United States
Environmental Protection
Agency
Office of Air Quality
Planning and Standards
Research Triangle ParkNC 27711
EPA-450/3-83-005b
June 1990
Air
Distillation
Operations in
Synthetic Organic
Chemical
Manufacturing
Industry-
Background
Information for
Promulgated
Standards
Final
EIS
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EPA-450/3-83-005b
Distillation Operations in
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EPA-450/3-83-005b
Distillation Operations in
Synthetic Organic Chemical
Manufacturing Industry —
Background Information
for Promulgated Standards
Emissions Standards Division
U S F-virrr--^rrtal Protection Agency
F^'.-vf^, I-b.cii-y (5?L-16)
27."' b- Dearborn btreat, Room 167.0
Chicago, IL 60604
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Air and Radiation
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
June 1990
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ENVIRONMENTAL PROTECTION AGENCY
Background Information
and Final Environmental Impact Statement
for Volatile Organic Compound Emissions from
Distillation Processes in
Synthetic Organic Chemical Manufacturing
Prepared by:
Director, Emission Standards Division
U. S. Environmental Protection Agency
Research Triangle Park, North Carolina 27711
1 The promulgated standards of performance will limit emissions of
volatile organic compounds from new, modified, and reconstructed
distillation processes. Section 111 of the Clean Air Act
(42 U S. C. 7411), as amended, directs the Administrator to establish
standards of performance for any category of new stationary source of
air pollution that ". . . causes or contributes significantly to air
pollution which may reasonably be anticipated to endanger public health
or welfare."
2 Copies of this document have been sent to the following Federal
Departments: Labor, Health and Human Services, Defense, Transportation,
Agriculture, Commerce, Interior, and Energy; the National Science
Foundation; State and Territorial Air Pollution Program Administrators;
EPA Regional Administrators; Local Air Pollution Control Officials;
Office of Management and Budget; and other interested parties.
3. For additional information contact:
Mr. Doug Bell
Standards Development Branch (MD-13)
U. S. Environmental Protection Agency
Research Triangle Park, N. C. 27711
Telephone: (919) 541-5568
4. Copies of this document may be obtained from:
U. S. EPA Library (MD-35)
Research Triangle Park, N. C. 27711
Telephone: (919) 541-2777
National Technical Information Service
5285 Port Royal Road
Springfield, VA 22161
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This report has been reviewed by the Emission Standards Division of the Office
of Air Quality Planning and Standards, EPA, and approved for publication.
Mention of trade names or commercial products is not intended to constitute
endorsement or recommendation for use. Copies of this report are available
through the Library Services Office (MD-35), U.S. Environmental Protection
Agency, Research Triangle Park, N.C. 27711, or from National Technical
Information Services, 5285 Port Royal Road, Springfield, Virginia 22161.
ii
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TABLE OF CONTENTS
PAGE
TITLE PAGE 1
DISCLAIMER n
LIST OF TABLES •' 1X
1.0 SUMMARY 1"1
1.1 SUMMARY OF CHANGES SINCE PROPOSAL I'1
1.1.1 Affected Facility Designation .1-2
1.1.2 Applicability of the Standards 1-2
1.1.3 Exemptions 1-3
1.1.4 Negligibly Photochemically Reactive
Compounds 1"3
1.1.5 Monitoring, Testing, and Reporting/RecordKeeping
Requirements -1"4
1.1.6 Flare Operating Specifications 1-5
1.1.7 TRE Coefficients !"5
1.1.8 Incorporation of a TRE Index Value Above
Which Monitoring and Recordkeeping Are
Not Required l~6
1.1.9 Definitions ....... I"6
1.1.10 Net Heating Value Equation 1-7
1.1.11 Miscellaneous I"7
1.2 SUMMARY OF IMPACTS OF PROMULGATED ACTION 1-7
1.2.1 Alternatives to Promulgated Action 1-7
1.2.2 Environmental Impacts of Promulgation Action. . . 1-8
1 2 3 Energy and Economic Impacts of Promulgated
Action 1'8
1.2.4 Other Considerations I'8
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TABLE OF CONTENTS (CONTINUED)
PAGE
2.0 SUMMARY OF PUBLIC COMMENTS 2-1
2.1 APPLICABILITY OF THE STANDARDS 2-1
2.1.1 Exemption Request for Specific Chemicals and
Processes 2-1
2.1.2 Exemption Requests for Low Level Production of
Listed Chemicals 2-11
2.1.3 Applicability to Petroleum Refineries 2-14
2.1.4 Date of Initial Performance Testing 2-16
2.1.5 Low Vent Stream Flowrate and Design Capacity
Exemption .2-17
2.1.6 Applicability Date of Standards 2-19
2.1.7 Batch Distillation Exemption .2-20
2.1.8 Request for Removal of Chemicals of Negligible
Photochemical Reactivity From Regulation 2-20
2.2 SELECTION OF AFFECTED FACILITY 2-21
2.2.1 Designation of Affected Facility. ... 2-21
2.3 DEFINITIONS 2-26
2.3.1 Definition of Vent Stream 2-26
2.3.2 Definition of Distillation Operations 2-26
2.3.3 Definition of Process Heaters 2-27
2.3.4 Definition of TOC 2-27
2.3.5 Definition of Corrosive Vent Stream 2-28
2.4 SELECTION OF BDT 2-28
2.4.1 NOX Emissions from BDT and BACT Review 2-28
2.4.2 Flare Specifications . 2-29
2.4.3 Catalytic Versus Thermal Incineration 2-33
2.4.4 Recovery Devices and Emissions Reduction .... 2-35
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TABLE OF CONTENTS (CONTINUED)
PAGE
2.5 COST ESTIMATION 2"37
2.5.1 Control Cost for Flares and Incinerators .... 2-37
2.5.2 Control Cost for Flare Systems 2-39
2.5.3 Cost of Monitoring Incinerator Temperatures . . . 2-44
2.5.4 Brine Disposal Costs 2~45
2.5.5 Base Year Used in Costing Procedure 2-45
2.5.6 Safety Costs for Boilers and Process Heaters . . 2-46
2.5.7 Pipeline System Costs 2'47
2.5.8 Economic Impact Analysis . 2-48
2.5.9 Costs for Low Heating Value Streams . 2-50
2.6 COST EFFECTIVENESS • 2-51
2.6.1 TRE Approach and Cutoff Value 2-51
2.6.2 Basis of TRE Cutoff • • • 2'57
2.6.3 Derivation of TRE Equation 2'57
2.6.4 Removal Efficiency for Combined Vent Streams . . 2-59
2.6.5 Calculation of TRE for Large Facilities 2-60
2.7 FORMAT OF STANDARDS 2-61
2.7.1 Compounds Included in TOC 2-61
2.7.2 Identification of Chemicals of Low
Photochemical Reactivity . *-*>*
2.7.3 Water Vapor Included in Low Flowrate Exemption. . 2-64
2.8 MODIFICATION/RECONSTRUCTION 2'64
2.8.1 Effective Date of Modification and
Reconstruction 2"54
2.8.2 Clarification of Modification Definition 2-65
2.8.3 Feasibility of Modifications to Meet Standards. . 2-66
284 Clarification of Modification and
Reconstruction Provisions 2-bb
2.8.5 Replacement of Trays and Packing 2-68
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TABLE OF CONTENTS (CONTINUED)
PAGE
2.9 MONITORING AND MEASUREMENT METHODS 2-68
2.9.1 Cost and Complexity of Monitoring Requirements. . 2-68
2.9.2 Monitoring During Startup, Shutdown, and
Malfunction 2-70
2.9.3 Flow Meter and Flow Indicator Requirements. . . . 2-72
2.9.4 Continuous Temperature Monitoring of Boiler . . . 2-74
2.9.5 Waiver Request of Performance Tests; 2-74
2.9.6 Distillation Unit Definition Effect; on
Monitoring . 2-76
2.9.7 Method for Sampling Small Diameter Vents 2-76
2.9.8 Use of Reference Method 2D 2-77
2.9.9 Measurement of Vent Stream Flowrate 2-77
2.9.10 Flow Monitors for Incinerators 2-78
2.9.11 Accuracy of Temperature and Flowrate Monitors . . 2-78
2.9.12 Continuous Recording 2-79
2.9.13 Continuous Monitoring Requirement 2-80
2.9.14 Alternatives to Method 18 2-81
2.9.15 Request for VOC Monitors on Incinerators 2-82
2.9.16 Monitoring of Flare Performance ... 2-83
2.9.17 Alternative Methods of Demonstrating Compliance . 2-84
2.9.18 Temperature Monitoring for Condensers 2-84
2.9.19 Temperature Monitoring for Catalytic
Incineration „ . 2-85
2.9.20 Product Recovery Systems and TRE Calculation. . . 2-86
2.9.21 Scrubbers and Recovery Devices 2-87
2.9.22 TRE Index Calculation Point ..... 2-89
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TABLE OF CONTENTS (CONTINUED)
PAGE
2.10 REPORTING AND RECORDKEEPING 2-90
2.10.1 Semiannual Reporting 2-90
2.10.2 Low Flow and Low Capacity Facilities 2-91
2.10.3 Length of Time Records Must be Kept ........ 2-92
2.10.4 Recordkeeping for Changes in Production Rate. . . 2-92
2.10.5 Reporting Variations in Steam Flowrate 2-92
2.10.6 Reporting Condenser Temperature Increases .... 2-93
2.11 GENERAL 2-94
2.11.1 Documentation of EPA Correspondence 2-94
2.11.2 Safety of Combining Vent Streams 2-94
2.11.3 CAS Numbers for Affected Chemicals 2-95
2.11.4 Surface Condensers 2-95
2.11.5 Significance of Energy Impacts 2-96
2.11.6 Typographical Error in Regulation 2-96
2.11.7 Typographical Error in Regulation 2-96
2.11.8 Typographical Error in Regulation 2-97
2.11.9 Typographical Error in Regulation 2-97
2.11.10 Reordering of Sections in Regulation ...... 2-97
2.11.11 Position of "Note" in Regulation 2-97
APPENDIX A: Federal Register Notices of Organic Compounds
Determined to have Negligible Photochemical
Reactivity. A-l
' INTRODUCTION A-l
42 FR 35314 A-2
42 FR 32042 A-5
42 FR 32424 A-7
45 FR 48941 ....".. A-8
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TABLE OF CONTENTS (CONCLUDED)
PAGE
APPENDIX B: TRE Equation and Coefficient Development for
Thermal Incinerators and Flares ... B-1
B.I INTRODUCTION B-1
B.2 INCINERATOR TRE INDEX EQUATION B-1
B.2.1 Incinerator TRE Index Equation
Development B-1
B.2.2 Example Calculation of an Incinerator-
based TRE Index Value for a Facility .... B-4
B.3 FLARE SYSTEM TRE DEVELOPMENT B-7
B.3.1 Development of the Flare TRE
v Index Equation .B-7
B.3.2 Flare TRE Coefficients Verification B-9
B.3.3 Example Calculation of a Flare-based
TRE Index Value for a Facility B-15
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LIST OF TABLES
TITLE PAGE
2-1 List of Commenters on the Proposed Standards of Performance
for Distillation Operations 2-2
B-l Distillation NSPS TRE Coefficients for Vent Streams
Controlled by an Incinerator B-3
B-2 Maximum Vent Stream Flowrate and Net Heating Value
Characteristics for Each Design Category B-5
B-3 Distillation Operations NSPS TRE Coefficients for Vent
Streams Controlled by a Flare B-10
B-4 TRE Index Values Generated Using TRE Coefficients and
the Flare Cost Algorithm Net Heating Value Greater
Than or Equal to 300 Btu/scf B-ll
B-5 Percent Difference Between TRE Index Values Generated
Using TRE Equation and the Flare Cost Algorithm Net
Heating Value Less Than 300 Btu/scf B-13
B-6 Percent Differences Between TRE Index Values Generated
by the Cost Algorithm and the TRE Equation for Vent
Streams with Heating Values Less Than 40 Btu/scf. ....... B-14
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1.0 SUMMARY
On December 30, 1983, the Environmental Protection Agency (EPA) proposed
standards of performance for distillation operations in the synthetic organic
chemical manufacturing industry (48 FR 57538) under the authority of
Section 111 of the Clean Air Act. Public comments were requested on the
proposal in the Federal Register. There were 34 commenters, most of whom are
industry representatives. Comments were also received from a vendor of
equipment used to control emissions from distillation operations and from a
representative of an environmental group. On May 16, 1985, EPA reopened the
public comment period (50 FR 20446) for the purpose of allowing public
comment on the results of the Agency's reanalysis of the total resource
effectiveness (TRE) equation and coefficients, the costing procedures, and
the designation of affected facility. The reanalysis resulted from the
acquisition of new information received in public comments and collected
since proposal. In response to the reopening of the public comment period,
one comment was received. The comments that were submitted, along with
responses to these comments, are summarized in this document. The comments
and subsequent responses serve as the basis for the revisions made to the
regulation between proposal and promulgation.
1.1 SUMMARY OF CHANGES SINCE PROPOSAL
Several changes and clarifications were made in the regulation as a
result of the review of public comments. Changes and clarifications were
made in the following general areas: (a) affected facility designation;
(b) applicability of the standards; (c) exemptions; (d) treatment of
negligibly photochemically reactive compounds; (e) monitoring requirements;
(f) flare operating specifications; (g) TRE coefficients; (h) incorporation
of a TRE index value above which monitoring and recordkeeping are not
required; (i) general definitions; (j) net heating value equation; and (k)
miscellaneous.
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1.1.1 Affected Facility Designation
The EPA has decided to change the designation of affected facility used
in the standards. The designation of affected facility in Section 60.660(a)
has been changed from a single distillation unit with the associated recovery
system to each recovery system and all associated distillation units venting
to that recovery system. Each distillation unit not feeding offgas into a
recovery system would constitute a separate affected facility. Because this
designation does not require apportioning of vent streams. Sections 60.664(c)
(l)(ii) and (iii), which specify the method of apportioning where distillation
columns share a common recovery system, have been deleted from the regulation.
1.1.2 Applicability of the Standards
The natural products -pinene; coconut oil acids, sodium salt; fatty
acids; tall oil, sodium salt; tallow acids, potassium salt; and tallow acids,
sodium salt; have been deleted from the list of affected chemicals in
Section 60.667. The manufacture of products derived from natural sources
such as these is not within the scope of this new source performance standard
(NSPS), which is intended to focus on synthetic organic chemical manufacturing
processes. Three fertilizer chemicals, ammonium carbamate, urea ammonium
nitrate (UAN) and urea have also been deleted from the list in Section 60.667.
According to information available to the Agency, the production of ammonium
carbamate and UAN does not involve the use of distillation operations and no
significant volatile organic compounds (VOC) are emitted during the production
of urea.
Some commenters were concerned that trace amounts of listed chemicals in
a product stream would cause them to be subject to the standards. This NSPS
would only be applicable to distillation operations within process units
producing as a product any of the chemicals listed in Section 60.667. A
definition of "product" has been added to the regulation to clarify that the
chemical is produced as a product when it is produced for sale or use in
another process unit, and that by-products, coproducts, arid intermediates are
considered "products" for the purposes of these standards. This new defini-
tion clarifies what constitutes production of one of the 211 high production
volume chemicals listed in Section 60.667.
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1.1.3 Exemptions
Batch distillation operations have been exempted from the standards. The
control technologies considered in the development of the distillation NSPS
are appropriate for continuous processes but may not always be applicable to
batch processes because batch processes typically have intermittent vent
streams. Therefore, EPA has decided to exempt batch processes explicitly in
Section 60.660(c). In addition, to clarify what is meant by a "batch
distillation operation" a definition of this term has been added to Section
60.661. This definition emphasizes the noncontinuous operation and the
discrete liquid feed nature of batch distillation operations.
The low flow rate exemption has been changed from a design flow rate
basis to an operating flowrate basis in Section 60.660(c). The EPA recog-
nizes that distillation facilities may be designed at the exemption level but
may operate at levels above or below.this design flow rate. The record-
keeping (Section 60.665(i)) and the semiannual reporting (Section
60.665(1)(5)) requirements for the low flow rate exemption have been likewise
amended to reflect this change.
1.1.4 Negligibly Photochemicallv Reactive Compounds
The distillation standards are intended to control VOC, i.e., compounds
that participate in atmospheric photochemical reactions to produce ozone.
Therefore, negligibly photochemically reactive compounds are permitted to be
subtracted from the total organic compound (TOC) emissions measured for
calculation of the TRE index value. However, when determining combustion
device emission reduction efficiency they should not be subtracted because
combustion devices are not compound-specific with respect to VOC destruction.
Furthermore, it is more costly and complex to subtract the negligibly reactive
compounds during performance testing.
In order to effect this change, Section 60.661 was amended to indicate
that the definition of "TOC" means TOC less all compounds that have been
determined by the Administrator to be negligibly photochemically reactive.
This definition is used only when applied to Sections 60.664(d)(2)(i) -
measuring molar composition; 60.664(d)(5), and 60.664(e) - measuring hourly
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emissions rate; and 60.665(b)(4) and 60.665(g)(4) - measuring TOC
concentration. For all other quantifications of TOC under these standards,
VOC equals TOC less methane and ethane as indicated in Section 60.662(a). The
Federal Register citations for the list of negligibly photochemically reactive
compounds that may be subtracted are presented in Appendix A and have also
been added to the definition of TOC in Section 60.661 of the regulation.
The definition of "TRE index value" has been amended to incorporate the
change in the definition of "TOC." The TRE is now defined as "a measure of
the supplemental total resource requirement per unit reduction of total
organic compounds . . ., emission rate of total organic compounds. . . ."
1.1.5 Monitoring. Testing, and Reporting/Recordkeeping Requirements
The required use of flow rate monitors for vent streams routed to thermal
incinerators has been changed. The EPA has decided to require the use of flow
indicators rather than flow rate monitors for incinerators because the reason
for monitoring is to provide an indication that the vent: stream is being
routed for destruction and flow indicators adequately serve1 this function.
This requirement is consistent with vent stream monitoring requirements for
all other combustion devices that may be used under the standards. Thus,
Section 60.663(A)(2) has been amended to indicate that at flow indicator is to
be used. Likewise, the reporting and recordkeeping requirements for flow
monitoring in Section 60.665(c)(3) have been deleted and replaced with
reporting and recordkeeping requirements for flow indication that are
integrated into Section 60.665(d).
Ultraviolet beam heat sensors have been included in addition to
thermocouples as suitable devices for the monitoring of the presence of a
flame. Section 60.663(b)(l) has been amended to indicate this.
The "continuous recording" requirements have been changed. All
measurements such as firebox temperature, absorber liquid specific gravity,
carbon adsorber steam mass flow rate, and others are now required to be taken
at least every 15 minutes. This allows use of computer-assisted monitors.
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The frequency for measurement of these parameters during compliance testing
has also been revised to be made at least every 15 minutes. Section 60.665(b)
has been amended accordingly. An advantage of this change is that the
parameter measurement frequencies required for monitoring and continuous
recording are consistent with the frequencies required in compliance testing.
Furthermore, the same equipment may be used for both monitoring and compliance
testing.
1.1.6 Flare Operating Specifications
Operating specifications for flares used to comply with requirements in
new source performance standards (NSPS) were recently added to Section 60.18
of the General Provisions (51 FR 2701, January 21, 1986). The regulation has
been revised to refer all owners or operators of affected facilities which
use flares to comply with this NSPS to the requirements in that section.
1.1.7 TRE Coefficients
Tables 1 and 2 of the regulation present the incinerator and flare
coefficients associated with the TRE index equation. Some of the coefficients
in these tables were corrected to predict more accurately the TRE indexes
(and associated cost-effectiveness values) of facilities. The modifications
of the coefficients resulted from changes in the costing procedures-on which
these coefficients are based. The changes in costing procedures and TRE
coefficients are discussed in the Agency's notice reopening the public
comment period for the proposed distillation standards (50 FR 20446).
Several modifications were also made in the format of Table 1 to provide
clarity to owners or operators of distillation facilities. These modifica-
tions included: (a) the designation of Category Al and A2 streams was changed
from "chlorinated" to "halogenated"; (b) the designation for flow rate was
changed from "W" to "Q " so that the symbol would match the symbol in the EPA
Reference Methods discussion; (c) the term representing flow rate intervals
for selecting TRE coefficients was changed from "design standard flow rate" to
"vent stream flow rate" to indicate that actual operating flow rate should be
used in selecting TRE coefficients; (d) the first flow rate interval was
eliminated because all vent streams with flow rates below the'minimum
incinerator size of 500 scfm are assumed to have a flow rate of 500 scfm for
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the purposes of calculating capital and annual operating costs; and (e) the
term representing flow rate for Category E streams was changed from "design
standard flow rate" to "dilution flow rate = (QsMHrVS.S" to indicate that
dilution flow rate should be used in selection of TRE coefficients. Table 1
presents the coefficients for the incinerator TRE equation. Table 2 presents
the coefficients for the flare TRE index equation.
1.1.8
Incorporation of a TRE Index Value Above Which Monitoring and
Recordkeemna Are Not Reauired
Several changes were made in the regulation to provide for inclusion of a
maximum TRE index value. The maximum TRE index value of 8.0 represents the
value above which monitoring and recordkeeping requirements would not be
imposed on a facility attempting to comply with the standards. It is the
judgment of the Agency that facilities with TRE index values above the maximum
would most likely not be able to make process changes that would cause the TRE
index value to fall below the cutoff. Thus, the Agency believes that the
monitoring and recordkeeping burden should not be imposed on such facilities.
However, if a process change occurs, the facility should recalculate the TRE
index value as required in Section 60.664(c) to determine whether the value
remains above the TRE maximum. Sections 60.660 and 60.664 of the regulation
have been amended to incorporate the requirements associated with the maximum
TRE index value.
1.1.9 Definitions
Both new and revised definitions have been included in Section 60.661.
New definitions for "batch distillation and operation," "continuous recorder,"
and "product" have already been discussed. Revised definitions for
"distillation operation," "distillation unit," "total organic compounds,"
"process heater," "process unit," "recovery system," "TRE index value," and
"vent stream" have also been included.
To further clarify the applicability of the distillation NSPS, the
definition of "distillation operations" has been amended to read,
"'distillation operation' means an operation separating one or more feed-
stream(s) into two or more exit streams. . ." instead of two or more product
streams, as stated in the proposed regulation. The definition of "distilla-
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tion unit" was broadened to include explicitly the accessories necessary for
some distillation operations, a vacuum pump and a steam jet. Because process
heater tubes may be arranged in a number of configurations other than "tubular
coils," this definition was revised to refer simply to "tubes." In order to
clarify what properly constitutes a "recovery system," this definition was
made more specific by referring to its purpose for recovering chemicals for
use in making other chemicals, reuse, or for sale." "Vent stream" was
revised to exclude explicitly equipment leaks and relief valve discharges,
which are covered under VOC fugitive emission standards. The reasons for
revising the definitions of "TOC" and "TRE index value" are explained in
Section 1.1.4 of this chapter.
1.1.10 Net Heating Value Equation
The net heating value equation, Section 60.664(c)(4), was changed to
include the heating value associated with carbon monoxide since it can
contribute to the net vent stream heat content if present. The concentration
of carbon monoxide in the vent stream must be determined according to
ASTM D1946-82 as required under Section 60.664 (c)(2)(ii).
To be sure that the net heating value is calculated on a wet basis, the
definition of symbol "C." (Section 60.664(c)(4)) was amended to include "on a
wet basis." The net heating value must be calculated on a wet basis because
the entire vent stream, including water vapor, would be combusted, and
therefore this is the heating value used in calculating a TRE value.
1.1.11 Miscellaneous
Word and symbol changes were made in Sections 60.664(c) and 60.665(k)(2)
to correct typographical errors.
1.2 SUMMARY OF IMPACTS OF PROMULGATED ACTION
1.2.1 Alternatives to Promulgated Action
The regulatory alternatives are discussed in Chapter 6 of the proposal
background information document (BID). These regulatory alternatives reflect
the different estimated number of facilities required to reduce VOC emissions
by 98 weight-percent or to 20 parts per million by volume under a particular
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cost-effectiveness cutoff. These regulatory alternatives were used for the
selection of the best demonstrated technology (BDT), considering the estimated
cost impacts, nonair quality health impacts, environmental impacts, and
economic impacts associated with each alternative. These alternatives have
not been changed.
1.2.2 Environmental Impacts of Promulgated Action
The changes in the regulation described above will have a minor effect
on the estimated air quality impacts attributed to the standards as originally
proposed. The new estimated air quality impacts of the standard are presented
in the Agency's notice reopening the public comment period for the proposed
distillation standards (50 FR 20446). The changes in the regulation will
have a negligible impact on the water quality and solid waste impacts
attributed to the final standards. The analysis of environmental impacts in
Chapter 7 along with the new air quality impacts presented at 50 FR 20446 now
constitute the final Environmental Impact Statement for the promulgated
standards.
1.2.3 Energy and Economic Impacts of Promulgated Action
Section 7.4 of the proposal BID describes the energy impacts and
Chapter 9 describes the economic impacts of the proposed standards. The
changes in the regulation described above will have a negligible effect on
these impacts.
1.2.4 Other Considerations
1.2.4.1 Irreversible and Irretrievable Commitment of Resources.
Chapter 7 of the proposal BID concludes that other than fuels required for
the operation of control equipment, there is no apparent irreversible or
irretrievable commitment of resources associated with the standards. The use
of the TRE concept encourages the use of recovery techniques to recover
chemicals for use, reuse or sale that would otherwise be disposed of as
pollutants. The control of VOC emissions using recovery techniques might be
an alternative for some distillation facilities. This would result in the
conservation of both chemicals and fuels. The changes in the regulation
described above will have no impact on the commitment of resources.
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1.2.4.2 Environmental and Energy Impacts of Delayed Standards.
Table 1-1 in the proposal BID summarizes the estimated environmental and
energy impacts associated with promulgation of the standards. If the
standards were delayed, adverse impacts on air quality could result. A delay
in promulgation would mean that affected facilities would be controlled to
the level specified in the appropriate State implementation plan. Emission
levels would be higher than would be the case were the standards in effect
because these estimated impacts have not changed since proposal.
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2.0 SUMMARY OF PUBLIC COMMENTS
A total of 34 letters commenting on the proposed standards were
received. A public hearing on the proposed standards was not requested. The
public comment period was reopened to allow comment on the Agency's reanalysis
of the total resource effectiveness (TRE) equations and coefficients, the
costing procedures, and the designation of affected facility. One letter
commenting on the reanalysis was received. The 35 comment letters have been
recorded and placed in the docket. The list of commenters, their affiliation,
and the Environmental Protection Agency (EPA) docket number for each of the
comments are shown in Table 2-1. The docket reference is indicated in
parentheses in each comment. Unless otherwise noted, all docket references
are part of Docket Number A-80-25, Category IV. The comments have been
organized into the following 11 categories:
2.1 Applicability of the Standards
2.2 Selection of Affected Facility
2.3 Definitions
2.4 Selection of Best Demonstrated Technology
2.5 Cost Estimation
2.6 Cost Effectiveness
2.7 Format of the Standards
2.8 Modification and Reconstruction
2.9 Monitoring and Measurement Methods
2.10 Reporting and Recordkeeping
2.11 General
2.1 APPLICABILITY OF THE STANDARDS
2.1.1 COMMENT: Several commenters (D-l, D-2, D-3, D-16, D-19, D-29,
D-31, and D-34) requested information on the possible exemption of various
organic chemicals and manufacturing processes from the proposed standards.
One commenter (D-19) inquired if a distillation facility used to produce a
chemical for use in the polymer manufacturing industry is exempt from the
standards when it is isolated from the polymers and resins process. The
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TABLE 2-1
List of Commenters on the Proposed Standards of Performance for Distillation
Operations in the Synthetic Organic Chemical Manufacturing Industry
Docket Number A-80-25, IV
Letters
Addressee Docket Reference
Mr. J. F. Cochrane 0-1
Director, Environmental Affairs
Department
J. R. Simplot Company
Post Office Box 912
Pocatello, Idaho 83201
Mr. D. H. Maybury 0-2
Regional Environmental Manager
Regional Operations Services
Hercules Incorporated
501 Glouchester Street
Brunswick, Georgia 31520
Mr. Finn Bohn 0-3
Environmental Engineer
Allied Chemical
Post Office Box 1053R
Morristown, New Jersey 07960
Mr. Edward P. Crockett D-4
American Petroleum Institute
1220 L Street, Northwest
Washington, D.C. 20005
Dr. Thomas A. Robinson D-5
Director, Environmental Affairs
Vulcan Chemicals
Post Office Box 7689
Birmingham, Alabama 35253
Mr. Gary D. Myers 0-6
President, The Fertilizer Institute
1015 18th Street, Northwest
Washington, D.C. 20036
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TABLE 2-1 (Continued)
Addressee Docket Reference
Mr. J. J. Moon D-7
Manager, Environment & Consumer Protection
Corporate Engineering
Phillips Petroleum Company
Bartlesville, Oklahoma 74004
Mr. David M. Flannery D-8
Counsel for Borg-Warner Chemicals,
Incorporated
Robinson & McElwee Law Offices
Post Office Box 1791
Charleston, West Virginia 25326
Mr. William J. Hague D-9
Principal Process Engineer
Allied Chemical
Post Office Box 1139R
Morristown, New Jersey 07960
Mr. Robert M. Yarrington ti-10
Product Manager
Englehard Industries Division
2655 US Route 22
Unfon, New Jersey 07083
Dr. Robert R. Romano D-ll
Manager, Air Programs
Chemical Manufacturers Association
2501 M Street, Northwest
Washington, D.C. 20037
Mr. G. L. Je.ssee D-12
Director, Regulatory Management
Monsanto Company
800 North Lindbergh Boulevard
St. Louis, Missouri 63167
Mr. J. D. Reed D-13
General Manager
Environmental Affairs and Safety
Standard Oil Company (Indiana)
200 East Randolph Drive
Chicago, Illinois 60601
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TABLE 2-1 (Continued)
Addressee Docket; Reference
Mr. Peter W. McCallum D-14
Senior Corporate Environmental Specialist
The Standard Oil Company
Midland Building
Cleveland, Ohio 44115
Mr. J. W. Torrance D-15
Supervisor, Environmental Engineering
Allied Fibers and Plastics
Technical Center
Post Office Box 31
Petersburg, Virginia 23804
Mr. Gary D. Myers D-16
President, The Fertilizer Institute
1015 18th Street, Northwest
Washington, D.C. 20036
Mr. Paul A. Cammer D-17
Executive Director
Halogenated Solvent Industry Alliance
1612 K Street, Northwest
Suite 300
Washington, D.C. 20006
Mr. U. V. Henderson, Jr. D-18
Associate Director, Environmental Affairs
Research, Engineering and Safety Department
Texaco, Incorporated
Post Office Box 509
Beacon, New York 12508
Mr. Ronald F. Black D-19
Environmental Specialist
Engineering Division
Rohm and Haas Company
Post Office Box 584
Bristol, Pennsylvania 19007
Dr. V. J. Marchesani D-20
Director, Energy and Environmental Quality
Health and Environmental Affairs
Post Office Box 751
ICI Americas, Incorporated
Wilmington, Delaware 19899
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TABLE 2-1 (Continued)
Addressee Docket Reference
Mr. David D. Doniger D-21
Senior Staff Attorney
Natural Resources Defense Council,
Incorporated
1725 I Street, Northwest
Suite 600
Washington, D.C. 20006
Mr. Ronald A. Lang D-22
Executive Director
Synthetic Organic Chemical Manufacturers
Association, Incorporated
1612 K Street, Northwest
Suite 300
Washington, D.C. 20006
Mr. A. G. Smith D-23
Environmental Affairs
Shell Oil Company
One Shell Plaza
Post Office Box 4320
Houston, Texas 77210
Mr. Barry Christensen D-24
Environmental Manager
Diamond Shamrock Chemicals Company
1149 Ellsworth Drive
Pasadena, Texas 77501
Mr. E. J. Shields • D-25
Director, Environmental Services
Allied Chemical
Post Office Box 1139R
Morristown, New Jersey 07960
Mr. Lawrence B. Gotlieb D-26
Assistant General Counsel
Distilled Spirits Council of the *
United States, Incorporated
425 13th Street, Northwest
Washington, D.C. 20004
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TABLE 2-1 (Continued)
Addressee Docket: Reference
Mr. A. H. Nickolaus [l_27
Chairman, CTG Subcommittee
Air Conservation Committee
Texas Chemical Council
1000 Brazos, Suite 200
Austin, Texas 78701
Mr. Steven A. Correll D-28
Senior Environmental Engineer
Georgia-Pacific Corporation
133 Peachtree Street, Northwest
Post Office Box 105605
Atlanta, Georgia 30348
Mr. Gary D. Myers 0-29
President, The Fertilizer Institute
1015 18th Street, Northwest
Washington, D.C. 20036
Mr. Mark E. Lowing D_30
Environmental Specialist
Dow Corning U.S.A.
3901 South Saginaw Road
Mail #144
Midland, Michigan 48640
Mr. Robert H. Collom, Jr. D-31
Chief, Air Protection Branch
Department of Natural Resources
Environmental Protection Division •
270 Washington Street, Southwest
Atlanta, Georgia 30334
Ms. Joyce M. Wood D-32
Chief, Ecology and Conservation Division
Office of the Administrator
United States Department of Commerce
National Oceanic and Atmospheric Administration
Washington, D.C. 20230
Mr. Jerry M. Starkey D-33
Senior Environmental Engineer
Northern Petrochemical Company
Post Office Box 459
Morris, Illinois 60450
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TABLE 2-1 (Concluded)
Addressee Docket Reference
Mr. Gary D. Myers D-34
President, The Fertilizer Institute
1015 18th Street, Northwest
Washington, D.C. 20036
Ms. Geraldine V. Cox, Ph.D. D-37
Vice President - Technical Director
Chemical Manufacturers Association
2501 M Street, Northwest
Washington, D.C. 20037
2-7
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commenter's question pertains to Section 60.660(a) of the proposed regulation
that states distillation units operating as part of a process unit which
produces polymers and resins are not affected facilities. Another commenter
(D-33) asked if the term "polymers and resins" used under Section 60.660(a)
refers to those specific polymers and resins which were addressed in the
proposed polymer manufacturing new source performance standard (NSPS).
Three commenters (D-2, D-3, and D-31) wanted to be sure that the
proposed standards are not applicable to coal tar distillation facilities and
facilities that "produce" the chemicals listed in the regulation by extrac-
tion from natural substances, not by synthesis. For example, one commenter
(D-31) stated that tall oil is a natural substance but contains pinene, one
of the chemicals listed in Section 60.667. He asked if a distillation unit
would be subject to this NSPS if the unit were to separate pinene from tall
oil. One commenter (D-26) agreed with EPA for exempting the distillation
operations in the beverage alcohol industry from the proposed standards.
Four commenters (D-l, D-16, D-29, and D-34) stated that urea,
urea-ammonium nitrate (UAN), and ammonium carbamate production should not be
covered by the standards because the production of these three chemicals
neither involves the use of a distillation operation nor the significant
emission of volatile organic compounds (VOC). One commenter (D-29) further
stated that these compounds should not even be considered synthetic organic
manufacturing industry (SOCMI) chemicals according to the EPA description of
how the SOCMI list was developed (Proposed Standards of Performance for SOCMI
Equipment Leaks of VOC, 46 FR 1136, January 5, 1981). The commenter believes
that only one of the five criteria presented in EPA's description applies' to
urea, UAN, and ammonium carbamate. The one common criterion is a high
production volume, and the commenter feels that it is not a sufficient reason
for the three chemicals to be included on the SOCMI list. One commenter
(D-16) presented information to clarify that the processes their companies
use for the production of urea employ a flash evaporator which is unlike a
distillation unit. Only water is removed by the flash evaporator with no
significant amounts of VOC being released during urea production, in contrast
to a distillation unit that separates volatile organic materials. Therefore,
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the commenter stated that urea production as well as UAN and ammonium
carbamate production does not employ distillation units and negligible
amounts of VOC are emitted. However, one commenter (D-29) indicated that
distillation units are used to produce urea and any of the organic material
emitted during production of urea is primarily in the form of particulates.
Another commenter (D-34) indicated that if formaldehyde based additives (FBA)
(used in the production of urea) were present when urea is concentrated (via
distillation) only insignificant amounts of formaldehyde would be vented to
the atmosphere. Because formaldehyde reacts so rapidly with urea to form a
nonvolatile solid, it is unlikely that free formaldehyde would be emitted
during urea production. For economic reasons, most existing facilities and
all new facilities use very efficient product recovery systems. It was
pointed out that all affected facilities that produce urea, UAN or ammonium
carbamate would probably comply with the standards by maintaining a TRE index
value greater than 1.0 because the cost of controlling VOC emissions would be
above the TRE cutoff. The reasons given for the expected high TRE index
values are the current and extensive use of recovery equipment and the high
amounts of fuel enrichment needed for the low heating value vent streams.
The commenter stated that exemptions based on the TRE cutoff would still be
costly because of the required monitoring, recordkeeping and reporting.
RESPONSE: It is not the intent of the distillation NSPS to regulate the
production of polymer chemicals because a polymer manufacturing NSPS is
currently being developed for this purpose. However, a distillation facility
that is not physically part of the polymer process line, as in the case cited
by one commenter, would be covered by the distillation NSPS if chemicals
listed in the regulation are produced within the process unit that contains
the facility. However, when a distillation operation is an affected facility
under both standards, only the polymer manufacturing standards are applicable.
In order to clarify the extent of coverage by the distillation standards,
-»
Section 60.660 has been amended to defer to the polymer manufacturing
standards in cases of overlapping coverage.
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As noted in Section 60.660(a), coal tar distillation is not covered by
these standards because these operations are covered by the national emission
standards for hazardous air pollutants (NESHAP) regulating benzene emissions
from coke by-product plants.
There is a small portion of organic chemicals that are extracted from
natural sources. The EPA does not consider the standards to be applicable to
chemicals that are extracted from natural sources because the production
processes, emissions, and control alternatives have not been investigated by
the Agency. Therefore, five chemicals listed in the proposed regulation that
are produced by extraction from natural sources have been removed from the
list. These five chemicals are: (1) coconut oil acids, sodium salt;
(2) fatty acids, tall oil, sodium salt; (3) pinene; (4) tallow acids,
potassium salt; and (5) tallow acids, sodium salt.
In considering the applicability of the standards to the production of
the fertilizer chemicals mentioned by the commenters, EPA solicited informa-
tion from many sources including the commenters themselves; (Docket Item
No. IV-C-7). According to the available information, including that provided
by the commenters (Docket Entries IV-D-35 and IV-E-14), the Agency concluded
that distillation operations are not involved in the production of ammonium
carbamate and UAN. Therefore, these two chemicals have been removed from the
list in the distillation regulation because the standards are not applicable
to the production of these chemicals.
Although distillation operations are involved in the production of urea,
EPA has removed urea from the list because no VOC emissions are expected to
occur during distillation operations involved with urea production. The vent
streams from these distillation units consist almost entirely of inert gases
(e.g., nitrogen), water, ammonia, and urea particulate. The potential for
VOC emissions would exist when FBA and/or methanol are added before or during
the distillation operation. However, available information indicates that at
the majority of urea production facilities, FBA is injected into the product
stream after the distillation operation. Therefore, there is no potential
for formaldehyde emissions from distillation units within this type of
production process. For process units where FBA are injected prior to or
during distillation, the only organic emissions expected from the
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distillation unit would be particulate urea. Any formaldehyde should be
completely reacted with urea to form methylenediurea because urea is in molar
excess of 125 to 1. Methylenediurea is a chemically stable compound under
the conditions encountered (Docket Item No. IV-E-14).
No information was available that indicates methanol is added before or
during distillation. For these reasons, the Agency has decided to remove
urea from the list of chemicals covered by the final standards.
2.1.2 COMMENT: Several commenters (D-8, D-ll, D-12, D-13, and D-33)
requested clarification on the applicability of the proposed standards to
distillation facilities that do not produce as the main product any of the
chemicals listed in the regulation. One commenter (D-12) stated that it is
inferred from the preamble that all economic modeling and costing was done on
distillation units that distilled as a product the chemicals listed in the
regulation. The commenter suggested that, if this were true,
Section 60.660(a) should be modified because it includes all distillation
units that are part of a system used to produce one or more of the regulated
chemicals.
Several commenters (D-ll, D-12, D-13, and D-15) recommended that
distillation operations that produce any of the chemicals listed in the
regulation at trace or low levels should be excluded from coverage by the
standards. One of the commenters (D-15) suggested that exclusion should
occur for distillation operations that separate inorganic or aqueous streams
with only trace (less than 1 percent) organics present. Another commenter
(D-ll) believed that the proposed regulation would be applicable to distilla-
tion facilities that contain listed chemicals only as impurities in a process
stream. Therefore, he suggested the standards state that if a process stream
could be tapped and piped to a product storage vessel (even if the process is
not currently so operated) and such a vessel could be filled with a product
listed in Section 60.667, then the distillation process would not be exempted
from the standards. The commenter indicated this wording would remove from
coverage by the standards processes that only contain listed chemicals as
impurities in the process streams. Two commenters (D-ll and D-12) suggested
that a minimum VOC level for the vent stream be specified to determine
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whether a distillation operation is an affected facility. A breakpoint level
of 10 percent VOC content was suggested as used in the promulgation of the
standards of performance for equipment leaks of VOC in the SOCMI (48 FR 48328
- October 18, 1983).
A recommendation was made (D-13) that only those distillation units that
produce one or more of the chemicals listed in Section 60.667, as products
should be considered as affected facilities. Contaminants, by-products, and
intermediates should not be included in the scope of these standards.
One commenter (D-8) requested clarification on the term "intermediate
product" as used in the proposed standards. The commenter suggested the
definition of "intermediate product" not include a manufacturing process
waste or a feedstock component that is recovered by the operator for subse-
quent use by the operator. Feedstock components may be recovered (not
"produced") during production for use in a subsequent batch. Another
commenter (D-33) requested that EPA clarify whether a facility would be an
affected facility if its process stream contains listed chemicals that are
either sold, disposed of, used in the production of other chemicals or
recycled.
RESPONSE: The EPA developed the standards from data on distillation
facilities within process units that produce the chemicals listed in
Section 60.667 as a product, by-product, coproduct, or intermediate. The EPA
believes it appropriate to consider by-products, coproducts and intermediates
as products, as indicated under Section 60.661 (Definitions), because the
cost of controlling emissions from the production of listed chemicals in any
of these forms is similar. Furthermore, the application of the standards to
facilities producing any of the listed chemicals was found to be reasonable.
Therefore, the Agency considers it appropriate for the standards to apply to
any distillation facility within a process unit producing any of the listed
chemicals as a product. All costing and economic impact analyses were based
upon distillation facilities within process units that produce the listed
chemicals as a product. However, sometimes process unit product streams
contain listed chemicals that are not sold or used in reactions to form other
chemicals. These types of process units were not analyzed and the distilla-
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tion facilities within them are not covered by the standards. Some examples
of process units that do not produce a listed chemical as a product are those
in which the listed chemical is a contaminant, a feedstock that is recycled
back to a process, part of a carrier gas used in another distillation opera-
tion, or a conveying gas for other process uses. Distillation operations
within these types of process units would not be affected facilities.
The main factor in.determining if a listed chemical is produced as a
product is the use of the chemical. The EPA considers either of the following
downstream uses as indicative of the production of a listed chemical as a
product: (1) produced for sale as that listed chemical, or (2) used in
another process that needs the listed chemical. An example of (2) is when
methanol, a listed chemical, is produced not for sale but to react with
carbon monoxide to produce acetic acid. However, if a listed chemical is
only part of a mixed stream exiting a process unit and cannot be sold or used
in another process as the listed chemical, then that listed chemical is not
considered to be produced as a product. For example, cyclohexane, a listed
chemical, may be present in a product stream exiting a distillation facility
within a process unit that only produces gasoline. Because the gasoline
would not be sold or used in a downstream process for the cyclohexane only,
the distillation facility would not be covered by the standards. Therefore,
a distillation operation is an affected facility only if it is within a
process unit that produces a compound to be sold as a chemical listed in
Section 60.667 or used in a process that needs a chemical listed in
Section 60.667 for the production of chemical(s) in another process unit.
Listed chemicals can be formed as contaminants from side reactions as a
consequence of producing other chemicals that are not listed, or by frac-
tionating feedstocks with small amounts of listed chemicals. These
contaminants would not be considered to be produced by the process unit if
they are not fractionated further to be sold or used in the production of a
final product.
Another case is when listed chemicals are separated from a reactor
product stream in a distillation operation and recycled back to the reactor
as an unreacted feedstock. For example, a low-yielding reaction occurs where
the reactants A and B are listed chemicals and are reacted to form a product
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C that is unlisted. A distillation operation is used to separate chemical C
from the unreacted chemicals A and B. Chemicals A and B are then recycled
back to the reactor. The distillation operations within this process unit
would not be covered by the standards because chemicals that are not pro-
duced, but are feedstock chemicals that are recovered for reuse, are not
considered products. However, if these distillation operations were within a
process unit manufacturing a listed chemical as a product. it would be
covered.
Another example of a case where the standards would not apply is when
the noncondensibles from a distillation overhead are used as a carrier gas to
facilitate the operation of another distillation operation or as a conveyor
gas for other process uses. If the carrier gas contains any listed
chemical(s) and is a process stream from a process unit used to produce an
unlisted chemical, then the standards would not apply to this facility*
The EPA has decided that for the purposes of these standards it is more
appropriate to determine applicability according to whether a listed chemical
is produced as a product, instead of setting a minimum concentration level of
a listed chemical as a means of defining what may constitute production as a
product. It is not feasible to set any one concentration limit for listed
chemicals below which the chemical is always an impurity or waste. It is not
feasible because the necessary concentration or purity for a listed chemical
to be considered a product can vary from site to site. For example, a
chemical that is produced as 90 percent pure from one process may only be
80 percent pure to be considered as a product for another process. If EPA
attempted to establish different concentration limits for all of the processes
covered by the standards, the complexity and resource requirements would be
extremely prohibitive because of the diversity of the SOCMI. Therefore, the
applicability of the standards is determined according to whether a listed
chemical is produced as a product. Section 60.661 has been amended to
include more specific definitions of product, coproduct, and by-product in
order to clarify the applicability of the standards.
2.1.3 COMMENT: Several commenters (D-4, D-7, D-14, and D-18) requested
clarification of the proposed standards with regard to the applicability of
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petroleum refineries producing any of the chemicals listed in the regulation.
One commenter (D-18) stated that because the information used to develop the
standards is limited to the organic chemical manufacturing industry, the
standards should not apply to distillation units in petroleum refineries.
Several commenters (D-4, D-14, and D-18) pointed out that many refinery
product streams contain complex mixtures with trace amounts of the chemicals
listed in Section 60.667 of the regulation. Two of these commenters (D-14
and D-18) stated that the standards should only apply to those processes that
produce the listed chemicals in pure or nearly pure form. It was recommended
the standards specify a minimum level for the quantities of the listed
chemicals in a process stream or distillation unit that would cause a
distillation facility to be subject to the standards. It was suggested that
streams having less than 10 percent of any of these listed compounds should
be exempt from the standards.
Two commenters (D-7 and D-13) noted that the background information
document (BID) (page 9-43) indicates chemicals produced primarily by
refineries are assumed to incur no costs as a result of the standards. Both
commenters stated that an increase in chemical cost would occur if petroleum
refineries must meet the standards.
RESPONSE: The standards were developed to apply to any distillation
facility within a process unit producing the chemicals listed in
Section 60.667 for sale or for use in the production of other chemicals (see
comment 2.1.2). The primary purpose of most petroleum refineries is the
production of petroleum products such as motor fuels. However, some
refineries are involved in producing one or more synthetic organic chemicals.
The EPA believes that the standards appropriately apply to distillation
facilities in the petroleum refineries that produce the listed chemicals.
The Agency evaluated data on organic chemical manufacturing including
that done at petroleum refineries, in developing this NSPS. The EPA has
found that distillation facilities within petroleum refineries do not vent
directly to the atmosphere. Instead, these facilities have their vent
streams recycled, routed to recovery, used as a fuel, or combusted by flaring
or incineration. In February of 1981, the American Petroleum Institute (API)
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sent comments concerning Chapters 3 through 6 of the BID to EPA (Docket Item
No. II-D-182). In these comments API agreed with the statement in the BID
that refinery distillation vent streams are already well controlled, recycled,
or completely recovered. The API further indicated that additional redundant
controls would not be necessary. However, EPA considers it advantageous to
regulate a segment of the industry that is already well controlled in order
to ensure those controls are properly operated and maintained and to guarantee
they will be applied to all facilities yet to be constructed. Another
advantage in regulating these facilities is to ensure that a consistent level
of control is maintained for all States. The EPA recognizes that there will
be costs associated with compliance testing, monitoring, recordkeeping, and
reporting for verification of compliance with the standards but these costs
were found to be reasonable.
Although the Agency believes that existing distillation facilities
within refineries are already well controlled, it is possible that a few new
refineries may be built with uncontrolled vent streams. However, these vent
streams would only have to be controlled if.EPA determines the cost
effectiveness of combustion to be less than $l,900/Mg. Therefore, the Agency
has determined that any control costs incurred by petroleum refineries as a
result of this NSPS would be reasonable.
Commenter D-13 was contacted for clarification of a comment regarding an
increase in chemical costs resulting from the NSPS. She stated that the
comment assumed that relief valve venting would be subject to control under
this NSPS and, in that case, additional costs would be incurred. Relief
valve discharges are not covered by the distillation NSPS,. For a discussion
of this issue refer to the response to comment 2.3.1.
2.1.4 COMMENT: One commenter (D-ll) stated that distillation
facilities starting up after promulgation of the standards; have 180 days to
attain compliance and that facilities starting up between the proposal and
promulgation should be given the same consideration. The commenter requested
that the initial reporting, performance test, and recordkeeping requirements
be required no sooner than 180 days after promulgation of these standards.
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RESPONSE: The General Provisions (40 CFR 60.8) specify that a
performance test be conducted at an affected facility no later than 180 days
after the initial startup of the facility. Even though the standards apply
to facilities commencing construction, reconstruction, or modification after
proposal (December 30, 1983), EPA does not require an immediate performance
test and written report to the Administrator. Once the standards are
promulgated, all affected facilities that were built between proposal and
promulgation will be given a reasonable amount of time of demonstrate
compliance. Any affected facility starting up after promulgation will have
180 days from their initial startup to conduct a performance test. A written
report must then be submitted to the Administrator.
2.1.5 COMMENT: Three commenters (D-9, D-ll, and D-27) inquired about
the low vent stream flow rate and design capacity exemptions specified in the
standards. Two commenters (D-ll and D-27) requested that a wording change be
introduced into the existing low flow rate exemption that would allow
distillation facilities operated with a maximum vent stream flow rate of less
than 0.008 m /min to be exempt. Section 60.660(d) of the regulation exempts
any distillation facility which is designed with a maximum vent stream
flow rate of less than 0.008 m /min from meeting the specifications in this
subpart, except for recordkeeping requirements. The commenters indicated the
designed vent stream flow rate is usually different from the operated flow
rate. With the requested wording change, distillation facilities could
operate with vent stream flow rates below 0.008 m /min and not become subject
to the standards. This could be done even if the design flow rate were
higher. Since vents are typically designed to accommodate emergency condi-
tions, the operating flow rates are usually lower than designed flow rates.
The additional wording would also clarify any ambiguity over vents that were
designed for 0.008 m /min but are operated at higher rates.
One commenter (D-9) noted that it is not clearly stated in
Section 60.660(c) that the 1 Gg/yr design capacity exemption refers to the
total amount of product from the distillation facility or that portion of the
total products which is a chemical listed in Section 60.667.
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RESPONSE; The Agency recognizes that some distillation facilities may
operate with vent stream flow rates above or below their designed level.
Therefore, EPA has decided to amend the regulation to exempt from coverage by
the standards, except for recordkeeping and reporting requirements, those
distillation facilities that operate with a vent stream flow rate less than
0.008 m /min. The Agency will no longer continue to exempt distillation
facilities only because they were designed for a vent stream flow rate below
0.008 m /min. To ensure the flow rate is continuously operated below
0.008 m /min, the owner or operator must demonstrate it to EPA. The owner or
operator of an affected facility that operates with a vent stream flow rate
O
below 0.008 m /min must notify EPA and demonstrate compliance with a per-
formance test that measures the operating flow rate. Furthermore, any
operational changes in the facility that may cause the vent stream flow rate
to no longer be below the exemptio» level must be recorded along with a
flow rate measurement after the change has been made. No reporting to EPA is
required until the low flow level has been exceeded and the report must
contain the new flow rate measurement. The following are a few examples of
operational changes that could affect the vent stream flow rate: increased
production or production capacity, use of a new feedstock, use of a new
catalyst, or any replacement, removal or addition of recovery equipment, or
changes in the operating characteristics of the distillation unit(s). If any
of these operational changes result in a flow rate greater than the exemption
level, they must be reported to EPA semiannually along with the new flow rate.
Otherwise, there are no reporting requirements after the initial performance
test. If the vent stream flow rate exceeds the exemption level, the owner or
operator must comply with the provisions of Section 60.662.
The low capacity exemption does not pertain only to the production of
chemicals listed in Section 60.667. The EPA exempts any distillation facility
from coverage by the standards, except for recordkeeping and reporting
requirements, when the process unit has a total design capacity less than •
1 Gg/yr (2.2 million Ibs/yr) of all products manufactured by that process
unit. This includes all listed and unlisted chemicals. In order to clarify
the meaning of this exemption, Section 60.660(c) has been amended to read
"... total design capacity less than 1 Gg/yr ".
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As required under Section 60.665(i), recordkeeping is needed only for
changes in process operation that increase the design production capacity of
the process unit containing the affected facility. Furthermore, semiannual
reporting is required under Section 60.665 (1)(6) only when these process
changes occur (see comment 2.10.2).
The EPA has decided to exempt process units with production capacities
lower than 1 Gg/yr from this NSPS because units of this size that produce a
listed chemical are typically used for research and development. Because
best demonstrated technology (BDT) was analyzed with respect to industrial
scale facilities and because the operation of research and development scale
facilities is different, BDT may not be applicable.
2.1.6 COMMENT: Two commenters (D-12 and D-24) requested that the
applicability date of the standards cited in Section 60.660(b) be changed
from December 30, 1983, to the date that the final rule is promulgated. It
was stated that any plants which start construction before the rule is
promulgated do not have a defined, final set of standards for design of their
distillation system.
RESPONSE: The EPA plans no change in the applicability date of the
standards as stipulated in Section 60.660(b). (Section lll(a)(2) of the
Clean Air Act (CAA) defines new sources as those that commence construction
after proposal). This date marks the time after which a distillation
facility may be considered an affected facility. However, compliance is not
required until after the promulgation date to allow for the final rule to
first be established before the compliance period begins. As noted in the
response to comment 2.1.4, all facilities that start up between proposal and
promulgation have a reasonable time after promulgation to demonstrate com-
pliance with a performance test. Furthermore, although subject to change,
the proposed standards provide an indication of what will be contained in the
final standards.
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2.1.7 COMMENT: Several commenters (D-8, D-ll, D-20, and D-22) stated
that the proposed standards do not seem to adequately treat the complex
nature of batch operations. These commenters suggested the standards be
applied on a case-by-case basis for batch distillation systems because the
vent streams from these operations often have variable characteristics. For
example, batch vacuum distillation may have an initial higher vent stream
flow rate as noncondensibles are removed from the products being purified
followed by very low emissions for most of the cycle. The commenter stated
that application of a recovery system for compliance with a TRE greater than
1.0 is likely to represent greater difficulty and cost impact on batch
distillation facilities than anticipated by the Agency.
RESPONSE; The EPA has decided to exclude batch distillation operations
from this NSPS because BDT was evaluated with respect to continuous opera-
tions which have relatively constant vent stream flow rates and compositions
within a process unit. Batch distillation typically emits a vent stream of
variable flow rate and composition during its operation. As a result, BDT may
not be applicable to vent streams from batch processes. The Agency is
currently investigating the need for an NSPS for batch processes within the
SOCMI separately from this NSPS.
Section 60.660 has been revised to specifically exempt batch
distillation operations. The following definition has been added to
Section 60.661: "'Batch Distillation Operation' means a noncontinuous
distillation operation in which a discrete quantity or batch of liquid feed
is charged into a distillation unit and distilled at one time. After the
initial charging of the liquid feed, no additional liquid is added during the
distillation operation."
2.1.8 COMMENT: Four commenters (D-9, D-17, D-24, and D-25) called for
the exclusion of certain chemicals listed in Section 60.667 that are con-
sidered to be low in photochemical reactivity. The commenters stated the
listing of five chemicals in the regulation is inappropriate because these
chemicals also appear in the list of chemicals determined to be negligibly
photochemically reactive by EPA (48 FR 57541) and thus are not considered to
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be VOC. The commenters list the chemicals in question as the following:
dichlorodifluoromethane; methylene chloride; trichlorofluoromethane;
trichlorotrifluoroethane, and 1,1,1-trichloroethane.
In addition to the five nonphotochemically reactive chemicals listed by
EPA in the regulation, two commenters (D-17 and D-24) requested the removal
of perch!oroethylene from the list of chemicals in Section 60.667. The
commenters indicated that EPA has previously designated this chemical as a
negligibly photochemically reactive compound that does not contribute to
ambient ozone formation.
RESPONSE: The production of chemicals of negligible photochemical
reactivity does not preclude the presence of photochemical^ reactive com-
pounds in the vent streams of these facilities. For example, chlorinated
organics*'(e.g., perchloroethylene) which are considered to be photochemically
reactive can be present in the process vent streams from the production of
chlorofluorocarbons. Thus, EPA plans no change in the list of chemicals
covered by the the standards.
In any event, with respect to perchloroethylene, the Agency has only
proposed that perchloroethylene be considered as a negligibly photochemically
reactive compound (48 FR 49097). As discussed in responses to comments
2.7.1 and 2.7.2, negligibly photochemically reactive compounds are allowed to
be subtracted from the TOC emission rate used to calculate the TRE index.
However, perchloroethylene cannot be subtracted because its status has not
been promulgated.
-2.2 SELECTION OF AFFECTED FACILITY
2.2.1 COMMENT: Seven commenters (D-8, D-ll, D-13, D-20, D-22, D-23,
and D-27) disagreed with the designation of affected facility used in the
proposed standards. At proposal, the Administrator designated the affected
facility as a single distillation unit with the associated recovery devices
located within the process units which produce any of the chemicals listed in
Section 60.667. Other possible designations were also mentioned at proposal
and EPA specifically solicited comments concerning the proposed designation
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of affected facility. The commenters indicated that the proposed designation
of affected facility is unrealistic and unrepresentative of the way
distillation units are operated within the industry. According to the
commenters, distillation units are often physically linked together and to
artificially separate them would be inappropriate. The commenters pointed
out that many processes consist of a series of distillation units and in some
cases, units receive, as feedstreams, the product streams of other units.
Under these conditions several units can use a common recovery device. They
concluded that in these cases, application of VOC reduction requirements and
monitoring methods under the proposed designation of affected facility would
be potentially confusing and costly.
The commenters prefer an affected facility to be designated as the
recovery system with all associated distillation units. The commenters
indicated that this designation would best reflect the way distillation units
are used within the industry. Also, ambiguities in monitoring and testing
requirements would be minimized when more than one distillation unit is tied
to a common recovery system. Overall, the commenters felt that this designa-
tion would reduce monitoring, control, and hardware costs incurred by affected
distillation facilities. Furthermore, the commenters expressed that
differences between emission reductions resulting from the EPA designation of
affected facility and the designation preferred by the seven commenters would
be small, if any.
The commenters stated that the broader affected facility designation
would allow a facility the flexibility to change operating conditions or
equipment in lieu of adding combustion devices. For example, the owner or
operator of an affected facility may reduce emissions in existing distilla-
tion units to offset increased emissions from new or modified distillation
units that become part of the facility. If this compensation is made, there
would be a zero net increase in emissions from the affected facility.
Therefore, no adverse environmental impact would result, yet economic and
energy conserving changes at a facility could be made.
One commenter (D-15) is in favor of the selection made by EPA because
this commenter believes the approach will allow for continuous improvement of
the air quality which is the intent of the standards. Another commenter
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(D-21) indicated that the definition of affected facility contained in the
proposed regulation conforms with the requirements of the CAA insofar as it
does not allow two or more distillation units which are joined to a common
recovery system to be interpreted as one facility.
RESPONSE: Based on these comments, the Agency reevaluated the
designation of affected facility and presented the results of the
revaluation in the Federal Register on May 16, 1985 (50 FR 20446). Based on
those results and the lack of adverse comment on that reevaluation, the
designation has been changed from a single distillation unit with the
associated recovery system to an individual recovery system and all
distillation units venting to that recovery system. For the majority of the
industry, this change will have no effect because approximately 80 to 90
percent of the industry's distillation units exist as individual units.
However, the effect of the designation change will be seen for the remaining
10 to 20 percent of the distillation units that share recovery devices. This
change was not made to provide industry with operating flexibility; rather
the new designation is estimated to result in greater emissions reduction.
Also, as discussed at the end of this response, the new designation would
facilitate the implementation of the standards because, in some cases, the
cost and complexity associated with determining a TRE index will decrease.
The EPA estimates a greater reduction in national VOC emissions because
of the change in designation of affected facility. Greater reduction in
emissions will occur with the new designation because for facilities where
the TRE is less than 1.0, emissions from existing distillation units will
also be controlled when new units are combined with existing units sharing a
common recovery system. The Agency believes that a widespread evasion of the
modification provisions would not occur under this designation. For example,
a change that would be considered a modification is made to one distillation
unit within a group of existing units. In order to avoid a modification, the
common recovery system is upgraded so that no emissions increase results.
However, operational or physical changes that would be considered modifica-
2-23
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tions are rarely made to individual distillation units sharing a recovery
device. Instead, it is more likely that new distillation units would be
added to an existing group of units resulting in increased emissions.
In the event an owner added a distillation unit to an existing group of
units ducted to the same recovery system, it is unlikely the facility could
avoid being considered a modification by offsetting the new distillation unit
emissions somewhere else within the distillation group. This is because it
would likely be technologically infeasible to reduce emissions sufficiently
from the other distillation units. Although some VOC reductions could occur
through upgrading recovery equipment, it is unlikely that this reduction
would result in a full offset of the new distillation emissions unit because
the increased load on the recovery device (i.e., increased flow and VOC)
would make the needed increase in VOC removal efficiency difficult to achieve.
Thus, the likely result is that addition of a distillation unit to a group of
joined units would bring the entire set under the coverage of the standards
as a modified facility. Even though it is unlikely to occur, if the owners
or operators of the facility could completely offset emissions from a new
distillation unit by upgrading the recovery system, it would be the equivalent
of 100 percent VOC control for that new distillation unit. This is 2 percent
more than would be necessary if the individual units were designated as
affected facilities and 98 weight-percent control were applied.
The EPA believes that coverage of equipment through the reconstruction
provisions will not be avoided under the broad designation because major
physical changes (i.e., reconstructions) to individual distillation units
within a group of units rarely occurs within the industry. It is not likely
that an owner or operator of an affected facility made up of a group of
distillation units could replace one of the units and avoid being considered
a reconstruction. Available data show this situation would not arise because
the replacement of the individual distillation units or pieces of recovery
equipment is rare within the industry. This is because distillation units
are expensive pieces of equipment which are designed to last a long time
(Docket Item No. II-B-13). Moreover, the Agency has concluded that those few
replacements which do occur often result from process changes or catastrophic
events that would probably require replacement of most of the group of
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distillation units joined to a single recovery system. These changes would
likely amount to a "reconstruction" of the facility as it is defined in these
standards. Thus, in the small percentage of cases where distillation unit
replacements occur, the facility would most likely fall under the coverage of
the standards.
An incidental effect of this change in the affected facility designation
is that implementation of the standards would be made significantly easier.
When two or more distillation units are joined to a common recovery system,
determining a TRE index value is less complex and less costly because fewer
test sites are required to measure the vent stream characteristics needed to
calculate a TRE index value. Under the designation of these standards set
forth at proposal, it was required only that the portion of the combined vent
stream contributed by the new, modified or reconstructed distillation unit
comply with the standards when it shares a recovery system with existing
units. Therefore, the TRE index value was determined for the portion of the
stream contributed by that unit only. This determination was complex and
costly and was based upon an apportioning method using sampling sites located
just downstream of the new unit and sampling sites located upstream and
downstream of the common recovery system. These sampling data were to have
been used to determine the overall efficiency of the common recovery system.
This efficiency was then to have been applied to the vent stream of the new
unit to determine its contribution to the total emissions from the common
recovery system.
Under the new designation, the standards require only one sampling site
located after the last recovery device to determine a TRE index value. No
determination of recovery efficiency is needed in this case because the
entire vent stream is covered. Therefore, there is no need to determine
which portion of the final vent stream from a group of distillation units is
attributable to new, modified, and reconstructed distillation units and which
portion is attributable to distillation units that have not been changed or
added. This results in a performance test requirement that is less costly
and less complex because fewer sampling sites and subsequent analyses are
needed.
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2.3 DEFINITIONS
2.3.1 COMMENT: Three commenters (D-8, D-13, and D-33) proposed
modifications of the definition for "vent stream" in Section 60.661 where the
term is designated to mean any gas stream released to the atmosphere from any
distillation unit. Two of the commenters (D-8 and D-33) expressed that
equipment leaks should be clearly excluded from the definition so that the
wording would apply only to VOC-containing streams. Two commenters (D-13 and
D-33) requested that the definitions of "vent stream" be made less broad so
as to exclude relief valve discharges. The commenters added that equipment
leaks and relief valve discharges are already covered by other NSPS.
RESPONSE: This NSPS is not concerned with regulating equipment leaks or
relief valve discharges of VOC. These sources are regulated by an NSPS for
fugitive emissions in the SOCMI (48 FR 48328). In order to clarify the
meaning of "vent stream" as used in this regulation, the Agency has amended
Section 60.661 as follows: "vent stream" means any gas stream released to
the atmosphere from any distillation facility excluding equipment leaks and
relief valve discharges.
2.3.2 COMMENT; One commenter (D-19) asked if the definition of
distillation operations excludes those distillation units that have one
product stream. The definition of "distillation operations" in
Section 60.661 of the proposed regulation states that one or more feed-
stream(s) are separated into two or more product streams during a
distillation operation. The commenter also inquired about still bottoms
being considered as a product stream according to this definition.
RESPONSE: The number of product streams exiting a distillation unit
would not be used to determine if it would be an affected facility. As
indicated in Section 60.660(a), the standards are applicable to any
distillation facility operating as part of a process unit producing any of
the chemicals listed in Section 60.667 as a product. Even if a listed
chemical were not produced as a product by a distillation unit, that unit
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would be affected by the standards if it were part of'a process unit pro-
ducing a listed chemical as a product. A discussion concerning the meaning
of "product" for the purposes of this NSPS is given in the response to
comment 2.1.2. To further clarify the applicability of the distillation
NSPS, the definition of distillation operations in Section 60.661 has been
amended to read "'distillation operation' means an operation separating one
or more feedstream(s) into two or more exit streams . . . within the
distillation unit."
In order for still bottoms or any other stream exiting a distillation
unit to be considered a product, the stream must contain a chemical listed in
the regulation. Furthermore, the stream must either be sold as that listed
chemical or used in another process requiring that listed chemical.
2.3.3 COMMENT: Two commenters (D-ll and D-12) stated that since some
process heaters may transfer heat to process fluids not contained in tubular
coils, any definition of process heater should not include a reference to
tubular coils. Therefore, both commenters suggested that the reference to
"tubular coils" be eliminated in the definition of "process heaters" in
Section 60.661 of the regulation.
RESPONSE: The Agency agrees that some process heaters do not have
tubular coils, but instead have straight-tube or U-tube arrangements. Thus,
to further clarify the definition of "process heaters," Section 60.661 has
been amended so that "tubular coils" is replaced by "tubes."
2.3.4 COMMENT: One commenter (D-27) stated that "TOC" as used in the
preamble is a poor abbreviation for total organic compound. The meaning for
"TOC" is more commonly taken to be total organic carbon.
RESPONSE: Because there is no reference to total organic carbon in the
preamble or regulation, the Administrator feels that "TOC" is not an
ambiguous abbreviation for the purposes of this NSPS. Furthermore, the term
total organic compound is clearly defined in the beginning of the regulation.
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2.3.5 COMMENT: One commenter (D-19) stated that the definition of
"corrosive vent stream" in Section 60.661 is not clear. The commenter was
uncertain whether EPA means streams containing the equivalent of 20 parts per
million by volume (ppmv) halogens or 20 ppmv halogen-bearing compounds are
corrosive. The commenter stated that the use of a 20 ppmv halogen-bearing
compound limit could result in a significant range of halogen concentrations
in the incinerator flue gas depending on the percentage of halogen in the
compound.
RESPONSE: The EPA considers a vent stream to be corrosive when the
stream concentration of halogen-bearing compounds is 20 ppmv or greater. The
Agency is aware that even small amounts of halogenated compounds may be
corrosive and can necessitate the use of an incinerator with a scrubber
system. It was judged that this 20 ppmv concentration is low enough to
account for this situation, even if many halogen atoms are attached to one
compound (e.g., carbon tetrachloride). Therefore, the control cost and TRE
were not underestimated for any facility.
In order to be consistent throughout the regulation, the phrase
"corrosive vent stream" in Section 60.661 (Definitions) has been changed to
"halogenated vent stream." However, the definition for halogenated vent
stream will remain the same as the earlier corrosive vent stream definition.
2.4 SELECTION OF BDT
2.4.1 COMMENT: One commenter (D-24) requested clarification on whether
BDT for the proposed standards would qualify as a best available control
technology (BACT) or lowest achievable emission rate (LAER).
The commenter also stated that NO emission increases resulting from the
A
combustion of process vent streams could bring combustion sources under BACT
review in attainment areas. In light of this, the commenter suggested that
EPA review the impact on costs associated with NO emission increases from
A
flares, boilers, and incinerators.
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RESPONSE: The BDT for the standards will be considered in defining BACT
or LAER in each plant-specific evaluation. The evaluation encompasses a
consideration of emissions such as S0? and NO as well as VOC emissions.
fc A
There are situations, however, where the emissions reduction required for a
pollutant under BACT or LAER may be greater than that which results from the
NSPS. The BACT is defined in Section 169(3) and LAER is defined in
Section 171(3) of the CAA.
Any NOX emissions increase resulting from the combustion of distillation
vent streams under the NSPS are not expected to be great enough to bring the
combustion sources under BACT review in attainment areas. A distillation
facility under BACT review would be required to control its NO emissions if
f ^
an increase in NOX of 40 tons per year or more occurred as required under
40 CFR 51.24(B)(23)(i). In order to estimate the likelihood that a 40 ton
per year increase in NOX emissions would occur as a result of vent stream
combustion of VOC emissions, two analyses were performed (Docket Item
No. IV-B-16). Typically, distillation vent streams in SOCMI contain non-
nitrogenous VOC compounds. One analysis was done for a facility with
non-nitrogenous VOC compounds in the vent stream. This analysis maximized
potential NOX emissions from an example facility by using the highest flow
rate vent stream found in the available emissions data along with a high VOC
concentration. The total amount of NOX as NOp estimated by this analysis is
less than 10 tons per year. An additional analysis was performed for the few
cases where the vent stream does contain nitrogenous compounds. For this
analysis the highest vent stream flow rate was also assumed and it was assumed
that this vent stream contained a high concentration of nitrogenous compounds.
The total amount of NOX as N02 estimated for this case is less than 30 tons
per year. Thus, analyses show that the combustion of vent streams from the
production of a listed chemical would not be expected to require the control
of NOX under a BACT review. Therefore, costs associated with NO control
will not be examined for this NSPS.
2.4.2 COMMENT: Eleven commenters (D-5, D-7, D-ll, D-12, 0-13, D-14
D-19, D-22, D-23, D-24, and D-27) are concerned that the flare specifications
listed in the proposed standards for combustion of process vent streams are
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too strict. The specifications set a minimum heating value at either
11.2 MJ/scm (300 Btu/scf) or 7.45 MJ/scm (200 Btu/scf) (depending upon the
type of flare) and an exit velocity of less than 18 m/sec (60 ft/sec).
Commenters (D-5 and D-22) suggested that whatever changes are made to the
flare specifications under the standards of performance for SOCMI equipment
leaks of VOC (48 FR 48328 October 18, 1983) should also be applied to this
proposed NSPS to maintain consistency.
Various reasons were given by the commenters why EPA should reconsider
using the flare specifications now listed as part of the distillation
standards. Four commenters (D-7, D-12, D-22, and D-24) stated that little
data and not a broad enough range of test conditions were used to establish
the specifications. It was also stated that the technical basis for the •
specifications should be explained. Commenters (D-7, D-ll, D-12, and D-23)
asserted that flares at higher velocities provide highly effective VOC
control. One commenter (D-27) stated that the vent stream minimum heating
value requirement for flame stability should be 150 Btu/scf, instead of the
300 Btu/scf in the proposed standards. Another commenter (D-19) remarked
that the EPA flare specifications on flare gas velocity and Btu content are
not reasonable and should be shifted to a performance based standard. The
commenter felt that the presence of a suitable flame should be the main
indicator of an efficient flare.
Several commenters were concerned that the specifications would have
negative effects upon the cost and operation of flares. Two commenters (D-ll
and D-13) noted that the use of advanced technology flares such as some
Linear Relief Gas Oxidizers (LRGO) would be precluded by the velocity
restrictions. Other commenters (D-13 and D-23) stated that normal and
emergency venting for pressure relief would be hindered by the flare maximum
velocity specification. Both commenters requested a provision for the waiver
of the maximum velocity of 60 ft/sec during periods of emergency pressure
relief. Three commenters (D-7, D-ll, and D-33) stated that the proposed
flare specifications would have a large economic impact on some existing
facilities that would come under the regulation of these standards. These
plants already use flares designed and operated at velocities considerably
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higher than the 60'ft/sec specification. Two of the commenters (D-ll and
D-33) stated that construction of new flares to meet the velocity
restrictions will be costly and in many cases completely infeasible.
One commenter (D-14) remarked that it should be possible to show that a
velocity lower than 60 ft/sec combined with a lower Btu content than either
300 or 200 Btu/scf (depending upon the flare type) would lead to a reduction
efficiency of at least 98 percent. It was noted the standards as written do
not give'proper credit for control devices prior to flares, such as vent gas
scrubbing systems that cause the vent stream heating value to decrease due to
the removal of organics. The commenter indicated that it may be unnecessary
to add natural gas to scrubbed vent streams if an exit velocity less than 60
«
ft/sec were used.
One commenter (D-27) requested an extension of the comment period so
they could review the Energy and Environmental Research report on flares
prepared for EPA.
RESPONSE: Because of the technical infeasibility of testing for the VOC
reduction efficiency of flares, EPA determined it necessary to set opera-
tional specifications to ensure 98 weight-percent reduction efficiency. The
original specifications were based upon the best data available at the time
of proposal. Based on new data on flare performance obtained since proposal,
EPA developed revised flare operating specifications and proposed these
specifications on April 16, 1985 (50 FR 1494). After receiving public
comments on the revised specifications, they were finalized and incorporated
into 40 CFR 60.18 of the General Provisions (January 21, 1986, 51 FR 2699).
During this period the commenters were given opportunity to review the new
study on the efficiency of flares and to comment on the study and the revised
operating specifications.
Two commenters noted that LRGO flares could not be used with the
60 ft/sec exit velocity limitation. The EPA does not have sufficient data to
evaluate the reduction efficiency of LRGO flares at exit velocities greater
than 60 ft/sec. However, the Agency will evaluate any data submitted by the
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SOCMI to demonstrate the 98 percent reduction efficiency of LRGO flares. If
these flares are judged to be capable of achieving 98 percent reduction
efficiency then they could be used in complying with the standards.
Two commenters requested a provision for the waiver of the maximum
velocity of 60 ft/sec during periods of emergency pressure relief. Emergency
venting is considered a malfunction and allowed under these standards and
there is no need for a waiver. However, records must be kept of each
•occurrence and its duration as required under Section 60.7(b) of the General
Provisions. Recordkeeping is required so that EPA will be able to determine
how many malfunctions are occurring and then be able to determine if the
device is being properly operated and maintained.
it
Two commenters stated that the exit velocity limitation of 60 ft/sec
when the gas stream heating value is less than 1,000 Btu/scf could necessi-
tate the replacement of existing flares designed and operated with velocities
greater than 60 ft/sec. However, EPA believes existing facilities coming
under the regulation of the standards would not have to completely replace
these flares. Instead of building a new flare, only the existing flare tip
and some auxiliary equipment would have to be changed to accommodate the
60 ft/sec limitation. Considering that many components of the existing flare
could still be used, EPA has judged the cost of modifying an existing flare
to be well below the cost estimated to construct an entire flare.
Furthermore, the cost of constructing a new flare was found to be reasonable,
and the TRE equations are based on new flare costs. Therefore, the cost
impacts for facilities which choose to control VOC by modifying an existing
flare should also be reasonable.
The requirement that vent streams to be flared have a heating value of
at least 300 Btu/scf, if air or steam assisted flares are used, is necessary
because available data show that for some flares, flame stability and 98
percent emissions reduction cannot be consistently maintained below a heating
value of 300 Btu/scf. Furthermore, it is important to maintain the flare
specifications and not only rely on the presence of a flame, as suggested by
one commenter. Data indicate that some flares with a visible flame can not
achieve a reduction efficiency of 98 percent (Docket Item No. IV-A-1).
Another commenter requested that specifications for velocities lower
than 60 ft/sec be provided and that.lower fuel requirements be specified for
these velocities. However, the current available data do not indicate that
0 1O
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an emissions reduction of 98 percent or greater can be constantly maintained
at heating values below 300 Btu/scf or 200 Btu/scf depending on flare type
and exit velocities lower than 60 ft/sec.
2.4.3 COMMENT: One commenter (D-10) stated that catalytic oxidation
can be an attractive alternative to thermal incineration. He indicated that
although catalytic oxidation can be designed for high VOC reduction
efficiencies, economic factors dictate whether these levels are practical.
The commenter added that the 98 percent reduction efficiencies associated
with the proposed standards would possibly require the use of uneconomically
large catalyst volumes in catalytic incinerators or require the use of
thermal incinerators. The commenter pointed out that 98 percent reduction
efficiency may not result in a measurable improvement in the environment over
the case of catalytic oxidation at an efficiency slightly lower than
98 percent. Furthermore, the use of thermal incineration may 'potentially
entail the following detrimental effects: (a) higher energy usage by the
affected facilities; (b) an increase in NO emissions from the affected
A
facilities using thermal incineration; and (c) a decrease in the inter-
national competitive position of domestic chemical producers with respect to
foreign competition.
RESPONSE: The EPA has determined that, where catalytic oxidation units
are applicable, they can achieve 98 weight-percent reduction efficiency.
However, since using catalytic oxidation for VOC emissions reduction has not
been demonstrated to be universally applicable for all distillation process
vent streams, catalytic oxidation was not evaluated by the Agency. Catalytic
oxidizers are limited by their inability to handle streams with high heating
values because deactivation of the catalyst occurs at high temperatures.
Catalysts can also be deactivated by compounds present in some waste streams,
such as arsenic, sulfur, mercury, lead, zinc, or tin.
The Agency evaluated two control techniques universally applicable
within the industry, therma-1 incineration and flaring. The Agency examined
emissions data from incinerators and flares already operating within the
industry, as well as incinerator and flare tests conducted by the'Agency and
by chemical companies. All the new, well-operated incinerators and flares
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were found to achieve 98 percent reduction efficiency. From the available
data the Agency determined many facilities could achieve 98 percent reduction
efficiency at a reasonable cost using thermal incineration and flaring. The
Agency has bounded the cost impacts associated with combustion devices by
costing the most expensive devices: thermal incinerators and flares. Costs
associated with these devices were found to be reasonable for facilities with
TRE index values less than 1.0. Therefore, if a stream does exist whose
constituents are such that a catalytic oxidizer is not applicable or if the
cost of using a catalytic oxidizer is too high for a particular situation, a
flare or thermal incinerator can be used.
When evaluating the economic effects of this NSPS, EPA calculated the
maximum chemical price increases that-could be expected as a direct conse-
quence of the standards. Because these "reasonably worst-case" price
increases were quite small, EPA can be sure there will be no significant,
unexpected, harmful economic effects associated with 'the standards. To be
sure, price changes are not the only economic effects of an NSPS, but if
potential price changes are small, there is no reason to suspect that the
NSPS might trigger significant changes in profits, interest rates, industry
growth, employment, production, competition, foreign trade, and related
economic variables. In general, firms will not build, modify, or reconstruct
production facilities until a reasonable return can be expected on the
investment, including the investment in pollution control. If the cost of
pollution control is not offset by improvements in reactor catalysts,
marketing economies of scale, etc., then firms may delay construction plans
for a short period until prices rise to cover the pollution control costs.
The commenter is particularly concerned that EPA, by riot allowing
catalytic incinerators to substitute for thermal incinerators, will create a
competitive disadvantage for U. S. plants vis-a-vis foreign competition.
However, the Agency is not preventing the use of catalytic incinerators.
They may be used if the emission reduction requirements are satisfied.
Furthermore, if an owner or operator chose to use a thermal incinerator, no
economic disadvantage should be created vis-a-vis foreign competition. Using
reasonable control estimates, chemical price increases are expected to range
from 0 to about 4 percent.
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The energy and environmental effects mentioned by commenter D-10 were
considered in selecting thermal incineration as one of the control techniques
upon which the impacts of the standards are based. The energy consumption
and cost associated with thermal incineration were considered and found to be
reasonable because these can be offset by the use of recuperative heat
exchangers. The potential for increased NOX emissions was also examined, but
the rate of N0x formation is expected to be low due to relatively low
combustion temperatures and relatively short residence times associated with
thermal incineration.
2.4.4 COMMENT; A request was made concerning the use of control
techniques other than combustion. One commenter (D-12) stated that industry
should be allowed to use switching condensers for control of VOC emissions if
98 percent reduction of VOC is achievable. A switching condenser operates
such that the condensate is removed by freezing on the heat exchanger
surface, and would probably work effectively in general VOC control service.
Another commenter (D-21) stated that the consideration of emission
control technologies should be expanded to include the evaluation of
technologies other than flaring or incineration. The commenter recommended
that technologies which involve lower costs and energy requirements than
flaring or incineration be evaluated for application to distillation
facilities for which flaring or incineration has been determined to have too
high a cost-effectiveness value. Specifically, the commenter pointed to
product recovery devices, such as carbon adsorption, or other devices such as
catalytic oxidation as technologies which should be examined further by the
Agency for application to sources which are currently exempted from the
emission reduction requirements.
RESPONSE: Several VOC control technologies such as recovery devices
(including condensers) and catalytic oxidizers were also examined but were
not included in the impacts analysis because the Agency was unable to
identify subcategories for which those devices would always apply. The
applicability and effectiveness of adsorption, absorption, or condenser
devices for VOC emission control is sensitive to several physical
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characteristics of the organics in a vent stream and other stream
characteristics. Organic characteristics such as solubility, molecular
weight and liquid/vapor equilibrium are important to the success of using
specific recovery devices for VOC control. Vent stream moisture content is
also important. However, these characteristics are variable from vent stream
to vent stream making it difficult to identify which particular recovery
device would be appropriate for application to categories or subcategories of
distillation vent streams.
In the case of catalytic oxidizers, these control devices are limited
by: (1) their inability to combust all streams equally as efficiently, (2)
the high capital cost of the catalyst, and (3) their inability to handle
streams with high heating values. In addition, deactivation of the catalyst
in these systems occurs at high temperatures. This is likely to occur during
incineration of streams with high heating values, which is a common situation
for distillation facilities. Catalysts can also be deactivated by compounds
present irr some waste streams, such as sulfur, bismuth, phosphorus, arsenic,
antimony, mercury, lead, zinc, or tin.
Because of these susceptibilities to individual waste stream
characteristics, using catalytic oxidation or recovery devices (including
condensers) for VOC emissions reduction has not been demonstrated to be
universally applicable to any identifiable subcategories of distillation
process vent streams. The VOC reduction efficiencies may vary among
processes and among plants. Although catalytic oxidizers and recovery
devices were not included in the impacts analysis, these devices can be used
to meet the requirements of these standards if they can achieve the
98 percent VOC reduction requirement on streams to which they are being
applied.
Since the Agency is unable with available information and resources to
identify subcategories of distillation operations for which other VOC control
techniques have been demonstrated to always apply, there is no way to evaluate
techniques for application to distillation units for which thermal incinera-
tion and flaring have been determined to be too costly. Even with greater
resources, this approach would be infeasible because it would require a
stream-by-stream characterization, ultimately resulting in the need for a
separate standard for each vent stream from a process used to produce a
distillation chemical. The number of standards required to regulate the same
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number of sources would increase by several hundred. The Agency believes
that such an approach to regulating the SOCMI distillation industry would be
administratively infeasible and therefore environmentally counterproductive.
In any event, proceeding now with this generic regulation based on thermal
incineration and flaring at least represents an important first step in
regulating distillation emissions and does not preclude later regulation of
subcategories of distillation facilities should that become feasible. The
EPA believes it has the authority to take this step by step approach under
Section 111. See, e.g.. Group Against Smog and Pollution v. EPA. 665 F.2d
1284 (D.C Cir. 1981).
2.5 COST ESTIMATION
2.5.1 COMMENT: One commenter (D-15) suggested that the cost analyses
presented in the preamble and BID that were used in developing the TRE index
should be reevaluated. Several expenses were not included in the EPA cost
equations. New cost equations should include:
(a) the cost of pipeline required to retrofit a distillation column in
an existing plant to control vent stream emissions;
(b) the cost of locating combustion units in relatively remote areas
to avoid a safety hazard;
(c) the cost of supplemental fuel required by flares for distillation
vent streams with low net heating values; and
(d) the cost of monitoring equipment and recordkeeping.
RESPONSE: In response to this and other comments, the Agency reexamined
the costing procedures used for the distillation operations NSPS. In addition
to reexamining the costing procedures in light of these comments, many other
cost assumptions not commented upon by industry were examined and, in some
cases, changed to include more up-to-date information. When making revisions
to the costs, the goal has been to provide an updated estimate of total
annualized costs that are representative of the actual costs experienced by
the majority of facilities in the industry. Industry comments, particularly
those dealing with recommended equipment additions, were first carefully
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evaluated by EPA to determine if inclusion of such items were reasonable. If
the addition of equipment was found to be valid, costs for that equipment
were estimated and included. This approach was used for recommended
operating cost revisions as well.
This commenter stated that new cost equations should include the cost of
pipeline required to retrofit a distillation column in an existing plant.
The EPA determined that since use of a new combustion device at a new plant
should be the basis of costing, duct length criteria should be based on the
most probable location of a new combustion device. Based on criteria
established by the National Fire Protection Association (NFPA) and the
Industrial Risk Insurers, EPA revised its design criteria to include 200 feet
of ducting between the edge of the process unit and an incinerator and 300
feet of ducting between the edge of the process unit and a flare. An addi-
tional 100 feet of ducting was included in the costing to route the vent
stream from the distillation unit vent to the edge of the process unit.
Installation factors are included in the costing.
The costs of locating combustion units in relatively remote areas to
avoid a safety hazard are implicit in the costing assumptions described
above. A combustion unit is expected to be located as close as possible to
the process unit, but far enough away to provide safety. For this reason,
the Agency used insurance underwriter criteria for locating combustion
sources at a safe distance from process equipment as a basis for costing.
The cost of supplemental fuel required by flares for distillation vent
streams with low heating values was reevaluated by EPA in its operating cost
revisions. For those distillation vent streams having heating values less
than 300 Btu/scf (11.2 MJ/scm), gas enrichment is necessary to comply with
the flare requirements of the proposed standards. It is likely that most
vent streams would be enriched through the addition of natura'i gas.
Therefore, the cost algorithm has been changed to incorporate the cost for
adding enough natural gas to achieve a vent stream heating value of
300 Btu/scf (11.2 MJ/scm).
The cost of monitoring equipment and recordkeeping is not included in
the cost analyses that were used in developing the TRE equations. However,
these costs were estimated and determined to be reasonable to ensure proper
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operation and maintenance of either the recovery system or the control
device. The TRE equations are used to determine BDT for each affected
facility. All costs associated with reducing VOC emissions by 98 weight-
percent or to 20 ppmv using either a flare or a thermal incinerator have been
included in the TRE equations. These are the costs that are the basis of the
BDT determination. Once this determination is made, the costs associated
with monitoring the recovery system or control device to ensure proper
operation and maintenance were estimated. The costs were then evaluated and
used to determine which monitoring and recordkeeping requirements were
necessary and reasonable. However, the TRE equations which are used to
determine BDT for an affected facility do not include monitoring or
recordkeeping costs.
2.5.2 COMMENT: Three commenters (D-ll, D-27, and D-37) stated that the
cost equation for flare systems result in costs that are too low. One
commenter (D-27) reevaluated a specific case for flare costing, and felt that
EPA has underestimated the total installed capital (investment) cost by a
factor of 3 and the annual cost by a factor of 2. The reason for the low
estimate of capital cost, according to commenters D-27 and D-37, is that EPA
did not adequately include all the services and auxiliaries needed to make
the system operate. The major capital cost-items identified as being either
overlooked or not adequately treated by EPA include the following:
(a) 500 feet of new pipe bridge; (b) all steam, natural gas and electrical
services to the flare; (c) knock-out drum and fluidic seal; and (d) a TV
camera to observe flare operations for smoke and a TV monitor in the central
control room. Major annual cost components identified as being either
overlooked or not adequately treated by EPA include the following:
(a) general plant overhead estimated as 50 percent of operating and main-
tenance labor costs; (b) engineering and environmental oversight costs
estimated as about 40 percent of maintenance and operator labor costs;
(c) labor and supervision for maintenance estimated as 3 percent of the total
installed capital costs; and (d) operating supplies estimated as 15 percent
of maintenance costs. Miscellaneous cost components that the commenter said
were overlooked by EPA include the following: (a) a general contingency
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allowance; (b) a labor allowance for bad weather; (c) the cost of a strip
chart recorder for temperature monitoring; and (d) electrical control room
equipment.
The same commenter (D-27) indicated EPA has made two basic flare design
errors that would result in additional material and operating expenses. One
flare design error results in an unsafe continuous heat intensity at ground
level. A much lower heat intensity should be used, resulting in a greater
flare height, and therefore greater capital and annual costs. However, the
commenter did not recommend an alternative value for ground level heat
intensity. The other design error indicated by the commenter is that the
flare tip pressure drop of 27 inches of water is too high for the 60 ft/sec
exit velocity limitation in the proposed standards. The 27 inch pressure
drop is also inconsistent with smokeless flare operation. The commenter
suggested the pressure drop be specified at less than 1 inch of water, which
would require a greater flare tip diameter and an increase in the estimated
capital cost.
One commenter (D-ll) stated that the EPA flare specifications would
result in higher capital and operating costs than the costs estimated by EPA.
The increased costs would be due to the larger diameter flares needed to meet
the flare specifications of 60 ft/sec exit velocity and a 300 or 200 Btu/scf
(depending on flare type) minimum heating value. Examples of these increased
costs include: (a) an increase in pilot gas requirements; (b) shortening of
flare tip life due to higher operating temperatures when exit velocities at
or below 60 ft/sec are used; and (c) added purge gas requirements during
shutdown and periods of no flow to the flare.
RESPONSE: In response to commenters' concerns regarding flare costing
assumptions, the Agency has reevaluated all costing assumptions and revised
them where it was justified. Throughout the development of the distillation
NSPS the Agency has made efforts to ensure that the cost algorithm resulted
in estimates that adequately represent control costs anticipated to be
incurred by the majority of facilities in the industry. Prior to proposal,
industry members were given the opportunity to provide substantial input into
the development of the cost algorithm. Preliminary costing assumptions were
reviewed by industry and subsequently revised based upon industry input.
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After proposal, costing assumption revisions were prepared and presented in a
supplemental Federal Register notice (50 FR 20446) on May 16, 1985. This
notice solicited further comments on costing procedures. The bases for these
revisions are documented in Docket Entry IV-B-8. The Agency feels confident
that the revised cost procedures represent accurate estimates for typical
facilities.
Revisions to the capital cost assumptions included the addition of the
costs of a new pipe support system for use in routing flare services and the
vent stream to the base of the flare. The 500-ft pipe bridge referred to by
the commenter is apparently a heavy-duty support structure capable of
supporting several large diameter pipes or ducts. Based on vent stream data,
the Agency judged that the flare-system would need a structure capable of
supporting relatively small diameter pipes or ducts and the number of these
pipes or ducts would be few. Therefore, the cost for a lighter weight pipe
rack was included in the cost algorithm instead of a pipe bridge.
Flare services (steam, air, and natural gas) were not included in the
original cost analysis for the proposed distillation standard because EPA
originally thought that existing flare services would be available. Upon
review of the requirements for flares dedicated to the control of distillation
vent streams, EPA determined that it was appropriate to include the capital
costs for flare services because many new flares would be built at locations
remotely located from existing flare services. Estimated capital costs for
flare services include pipe suspension and installation costs. The commenter
included electrical services in the flare services item. Capital costs
associated with electrical services are accounted for in the installation
factors built into the costing procedures. These include a 0.01 electrical
factor under installation, a 0.03 contingency factor under indirect costs and
a 0.10 construction and field factor under indirect costs. These installa-
tion factors are meant to account for any variability of costs beyond the
actual costs for the flare itself and are consistent with engineering cost
estimation practices.
The knock-out drum and fluidic seal are included in the estimated cost
for the flare system. Furthermore, EPA believes that these two devices have
been adequately accounted for in the costing procedure developed at proposal.
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The Agency has reviewed and, where appropriate, revised costing assump-
tions for annual cost components. The costing procedures; used at proposal
did include the calculation of operating labor, maintenance labor, and
overhead, but the maintenance labor and overhead calculations were not
separate, easily identified line items, making comparison of labor rates
difficult. Since procedures used at proposal were not well defined, and
because it is reasonable to assume supervisory labor will be needed in
operating the flare system, EPA decided to include supervisory labor costs
and to use an alternative method for calculating overhead costs. Supervisory
labor cost is estimated to be 15 percent of the operating labor cost.
Overhead labor cost is calculated as 80 percent of the sum of operating,
supervisory, and maintenance labor costs. Maintenance labor cost is
calculated as 3 percent of the total installed capital cost of a new flare
system. Previously, the cost of maintenance labor and parts had been
estimated together. Maintenance parts costs are now calculated as 3 percent
of total installed capital cost.
Engineering and environmental oversight costs were cited by the
commenter as being inadequately represented. However, EPA believes these
costs are adequately accounted for in its revised costing procedure. As
stated above, the Agency has considered supervisory labor in its revised
costing procedures. In addition, the costs of maintenance labor and
materials to ensure the proper operation and maintenance of control devices
are included in the costing procedures. The Agency considers these costs to
be representative of the costs associated with proper operation and
maintenance of the control devices. Because any additional labor needs as a
result of bad weather will be one time costs and are unpredictable, no
allowance was made in developing the costs associated with normal operation.
The Agency has reviewed flare design criteria to ensure they represent
the safe practices for workers in facilities complying with the standards.
The maximum ground level thermal radiation intensity design criterion used at
proposal (1,200 Btu/hr-ft2 from the flare alone) was determined to be too
high. A lower maximum ground level intensity (140 Btu/hr-ft2 from the flare
alone) has been selected. The EPA agrees that for vent streams having high
heating values and high flow rates, the revised maximum thermal radiation
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intensity at ground level lead to a taller flare design. However, the cost
for controlling most distillation vent streams would be unaffected by this
change because they typically contribute much less than 140 Btu/hr-ft2 at
ground level even when combusted through the shortest flare commercially
available (30 ft).
In the cost algorithm used at proposal, the pressure drop associated
with the flare tip was at least 27 in. water column, depending on the vent
stream characteristics. However, in reviewing the previously constructed
cost algorithm and the associated flare design criteria, EPA has determined
that a pressure drop of this magnitude is representative of a typical
emergency flare operation, not a flare designed for low velocity, continuous
vent stream such as for a distillation operation. A flare tip pressure drop
that is more representative of a dedicated flare designed to handle a con-
tinuous flow vent stream was calculated to be slightly lower than 0.5 in.
water column. The Agency does not believe that the flare tip design pressure
drop would promote smoking in an operating flare.
The EPA's revision of the flare design criteria to reflect the velocity
limitation included in the proposed standard resulted in an increased
diameter for the flare tip, and, therefore, a slightly increased capital cost
for some of the higher flow rate vent streams. For many distillation vent
streams,- the diameter calculated according to the revised design criteria
will be less than 2 inches, the smallest available flare diameter. These
streams would have required a 2-inch diameter flare according to the
previously used design criteria as well. For those distillation vent
streams, the cost of the flare would remain unchanged. However, for streams
with flow rates sufficiently high to require larger flare diameters using the
revised design criteria, the revision will cause a slight increase in capital
cost.
Pilot gas and purge gas costs are included in annual direct operating
and maintenance costs and have been calculated based on flare design
parameters. The commenter cited costs resulting from the shortening of flare
tip life due to higher operating temperatures. The Agency is aware that
combustion control equipment is subject to maintenance, repair, and replace-
ment. In the costing procedures, maintenance labor and maintenance parts are
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each included as 3 percent of the total installed capital cost of the
combustion system. The costing procedures also include annualized equipment
capital costs which are based on a 15-year life for flares.
The commenters suggested the inclusion of the cost of monitoring
equipment in the cost analysis and TRE equations. The items suggested
include a TV camera and monitor, a strip chart recorder for temperature
monitoring, and electrical control room monitoring equipment. While the cost
of the monitoring and recordkeeping requirements has been estimated and
determined to be reasonable, this cost was not included in the development of
the TRE equations. For further information, see response to Comment 2.5.1.
2.5.3 COMMENT: One commenter (D-9) stated that EPA did not include in
its cost estimates of combustion control systems the cost associated with
continuous recording of temperature measurements for incinerator fireboxes
and for boilers or process heaters. The commenter indicated that continuous
recording can be quite costly. A temperature range of 2,500 - 3,200°F is
common to the fireboxes of incinerators and boilers. Typically, platinum/
rhodium thermocouples are required to handle these temperatures, and such
systems commonly cost approximately $15,000 per installation.
RESPONSE: The EPA believes that the cost of an adequate temperature/
recording system would cost well below $15,000. In fact, vendor data show
the equipment cost could be approximately $4,500 even if a platinum/rhodium
thermocouple were needed (see Docket Entry IV-E-9). Furthermore, peak
temperatures exceeding 2,800°F are expected to occur for boilers where
temperature monitoring is required while the maximum temperature for an
incinerator firebox is expected to be around 2,000°F. Therefore, less
expensive materials than the commenter suggests could be used to monitor
incinerator temperatures. The Administrator has determined that the costs
associated with the monitoring requirements of the final standards are
reasonable. However, these costs were not included in the development of the
TRE equations (see response to Comment 2.5.1).
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2.5.4 COMMENT: Two commenters (D-12 and D-27) disagreed with the
assertion in the preamble that annualized costs associated with the disposal
of sodium chloride from scrubbing incinerator flue gases are insignificant.
Both commenters stated that disposal will be expensive unless the plant is
located near salt water and can get a permit to dump its brine. One
commenter (D-27) indicated that the operating costs for deep-well disposal of
sodium chloride range from $3 to $6 per 1,000 gallons of brine.
RESPONSE: The Agency has conducted an investigation into the methods of
brine disposal available to the chemical industry (see Docket Entry IV-B-11).
This investigation included a review of available literature and discussions
with State regulatory agencies, brine disposal companies, chemical manu-
facturers, and consultants. Alternatives available for brine disposal
include:
o Direct discharge.
o Evaporation.
o On-site deep well injection.
o Off-site deep well injection.
o Existing disposal method if the plant is already disposing of
brine solutions.
Of the disposal methods shown above, off-site deep well injection is
considered to be the most expensive and least popular. The option is
generally viewed as impractical by industry representatives due to its costs.
Based on available data, there appears to be no reason why any facility
covered by the distillation NSPS would not be able to select one of the other
lower cost options. It is assumed that all facilities will use the lowest
cost option available. Therefore, the Agency has no reason to believe that
any distillation facility will incur a significant brine disposal cost as a
result of this NSPS.
2.5.5 COMMENT: One commenter (D-27) recommended that all costs
discussed in the preamble be inflated from 1978 dollars to first quarter 1984
dollars. This commenter indicated that the cost-effectiveness cutoff would
then become $2,600/Mg, which is significantly higher than $l,900/Mg.
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RESPONSE: The EPA agrees that the cost effectiveness of $l,900/Mg
(December 1978 dollars) would be about $2,600/Mg in first quarter 1984
dollars. However, EPA maintains that this would not change the analysis or
the requirements of the standards. When the analysis for the distillation
NSPS was begun, it was decided that 1978 would be the appropriate base year
for costs because more recent data were not available. If the implicit price
deflator for the gross national product is applied, the cost-effectiveness
cutoff inflates 40 percent over the 5-year period. However, regardless of
whether it is expressed in 1978 or 1984 dollars, the cost-effectiveness
cutoff has the same impact. If the cost-effectiveness cutoff is increased by
40 percent by an inflation factor to $2,600/Mg, the reference cost
effectiveness will also increase by 40 percent, since both values are
calculated using the same cost assumptions. Furthermore,, in considering an
inflated TRE cutoff, it should also be realized that the value of the
benefits associated with the standards are also inflated accordingly. Thus,
the ratio will remain the same, and the TRE index cutoff value will still be
1.0. Inflation does not affect the validity of the TRE index. Thus, there
is no need to revise the cost-effectiveness cutoff.
2.5.6 COMMENT: Two commenters (D-7 and D-25) noted that EPA did not
adequately address the capital costs of precautionary safety measures
necessary when introducing a vent stream into a boiler or process heater as a
fuel. According to one commenter, the NFPA may require safety closure valves
and vent systems, as well as appropriate containment when vent streams are
combusted as fuel. These safety measures would increase the capital cost of
using a boiler or process heater to combust vent streams. The other
commenter indicated that to prevent explosions, liquid hydrocarbons must be
kept out of the vent streams going to these units. The extra cost for surge
tanks, knock-out drums and extra control instruments would cancel out most of
the economic benefits associated with using the vent stream as a fuel.
RESPONSE: Boilers and process heaters can sometimes be attractive
candidates for the control of vent streams from distillation facilities
because they can provide at least 98 percent reduction efficiency of VOC and
nearly the complete recovery of the heat content of a vent stream. There are
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three plants in the available data that use boilers as a control device on
vent streams with heating values ranging from 449 to 1,258 Btu/scf. Because
these streams have high energy recovery potential, there is an economic
incentive to use boilers in order to recover heat energy.
The EPA did not include boilers or process heaters as control devices in
the regulatory analysis and as such, specific boiler costs such as the ones
outlined by the commenter do not play a role in analyzing cost impacts
associated with the standards. Since flares and incinerators are more widely
applicable for VOC control than are boilers or process heaters, EPA selected
flares and incinerators as the control techniques upon which the standards
are based and estimated the impacts associated with their application.
Because the impacts associated with the use of flares and thermal
incinerators were found to be reasonable for all distillation operations that
would be required to reduce VOC emissions by 98 weight-percent or to 20 ppmv
according to the standards, there was no need to evaluate the impacts
associated with other less expensive control techniques.
2.5.7 COMMENT: One commenter (D-25) stated EPA did not include the
cost of more expensive compressor and pipeline systems in its cost estimates
for combustion control. It was noted that for each of the combustion control
options considered, EPA assumes in its cost equations that the same type of
pipeline system is used to recover vent gases and deliver them to the com-
bustion device. This approach may be both impractical and unsafe for some
vent streams containing potentially explosive compounds, or compounds which
present erosion problems during liquefaction. Such compounds (e.g.,
chlorotrifluoroethylene) are not necessarily included in the list of products
to be regulated, but may be included in the emission streams containing
compounds that are listed.
RESPONSE: The commenter noted that the vent stream mover system
included in the costing procedures at proposal would present erosion problems
due to liquefaction. The EPA believes that the relatively low pressure drops
expected for flare and incinerator mover systems [i.e., 3.0 kPa (12 in. w.c.)
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for an incinerator and 5.2 kPa (21 in. w.c.) for a flare] would not cause
significant liquefaction problems with pipeline components. Thus, erosion
problems would be minimal. However, EPA is aware that minor problems with
erosion, corrosion, and the like over an extended period of time may cause
maintenance expenses. To account for these costs, the costing procedures for
flares and incinerators include maintenance labor at 3 percent and maintenance
parts at 3 percent of the total installed capital cost of the combustion
system. In addition, since the combustion systems will eventually have to be
replaced, annualized capital costs are calculated based on reasonable
expected system lifetimes. The costing procedures use a a 10-year life for
incinerators and a 15-year life for flares. It should be noted that
incinerators are used for combusting more corrosive (i.e., halogenated)
streams.
The design of flare systems include various safeguards against
explosion. These include knockout drums, water seals, fluidic seals, and
purge gas systems. Major equipment purchase costs for incinerators include
equipment for fire protection. Furthermore, the capital costing for com-
bustion systems includes a contingency factor to address site-specific needs
for special combustion system design. The unique requirements of individual
distillation units are expected to be addressed by the contingency factor
allowance.
2.5.8 COMMENT: One commenter (D-32) stated that the BID description of
price increases that might follow from the NSPS is deceptive because EPA
assumed that control costs will automatically pass through to consumers. The
competitive environment of the chemical industry, the commenter continued,
makes pass-through opportunities rare. As evidence, the commenter cited the
experience of producers who are unable to pass Superfund costs through to
consumers. Therefore, the commenter concluded, EPA should emphasize the
separation of costs and prices, and should modify the analysis of rolled-
through costs, particularly the statement on p. 8-39 of the BID that reads
"producers of intermediates will roll through the entire cost of control to
other SOCMI producers."
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RESPONSE: Standards may affect prices, profits, production levels,
capacity utilization, construction of new facilities, employment, foreign
trade, and a myriad of other economic variables. Confronted with so many
variables, and with standards that will affect the production of 211
chemicals, EPA focuses its analysis on projecting worst-case, or reasonably
worst-case price effects. This focus simplifies the economic analysis and
yet enables EPA to be sure a standard will not have any significant,
unexpected, harmful economic effects. However, a worst-case analysis does
not lead to predictions about most probable effects. In the case in point,
an effort was made to find the upper limit of price increases that could
result from this distillation NSPS. Finding the upper limit is quite small,
less than 5 percent, EPA went on to analyze other variables. No effort was
made to predict most likely short- or long-term price effects.
The EPA did not intend to convey the impression that all control costs
are rolled along a chemical process chain and then passed along to consumers.
Some are, but, especially in the short run, some are shared by stockholders,
taxpayers, and suppliers. The commenter's finding that some firms cannot
pass through Superfund costs is not applicable to an NSPS. Superfund taxes
are assessed to existing operations. The NSPS costs apply only to future,
new facilities, and to some existing facilities after they are modified or
reconstructed. It is not in the economic interest of a firm to build, to
modify, or to reconstruct facilities until and unless a reasonable return can
be expected on the investment, including the investment in pollution control.
Thus, in the very long run, when all facilities come under the standard, all
control costs probably will be passed through. However, it should be
remembered that the modeling assumptions EPA used to compute price increases
are very conservative. This means that the actual long-term price increases
should be less than EPA's very conservative estimates.
The quotation given by the commenter is incomplete. The full sentence
from p. 8-39 of the BID is "The analysis here assumes that all facilities --
existing as well as the new -- are subject to the standards, and that
producers of intermediates will roll through the entire costs of control to
other SOCMI producers." These are two conservative assumptions in the sense
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that they lead to an overestimation of price increases. Clearly, the
distillation NSPS does not apply to the majority of existing facilities. It
is also clear that all producers will not roll through all costs in the first
5 years of the standard. (Five years is the period of analysis used in most
studies of this nature.) To replace these and other conservative assumptions
with most-probable assumptions would require a substantial commitment of
EPA's time and resources. Furthermore, prediction of expected, most-probable
price changes would not influence the final form of the standard.
For these reasons, EPA does not think it is necessary to revise the
price increase analysis.
2.5.9 COMMENT: One commenter (D-15) stated that EPA should consider
the cost of fuel oil in estimating the cost of controlling vent streams with
extremely low heating values. It was indicated that some distillation
facilities may choose to use fuel oil instead of natural gas to supplement
the low heating value of vent streams if flaring were used as a control
device. Fuel oil may be used in some cases because it is relied upon more
than natural gas at some facilities where both fuels are available. The
commenter believes that using fuel oil instead of natural gas could increase
the cost of controlling VOC emissions.
RESPONSE; The Agency chose to include the most typical equipment and
operating procedures in estimating the cost of controlling VOC emissions.
The use of fuel oil as a supplemental fuel for flaring was not considered
because the Agency believes that the vast majority of producers have access
to natural gas and the vast majority of producers would use natural gas as a
supplementary fuel for flaring. The costs were developed to be represen-
tative of the costs anticipated to occur at the majority of facilities in the
industry.
The commenter was contacted for clarification of the statement regarding
the need to consider the cost of fuel oil. The commenter indicated that
natural gas is not always available and fuel oil is required for flaring for
about 10 percent of the operating schedule (Docket Item No. IV-D-38).
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However, because there is a diverse group of chemical producers it would be
infeasible to evaluate every process and producer on an individual basis.
Therefore, the Agency must use a method of estimating control costs that are
typical of the vast majority of SOCMI producers. The EPA believes that it is
reasonable to incorporate into the flare costing algorithm the cost of
natural gas as the only supplemental fuel for flaring.
2.6 COST EFFECTIVENESS
2.6.1 COMMENT: Five commenters (D-ll, D-20, D-23, D-24, and D-27) are
in favor of using the TRE approach in the proposed standards. Reasons given
include: (a) it gives a standardized cost estimate that can serve as a
rational basis for developing standards; (b) it encourages product recovery
and considers economic viability; and (c) it shows a consideration of the
large incremental costs associated with diminishing air quality benefits in
the standards development process. One commenter (D-2) is in disagreement
with the use of cost effectiveness as the sole determinant for which
facilities have to use add-on control devices.
Two commenters (D-21 and D-27) indicated that the $l,900/Mg
cost-effectiveness cutoff is unreasonable. One commenter (D-21) suggested
that cost-effectiveness ratios are not a valid basis for not requiring the
use of controls that EPA's analysis shows are affordable. This commenter
then suggested that, even if cost effectiveness were relevant, EPA chose the
wrong cutoff because: (1) it is below the cost-effectiveness level associated
with a substantial number of past standards; and (2) even if the cutoff were
above those past figures, the higher costs are justifiable as means to
protect the public health from the potentially hazardous pollutants in these
streams.
One commenter (D-27) considers the TRE cutoff as too high and stated
that the $l,900/Mg cutoff is not adequately justified by the Agency. The
commenter suggested that a $500/Mg cutoff is more than adequate to secure all
meaningful reductions. A plot of the data from Table 1 at 48 FR 57545 shows
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a point of sharply diminished VOC emission reduction in the $200 to $600/Mg
range with essentially no additional reduction in emissions achieved at any
cost above that range.
Commenter 0-27 stated because EPA has underestimated the total installed
capital cost of control devices by a factor of 3 and the annual operating
costs by a factor of 2, the cutoff of $l,900/Mg (1978 dollars) for VOC
abatement is understated. The actual cutoff figure, as calculated by the
commenter in first quarter 1984 dollars, it about $5,400/Mg. The commenter
indicated that this exceeds the $l,000/Mg limit used in most other NSPS.
Two commenters (D-27 and D-37) asserted that the $l,900/Mg cutoff cannot
be justified based on the presence of toxic constituents in the vent streams
from distillation facilities. One of the commenters pointed out that control
of toxic pollutants is the objective of standards developed under Section 112
of the CM (NESHAP) and not standards such as these which are being proposed
pursuant to Section 111 of the Act (NSPS). The commenter also stated the
preamble does not adequately demonstrate that the presence of toxic pollutants
in the emissions from distillation facilities are sufficiently different from .
the emissions from other VOC sources to justify a special consideration of
their hazards. Concerning VOC emissions generally, the commenter stated that
EPA has decided (48 FR 628) an ambient air standard to protect public health,
etc., from hydrocarbons is unnecessary.
RESPONSE: The EPA believes that its decision to consider cost
effectiveness when determining the cutoff for applying the percent reduction
standards reflects a reasonable interpretation of Section 111 of the CAA. In
analyzing the question of whether the consideration of cost effectiveness is
appropriate, EPA looked to see whether Congress had "directly spoken to the
precise question." Chevron. U.S.A.. Inc. v NRDC. 467 U.S. 837, 104 S.Ct.
2778, 2782 (1984). Section 111 requires EPA to promulgate NSPS limiting
emissions to the level that reflects the best system of emission reduction
"which (taking into consideration the cost of achieving such emission
reduction, any nonair quality health and environmental impact and energy
requirements) the Administrator determines has been adequately demonstrated."
Section lll(a)(l). Nothing in either Section 111 or elsewhere in the Act
defines "the cost of achieving such emission reduction." The plain meaning of
the phrase, however, is quite broad. This indicates that; Congress implicitly
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delegated to EPA the authority to interpret the phrase to encompass a range of
impacts, including costs of control in relation to the emission reduction
achieved. Further, Congress did not specify any particular manner in which
EPA was to take these costs "into consideration." Thus, absent a clear
Congressional direction to the contrary discernible from the Act's history,
Chevron, 104 S.Ct. at 2783, Section 111 gives EPA authority to reject NSPS
control options on the ground that their costs are unreasonably high in light
of the emission reductions they achieve. I/
The EPA has reviewed the legislative history of Section 111 and concluded
that no contrary intent is discernible. Most important, the history contains
no express repudiation of the use of cost effectiveness as one mechanism in
considering costs when setting an NSPS.
For these reasons, EPA believes that Congress implicitly delegated the
Agency the authority to decide how best to "take into consideration... cost-
in setting NSPS and, if the Agency concluded it was appropriate, to consider
cost effectiveness.
Further, in Portland Cement Association v. Train. 513 F.2d 506, 508 (D.C.
C1r- 1975), cert, denied. 416 U. S. 1025 (1975) ("Portland II"), the Court
stated that EPA may reject control options that result in a "gross
disproportion between achievable reduction in emissions and cost of the
control technique." Since the purpose of cost-effectiveness analysis is to
highlight such disproportion, this passage supports EPA's approach.
In selecting cutoffs related to applicability of NSPS, EPA looks at a
variety of factors including: (1) the technical feasibility of additional
control; (2) the economic feasibility associated with different control
alternatives; (3) the magnitude of emission reductions associated with a
control alternative (e.g., a slightly higher cutoff could be selected if it
led to a substantial increase in the emission reduction achieved by the NSPS);
I/ For instance, Congress provided a more specific restriction on the
consideration of costs on Part C of the Act. Section 169(3) defines "best
available control technology" as "an emissions limitation based upon the
maximum degree of reduction... taking into account energy, environmental, and
economic impacts and other costs, determines is achievable for such
facility..." (Emphasis added). Here it is more likely that Congress intended
to ensure the maximum control considering case-by-case economic impacts but
regardless of cost effectiveness.
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(4) the cost effectiveness (C/E) of the control alternative in terms of annual
cost per megagram ($/Mg) of emissions reduced; (5) the quality of the cost
estimates (e.g., worst case versus realistic estimates); (6) potential
reductions in other air pollutants not specifically regulated by the NSPS
resulting from a control alternative; and (7) the location of the sources
(e.g., urban versus rural). Because these factors vary from industry to
industry and, in some cases, within the same industry, decisions on the
appropriate level of control are made on a category by category basis.
In evaluating the above factors, EPA found that the following
considerations were key to the selection of the appropriate cutoff for SOCMI
distillation operations: (1) the cost effectiveness of NSPS for VOC emissions
previously promulgated by the EPA; (2) the fact that distillation vent streams
contain compounds that are considered potentially toxic by EPA and that many
of the facilities are located in urban areas; and (3) the likelihood that
these maximum costs will not be incurred by industry.
A survey of the VOC standards for other source categories shows that the
cost effectiveness of those control requirements has sometimes ranged as high
as $2,000/Mg. (See Docket Item No. IV-B-17.) The Agency's experience in
implementing these standards reveals that NSPS requiring this level of control
have proved a useful tool in bringing about the installation of much emissions
control technology, significant reductions in emissions and corresponding
improvements in air quality, yet have not imposed costs that appear "grossly
disproportionate" to the emission reduction achieved. Portland II. 513 F.2d
at 508. Such an approach simply makes this NSPS consistent (as to dollars
spent per metric ton of VOC removed) with the existing body of NSPS
regulations, all of which have either been promulgated without legal challenge
or have been judicially upheld.
EPA also considered evidence that distillation streams include compounds
that may be toxic. 2/ Although that evidence has not yet resulted 1n a
2/ The Agency has adequately documented that this is the case. (See Wehrum,
W. et a!., "Air Toxics Emission Patterns and Trends", Docket Item No. IV-A3,
and Registry of Toxic Effects of Chemical Substances, Docket Item
No. IV-J-9). Moreover, it is apparent that combustion of those streams will
reduce those compounds proportionately. (See, e.g., "Thermal Incinerator
Performance for NSPS", Docket Item No. II-B-3.) The Agency received no
comment questioning this documentation.
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determination that those compounds should be listed as hazardous under
Section 112, EPA considered this potential toxicity along with other relevant
factors when choosing the cutoff. As stated in EPA's Air Toxic Strategy
published in July 1985, the Agency will consider the likely toxic pollutant
control benefits in the course of carrying out its responsibilities under
Section 111. This strategy reduces emissions of potentially toxic compounds
from new sources and from industries as their facilities are reconstructed or
modified. This approach achieves significant reductions in these compounds of
concern while the Agency evaluates them for regulation under Section 112. The
Agency disagrees with the argument that EPA has no authority to do this. The
EPA is not attempting here to regulate streams based on a decision that they
contain hazardous air pollutants within the meaning of Section 112. Rather,
the Agency is simply considering all available evidence within the framework
of Section 111. Section 111 does not attempt to restrict EPA's discretion to
consider all relevant factors in making that decision, and certainly the
potential toxicity of a stream is relevant to the control requirement
selected. Many SOCMI facilities are located in urban areas and, as a result,
many people will be exposed to any hazardous air pollutants emitted from these
facilities.
A third consideration in setting the cutoff at $l,900/Mg is the
likelihood that no facility will actually have to incur the costs implied by
that cutoff. The reasons are: (a) less expensive control systems may be
used, thus reducing the costs and cost effectiveness incurred by individual
facilities; (b) the cost estimates for thermal incinerators and natural gas
prices are overstated; and (c) the inherent flexibility within the regulation
encourages the use of product recovery modifications that will significantly
reduce the cost incurred by individual facilities that may have otherwise had
to add a combustion device. The regulatory analysis assumes that each
distillation operation process vent would have its own combustion device and
would need separate ducting and support structures. It is expected, however,
that some operations will share control systems with other process vents. The
analysis also assumes that incinerators or flares will be used to reduce VOC
emissions by 98 weight-percent. However, many facilities will opt to use
boilers, process heaters or catalytic oxidizers. When these devices are used,
the cost of control will be significantly reduced over the cost of thermal
incineration. Data on current capital costs of thermal incinerators indicate
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Incinerators Indicate that units are now available at substantially reduced
costs compared to the costs used In developing these standards. Lower capital
costs would reduce the annualized costs estimates, also, but not as
significantly. This 1s an Important consideration in selecting the
appropriate cost-effectiveness cutoff. Another consideration is the fact that
natural gas prices used to calculate the cost effectiveness for each stream
are overstated by about 40 percent, even though they were updated after
proposal (see following section on "Costing Revisions"). These conservative
assumptions have resulted in higher cost and cost-effectiveness estimates than
will actually occur. Finally, the standard encourages pollution prevention by
not requiring 98 weight-percent reduction if a TRE index greater than 1.0 is
maintained. The EPA believes that many facilities having a TRE index just
below the 1.0 cutoff (equivalent to $l,900/Mg) will upgrade product recovery
to reduce VOC and raise their TRE index above 1.0. This will significantly
reduce the cost of control incurred by the industry while reducing emissions
and will also minimize the national energy impacts. A preliminary examination
of the national statistical profile shows that because many facilities have
the potential to reduce VOC emissions sufficiently to raise their TRE values
above 1.0, the highest cost effectiveness that a facility will actually incur
as a result of installing a combustion device is estimated to be approximately
$l,400/Mg.
The EPA believes that this process reflects a reasoned interpretation of
the phrase "taking into consideration the cost of achieving such emission
reduction," especially given the lack of clear Congressional guidance. The
commenters' arguments that EPA should have selected either a higher cutoff to
provide for a greater degree of protection of the public health, or a lower
cutoff because most VOC standards have lower costs in relation to the
resulting emission reduction, fail to provide a more reasoned methodology for
selecting the appropriate level. Instead, they merely reflect each of the
competing goals reflected in Section Ill's history, as described above.
Consideration of all of the above factors confirmed EPA's belief that a
TRE value of 1.0 (i.e., $l,900/Mg) represents an appropriate cutoff for
determining which facilities must reduce VOC emissions by 98 weight-percent or
to 20 ppmv. The cutoff is specific to the SOCMI distillation operations
source category and would not necessarily be appropriate for other source
categories; therefore, it should not be viewed as a benchmark for other
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standards. It is not surprising, however, that the cost-effectiveness cutoff
for distillation would be the same as for the air oxidation NSPS for a number
of reasons. First, the same pollutant, (i.e., VOC) is being regulated.
Second, the same general class of VOC emitters (i.e., SOCMI) and similar types
of process equipment (e.g., recovery equipment) are affected. Third, the same
types of control techniques are applicable.
A commenter was concerned that because EPA has underestimated the total
installed capital cost and the annual operating costs of control devices, the
TRE cutoff is underestimated. As a result of this and other comments, the
Agency performed a complete review of all costing procedures. Based on that
analysis, several changes to the costing methodology were made and presented
in a supplemental Federal Register notice (50 FR 20446) on May 16, 1985.
Changes made to costing procedures were based on information presented in two
memoranda entitled "Revisions to the Incinerator Costing Algorithm" (Docket
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Entry IV-B-7), and "Revisions to the Flare Costing Algorithm"" (Docket Entry
IV-B-8). The commenter is referred to Section 2.5.2 for a discussion of the
costing methodology.
2.6.2 COMMENT: Two commenters (D-21 and D-27) indicated that EPA had
used the same $l,900/Mg cutoff in the recently proposed air oxidation NSPS.
They suggested this figure results from an EPA policy decision not from a
specific evaluation of the costs and impacts associated with the distillation
NSPS.
RESPONSE: The Agency has based the $l,900/Mg cutoff on a specific
evaluation of the costs and impacts associated with the distillation NSPS.
It is not surprising however that the cost-effectiveness cutoff for
distillation would be the same as for the air oxidation NSPS for a number of
reasons. First, the same pollutant (i.e., VOC) is being regulated. Second,
the same general class of VOC emitters (i.e, SOCMI) and similar types of
process equipment (e.g., product recovery) are affected. Third, the same
types of control techniques are applicable.
2.6.3 COMMENT: One commenter (D-24) requested information on how the
TRE equation was derived. The commenter stated that the derivation of the
TRE equation coefficients is not explained in an understandable manner.
The commenter also requested clarification on when the TRE index value
would need to be recalculated. The commenter presented two suggestions
regarding when the TRE index value should be recalculated. Section 60.664(d)
of the regulation states: "Each owner or operator of an affected facility
shall recalculate the TRE index value for that affected facility whenever
changes are made in production capacity, feedstock type, or catalyst type, or
whenever there is replacement, removal, or addition of product recovery
equipment." One of the suggestions made by the commenter is that recalcula-
tions of TRE index values should be done as part of the permit process only
in situations where increases in emissions or changes in chemical constituents
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are likely to occur. The other recommendation presented by the commenter is
that an exemption from monitoring or recordkeeping requirements should be
allowed, perhaps if the TRE exceeds 10.0.
RESPONSE: A description of the development of the TRE index equations
is presented in Appendix B of this document. An explanation of the
derivation of the TRE equation coefficients is presented in Docket Item No.
IV-B-15.
Since proposal of the standards, the Agency has revised the TRE equation
and derived new coefficients for the equation. These revisions resulted from
changes in the costing procedures. The results of the Agency's reanalysis of
the TRE equations, coefficients, and costing procedures are discussed in the
supplemental notice reopening the public comment period (50 FR 20446).
The EPA requires that the TRE be recalculated for the changes listed in
Section 60.664(d) because the changes have the potential to lower the TRE
index below 1.0 indicating the cost of control for that facility is below
$l,900/Mg of VOC removed. In some cases it may be possible to make process
changes that would require the recalculation of a TRE index but would not
come.under the permit review process. Therefore, it would be improper to use
the permit review process as a trigger for initiating this determination as
suggested by the commenter. In some cases it may be possible to make changes
in the process which could result in a TRE index less than 1.0, but which
would not come under the permit review process. Therefore, EPA believes that
it is necessary to require a TRE calculation as a result of the changes
listed in the regulation in order to ensure that the standards are being met
by all facilities.
The commenter suggested that EPA exempt affected facilities showing a
TRE index value greater than 10.0 from monitoring or recordkeeping require-
ments. Several changes were made in the regulation to provide for inclusion
of a maximum TRE index value above which monitoring and recordkeeping
requirements would not be imposed on a facility attempting to comply with the
standards. It is the judgment of the Agency that facilities with TRE index
values above 8.0 would most likely not be able to make process changes that
would cause the TRE index value to fall below the cutoff. Thus, the Agency
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believes that the monitoring and recordkeeping burden should not be imposed
on such facilities. However, if a process change occurs, the facility would
have to recalculate the TRE index value as required in Section 60.665(f)(l)
to determine whether the value remains above the TRE maximum. Sections
60.664 and 60.665 of the regulation have been amended to incorporate the
requirements associated with the maximum TRE index value., The basis for the
determination of the 8.0 TRE index value is discussed in Docket Item No.
IV-B-14.
2.6.4 COMMENT: One commenter (D-27) requested clarification on
determining removal efficiency for a recovery device when vents that are
affected and vents that are unaffected by the proposed standards are routed
through the same recovery device. The commenter presented an example where
the vent streams from an affected distillation column and a distillation
column not covered by the standards are combined and fed to a single con-
denser. The commenter stated that for this example two different TRE values
could be calculated depending on the assumption used in estimating the
removal efficiency of the condenser. One TRE value is based on the condenser
removal efficiency for all of the VOC removed from both vent streams (Case
1). The other value is based only on the removal efficiency associated with
VOC present in the vent stream affected by the proposed standards (Case 2).
For Case 1, the TRE value calculated with the condenser removal efficiency
based on the combined stream was found to be below the $l,900/Mg cutoff. For
Case 2, however, the TRE value calculated with the condenser removal
efficiency based on only the affected vent was found to be above $l,900/Mg.
The commenter is unsure of the correct procedure for estimating removal
efficiency but suggested that the efficiency be based on only the affected
vent.
The commenter indicated the designation of affected facility that
includes all distillation units vented to a common recovery device as one
affected facility would eliminate the confusion over which removal efficiency
to use for the TRE calculation.
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RESPONSE: With the change in designation of affected facility (see
comment 2.2.1) there will be no need to use the removal efficiency for a
product recovery device in calculating the TRE when an affected distillation
vent stream is combined with existing distillation vent streams. As a result
of the change in designation, all of the distillation units vented into a
common product recovery device will be the affected facility. To calculate a
TRE index value the vent stream characteristics of the total flow exiting the
final recovery device will be used and no apportioning of removal efficiency
to the affected vent stream will be necessary.
2.6.5 COMMENT; One commenter (D-30) believes that the TRE index
calculation contains no provision for the high efficiency of product recovery
devices used in large distillation facilities. It was pointed out that
generally, larger facilities operate more efficiently than smaller facilities
in the production of synthetic organic chemicals and subsequent recovery of
organics from process vent streams. The commenter stated that even though a
large facility is more efficient than a small one, the TRE index calculation
would allow a small facility to be exempt from coverage by the standards,
while a larger facility would not be exempt only because of its larger vent
stream flow rate and higher VOC emission rate. Therefore, the commenter
suggested that a factor be included into the TRE index calculation that
relates total facility production rate to the final vent VOC emission rate.
RESPONSE: The TRE equation was developed to determine if the cost
effectiveness of reducing VOC emissions is reasonable for a particular
facility regardless of size. No facility will have to spend more than
$l,900/Mg to meet the emission reduction requirements. The TRE equation
estimates the total cost of constructing, operating and maintaining com-
bustion equipment sized according to the flow rate and heating value of the
vent stream from the facility. In general, vent streams from facilities
using highly efficient product recovery would have relatively low VOC
concentrations. These types of streams are expensive to control because
substantial amounts of supplemental fuel must be added prior to combustion.
This fact is taken into account in the TRE calculation. Conversely, vent
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streams emanating from less efficient product recovery devices usually have
higher VOC concentrations. In these cases, combustion control is more cost
effective and likely could be accomplished for less than $l,900/Mg. There-
fore, it is not the size of the facility or the vent stream that
predominantly determines which streams are required to be combusted but
rather the vent stream VOC concentration (and associated heating value).
2.7 FORMAT OF THE STANDARDS
2.7.1 COMMENT: Eight commenters (D-5, D-ll, D-12, D-13, D-17, D-20,
D-22, and D-27) disagreed with the regulation of VOC emissions by controlling
TOC emissions less methane and ethane. These commenters stated that the
standards should not list methane and ethane as the only chemicals to be
subtracted from TOC emissions'. Instead, they suggested that the standards
should allow for all compounds listed in 48 FR 57542 to be subtracted, if
present in the vent stream, from TOC emissions. They stated that the com-
pounds listed in 48 FR 57542 have been determined by the Administrator to be
negligibly photochemically reactive.
One commenter (D-5) stated that it is not proper to subject distillation
facilities that emit negligibly photochemically reactive compounds to
standards specifically designed to limit the emissions of VOC which are
photochemically reactive compounds and which contribute to ozone formation.
One commenter (D-27) stated that TOC's (minus methane and ethane) are
not the best demonstrated surrogate to regulate VOC. The commenter indicated
that Reference Method 18 gives specific compound identification and measure-
ment capabilities. Thus, the compounds listed in 48 FR 157542 can be
accurately measured and subtracted from TOC emissions. Therefore, the
commenter requested that EPA regulate VOC emissions directly and allow the
subtraction of negligibly photochemically reactive compounds from TOC
emissions. In order for VOC emissions to be directly regulated the
commenters suggested that the phrase: "less those compounds that are not VOC
as determined by the Administrator" be used whenever the phrase: "less
methane and ethane" is used in the standards.
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RESPONSE: The NSPS for SOCMI distillation operations are intended to
cover distillation facilities that emit VOC (i.e., compounds which
participate in atmospheric photochemical reactions to produce ozone). Since
compounds with negligible photochemical reactivity do not appreciably con-
tribute to the production of ozone, the Agency believes that it is
appropriate to exclude these compounds in determining a TRE index. The owner
or operator of an affected facility should subtract the negligibly photo-
chemically reactive organic compounds from the TOC, when quantifying the
hourly emissions rate for input into the TRE equation. For example, if the
vent stream of a facility contains 90 percent negligibly reactive organic
compounds and 10 percent reactive organic compounds only 10 percent of the
organic compounds emitted from that facility would be considered for
calculating a TRE index. Although subtraction of negligibly reactive organic
compounds is permitted, it is expected that no significant change in national
impacts will occur since less than 5 percent of the distillation vent streams
represented in the available emissions data contain these compounds.
However, subtraction of negligibly reactive compounds applies to hourly
emission rate only and when determining the vent stream flow rate and heating
value of a stream, these compounds must not be ignored. The TRE value
incorporates the cost of supplemental fuel and if any of these compounds have
a heating value associated with them they must be included to avoid over-
estimating supplemental fuel costs. The TRE value also incorporates the vent
stream flow rate because the size of the total flow rate entering the
combustion device influences the cost of control. The larger the total flow
rate the greater it will cost to construct, operate and maintain a combustion
device. Therefore, to properly evaluate the cost effectiveness for
controlling a particular vent stream, the total flow rate and total net
heating value are needed for the TRE calculation.
To allow for subtraction of compounds with negligible photochemical
reactivity in calculating a TRE index, the definition of TOC in Section 60.661
has been modified. The new definition indicates that "Total Organic Compound"
means those compounds measured according to the procedures in Section 60.664.
For the purpose of determining the molar composition as required in
Section 60.664(c)(l)(i) and the hourly TOC emissions rate as required in
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Section 60.664(c)(5), Section 60.664(c)(7), and Section 60.665(g)(4), the
definition of TOC excludes or allows the subtraction of those compounds which
the Administrator has determined do not participate in photochemical reactions
to produce ozone. The compounds to be subtracted are identified in EPA
statements on ozone abatement policy for SIP revisions (42 FR 35314;
44 FR 32042; 45 FR 32424; 45 FR 48941)." These compounds are methane;
ethane; 1,1,1-trichloroethane; methylene chloride; trichlorofluoromethane;
dichlorodifluoromethane; chlorodifluoromethane; trifluorornethane; trichloro-
trifluoroethane; dichlorotetrafluoroethane; and chloropentafluoroethane. An
appendix to this document contains the complete copies of these notices.
Combustion devices destroy TOC by at least as great an efficiency as
when only VOC are in the stream. Furthermore, it is less costly and less
complex not to subtract the negligibly reactive compounds during performance
testing. Therefore, these compounds should be included in determining the
removal efficiency of thermal incinerators (performance te>sts).
2.7.2 COMMENT: Two commenters (D-8 and D-29) stated that EPA has given
no method in the proposed standards for determining that the organic
compounds listed in the preamble are not photochemically reactive organics.
The commenters suggested that the owner or operator of an affected facility
should be allowed to demonstrate that the particular organic compounds(s)
involved in a given operation are not photochemically reactive organics. One
commenter (D-8) further suggested that this demonstration could be submitted
with the notification of initial startup required by Section 60.7(a)(3).
RESPONSE: There are no EPA-approved procedures on determining the
photochemical reactivity of organic compounds. The EPA established the
current list of negligibly photochemically reactive compounds through a broad
research effort. During this effort, EPA has not developed a standard
procedure by which anyone outside the Agency could demonstrate an organic
compound to be of negligible photochemical reactivity.
As indicated in the response to comment 2.7.1, the Agency has agreed to
allow for the subtraction of negligibly photochemically reactive compounds
from the hourly emissions rate of TOC in determining a TRE index. The only
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negligibly reactive compounds that will be allowed to be subtracted are
identified in EPA statements on ozone abatement policy for SIP revisions
(42 FR 35314, 44 FR 32042; 45 FR 32424; 45 FR 48941) along with the rationale
for determining that they are negligibly reactive. These citations are also
given in the definition of "TOC" in the regulation, and copies of the complete
notices are given in Appendix A to this document.
2.7.3 COMMENT: In Section 60.662(a) the regulation specifies that the
98 weight-percent reduction requirement and the 20 ppmv concentration limit
must be met on a dry basis. One commenter (D-12) suggested that the low flow
exemption of 0.008 nT/min should also be on a dry basis.
a
RESEQNS£: The EPA will continue to require the flow rate measurement
for the low flow exemption to be based upon all of the vent stream
components, including water vapor. Because the flow rate used in the TRE
equation includes the concentration of water vapor and because the low flow
exemption was developed from flow rate data measured on a "wet basis," it is
appropriate for the low flow exemption to be consistent with the TRE^equation
and data.
2.8 MODIFICATION/RECONSTRUCTION
2.8.1 COMMENT.: Four commenters (D-8, D-ll, D-15, and D-22) recommended
a wording change in Section 60.660(b) to indicate that affected facilities
beginning modification or reconstruction after the date of proposal would be
covered by the standards. This addition was recommended because of a dis-
crepancy between the preamble and the regulation. The preamble (48 FR 57549)
states: "The proposed standards would apply to all affected facilities,
which commenced construction, reconstruction. Or modification after the'date
of proposal of the NSPS." However, Section 60.660(b) of the regulation now
refers only to affected facilities commencing construction after the proposal
date. Another commenter (D-12) did not suggest any wording change but
requested clarification on the initial startup date for cases when existing
facilities become subject to the NSPS.
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RESPONSE; As stated 1n the General Provisions*(40 CFR 60.1), standards
of performance for new stationary sources apply to new, modified, and
reconstructed facilities. This statement was reiterated in the preamble to
the proposed standards. To avoid misinterpretation, EPA has clarified the
wording in Section 60.660(b) of the regulation.
2.8.2 COMMENT: One commenter (0-19) Inquired whether a change in the
production of one chemical listed in the proposed standards to another listed
chemical would result in a modification if emissions do not increase.
The same commenter requested that Section 60.660 of the regulation
include a statement exempting process improvements from the standards. The
requested statement is as follows: the addition or replacement of equipment
for the purpose of process improvement that is accomplished without a capital
expenditure shall not by itself be considered a modification under this
subpart.
RESPONSE: Section 60.14 of the General Provisions of 40 CFR Part 60
defines "modification" for purposes of NSPS generally. If a change in the
production of one listed chemical to another listed chemical were done with a
resulting increase in emissions then that change could be considered a
modification. However, if the distillation operation were designed prior to
the applicability date of the standards to accommodate the production of this
different listed product then the change would not be a modification
regardless of changes in emissions.
The commenter requested that process improvements that are accomplished
without a capital expenditure not be considered as modifications. An exemp-
tion similar to what the commenter requested was included in the standards of
performance for equipment leaks in the SOCMI (48 PR 48328). However, as
discussed in the preamble when those standards were proposed (46 FR 1139), the
reason for the exemption was that routine changes and additions of fugitive
emission sources in an existing SOCMI process unit could result in
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the unit's being modified and, therefore, subject to the standards of
performance. In this situation, the addition of a small fugitive emission
source to the process unit would result in all of the fugitive emission
sources within the entire process unit being covered by the standards.
However, under the standards of performance for SOCMI distillation opera-
tions, if a change or addition is made for process improvement reasons to an
existing distillation facility that results in an increase in VOC emissions,
only that facility is considered modified and subject to the standards. The
impacts associated with covering this type of situation have been analyzed
and determined by the Administrator to be reasonable. Therefore, process
improvements will not be exempted from the standards.
2.8.3 COMMENT: One commenter (D-24) stated that it may not be
technically or economically feasible to meet the standards for a f«w
modifications of existing facilities. In these circumstances, adequate space
or land may not be available for construction of the combustion or recovery
equipment which may be required to meet the NSPS.
RESPONSE: Before any modifications are begun, the owner or operator
should plan for the possibility of complying with these standards and he
should consider such things as space limitations when planning construction
of new facilities or the modification or reconstruction of existing
facilities. The EPA believes these requirements are reasonable because it is
possible that the owner or operator of an affected facility can comply with
the standards by showing a cost of VOC control to be above the established
cutoff.
2.8.4 CQMMENI: One commenter (D-12) indicated that Chapter 5 of the
BID does not address the subject of modification and reconstruction with
specific reference to distillation facilities.
The same commenter requested an explanation of what would constitute a
modification or reconstruction for an existing distillation facility and how
the affected facility would be expected to initiate its compliance obliga-
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tions. The commenter also requested that EPA distinguish between the General
Provisions of the proposed standards that apply to new facilities and those
that apply to modified or reconstructed facilities.
RESPONSE: The EPA acknowledges that Chapter 5 of the BID does not
address the subject of modification and reconstruction with specific
reference to distillation facilities. An errata sheet has been prepared and
sent to all individuals who received the incorrect copy of Chapter 5 of the
BID.
As stated in the preamble, the proposed standards would apply to all
affected facilities which commenced construction, reconstruction, or
modification after the date of proposal of the NSPS. According to the
definition of modification given in 40 CFR 60.14, a modified distillation
facility would occur when any physical change in, or changf in the method of
operation of, an existing distillation facility increases the amount of VOC
emitted into the atmosphere by that facility, or results in the emission of
VOC not previously emitted. Some examples of a potential modification
include: (a) replacement of column internals (e.g., trays, packing); (b)
replacement of column accessories (e.g., reboiler, condenser, vacuum
systems); (c) feedstock or catalyst changes; and (d) equipment changes for
the purpose of energy conservation. Exceptions to the definition of
modification are presented in paragraph (e) of Section 60.14. A
reconstructed distillation facility, based on the definition of
reconstruction in 40 CFR 60.15, occurs when components of an existing
distillation facility are replaced to such an extent that; (1) the fixed
capital cost of the new components exceeds 50 percent of the fixed capital
cost that would be required to construct a comparable entirely new facility,
and (2) it is technologically and economically feasible to meet the
applicable standards. Any of the previous examples of a potential
modification could also represent a potential reconstruction if these two
criteria are met.
An existing distillation facility that undergoes a modification or
reconstruction would be expected to initiate its compliance obligations by
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notifying the Administrator as required by 40 CFR 60.7 and by completing a
performance test as required by 40 CFR 60.8.
2.8.5 COMMENT: One commenter (D-33) requested that the replacement of
trays and packing in distillation columns not be considered a reconstruction
when the cost of replacement exceeds 50 percent of the facility replacement
cost and no increase in emissions results. The commenter indicated that
custom fabricated trays and packing are subject to wear, corrosion, fouling,
and damage and can be very expensive to replace.
RESPONSE: The EPA states in the BID for the proposed standards that the
replacement of internals (trays and packing) for the most part involves a low
percentage capital cost relative to a new facility. Generally, individual
trays and packing are replaced one at a time in response to maintenance needs
(e.g., cracked tray). Since replacement costs considered for reconstruction
are only accumulated over a 2-year period, these types of replacements would
not likely result in a facility being considered as reconstructed. It is
possible that the internals replacement cost could approach the 50 percent
criteria for large capacity columns with a large number of trays if the trays
and all the packing were all replaced at the same time. However,
replacements of this extent would not be regarded as a routine maintenance or
repair activity. Rather, total replacement of internals would be done as a
result of a process change either to increase efficiency or to make a new
product.
2.9 MONITORING AND MEASUREMENT METHODS
2.9.1 COMMENT; Two commenters (D-8 and D-15) stated that the
monitoring requirements will be costly and cumbersome for both the industry
and EPA. The industry will be burdened by the constant vigilance and upkeep
required to maintain the recording and sensing devices. One commenter (D-15)
stated that the monitoring requirements would make it difficult for the
Agency to properly evaluate the measurement data provided by the affected
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facilities because of the large amount of information involved. The other
commenter (D-8) urged EPA to reduce the monitoring requirements to a more
reasonable level.
RESPONSE; In establishing the monitoring requirements for this NSPS,
EPA had to reconcile the need to ensure the effective operation of control
and product recovery devices with the degree of complexity and economic
burden of the monitoring systems on the industry. The Agency believes that
it has chosen the most reliable and fair methods of monitoring. Considering
the complexity of the processes involved and the burden on both EPA and
industry, the monitoring and reporting methods specified are believed to be
the least burdensome way of providing EPA with reliable information about
changes in combustion device operation that could lead to increased VOC
emissions and to ensure the proper operation and maintenance of product
recovery devices.
Two monitoring methods were considered for this NSPS. One was to
require the continuous monitoring of selected parameters at the final product
recovery or control device. Selected parameters for an incinerator, for
example, would be the inlet and outlet organics concentrations monitored
continuously. This procedure would provide a continuous direct indication of
actual emissions and control device efficiency. However, two monitors would
be required in order to determine the incoming and outgoing organic concen-
trations. Therefore, it was decided that this type of system would be too
complex, labor intensive and relatively expensive even if only one monitor
were required on the outlet.
The other monitoring method considered was to rely on more easily
measured process operating parameters that could be related to control device
efficiency. These monitored values could then be compared to the values
obtained during the most recent performance test to ensure the required VOC
removal was still being achieved. For example, the owner or operator of an
affected facility using an incinerator to comply with the standards could
monitor the temperature of the firebox because it has been shown to have a
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profound effect on the efficiency of VOC reduction. Changes in temperature
from the original test could indicate that 98 percent VOC reduction
efficiency is not being achieved.
The same approach was investigated and found to be feasible for all
recovery devices and combustion devices that may be used to comply with these
standards. This method has the advantages of a lower cost while still having
a reasonable reliability compared to the continuous monitoring of organics
concentrations. Furthermore, EPA believes the cost of the monitoring
requirements to be reasonable and necessary to ensure the proper operation
and maintenance of control or recovery systems used to comply with the
standards. Thus, the monitoring method relying on easily measured parameters
was selected for this NSPS. Also, EPA has decided to allow for the use of
computerized data control systems to monitor product recovery and combustion
control equipment at a frequency of at least 1 percent of the compliance
period (see comment 2.9.12).
2.9.2 COMMENT: Two commenters (D-ll and D-13) stated that monitoring
requirements should not apply to startups, shutdowns and malfunctions.
Because the standards do not exempt affected distillation facilities from
monitoring requirements during irregular operations, the commenters requested
this exemption be included in the monitoring section of the regulation.
Also, three commenters (D-5, D-12, and D-13) stated that reporting and
recordkeeping requirements are not appropriate for this NSPS for periods when
there is no vent stream flow rate such as during shutdowns and malfunctions.
One of the commenters (D-12) indicated that periods of no flow rate into
combustion devices wil.l occur often during shutdowns. He believes that the
semiannual reporting required under Section 60.665(k) should not include
these shutdowns. Another commenter (D-5) stated that the reporting require-
ments would apply to distillation facilities that normally have no vent
stream flow rate because of the use of pressure relief valves on the
accumulator or reflux drums. There would be a flow rate of the vent stream
only when the pressure at the relief valve were great enough to cause a
release of the gas.
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One of the commenters (D-13) requested clarification on the requirement
that smokeless flares not have visible emissions (except for periods of no
more than 5 minutes in 2 consecutive hours). It is the commenter's
impression that startups, shutdowns, and malfunctions are not covered under
these standards and monitoring should not be required.
A request was made by one commenter (D-9) for an allowance of increased
emissions during periods when boilers and process heaters are shutdown. Such
devices are generally shutdown for periods from 5 to 10 days per year to
conduct safety and operational inspections, and perform preventative
maintenance work.
RESPONSE: The General Provisions (40 FR 60.8(c)), do specify that
emissions in excess of the level of the applicable emission limit during
periods of startup, shutdown, and malfunction are not considered a violation
of the applicable emission limit. This means that emission levels during
these periods are not counted as violations if they exceed the levels
specified in the standards.
However, monitoring is still necessary during these periods. The
General Provisions require under Section 60.11(d) that at all times,
including periods of startup, shutdown, and malfunctions, owners and
operators shall to the extent practicable, maintain and operate any affected
facility including associated air pollution control equipment in a manner
consistent with good air pollution control practice for minimizing emissions.
Determination of whether acceptable operating and maintenance procedures are
being used will be based on information available to the Administrator which
may include, but is not limited to, monitoring results, opacity observations,
review of operating and maintenance procedures, and inspection of the source.
According to the definitions given in the General Provisions, "startups"
and "shutdowns" refer only to the affected facility and not to control
devices. However, "malfunctions" are any sudden and unavoidable failure of
the affected facility or control devices to operate in a normal manner or
usual manner. Therefore, emissions beyond the limit due to scheduled
maintenance work on boilers or process heaters are not allowed by EPA.
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2.9.3 COMMENT: One commenter (D-27) considered it unnecessary to
monitor the inlet of each incinerator within an affected facility by using a
flow meter and continuous recorder according to Section 60.663(a)(2). The
commenter further stated that EPA indicated in the air oxidation NSPS
preamble (48 FR 48945) that a flow meter and continuous recorder are not
needed because there is no meaningful relationship between flow rate and VOC
reduction efficiency.
Two commenters (D-27 and D-33) stated that flow indicators are not
necessary for flares, boilers and process heaters, as required under para-
graphs (b)(2) and (c)(l) of Section 60.663. They indicated that although the
requirement is intended to ensure vent streams are being routed for
destruction, the chance of a vent stream flowing anywhere unintended is
unlikely. In the case of flares, one of the commenters (D-33) felt that the.
only way to ensure flow to the flare is to hard pipe the flow to the flare
and only the flare. The other commenter (D-27) indicated that vent streams
must be actively directed for safety reasons. To avoid explosion hazards,
the commenter explained, pipes and headers will have to be operated at least
a little above atmospheric pressure to prevent air from leaking in. Vents
from these pipes and headers will have to be pressurized and purged with
either nitrogen or natural gas to remove oxygen from the vents. An oxygen
monitor will also be required. Because the system is under pressure, it is
unlikely that leaks of VOC to the atmosphere will occur.
One commenter also requested that reporting and recordkeeping
requirements for vent stream flow rates into combustion devices be deleted
from the standards according to the same reasoning provided about monitoring
requirements. He added that flow rate monitoring is not required for the same
equipment in the SOCMI equipment leaks NSPS and the air oxidation NSPS.
One commenter (D-33) requested that there be no requirement to monitor
flow of individual vent streams at points before the streams are combined for
routing to the flare. He saw no need to use monitors on individual vent
stream flow which, at his proposed plant, could result in costs of up to
$115,000. The commenter stated that if flow had to be monitored, EPA should
require monitoring of the combined flare from all sources and not individual
vents from all pipes fed to the flare.
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RESPONSE: The EPA has amended the regulation (Section 60.663(a)(2)) to
require flow indicators instead of flow meters for monitoring a distillation
vent stream flowing into an incinerator. The Agency has determined that flow
indicators are sufficient for ensuring the vent stream is; being routed for
destruction and that firebox temperature alone provides an adequate indication
of incinerator performance.
As stated above, flow indicators and recordkeeping and reporting, are
required for incinerators, as well as boilers, process heaters and flares in
order that EPA can be assured vent stream emissions are routed to an appro-
priate control device. The EPA found that the cost associated with these
requirements is reasonable. Even though vent streams may be directed to a
control device for safety reasons, the Agency requires a demonstration that
each vent stream is directed to a properly functioning control devjce. In
the event flow to the combustion device is interrupted, such as emergency
venting due to over pressure in the lines or a combustion device shutdown,
the Agency must have a means of identifying when this occurs and how often.
A discussion of the cost resulting from monitoring requirements is presented
in the response to comment 2.9.1.
One commenter requested that vent stream flow indicators be required for
flares at a point after all streams have been combined. The EPA will
continue to require flow indicators in the vent stream from each distillation
unit within an affected facility before each stream is combined with any
other vent stream being routed to a combustion device. The Agency has
determined the cost of this monitoring requirement to be reasonable. If
indicators were not placed in each affected vent stream before it were
combined, then it would not be possible for the Agency to be certain that
each vent stream is routed to the combustion device. Furthermore, if
nondistillation vent streams were combined with distillation vent streams
before combustion and a flow indicator were placed in the combined stream,
then the monitoring requirements would be applied to process streams that
were not intended to be covered by the standards.
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2.9.4 COMMENT: One commenter (D-13) suggested that only periodic
thermocouple monitoring plus recordkeeping should be required to determine
whether a boiler is in service or not in service. Section 60.663(c)(2)
requires the use of a temperature measurement device equipped with a con-
tinuous recorder for boilers or process heaters of less than 44 MW
(150 million Btu/hr) heat input design capacity. It was indicated that
thermocouples are routinely placed in process heaters where temperatures run
about 1,600 - 1,700°F. However, boilers do not usually have firebox thermo-
couples because the firebox temperature runs between 2,000 - 2,700°F. The
commenter concluded that continuous temperature monitoring would be difficult
because of high temperatures in boilers and the related problems with thermo-
couple maintenance. A decreased exposure time of the thermocouple to the
firebox, as with periodic sampling, would decrease the heat stress upon the
thermocouple and thus prolong its reliability.
RESPONSE: The EPA believes that continuous temperature monitoring of a
boiler firebox with a design heat input capacity of less than 44 MW can be
accomplished at a reasonable cost. In order to protect the thermocouple from
heat stress, a relatively inexpensive ceramic insulator can be used (see
Docket Item No. IV-J-16). The thermocouple and ceramic insulator can be
purchased for less than $400 and can be permanently installed to the boiler.
Thus, the continuous temperature monitoring of boilers as required under
Section 60.663(c)(2) has not been changed. The EPA has changed the
definition of "continuous" to mean a time interval of at least every
15 minutes. This change will allow for the use of computer-assisted systems
for monitoring requirements (see comment 2.9.12).
2.9.5 COMMENT: One commenter (D-28) agreed with EPA and stated that it
is appropriate to waive performance tests and monitoring requirements for
sources combusting process vent streams in steam generating devices that have
heat input capacities of 44 MW or greater. The commenter suggested that
performance testing and monitoring requirements be waived under the following
conditions: (a) boilers with heat input capacities of 44 MW or greater;
(b) all combustion devices maintaining a combustion temperature of 1,100°C
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and 1 second residence time; or (c) incinerators maintaining a temperature of
870°F and 0.75 second residence time if no halogenated organic compounds are
in the vent stream.
RESPONSE: The EPA believes that condition (a) mentioned by the
commenter is sufficient for exemption from performance tests. The Agency
believes that boilers and process heaters with a design heat input capacity
of 44 MW or greater would achieve a reduction efficiency of 98 percent or a
reduction to 20 ppmv, so long as the distillation vent stream is introduced
into the flame zone. These boilers and process heaters are typically
operated at temperatures and residence times greater than 1,100 C and
1 second, respectively. A firebox temperature of 1,100°C and 1 second
residence time represent the conditions that might in the worst case be
necessary to achieve 98 percent reduction, even if the organics were
chlorinated. Furthermore, it is to the economic advantage of the owners of
facilities using boilers or process heaters to design and operate them with
adequate mixing of gases to maximize the extent of combustion, thereby
maximizing the steam or heat generation rate.
However, conditions (b) and (c) mentioned by the commenter are not
sufficient. Even though an incineration device may be operated at tempera-
tures greater than 1,100°C and 1 second residence time (870°C and 0.75 second
residence time for nonhalogenated streams) the distillation column offgas,
combustion gases, and supplemental air must be well mixed in order to achieve
complete combustion. The EPA has determined that proper mixing is, in fact,
as important as temperature and residence time in determining incinerator
efficiency. This concept is explained in an EPA memorandum (Docket Item
No. II-B-3). Improperly mixed gases may actually offset the increases in
efficiency generated by raising the combustion temperature. This is due to
the fact that increases in temperature only increase the destruction
efficiency for VOC within the well-mixed portion of the waste gas. In an
improperly mixed stream the increase in temperature does not greatly affect
combustion efficiency. Temperature would be a poor indicator of system
efficiency in such a case.
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Unfortunately, mixing is a variable which cannot be measured. Proper
mixing is generally achieved through a trial-and-error process of adjusting
the incinerator after startup. There is no practical method of ensuring that
proper mixing occurs except by conducting a performance test and making the
necessary adjustments. For this reason, incinerators operating at the
temperatures and residence times expressed by the commenter in conditions (b)
and (c) are not exempt from the performance test requirements.
2.9.6 COMMENT: One commenter (D-12) stated that the definition of
"distillation unit" in Section 60.661 should include a vacuum pump or steam
jet, if present, as part of the distillation unit. The commenter noted that
it is impractical to sample upstream of these pumps or jets in vacuum
distillation systems and wants to be sure that EPA would not require sampling
at this location.
RESPONSE: Vacuum pumps and steam jets attached to a distillation column
are necessary components for the distillation operation to occur and are
considered to be examples of the accessories referred to in the definition of
"distillation unit" in Section 60.661. In order to clarify that sampling
downstream of a vacuum pump or jet is considered to be appropriate by EPA,
the definition of "distillation unit" has been amended to specifically
include these accessories.
2.9.7 COMMENT: One commenter (D-15) requested that a method for
locating sampling sites for vents less than 4 inches in diameter be provided
in Section 60.664(c)(l). Methods 1 or 1A are those specified for selecting a
sample site. Method 1 is applicable to vents greater than 12 inches in
diameter. Method 1A applies to vents from 4 to 12 inches in diameter.
However, no method is given for locating sampling sites on vents less than
4 inches in diameter.
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RESPONSE: Method 2D - Measurement of Gas Volume Flow rates in Small
Pipes and Ducts (48 FR 48957) can be used to sample vents less than 4 inches
in diameter. The method is listed in Section 60.664 as a. suitable method for
this NSPS.
Because a pitot tube and sampling probe, as used in larger diameter
vents, would be disruptive to the flow rate of a small diameter vent,
Method 2D requires that the entire vent stream be directed through a
measurement device such as a rotameter. Therefore, a specific site location
is not required. Section 60.664(c)(l) has been amended to clarify that no
site selection method for the vent cross section is needed for vents smaller
than 4 inches. Method 2D is appropriate in this case.
2.9.8 COMMENT: One commenter (D-27) requested the addition of
Reference Method 2D to Section 60.664(f). This section indicates that only
Methods 2A and 2C are appropriate to determine vent stream volumetric
flow rates.
RESPONSE: Section 60.664(f) has been amended so that Reference
Methods 2 and 2D will be allowed in order to be consistent with
Section 60.664(a)(2).
2.9.9 COMMENT: One commenter (D-14) stated that the measurement of
vent stream velocities according to the proposed standards may present a
safety hazard. He indicated that when an orifice is placed in a vent in
order to measure stream velocity, a constriction is made in the piping. This
constriction would hamper the ability of the piping to handle high vent
stream loads in upset conditions, possibly leading to unsafe pressure buildup
in upstream equipment. Therefore, the commenter suggested deleting this
requirement.
RESPONSE: If the owner or operator feels the use of an orifice meter is
an unsafe procedure, there are several ways to ensure the safety of the
procedure. For example, a T-joint with a rupture disc can be placed in the
vent upstream of the orifice meter so that the disc is parallel to the
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direction of flow. The rupture disc would provide for emergency venting due
to any potential pressure buildup. Because these and other safety procedures
can be implemented at a relatively low cost and because methods other than
orifice meters are available, EPA has not deleted the requirement to use a
pipe constriction as one of several alternatives to measure the flow rate in
small vents.
2.9.10 COMMENT: One commenter (D-13) suggested that rather than
requiring flow monitors to be installed on all small vent streams affected by
the standards, the option of tank car seals should be allowed in the
regulation. It was pointed out that these seals can be used to assure that
all connections on a vent line, other than to a combustion or recovery
device, are closed. The commenter recommended that quarterly monitoring of
the tank car seals could be used to ensure seal closure. The commenter
stated that the use of these seals on vent streams fed to boilers or process
heaters would allow for regulatory flexibility.
RESPONSE: As discussed in the response to comment 2.9.3, EPA has
changed the monitoring requirement (Section 60.663 (a)(2)) for a vent stream
combusted by an incinerator from the use of .flow meters to flow indicators.
Flow indicators are required to ensure that the vent stream is directed to
the combustion device used to control VOC emissions. These indicators
provide a record and can be quickly and regularly checked to determine if the
vent stream is reaching the combustion device. The EPA decided to require
the use of flow indicators because of this reliability and th.eir low cost.
As listed in the General Provisions (Section 60.13(1)), EPA allows the
owner or operator of an affected facility to apply to the Administrator to
use alternatives to any monitoring procedures or requirements listed in the
distillation regulation. The owner or operator can pursue this avenue for
alternative methods, including tank car seals.
2.9.11 COMMENT; One commenter (D-19) expressed uncertainty about the
basis for the specified accuracy of temperature recorders and flow rate
recorders. The commenter stated that it is unreasonable to attain an
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accuracy of 1 percent or +2.5 C at firebox temperatures of 1,100 C. The
commenter also questioned the need for an accuracy of 1 percent or +2.5QC for
temperature readings on scrubbing liquids, condenser coolants, and carbon
beds (Section 60.663(d)(l), (2) and (3)). The commenter indicated that this
is too restrictive in light of the accuracy of current technology.
The commenter stated that for continuous flow rate recorders the accu-
racy of 5 percent at flow rates of 100 to 500 scfm (Section 60.663(a)(2))
seems restrictive. He feels that current recorders are not capable of
providing this level of accuracy.
RESPONSE: The EPA has acquired a great deal of experience in the
capabilities and limitations of various test methods and monitoring/
measurement equipment. Based on this experience, the Agency has reevaluated
the temperature monitor accuracy requirement and has determined that the
accuracy should be 1 percent or +0.5°C, whichever is greater. Therefore, the
final regulation will require this accuracy instead of the +2.5°C in the
proposed regulation. For an incinerator operating at 870°C an accuracy of
+8.7°C would be required. These accuracies can be achieved at a reasonable
cost through the use of readily available equipment. Flow meters are no
longer required for the measurement of vent stream flow rate into an
incinerator, instead, flow indicators are now required. Flow indicators have
no accuracy requirements because their function is only to indicate the
presence or absence of flow to the incinerator.
2.9.12 COMMENT: Two commenters (D-15 and D-27.) requested the standards
allow the use of computer-assisted systems to monitor product recovery and
combustion control equipment. One commenter (D-15) stated that only inter-
mittent recording at 6 to 10 minute intervals (not a totally continuous
recording) is possible with certain computer control/recording systems. The
other commenter (D-27) noted the maintenance, storage of spare parts and
understanding of an analog system with a strictly continuous recording system
would present many problems since they are rarely Used in the industry
anymore. The commenter recommended that "continuous" be defined in the
regulation such that data should be collected at a frequency not less than
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1 percent of the compliance period. For example, if the compliance period
were 180 minutes, then the frequency of sampling would be at least every
1.8 minutes. The commenter believes that this definition of "continuous"
would serve the EPA purposes equally well while still allowing industry to
use a monitoring/recording system compatible with current computer control
systems. The other commenter (D-15) recommended that continuous monitoring
be defined as systems capable of continuously recording parameters in
increments of 10 minutes or less.
RESPONSE: The EPA has agreed to add a. definition of "continuous" to
Section 60.661 as follows: "Continuous recorder" means a data recording
device capable of recording data at time intervals of at least every
15 minutes. This will enable industry to use existing computerized data
control systems attached to a measurement device. Furthermore, this time
interval has been found to be an adequate time period for providing EPA with
sufficient data to ensure proper operation and maintenance of VOC control
equipment. The measurement device will actually be sensing on a constant
basis, but the data will only be sampled at certain intervals.
2.9.13 COMMENT: One commenter (D-12) wanted to be certain that the
standards provide for continuous monitoring. Therefore, he suggested a
wording change for Section 60.665. Where the phrase "every-15-minutes" is
used, a wording change should be made so the phrase reads "at least every
15 minutes." The same commenter requested that EPA discuss the potential
difficulties in making continuously recorded measurements. He also wanted to
know if reliable devices are readily available.
RESPONSE: In Section 60.665 of the proposed regulation, the phrase
"every 15 minutes" refers to the measurement of parameters during performance
testing to establish parameter boundaries for use during monitoring pro-
cedures to ensure that the required VOC emission reductions occur. However,
based on a review of performance test requirements and monitoring
requirements the regulation has been amended to require measurement and
monitoring be done on a consistent basis. The measurements of temperature,
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specific gravity and steam mass flow rate made during performance tests are to
be made at least every 15 minutes. This interval is the same as the
monitoring interval discussed in the response to comment 2.9.12.
A discussion of the practicality of making continuously recorded
measurements was given in the preamble to the proposed standards
(48 FR 57550). Two of the criteria used by EPA to establish the monitoring
requirements are reliability and accessibility. For example, continuous
monitors to measure TOC were not required because they are expensive and
require much maintenance. Instead, EPA chose to require monitoring of
temperature and flow rate as a more reliable and less cumbersome measure that
would involve readily available equipment.
2.9.14 COMMENT: One commenter (D-28) stated that Method 18 (a gas
chromatography procedure for measuring organic compounds) is not always the
best method to measure specific organic compound concentrations. According
to the commenter, gas chromatography is not sensitive enough to detect
concentrations of certain compounds in the range of 20 ppmv. It was
suggested that the standards contain a discussion of alternate test
procedures, such as wet chemical methods, that have greater sensitivity than
gas chromatography.
RESPONSE: The EPA has judged this method to be accurate within
10 percent, and to have a lower limit of detectability to about 1 ppmv.
Although Method 18 cannot be used in a limited number of situations such as
in measuring compounds that can polymerize before analysis, the vast majority
of organics emitted from industrial sources can be analyzed using this
method. Therefore, Method 18 has been judged to be an applicable and
dependable method for measuring emissions from distillation facilities.
However, under Section 60.13(i), the General Provisions allow an owner or
operator to apply to the Administrator for the approval of alternatives to
any of the measurement requirements or procedures listed in the distillation
regulation.
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2.9.15 COMMENT: One commenter (D-10) stated that the actual
measurement of VOC emissions from incinerators would provide a more accurate
assessment of performance than what is currently required in the proposed
regulation. He stated that in addition to internal operating temperature,
residence time and turbulence are also important indicators of thermal
incineration performance. He indicated that many incinerators have heat
exchangers to preheat the incoming vent stream by using incinerator exhaust
Because of the very high operating temperatures of the incinerator, leaks may
develop within the heat exchanger. According to the commenter, these leaks
can permit uncombusted VOC in the incoming vent stream to migrate into the
incinerator exhaust. He further pointed out that this decrease in the amount
of VOC that is combusted would not be detected by monitoring internal
temperature alone. The commenter stated that measurement of VOC emissions
would enable the SOCMI and EPA to judge the relative merits of various
control equipment designs on a consistent basis.
RESP°NSE: The A9ency analyzed the combustion device operating
parameters that affect incinerator performance. Included in these variables
are temperature, mixing, type of compound combusted, residence time inTet
concentration, and flow regime. The last two variables were judged'to have
only a small impact on incinerator performance. Residence time is
essentially set after incinerator construction unless vent stream flow rate
is changed. Compound type has little effect on combustion efficiency at
temperatures above 760°C. Mixing (turbulence) was judged to be as important
as temperature and residence time in determining incinerator efficiency (see
Docket Item No. II-B-3). Unfortunately, mixing is a variable that cannot be
measured. Given the large effect of temperature on efficiency and the low
cost of temperature monitors, this variable is clearly an effective parameter
to monitor.
The EPA recognizes that monitoring temperature alone is not a sufficient
means of determining incinerator performance. It is for this reason that
temperature and vent stream flow rate are measured during the performance
test and then monitored to determine if their values deviate from the values
measured during the performance test. This is true for both catalytic and
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thermal incinerators. Considering the complexity of the processes involved
and the burden on both EPA and industry, the monitoring methods specified are
believed to be the least burdensome way of ensuring that the control
equipment is properly operated and maintained.
Development of leaks in the heat exchanger is an example of deterioration
problems that can occur in all control equipment over a period of time. The
General Provisions (Section 60.11(d) require owners and operators to maintain
and operate control equipment in a manner consistent with good air pollution
control practices for minimizing emissions. General enforcement inspections
may be made to check for any deterioration in control equipment and to
determine the need for performance tests.
2.9.16 COMMENT: Two commenters (D-ll and D-13) requested that the
proposed standards include the option to monitor flare performance visually
or by ultra-violet beam sensor instead of using a thermocouple heat sensor on
the pilot flame of the flare. One of the commenters (D-ll) stated that when
a temperature device is used for flare monitoring, increased emissions may
result due to shutdowns for monitoring instrument repair. Therefore, the
commenter requested devices such as an ultra-violet beam sensor be allowed by
these standards. The other commenter (D-13) noted that normal flare design
assures a flame presence at all times because the pilot flame is supplied
with gas by an independent and reliable source. It was pointed out that
experience shows thermocouples to present a major and unnecessary maintenance
problem. This commenter recommended flame and smoke detection to be done by
a remote video camera.
RESPONSE: The EPA has decided that use of a ultra-violet beam sensor is
suitable to indicate the presence of a flame. Therefore, the regulation will
be amended to allow for ultra-violet beam sensors or thermocouples to be used
as a heat sensing device at the pilot light to indicate the continuous
presence of a flame.
The detection of flame presence by visual means or by remote video
camera is not a suitable method. If a flare is operating smokelessly it can
be difficult to determine if a flame is present.
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2.9.17 COMMENT: One commenter (D-28) suggested that EPA provide for
alternative methods of demonstrating compliance when distillation process
emissions are combined with other emission sources within the plant. For
example, vent streams from distillation processes may be combusted in wood-
fired boilers. Since wood-fired boilers inherently generate VOC emissions,
demonstration of compliance with the proposed standards may be difficult.
RESPONSE: The General Provisions (40 CFR 60.8) state that the
Administrator may approve the use of "an alternative method (of demonstrating
compliance), the results of which he has determined to be adequate for
indicating whether a specific source is in compliance" with a standard. This
is applicable to all NSPS and need not be specified in the regulation.
When distillation vent streams are combined with nondistillation offgas
streams within the plant, compliance of the-combined stream may be demon-
strated using Reference Method 18, using an alternative method approved for
the particular facility by the Administrator or waived because the owner or
operator has demonstrated by other means to the Administrator's satisfaction
that the affected facility is in compliance with the standards. For example,
the offgas stream from a reactor may be routed through the product recovery
device or directly to the control device of a distillation affected facility.
The EPA has determined that if compliance is demonstrated with the combined
stream, compliance would also be achieved when routing the distillation vent
stream alone.
In the commenter's example wherein a wood-fired boiler is used to
combust distillation vent gases, VOC will be generated by the combustion
device itself. In this case, the total VOC reduction would still have to be
98 percent. If the VOC generated by the wood-fired boiler prevents this, it
will not be considered in compliance with the standards.
2.9.18 COMMENT: One commenter (D-ll) requested the option to use other
methods to monitor condenser performance in lieu of the current requirement
to monitor the exit (product side) temperature of the offgas. The commenter
recommended methods such as the cooling water differential temperature or the
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on-line analysis of the exit VOC concentration of the condenser on the
product side. Correlations developed during a performance test were also
recommended as an indicator of compliance during routine operation.
RESPONSE: The EPA has determined that the monitoring of the exit
(product side) temperature provides the Agency with sufficient information
and is a relatively inexpensive indicator of condenser performance. Although
measuring the cooling water differential temperature may also provide
sufficient information, EPA does not require this measurement because it
would call for the use of two temperature monitors instead of one monitor.
This differential measurement would be more costly and would provide little
additional information than the exiting product side temperature alone.
However, as indicated in the General Provisions under Section 60.13(i) and in
the distillation regulation under Section 60.663(d), the owner or operator
may apply to the Administrator to use alternative monitoring methods, such as
cooling water differential temperature.
A continuous monitor to measure the TOC (minus methane and ethane)
exiting the condenser would be much more expensive and complex than the
current monitoring requirements. Furthermore, the reliability and accuracy
of these devices may be poor in some situations. Therefore, EPA has decided
that, generally, the exiting product side temperature is the least burdensome
way for an owner or operator to effectively monitor condenser performance.
However, as indicated above, an application to the Administrator may be made
to use this device in lieu of the current requirements.
2.9.19 COMMENT: One commenter (D-12) requested clarification on
temperature monitoring during catalytic incineration. The commenter stated
that the temperature of the incinerator after the catalyst bed is critical
for compliance, not before the bed as stated in Section 60.665(c)(2).
RESPONSE: According to Section 60.665(c)(2), temperature measurement is
required immediately after the catalyst bed as well as before the bed. The
inlet and outlet temperatures must be monitored because a temperature
differential that is within 80 percent of the differential measured during
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the most recent performance test indicates that catalyst performance and
subsequent destruction efficiency is similar to those during performance test
conditions. When only the outlet temperature is monitored, a preheated vent
stream could be sent through an inactive catalyst bed at a desired tempera-
ture so it would appear as if the catalyst were functioning properly.
However, monitoring a temperature rise from the inlet to outlet of the
catalyst bed would indicate that the temperature increase was due to
emissions destruction. Therefore, no changes will be made to the regulation
concerning the monitoring requirements for catalytic incinerators.
2.9.20 COMMENT: One commenter (D-20) expressed confusion over what
constitutes "recovery" with regard to the use of the TRE index. The
commenter stated that the term "recovery system" is defined in Section 60.661
as an individual unit or series of material recovery units used for the
purpose of recovering TOC from a vent stream. The commenter pointed out that
the BID (pp. 4-8, 4-10) indicates "recovered" VOC may be disposed. The
commenter prefers the definition of "recovery" to allow for the disposal of
collected VOC. Therefore, he requested the definition of recovery system be
revised to allow for the disposal of VOC.
The commenter stated that if recovery means reclaimed for beneficial
reuse only, then the point in the recovery system where the distillation vent
stream is selected for a TRE index calculation is inappropriate. If any of
the organics collected from recovery equipment are reclaimed for beneficial
reuse, then the TRE value is calculated for the vent stream after the
recovery equipment. But, if organics exiting the same recovery equipment
were disposed of, then the TRE value for the vent stream would be calculated
before that equipment. The commenter noted that the same emissions would
result in either case.
RESPONSE: According to Section 60.661 of the regulation, in order for
the TRE to be determined after a recovery device, the VOC exiting that device
•ust be either used, reused (e.g., recycled), or sold. The Agency maintains
that disposal of VOC collected by a device does not constitute recovery of
that VOC. Therefore, it is not appropriate to designate that as a recovery
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device for the purposes of these standards. The wording in the BID indicated
by the commenter does not convey the proper intent of the standards. The
outflows from the recovery devices diagrammed on pp. 4-8 and 4-10 should not
have been designated as routed for disposal. Instead, the label should have
indicated "for use, reuse, or sale."
In order for a control device which disposes of collected VOC to be used
in complying with these standards, a 98 weight-percent VOC reduction or
20 ppmv emission limit must be maintained. However, the owner/operator of an
affected facility using such a device must satisfy existing regulations
concerning the disposal of the collected VOC. When using such a device to
comply with the 98 weight-percent or 20 ppmv emission limit, compliance must
be demonstrated as described in Section 60.664(b)(4). Furthermore, as
described in Section 60.663(e), the owner/operator must provide to the
Administrator information describing the operation of the control device and
the process parameter(s) which would indicate proper operation and maintenance
of the device.
2.9.21 COMMENT; One commenter (D-30) requested a change in the
monitoring requirements for the case when two or more distillation streams
containing dimethyldichlorosilone, a chemical listed Section 60.667, share a
common recovery device [Section 60.664(c)(ii)]. The commenter requested an
allowance for these distillation streams to be monitored after the outlet of
the last methylchlorosilone hydrolysis control device. It was pointed out
that in the production of dimethyldichlorosilone, as much as 50 percent of the
TOC's emitted from distillation columns are methylchlorosilones. The
commenter stated that these chemicals readily hydrolyze upon contact with
water to form nonvolatile polysiloxane gels, water soluble silanols, and
hydrogen chloride gas. The commenter indicated EPA does not recognize that
VOC is removed and converted to nonvolatile forms through the hydrolysis
control of methylchlorosiTones. The commenter believes that a properly
designed water scrubbing device provides a VOC emission control that meets the
EPA standards for the production of dimethyldichlorosilone. The commenter
proposed that the method for locating sites to sample flow rate and
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molar composition as listed under Section 60.664(c)(l)(ii) be changed to
include "the outlet of the last methylchlorosilone hydrolysis control
device."
The same commenter stated that Section 60.664(c)(l)(111) does not
contain sufficient information to allow evaluation of the sampling method
requirements when an affected distillation column shares a common recovery
device with one or more existing distillation columns. The commenter
requested that EPA reword the paragraph.
RESPONSE: According to the definition of recovery system in
Section 60.661 the methylchlorosilone hydrolysis control device would be a
product recovery device if it were used to recover VOC exiting the device for
beneficial reuse. The term, beneficial reuse, refers to the fate of VOC
after it exits the recovery device. If the VOC is either sold, recycled
within the process unit or used in another process unit, but not disposed of,
then the VOC is beneficially reused. Therefore, the TRE determination and
monitoring would be associated with the last such recovery device. If the
VOC were not beneficially reused and thus disposed of, then the vent stream
characteristics must be measured before that device for the TRE calculation.
As discussed in the response to comment 2.9.20, the only way a device which
disposes VOC can be used to comply with these standards is if a
98 weight-percent VOC reduction or 20 ppmv outlet concentration is
maintained.
The commenter also requested more information on the sampling
requirements when an affected distillation column shares a recovery device
with one or more existing distillation columns. The EPA has decided to
change the designation of affected facility such that all of the columns
sharing a common recovery device would constitute a single affected facility
(see comment 2.2.1). Therefore, there will be no need to apportion the vent
stream between affected and nonaffected distillation columns in this case
since all columns would constitute one affected facility.
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2.9.22 COMMENT: Commenter D-37 stated that the TRE index should be
calculated including all equipment up to the point at which the process
stream vents to the atmosphere to ensure that the TRE equation can be used
with respect to some developing technologies. In addition, the commenter
said that the TRE equation should be modified to allow use of the charac-
teristics of the vent stream emitted to the atmosphere. The owner/operator
should then be required to demonstrate that no negative environmental impact
will result from disposal of liquids or solids from the control device. The
commenter stated that the proposed method for determining TRE could prevent
the cost-effective use of some control devices without any commensurate
benefit to environmental quality. The commenter further stated that without
the modifications suggested, some control devices would be able to show
compliance under the "98 percent reduction" alternative standard but not show
compliance using the TRE index.
RESPONSE: As stated in the preamble to the proposed standards, a
distillation column generally does not release emissions directly to the
atmosphere since all offgas from it is vented to recovery devices. In
developing the final standards, EPA designated the recovery system and its
associated distillation columns as the affected facility because it led to
greater emission reductions than alternative designations (see Comment
2.2.1). Because recovery systems are part of the process and also very
effective in reducing VOC emissions, it was decided that all decisions on the
need for additional VOC control should be based on the stream characteristics
of the vent stream exiting the recovery system. The impacts associated with
requiring additional VOC control after product recovery were then estimated
and evaluated. The Administrator determined that when the cost of control of
the recovery system's vent stream was greater than $l,900/Mg of VOC removed,
BDT is no additional control. It was also determined that when the cost was-
less than $l,900/Mg of VOC removed, BDT is the reduction of VOC emissions by
98 weight-percent or to 20 ppmv. Recovery equipment normally is operated at
the most economically efficient level which may not correspond to maximum
reduction of VOC emissions. However, the Administrator determined that where
the cost of control is less than $l,900/Mg of VOC removed, requiring an
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additional 98 weight-percent reduction is reasonable. The change the
commenter suggested would allow the use of control devices that are not as
effective as BDT. Because the impacts associated with requiring BDT are
reasonable, no change has been made to the final standards.
2.10 REPORTING AND RECORDKEEPING
2.10.1 COMMENT: Three commenters (D-5, D-12, and D-13) stated that
annual reporting of changes in normal operations would be sufficient instead
of the semiannual reports currently required under Section 60.665(k). One
commenter (D-24) agreed with the waiving of the semiannual reporting
requirements for affected facilities in States where EPA, in the course of
delegating the enforcement programs, approves alternative reporting
requirements or means of source surveillance.
RESPONSE: Semiannual reporting is only required for the following
circumstances: (a) when the monitored parameters of combustion and recovery
devices exceed the latest performance tests; (b) when a vent stream is
diverted from a control device or does not have a flow rate; (c) for periods
when a boiler or process heater is not operating; (d) when the pilot flame of
a flare is absent; (e) for any changes in a process operation that cause an
increase in the maximum design vent stream flow rate for affected facilities
with a flow rate less than 0.008 m /min; (f) for any changes in a process
operation that increases the design production capacity of the process unit
for affected facilities with a design production capacity less than 1 Gg/yr;
and (g) for any recalculation of the TRE index value. Reporting of these
occurrences are required on a semiannual, instead of annual, basis because
any situation which has the potential to result in an increase in pollution
should not go unreported for as long as a full year. In addition, because
changes to the process can affect which control requirements the affected
facility must comply with, it is important that these changes be reported at
least semi annually.
The Agency also agrees that semiannual reporting should be waived when
the enforcement program has been delegated to the States and alternative
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requirements have been approved. The Administrator has determined semiannual
reporting of the above occurrences not to be overly burdensome to the
industry to ensure compliance of each affected facility with the appropriate
section of the standards.
2.10.2 COMMENT; One commenter (D-19) stated that the recordkeeping
requirements are excessively burdensome for distillation facilities having a
design capacity of less than 1 Gg/year or a designed maximum flow rate of
0.008 m3/nrin. The commenter suggested that those facilities meeting the
design capacity or vent stream flow rate exemption should only be required to
notify EPA of its exemption status and when the status changes. The
commenter requested that EPA specify under Section 60.665 what these reports
should contain.
RESPONSE: The EPA has decided to exempt from coverage by the standards
distillation facilities that operate with a vent stream flow rate less than
0.008 m3/min, even if the facility is designed for a vent stream flow rate
above that level. However, Section 60.665(i) has been amended to require
the owner or operator of exempted facilities to record any changes in process
operation that may cause the vent stream flow rate to exceed the 0.008 m /min
level and to measure and record the flow rate after the change has been made.
The EPA requires semiannual reporting of process changes and the new vent
stream flow rate measurement only when changes have been made that cause the
vent stream flow rate to exceed the exemption value. Examples of changes in
process operation are given in comment 2.1.5.
The Agency also requires the recordkeeping and semiannual reporting of
changes in process operation that increase the design production capacity of
facilities with design production capacities below 1 Gg/yr. If a change in
process operation does not increase the total design capacity then no record-
keeping or reporting are necessary. The EPA does not feel that semiannual
reporting is excessive.
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2.10.3 COMMENT: One commenter (D-5) requested clarification on the
length of time that records must be maintained by the owner or operator The
commenter suggested that only the most recent performance test data be kept
It was also suggested that the continuous records of the equipment operating
parameters as well as the type of information mentioned in comment 2.10.1 be
kept during the interval between reporting periods.
RESPONSE: The preamble to the proposed standards states that "all
records would be required to be kept up to date and in readily accessible
files for 2 years." Two types of records are required to be kept for this
period. One type is the operations parameters that are monitored during the
operation of control devices or product recovery devices (Section 60 663
Section 60.7(d) of the General Provisions). The other type is the tabulation
of periods when the measurements of the control device or product recovery
device operating parameters significantly deviate from measurements of the
same parameters during the most recent performance test [Section 60 665(c)
through (g)].
2.10.4 COMMENT.: One commenter (D-5) requested clarification on whether
Section 60.665(g)(5)(i) requires recordkeeping for any affected distillation
facility that changes its production rate or for only those facilities where
the design capacity is exceeded.
RESPONSE: The EPA requires under Section 60.665(g)(5)(i) recordkeeping
of any changes in production rate. The Agency may need this information to
be certain that an affected facility demonstrating compliance with a TRE
index value greater than 1.0 is still in compliance after a change in
production rate has been made.
2.10.5 COMMENT.: One commenter (D-12) stated that practical "parameter
boundaries" are needed for the total mass steam flow during carbon bed
regeneration cycles [Section 60.665(g)(3)(i)]. A parameter boundary is a
li.it set during the most recent performance test. Any future measurements
that fall below or exceed (depending on the parameter) this limit must be
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recorded as specified under Section 60.665(g). Another commenter (D-ll)
requested that the same section allow for the exclusion of insignificant
steam flow rate changes that are within the variability of the steam meter.
The commenter recommended that Section 60.665(g)(3)(i) be modified by adding
the following wording: "within the accuracy of the steam meter."
RESPONSE: It is inappropriate for an accuracy limit to be used as a
parameter boundary because it allows for no minor deviation from the
parameter value measured during the last performance test. Therefore, the
regulation has been amended so that reporting is now required under
Section 60.665(g) (3)(i) when the mass steam flow is more than 10 percent
below the total mass flow during the most recent performance test. When the
amount of steam used to regenerate a carbon bed has decreased beyond the
parameter boundary, the carbon adsorber may not adequately be serving as a
product recovery device and thus the TRE value may be less than 1.0.
2.10.6 COMMENT; One commenter (D-15) requested an allowance in the
reporting requirements for condensers [Section 60.665(g)(2)] to account for
increased water temperature during summer conditions. If the performance
test is done in winter when a cooling tower or once-through river water is
used for cooling, the incoming water temperature will increase by greater
than 10°C in the summer. This temperature change will cause the summer
operating temperature of the condenser to continuously exceed the previous
winter operating temperature only because of the summer conditions.
RESPONSE: When the cooling water entering a condenser increases in.
temperature, the effectiveness of the condenser as a product recovery device
is likely to decrease. The requirement to record and report exceedances of
the operating parameters is needed for the owner or operator and the
enforcement agency to know when the condenser may no longer be operating
properly, even if the exceedance is due to seasonal temperature changes.
Therefore, in this case, the owner or operator should either cool the
water to a temperature below the exceedance level or demonstrate to EPA that
the TRE value is still above 1.0.
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2.11 GENERAL
2.11.1 COMMENT: One commenter (D-21) requested better documentation of
contacts between EPA and the Office of Management and Budget (OMB)
especially in regard to the cost-effectiveness cutoff used in the proposed
standards. To substantiate this request, the commenter cited Sierra Cluh .
Costle, 657 F.2d 298 (D.C. Cir. 1981), in which the court accepted the
practice of reducing oral communications to memoranda and inserting them in
the docket. This commenter also cited the CAA Section 307(d)(4)(B)(1i)
which requires written communications to be placed in the public docket!
BESEQNSE: All correspondence between EPA and OMB directly related to
the proposed NSPS for SOCMI distillation operations are contained in Docket
No. A-80-25, which is available for public inspection. The correspondence
can be found under Docket Item Numbers II-F-1 and II-F-2. The policy of how
any communication between EPA and any other Federal agency is treated by EPA
has been clearly described in a letter from a previous Administrator to the
commenter's organization. (Docket No. IV-C-6).
2.11.2 COMMENT: One commenter (D-15) stated that ducting the vent
streams from several distillation units into a common recovery device is
potentially dangerous. It was further pointed out that using a manifold to
jom several vent streams results in a system that is difficult to control
and does not meet the safety requirements of insurance underwriters.
RESPONSE: The Agency does not require ducting vent streams into common
recovery devices. However, some distillation facilities operate by using
common ducting. The EPA realizes that caution must be taken when vent
streams from several distillation units are ducted into a common recovery
device. It is the responsibility of facility owners or operators to meet the
safety requirements established by the company or its underwriters
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2.11.3 COMMENT: One commenter (D-12) stated that chemical names,
mixtures, and generic terms are intermingled for the chemicals listed in
Section 60.667. Also, he indicated that no Chemical Abstracts Registry (CAS)
numbers were supplied. The commenter requested that the chemicals in
Section 60.667 be listed according to the format used for the standards of
performance for equipment leaks of VOC in SOCMI (48 FR 48342 to 48344).
RESPONSE: In order to facilitate the identification of chemicals
affected by the distillation NSPS, the Agency has included the appropriate
CAS numbers in Section 60.667 in the final rule. The chemicals are now
listed according to the format used for the VOC equipment leaks standard.
2.11.4 COMMENT: One commenter (D-12) stated that the discussion of
condensation in the BID should contain a treatment of surface condensers that
do not require dehumidification equipment. It was pointed out that EPA
should not assume water will be present in all distillation vent streams.
The commenter indicated that presence of water vapor requires the use of
dehumidification equipment. According to the commenter, this equipment would
not be suitable for the production of some organics such as benzene that
freeze at the temperature needed for proper water vapor control.
RESPONSE: The discussion in the BID on surface condensers is intended
to provide general description of the product recovery techniques that can be
used to reduce and recover VOC emissions from distillation facilities.
Dehumidification equipment is included in the description of surface con-
densers because water must be removed from many product streams from
distillation operations. However, EPA recognizes that some vent streams
contain no water vapor and this is reflected in the data used to analyze the
standards. Furthermore, neglecting to indicate that some surface condensers
do not use dehumidification equipment does not affect the applicability of
the proposed standards to the production of the listed chemicals. Therefore,
no further discussion of surface condensers is planned for the BID.
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2.11.5 COMMENT: One commenter (D-12) stated that the potentially
detrimental impacts from energy demand as a result of the standards may
offset the benefit to air quality noted in Table 1-1 of the BID. The
numerical values given in Table 1-1 indicate that energy demand is expected
to have minimal impacts. However, the discussion of this table in the text
indicates that energy impacts could be significantly detrimental. The
commenter suggested that because the BID text discusses possible negative
energy impacts, Table 1-1 should quantify an energy impact that could be
significantly detrimental.
RESPONSE: The numerical values given in Table 1-1 do not contradict the
discussion of the table given in the text. The text does not indicate that
the energy impacts are very detrimental. It indicates that the impacts are
reasonable even under a worst-case scenario where in the fifth year
1.2 billion MJ/yr (190 thousand barrels of oil equivalent) would be used for
a flare preference on vent streams with no halogenated compounds.
Furthermore, EPA believes that the energy impacts will be substantially less
than the worst-case scenario. The impacts from this worst-case scenario
would be lessened because of heat recovery with combusting vent streams in
boilers and process heaters, and the upgrading of product recovery equipment
to raise the TRE value above the cutoff.
2.11.6 COMMENT: Two commenters (D-9 and D-14) stated that the
conversion constant "K" in Section 60.664(c)(4) should be 1.740 x 10"7
instead of 1.740 x 10 as it is presently written.
RESPONSE: Section 60.664(c)(4) will be amended to read "K » constant,
1.740 x 10" ..." instead of 1.740 x 107. A typographical error had been
made.
2.11.7 COMMENT: Seven commenters (D-8, D-9, D-ll, D-14, D-22, D-27,
and D-33) indicated that there is an error in the first column of Table 1 in
Section 60.664(c)(6). Four of the commenters (D-9, D-ll, D-22, and D-27)
recommended that the second line of Table 1 contain a "greater than" symbol.
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2.11.8 COMMENT; One commenter (D-9) recommended that the coefficient
on the second line under heading "f" of Table 1 [Section 60.664(c)(6)] should
be -0.0036. The coefficient is now given as 0.0036.
RESPONSE: The commenters in 2.11.7 and 2.11.8 correctly identified
errors in Table 1 of Section 60.664 in the proposed regulation. Because the
coefficients and tables have been completely revised, the specifics of the
comments are no longer relevant. However, the errors cited have been
corrected and the corrections are incorporated into the final regulation.
2.11.9 COMMENT: Two commenters (D-ll and D-12) suggested that the word
"steam" in Section 60.665(k)(2) should be changed to "stream."
RESPONSE: Section 60.665(k)(2) will be amended such that the word
"steam" will be replaced by "stream."
2.11.10 COMMENT: One commenter (D-27) indicated that Section 60.663
(c)(3) should be moved to Section 60.665.
RESPONSE; Section 60.663(c)(3) is needed in order to indicate that no
monitoring is required for a boiler or process heater when the design heat
input is 44 MW (150 million Btu/hr) or greater. Records indicating periods
of operation are required in lieu of monitoring. The same requirement is
also given under Section 60.665(e).
2.11.11 COMMENT: One commenter (D-9) suggested that the "note" at the
end of Section 60.660 should be placed at the end of Section 60.662.
RESPONSE; The "note" at the end of Section 60.660 is in an appropriate
position because it indicates that numerical emission limits are expressed in
terms of TOC's, less methane and ethane. This information is useful when
reading the definitions in the next section. Three of the 13 definitions
refer to TOC's.
2-97
-------
APPENDIX A: FEDERAL REGISTER NOTICES OF ORGANIC
COMPOUNDS DETERMINED TO HAVE NEGLIGIBLE
PHOTOCHEMICAL REACTIVITY
INTRODUCTION
As indicated by the Federal Register notices included in this
appendix, the following chemicals have been determined to be negligibly
Photochemically reactive compounds: methane; ethane; 1,1,1-trichloro-
ethane; methylene chloride, trichlorofluoromethane; dichlorodifluoro-
methane; chlorodifluorotnethane; trifluoromethane;
trichlorotrifluoroethane-; dichlorotetrafluoroethane; and
chloropentafluoroethane.
A-l
-------
35314
ENVIRONMENTAL PROTECTION
AGENCY
ina. 739-8]
MR QUALITY
NOTICES
PUWOSB
of this notice Is to rec-
. This
be approvable. However.
be followed by EPA whenever it
aulred to draft State
Flans for the control- of
re-
•tuiamea wu» lormuUte la an _
proved rule for national UM.
SUMMARY
Analysis of available data and tof or- .
nation show that very few volatile or-.
Sanic compounds are of «<£low photo-
chemical reactivity that they can be-.
Snored in oxldant control programs.
For this reason. EPA's recommended
policy reiterates the need for positive
reduction techniques (such as the reduc-
tion of volatile organic compounds in
surface coatings, process. changes, and
the use of control equipment) rather
than the substitution of compounds «f •
low (slow) reactivity to the place of
more highly (fast) reactive compounds.
There are three reasons for this. First
nn.ny of the VOC that previously have
been* designated as having low reactnW
.are.now known to be moderately or
reactive to urban atmospheres.
Preon 114. and Preon 115. which are cur.
rentiy used ae aerosol propellants. The
Agency la planning to Investigate control
systeiiu and substitutes for nonpropei-
• lent •uses nn^1* TSCA. as announced m
May 13. Methyl chloroform is not a fully
naSognnated chloronuoroalkane. Rather,
it is among the chlorine-containing com-
Dountls for which, the Agency has not
completed its analysis: EPA has not ret
ccncliided whether it is or is not a threat
to th« stratospheric ozone. Therefore, it
has been placed on this list as an accept-
able exempt compound. As new informa-
tion becomes available on these com-
jwuniis. EPA will reconsider the recom-
mendation. —•
•The -volatile organic compounds listed
to Table 2. while more photochemicaUy
reactive than, those to Table 1. never-
theless do not contribute large quantities
of ozidant under many atmospheric con-
Photochemical oxidants result from,
sunlight acting on volatile o**»n]*eom-
pounds (VOC) and oxides of nttrogen.
^^VOC. by then-nature, start to form
•~* after only a short period of ff-
bidfr to ttM* atmosphere. Other VOC
"undergo irradiation for a longer
period before they yield-measurable
. toits guidance.to State. le*ttuprep-.
•ration, adoption, and submittal of State
implementation planspuWtohed toan.
the Environmental Protection Agency
—Tph..*^ reduction of total organic
compound emissions, rather than^nb-
BJ However, to ..
that substitution of one «~—
another might *e-useful wbw«^^
—suit to a clearly evident decrease in
teacttvity and thus tend to reduce photo-
chemical oxldant formation. Subse-
mently Tp«nT State. Implementation
Plans were promulgated with *>»«£
substitution provisions similar to Rule
88 of the Los Angeles County Air Pollu-
tion Control ""' """•" *""*' * ""*
Speared in the PES«AL RxoOTa on
££ruary5.197«<41FR5330).
The 1978 policy statement ««*fd»°
that the reactivity concept was useful
.Tan interim measure only, and would
Sotbe considered a reduction to organic
emissions for purposes of estimating at-
tainment of the ambient air quality
rtandard for oxidants. The document
also included the following statement:
Although the lubttltutton Po
M and rtfflllir rules represent
ttw«* regulations eta
veloped. one* on current knowledge of re-
nigf"Y mcww 4** *•*•!" • ^ _ _
Second, even compounds.that are pres-
ently known to Have low reacttvttj can
form appreciable amounts of oxldant-
under multiday stagnation cortrtlttnna
such as occur during summer to many
areas. Third, some compounds of low
or negligible reactivity may have other
deleterious effects.
Of the small number of VOC which
'have only negligible photochemical re-11
activity, several. (benzene. *cetonilzile.-
chlomform. carbon tetrachtorlde.ethyl-
ene dichlortde. ethylene dibromide, and.
methylene chloride) have been identlfled,
or implicated as being carcinogenic, mu-
tagenic. or teratogenlc. An additional
compound, benzaldehyde. while produc-
togno appreciable ozone. nevertheUas.
forms a strong eye irritant under irradia-
tion. In view of these circumstances, it
would be inappropriate for EPA to en-
courage or support increased utilization
. of these compounds. Therefore, they are
not recommended for exclusion from
control. Only the four compounds listed
to Table 1 are recommended for exclu-
sion from SIP regulations and. therefore.
It is not necessary that they be inven-
toried or controlled, to determintoii; re-
ductions required to meet oxidant.
NAAQS. these VOC should not be In-
cluded to the base line nor should reduc-
Uonsto their emission be credited toward
achievement of the NAAQS.
• rt 1* —~™««d that the two halo-
-enated^oWMnds listed to Table 1
(methyl chloroform and Preon 113J may
cauMdeterioration of the earth's ultra-
violet radiation shield since they are
neSy-unreactlve to the lower atmos-
phere and all contsJn appreciable frac-
tions of chlorine. The Agency has
reached conclusions on the effects of only
Selully halogenated chloronuoroal-
kanes. The Agency on May 13.1977 (42
FR 24542) proposed rules under the
Toxic Substances Control Act (TSCA) to
prohibit the nonessential use of fully
halogenated chlorofluoroallcanes as aero-
sol propellants. The restrictions were ap-
plied to all members of this class In-
cluding Freon 113. since they are poten-
tial substitutes for Freon 11.. Freon 12.
U—VolatU* Orjante. Compound! of
KKritafUf motaehcnrical Beactttity That
ShESuB* Zttmp* from Regulation
rt&tttt ImpUiwntatton Plan*
vSSwchKroethene (Methyl Chloroform*'
PJ^IT-J tfBjBMMAflMAf^Kfftfch^AA (FrooQ 113)
h»v«
tueretore.
jtareoootzoU.
r Xr-ralotUt Organic Compo-.-«Jj
Low Motocntmic* Reactivity
Acdone •
Methyl Ethyl Ketone
Uethenol '••
bopropiaot
Uethyl Pencn«te
TtnttaryAlkyl Alcohols
UrtbylAoet*** •-
phenyl Aceteta .
Ethyl Amtoe* '" -
•
V. IT-dlmethyl fornumide
Only during multiday stagnations do,
Table 2 VOC yield significant oxidamt;
Tfaerefore. if resources are limited or U.
the sources are located to areas where;
prolonged atmospheric stagnations are
-uncommon, priority should be given to
controlling more reactive VOC first ana
Table 2 organies later. Table 2 VOC art-
to be included to base line emission In-
ventories and reductions to them wul B«-
credlted toward achievement of tae.
NAAQS. Reasonably available control
technology should be applied to signin-
eaiatsourees of Table 2 VOC where neca-
sary toattoto the NAAQS for oxidants.
SZ s^ceTof these compounds wlU a^
be subject to new source renew require^
"'p^hloroethylene. the principal soU
ventmployed to the dry cleaning todus-
toy UaJso of low reactivity. comparaW
to VOC listed to Table 2. It was not Itt-
SBdeTtoTable 2 because of reported adj
tenslvely by occupational healthi aumor _
«:hylene currently are being^tudiefl'.^
vistigations may have major impact o»
IMinn. VOl. «». NO. ,31_«IOAt. JULY •.
A-2
-------
industrial users. In designing control reg-
oUtions for perchloroethylene sources.
oartlculariy dry cleaners, consideration
should be gtven to these findings as well
as industry requirements and the cost of
applying controls. Available control tech-
nology is highly cost effective forjarge
Derehloroethylene dry clfimmg opera-
tions. However, for corn-operated and
irnT«n dry cleaners, the same equipment
would represent a heavy -economic
burden.
As part of Its continuing program. EPA.
will review new information relative to
the photochemical reactivity, toxlcity, or
effects on stratospheric ozone of volatile
organic compounds. Where appropriate;
additions or deletions will be made to the
lists of VOC la Tabels 1 and 2. .
Dsccssmf
Most air pollution control regulations
applicable to stationary sources of VOC
to the United States are patterned after
Rule 06 of the tow Angeles county Air
pollution control District (presently
Begutetton 443 of the> Southern Califor-
nia Air PoUutton Control Ettstrictt. Bole
66 and similar regulations Incorporate
two basic strategies to reduce ambient
oxidant levels, f-e, positive VOC reduc-
tion and selective solvent substitution
based on pboteehendeal reectWtr. Posi-
ttvet reduction, schemes such as Incinera-
tion, absorption, and the'use of low-sol-
vent coatings are acknowledged means of
reducing ambient oxidant levels; they
should be retained m future VOC control
programs, m contrast, the utility of sol-
vent substitution strategies has been
questioned as more information on pho-
to chemical reactivity has emerged.
EPA acknowledged the shortcomings
of solvent substitution based on Rule 66
reactivity criteria hi a 1976 policy state-
ment (41 FR 5350). Findings were cited
which indicated that almost an VOC
eventually react in the atmosphere to
form some oxidant. Concurrently..EPA
initiated an Investigation to consider Im-
plications of revising the solvent eubsti-
tuton aspects of Rule 86. Three separate
forms were conducted with representa-
tives of State end local ah- pollution
cnntiul egencies. university professors.
end Industrial representatives with
knowledge and expertise in-the fields of
Atmospheric chemistry and industrial
polvent applications. In addition, nu-
merous discussions were held with ac-
knowledged experts in the field. Topics
of particular concern were:
Bui* 06 substitution criteria
eould be renied consistent with available
*»acttTlty data am yet be compatible with
industrial processes and wltn product re-
quirements.
Whether eome compounds an of suffi-
ciently low reactinty that ther-are not oxl-
«ant preeunors and can be exempted from
control under State Implementation Plane.
Whether the Imposition of reactmty re-
e&lctlons In addition to positive emission
reductons will delay the development or
implementation o* promising technologies,
particularly «he use at water-borne end
high-solids eurfaos
NOTICES
investigation showed that:
1. Solvent substmtion based on Role
66 ha* been dlrecUonally correct in the
aggregate and probably effects some re-
ductions in peak oxidant levels. How-
ever. because of the relatively high re-
activity of most of the substituted sol-
vents. the reduction is small compared to
that which can be accomplished with
positive reduction techniques. Revision
of Rule 66 consistent with current knowl-
edge of. reactivity would eliminate the
•solvent substitution option, for most
sources la which substitution is new em-
ployed. Many of the organic solvents
which ham been categorized as having.
low photochemical reactivity are, la fact.
tmyforfttoiy or I^f^y reactive; they yield
^ynm/.ant oxidant when, subjected to
I
nlm"!?** **"? urban, atmosphere.
2. A few VOC yield only negligible
Ha«^ •««< ethane* e> yfM*tp
be so-classified. Tf"**
. react Terr alowly yielding
little ozone- during, .the first few days.
followinc fe*1**^ release to *F»* alny?fp**£T^i
Available data, suggest that none of the.
etitZniflCeVLLv -
oxidanteven during extended Irradiation
under multiday stagnation conditions. ' '
The broad group "halogenated paraf-
fins" includes important Industrial
solvents, most of which are chlorinated
methanes and ethanes and ehlorofiuoro-
ethanes. They *"* use as metal cleaning
and dry cleaning solvents and as paint
removers. Halogenated paraffins also
serve as building blocks in the manufac-
ture of other halogenated organlcs:
these processes do not necessarily release
significant VOC to the atmosphere.
*3. Besides focusing on VOC of
negligible reactivity, smog chamber
studies show that a few additional VOC
generate oxidant at a relatively stow rate.
Under favorable atmospheric conditions."
these VOC releases may not form oxidant
until they have been transported sub-
stantial distances and become-greatly
diluted. However, under multiday stag- -
nation conditions such as occur during •
summer in "^"y areas of the mf*1*^<> and
' eastern United States, there is the •
potential for these organlcs to undergo
appreciable conversion to oxidant. The
more important VOC In this category are
acetone, methyl ethyl ketone. parebloro-
ethylene. methanol, Isopropanol. and
propane. All except propane are indus-
trial solvents. The latter, a gas under.
normal conditions;4 Is associated prin-
cipally with crude oil and liquefied
petroleum gas- operations.
' 4. The vast number of volatile organic
compounds—particularly nonbalogenat-
ed VQC—yield appreciable ozone when
irradiated in the presence of oxides of
nitrogen. While there are measurable
variations in then* rates of ozone f orma-
«**" VOC listed in Table X Quickly re-
active VOC include almost all aliphatic
35315
and aromatic solvents, alcohols, ke-
tones. glycols. and ethers.
5. Low photochemical reactivity is not
synonymous with tow biological activity.
Some of the negligible or slowly reactive
compounds have adverse effects on hu-
man health. Benzene, acetonltrile. car-
bon tetrachloride. chloroform, perchlo-
roetbxlene, ethylene dlchloride. ethylene
dlbromlde. and methylene chloride have
been Implicated as being carcinogens.
teratogens, or mutagens. In. addition.
benzaldehyde. which produces no ap-
preciable ozone, nevertheless forms a
strong eye irritant under Irradiation
While their use might reduce ambient
oxidant levels. It would be unwise to en-
courage their uncontrolled release. Ad-
ditional halogenated organlcs are being
UTvestigatedfor possible toxlcity. " .
Most of the related health inform*-'
Hnn iTtillaMm*1'thu time concerns acute
toxlcity. Threshold limit values (TLVs)
have been developed for many VOC.
They are appropriate- for the healthy.
adult work force nrrmtnt eight hour* *
day. five day* a, week. Experts suggest.
that more, stringent levels-should be
^flMuh^t foe the general population.
Hazards-represented by cfarnnVT. aM sub-.
chronie rumm^ are rmv* more diffi-
cult to- quantify than acute toxlcity. Ad-
verse health effect* of the VOC cited
above are g»q»~iiy- recognized although
not completely quantified. Chlorinated
solvents currently are under intensive
study. - '-, •
6. Some VOC are of such low photo-.
chemical reactivity that they persist in
the atmosphere for several years, even-
tually migrating to the stratosphere
where they are suspected of reacting and
destroying ozone. Since stratospheric
ozone Is.the principal absorber of ultra-
violet (UV) light, the depletion could
teed to an Increase in UV penetration
with a resultant worldwide increase in
skin cancer. The only in-depth analysis
of this potential problem has focused on
the chlorofluoromethanes (CFM). Freon
11 and Freon 12. because of their known
stability and widespread use in aerosol
containers. A report of the National
Academy of Sciences concerning envi-
ronmental effects of CFM's concluded
jShat: - .--.- - - " -.
"•«'• • seletclve regulation of CFM uses
and releases Is almost certain to be necessary
at some time and to some extent of com-"
ptotenees. ' • . : ^ -'
In response-to the report of the National
Acadcr^y of Sciences *^rf other studies.
. EPA on May 13.1977 (42 FR 24542). pro-
posed rules to prohibit nonessential use-
age of fully halogenated chtorofluoroal-
kanes as areosol propellents. The re-
strictions, were applied to all members
of this class including Freon 113 since
they are potential substitutes for Freon
11. Freon 12. Freon 114. and Freon 115
which are currently used. as aerosol
propellents.
Other stable halogenated solvents
which are released In volumes compare- <
ble to the cnlorofluoroalkanes also are
suspected of depleting tba earth's UV
shield. Of major concern is the wide-
KOUAL U6ISTEI. VOL 42. NO. 131—EIIOAT, JULY (. 1977
A-J
-------
35316
spread substitution of methyl chloroform
(U.1 trlchloroethane) for the photo-
rhemtcallr reactive degreasing solvent
trlchloroethylene. Such substitution un-
der Rale 66 generation regulations has
already influenced industrial decreasing
operations to the extent that methyl
chloroform production has surpassed
that of tnchloroethylene in the United
States. Any regulation in the area .will
have a marked effect on the production
and atmospheric «••«•«<«««« of both sol-
vents. Endorsing methyl chloroform sub-
stitution would increase emissions, par-
ticularly in industrial States that have-
not, heretofore. Implemented Bole 66. On
the other hand, disallowing methyl chlo-
roform as a substitute or h"w««g it alto-;
gather would significantly increase emis-'
slons of trlcnloroethylene even if de-
greasers were controlled to the limits of
available'technology. Presently; tech-
•nology is only able to reduce emissions by
approximately 50 percent. Itt metropoli-
tan areas which have already 'imple-
mented Rule 66. a return to trlchloro-
ethylene would have an advene effect
-on «»»)M»nt oxidant levels. In addition to
•being highly reactive, trlchloroethylene
rhas been implicated as a carcinogen.
_ -Alternatives to the above-cited choices
-would be (1)-development and appuea-
.tion of highly efficient degreaser control
systems and (2) •replacement with an
NOTICES
intermediate sol vent which Is neither re-
active nor detrimental to the upper at-'
mosphere. Major revisions would be
needed to degreaser designs to improve
vapor capture above the current best
level. Antlripatfri design changes could
add materially to degreaser costs. No. al-
ternative solvent is clearly acceptable •
from the standpoints of photochemical
oxidant Brnl stratospheric prone deple-
tion. Neither metbylene chloride nor
trtchlorotrifluoroethane are reactive, but.
like methyl chloroform, are suspected of*
causing damage to *•-*** stratospheric
flypflft layer. In ftdditlff", methyleno chlo-
ride -is- a' suspect mutagen. Perchloro-
ethylene. the principal dry. cleaning sol-
Tent, does "not present a hazard to the
•stratosphere but has been Implicated as.
being a«arcinogen and also reacts slowly
In the- atmosphere to form oxidant.
.- 7.-Organic-solvents of low or negligible
photochemical.' reactivity- have only
limited use in many Industries. Most are
chlorinated- organlcs that find principal
applications as cleaners for metals and
fabrics. Atew nonhalogenated VOC such
as acetone, methyl ethyl ketone. and
isopropanol are of low reactivity but
these, can't possibly satisfy all the myriad
needs of the paint, plastics; pharmaceu-
tical, or many other-industries.. While
users of reactive VOC usually can employ
effective control equipment to recover or
destroy VOC •»««"*""•, they seldom have
the option of applying reactivity con-
siderations in choosing solvents. Applying
reactivity restrictions to the surface coat-
ing industry would be especially disad-
vantageous since It would greatly inhibit
the development of low-solvent coatings;
essentially all of the organic solvents
used to constitute high-solids coatings
and waters-borne coatings are. in fact..
highly reactive.
8. It Is recognized that smog chamber'
studies conducted to date are incomplete
because* many organic compounds have
not been examined and It has been un- -!
posslbltt to duplicate all atmospheric sit-'.
nations. For example., there has been ,
only limited fTftmlnp+l"" of oxidant for- .:
mation under relatively high ratios of:
VOC to NO, (30:1 and greater) . compar-
able to rural conditions. Any policy on
.photochemical reactivity necessarily has
to be open to revision as new Information
is developed which may show specific
organic: compounds to be more or less,
photoeliemlcally. reactive than indicated
by current data.! ..... ' * -
June 29. 1077.
. ..• . EDWUD F. Tens.
' Acting .Assistant AdmtiHttrator
•J.f?z10*4i' and Watte Management.
^IFBf Doe.TT-lBSSS FIM 7-7-77:8:45 am|
ttGISTEt, V01. 41, NO. 131—HMOAY, JUIY ». 1977
A-4
-------
Federal Register / VoL 44. No. 108 / Monday. June 4. 1979 / Notices
Review under 42 U.S.C ! 719(b) (1977
Stiff.] from en order of the Secretary of
Energy.
Copies of the petition for review have
been served on the Secretary. y
Department of Energy, and all
participants in prior proceedings before
the Secretary.
Any person desiring to be heard with
reference to such filing should on or
before June 12, 1979. file a petition to
•intervene with the Federal Energy
Regulatory Commission. 825 North
Capitol Street Ni. Washington. D.C
20429. in accordance with the
Commission's rules of practice and
procedure (18 CFR 1.8). Any person
wishing to become a party or to
participate as a party must file a petition
to intervene. Such petition must also be
served on the parties of record in this
proceeding and the Secretary of Energy
through Gaynell C Methvia, Deputy
General Counsel for Enforcement and
Litigation. Department of Energy. 12th
and Pennsylvania Ave, N.W,
Washington, D.C. 20481. Copies' of the
petition for review are on file with the
Commission and are available for public
inspection at Room 1000, 825 North
Capitol SU RE, Washington. D.C
20428.
KnaMhF.Ptas*.
(Ft OH.
[Docket No. RI79-M1
Triton OH * Gas Conn; Petition for
Declaratory Order
and 598-A or show cause why such
refunds were not due. Triton's position
is that because sales under these rate
schedules were authorized by
permanent certificates of public
convenience and necessity which
contained no refund conditions.'there is
no refund obligation. Triton
acknowledges that the Commission may
order refunds and reductions in rates
after August 1.1971—the effective date
of Opinion No. 598. However, it asserts
that the Commission is without
authority to order such adjustments
- prior to the effective date where rates
were not collected subject to a
suspension order or under a temporary .
certificate.
, Any person desiring to be heard or to
make any protest with reference to said
petition should file a petition to
intervene or a protest with the Federal
Energy Regulatory Commission, 825
North Capitol Street N.E, Washington.
D.C 20428. in accordance with
requirements of the Commission's rules
of practice and procedure (18 CFJL U
or 1.10). All such petitions or protests
should be filed on or before June-20.
1979. AH protests filed with the
Commission will be considered by it in
determining'the appropriate action to be
taken but will not serve to make the
protestants parties to the proceeding.
•- Any person wishing to become a party
to a proceeding, or to participate as a
party in any hearing therein, must file a
petition to intervene in accordance with
ttui Commission's rules.
KeanetaKPhnnb.
Take notice that on April 5, 1979.
Triton-Oil and Gas Corporation (Triton).
One Energy Square. 4925 Greenville
Avenue. Dallas. Texas 75208 filed in
Docket No. RITB-M a petition for
declaratory order pursuant to Section U
of the* CommissioB/s Rules -OK Practica*
and ProcedurevTriton requests-a
obtigatioa- under Southern Looisiana
Area Rat* Opimon No. 59» for rates it
cofieeted for certain sales of gas. Ths
gas is produced from four fields in th*
i Area-siid sold tar
Gas Pipeline Company,
CM Transmission Company and
npany under.
Southern Natural Gas Co
Triton's Rat* Schedules land 8.6. and 7
respectively.
On June 6.1978, the Comntission
directed Triton, among other producers.
to disburse refunds for the period from
October 1988 to January 1971 pursuant
to the Commission's Opinion Nos. 598
[Docket Net. IW7B-M1
UnttsdGas Pte« Un« Co; informs*
Takejwoce that on jtm*7,197arat~
f*yy p nil aii.faifti-Hff'fli conference *yf»it
Interested persons* will be convened tot
the* purpose of cootnmed settlement.
discussions fat -^iw proceeding. The*
conference- will be held in Room 3300 of
the Federal Energy Regulatory
Commission at 941 North Capitol Street.
-KE-. Washington. D-C 20428.
Customers and other interested
persons will be permitted to attend, but
if such persons have not previously been
permitted to intervene by order of the
Commission, attendance will not be
deemed to authorize intervention as a
party in mis proceeding.
All parties will be expected to come
fully prepared to discuss the merits of
the issues arising in this proceeding and
to make commitments with respect to
such issues and any offers of settlement
or stipulation discussed at the
conference.
Lois D. CubcO.
Acting Stcntarr-
soon and
Office of Energy Co
Solar Applications
*
Meeting Regarding Emergency
Building Temperature) Restrictions
Program
Notice is hereby given that the
Department of Energy (DOE) will hold a
meeting with the National Governors'
Association on Friday. June 8.1979. at It
ajn. in Room 285.444 North Capitol
Street Washington, D.C
- The purpose of the meeting will be to
discuss the rote of the States in
implementing the Emergency Building
Temperature Restrictions Program. This
program is authorized by-the President's
"Standby Conservation Plan No. 2:
Emergency Building Temperature
Restrictions." which recently was
approved by the Congress.
Issued la Wssttngton. D.C on May n.
1879.
MaxmeSevmc, .
Deputy AMOtantSfCTttarf. Cotatrratioa
andSoiarAppiicatiam.
(fin
ENVIRONMENTAL PROTECTION
AGENCY
[FRI.12JS-41
i of Agency
PoOcyConcsjrningOzone-SlP
ACT*
LIS nnniisnm n******
the anthoritrof section lOl(b) and
section 103 of the Clean Air Act The
notice darlffas EPA's "Recommended
Policy on Control of Volatile Organic
Compounds." 42 FR 35314 duly 8,1977).
STATZMCNT: The July 1977 Policy
'Statement noted that only reactive
volatile organic compounds participate
in the chemical reactions that form
photochemical oxidants. Currently
• available information suggests that
negligibly pbotochemically reactive
volatile organic compounds as defined
in that Statement including methyl
A-5
-------
32043
Federal Register
====== \. -j A* these compounds under the Clean Air
a ——
Cementation plan or plan
MJJMO DAT! «M»«1-II
^~~-
27711(919)541-5204.
ha controlled under state ,
SptaStation plan, for *•££• •«
sss«S=aSr- --
\gn and March 8. 1979. there*
stive evidence that .both
are
SnmiW.eonBTforc«n«it;Ooen
Meotina
issuer. Eavironmental Protection
Agency CEPA). Office of Pesticide
programs.
.-^.i. Notice of Open Meeting.
^MMA^TTie«willb«atwo-day
. .,
•w«wi«~j RCi9earch and Evaluation Group
irinkina Water Act w w Atlanta. Georgia. Teiepnone.««/
^JonS- S^oaandwulbeopentothepubha
. Of the Environmental FURTMBI INMUMATION CONTACT:
Kfr William BuSaloe. North CaroUna
Department of Agriculture. Rale.'^;
NorthCarolina. Telephone: 919/733-
ULu«niu»fc- 3556: or Mr. Anthony Dellavecchia,
Cumberland and Cape I»esticida and Toxic Substances
"- J Enforcement Division. EPA. 401M
Street S.W, Washington. D.C,
telephone: 202/755-0914.
wftunmnuet WWOHMATKJN: This the
Mcond meeting of the Working
Conumtt«oBEnfo«m«t^.meeting
sfe^S5;j-=:s: .»====••=*•
1. Plan for future recall and
nogrim.aainiarfJ7.w^^^^ arfWimsdstopiwrtdemei
Contej^j^^^0^^ ^«»^thecmnn.ent^
imments. data and
jW
both methyl chloroform and
duorfd. «« P
.. uo .
hamfaL BPA recommenda ttat tnea«
etenicala not be snbstftuted for other
aohvot* in efforts to reduce otone
ooneentrationa, EPA further
Meammends that the states control
th,,. compounds underthe authority
re^rred to-them in section 118 of &•
Clean Air Act Moreover, there is a
stiong possibility for future regulation of
o . .Y. 10007,
Attention: Coastal Plain Aquifer.
Information concerning &e Coastal
Plain Aquifer System will be available
for inspection at the above address.
A-6
Section 28 and 27 of HFRA:
3. Status of State-primacy use
enforcement notice
.ijjea of raconanendations «*
aaricnltaral extension publications by
•pesticide sales representatives;
5. Discussion of definition of "non
cropland:'* '
8. FFRA Section 7—producers of
active ingredients: and
7. Other enforcement matters wmch
may arise.
Dated! May 25.1979.
EdwinMohn»oa, . .
Want Administrator for Pestiad
ire Doe. rvtra* raw ••*->««• «-l
Mima coo« «•*«>«•
-------
'--•
T-——*•««*, sr"*"1**'1^^
'F**SttS&1SSZ* *i*.»*1****'»**»
SScttt^Sraarm *^» «££
SSfeasn-tt.* Mgr
•ssffls^^ tsssssr
^I?mSSP^.t^Sir ^^^r
drfnMra ofa"sen«ittve are*. The
«l.M.ofanyp~ticid.spr.y..not ^ ^^ ^ AcTTh. no'tic.
permitted over a sensitive;area or m ™ fj"^"..-^ clarification of a policy
=saiS.vsS& "^" fe^^Tfssrti-.
only spray drift fallout from th. g2£da?"«ra 3S314 (July 8.1977)
—'—«-« «»•«- "jSnTriScation of Agency Policy
EPA approval. If a state chooses to
controKssions of these compounds.
TOchmeaswes will be considered as
aiate regulations only and not as part of
en ozone SIP. EPA will not enforce
Sn^ok on emissions of eiUier methyl
chloroform or methylene chloride
adopted by the state as part of an
implementation plan for ozone.
States retain authority to control
emissions of these compounds under the
authority reserved to them under
Section 118 of the Dean Air Act For
further information relevant to the
exercise of this authority see the July 8.
^and June 4.1979 policy statements.
This policy notice should not be read as
a statement of EPA's views on the
desirability of controls on these
nihstances. . .
jSKSssssra-
be buffered against direct application.
Hnwcver many of these dwellings are
ne« aquatic sites listed in Table H
which will be buffered.
To minimize operational errors.
overflights of the treatment area pnor to
the actual spray operation are
encouraged. The purpose of these
overflights is to locate visually all
sensitive areas and bufferzones
designated on the spray block auP*-
Particular attention should be given to
identifying ephemeral streams and
oonds visible from an aircraft flying at
an altitude of UOO feet or less above me
t.rrain at the time of treatment, which
maynot be designated on the spray
block map due to their seasonably.
Authority
This Advisory Opinion governing the
use of certain insecticides for the
.uppression of the spruce budworm in
Maine through July. 1980. is issued
pursuant to the authority granted to the
Administrator by Section 2^et'^Lgv
4.1979).
us policy
"FteffiBPA wishes to point outthat
this policy notice addresses only the
ATeicVslack of authority to include in
fcderaUy approved SIPs controls on
.ubSes whose emissions do not
contribute, either directly or indirectly.
£ «ncentrations of po^'ants for which
NAAQS have been established under
..ction 109 of the Act This poUcy notice
does not address the question of SIP
measures which control substances
reactive and do not appreciably
!X>ute to the formation of ozone.
Consequently, controls on emissions ol
these two compound would not
contribute to the attainmen and
maintenance of the national ambient.air
quality standards for ozone. In the June
1979 policy statement EPA explained
mat it would not disapprove any state
toplementation plan ISIP) or plan
^vision for its failure to contain
regulations restricting emissions of
^Sfchlorofonn and/or methylene
bVmore strict than absolutelynecessary
ittain and maintain the NAAQS. EPA
. „„ authority to exclude such
«--
See) defines this terminology"
prohibiting the use of registered
estiddTln a n«»n«-no»Pnm?
pes ,
{he labeling." However. »^°° *">
.1,0 provides that mis prohibition does
not apply with respect to "any use of a
pesticide In a manner that the
Administrator determines to be
•^Scft's statement clarifies EPA
oolicv reaarding state implementation
SttlnKtals which do contain
mulations restricting emissions of the
KSSrnd^ StetoilOMei) of th«
dean Air Act limits state
Implementation plans to measures
designed to achieve and maintain the
Mttonal «nbient air quality ^^Q
fNAAQS). Because current information
indicates that emissions of methyl
chloroform and methylene chloride do
not appreciably affect ambient ozone
tavels. EPA cannot approve measures
.oeciflcaily controlling emissions of
- either or both com^unds as partof a
SderaUy enforceable ozone SIP. EPA
to attain ana mamwu» u« ^ - -
has no authority to exclude such
measures from SIPs.
ran rowTHW INFOHMATIOM CONTACT
G T Helms. Chief. Control Programs
G^eration, Branch (MD-15). Research
Triwgle Park. North Carolina 27711.
S£)541-S228. FTS 829-5226. -
Dated: May 9.1980.
David G. Hawkins.
AssittantAdmifiituatorforAir. NO>M a"d
Radiation.
-
cooe •*»+*-*
deraUy enforceable ozone .
wUl take no action on any measures
•necifically controlling emissions of the
S^mpounds which are submitted by
the states as ozone SIP measures for
im. 14S1-7; W 601807/12391
Extension oi a Temporary Tolerance
AGENCY: Environmental Protection
Agency (EPA).
ACTION; Notice.
SUMMARY: EPA has extended the
temporary tolerance for residues of the
herbicide thidiazuron (JV-phenyl-N -1O.3-
thiadiazoM-ylurea) and its aniline-
containing metabolites in or on the raw
agricultural commodities cottonseed at
O2 part per million (ppm). milk O.OS ppm.
eggs 0.1 ppm. meat fat and meat
byproducts of cattle, goats, hogs, horses.
poultry, and sheep at OJ ppm.
-------
Federal Register / Vol. 45. No. 142 / Tuesday. July 22. 1980 / Notices
48941
Dempasco Service Sta. U.S. 1 and Hwy A1A.
Juno Beach. FL 33408—S-14-80
Par Mobil 324 Par Avenue. Orlando. FL
32804—3-18-80
John Gibson. 1-65 and KY 90, Cave City. KY
42127—3-18-80
Bellmeade Shell 5315 S. Harding. Nashville,
TN 37205—3-19-80
Corner Store. 1401 No. Main Street.
Kissimmee. FL 32741—3-19-W
Kopper KetUe. Highway 100 & 1-65. Franklin.
KY 42134 « 7-80
Bueehel Terrace Chevron. 4219 Bardstown
Rd, Louisville. KY 40218-4-10-60
UPorte Exxon. 1829 a Federal Hwy,
Hollywood. FL 33020—4-24-40
Risner's Chevron. 3420 Lebanon Road.
Hermitage. TN 37076—5-13-80
Douglas Amoco Service. 583 Donaldson Pike,
NashviUe. TN 37214—9-14-80
Town & River Texaco. 1024 Cypress Lakes
Rd, Ft Meyers. FL 33907—5-14-80
Trail Sunoco. 8168 So. Tamimiami. Ft Meyers,
FL 33907—8-14-80
Villas Chervron. 8180 So. Tamamiami. Ft
Meyers. FL 33907—6-14-80
Port Comfort Box 105, Rt 24. Ft Meyers. FL
33908—5-15-80
Cantrell's Exxon. 1910 Dickerson Rd,
NashvittVTN 37207—5-18-80
Barker Westgate Standard 2510 Pio Nono
Ave. Macon. CA 31206—S-19-80
Seminole Exxon. 1949 W. Tenn, Tallahassee.
FL 32304—5-19-80
Fred Hulse^s Chevron, 5012 Romeiser Road,
Macon. CA 31204—5-20-80
Winston Chevron. 825 Madison Street.
Huntsville. AL 35501—4-22-80
H & A Fuel Service. P.O. Box 449. Hardeville.
SC 29929—*^—23—80
Chancy'i Standard, P.O. Box 1701 St Sunona
Island. GA 31S23—5-28-80
Norman's Standard. 3304 Glynn Avenue,
Brunswick. CA 31520—5-28-80
Plaza Standard. 1965 Glynn Avenue.
Brunswick. GA 31520—5-28-80
Coley's Exxon. Rt 11-85 and SC 290. Duncan.
SC 29334—5-28-80
Bingham's Texaco. Rt 11-85 and SC 290.
Duncan. SC 29334—5-28-80
White's Exxon. Hwy MS and SC-8.
Spartanburg. SC 29303—5-28-80
Mauldin Chevron. 804 N. Main. Mauldin, SC
29662—5-29-80
Wade Hampton Mall Exxon. 1035 Wade
Hampton Blvd. Greenville. SC 29609—5-
29-80
Harris Standard, P.O. Box 405. Nahunta. GA
31553—5-29-80
Pittman's Standard. 1-75 and Juliette Rd,
Forsyth. GA 31029—5-30-80
Trout's Texaco. 108 N A1A Hwy. Satellite
Beach. FL 32937—5-30-80
Magnolia Plantation. P.O. Drawer. Tifton. CA
31794—5-30-80 '
M & M 76.1100 SR 324 Rt 1. Cocoa. FL
32922—5-30-80
Issued in Atlanta. Georgia on the llth day
of July 1980.
James CEatterday.
District Manager.
Concurrence:
Leonard F.Bittner.
Chief Enforcement Counsel.
[FH Doe a>-ZUM Flbd 7-a-Hk Ml «•)
eajJNO COM (4M-OVM
ENVIRONMENTAL PROTECTION
AGENCY
[FHL1545-7]
Air Quality; Clarification of Agency
Policy Concerning Ozorw SIP
Revision* and Solvent Reactivities
AGENCY: Environmental Protection
Agency (EPA).
ACTION; Notice.
BACKGROUND: This notice is published
under the authority of section 101(b) and
section 103 of the Clean Air, Act The
notice provides further clarification of a
policy announced in EPA's
"Recommended Policy on the Control of
Volatile Organic Compounds." 42 FR
35314 (July 8.1977) and "Clarification of
Agency Policy Concerning Ozone SIP
Revisions and Solvent Reactivities." 44
FR 32042 (June 4.1979) and 43 FR 32424
(May 16,1980).
DISCUSSION: The previous policy
statements on the control of volatile
organic compounds (VOCa) noted that
despite concerns about their potential
toxicity 1.1,1-trichloroethane (methyl
chloroform) and methylene chloride are
negligibly photochemically reactive and
do not appreciably contribute to the
formation of ozone. Today's statement
expands the list (45 FR 32424) of organic
compounds (VOCs) of negligible
photochemical reactivity to include the
following chlorofluorocarbons (CFC) or
fluorocarbons (FC):
trichlorofluoromethane (CFC-11):
dichlorodifluoromethane (CFC-12);
chlorodifluoromethane (CFC-22);
trifluoromethane (FC-23);
trichlorotrifluoroethane (CFC-113);
dichlorotetrafluoroethane (CFC-114);
and chloropentafluoroethane (CFC-11S).
EPA has determined that these
halogenated compounds are no more
photochemically reactive than methyl
chloroform and methylene chloride and
do not appreciably contribute to the
formation of ambient ozone.
Consequently, controls on emissions of
these compounds would not contribute
to the attainment and maintenance of
the national ambient air quality
standards for ozone. EPA cannot
approve or enforce controls on these
compounds as part of a Federally
enforceable ozone State Implementation
Plan (SIP). EPA will take no action on
any measures specifically controlling
emissions of these compounds which
are submitted by the States as ozone SIP
measures for EPA approval. (See 45 FR
32424.)
However. EPA would like to reiterate
its continuing concern over the possible
environmental effects from emissions of
these compounds. As such, EPA is not
precluding the possible future regulation
of these compounds.
It should be recognized that the two
halogenated compounds, methyl
chloroform and CFC-113. stated to be of
negligible photochemical reactivity in
the July 8,1977 Federal Register, have
been implicated in the depletion of the
stratospheric ozone layer. This layer is a
region of the upper atmosphere which
shields the earth from harmful
wavelengths of ultraviolet radiation that
increase the risk of skin cancer in
humanii.
In response to this concern, the
Agency promulgated on March 17.1978
(43 FR 11318). rules under the Toxic
Substances Control Act (TSCA) to
prohibit the nonessential use of fully
halogenated chlorofluoroalkanes as
aerosol propellants. Restrictions were
applied to all members of this class,
including CFC-113. since they are
potential substitutes for CFC-11, CFC-
12. CFC-114, and CFC-115, which are
currently used as aerosol propellants.
The Agency i' investigating control
options and restitutes for
nonpropellai; ases.
EPA lias prr-Tosed new source
performance standards under Section
111 for organic solvent cleaners (45 FR
39768, June 11,1980). These proposed
standards would limit emissions of the
reactive volatile organic compounds
trichloroethylene and perchloroethylene
as well as methyl chloroform, methylene
chloride, and trichlorotrifluoroethane
(CFC-113) from new. modified, or
reconstructed organic solvent
degreasers. If these standards are
promulgated, EPA will develop a
guideline document for States to us* in
developing regulations required under
Section lll(d) for existing organic
solvent cleaners that use any of the
designated compounds.
Whether, and to what extent, methyl
chloroform and methylene chloride are
human 'Carcinogens or have other toxic
effects, and to what extent methyl
chloroform. CFC-113. and other CFCs
deplete the ozone layer, are issues of
considerable debate. Detailed health
assessments of methyl chloroform.
methylene chloride, and CFC-113 are
being prepared by EPA's Office of
A-8
-------
--- i===^—
Research and Development These
assessments will be submitted for
external review, including a review by
the Science Advisory Board, prior to
promulgation of the regulations and the
proposal of EPA guidance to States for
developing existing source control
measures. The extent to which the
preliminary findings are affirmed by the
review process may affect the final
rulemaking for new as well as existina
sources. ^
. J?"'!1 the«j8»UB» of environmental
impact are fully resolved. EPA remains
««Ce7!f f*8t " theae «*"*•!• are
exempted from regulation, the
substitution of exempt for nonexemnt
solvents could result in large increases
of emissions of pollutants that may have
adverse health impacts.
The emissions of CFC-22 and FC-23.
also of relatively low photochemical
reactivity, are of continuing concern
with regard to possible environmental
effects. Consequently. EPA is not
precluding the possible future regulation
of these compounds as well
Finally. EPA wishes to point out that
this notice addressee only the Agency's
lack of authority to include in Federally
approved SIPs controls on substance,
whose emissions do not contribute.
either directly or indirectly, to
'"0"8
r-?* Cajifo"»a Air Resources
Board (GARB) notified EPA of two
recent amendments to California's
emission standards and test procedures
for motor vehicles produced by certain
small-volume manufacturers, and
requested a waiver of Federal
preemption for each amendment EPA
will consider these waiver requests
among other issues, at a public hearing
already scheduled for July 24, 1980 at
EPA's San Francisco office, as
** "0tiCe
f — "j ™«» **#ww*
AOORKSSU: EPA will consider the
I?n cr ?q"MtS at a public heari«S held
at U.S. Environmental Protection
NS IT™*- °P«6 (Re8ion ^
^^
that the State standards will be. in the
aggregate, at least as protective of
public health and welfare as applicable
Federal standards. The Administrator
mll?l8ra/lt a waiver unless he finds that-
(1) The determination of the State is
arbitrary and capricious. (2) the State
does not need the State standards to
meet compelling and extraordinary
conditions, or (3) the State standards
and accompanying enforcement
procedures are inconsistent with section
202(a)oftheAct
Pursuant to these provisions, the
Administrator of EPA granted California
waivers of Federal preemption allowing
the State to enforce its exhaust emission
standards for 1979 and subsequent
model year passenger cars ' and for 1979
Ste!E^.^J^*
o Pofcnts r which
NAAQShave been established undeT
Section 109 of the Act This policy notice
does not address the question ofSlP
measures which control substances
contributing to concentrations of
---»- -~. i laucisco. California. Conies
of all materials relevant to the hearing
are available forpublic inspection
dunng normal working hours (8:00 a.m.
to 4:30 p.mj at- U.S. Environmental
Protection Agency. Public Information
Reference Unit Room 2922 (EPA
Library). 401M Street SW,
Washington. D.C. 20460.
FOR FURTHER INFORMATION CONTACT:
Glenn Unterberger, Chief, Waivers
Section. Manufacturers Operations
Division (EN-340), U.S. EnVironmental
u*-«y veice
). • In American Motors Corp. v
lfeDf u0*011 held that "ction
202 b)(l)(B) of the Act entitled American
Motors Corporation (AMQ to two
-additional years of lead time to meet
certain California oxide of nitrogen
(NOJ emission standards for passenger
As a result in a Federal Register
notice issued July 3. 1980. the
Administrator modified his passenser •
*e' diion "^ *
, c are contended to
be more strict than absolutely necessary
to attain and maintain the NAAQS. EPA
has no authority to exclude such
measures from SIPs.
ro*FUHTHra INFORMATION CONTACT!
C. T. Helms. Chief. Control Programs
Operations Branch (MD-is) Research
Triangle Park, North Carol*, ™
(919) 541-5226. FTS 629-5228.
Dated: July 10,1980.
David C. Hawkins,
r- *** «*
IF* Doe. ohitwi RM 7-a^a tu ln|
•HUNG COM «€
ACTION: Notice of public hearing on
— -™» \****i i* *-trt«.i.
SUPPLEMENTARY INFORMATION:
I Background and Discussion
Section 209(a) of the Clean Air Act as
amended. 42 U.S.C. 7543{a) ("Act")
Pro.^!de?in part: "No state or any
political subdivision thereof shaU adopt
or attempt to enforce any standard P
relating to control of emissions from "
new motor vehicles or new moto?
vehicle engines subject to this part* • •
for] require certification, inspection, or
any other approval relating to the
control of emissions* • * as condition
precedent to the initial retail sZtiitag
(if any), or registration of such motor
vehicle.motor vehicle engine, or
equipment"
Section 209(b)(l) of the Act requires
the Administrator, after notice and
opportunity for public hearing, to waive
application of the prohibitions of section
209 to any State which had adopted
standards (other than crankcase
emission standardsj.for the control of
emissions from new motor vehicles or
new motor vehicle engines prior to
March 30.1988. if the State determines
A-9
, fion " re*pect to
and 1981 model year AMC passenger
cars, and announced a public hearing to
reconsHier the earlier LDT/MDV waiver
decisions in light of AMC v. Slum The
notice further provided that EPA wo"ld
consider at the public hearing anv T .w
waiver requests filed by California , or
before July 7. 1980 to cover amended
NO, standards and enforcement
procedures for 1980 and later model
year passenger cars and 1981 and later
year passenger cars and 1981 and later
year model year iDTs and MDVs
manufactured by AMC
In a June 13. 1980 letter to the
Adminisfrator, CARS notified EPA that
it had taken several actions to revise '
t^lifornia s new motor vehicles
m Pre8ram ta resP°n»
v. Blum. GARB requested a
waiver of Federal preemption for the
following items:
s ,3nrfm,enU> t0
standards and test procedures for 1980
-------
-------
APPENDIX B: TRE EQUATION AND COEFFICIENT DEVELOPMENT
FOR THERMAL INCINERATORS AND FLARES
B.I INTRODUCTION
B.2 INCINERATOR TRE INDEX EQUATION
This section presents the method used to develop the incinerator TRE
-dex elation and an exaraple calculation of the incinerator"E lex
B.2.1 Inci
uation Devplnpmont
c nno h t e COS «' "«• -I- y
co^b n,ng the equat.ons for each component of the annuaHzed costs The
ua ;r, °;nr r;alized cost component - sh°- •« ^ ».
bo cos" elT I a"nUal1Zed CaPUa1 C°StS' "W1-"^ «« costs
costs,
• scrubber
"
results in an equation with the following form:
1
ETQC [a
f (Ys)0-]
+ ^^ Q g
0-5 S T
treafOWate of
B-l
-------
TRE = Total resource effectiveness index value.
Q = Vent stream flowrate (scm/min), at a standard temperature of
20 C.
HT = Vent stream net heating value (MJ/scm), where the net enthalpy
per mole of vent stream is based on combustion at 25 C and
760 mm Hg, but the standard temperature for determining the
volume corresponding to one mole is 20 C, as in the definition
of Qs.
ETQC = Hourly emissions of total organic compounds reported in kg/hr
measured at full operating flowrate.
Y = Q for all vent stream categories listed in Table B-l except for
Category E vent streams where Y = (Q )(HT)/3.6.
SSI'
where for a vent stream flowrate (scm/min) at a standard temperature of 20°C
that is less than 14.2 scm/min:
TRE = Total resource effectiveness index value.
Qs = 14.2 scm/min
HT = (FLOW)(HVAL)/14.2
where:
FLOW = Vent stream flowrate (scm/min), at a temperature of 20°C.
HVAL = Vent stream net heating value (MJ/scm), where the net enthalpy
per mole of vent stream is based on combustion at 25 C and
760 mm Hg, but the standard temperature for determining the
volume corresponding to one mole is 20 C, as in the definition
of Qs.
Hourly emissions of total organic compounds reported in Kg/hr
measured at full operating flowrate.
Y = Q for all vent stream categories listed in Table B-l except for
Category E vent streams where Y = (Q_)(HT)/3.6.
S SI'
The coefficients a through f are functions of incinerator design
parameters, such as temperature, residence time, supplemental fuel require-
ments, etc. There are six different design categories of incinerators used
B-2
-------
Vent Stream Flowrate (scm/min)
' '
14-2 < Q < 18.8
18.8 < Qs < 699
699 < Q* < 1400
1400 < Q < 2100
2100 < Q* < 2800
2800 < Qs < 3500
14'2
18.8 <
699
1400
2100
2800
« < 18-8
Q < 699
< Q3 < uoo
< Q < 2100
< q* < 2800
< Qs < 3500
14-2 1 Q, < 1340
1340 < Q5 < 2690
2690
Qs - Vent Stream Flowrate (,c./mtn>
u-2 < Q < 1340
1340 < Q £ 2690
2690 < Q* < 4040
_
DESIGN CATEGORY D.
- Vent Stream Flowrate (scm/min)
19.18370
20.00563
39.87022
59.73481
79.59941
99.46400
0.27580
0.27580
0.29973
0.31467
0.32572
0.33456
0.75762
0.30387
0.30387
0.30387
0.30387
0.30387
-0.13064
-0.13064
-0.13064
-0.13064
-0.13064
-0.13064
18.84466
19.66658
39.19213
58.71768
78.24323
97.76879
0.26742
0.26742
0.29062
0.30511
0.31582
0.32439
0 . 20044
-0.25332
-0.25332
-0.25332
-0.25332
-0.25332
0
0
0
0
0
0
8.54245
16.94386
25.34528
0.10555
0.11470
0.12042
0.09030
0.09030
0.09030
9.25233
18.36363
27.47492
0.06105
0.06635
0.06965
0.31937
0.31937
0.31937
-0.16181
-0.16181
-0.16181
0
0
0
0
0
0
0
0
, 0
0
0
0
0.01025
0.01025
0.01449
0.01775
0.02049
0.02291
0.01025
0.01025
0.01449
0.01775
0.02049
0.02291
DESIGN CATEGORY B.
Qs - Vent Stream Flowrate (scm/min)
-0.17109
-0.17109
-0.17109
0.01025
0.01449
0.01775
0.01025
0.01449
0.01775
14-2 < Q < 1180
1180 < Qs < 2370
2370 < QS < 3550
6.67868
13.21633
19.75398
0.06943
0.07546
0.07922
„
0.02582
0.02582
0.02582
0.01025
0.01449
0.01775
6.67868
13.21633
19.75398
0.00707
0.00707
0.00707
0.02220 0.01025
0.02412 0.01449
0.02533 0.01775
B-3
-------
in the costing algorithm. These design categories and category parameters are
discussed in Chapter 8 of the BID for the Air Oxidation Processes in SOCMI
(EPA-450/3-82-001a). Table B-2 presents the updated heating values and
flowrate intervals associated with each category. Substituting the design
values into the general equation allows values for coefficients a through f to
be derived for each design category. This derivation is included in Docket
item No. IV-B-15.
The results of this deriviation are summarized in Table B-l. As shown,
the coefficients are divided into six incinerator categories. Under each
design category listed in Table B-l, there are several intervals of vent
stream flowrate. Each flowrate interval is associated with a different set of
coefficients. The first flowrate interval in each design category applies to
vent streams with a flowrate corresponding to the smallest control equipment
system easily available without special custom design.
The remaining flowrate intervals in each design category apply to vent
streams which would be expected to use two, three, four, or five sets of
control equipment, respectively. These flowrate intervals are distinguished
from one another because of limits to prefabricated equipment sizes.
B.2.2 Example Calculation of an Incinerator-based TRE Index Value for a
Facility
This section presents an example of use of the TRE index equation. The
example distillation vent stream has the following characteristics:
1. Qs - 284 scm/min
2. HT = 0.37 MJ/scm
3. ETOC =76.1 kg/hr.
4. Ys - 284 scm/min.
5. No halogenated compounds in the vent stream.
Based on the stream heating value of 0.37 NJ/scm, Category B is the
applicable incinerator design category for this stream. The flowrate is
284 scm/min, and therefore the coefficients for the first flowrate interval
under Category B are used. The coefficients for Category B, flow interval #1
are:
B-4
-------
TABLE B-2. MAXIMUM VENT STREAM FLOWRATES AND NET HEATING VALUE
CHARACTERISTICS FOR EACH DESIGN CATEGORY
... . Maximum Process Vent
Minimum Net Maximum Net Stream Flowrate at
Hewing Value Heating Value Incinerator Inlet
Category (MJ/scm)* (MJ/scm)* (io5 scm/min)
Al
A2
B
C
D
E
0
3.5
0
0.48
1.9
3.6
3.5
-
0.48
1.9
3.6
-
0.70
0.70
1.34
1.34
1.18
1.18
These values are based on process vent stream conditions.
B-5
-------
a = 8.54
b = 0.106
c = 0.090
d = -0.171
e = 0
f = 0.010
The TRE equation is:
1
TRE = ETQC [a + b(Qs)°'88 + c(Q$) + d(Qs)(HT) + e(Q$ °'88)(HT °'88)
f (Qs)°'5]
TRE = (.013)[8.54 + 0.106 (284)°*88 + (0.090)(284)(-0.171)
(284)(.37) + 0 + 0.010)(284)°'5]
TRE = 0.111 + 0.199 + 0.332 - 0.236 + 0 + 0.002
TRE = 0.408
Since the calculated TRE index value of 0.408 is less than the cutoff value
of 1.0, this facility would be required to reduce VOC emissions by 98 weight-
percent or to 20 ppmv because the cost of incineration is considered to be
reasonable. Because the TRE index is a ratio of two cost-effectiveness
values, it is possible to calculate cost effectiveness for controlling any
vent stream given its TRE index value. The TRE index value of the facility
is multiplied by the reference cost effectiveness $l,900/Mg as follows:
TRE = 0.408
Reference cost effectiveness = $l,900/Mg
Cost effectiveness for example stream = (0.408)(1,900) = $775/Mg of
VOC removed
B-6
-------
If the TRE index value for this example were above 1.0, the flare-based TRE
equation (see Section B.3) would be used to calculate the flare-based TRE
index because flares can be applied to nonhalogenated vent streams. If the
flare-based TRE index were less than 1.0, this facility would have to reduce
VOC emissions by 98 weight-percent or to 20 ppmv, whichever is less stringent.
If the flare TRE index were also above 1.0, or if the stream contained
halogenated compounds so a flare could not be used, then no further controls
would be required.
B.3 FLARE SYSTEM TRE DEVELOPMENT
This section presents the development of the flare TRE index equation,
verification of the equation, and an example calculation of the flare TRE
index.
t
B-3.1 Development of the Flare TRE Index Equation
The flare TRE index equation was developed by selecting a general form
for the equation which contained the stream characteristics of flowrate,
heating value, and VOC emission rate as the independent variables, and the TRE
index as the dependent variable, and fitting this equation to the TRE index
values calculated from the annualized cost equations. The form of the TRE
index equation for flaring had to be selected so that an accurate prediction
of the TRE index could be obtained for a given set of vent stream
characteristics. The form of the flare TRE index equation selected was the
same as the form used in the proposed standards for Distillation Operations
(50 FR 20446).
The general form of the equation is as follows:
[a(QJ + b(Qsr + c(QJ(HT) + dfE^) + e]
where:
TRE - total resource effectiveness index value
Qs = vent stream flowrate (scm/min) at a standard temperature of 20°C
B-7
-------
= vent stream net heating value (MJ/scm) where the net enthalpy
per mole of vent stream is based on combustion at 25°C and
760 mm Hg, but the standard temperature for determining the
volume corresponding to one mole is 20°C as in the definition
of Qs.
hourly emission rate of total organic compounds reported in
kg/hr measured at full operating flowrate.
a, b, c, d, and e are coefficients.
The coefficients for the flare TRE index equation were developed with a
regression analysis procedure. The regression analysis procedure used is the
General Linear Model (GLM) procedure of the Statistical Analysis System
Institute, Inc., Raleigh,.North Carolina. The development of the
coefficients involved three steps: (1) formation of an appropriate data base
for the regression; (2) calculating a TRE index value for each set of vent
stream characteristics in the data base with the revised flare costing
procedure described in Docket Entry IV-B-8; and (3) using the GLM procedure
to regress TRE index values against the vent stream characteristics.
The distillation NSPS National Emissions Profile (NEP) and the reactor
processes Emissions Data Profile (EDP) were used as the data base for the
regression analysis. Adding the reactor processes EDP was judged to be
appropriate because of two significant similarities with the distillation
NEP: (1) the vent stream characteristics represented in the two data bases
are similar; and (2) identical or similar synthetic organic chemicals are
produced by both reactor processes and distillation operations.
After the data base was formed, the cost of controlling VOC emissions
using flares was calculated from the annualized cost equations for each
facility with nonhalogenated vent streams in the NEP and EDP. These costs
were divided by the amount of VOC emissions reduced by flaring (i.e., 98
weight-percent) to obtain a value for cost of control per megagram of VOC
reduced. Next, these values were divided by a TRE cutoff of $l,900/Mg to
obtain a TRE index value for each facility. The TRE index value and vent
stream characteristics for each facility were then input to the GLM
regression program.
B-8
-------
TRE inH 7ntS e"e0Ped f°r "Ch te™ fn the TRE """"on "'Ing the
E , dex value as the dependent variable and the vent stream character s
« depen en ar1 ables. The flare TRE coefficients are shown in Tab, "
wi a i r ; 7 deveioped for each °f
(0 Btu s f, r?V WUh heatjn9 Va'U
lues for b" ' C°mbUSt10n WUh 3 fUre f°r
values at or above 11.2 MJ/scm (300 Btu/scf). The
w,th vent stream heating values at or above 11.2
ar:StChf)heatThereT ' """ "* °? « ^"'^
streams W1th heating values at or above 11.2 MJ/scm.
B'3'2 ^are TRF Coefficients •tfa>.1f1catinn
capabnitv'oT TRE T*10" and C°effiCie"ts "" «-1»- to ensure their
capability of accurately predicting the TRE Index value for a facility fr™
E6 cVoelStr"; Cha^iSt1"- * -'fication procedure for^,
u no th i lnV°1Ved ^^ Ste"S: U) "'culati- " • TRE index
n he newly derived TRE elation for each facility 1n the data ^.
„ . „.„ ,,, „„„. „.
„
B-9
-------
TABLE B-3 DISTILLATION OPERATIONS NSPS TRE COEFFICIENTS FOR VENT STREAMS
CONTROLLED BY A FLARE
MJ/scm
a b c d e
MJ/scm 2.25 0.288 -0.193 -0.0051 2.08
B-10
0.309 0.0619 -0.0043 -0.0034 2.08
-------
TABLE B-4. TRE INDEX VALUES GENERATED USING TRE COEFFICIENTS AND THE
ALGORITHM NET HEATING VALUE GREATER THAN OR
Flowrate
(scf/min)
— •
70.00
1.45
1.20
2.04
1.39
.20
0.30
6.60
— ^— — _ — _^^____
Heat Content
(Btu/scf)
•
323.00
903.00
1024.00
1024.00
966.00
2778.00
4978.00
1286.00
VOC
db/hr)
___^_
6.60
1.60
3.81
6.47
6.04
2.00
4.90
3.00
» TRE
INDEX VALOE
Algorithm Coefficients
0.88
2.90
1.22
0.72
0.77
2.31
0.95
1.57
— —
0.91
2.91
1.22
0.72
0.77
2.31
0.94
1.57
Percen
D if fere
• .
3.39
0.43
0.03
-.08
-.06
-.01
-.49
0.08
B-ll
-------
values calculated with the TRE equation and those calculated using the cost
algorithm for the same facility as described above.
For vent streams with heating values below 11.2 MJ/scm there was poor
agreement initially between the algorithm and TRE equation. Therefore, those
data points resulting in very higji TRE indexes were removed after the initial
verification procedure was performed because they caused the poor agreement
at TRE index values near the cutoff. After removal of those data points, the
TRE coefficients for vent stream heating values less than 11.2 MJ/scm were
recalculated and the verification procedure was undertaken again. The
percentage difference in the recalculated TRE index values near the cutoff
ranged from 2.38 to -7.39. Thus, it was concluded that the recalculated TRE
coefficients for vent streams with heating values below 11.2 MJ/scm provided
good agreement with the actual TRE index values. Table B-5 presents a
comparison of TRE indexes near the cutoff for vent streams with heating
values below 11.2 MJ/scm.
As a final verification step for vent streams with heating values below
11.2 MJ/scm, the recalculated TRE coefficients were used to determine a TRE
index value for those data points which were removed after the initial
verification procedure was performed. The percentage difference between the
TRE index values determined using the recalculated coefficients and the TRE
index values determined using the flare cost algorithm ranged from 2.29 to
-6.24. Thus, it was concluded that the coefficients enable accurate
estimation of even those facilities with high TRE index values. Table B-6
presents a comparison of TRE index values for those vent streams with high
TRE index values.
In summary, the flare TRE equations developed for this NSPS allow for
the calculation of TRE index values that are highly correlated with the TRE
index values obtained from the costing algorithm. The TRE equations do not
necessarily result in the best statistical fit between TRE values and vent
stream characteristics. This is because the primary concern in developing
the equation and coefficients is to ensure very good agreement between the
TRE equation and cost algorithm for TRE's at or around the cutoff.
B-12
-------
TABLE B-5. PERCENT DIFFERENCE BETWEEH TRE IMDEX VALUES GENERATED USIHG IRE EQUATION AND THE
FLARE COST ALGORITHM NET HEATING VALUE LESS THAN 300 Btu/scf
Flowrate
(scf/mln)
17.00
75.00
50.40
4.40
22.60
11.30
68.70
7.57
27.30
4.20
88.00
7.50
2.40
17.90
15.00
80.00
Heat Content
(Btu/scf)
181.00
102.00
70.00
190.00
92.00
168.00
72.00
18.00
47.00
18.00
47.00
47.00
260.00
69.00
149.00
9.00
VOC
(Ib/hr)
16.00
6.10
16.90
4.00
10.50
5.23
26.30
5.00
8.50
28.50
2.50
4.00
4.00
8.00
6.60
19.60
TRE
Algorithm
0.38
2.12
0.65
1.22
0.73
1.16
0.50
1.14
1.02
1.04
0.57
2.23
1.17
0,92
0.96
0.87
INDEX VALUES
Coefficients
Recalculated
.37
2.12
0.65
1.24
0.69
1.07
0.50
1.16
0.99
1.06
.58
2.28
1.18
0.87
0.91
0.86
Percent Differences
Compared to Algorithm
Coefficients
Recalculated
-2.23
- .10
0.00
1.84
-5.16
-7.39
0.21
2.06
-3.63
1.29
0.68
2.38
1.05
-5.71
-5.2-9
-1.53
aTRE coefficients derived from vent streams with a heating value greater than 40 Btu/scf but less than 300 Btu/scf.
B-13
-------
TABLE B-6. PERCENT DIFFERENCES BETWEEN TRE INDEX VALUES GENERATED BY THE COST
ALGORITHM AND THE TRE EQUATION FOR VENT STREAMS WITH. HEATING
VALUES LESS THAN 40 Btu/scf
Flowrare
(scf/min)
99.00
822.00
16.67
0.05
39.20
6.60
2.00
6.25
12.40
13.53
Heat Content
(Btu/scf)
0.00
0.00
4.00
36.00
4.00
8.00
0.00
9.00
0.00
0.00
VOC
(Ib/hr)
0.10
0.10
.37
0.10
0.18
.60
.003
.40
0.14
0.03
TRE INDEX VALUE
Algorithm
203
1325
21
46
61
9
1640
14
51
242
Coefficient.!*
202
1290
20
46
60
9
1658
14
48
228
Percent
Difference
- .91
-2.65
-5.16
0.19
-2.28
2.24
1.14
2.29
-6.24
-5.96
Equation coefficients were developed after excluding vent streams with heating values
less than 40 Btu/scf,
B-14
-------
B.3.3
f a Flare-Rased TRF TnH
Value for a Far*Tft
an example calculation for the
3.
4.
.2.2. The vent stream
Qs = 284 scm/min
HT =0.37 MJ/scm
ETOC m7*-1 k9/hr
are as fonows:
a
b
c
d
e
No halogenated compounds in vent stream.
on the stream h.^™ value Qf Q 3? MJA(;m
as '-"
2.25
0.288
-0.193
-0.0051
2.08
.
emlsslons by 98 weight-percent or below 20 ppmv
B-15
-------
-------
|l. REPORT NO.
EPA-450/3-83-005b
ton Operations 1n Synthetic Organic Chemical
Manufacturing - Background Information for Final
standards
7. AUTHOmSI
"' P6"?°?MING ORGANIZATION NAME AND ADDRESS'
Office of Air Quality Planning and Standards
U. S. Environmental Protection Agency
Research Triangle Park, North Carolina 27711
12. SPONSORING AGENCY NAME AND ADDRESS
Office of Air and Radiation, U. S. EPA
Research Triangle Park. North Carolina
IS. SUPPLEMENTARY NOTES~ ThlS~ Ul
S2M5^^ra^*^5^^;^SBr
operations in the synthetic organic chemical manufacturing industry.
AasTSA/r • - . . i_n. , . _ .. J
16. ABSTRACT
EPORT DATA
rertnt be fan completing
9. RfCIfliNT-S ACCESSION NO!
B. ftiFOftT OATB
_
». PERFORMING ORGANIZATION CODE
•. PERFORMING ORGANIZATION REPORT NO
68-02-3058
3. TYP£ Of (WORT ANO PEBlOO COVEBEo
EPA/200/04
27711
i
KEY WORDS AND DOCUMENT ANALYSIS
^ n—• i _
_-___..
b.lDENTIFIERS/QPEN 6NO6D TERMS
COSATI f-ifld/Croup
Air Pollution Control
DESCBIfTOBS
Air pollution
Distillation unit operations
Pollution control
Standards of performance
Organic chemical industry
Volatile organic compounds (VOC)
IB. O'STBisunoN STATEMENT"
Unlimited - available to the public free
of charge from U. S. EPA Library (MD-35)
Research Triangle Park. N.C. ?77JV ^
PAF«n,2220.UR...4.77, P.cv.ou, CC.T.ON „ ,
19 56CUHITY CLASS <
Unclassified
20 SECURITY CLASS tTiltspafti'
Unclassified
j21. NO. OF PAGES
142
(22. PRICE
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