-73, August, 1970.
11. Scrubber Handbook Volume 1. Ambient Purification
Technology, Inc., under Contract No. CPA-70-95, July
1972.
12. White, H.J. Industrial Electrostatic Precipitation.
Addison-Wesley Publishing Company. Palo Alto, Cali-
fornia. 1963.
3-9
-------
4.0 INSTRUMENTATION, RECORDS, AND REPORTS
To determine compliance, the NSPS inspector will rely
primarily upon the readings from the installed emission
monitoring systems. However, for plants not covered by
NSPS, the inspector will usually have to rely upon process
or control equipment instrumentation plus facility records
of fuel sulfur and ash contents. This section is designed
to familiarize the inspector with emission-related instru-
mentation commonly encountered in process operation, emis-
sion controls, and emission monitoring. The type, location,
and purpose of each instrument are described briefly; de-
tailed theoretical principles of instrument operation are
available from other literature sources.1'^ Recordkeeping
and reporting requirements of the NSPS are also outlined.
4.1 PROCESS INSTRUMENTATION
Large steam generators, such as those with heat inputs
greater than 63 MM Kcal (250 MM BTU) per hour, usually
display instrumentation on a control panel. Although the
instruments are designed mainly to aid the boiler operator,
several of them can also aid the inspector in determining
whether the power plant is complying with regulations.
Steam Flow/Air Flow Recorder
The steam and air flow monitor is equipped with a cir-
cular or strip chart on which are recorded instantaneous
values of steam and air. Air flow inputs must be propor-
tioned properly to ensure complete fuel combustion and
minimum uncontrolled particulate emissions. Steam flow
values also serve as a check on heat input values (BTU)
given to the inspector by utility personnel.
Oxygen (Combustion Gas) Recorder
The recorded amount of CO2 or 02 in the flue gas is
significant in defining the status or the combustion process.
For efficient combustion, 02 values of 2 to 5 percent in the
flue gases indicate a proper proportion of excess air.
Lower amounts of oxygen indicate insufficient air, a con-
dition that increases particulate concentrations and causes
4-1
-------
black smoke. Higher values of 0? result in low furnace
temperature (white smoke), or poor fuel atomization. In
addition, the increased airflow tends to overload the con-
trol equipment. If a steam generator is using low excess
air (e.g. less than 2 to 5 %) to reduce NO emissions, this
will be indicated by the 0- analyzer and can be used as a
future compliance check (i.e., the boiler should be operated
at approximately the same low excess air levels to minimize
NO emissions).
.o.
Oil and Steam Pressure Recorders
Oil and steam pressure gages are located in supply
lines leading to the burners. Although pressures and
temperatures vary depending on boiler design and fuel
properties, values should be between 120 and 180 psi pres-
sure, and 170 and 220°F. Steam atomizing pressures should
be about 15 psi higher than oil pressures.
Fan Amperage Meters
Gas volume changes are detected by amperage meters on
the fan system. The gages serve as a check on air flow
monitor values discussed earlier in this section.
Other Records
Performance standards require new or modified steam
generators to record daily fuel rates and electrical gen-
eration. The facility should also maintain a record of fuel
sulfur and ash contents. If low-sulfur coal is used for
compliance purposes, a daily sulfur analysis, in accordance
with Part §60.45 of 40 CFR 60, may be substituted for fuel
monitoring requirements.
4.2 CONTROL DEVICE INSTRUMENTATION
The inspector can collect initial control device data
when performance tests are performed. Comparison with data
from later inspections should indicate whether the source is
in compliance without further emission testing.
Control devices designed for new and modified steam
generators include precipitators and scrubbers.
Electrostatic Precipitators
The inspector should record voltage, current, and spark
rates from instrument gages usually located near the pre-
cipitator power supply.
A transformer converts incoming "primary" voltage (220
or 440 volts) to "secondary" kilovolts required by the
precipitator unit. Secondary current and voltage readouts
are in mA and kV, respectively. Gages may record primary or
secondary voltages and currents, or both.
The spark rate meter is calibrated in sparks per
minute. Low spark rates may be due to low power input.
4-2
-------
Each section of precipitators has its own instrumen-
tation. The inspector must record values from all sections.
Control equipment manufacturers state acceptable values for
electrostatic precipitator power requirements; spark rates
between 50-100 sparks per minute usually indicate optimum
particulate collection.
Scrubbers
When inspecting venturi scrubbers for particulate
removal, the inspector should check the pressure drop across
the venturi throat.
Sulfur dioxide scrubbing systems incorporate additional
instrumentation. Essentially all systems will have an
outlet SO- emissions monitor. In addition, most FGD systems
have extensive instrumentation to measure pressure drops
through various sections of the scrubbing trains, solids
concentrations in scrubber make-up, hold and recirculation
tanks, and pH of the scrubbing slurry. To a limited extent
such instrumentation can be used to monitor performance but
any significant departure from accepted or normal values of
these parameters will lead to system upsets (e.g., plugging,
loss of pH control) which will cause the system to be
brought off-line anyway.
4.3 EMISSION MONITORING INSTRUMENTATION
Concentrations of particulate, sulfur dioxide, and
nitrogen oxides must be continuously monitored and recorded.
Specific requirements for coal-, oil-, and gas-fired steam
generators are summarized in Section 2.2.
The NSPS inspector must be familiar with the various
types of instrumentation and with methods of verifying the
levels of pollutants indicated by the instruments.
4.3.1 Opacity Monitors
The photoelectric opacity monitor and recorder directly
measures the attenuation of light passing through stack
exhaust gas. As shown in Figure 4.1, transmissometers
incorporate a light source on one side of the stack and a
detector on the other side. Invisible plumes have a trans-
mittance of 100 percent and an opacity of zero percent;
opaque plumes attenuating all of the light have zero trans-
mittance and 100 percent opacity. An electronic strip-chart
recorder continuously records opacity values. Many models
zero themselves automatically at regular intervals; this
adjustment is indicated on the chart paper.
At present none of the opacity monitors meet NSPS daily
calibration requirements. In any two-ended system the gas
4-3
-------
flow must be shut off to obtain a calibration for zero
percent opacity. The instrument should be calibrated each
time the unit is down. Inherent problems include dirty or
scratched optics and changes in the detector and light
source characteristics; these latter problems are minimized
by automatic zeroing units.
CLEAN PURGE GAS -N
"itl
LIGHT SOURCE |||
;*
f'/f
_j
/
/A
^0 ti
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COLLIMATION; |||
LENS SYSTEM ' ^
CLEAN PURGE GAS''
1
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/'CLEAN PURGE GAS
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PHOTOCELL
1
A ':
0 -
1 ] l
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^
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^ STACK,
^ 'WALL
^r.
^
^
h
HI '^TELESCOPIC
1 U LENS SYSTEM
\ AMOUNTING FLANGES
\
-CLEAN PURGE GAS
Figure 4.1 Light transmission system.
4.3.2 Sulfur Dioxide Instrumentation
Many types of instruments are in current use for con-
tinuous analysis of SOj gas, including spectrometers and
electrochemical sensors. Wet chemical analyzers are not
practical for stack monitoring, since they are subject to
fouling by mist and particulates and to interference from
unremoved gases and water vapor.
The spectrometer using the ultraviolet region of the
S02 spectrum is the monitor most commonly used, since other
types of monitors require withdrawl of a sample from the
stack. The UV absorber uses the stack as its optical path
and thereby provides cross-stack average measurements. The
S02 absorption spectrum is matched against a reference
pattern in such a way that other materials do not interfere,
Electrochemical instruments can detect both sulfur
dioxide and nitrogen oxides. A fuel cell sensor generates
an electric current by electro-catalytic oxidation or
4-4
-------
reduction of S02; the current is directly proportional to
the SO2 concentration in the sample of the gas stream.
These sensors must be replaced periodically to provide
accurate readings. The inspector can calibrate the in-
struments by inserting known concentrations of calibration
gas into the analyzer. Two known concentrations can be
carried in small sample cylinders and calibrations performed
according to the manufacturer's specifications at operating
temperatures and pressures. Erroneous SO- readings result
from leaks and plugs in the lines and filters from coating
of the lens. Periodic maintenance is required to remove
dust, oil, and condensation from the system.
4.3.3 Nitrogen Oxides Instrumentation
The NSPS for NO emissions from new and modified steam
generators apply to Both NO and N02 although less than 5
percent of the NO is present as N02. Therefore, measure-
ment of stack NO content is adequate for monitoring purposes
(unless excessive "excess air" is introduced into the ex-
haust gas stream).
Nitrogen oxide instrumentation includes photometric and
spectroscopic analyzers, electro-chemical methods, and
chemiluminescent detectors. Wet-analyses instruments are
not practical for in-stack monitoring.
Photometric and spectroscopic analyzers measure light
transmission at a specific wavelength. Since these instru-
ments depend upon light transmission, they may give erro-
neous readings as a result of absorption of radiation by
particulate matter or condensates in combustion gases.
Electrochemical instruments were discussed above for
monitoring sulfur dioxide. NO readings may be high as a
result of the presence of S02«X The inspector should note
whether the sample inlet system has an absorber to remove
SO2 from the sample.
Nitric oxide is detected by the chemiluminescent re-
action of NO with ozone-producing light. The intensity of
the light, which is detected by a photomultiplier tube, is
proportional to the NO concentration. The inspector can
calibrate the instrument with standard concentrations of NO
by techniques similar to those mentioned for S0~ calibration.
4.4 FUEL ANALYSIS PROCEDURE
A representative fuel sample taken during a performance
test of a coal- or oil-burning facility provides a sample
for performing an ultimate analysis. Heating values are
required to define emissions in terms of BTU heat input.
4-5
-------
Although carbon, hydrogen, sulfur, nitrogen, and ash frac-
tions are not directly needed, they do provide a material
balance check of boiler gas volumes. In addition, emission
estimates based on sulfur and ash percentages serve as
useful companion information to source test emission data.
Samples can be removed from the feed coal before or
after it enters the pulverizers. Placing the sample in
sealed polyethylene bags prevents moisture from escaping so
that accurate "dry basis" and "as received" values can be
obtained. A total coal or oil sample of 1 to 2 quarts taken
at half-hour test intervals constitutes a sufficient fuel
sample for analysis.
4.5 FACILITY RECORDKEEPING REQUIREMENTS
Operators of new and modified steam generators are
required to keep records of specific items. These items
were discussed and summarized in Section 2. Additional
items that must be recorded include combustion gas data
(C02, 02, or unburned combustibles), process data that
influence NO emissions, and specific process and control
device maintenance information.
Table 4.1 lists the items directly or indirectly
associated with air pollutant emissions that should be
recorded. The recording procedure, frequency, and accuracy
of data are given for each parameter. The inspector can
review records in either of two ways: he can complete his
own at the time of his visit to the site, or he can have
facility personnel complete a checklist and give it to him
at the time of his inspection. The latter method appre-
ciably reduces the time required of the inspector at each
individual boiler facility. The six-part form presented in
Table 4.2 can be completed in either manner.
4-6
-------
Table 4.1 ITEMS TO BE RECORDED BY POWER PLANTS SUBJECT TO NSPS
frwiuanoy
Racordkaapln? Accuracy Reworks
• Sulfur
• Mating Vain*
Hocaaa
Staaa Flow
Air new
• rval Rata
• »y«r«g« Electrical Output
* Maximal Hourly Output
i Hourly Output
Coajbustlon Analysis
°a
riua Cat Temperature
riua Gal Recirculatlon Rat*
Ml Preheat Tu.ptr.tor*
Oil trah.it rnmnn
Control Daviea
Spark Mater Is)
Unit Voltag.(»)
Onit Currant(a)
fcrubber
Wat.r Rat*
Additive Bata
Pressure Drop
Dally
WMfcly
Weekly
0.01%
0.01%
4 Signficant Figure*
See remarks
See remarks
Record dally Integral value.
During startup, record
fuel usage until unit is
•tabillzed
Divide dally MW output by
hours of operation
Record highest daily MW
production and hour of
occurrence
Record lowest daily MW
production and hour of
occurrence
For gage instrumentation.
record CO. and/or O.
twice during 24 hr. periodt
read at anticipated high
and low daily load for
chart instrumentation.
see remarks.
See remarks
Read once daily
Head one* daily
R«ad onoe daily
Read onca daily
Read onca daily
Read one. daily
Record daily throughput
and compute avg/minute
Record Daily total and
compute pounds/day
Raad onca daily
Haoord one. daily
3 Significant Figures
3 Significant Figures
4 Significant Figures
4 Significant Figures
4 Significant Figures
4 Significant Figures
0.1%
0.1%
Nearest Degree
Nearest Degree
Nearest pel
Sparks Per Minute
3 Significant Piguraa
3 Significant Pigurea
Gallon. Par Minut.
Pounds Per Day
Nearest Tenth
0.1 inch H,0
State ASTM (F.R.) or ASME Method (coal
rrr i.?-]<>;4i oil PTC 3.1-lisn) or
onuiv. Avq. of 3 samples taken not less
than 4 hrs. apart.
State ASTM (F.R.) or ASME Method (coal
PTC 3.2-19541 oil PTC 3.1-195B) or
equiv. Avg. of 3 samples taken not laaa
than 24 hrs. apart.
State ASTM (F.R.) or ASME Method (coal
PTC 3.2-1954! oil PTC 3.1-1958) or
equiv. Also report "as fired" to
calculate BTU/hr) and dry (for C
balance), also state whether method
determined from Bomb or Seyl.r coal
chart.
Mark dates on strip or circular charts
and keep.
Available for inspector.
Mark dates on strip charts and keep
available for inspector.
Mark dates on strip charts and keep
available for Inspector.
Many control devices are designed in
units or sections. In this case*
records of each individual section is
required.
4-7
-------
Table 4.1 (Continued). ITEMS TO BE
RECORDED BY POWER PLANTS SUBJECT TO NSPS
Recording procedure and
frequency
Recordkeeping Accuracy Remarks
Monitor!
* Particulate/Opaeity
"Malfunctions, startup
Read high value from chart
per 8 hr. period; record
amplitude and time
Read nigh value from chart
per 8 hr. period) record
amplitude and time
Record high value from chart
per 8 hr period: record
amplitude and time
Frequency a> required
Nearest Percent
Dearest ppm
Nearest ppm
M Required
Maintenance and Calibration
Monitor*
• Partieulate/Opacity
* «°2
* *>«
Instruments
Pulverizers/Feeders
Control Device
State weekly history
As Required
These instrumenta detect ppra (by volume
to volume). Records shall be kept in
in these units since they cannot "be
reduced to ... the applicable stan-
dard..." As stated by §60.45(f). This
would involve computation of instanta-
neous fuel heating values. Heating
values are required only on a weekly
basis.
A quarterly report of all startups and/
or malfunctions wni.cn lei
higher than applicable s
submitted on the 15th da
end of the calendar guar
shall include descriptio
tion, date, duration, na
corrective actions and p
andards will =*
following the
er. The report
of malfunc-
ure and cause,
eventive
aeasures, and values of emissions from
pollutant monitors.
Calibration required daily or more
frequent if specified by manufacturer.
Check air flow/steam flow monitor
weekly. Check CO- and 0. meters against
fyrite or orsat results
Check coal sizing weekly per ASTM 410-
36; ASME 3.2 1954.72 (stokers) and
ASTM D 197-30; ASME 3.2 19S4.84
(pulverizers)
Inspect weekly for plugging, poor
•tonizvtion (higher atoroization
pressure) clean as required.
Required by NSPS
4-8
-------
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4-9
-------
Table 4.2 (Continued). NSPS RECORDKEEPING DATA SHEETS
STEAM GENERATING FACILITIES
PART III EMISSION MONITORING DATA
0 Emission monitor data requires three daily values taken once
per shift or 8 hour duration
0 If plant operates less than 3 shifts per day or unit is down,
write in "no operation."
0 Define pollutant units (i.e., % opacity or transmittance, ppm,
etc.)
0 Disregard recordkeeping if instrument is equipped with a
strip-chart recorder
Day &
shift
Particulate/opacity
Time
(24-hr clock)
Reading
units
Sulfur dioxide
Time
(24-hr clock)
Reading
units
Nitrogen oxide
Time
(24-hr clock)
Reading
units
4-10
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at 15 minute intervals.
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4-13
-------
REFERENCES FOR CHAPTER 4
1. Evans, R.K., Combustion Control, Power. December 1967.
2. The Babcock and Wilcox Company. Steam: Its Generation
and Use, 1963.
3. Guidelines for the Selection and Operation of a Con-
tinuous Monitoring System for Continuous Emission
Sources, EPA Contract No. 68-02-0226, Task 14 (Pre-
liminary draft).
4. Performance Specifications for Stationary Source
Monitoring Systems for Gas and Visible Emissions, EPA
Report No. EPA 650/2-74-013 (Preliminary draft).
4-14
-------
5 . 0 START-UP/SHUTDOWN/MALFUNCTIONS
Steam generating facilities are required to report
measured or estimated emissions for each occurrence of a
shutdown- start-up cycle and submit a written report fol-
lowing the end of each calendar quarter. The report shall
include the nature and cause of any malfunction resulting in
a shutdown, corrective actions taken, and preventive mea-
sures adopted.
5.1 FREQUENCY OF OCCURRENCES
Forced outages result from unpredicted malfunctions
requiring immediate shutdown. Planned outages are required
for routine maintenance and inspection. An accumulation of
outage data for fossil-fuel-fired units is presented in
Table 5.1.1 rp^e column "Total annual outages per unit per
year" is the sum of all forced and planned outages. The
table should serve only as a general guide for the occur-
rences of start-up, shutdown, and malfunctions.
Table 5.1 FREQUENCY OF SHUTDOWNS OF STEAM
GENERATING FACILITIES
Unit size,
MW
> 60
> 400
No. of units
reviewed
733
98
Total annual
outages per
unit per year
11
17
Forced annual
outages per
unit per year
6
12
If a malfunction is related to the emissions control
system, emissions may be in excess of NSPS until the problem
is noticed and the unit is shutdown. Since many different
malfunctions can occur, the duration of excess emissions
cannot be predicted with any degree of reliability.
5.2 TYPES OF OCCURRENCES
Forced outage malfunctions, by definition, involve a
shutdown-start-up cycle. Some malfunctions, however, can be
5-1
-------
resolved on-line and do not require a shutdown. In these
instances a boiler may be "turned down" to as low as 10
percent of design load without appreciably increasing emis-
sions.
Planned outages require complete shutdown of the unit
to enable maintenance personnel to perform such tasks as
slag cleanout, precipitator repair and boiler tube repair.
Some facilities find it desirable to use lower cost,
less efficient units for peaking operations. Such units may
be subject to intermittent service that requires start-up
every weekday morning. New steam generators are not nor-
mally used as peaking units.
Discussions of start-up, shutdown, and malfunction
occurrences follow.
Start-up
During start-up, particulate emissions and equivalent
opacity will be higher than during normal operation and will
persist until operation is stabilized. Figure 5.1 shows the
time required for various boiler sizes to reach stable load.
A steam generator may have unique characteristics that
result in significant deviation from the graph.
100
200
UNIT SIZE. Mw
300
400
Figure 5.1 Required start-up time to achieve on-line
load demand for fossil-fuel-fired steam generators.
Shutdown
Air pollutant emissions are not a problem during boiler
shutdown. The firebox interior aids in fuel burnout after
the boiler is turned off. The units can be shutdown very
quickly and easily.
5-2
-------
Malfunctions
Malfunctions result from either equipment breakdown or
operator error; however, not all malfunctions substantially
increase emissions. Those that can result in excessive
emissions are presented below:
0 improper combustion air flow due to faulty fans or
dampers
0 air preheater system (if used) not sufficiently heating
air
0 irregular fuel flow to coal mills or oil or gas burners
0 firebox flame out (usually detected on control panel)
0 emission control device malfunction.
Air flow malfunctions occur if fan and damper compo-
nents fail, or when operators inadvertently set dampers at
improper positions. Shutdowns associated with fuel flow
problems frequently result from negligent maintenance, such
as coked or burned burner impellers or plugged oil tips.
Many malfunctions are signalled immediately by safety
features incorporated in the control panel. Excess tempera-
tures and/or pressures, burner flame outs, and improper fuel
feed rates are malfunctions that are signalled to the
operator.
Steam generator load swings are necessary to meet
output demand. Although not defined or covered as start-up,
shutdown, or malfunction, load change often results in
excessive particulate emissions. The high rate of emissions
can last for several minutes until air flow and fuel flow
are equilibrated. Of course, careless operation will in-
crease both the excessive emission rate and duration.
Precipitator malfunctions are usually due to some
failure which affects the capability of supplying power to
one or more of the precipitator sections. Such failures can
be caused by broken wires and insulators, power supply or
control malfunctions. Whether or not particulate emission
standards are exceeded when one or more sections are de-
energized depends upon the precipitator design.
Failure of the ash removal system to empty an ash
hopper can increase particulate emissions by causing a
section to short-out (when the fly ash builds up to the
point where it hits the electrodes) and through reintrain-
ment of the fly ash in the hopper. Improper bin design can
5-3
-------
create a "rat-hole" condition where a hole is created
through the bed of ash in a hopper rather than the entire
hopper emptying.
Flue gas desulfurization systems can malfunction for a
variety of reasons. The problems include scaling, plugging,
corrosion or erosion, as well as failure of individual com-
ponents. These problems can be resolved in the design,
start-up, or debugging phases of FGD system operation.
Reliability of the system should be about the same as the
boiler (on the order of 90%). If the reliability of the
system is less than this, the inspector should have the
utility categorize the problems, the percent of time the
system is down due to each problem, the specific corrective
action which will be taken, and the timetable for such
corrective action.
5-4
-------
REFERENCES FOR CHAPTER 5
1. Letter to EPA Division of Stationary Source Enforcement
(Attention: Mr. Megonnell) by Edison Electric Institute
(W. D. Crawford,) dated October 10, 1972.
5-5
-------
6.0 PERFORMANCE TEST
During the performance test the inspector must observe
process and control equipment operation to ensure that the
tests are conducted under the proper operating conditions, as
well as the emission tests to determine whether proper test
procedures are followed. The purpose of the performance test
is to determine whether the emission standards will be met
when the boiler is operating under normally encountered con-
ditions that create the maximum emission rate. In addition,
values for key process and control equipment operating param-
eters can be obtained to form a basis for comparison on future
plant inspections.
Section 6.1 covers the inspector's responsibilities in
preparing for the performance test. Section 6.2 describes the
steam generator and control equipment operating conditions
under which tests should be conducted. Section 6.3 describes
the source test data the inspector should obtain to determine
whether the test was properly conducted. An inspection
checklist is presented in Section 6.4 which summarizes all
process and test parameters to be recorded during the perfor-
mance test.
6.1 PRETEST PROCEDURES
Although the new source performance standards stipulate
exact procedures for compliance, facility personnel may
misunderstand or not be aware of parts of the regulations.
The inspector should therefore arrange a meeting with plant
personnel to review details of the standards and the testing
procedures prior to the actual performance test. The inspec-
tor provides copies of the performance standards at the meeting,
The inspector informs all parties of the latest revisions to
the standards, such as the proposal and possible promulgation
of the September 11, 1974 rules.
The inspector must also survey the ductwork for test
port locations. The location of a clean-up area should be
agreed upon by all parties prior to the test date. During a
tour of the power plant, the inspector determines whether
additional inspection personnel are required to monitor the
process, sampling site, and exhaust stack.
The inspector must ensure that management understands
that performance tests are valid only if performed while the
facility is operating at representative performance. At this
time, the parties should agree on the parameters constituting
"representative performance." The inspector should also
determine which testing firm is to perform the tests and, if
no representative of the firm attends the meeting, contact the
6-1
-------
firm to ensure that tests are run in accordance with pro-
cedures outlined in 40 CFR 60. The chief purpose of the
pretest meeting is to outline clearly for all concerned
parties the purpose of the tests and the required test
procedures.
6.2 PROCESS AND CONTROL EQUIPMENT OPERATING CONDITIONS
Important process operating emission control device
parameters for which values must be established before the
tests are conducted are listed below:
0 steam production rate
0 fuel composition (ash, sulfur)
0 excess air rate
0 flue gas recirculation rate (if applicable)
0 number of electrostatic precipitator sections in
operation
0 scrubber pressure drop and L/G ratio (particulate emis-
sion control)
Parameters of secondary importance are:
0 soot blowing frequency
0 oil preheat temperature and burner atomizing pressures
The importance of each of these is briefly described
below:
Steam production rate - As required by Part §60.8, the
tests should be conducted at representative performance
conditions. Boiler capacities are typically rated in terms
of ascending output as rated or name-plate, maximum con-
tinuous, and peak. Peak capacity is the maximum output the
boiler can and will produce for short periods of time,
usually measured in terms of a few hours. Tests should be
conducted at the maximum continuous capacity since it is not
practical to conduct the particulate tests at the peak value
and tests for all three pollutants should be conducted under
the same conditions. Furthermore, boilers are operated only
infrequently at peak operating conditions.
Fuel composition - Particulate emissions from an
electrostatic precipitator on a coal-fired boiler should be
tested with coal of the lowest sulfur content, and to the
extent possible given the previous constraint, the highest
ash content that the plant anticipates using.
6-2
-------
Excess air rate - If the plant uses low excess air
firing to meet the NOX emission limitations, then the tests
should be conducted at the excess air rate that the plant
anticipates using. Particulate emission tests must be
conducted at this excess air level since particulate emissions
can increase as excess air levels are reduced.
Flue gas recirculation rate - The percentage of flue
gas recirculated should be set if this method is used to
minimize NOX emissions.
Number of electrostatic precipitator sections - The
precipitator may be designed to meet the standard with one
or more sections de-energized. The precipitators are to be
operated during the compliance test with any specific
sections de-energized that were designed as a safety factor
with respect to emission standards.
Particulate emission scrubber pressure drop - Since
scrubber efficiency for particulate emissions control
decreases with decreasing scrubber pressure drop, the par-
ticulate emission tests should be conducted with the scrub-
ber pressure drop (consistent with boiler load conditions
identified above) at the lowest value under which the
facility anticipates operating.
For boilers equipped with intermittent blowing, the
frequency of soot blowing during the particulate emission
tests must be proportioned to the soot blowing during the
representative performance.
6.3 EMISSION TEST OBSERVATIONS
Emission tests and opacity determinations are conducted
by qualified emission testing personnel. The inspector is
responsible for ensuring that all pertinent data are collected,
that the field procedures and equipment meets CFR, and that
the power plant is run at representative performance during
all sampling operations. A technician or engineer qualified
by EPA Method 9 reads visible emissions, as described in
Part 60.11(b). The visible emission form, Appendix B, is
the appropriate form for recording visible emissions.
The inspector's degree of surveillance of the stack
sampling team depends on the confidence of the inspector and
qualifications of the test personnel. Even if the inspector
has complete trust in the sampling crew, the following task
should always be performed:
6-3
-------
Record duct dimensions (both inside and outside) and
location of sample ports.
Check the number of ports at the sampling site and
examine the ducting for the nearest upstream and down-
stream obstructions. Ask the crew leader how many
total points will be traversed and check with Figure
1.1 in 40 CFR 60 to determine whether the stream will
be properly sampled.
Note whether the crew runs a preliminary traverse, and
if so, inquire what nozzle diameter is selected.
(Isokinetic sampling is a function of nozzle size.)
Check to ensure that the moisture content of the gas
stream is determined by Method 4 or an equivalent method
such as drying tubes or volumetric condensers; assumption
of the moisture content is not allowed.
Observe the leak test of the sampling train. . The
allowable leak rate is given in Method 5. Leakage
results in lower concentrations than are actually
present. Be next to the dry gas meter during the
leak check, note whether the meter hand is moving.
(The more the hand is moving, the greater the leakage.)
Leak checks must also be made if the train is dis-
assembled during the run to change a filter or to
replace any component.
0 Ensure that a fuel sample and gas analysis are taken to
calculate a material balance. This serves as a check
of flow rates obtained by pitot tube readings.
0 Record dry gas meter readings before and after test.
0 Record average velocity head and temperatures in duct
during test.
0 If impingers are used during test, observe whether they
are bubbling. If they are not, the sampling train is
either plugged or disconnected from the pump.
0 Check the cleaning procedure for the front half of the
train. Careless removal of filters or cleaning of
probes will result in lower calculated emissions. Look
for broken glass from probes or connectors. Test is
void if glass probe was broken during test. If glass
connectors are broken in transport from sampling site
to clean-up area, test is still valid. Be sure identi-
fication labels are properly attached to collection containers.
The probe should be brushed and rinsed with acetone thoroughly
to remove all particulates. The probe should be visually
inspected after cleaning to ascertain that all particulates
have been removed.
Check control panel periodically as outlined.
6-4
-------
0 For NO tests, check the mercury manometer to ensure
that ffask is evacuated to at least 20 inches Hg
absolute pressure. If this level cannot be reached, a
larger pump is needed.
0 For NO and S02 test, note whether the gas stream has a
negative or positive pressure. If a negative pressure
is present, precautions are needed (i.e., long probe,
sealed port) to ensure that no ambient air passed
through the train, which would result in calculated
emissions lower than those actually present. The
Federal Register states that the duct sampling point
cannot be less than 3 feet from the duct wall if the
cross-sectional area is greater than 50 square feet.
0 Observe gas analysis procedure for determining C^.
Technician should take at least three samples before
averaging readings. Variations greater than 0.5 per-
cent (grab sample) or 0.2 percent (integrated sample)
indicate gas mixture was not thoroughly bubbled in
reagents. Ask technician or crew leader when new
reagents were added to apparatus.
The inspector's role regarding emission monitoring
instruments is summarized below. The operating principles
of the instruments described previously are complex, and the
probability exists of encountering undetected errors. The
inspector can only be responsible for carrying out the fol-
lowing steps:
0 Note values on emission monitoring instrument. Gaseous
concentrations of S02 and NO in ppm and Ib emitted per
MM BTU are related during the compliance test. NSPS
are in terms of the latter units. During future tests,
only the ppm values are recorded from the monitors.
0 Check previous history of calibrations, malfunctions,
cleaning, repair, and trends of recorded emissions.
Regulations state that emission monitoring instruments
must be calibrated at least once per 24 hour operating
period. The inspector should note the calibration
frequency, and the error in readings prior to calibra-
tion. If the instrument readout drifts greatly, the
inspector should ask plant personnel to contact the
manufacturer for service.
Regulations also require that emissions be read to
within + 20 percent with a 95 percent confidence level. The
inspector should check instrument accuracy with manufacturer's
specifications.
6-5
-------
6.4 PERFORMANCE TEST CHECKLIST
The inspector must observe the steam process and emis-
sion tests simultaneously to ensure that data used in
determining plant performance are valid. He should also
complete a performance checklist, outlined on the following
page. If the inspector observes any additional parameters
the facility records that are directly related to emissions,
they should also be recorded.
In the event of a malfunction or upset, the enforcement
officer must inform the test crew leader that the sampling
trains are to be shut-off and removed from the ducts as
quickly as possible. If process changes or deviations occur,
the inspector is responsible for instructing the sampling
personnel whether to proceed with the run or temporarily
stop the test.
The enforcement officer keeps a log of any abnormal
operation, time of occurance, and return to representative
conditions. After reviewing emission test results, he can
decide whether the run is valid.
When the emission testing firm submits a test report,
results must be carefully checked and compared with data
recorded on the inspector's checklist. Thus, the checklist
both provides verification that the tests were properly con-
ducted and serves as the baseline for future inspections of
the facility. A suggested format for the contents of the
emission tests are presented in Appendix C.
6-6
-------
Table 6.1
NSPS INSPECTION CHECKLIST FOR STEAM-ELECTRIC GENERATORS
DURING PERFORMANCE TEST
COMPANY NAME.
SOURCE CODE NUMBER
COMPANY ADDRESS
NAME OF PLANT CONTACT.
UNIT DESIGNATION (TO BE TESTED)
STEAM CAPACITY MM BTU/hr
TURBOGENERATING CAPACITY megawatts
INITIAL START-UP DATE
REPRESENTATIVE PERFORMANCE ACHIEVEMENT DATE
TEST DATE
A. STEAM GENERATOR CHARACTERISTICS (See Plant Engineer)
Fuel Type Percentage %
D Coal
DOil
DGas
Firing Type
DFront Wall
D Opposed Wall
DVertical
D Tangential or Corner
Boiler Characteristics
QFly Ash Recirculation
[U Staged Firing
APC Device Type
D Scrubber
DESP
6-7
-------
NSPS INSPECTION CHECKLIST (Continued)
Heat Input
D Fuel Feed Meter
D Heat Rate Calculation
Fuel Analysis Source
Heating Value BTU lb.
^ gal,
Sulfur Content %
Ash Content %
6-8
-------
NSPS INSPECTION CHECKLIST (Continued)
B. INSTRUMENTATION DATA
Record the following data every 30 minutes during perfor-
mance test.
Parameter Units
Recording Time 24 hr
Steam Load Ib/hr
Air Load Ib/hr
C02 %
°2 %
Gas Exhaust Temp. °F
Flue Gas Recirc. Draft in. H~0
Oil Preheat Temp. °F
Oil Pressure psig
Atomizing Pressure psig
Heat Input
Fuel Feed lb, gal., ft3/hr
Heat Rate MM BTU/hr
Soot Blowing Time minutes
Monitors
Opacity %
S09 *
NO *
X
APC Device
Spark Rate sparks/min
Unit Voltage kv or v
Unit Current ma or a
PH
Liquid Solvent Rate gal./min
Pressure Drop in. H-O
Additive Rate Ib/hr
Stack Plume % opacity
Values
Indicate ppm or other units.
6-9
-------
NSPS INSPECTION CHECKLIST (Continued)
C. PRETEST DATA (SEE SAMPLING TEAM FIELD LEADER)
TEST COMPANY
FIELD LEADER
DUCT DIMENSIONS
in. x
NEAREST UPSTREAM OBSTRUCTION
NEAREST DOWNSTREAM OBSTRUCTION
NO. OF SAMPLING PORTS
NO. OF SAMPLING POINTS
NO. OF SAMPLING POINTS REQUIRED FROM
FIGURE 1.1 IN 40 CFR 60
Dl. PARTICULATE PERFORMANCE TEST
.in.? Area
TEST NO..
START TIME.
FINISH TIME.
Preliminary Traverse Run (Method 1)
Chosen Nozzle Diameter in.
Moisture Determination (Method 4)
Percent Moisture
ml Collected/Gas Volume
Train Leak Check
Fuel Sample Taken
Yes
D
D
Dry Gas Meter Reading Before Test
Dry Gas Meter Reading After Test
Volume Sampled
Test Duration
ft'
.ft
ft
No
n
n
2 ml ft
n
n
•3
* Test ft @
0
Test ft @
n
n
(time)
(time)
ft3
minutes
Average of Meter Orifice Pressure Drop.
Average Duct Temperature
inches of H20
6-10
-------
NSPS INSPECTION CHECKLIST (Continued)
Velocity Head at Sampling Point inches H90
Meter AH@*
Repetition Start Time
Repetition Finish Time
D2. SO2 PERFORMANCE TEST
Test Repetition
Duct Static Pressure QPositive QNegative
Port Protection Against Air Leakage QYes
Probe Length inches
D3. NO PERFORMANCE TEST
X "•" "'"
Test Repetition.
Duct Static Pressure DPositive QNegative
Port Protection Against Air Leakage DYes DNo
Mercury Manometer Head
Left Leg in. Hg
Right Leg in. Hg
Total Vacuum in. Hg
E. CLEANUP PROCEDURE
Filter Condition D Dry D Wet
Probes D Unbroken Q Broken
Glass Connectors D Unbroken D Broken
Cleanup Sample Spillage D None D Slight D Major
Sample Bottle Identification D Yes D No
Acetone Blank Taken D Yes Q No
NO Flasks Shaken Adequately Q Yes Q No
* Orifice pressure differential pumping 0.75 ft of dry air at
standard conditions.
6-11
-------
REFERENCES FOR CHAPTER 6
1. Emission Testing Compliance Manual, PEDCo-Environmental
Specialists, Inc., EPA Contract No. 68-02-0237, Task No.
19, August, 1974.
6-12
-------
7.0 INSPECTION PROCEDURES
The inspector's periodic visits will enable him to deter-
mine the plant emission control status. These subsequent
inspections, described in Section 7.1, are as rigorous as the
orignial performance inspection. An inspection checklist is
prepared in Section 7.2. Section 7.3 describes follow-up
procedures after completing a review of the steam generator.
7.1 FUTURE INSPECTION PROCEDURES
The inspector's frequency of future visits is governed by
each agency's policy. A quarterly inspection is recommended
unless malfunctions or complaints dictate more frequent inspec-
tions.
Major emphasis of the inspection is placed upon checking
facility records and emission monitors. Records reveal
whether the facility is in compliance between inspections.
Properly functioning NO and S02 instruments quickly indicate
gaseous emission levels. Control device inspection will give
an indication of particulate emissions.
The following procedure should be followed in the order
shown whenever possible. The format enables the inspector to
tour the plant and monitor instruments under actual conditions.
Any questionable areas can be investigated later by looking at
records after touring the facility.
OUTSIDE OBSERVATIONS
0 Note plume opacity and color. Opacities greater than 20
percent are in violation.
EMISSION MONITORS
0 Check automatic zero.
° Check calibration of instrument using calibrated gas
cylinders.
CONTROL EQUIPMENT
0 Read gages on precipitator indicating power input and
spark rate.
7-1
-------
0 Read pressure drop gages on scrubbers used for particu-
late emission control.
RECORDS
0 Scan emission monitoring records; note each occurrence
with corresponding level when opacity, S02 and NO
values are over standards. (Gas sampling instruments
read concentrations in ppm. Appendix D contains graphs
for converting ppm values to Ib/MM BTU). Standards for
opacity, S02 and NO are shown in Table 2.5. Sulfur
dioxide allowable standards are approximately 600 ppm
for coal and 400 ppm for oil usage. If NO concen-
trations of 400 ppm for coal, 200 ppm for c§il, and 150
ppm for natural gas are exceeded, the steam generator
is in violation of NSPS.
0 Check calibration records. Instruments must be zeroed
and calibrated daily.
0 Scan fuel records, noting instances of sulfur and ash
over values stated below. Fuel analyses must be per-
formed at least once per week on representative coal
samples. Steam generators attempting to achieve S02
standards by burning low-sulfur fuel have the option of
analyzing and recording fuel constituents daily, or
monitoring SO^. Plants attempting to meet S0_ stan-
dards by burning low-sulfur fuel must use coal or oil.
with a sulfur content less than 0.75a and 0.8 percent,
respectively. Ash content of coal must be similar to
values during performance test.
0 Review steam flow or electrical output records to
determine whether unit capacity was exceeded. Fuel
burning rate, electrical output, and hourly generation
must be measured and recorded daily. Note values and
frequency occurrence of steam or electrical generation
over that during the performance test.
0 Scan records of control device performance for (ESP)
power requirements and (scrubber) pressure drops.
Steam generators are not required to maintain control
device records; records should be kept in a format
similar to the one shown in Figure 4.2. Power pressure
losses are indicative of performance degradation.
0 Review records of malfunction. Note the number of
identical occurrences and the action taken to alleviate
future occurrences.
Assumes 12,500 BTU/lb
Assumes 15,000 BTU/gal
7-2
-------
7.2 INSPECTION CHECKLIST
An inspection form, Table 7.1, follows which is derived
from procedures in Section 7.1.
7.3 INSPECTION FOLLOW-UP PROCEDURES
The inspector's affiliations may be with a Federal,
state or local agency. Interagency communications are
necessary to keep personnel aware of the status of new steam
generators.
If the inspector has evidence to cite the facility
after a tour of the grounds, he should precisely state the
reasons on the citation. A citation at this point can only
be given for definite violations or failure to keep required
records. Table 7.2 outlines follow-up procedures after
inspecting the plant and reviewing records. The guidelines
are for general situations; unique circumstances may be
encountered that call for different action.
7-3
-------
Table 7.1
NSPS INSPECTION CHECKLIST FOR STEAM-ELECTRIC GENERATORS
AFTER PERFORMANCE TEST
COMPANY NAME
SOURCE CODE NUMBER
COMPANY ADDRESS
NAME OF PLANT CONTACT,
UNIT DESIGNATION
STEAM CAPACITY
TURBOGENERATING CAPACITY_
INSPECTION DATE
A. PRE-ENTRY OBSERVATIONS Time
Stack Plume Equivalent Opacity (circle one):
0 10 20 30 40 50 75
Opacity Regulation O in compliance
r-, not in
u compliance
Smoke Color
B. EMISSION MONITORS Time
D Transmittance
Concentrations QOpacity ^
Sulfur Dioxide ppm
Nitrogen Oxides ppm
Calibration Gas Monitor
Gas cone, pressure readout Satis. Unsat,
(ppm) (psig) (ppm)
so2 . D D
NOV D D
X
7-4
-------
NSPS INSPECTION CHECKLIST (Continued)
C. CONTROL EQUIPMENT
ELECTROSTATIC PRECIPITATOR
SECTION
Primary current (amps)
Primary voltage (volts)
Secondary current (ma)
Secondary voltage (kv)
Spark rate (spk/min)
1
2
3
4
SCRUBBER
SECTION
Pressure drop
scrubber (in.
across
H20)
1
2
3
4
ADDITIONAL OBSERVATIONS:
7-5
-------
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7-6
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Table 7.2 FOLLOW-UP PROCEDURES AFTER
INSPECTING STEAM GENERATING FACILITY
Compliance parameter
Course of action
Visual emissions
Opacity, SO_, NO
monitors
Control equipment
instrumentation
Records
The November 12, 1974 Federal Register states that EPA is in the
process of defining a method to enforce opacity standards, such
as specifing the number of readings per hour above the opacity
standard that would constitute a violation.
a) Not in operation - issue citation
b) Not properly calibrated or zeroed - advise plant personnel
to implement a satisfactory program which might include
services of outside consultants.
a) Not in operation - request in follow-up letter schedule
to repair instruments.
b) Values indicating unit out of compliance - Determine
reasons - have plant take appropriate corrective action.
a) Not kept - Issue citation
b) Values indicating plant is out of compliance:
i. monitors - If SO. and/or NO standards are exceeded
more than 5 times' a month for intervals
less than 4 hours, issue citation.
- If SO, and/or NO standard is exceeded more
than 8 continuous hours, issue citation
- If opacity standard is ever exceeded for
more than 2 continuous hours, issue citation.
ii. fuel records - If ash/sulfur is frequently over values
during performance test, determine reason.
iii. generating capacity - Disregard short-term peak loads.
If electrical output/fuel usage is con-
sistently higher than emission test
values, request another performance test.
c) Daily instrument zero/calibration - Issue citation if instru-
ments are not zeroed and calibrated within 3 or more consecu-
tive days.
d) Fuel analysis - Units without SO_ control equipment must
analyze fuel daily.
e) Malfunction records - If complete information (time, levels,
malfunction description, problem correction methods) is not
recorded for all malfunctions, issue citation.
7-7
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APPENDIX A
STANDARDS OF PERFORMANCE FOR NEW
STATIONARY SOURCES
CODE OF FEDERAL REGULATIONS
(See 40 CFR 60 for complete
sampling procedures)
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Chapter 1 - Environmental Protection Agency
SUBCHAPTER C - AIR PROGRAMS
PART 60 - STANDARDS OF PERFORMANCE
FOR NEW STATIONARY SOURCES
Subpart A - General Provisions
§60.1 Applicability.
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 com-
menced 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.
§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 Administrator of the
Environmental Protection Agency or his authorized represen-
tative .
(c) "Standard" means a standard of performance proposed
or promulgated under this part.
(d) "Stationary source" means any building, structure,
facility, or installation which emits or may emit any air
pollutant.
(e) "Affected facility" means, with reference to a
stationary source, any apparatus to which a standard is
applicable.
(f) "Owner or operator" means any person who owns,
leases, operates, controls, or supervises an affected facil-
ity or a stationary source of which an affected facility is
a part.
(g) "Construction" means fabrication, erection, or
installation of an affected facility.
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(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 pollutant (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 considered 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 standard under this part becomes
applicable to such facility, as provided by §60.1, the
affected facility is designed to accomodate such alternative
use.
(i) "Commenced" means, with respect to the definition
of "new source" in section 111(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.
(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 oxides of nitrogen
except nitrous oxide, as measured by test methods set forth
in this part.
(1) "Standard conditions" means a temperature of 20°C
(68°F) and a pressure of 760 mm of Hg (29.92 in. of Hg).
(m) "Proportional sampling" means sampling at a rate
that produces a constant 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) "Start-up" means the setting in operation of an
affected facility for any purpose.
(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 pre-
ventable upset condition or preventable equipment breakdown
shall not be considered malfunctions.
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(r) "Hourly period" means any 60 minute period com-
mencing on the hour.
(s) "Reference method" means any method of sampling
and analyzing for an air pollutant as described in Appendix
A to this part.
(t) "Equivalent method" means any method of sampling
and analyzing for an air pollutant which have been demon-
strated to the Administrator's satisfaction to have a con-
sistent and quantitatively known relationship to the refer-
ence methods, under specified conditions.
(u) "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.
(v) "Particulate matter" means any finely divided
solid or liquid material, other than uncombined water, as
measured by Method 5 of Appendix A to this part or an
equivalent or alternative method.
(w) "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.
§60.4 Address.
All requests, applications, submittals, and other
communications to the Administrator pursuant to this part
shall be submitted in duplicate and addressed to the appro-
priate Regional Office of the Environmental Protection
Agency, to the attention of the Director, Enforcement
Division.
§60.5 Determination of construction or modification.
When requested to do so by an owner or operator, the
Administrator will make a determination of whether actions
taken or intended to be taken by such owner or operator
constitute construction or modification 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
modification for the purpose of providing technical advice
to the owner or operator.
(b)(1) A separate request shall be submitted for each
construction or modification project.
(2) Each request shall identify the location of such
project, and be accompanied by technical information de-
scribing the proposed nature, size, design, and method of
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operation of each affected facility involved in such project,
including information on any equipment to be used for mea-
surement or control of emissions.
(c) Neither a request for plans review nor advice
furnished by the Administrator in response to such request
shall (1) relieve an owner or operator of legal respon-
sibility 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 provi-
sion 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 notifica-
tion as follows:
(1) A notification of the anticipated date of initial
start-up 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 start-
up 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 start-up, shutdown, or
malfunction in operation of any affected facility.
(c) A written report of excess emissions as defined in
applicable subparts shall be submitted to the Administrator
by each owner or operator for each calendar 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 emis-
sions. Periods of excess emissions due to start-up, shut-
down, and malfunction shall be specifically identified. The
nature and cause of any malfunction (if known), the correc-
tive action taken, or preventive measures adopted shall be
reported. Each quarterly report is due by the 30th day
following the end of the calendar quarter. Reports are not
required for any quarter unless there have been periods of
excess emissions.
(d) Any owner or operator subject to the provisions of
this part shall maintain a file of all measurements, in-
cluding monitoring and performance testing measurements, and
all other reports and records required by all applicable
subparts. Any such instruments, reports and records shall
be retained for at least 2 years following the date of such
measurements, reports, and records.
§60.8 Performance tests.
(a) Within 60 days after achieving the maximum pro-
duction rate at which the affected facility will be op-
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erated, but not later than 180 days after initial start-up
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 Administrator with a written report
of the results of such performance test(s).
(b) Performance tests shall be conducted and data
reduced in accordance with the test methods and procedures
contained in each applicable subpart unless the Adminis-
trator (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 results of which he has
determined to be adequate for indicating whether a specific
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
satisfaction that the affected facility is in compliance
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.
(c) Performance tests shall be conducted under such
conditions as the Administrator shall specify to the plant
operator 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 during
periods of start-up, shutdown, and malfunction shall not
constitute representative conditions of performance tests
unless otherwise specified in the applicable standard.
(d) The owner and operator of an affected facility
shall provide the Administrator 30 days prior notice of the
performance test to afford the Administrator the opportunity
to have an observer 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 platform(s).
(4) Utilities for sampling and testing equipment.
(f) 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 condi-
tions occur in which one of the three runs must be discon-
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.
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§60.9 Availability of information.
(a) Emission data provided to, or otherwise obtained
by, the Administrator 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 other-
wise obtained by, the Administrator in accordance with the
provisions of this part shall be available to the public,
except that (1) upon a showing satisfactorily to the Admin-
istrator by any person that such records, reports, or in-
formation, or particular part thereof (other than emission
data), if made public, would divulge methods or processes
entitled to protection as trade secrets of such person, the
Administrator shall consider such records, reports, or
information, or particular part thereof, confidential in
accordance with the purposes of section 1905 of title 18 of
the United States Code, except that such records, reports,
or information, or particular part thereof, may be disclosed
to other officers, employees, or authorized representatives
of the United States concerned with carrying out the provi-
sions of the Act or when relevant in any proceeding under
the Act; and (2) information received by the Administrator
solely for the purposes of §60.5 and §60.8 shall not be
disclosed if it is so identified by the owner or operator as
being a trade secret or commercial or financial information
which such owner or operator considers confidential.
§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 emission standard or
limitation applicable to an affected facility, provided that
such emission standard or limitation is not less stringent
than the standard applicable 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.
§60.11 Compliance with standards and maintenance require-
ments.
(a) Compliance with standards in this part, other than
opacity standards, shall be determined only by performance
tests established by §60.8.
(b) Compliance with opacity standards in this part shall
be determined by conducting observations in accordance with
Reference Method 9 in Appendix A of this part. Opacity readings
of portions of plumes which contain condensed, uncombined
water vapor shall not be used for purposes of determining
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compliance with opacity standards. The results of continuous
monitoring by transmissometer which indicate that the opacity
at the time visual observations were made was not in excess
of the standard are probative 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 I in Appendix B of this part, has been properly
maintained and (at the time of the alleged violation) calibrated,
and that the resulting data have not been tampered with in
any way.
(c) The opacity standards set forth in this part shall
apply at all times except during periods of start-up, shut-
down, or malfunction, and as otherwise provided in the
applicable standard.
(d) At all times, including periods of start-up, shut-
down, and malfunction, owners and operators shall, to the
extent practicable, maintain and operate any affected fa-
cility including associated air pollution control equipment
in a manner consistent with good air pollution control
practice for minimizing emissions. Determination of whether
acceptable operating and maintenance procedures are being
used will be based on information available to the Adminis-
trator 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 affected facility may
request the Administrator to determine opacity of emissions
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 results 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 affected
facility is in compliance with all applicable standards for
which performance 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
facility and associated air pollution control equipment
was operated and maintained in a manner to minimize the
opacity of emissions during the performance tests; that the
performance tests were performed under the conditions esta-
blished by the Administrator; and that the affected facility
and associated air pollution control equipment were incapable
of being adjusted or operated to meet the applicable opacity
standard.
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(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 concentration emission standard. The Administrator will
promulgate the new opacity standard in the Federal Register.
§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 otherwise constitute a violation of an applicable
standard. Such concealment includes, 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 concentration of a pollutant in the gases discharged
to the atmosphere.
Subpart D - Standards of Performance
for Fossil-Fuel-Fired Steam Generators
§60.40 Applicability and designation of affected facility.
The provisions of this subpart are applicable 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 accommodate the
use of combustible materials, other than fossil fuels as
defined in this subpart, shall not bring the unit under the
applicablility of this subpart.
§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 generating 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 creating useful heat.
§60.42 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 provisions of this subpart shall
cause to be discharged into the atmosphere from any affected
facility any gases which:
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(1) Contain particulate matter in excess of 0.18 g per
million cal heat input (0.10 Ib per million BTU) derived
from fossil fuel.
(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.
§60.43 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 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 input (0.80 Ib per
million BTU) derived from liquid fossil fuel.
(2) 1.4 g per million cal heat input (1.2 Ib per
million BTU) derived from solid fossil fuel.
(b) When different fossil fuels are burned simulta-
neously in any combination, the applicable standard shall be
determined by proration using the following formula:
y(l.4) + z(2.2)
y + z
where:
y is the percentage of total heat input derived from
liquid fossil fuel, and
z is the percentage to total heat input derived from
solid fossil fuel.
(c) Compliance shall be based on the total heat input
from all fossil fuels burned, including gaseous fuels.
§60.64 Standard 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 part shall cause
to be discharged into the atmosphere from any affected
facility any gases which contain nitrogen oxides, expressed
as N02 in excess of:
TD 0.36 g per million cal heat input (0.20 Ib per
million BTU) derived from gaseous fossil fuel,
(2) 0.54 g per million cal heat input (0.30 Ib per
million BTU) derived from liquid fossil fuel.
(3) 1.26 g per million cal heat input (0.70 Ib per
million BTU) derived from solid fossil fuel (except lignite),
(b) When different fossil fuels are burned simulta-
neously is any combination, the applicable standard shall be
determined by proration. Compliance shall be determined by
using the following formula:
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x(0.36) + (0.54) + z(1.26)
x + y + z
where:
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
z is the percentage of total heat input derived from
solid fossil fuel (except lignite).
§60.45 Emission and fuel monitoring.
(a) There shall be installed, calibrated, 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 compliance 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 section shall be capable of monitoring
emission levels within_+20 percent with a confidence level
of 95 percent and shall be calibrated in accordance with the
method(s) of such instruments; instruments shall be subject
to manufacturers recommended zero adjustment and calibration
procedures at least once per 24-hour operating period unless
the manufacturer(s) specifies or recommends calibration at
shorter intervals, in which case such specifications or
recommendations shall be followed. The applicable method
specified in the appendix of this part shall be the ref-
erence method.
(c) The sulfur content of solid fuels, as burned, shall
be determined in accordance 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 accordance with the American Society
for Testing and Materials 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
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at least once per week and recorded. Where the steam gen-
erating unit is used to generate electricity, the average
electrical output and the minimum and maximum hourly gen-
eration rate shall be measured and recorded daily.
(g) For the purpose of reports required pursuant to
§60.7(a), periods of excess emissions that shall be reported
are defined as follows:
(1) Opacity. All hourly periods during which there are
three or more one-minute periods when the average opacity
exceeds 20 percent.
(2) Sulfur dioxide. Any two consecutive hourly periods
during which average sulfur dioxide emissions exceed 0.80
pound per million BTU heat input for solid fossil fuel
burning equipment or exceed 1.2 pound per million BTU heat
input for solid fossil fuel burning equipment; or for
sources which elect to conduct 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 consecutive hourly
periods during which the average nitrogen oxides emissions
exceed 0.20 pound per million BTU heat input for gaseous
fossil fuel burning equipment, or exceed 0.30 pound per
million BTU for liquid fossil fuel burning equipment, or
exceed 0.70 pound per million BTU heat input for solid
fossil fuel burning equipment.
§60.46 Test methods and procedures.
(a) The reference methods in Appendix A to this part,
except as provided for in §60.8(b), shall be used to deter-
mine compliance with the standards prescribed in §§60.42,
60.43, and 60.44 as follows:
(1) Method 1 for sample and velocity traverses;
(2) Method 2 for velocity and volumetric 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 concentration of S0?; and
(6) Method 7 for the concentration of NO .
(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 volumes, when necessitated by process variables or
other factors, may be approved by the Administrator.
(c) For Methods 6 and 7, the sampling site shall be the
same as that for determining volumetric flow rate. 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).
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(d) For Method 6, the minimum sampling time shall be 20
minutes and the minimum sample volume shall be 0.02 dscm
(0.71 dscf) except that smaller sampling times and sample
volumes, when necessitated by process variables or other
factors, may be approved by the Administrator. The sample
shall be extracted at a rate proportional to the gas veloc-
ity at the sampling point. The arithmetic average of two
samples shall constitute one run. Samples shall be taken at
approximately 30-minute intervals.
(e) For Method 7, each run shall consist of at least
four grab samples taken at approximately 15-minute inter-
vals. The arithmetic mean of the samples shall constitute
the run values.
(f) Heat input, expressed in cal per hr (BTU/hr), shall
be determined during each test period by multiplying the
heating value of the fuel by the rate of fuel burned.
Heating value shall be determined in accordance with ASTM
Method D2015-66 (Reapproved 1972), D240-64 (Reapproved
1973) , or D1826-64 (Reapproved 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) /or each run, emissions expressed in g/million cal
shall be determined by dividing the emission rate in g/hr by
the heat input. The emission rate shall be determined by
the equation g/hr = Q x c where Q = volumetric flow rate
of the total effluent in dscm/hr a§ determined for each run
in accordance with paragraph (a)(2) of this section.
(1) For particulate matter, c = particulate concen-
tration in g/dscm, as determined in accordance with para-
graph (a) (4) of this section.
(2) For SO2, c = SO- concentration in g/dscm, as
determined in accordance with paragraph (a)(5) of this
section.
(3) For NO , c = NO concentration in g/dscm, as
determined in accordance with paragraph (a)(6) of this
section.
A-13
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APPENDIX - TEST METHODS
Method 1 - Sample and Velocity Traverses
For Stationary Sources
1. Principle and Applicability
1.1 Principle. A sampling site and the number of
traverse points are selected to air in the extraction of a
representative sample.
1.2 Applicability. This method should be applied only
when specified by the test procedures for determining
compliance with the New Source Performance Standards.
Unless otherwise specified, this method is not intended to
apply to gas streams other than those emitted directly to
the atmosphere without further processing.
2. Procedure
2.1 Selection of a sampling site and minimum number of
traverse points.
2.1.1 Select a sampling site that is at least eight
stack or duct diameters downstream and two diameters upstream
from any flow disturbance such as a bend, expansion, contraction,
or visible flame. For rectangular cross section, determine
an equivalent diameter from the following equation:
equivalent diameter =2 Ma equation l-l
2.1.2 When the above sampling site criteria can be
met, the minimum number of traverse points is twelve (12).
2.1.3 Some sampling situations render the above sampling
site criteria impractical. When this is the case, choose a
convenient sampling location and use Figure 1-1 to determine
the minimum number of traverse points. Under no conditions
should a sampling point be selected within 1 inch of the
stack wall. To obtain the number of traverse points for
stacks or ducts with a diameter less than 2 feet, multiply
the number of points obtained from Figure 1-1 by 0.67.
2.1.4 To use Figure 1-1 first measure the distance
from the chosen sampling location to the nearest upstream
and downstream disturbances. Determine the corresponding
number of traverse points for each distance from Figure 1-1.
A-14
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0.5
1.0
NUMBER OF DUCT DIAMETERS UPSTREAM
(DISTANCE A)
1.8
2
S
3
FROM POINT OF ANV TYPE OF
DISTURBANCE 1BEND, EXPANSION, CONTRACTION. ETC.)
NUMBER OF DUCT. DIAMETERS DOWNSTREAM'
(DISTANCE 8)
Figure 1-1. Minimum number of traverse points.
Select the higher of the two numbers of traverse points, or
a greater value, such that for circular stacks the number is
a multiple of 4, and for rectangular stacks the number
follows the criteria of section 2.2.2.
2.2 Cross-sectional layout and location of traverse
points.
2.2.1 For circular stacks locate the traverse points
on at least two diameters according to Figure 1-2 and Table
1-1. The traverse axes shall divide the stack cross section
into equal parts.
Figure 1-2. Cross section of circular stack divided into
12 equal areas, showing location of traverse points at
centroid of each area.
A-15
-------
Table 1-1,. 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
14.7
29.5
70.5
85.3
95.6
8
3.3
10.5
19.4
32.3
67.7
80.6
89.5
96.7
10
2.5
8.2
14.6
22.6
34.2
65.8
77.4
85.4
91.8
97.5
12
2.1
6.7
11.8
17.7
25.0
35.5
64.5
65.0
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
93.2
16
T.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
91.5
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
26.1
31.5
39.3
60.7
68.5
73.9
78.2
82.0
85.4
88.4
91.3
94.0
96.5
9&.9
24
1.1
3.2
5.5
7.9
10.5
13.2
16.T
19.4
23.0
27.2
32.3
3.9.3
60.2
67.7
72.3
77.0
80.6
83.9
86.8
89.5
92.1
94.5
S6.8
93.9
2.2.2 For rectangular stacks divide the cross section
into as many equal rectangular areas as traverse points,
such that the ratio of the length to the width of the elemental
areas is between one and two. Locate the traverse points at
the centroid of each equal area according to Figure 1-3.
o
.......
o
o
1
1
o I o
1
J
1
f
O 1 0
1
i [ *
1
1
o
M »» _•«.• —
o
o
Figure 1-3. Cross section of rectangular stack divided into
12 equal areas, with traverse points at centroid of each area."
A-16
-------
3. References
Determining Dust Concentration in a Gas Stream, ASME
Performance Test Code #27, New York, N.Y., 1957.
Devorkin, Howard, et al., Air Pollution Source Testing
Manual, Air Pollution Control District, Los Angeles, Cali-
fornia, November 1963.
Methods for Determination of Velocity, Volume, Dust and
Mist Content of Gases, Western Precipitation Division of Joy
Manufacturing Co., Los Angeles, California, Bulletin WP-50,
1968.
Standard Method for Sampling Stacks for Particulate
Matter, In: 1971 Book of ASTM Standards, Part 23, Philadelphia,
Pennsylvania, 1971, ASTM Designation D-2928-71.
Method 2 - Determination of Stack Gas Velocity
and Volumetric Flow Rate (Type S Pitot Tube)
1. Principle and applicability
1.1 Principle. Stack gas velocity is determined from
the gas density and from measurement of the velocity head
using a Type S (Stauscheibe or reverse type) pitot tube.
1.2 Applicability. This method should be applied only
when specified by the test procedures for determining
compliance with the New Source Performance Standards.
2. Apparatus
2.1 Pitot tube - Type S (Figure 2-1), or equivalent,
with a coefficient within +5% over the working range.
2.2 Differential pressure gauge - Inclined manometer,
or equivalent, to measure velocity head to within 10% of the
minimum value.
2.3 Temperature gauge - Thermocouple or equivalent
attached to the pitot tube to measure stack temperature to
within 1.5% of the minimum absolute stack temperature.
2.4 Pressure gauge - Mercury-filled U-tube manometer,
or equivalent, to measure stack pressure to within 0.1 in.
Hg.
2.5 Barometer - To measure atmospheric pressure to
within 0.1 in. Hg.
2.6 Gas analyzer - To analyze gas composition for
determining molecular weight.
2.7 Pitot tube - Standard type, to calibrate Type S
pitot tube.
3. Procedure
3.1 Set up the apparatus as shown in Figure 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.
A-17
-------
PIPE COUPLING
TUBING ADAPTER
Figure 2-1. Pitot tube-manometer assembly.
3.2 Measure the static pressure in the stack.
3.3 Determine the stack gas molecular weight by gas
analysis and appropriate calculations as indicated in Method
3.
4. Calibration
4.1 To calibrate the pitot tube, measure the velocity
heat at some point in a flowing gas stream with both a Type
S pitot tube and a standard type pitot tube with known
coefficient. 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.
equation 2-1
where:
C
= Pitot tube coefficient of Type S pitot tube.
^test
C = Pitot tube coefficient of standard type pitot
pstd tube (if unknown, use 0.99)
A-18
-------
A = Velocity head measured by standard type pitot
pstd tube.
A = Velocity head measured by Type S pitot tube.
ptest
4.3 Compare the coefficients of the Type S pitot tube
determined first with one leg and then the other pointed
downstream. Use the pitot tube only if the two coefficients
differ by no more than 0.01.
5. Calculations
Use equation 2-2 to calculate the stack gas velocity.
Wave = Kncn< A/Ap)avg. n /(Vavg. equation 2-2
5 dvlj. p \> » ' ' *-
wlu?r.e :
(V ) = Stack gas velocity, feet per second (f.p.s.)
s avg.
K = 85.48 Upr- s-1—o-=r\ when these units are used,
p sec. Vlb.mole-°Rl
C = Pitot tube coefficient, dimensionless.
(T ) = Average absolute stack gas temperature, °R.
s avg.
(/Ap~) = Average velocity head of stack gas, inches
avg- H20 (see Figure 2-2).
P = Absolute velocity head of stack gas (wet basis),
s Ib/lb-mole.
M = Molecular weight of stack gas (wet basis), lb./lb.-
mole M,(1-B )+18B
d wo wo
M = Dry molecular weight of stack gas (from Method 3).
B = Proportion by volume of water vapor in 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 2-2 to determine the average stack gas velocity from
Equation 2-2.
A-19
-------
PLANT
DATE
RUN NO.
STACK DIAMETER, in.
BAROMETRIC PRESSURE, in. Hg
STATIC PRESSURE IN. STACK (Pg). in. Hg.
OPERATORS
SCHEMATIC OF STACK
CROSS SECTION
Traverse point
number
Velocity head.
in. H2O
Stack Temperature
AVERAGE:
Figure 2-2. Velocity traverse data,
A-20
-------
Use Equation 2-3 to calculate the stack gas volumetric
flow rate.
QS=3600(1-BWO)VSA
where:
T
std
(T.)
s'avy.
P,
L-\ equation 2-3
std j
Q = Volumetric flow rate, dry basis, standard conditions,
s ft.Vhr.
2
A = Cross-sectional area of stack, ft
T , j = Absolute temperature at standard conditions,
Std 530°R.
P . , = Absolute pressure at standard conditions,
S 29.92 inches Hg.
6. References
Mark, L. S., Mechanical Engineers' Handbook, McGraw-
Hill Book Co., Inc., New York, N.Y., 1951.
Perry, J. H., Chemical Engineers' Handbook, McGraw-Hill
Book Co., Inc., New York, N.Y., 1960.
Shigehara, R. T., W. F. Todd, and W. S. Smith, Significance
of Errors in Stack Sampling Measurements. Paper presented
at the Annual Meeting of the Air Pollution Control Associa-
tion, St. Louis, Missouri, June 14-19, 1970.
Standard Method for Sampling Stacks for Particulate
Matter, In: 1971 Book of ASTM Standards, Part 23, Philadelphia,
Pennsylvania, 1971, ASTM Designation D-2928-71.
Vennard J. D., Elementary Fluid Mechanics, John Wiley &
Sons, Inc., New York, N.Y., 1947.
Method 3 - Gas Anaylsis for Carbon Dioxide,
Excess Air, and Dry Molecular 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 applied only
when specified by the test procedures for determining
compliance with the New Source Performance Standards. The
test procedure will indicate whether a grab sample or an
integrated sample is to be used.
2. Apparatus
2.1 Grab sample (Figure 3-1).
A-21
-------
PROBE
FLEXIBLE TUBING
TO ANALYZER
FILTER (GLASS WOOL)
SQUEEZE BULB
Figure 3-1. Grab-sampling train.
2.1.1 Probe - Stainless steel or Pyrex glass, equipped
with a filter to remove particulate matter.
2.1.2 Pump - One-way squeeze bulb, or equivalent, to
transport gas sample to analyzer.
2.2 Integrated sample (Figure 3-2).
RATE METER
Wil
VALVE
AIR-COOLED CONDENSER / PUMP
PROBE
FILTER (GLASS WOOL}
RIGID CONTAINER'
QUICK DISCONNECT
,BAQ
Figure 3-2. Integrated gas - sampling train.
2.2.1 Probe - Stainless steel or Pyrex glass, equipped
with a filter to remove particulate matter.
2.2.2 Air-cooled condenser or equivalent - To remove
any excess moisture.
2.2.3 Needle valve - To adjust flow rate.
2.2.4 Pump - Leak-free, diaphragm type, or equivalent,
to pull gas.
2.2.5 Rate meter - To measure a flow range from 0 to
0.035 cfm.
Trade name.
A-22
-------
2.2.6 Flexible bag - Tedlar, or equivalent, with a
capacity of 2 to 3 cu. ft. Leak test the bag in the laboratory
before using.
2.2.7 Pitot tube - Type 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
varying with time or a sample traverse is conducted.
2.3 Analysis
2.3.1 Orsat analyzer, or equivalent.
3. Procedure
3.1 Grab sampling
3.1.1 Set up the equipment as shown in Figure 3-1,
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 analyzer.
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 all connections are tight and that
there are no leaks.
3.2.2 Sample at a rate proportional to the stack
velocity.
3 . 3 Analysis
3.3.1 Determine the CO-, O~ , and CO concentrations as
soon as possible. Make as many passes as are necessary to
give constant readings. If more than ten passes are necessary,
replace the absorbing solution.
3.3.2 For grab sampling, repeat the sampling 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 the analyses of
the sample until three consecutive analyses vary no more
than 0.2 percent by volume for each component being analyzed.
4 . Calculations
4.1 Carbon dioxide. Average the three consecutive
runs and report the results to the nearest 0.1% CC"2 -
4.2 Excess air. Use Equation 3-1 to calculate excess
air, and average the runs. Report the result to the nearest
0.1% excess air.
(%09) - 0.5(%CO)
x 100 equation 3-I
0.264(%N2) - (%02) + 0.5(%CO)
Trade name.
A-23
-------
where :
%EA = Percent excess air.
%0~ = Percent oxygen by volume, dry basis.
%l^2 - Percent nitrogen by volume, dry basis.
%CO = Percent carbon monoxide by volume, dry basis.
0.264 = Ratio of oxygen to nitrogen in air by volume.
4.3 Dry molecular weight. Use Equation 3-2 to calculate
dry molecular weight and average the runs. Report the
result to the nearest tenth.
equation 3-2
where:
M, = Dry molecular weight, Ib./lb-mole.
%CO~ = Percent carbon dioxide by volume, dry basis.
%0.? = Percent oxygen by volume, dry basis.
%N2 = Percent nitrogen by volume, dry basis.
0.44 = Molecular weight of carbon dioxide divided by
100.
0.32 = Molecular weight of oxygen divided by 100.
0.28 = Molecular weight of nitrogen and CO divided by
100.
5. References
Altshuller, A. P., et al., Storage of Gases and Vapors
in Plastic Bags, Int. J. Air & Water Pollution, 6:75-81,
1963.
Conner, William D. , and J. S. Nader, Air Sampling with
Plastic Bags, Journal of the American Industrial Hygiene
Association, 25:291-297, May-June 1964.
Devorkin, Howard, et al. , Air Pollution Source Testing
Manual, Air Pollution Control District, Los Angeles, Cali-
fornia, November 1963.
A-24
-------
Method 4 - Determination of Moisture in Stack Gases
1. Principle and applicability
1.1 Principle. Moisture is removed from the gas
stream, condensed, and determined volumetrically.
1.2 Applicability. This method is applicable for the
determination of moisture in stack gas only when specified
by test procedures for determining compliance with New
Source Performance Standards. This method does not apply
when liquid droplets are present in the gas stream^ and the
moisture is subsequently used in the determination of stack
gas molecular weight.
Other methods such as drying tubes, wet bulb-dry bulb
techniques, and volumetric condensation techniques may be
used.
2. Apparatus
2
2.1 Probe - Stainless steel or Pyrex glass sufficiently
heated to prevent condensation and equipped with a filter to
remove particulate matter.
2.2 Impingers - Two midget impingers, each with 30 ml.
capacity, or equivalent.
2.3 Ice bath container - To condense moisture in
impingers.
2.4 Silica gel tube (optional) - To protect pump and
dry gas meter.
2.5 Needle valve - To regulate gas flow rate.
2.6 Pump - Leak-free, diaphragm type, or equivalent,
to pull gas through train.
2.7 Dry gas meter - To measure to within 1% of the
total sample volume.
2.8 Rotameter - To measure a flow range from 0 to 0.1
c.f.m.
2.9 Graduated cylinder - 25 ml.
2.10 Barometer - Sufficient to read to within 0.1 inch
Hg.
2.11 Pitot tube - Type S, or equivalent, attached to
probe so that the sampling flow rate can be regulated
proportional to the stack gas velocity when velocity is
varying with time or a sample traverse- is conducted.
If liquid droplets are present in the gas stream, assume
the stream to be saturated, determine the average stack
gas temperature by traversing according to Method 1,
and use a psychrometric chart to obtain an approximation
of the moisture percentage.
Trade name.
A-25
-------
3.
Procedure
3.1 Place exactly 5 ml. distilled water in each impinger.
Assemble the apparatus without the probe as shown in Figure
4-1. Leak check by plugging the inlet to the first impinger
and drawing a vacuum. Insure that flow through the dry gas
meter is less than 1% of the sampling rate.
HEATED PROB
FILTER'(GLASS WOOL)
SILICA GEL TUBE
ROTAMETER
ICE BATH
rflDGET IMPINGERS
PUMP
DRY GAS METER
Figure 4-1. Moisture-sampling train.
3.2 Connect the probe and sample at a constant rate of
0.075 c.f.m. or at a rate proportional to the stack gas
velocity. Continue sampling until the dry gas meter registers
1 cubic foot 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 4-2.
LOCATION.
TEST
DATE
OPERATOR.
COMMENTS
BAROMETRIC PRESSURE
CLOCK TIME
GAS VOLUME THROUGH
METER. (Vm),
ft*
HOTAMETER SETTING
1t3/min
METER TEMPERATURE.
•t
Figure 4-2. Field moisture determination,
A-26
-------
3.3 After collecting the sample, measure the volume
increase to the nearest 0.5 ml.
4. Calculations
4.1 Volume of water vapor collected.
t3
nl Wf-Vj) equation 4-1
where: "" Pstd %()
V = Volume of water vapor collected (standard)
WC conditions), cu.ft.
Vf = Final volume of impinger contents, ml.
V. = Initial volume of impinger contents, ml.
R = Ideal gas constant, 21.83 inches Hg - cu.ft./lb.mole-
p _ = Density of water, 1 g./ml.
H2U
T , = Absolute temperature at standard conditions,
S 530°R.
P ., = Absolute pressure at standard conditions, 29.92
inches Hg.
MU r, = Molecular weight of water, 18 Ib./lb.-mole.
ri.~U
4.2 Gas volume.
V = V
me m
m
std
'std
T
where:
m
- 17.71 .-- (VmP,
in. Hg
mm
T
m
equation 4-2
V = Dry gas volume through meter at standard conditions,
me -r_
cu.ft.
V = Dry gas volume measured by meter, cu.ft.
m j ^
P = Barometric pressure at the dry gas meter, inches
Hg.
P' , = Pressure at standard conditions, 29.92 inches
Hg.
T . , = Absolute temperature at standard conditions,
Sta 530°R.
T = Absolute temperature at meter (°F+460), °R.
A-27
-------
4.3 Moisture content.
Bwo = v v +Bm= u-- +(°-°25) equation 4-3
vwc me
where :
wm
wc me vwc "me
B = Proportion by volume of water vapor in the gas
wo stream, dimensionless.
V = Volume of water vapor collected (standard conditions) ,
WC _^_i_
cu. ft.
V = Dry gas volume through meter (standard conditions) ,
lilt-*- r~ .
cu. ft.
B = Approximate volumetric proportion of water vapor
^^ in the gas stream leaving the impingers, 0.025.
5. References
Air Pollution Engineering Manual, Danielson, J. A.
(ed.), U.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 Control District, Los Angeles, Cali-
fornia, November 1963.
Methods for Determination of Velocity, Volume, Dust and
Mist Content of Gases, Western Precipitation Division of Joy
Manufacturing Co., Los Angeles, California, Bulletin WP-50,
1968.
Method 5 - Determination of Particulate
Emissions From Stationary Sources
1. Principle and applicability
1.1 Principle. Particulate matter is withdrawn
isokinetically from the source and its weight is determined
gravimetrically after removal of .uncombined water.
1.2 Applicability. This method is applicable for the
determination of particulate emissions from stationary
sources only when specified by the test procedures for
determining compliance with New Source Performance Standards.
2 . Apparatus
2.1 Sampling train. The design specifications of the
particulate sampling train used by EPA (Figure 5-1) are
described in APTD-0581. Commercial models of this train are
available.
A-28
-------
REVERSE-TYPE
PITOT TUBE
IMPINGER TRAIN OPTIONAL. HAY BE REPLACED
BY AN EQUIVALENT CONDENSER
HEATED AREA ^ILTER HOLDER / THERMOMETER CHECK
VALVE
..VAtUUM
LINE
IMPINGERS ICE BATH
BY-PASS VALVE
THERMOMETERS
DRY TEST METER
VACUUM
GAUGE
MAIN VALVE
AIR-TIGHT
PUMP
Figure 5-1. Particulate-sampling train.
2.1.1 Nozzle - Stainless steel (316) with sharp,
tapered leading edge. ,
2.1.2 Probe - Pyrex glass with a heating system
capable of maintaining a minimum gas temperature of 250°F at
the exit end during sampling to prevent condensation from
occurring. When length limitations (greater than about 8
ft.) are encountered at temperatures less than 600°F, Incoloy
825 , or equivalent, may be used. Probes for sampling gas
streams at temperatures in excess of 600°F must have been
approved by the Administrator.
2.1.3 Pitot tube - Type S, or equivalent, attached to
probe to monitor stack gas velocity.
2.1.4 Filter holder - Pyrexl glass with heating system
capable of maintaining minimum temperature of 225°F.
2.1.5 Impingers/Condenser - Four impingers connected
in series with glass ball joint fittings. The first, third,
and fourth impingers are of the Greenburg-Smith design,
modified by replacing the tip with a 1/2-inch ID glass tube
extending to one-half inch from the bottom of the flask.
The second impinger is of the Greenburg-Smith design with
the standard tip. A condenser may be used in place of the
impingers provided that the moisture content of the stack
gas can still be determined.
2.1.6 Metering system - Vacuum 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 an isokinetic sampling
rate and to determine sample volume.
2.1.7 Barometer - To measure atmospheric pressure to
+0.1 inches Hg.
Trade name.
A-29
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2.2 Sample recovery.
2.2.1 Probe brush - At least as long as probe.
2.2.2 Glass wash bottles - Two.
2.2.3 Glass sample storage containers.
2.2.4 Graduated cylinder - 250 ml.
2.3 Analysis.
2.3.1 Glass weighing dishes.
2.3.2 Desiccator.
2.3.3 Analytical balance - To measure to +0.1 mg.
3. Reagents
3.1 Sampling
3.1.1 Filters - Glass fiber, MSA 1106 BH , or equivalent,
numbered for identification and preweighed.
3.1.2 Silica gel - Indicating type, 6-16 mesh, dried
at 175°C (350°F) for 2 hours.
3.1.3 Water.
3.1.4 Crushed ice.
3.2 Sample recovery.
3.2.1 Acetone - Reagent grade.
3.3 Analysis
3.3.1 Water. i
3.3.2 Desiccant - Drier.ite, 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 gram approximately 200 g. of silica gel. Label a
filter of proper diameter, 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 impingers, 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 sampling
site by plugging up the inlet to the filter holder and pulling
a 15 in. Hg vacuum. A leakage rate not in excess of 0.02
c.f.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 more
ice during the run to keep the temperature 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.
Trade name.
Dry using Drierite1 at 70°F +10°F.
A-30
-------
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
conditions 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; sampling 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-0576
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 with the sampling recovery process
described in section 4.2.
IOCATIOI
WtHATO«
OAtE
MM NO.
MOOT 801 NO.
irmtHj
C FACTO*
Al»IENTTCV««ATUK
ASSWCD MOUIME. »
Hum xn scnwo
NOtUE CXAKTEI. In _
FKOIC Hf ATM SETTING.,
SCHEMATIC OF STACK CROSS StC1W
TIAVEK3KMT
Nuvni
TOrAt
SAMFIDM
TIK
M.ri*.
AV(R«CE
STATIC
PKESUK
»st. !•. H»
Si Ad
TWEUIUC
Hsi.'f
vtiocm
HEAD
Ufj).
mssu*c
DVTEKNnAl
Acioa
OTIFlCt
KTEI
(•HI.
feHfO
OASSAWU
VOIUW
CW. h*
6AS SAWIE TilVEUtUK
AT EWT GAS MTtN
imn
IT«UI.«F
*<1
ountr
""oui1-"'
Avq.
A*c)
SAuaE lot
TEMPtftATUK.
"*
TWPtfl*TU»E
OFCU
UAVIMG
COnotmtB OR
LAST MPINCCR
•r
Figure 5-2. Particulate field data.
4.2 Sample recovery. Exercise care in moving the
collection train from the test site to the sample recovery
area to minimize the loss of collected sample or the gain of
extraneous particulate matter. Set aside a portion of the
acetone used in the sample recovery as a blank for analysis.
Measure the volume of water from the first three impingers,
then discard. Place the samples in containers as follows:
Container No. 1. Remove the filter from its holder,
place in this container, and seal.
A-31
-------
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 the
fourth impinger to the original container and seal. Use a
rubber policeman as an aid in removing silica gel from the
impinger.
4.3 Analysis. Record the data required on the example
sheet shown in Figure 5-3. Handle each sample container as
follows:
PLANT.
DATE_
RUN NO..
CONTAINER
NUMBER
1
2
•MHBHHMKkHMK^MMMMHHWMM
TOTAL
WEIGHT OF PARTICULATE COLLECTED,
mg
FINAL WEIGHT
TARE WEIGHT
:x
WEIGHT GAIN
FINAL
INITIAL
LIQUID COLLECTED
TOTAL VOLUME COLLECTED
VOLUME OF LIQUID
WATER COLLECTED
IMPINGER
VOLUME.
ml
SILICA GEL
WEIGHT,
a
9* ml
CONVERT WEIGHT OF WATER TO VOLUME BY DIVIDING TOTAL WEIGHT
INCREASE BY DENSITY OF WATER, (1 g. ml):
- VOLUME WATER, ml
Figure 5-3. Analytical data.
A-32
-------
Container No. 1. Transfer the filter and any loose
particulate matter from the sample container to a tared
glass weighed dish, desiccate, and dry to a constant weight.
Report 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 pressure. Desiccate and dry to a constant weight.
Report results to the nearest 0.5 mg.
Container No. 3. Weigh the spent silica gel and report
to the nearest gram.
5. Calibration
Use methods and equipment which have been approved by
the Administrator to calibrate the orifice meter, pitot
•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°F, 29.92
inches Hg) by using Equation 5-1.
AH
=V
fT
std
where:
mstd m T
m
13.6
P,
std
17.71
in.Hg
'P
V
bar
13.6
m
T
m
equation 5-I
V = Volume of gas sample through the dry gas meter
std (standard conditions), cu. ft.
V = Volume of gas sample through the dry gas meter
(meter conditions), cu. ft.
T . -, = Absolute temperature at standard conditions,
StCl 530°R.
T = Average dry gas meter temperature, °R.
P. = Barometric pressure at the orifice meter,
inches Hg.
AH = Average pressure drop across the orifice meter,
inches H?0.
13.6 = Specific gravity of mercury.
P . , = Absolute pressure at standard conditions, 29.92
inches Hg.
A-33
-------
6.3 Volume of water vapor.
'RTstd
Pstd
! 1
=
n «„-,, CU" ft
0.0474 ml.
V,
equation 5-2
where:
V
w
= Volume of water vapor in the gas sample (standard
std conditions), cu. ft.
V, = Total volume of liquid collected in impingers and
c silica gel (see Figure 5-3) , ml.
H
ri
M.
= Density of water, 1 g./ml.
= Molecular weight of water, 18 Ib./lb.-mole.
R = Ideal gas constant, 21.83 inches Hg-cu. ft./lb.-
mole-°R.
T . , = Absolute temperature at standard conditions,
sta 530°R.
P . , = Absolute pressure at standard conditions, 29.92
inches Hg.
6.4 Moisture content.
V
B
wstd
where:
wo w + w
mstd wstd
equation 5-3
B
wo
V
w
V
m
= Proportion by volume of water vapor in the gas
stream, dimensionless.
= Volume of water in the gas sample (standard
std conditions), cu. ft.
= Volume of gas sample through the dry gas meter
std (standard conditions), cu. ft.
6.5 Total particulate weight. Determine the total
particulate catch from the sum of the weights on the analysis
data sheet (Figure 5-3).
6.6 Concentration.
6.6.1 Concentration in gr./s.c.f.
0.0154
V
mstd
equation 5-4
A-34
-------
where:
c' = Concentration of particulate matter in stack gas,
5 gr./s.c.f., dry basis.
M = Total amount of particulate matter collected, mg.
V
m
= Volume of gas sample through dry gas meter
std (standard conditions), cu. ft.
6.6.2 Concentration in Ib./cu. ft.
1
IIL
cs =
453,600 mg.| '"" fi Mn
—g - = 2.205 X10'6 n-11-
mstd mstd
equation 5-5
where:
C = Concentration of particulate matter in stack
gas, Ib./s.c.f., dry basis.
453,600 = Mg/lb.
M = Total amount of particulate matter collected,
mg.
V
m
= Volume of gas sample through dry gas meter
std (standard conditions), cu. ft.
6.7 Isokinetic variation.
+
M>
m
13.6
0VsPsAn
X100
1.667
min.
sec.
0.00267
in.
Hg
-cu. ft.
ml.- °R
V
'c+
Vm
Tm
Pbar
4-
AH
13.6.
where:
equation 5-6
I = Percent of isokinetic sampling.
= Total volume of liquid collected in impingers
"c and silica gel (See Fig. 5-3), ml.
_ = Density of water, 1 g./ml.
)
R = Ideal gas constant, 21.83 inches Hg-cu. ft./
Ib. mole-°R.
A-35
-------
MH n = Molecular weight of water, 18 Ib./lb. -mole.
V = Volume of gas sample through the gas meter
(meter conditions) , cu. ft.
T = Absolute average dry gas meter temperature
m (See Figure 5-2) , °R.
P, = Barometric pressure at sampling site,
inches Hg.
AH = Average pressure drop across the orifice
(see Fig. 5-2), inches H_0.
£ .
T = Absolute average stack gas temperature
(see Fig. 5-2) , °R.
0 = Total sampling time, min.
V = Stack gas velocity calculated by Method 2,
Equation 2.2, ft. /sec.
P = Absolute stack gas pressure, inches Hg.
A = Cross-sectional area of nozzle, sq. ft.
6.8 Acceptable results. The following range sets the
limit on acceptable isokinetic sampling results :
If 90% <_! £110%, the results are acceptable, otherwise,
reject the results and repeat the test.
7. Reference.
Addendum to Specifications for Incinerator Testing at
Federal Facilities, PHS , NCAPC , Dec. 6, 1967.
Martin, Robert M. , Construction Details of Isokinetic
Source Sampling Equipment, Environmental Protection Agency,
APTD-0581.
Rom, Jerome J. , Maintenance, Calibration, and Operation
of Isokinetic Source Sampling Equipment, Environmental
Protection Agency, APTD-0576.
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 Control Associa-
tion, St. Louis, Mo., June 14-19, 1970.
Smith, W. S., et.al., Stack Gas Sampling Improved and
Simplified with New Equipment, APCA paper No. 67-119, 1967.
Specifications for Incinerator Testing at Federal
Facilities, PHS, NCAPC, 1967.
A-36
-------
Method 6 - Determination of Sulfur Dioxide
Emissions from Stationary Sources
1. Principle and applicability
1.1 Principle. A gas sample is extracted from the
sampling point in the stack. The acid mist, including
sulfur trioxide, is separated from the sulfur dioxide. The
sulfur dioxide fraction is measured by the barium-thorin
titration method.
1.2 Applicability. This method is applicable for the
determination of sulfur dioxide emissions from stationary
sources only when specified by the test procedures.for
determining compliance with New Source Performance Standards,
2. Apparatus
2.1 Sampling. See Figure 6-1.
PROBE (END PACKED
WITH QUARTZ OR ^f STACK WALL
PYREX WOOL) i V^ MIDGET BUBBLER MIDGET IMPINGERS
GLASS WOOL
TYPE S PITOT TUBE
SILICA GEL DRYING TUBE
THERMOMETER
PUMP
DRY GAS METER ROTAMETER
Figure 6.1. SO- sampling train.
2.1.1 Probe - Pyrex1 glass, approximately 5 to 6 mm,
ID, with a heating system to prevent condensation and a
filtering medium to remove particulate matter including
sulfuric acid mist.
2.1.2 Midget bubbler - One, with glass wool packed in
top to prevent sulfuric acid mist carryover.
2.1.3 Glass wool.
2.1.4 Midget impingers - Three.
2.1.5 Drying tube - Packed with 6 to 16 mesh indicating-
type silica gel, or equivalent, to dry the sample.
Trade name.
A-37
-------
2.1.6 Valve - Needle valve, or equivalent, to adjust
flow rate.
2.1.7 Pump - Leak-free, vacuum type.
2.1.8 Rate meter - Rotameter or equivalent, to measure
a 0-10 s.c.f.h. flow range.
2.1.9 Dry gas meter - Sufficiently accurate to measure
the sample volume within 1%.
2.1.10 Pitot tube - Type S, or equivalent, necessary
only if a sample traverse is required, or if stack gas
velocity varies with time.
2.2 Sample recovery.
2.2.1 Glass wash bottles - Two.
2.2.2 Polyethylene storage bottles - To store impinger
samples.
2.3 Analysis.
2.3.1 Pipettes - Transfer type, 5 ml. and 10 ml. sizes
(0.1 ml. divisions) and 25 ml. size (0.2 ml. divisions).
2.3.2 Volumetric flasks - 50 ml., 100 ml., and 1,000
ml.
2.3.3 Burettes - 5 ml. and 50 ml.
2.3.4 Erlenmeyer flask - 125 ml.
3. Reagents
3.1 Sampling.
3.1.1 Water - Deionized, distilled.
3.1.2 Isopropanol, 80% - Mix 80 ml of isopropanol with
20 ml of distilled water.
3.1.3 Hydrogen peroxide, 3% - dilute 100 ml. of 30%
hydrogen peroxide to 1 liter with distilled water. Prepare
fresh daily.
3.2 Sample recovery.
3.2.1 Water - Deionized, distilled.
3.2.2 Isopropanol, 80%.
3.3 Analysis.
3.3.1 Water - Deionized, distilled.
3.3.2 Isopropanol.
3.3.3 Thorin indicator - 1-(o-arsonophenylazo)-2-
naphthol-3, 6-disulfonic acid, disodium salt (or equivalent).
Dissolve 0.20 g. in 100 ml. distilled water.
3.3.4 Barium perchlorate (0.01 N) - Dissolve 1.95 g.
of barium perchlorate [Ba(C104)2.3H20] in 200 ml. distilled
water and dilute to 1 liter with isopropanol. Standardize
with sulfuric acid. Barium chloride may be us^d
3.3.5 Sulfuric acid standard (0.01 N) - Purchase or
standardize to +0.0002 N against 0.01N NaOH which has
previously been standardized against potassium acid phthalate
(primary standard grade).
A-38
-------
4. Procedure
4.1 Sampling.
4.1.1 Preparation of collection train. Pour 15 ml. of
80% isopropanol into the midget bubbler and 15 ml. of 3%
hydrogen peroxide into each of the first two midget impingers,
Leave the final midget impinger dry. Assemble the train as
shown in Figure 6-1. Leak check the sampling train at the
sampling site by plugging the probe inlet and pulling a 10
inches Hg vacuum. A leakage rate not in excess of 1% ®f the
sampling rate is acceptable. Carefully release the probe
inlet plug and turn off the pump. Place crushed ice around
the impingers. Add more ice during the run to keep the
temperature of the gases leaving the last impinger at 70°F
or less.
4.1.2 Sample collection. Adjust the sample flow rate
proportional to the stack gas velocity. Take readings at
least every five minutes and when significant changes in
stack conditions necessitate additional adjustments in flow
rate. To begin sampling, position the tip of the probe at
the first sampling point and start the pump. Sample propor-
tionally throughout the run. At the conclusion of each run,
turn off the pump and record the fina'l readings. Remove the
probe from the stack and disconnect it from the train.
Drain the ice bath and purge the remaining part of the train
by drawing clean ambient air through the system for 15
minutes.
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 polyethylene
shipment bottle. Rinse the three midget impingers and the
connecting tubes with distilled water and add these washings
to the same storage container.
4.3 Sample analysis. Transfer the contents of the
storage container to a 50 ml. volumetric flask. Dilute to
the mark with deionized, distilled water. Pipette a 10 ml.
aliquot of this solution into a 125 ml. Erlenmeyer flask.
Add 40 ml. of isopropanol and two to four drops of thorin
indicator. Titate to a pink endpoint using 0.01 N barium
perchlorate. Run a blank with each series of samples.
5. Calibration
5.1 Use standard methods and equipment which have been
approved by the Administrator to calibrate the rotameter,
pitot tube, dry gas meter, and probe heater.
5.2 Standardize the barium perchlorate against 25 ml.
of standard sulfuric acid containing 100 ml. of isopropanol.
6. Calculations
6.1 Dry gas volume. Correct the sample volume measured
by the dry gas meter to standard conditions (70°F and 29.92
inches Hg) by using equation 6-1.
A-39
-------
m
m
std
'std
'm
[bar
Pstd
op I \l p
= 17 71 mr bar
in.Hg
m
equation 6-1
where:
vm 4-fi = Volume of gas sample through the dry gas meter
(standard conditions) , cu. ft.
V = Volume of gas sample through the dry gas meter
(meter conditions) , cu. ft.
T , = Absolute temperature at standard conditions,
530°R.
T = Average dry gas meter temperature, °R.
P. = Barometric pressure at the orifice meter,
inches Hg.
P , = Absolute pressure at standard conditions, 29.92
inches Hg.
6.2 Sulfur dioxide concentration.
'SO,
Ib.-l.
g.-ml.
(vt
- Vtb> M
soln
va
m.»j
equation 6-2
where:
= Concentration of sulfur dioxide at standard
conditions, dry basis, Ib./cu. ft.
— 5
7.05x10 = Conversion factor, including the number of
grams per gram equivalent of sulfur dioxide
(32 g./g.-eq.), 453.6 g./lb., and 1,000
ml./l., Ib.-l./g.-ml.
V = Volume of barium perchlorate titrant used for the
sample, ml.
V , = Volume of barium perchlorate titrant used for the
blank, ml.
N = Normality of barium perchlorate titrant, g.-eg./l.
V n = Total solution volume of sulfur dioxide, 50 ml.
soln
V = Volume of sample aliquot titrated, ml.
a
A-40
-------
V = Volume of gas sample through the dry gas meter
mstd (standard conditions), cu. ft., see Equation 6-1.
7. References
Atmospheric Emissions from Sulfuric Acid Manufacturing
Processes, U.S. DHEW, PHS, Division of Air Pollution, Public
Health Service Publication No. 999-AP-13, Cincinnati, Ohio,
1965.
Corbett, P. F., The Determination of SO2 and SO., in
Flue Gases, Journal of the Institute of Fuel; 24:237-243,
1961.
Matty, R. E. and E. K. Diehl, Measuring Flue-Gas SO-
and SO.,, Power 101:94-97, November, 1957.
Patton, W. F. and J. A. Brink, Jr., New Equipment and
Techniques for Sampling Chemical Process Gases, J. Air
Pollution Control Association, 13, 162 (1963).
Method 7 - Determination of Nitrogen Oxide
Emissions from Stationary Sources
1. Principle and applicability
1.1 Principle. A grab sample is collected in an
evacuated flask containing a dilute sulfuric acid-hydrogen
peroxide absorbing solution, and the nitrogen oxides, except
nitrous oxide, are measured colorimetrically using the phenoldi-
sulfonic acid (PDS) procedure.
1.2 Applicability. This method is applicable for the
measurement of nitrogen oxides from stationary sources only
when specified by the test procedures for determining compliance
with New Source Performance Standards.
2. Apparatus
2.1 Sampling. See Figure 7-1.
2.1.1 Probe - Pyrex1 glass, heated, with filter to
remove particulate matter. Heating is unnecessary if the
probe remains dry during the purging period.
2.1.2 Collection flask - Two-liter, Pyrex-^- round
bottom 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
equivalent, capable of measuring 2°F intervals from 25° to
125°F.
2.1.5 Vacuum line - Tubing capable of withstanding a
vacuum of 3 inches Hg absolute pressure, with "T" connection
and T-bore stopcock, or equivalent.
Trade name.
A-41
-------
PROBE
Cu_ZZ
FILTER
CROWD-CLASS SOCKET,
5 NO. Mft
3 WAY STOPCOCK."
T-1ORE. *. PffltJt,
2-mm BORE, tim OO
FLASK-.
FLASK SHI Eta,
GROUND GLASS CONE,
STANDARD TAPER, GROUND GLASS
J SLEEVE NO, 24/40 SOCKET, 5 NO. 12*
' PtREX
v-
—-! fOAM ENCASEMINT
BOILING fLASK •
2-LIUR ROUND BOTTOM SHORT NECK,
miHJSIHVE NO. 24/40
Figure 7.1. Sampling train, flask valve, and flask.
2.1.6 Pressure gauge - U-tube manometer, 36 inches,
with 0.1-inch divisions, or equivalent.
2.1.7 Pump - Capable of producing a vacuum of 3 inches
Hg absolute pressure.
2.1.8 Squeeze bulb - One way.
2.2 Sample recovery.
2.2.1 Pipette or dropper.
2.2.2 Glass storage containers - Cushioned for shipping.
2.2.3 Glass wash bottle.
2.3 Analysis.
2.3.1 Steam bath.
2.3.2 Beakers or casseroles - 250 ml., one for each
sample and standard (blank).
2.3.3 Volumetric pipettes - 1, 2, and 10 ml.
2.3.4 Transfer pipettes - 10 ml. with 0.1 ml. divisions.
2.3.5 Volumetric flask - 100 ml., one for each sample,
and 1,000 ml. for the standard (blank).
2.3.6 Spectrophotometer - To measure absorbance at 420
nm.
2.3.7 Graduated cylinder - 100 ml. with 1.0 ml. divisions,
2.3.8 Analytical balance - To measure to 0.1 mg.
3. Reagents
3.1 Sampling.
3.1.1 Absorbing solution - Add 2.8 ml. of concentrated
H2SC-4 to 1 liter of distilled water. Mix well and add 6 ml.
of 3 percent hydrogen peroxide. Prepare a fresh -solution
weekly and do not expose to extreme heat or direct sunlight.
A-42
-------
3.2 Sample recovery.
3.2.1 Sodium hydroxide (IN) - Dissolve 40 g. NaOH in
distilled water and dilute to 1 liter.
3.2.2 Red litmus paper.
3.2.3 Water - Deionized, distilled.
3.3 Analysis.
3.3.1 Fuming sulfuric acid - 15 to 18% by weight free
sulfur trioxide.
3.3.2 Phenol - White solid reagent grade.
3.3.3 Sulfuric acid - Concentrated reagent grade.
3.3.4 Standard solution - Dissolve 0.5495 g. potassium
nitrate (KNOo) in distilled water and dilute to 1 liter.
For the working standard solution, dilute 10 ml. of the
resulting solution to 100 ml. with distilled water. One ml.
of the working standard solution is equivalent to 25 yg
nitrogen dioxide.
3.3.5 Water - Deionized, distilled.
3.3.6 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 for 2 hours. Store in a dark, stoppered
bottle.
4. Procedure.
4.1 Sampling.
4.1.1 Pipette 25 ml. of absorbing solution into a
sample flask. 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. Turn the flask valve and the pump valve to
their "evacuate" positions. Evacuate the flask to at least
3 inches Hg absolute pressure. Turn the pump valve to its
"vent" position and turn off the pump. Check the manometer
for any fluctuation in the mercury level. If there is a
visible change over the span of one minute, check for leaks.
Record the initial volume, temperature, and barometric
pressure. Turn the flask valve to its "purge" position, and
then 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 flask valve area, heat the probe and
purge until the condensation disappears. Then turn the pump
valve to its "vent" position. Turn the flask valve to its
"sample" position and allow sample to enter the flask for
about 15 seconds. After collecting the sample, turn the
flask valve to its "purge" position and disconnect the flask
from the sampling train. Shake the flask for 5 minutes.
4.2 Sample recovery.
4.2.1 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
A-43
-------
flask to the manometer, and record the flask pressure and
temperature along with the barometric pressure. Transfer
the flask contents to a container for shipment or to a 250
ml. beaker for analysis. Rinse the flask with two portions
of distilled water (approximately 10 ml.) and add rinse
water to the sample. For a blank use 25 ml. of absorbing
solution and the same volume of distilled water as used in
rinsing the flask. Prior to shipping or analysis, add
sodium hydroxide (IN) dropwise into both the sample .and the
blank until alkaline to litmus paper (about 25 to 35 drops
in each).
4.3 Analysis.
4.3.1 If the sample has been shipped in a container,
transfer the contents to a 250 ml. beaker using a small
amount of distilled water. Evaporate the solution to dry-
ness on a steam bath and then cool. Add 2 ml. phenol-
disulfonic acid solution to the dried residue and triturate
thoroughly with a glass rod, making sure the solution con-
tacts all the residue. Add 1 ml. distilled water and four
drops of concentrated sulfuric acid. Heat the solution on a
steam bath for 3 minutes with occasional stirring. Cool,
add 20 ml. distilled water, mix well by stirring, and add
concentrated ammonium hydroxide dropwise with constant
stirring until alkaline to litmus paper. Transfer the
solution to a-100 ml. volumetric flask and wash the beaker
three times with 4 to 5 ml. portions of distilled water.
Dilute to the mark and mix thoroughly. If the sample contains
solids, transfer a portion of the solution to a clean, dry
centrifuge tube, and centrifuge, or filter a portion of the
solution. Measure the absorbance of each sample at 420 nm.
using the blank solution as a zero. Dilute the sample and
the blank with a suitable amount of distilled water if
absorbance falls outside the range of calibration.
5. Calibration
5.1 Flask volume. Assemble the flask and flask valve
and fill with water to the stop-cock. Measure the volume of
water to +10 ml. Number and record the volume on the flask.
5.2 "Spectrophotometer. Add 0.0 to 16.0 ml. of standard
solution to a series of beakers. To each beaker add 25 ml.
of absorbing solution and add sodium hydroxide (IN) dropwise
until alkaline to litmus paper (about 25 to 35 drops).
Follow the analysis procedure of section 4.3 to collect
enough data to draw a calibration curve of concentration in
yg. NOX per sample versus absorbance.
6. Calculations
6.1 Sample volume.
A-44
-------
Tstd
rstd
P.
T.
= 17.71
in. Hg
(Vf-25ml.)
TfTi
equation 7-I
where:
V = Sample volume at standard conditions (dry basis), ml,
sc
T , = Absolute temperature at standard conditions,
sca 530°R.
P , , = Pressure at standard conditions, 29.92 inches
std Hg.
V, = Volume of flask and valve, ml.
V = Volume of absorbing solution, 25 ml.
a
Pf = Final absolute pressure of flask, inches Hg.
P. = Initial absolute pressure of flask, inches Hg.
Tf = Final absolute temperature of flask, °R.
T. = Initial absolute temperature of flask, °R.
6.2 Sample concentration. Read yg N02 for each sample
from the plot of yg. NO- versus absorbance.
m
V
sc
lib.
cu. ft.
1.6XKT
ml. '
sc
equation 7-2
where:
C = Concentration of NO as NO- (dry basis), Ib./s.c.f.
J\ £
m = Mass of NO~ in gas sample, yg.
V = Sample volume at standard conditions (dry basis),
sc ml.
7. References
Standard Methods of Chemical Analysis. 6th ed. New
York, D. Van Nostrand Co., Inc., 1962, vol. 1, p. 329-330.
Standard Method of Test for Oxides of Nitrogen in
Gaseous Combustion Products (Phenoldisulfonic Acid Procedure),
In: 1968 Book of ASTM Designation D-1608-60, p. 725-729.
A-45
-------
Jacob, M. B., The Chemical Analysis of Air Pollutants,
New York, N. Y., Interscience Publishers, Inc., 1960, vol.
10, p. 351-356.
Method 8 - Determination of Sulfuric Acid Mist
and Sulfur Dioxide Emissions From Stationary Sources
1. Principle and applicability
1.1 Principle. A gas sample is extracted from a
sampling point in the stack and the acid mist Including
sulfur trioxide is separated from sulfur dioxide. Both
fractions are measured separately by the barium-thorin
titration method.
1.2 Applicability. This method is applicable to
determination of sulfuric acid mist (including sulfur trioxide)
and sulfur dioxide from stationary sources only when specified
by the test procedures for determining compliance with the
New Source Performance Standards.
2.
Apparatus
2.1 Sampling. See Figure 8-1. Many of the design
specifications of this sampling train are described in APTD-
0581.
PROBE
REVERSE-TYPE
PITOT TUBE
THERMOMETER
CHECK
VALVE
.VACUUM
LINE
VACUUM
GAUGE
DRY TEST MEItR
IR-TIGHT
PUMP
Figure 8.1. Sulfuric acid mist sampling train.
A-46
-------
2.1.1 Nozzle - Stainless steel (316) with sharp,
tapered leading edge.
2.1.2 Probe - Pyrex^ glass with a heating system to
prevent visible condensation during sampling.
2.1.3 Pitot tube - Type S, or eqivalent, attached to
probe to monitor stack gas velocity.
2.1.4 Filter holder - Pyrexl glass.
2.1.5 Impingers - Four 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 Greenburg-
Smith design, modified by replacing the standard tip with a
1/2-inch ID glass tube extending to one-half inch from the
bottom of the impinger flask. Similar collection systems,
which have been approved by the Administrator, may be used.
2.1.6 Metering system - Vacuum 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 an isokinetic sampling
rate and to determine sample volume.
2.1.7 Barometer - To measure atmospheric pressure to
+0.1 inch Hg.
2.2 Sample recovery.
2.2.1 Wash bottles - Two.
2.2.2 Graduated cylinders - 250 ml., 500 ml.
2.2.3 Glass sample storage containers.
2.2.4 Graduated cylinder - 250 ml.
2.3 Analysis
2.3.1 Pipette - 25 ml., 100 ml.
2.3.2 Burette - 50 ml.
2.3.3 Erlenmeyer flask - 250 ml.
2.3.4 Graduated cylinder - 100 ml.
2.3.5 Trip balance - 300 g. capacity, to measure to
+0.05 g.
2.3.6 Dropping bottle - To add indicator solution.
3. Reagents
3.1 Sampling.
3.1.1 Filters - Glass fiber, MSA type 1106 BH, or
equivalent, of a suitable size to fit in the filter holder.
3.1.2 Silica gel - Indicating type, 6-16 mesh, dried
at 175°C (350°F) for 2 hours.
3.1.3 Water - Deionized, distilled.
3.1.4 Isopropanol, 80% - Mix 800 ml. of isopropanol
with 200 ml. of deionized, distilled 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 Water - Deionized, distilled.
3.2.2 Isopropanol, 80%.
Trade name.
A-47
-------
3.3 Analysis.
3.3.1 Water - Deionized, distilled.
3.3.2 Isopropanol.
3.3.3 Thorin indicator - 1-(o-arsonophenylazo)-2-
naphthol-3, 6-disulfonic acid, disodium salt (or equivalent).
Dissolve 0.20 g. in 100 ml. distilled water.
3.3.4 Barium perchlorate (0.01N) - Dissolve 1.95 g. of
barium perchlorate [Ba(C04)2•3H20] in 200 ml. distilled
water and dilute 1 liter with isopropanol. Standardize with
sulfuric acid.
3.3.5 Sulfuric acid standard (0.01N) - Purchase or
standardize to +0.0002N against 0.01 N NaOH which has previously
been standardized against primary standard potassium acid
phthalate.
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. Place 100 ml.
of 80% isopropanol in the first impinger, 100 ml. of 3%
hydrogen peroxide in both the second and third impingers,
and about 200 g. of silica gel in the fourth impinger.
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 c.f.m. at a
vacuum of 15 inches Hg is acceptable. 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 the gases leaving the
last impinger at 70°F or less.
4.1.3 Train operation. For each run, record 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
pointing directly into the gas stream. Start the pump and
immediately adjust the flow to isokinetic conditions.
Maintain isokinetic sampling throughout the sampling period.
Nomographs are available which aid in the rapid adjustment
of the sampling rate without other computations. APTD-0576
details the procedure for using these nomographs. At the
conclusion of each run, turn off the pump and record the
final readings. Remove the probe from the stack and disconnect
A-48
-------
it from the train. Drain the ice bath and purge the remaining
part of the train by drawing clean ambient air through the
system for 15 minutes.
PUVT
IOC AT ION
OrffiATOR ___.
DATE
SUN NO,
SAMPIE BOX N0j
METtRBOXNO._
AJW11NT UWERATURf_
BAROMETRIC PRESSURE..
ASSUMED MOISTURE. %_
PRO«E LENGTH, m._
NOHLt DIAMETER. In,
PRO6E HEATER SETTING,
SCHEMATIC Of STACK CROSS SECTION
TRAVERSE FOffaT
NUVBER
TOTAL
SVPLING
7IH£
(•). win.
AVERAGE
STATIC
PPESSUFT
|P$], In. Ha
STACK
TTJ.'P£RAnjRE
fTs)."'
VTLOCITV
MCAO
u PS).
PRESSURE
DEFERENTIAL
ACROSS
wince
METtR
< A H),
in. H;0
C.ftS SA'tPlt
VOtUVE
IVni). ft*
GAS SAWIE TtMPEHMVfflE
AT DRY GAS METER
INLET
ITm ,„».'*
Avg.
OUIUT
lt«M1.'f
Avg
Avg.
SA'.'ptr BOJI
TEMPERATURE.
•F
IMPING! R
TtAWERATlrtt.
•F
Figure 8.2. Field data.
4.2 Sample recovery.
4.2.1 Transfer the isopropanol from the first impinger
to a 250 ml. graduated cylinder. Rinse the probe, first
impinger, and all connecting glassware before the filter
with 80% isopropanol. Add the rinse solution to the cylinder.
Dilute to 250 ml. with 80% isopropanol. Add the filter to
the solution, mix, and transfer to a suitable storage container.
Transfer the solution from the second and third impingers to
a 500 ml. graduated cylinder. Rinse all glassware between
the filter and silica gel impinger with deionized, distilled
water and add this rinse water to the cylinder. Dilute to a
volume of 500 ml. with deionized, distilled water. Transfer
the solution to a suitable storage container.
4.3 Analysis.
4.3.1 Shake the container holding isopropanol and the
filter. If the filter breaks up, allow the fragments to
settle for a few minutes before removing a sample. Pipette
a 100 ml. aliquot of sample into a 250 ml. Erlenmeyer flask
and add 2 to 4 drops of thorin indicator. Titrate the
sample with barium perchlorate to a pink end point. Make
sure to record volumes. Repeat the titration with a second
aliquot of sample. Shake the container holding the contents
of the second and third impingers. Pipette a 25 ml. aliquot
of sample into a 250 ml. Erlenmeyer flask. Add 100 ml. of
A-49
-------
isopropanol and 2 to 4 drops of thorin indicator. Titrate
the sample with barium perchlorate to a pink end point.
Repeat the titration with a second aliquot of sample.
Titrate the blanks in the same manner as the samples.
5. Calibration
5.1 Use standard methods and equipment which have been
approved by the Administrator to calibrate the orifice
meter, pitot tube, dry gas meter, and probe heater.
5.2 Standardize the barium perchlorate with 25 ml. of
standard sulfuric acid containing 100 ml. of isopropanol.
6. Calculations
6.1 Dry gas volume. Correct the sample volume measured
by the dry gas meter to standard conditions (70°F, 29.92
inches Hg) by using Equation 8-1.
/T
V = V
mstd m IT
std
m
u
bar
13.6
P
std
17.71
in. Hg
rbar
AH
13.6
m
equation 8-1
m
where:
= Volume of gas sample through the dry gas meter
(standard conditions), cu. ft.
V = Volume of gas sample through the dry gas meter
(meter conditions), cu. ft.
T ., = Absolute temperature at standard conditions,
Std 530°R.
T = Average dry gas meter temperature, °R.
P = Barometric pressure at the orifice meter, inches
bar TT
Hg.
AH = Pressure drop across the orifice meter, inches
H2°*
13.6 = Specific gravity of mercury.
P , = Absolute pressure at standard conditions, 29.92
3 inches Hg.
6.2 Sulfuric acid concentration.
A-50
-------
'H2S04= 1.08X10
(Vt-Vtb)(N)
soln
u
a
equation 8-2
m
std
where:
C
go = Concentration of sulfuric acid at standard
2 4 conditions, dry basis, Ib./cu.ft.
-4
1.08 x 10 = Conversion factor including the number of
grams per gram equivalent of sulfuric acid
(49 g./g.-eq.), 453.6 g./lb., and 1,000
ml./l., Ib.-l./g.-ml.
V = Volume of barium perchlorate titrant used for the
sample, ml.
V , = Volume of barium perchlorate titrant used for the
blank, ml.
N = Normality of barium perchlorate titrant, g.-eq./l.
V , = Total solution volume of sulfuric acid (first
so n impinger and filter), ml.
V = Volume of sample aliquot titrated, ml.
a
Vm , = Volume of gas sample through the dry gas meter
s (standard conditions), cu. ft., see Equation
8-1.
6.3 Sulfur dioxide concentration.
Cso2"
7-05X1° g,ml.
(vt-vtb)(N)
Vsoln
Va
m.*j
equation 8-3
where:
'SO,
Concentration of sulfur dioxide at standard
conditions, dry basis, Ib./cu.ft.
7.05 x 10
-5
Conversion factor including the number of
grams per gram equivalent of sulfur dioxide
(32 g./g.-eq.) 453.6 g./lb., and 1,000
ml./l., Ib.-l./g.-ml.
A-51
-------
V. = Volume of barium perchlorate titrant used for the
sample, ml.
V , = Volume of barium perchlorate titrant used for the
blank, ml.
N = Normality of barium perchlorate titrant, g.-eq./l.
V oln = Total solution volume of sulfur dioxide (second
and third impingers), ml.
V = Volume of sample aliquot titrated, ml.
ci
V = Volume of gas sample through the dry gas meter
std (standard conditions), cu. ft., see Equation 8-1.
7. References
Atmospheric Emissions from Sulfuric Acid Manufacturing
Processes, U.S. DHEW, PHS, Division of Air Pollution, Public
Health Service Publication No. 999-AP-13, Cincinnati, Ohio,
1965.
Corbett, D. F., The Determination of SC>2 and 803 in
Flue Gases, Journal of the Institute of Fuel, 24:237-243,
1961.
Martin, Robert M., Construction Details of Isokinetic
Source Sampling Equipment, Environmental Protection Agency,
Air Pollution Control Office Publication No. APTD-0581.
Patton, W. F., and J. A. Brink, Jr., New Equipment and
Techniques for Sampling Chemical Process Gases, J. Air
Pollution Control Assoc. 13, 162 (1963).
Rom, Jerome J., Maintenance, Calibration, and Operation
of Isokinetic Source Sampling Equipment, Environmental
Protection Agency, Air Pollution Control Office Publication
No. APTD-0576.
Shell Development Co. Analytical Department, Determination
of Sulfur Dioxide and Sulfur Trioxide in Stack Gases,
Emeryville Method Series, 4516/59a.
Method 9 - Visual1 Determination of Opacity
of Emissions From Stationary Sources
1. Principle and applicability
1.1 Principle. The relative opacity of an emission
from a stationary source is determined visually by a qualified
observer.
1.2 Applicability. This method is applicable for the
determination of'the relative opacity of visible emissions
from stationary sources only when specified by test procedures
for determining compliance with the New Source Performance
Standards.
A-52
-------
2.
Procedure
2.1 The qualified observer stands at approximately 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 percent opacity. A minimum of 25
readings is taken.
M N^,
- -
0
—
—
.
IS
—
,0
—
--
—
•>
—
—
—
M"C
-
»
_..
—
—
—
15
JO
—
46
—
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Ob*«'v*r >
n.t. _
Tit* „
D.itmci to itack
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W,«d to.id . . -<
Jnt.l n..ml,t(-..t rtlrf,ngf _ ,. —
Sum of nof. t«cord«J
Toll! noi f»»dir>fl»
1 —
3.
Figure 9.1. Field data.
Qualifications
3.1 To certify as an observer, a candidate must complete
a smokereading course conducted 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 percent
A-53
-------
in each category. The smoke generator used to qualify the
observers 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 Pollution Control District, Chapter
2, Schedule 6, Regulation 4, Prohibition, Rule 50, 17 p.
Kudluk, Rudolf, Ringelmann Smoke Chart, U.S. Department
of Interior, Bureau of Mines, Information Circular No. 8333,
May 1967.
A-54
-------
APPENDIX B
VISIBLE EMISSION OBSERVATION FORM
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B-3
-------
APPENDIX C
SUGGESTED CONTENTS OF STACK TEST REPORTS
C-l
-------
CONTENTS OF STACK TEST REPORTS
In order to adequately assess the accuracy of any test
report the basic information listed in the following suggested
outline is necessary:
1. Introduction. Background information pertinent to the
test is presented in this section. This information
shall include, but not be limited to, the following:
a. Manufacturer's name and address.
b. Name and address of testing organization.
c. Names of persons present, dates and location of
test.
d. Schematic drawings of the process being tested
showing emission points, sampling sites, and stack
cross section with' the sampling points labeled and
dimensions indicated.
2. Summary. This section shall present a summary of test
findings pertinent to the evaluation of the process
with respect to the applicable emission standard. The
information shall include, but not be limited to, the
following:
a. A summary of emission rates found.
b. Isokinetic sampling rates achieved if applicable.
c. The operating level of the process while the tests
were conducted.
3. Procedure. This section shall describe the procedures
used and the operation of the sampling train and process
during the tests. The information shall include, but
not be limited to, the following:
a. A schematic drawing of the sampling devices used
with each component designated and explained in a
legend.
b. A brief description of the method used to operate
the sampling train and procedure used to recover
samples.
C-2
-------
Analytical Technique. This section shall contain a
brief description of all analytical techniques used to
determine the emissions from the source.
Data and Calculations. This section shall include all
data collected and calculations. As a minimum, this
section shall contain the following information:
a. All field data collected on raw data sheets.
b. A log of process and sampling train operations.
c. Laboratory data including blanks, tare weights,
and results of analysis.
d. All emission calculations.
Chain of Custody. A listing of the chain of custody of
the emission test samples.
Appendix:
a. Calibration work sheets for sampling equipment.
b. Calibration or process logs of process parameters.
C-3
-------
APPENDIX D
GAS CONVERSION GRAPHS
D-l
-------
nia ww/qi 'Noissiwa ssvw zos
D-2
-------
CO
CO
CO
CO
CVJ
i
CONVERSION FROM ppm TO Ib/MM BTU
3% 02 IN FLUE GAS
200 400 600 800
N02 CONCENTRATION IN FLUE GAS, ppm
1000
1200
Figure D2. N0x conversion graph: ppm to Ib/MM BTU heat input,
D-3
-------
TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO.
EPA 340/1-75-002
3. RECIPIENT'S ACCESSIOI^NO.
4. TITLE AND SUBTITLE
Inspection Manual for the Enforcement of
New Source Performance Standards: Fossil-
Fuel-Fired Steam Generators
5. REPORT DATE
Issue: February 1975
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
T. W. Devitt and N. J. Kulujian
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORG "\NIZATION NAME AND ADDRESS
PEDCo-Environmental Specialists, Inc.
Suite 13, Atkinson Square
Cincinnati, Ohio 45246
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
68-02-1073
12. SPONSORING AGENCY NAME AND ADDRESS
13. TYPE OF REPORT AND PERIOD COVERED
Environmental Protection Agency
Office of Air and Water Programs
Research Triangle Park, North Carolina 27711
Final
14. SPONSORING AGENCY CODE
15. SUPPLEMENTARY NOTES
One of a series of NSPS Enforcement Inspection Manuals
16. ABSTRACT
This document presents guidelines to enable enforcement personnel
to determine whether new or modified fossil-fuel-fired steam gen-
erators comply with New Source Performance Standards (NSPS). Key
parameters identified during the performance test are used as a
comparative base during subsequent inspections to determine the
facility's compliance status. The steam generating process,
atmospheric emissions from these processes, and emission control
methods are described. The inspection methods and types of
records to be kept are discussed in detail.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
c. cos ATI Field/Group
Steam electric power plants
Air pollution control
Verification inspection
Performance tests
New Source Perform-
ance Standards
Enforcement
Emission testing
13 B
14 D
18. DISTRIBUTION STATEMENT
Release unlimited
19. SECURITY CLASS (This Report)
Unclassified
21. NO. OF PAGES
140
20. SECURITY CLASS (Thispage)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
U.S. GOVERNMENT PRINTING OFFICE: 1975—210-810:37
------- |