United States Office of Air Quality EPA-450/3-82-024b
Environmental Protection Planning and Standards May 1985
Agency Research Triangle Park NC 27711
Air
vvEPA Equipment Leaks EIS
of VOC in Natural
Gas Production
Industry
Background
Information for
Promulgated
Standards
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EPA-450/3-82-024b
Equipment Leaks of VOC
in Natural Gas Production Industry -
Background Information
for Promulgated
Standards
Emission Standards and Engineering Division
U.S ENVIRONMENTAL PROTECTION AGENCY
Office of Air and Radiation
Office of Air Quality Planning and Standards
Research Triangle Park. North Carolina 2771 1
May 1985
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This report has been reviewed by the Emission Standards and Engineering Division of the Off ice 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, North Carolina 27711;or, fora fee, from
the National Technical Information Services, 5285 Port Royal Road. Springfield, Virginia 22161.
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ENVIRONMENTAL PROTECTION AGENCY
Background Information
and Final Environmental Impact Statement
for Equipment Leaks of VOC from Onshore Natural Gas Processing Plants
Jack R. Fanner
Director, Emission Standards and Engineering Division
U.S. Environmental Protection Agency
Research Triangle Park, North Carolina 27711
1. The promulgated standards of performance will limit equipment leaks
of VOC from new, modified, and reconstructed gas plant process
units and compressors. 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 we! fare."
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; the Council on Environmental Quality; State and
Territorial 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:
Ms. Dianne Byrne or Mr. Gilbert Wood
Standards Development Branch (MD-13)
U.S. Environmental Protection Agency
Research Triangle Park, NC 27711
Telephone: (919) 541-5578
4. Copies of this document may be obtained from:
U.S. EPA Library (MD-35)
Research Triangle Park, NC 27711
Telephone: (919) 541-2777
National Technical Information Service
5285 Port Royal Road
Springfield, VA 22161
11
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TABLE OF CONTENTS
Section Title Page
TABLE OF CONTENTS v
LIST OF TABLES viii
LIST OF FIGURES ix
1.0 SUMMARY 1-1
1.1 Introduction 1-1
1.2 Summary of Changes Since Proposal 1-1
1.3 Summary of Impacts of Promulgated Action ... 1-4
1.4 Summary of Public Comments 1-5
2.0 NEED FOR STANDARDS 2-1
2.1 Significance of Emissions and Public Health
Impact 2-1
2.2 Adequacy of Current Controls and
Regulations 2-3
2.3 Industry Growth, Industry Mobility,
and Seasonal Considerations 2-5
3.0 BASIS FOR STANDARDS 3-1
3.1 Introduction 3-1
3.2 Valves 3-1
3.3 Pumps 3-1
3.4 Compressors 3-2
3.5 Open-Ended Lines 3-2
3.6 Pressure Relief Devices 3-2
3.7 Sampling Connections 3-4
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TABLE OF CONTENTS (Continued)
Section Title pa ge
4.0 FORMAT AND REQUIREMENTS OF STANDARDS 4-1
4.1 Format of Standards 4-1
4.2 Valves 4-1
4.3 Pumps 4-4
4.4 Compressors 4-5
4.5 Open-Ended Lines 4-7
4.6 Pressure Relief Devices 4-9
4.7 Control Devices 4-13
4.8 Leak Detection and Repair 4-18
5.0 APPLICABILITY OF STANDARDS 5-1
5.1 Definitions 5-1
5.2 Selection of Sources 5-7
5.3 Selection of Affected Facilities 5-10
5.4 Applicability Date 5-12
5.5 Alaskan North Slope 5-13
5.6 Small Plants 5-15
6.0 ENVIRONMENTAL IMPACTS 6-1
6.1 Emission Reductions 6-1
6.2 Leak Frequencies 6-4
6.3 Emission Factors 6-5
6.4 Model Plants 6-7
6.5 Nonair Environmental Impacts 6-7
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TABLE OF CONTENTS (Concluded)
Section Title
Page
7.0 COST OF CONTROL 7_1
7.1 General 7_1
7.2 Compressors 7.3
7.3 Pressure Relief Devices 7-6
7.4 Control Devices 7.7
7.5 Leak Detection and Repair 7_g
8.0 ECONOMIC IMPACTS 8-1
8.1 Prices 8_1
8.2 Industry Impacts 8-3
8.3 Small Businesses 8-4
9.0 MODIFICATION AND RECONSTRUCTION 9-1
9.1 Capital Expenditure g_l
9.2 Modification of Existing Sources 9-2
9.3 Miscellaneous 9_3
10.0 TEST METHODS 10_l
10.1 Leak Detection Methods 10-1
10.2 Leak Definition 10-4
11.0 RECORDKEEPING AND REPORTING 11-1
11.1 General ll-l
11.2 Reporting 11-4
11.3 Recordkeoping 11-5
12.0 MISCELLANEOUS 12_!
VI 1
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LIST OF TABLES
Number Title Paqe
1-1 Projected VOC Equipment Leak Emissions
from Uncontrolled, Baseline, and NSPS
Control Levels 1-6
1-2 List of Cornrnenters on Proposed Standards
of Performance for Equipment Leafcs of VOC
from Onshore Natural Gas Processing Plants 1-8
3-1 Control Costs per Megagram of VOC
Reduced 3-3
7-1 Cost Effectiveness of Compressor Vent
Control Systems for Model Plant B 7-5
7-2 Summary of Total Annual Costs to Perform
Leak Detection and Repair Program at a
500-Componen.t Gas Plant 7-12
VII 1
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LIST OF FIGURES
Number Title Page
5-1 Cost Effectiveness versus Plant
Size for Small Plants 5-16
i x
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1.0 SUMMARY
1.1 INTRODUCTION
On January 20, 1984, the Environmental Protection Agency (EPA)
proposed standards of performance for equipment leaks of volatile
organic compounds (VOC) emissions from onshore natural gas processing
plants (49 FR 2636) under the authority of Section 111 of the Clean Air
Act. Public comments were requested on the proposal in the Federal
Register. EPA received 37 comment letters on the proposed standards
and statements from five speakers at the public hearing on March 7, 1984.
Industry representatives submitted most of the comments. Also commenting
was a vendor of safety equipment. The comments that were submitted,
along with responses to these comments, are summarized in this document.
This summary of comments and responses serves as the basis for the
revisions made to the applicability and requirements of the standards
between proposal and promulgation.
1.2 SUMMARY OF CHANGES SINCE PROPOSAL
The proposed standards were revised as a result of reviewing public
comments. Changes were made in the following areas:
Exemption for reciprocating compressors in wet gas service
Revisions to flare requirements
Definition of "in VOC service"
Monitoring requirements for pressure relief devices at certain
pi ants
t Provision for difficult-to-monitor valves in new units
t Leak detection and repair requirements for natural gas processing
plants located in the North Slope of Alaska
Alternative for determining a "capital expenditure"
1.2.1 Exemption for All Reciprocating Compressors in Wet Gas Service
At proposal, EPA exempted reciprocating compressors in wet gas
service only if they were located at a gas plant that did not have an
existing control device. The cost effectiveness of controlling such
compressors was high due to the cost of installing and operating a
control device. However, the cost effectiveness of controlling wet
gas reciprocating compressors at plants with an existing control
device ($1700 per megagram of VOC reduced) was considered reasonable,
given that the average cost effectiveness (combining cost-effectiveness
numbers for centrifugal and reciprocating compressors) was estimated
to be much lower ($460 per megagram). However, since proposal, several
industry representatives commented that many gas plants, especially
small ones, will use reciprocating compressors almost exclusively.
For such plants, the compressor control cost effectiveness would be
essentially the same as the cost effectiveness for controlling only
1-1
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wet gas reciprocating compressors at plants with an existing control
device (i.e., $1700 per megagram). This cost effectiveness, when
considered representative of the overall compressor control costs for
small plants, is judged to be unreasonably high. For this reason,
the promulgated standards have been revised to exempt all wet gas
reciprocating compressors. Reciprocating compressors used in natural
gas liquids (NGL) service and all centrifugal compressors in wet gas or
NGL service are still required to be equipped with closed vent systems,
however, because they can be controlled at a reasonable cost effectiveness.
1.2.2 Revisions to Flare Requirements
The velocity and heating value requirements for flares have been
changed since proposal of the standards to allow flares burning gas
streams with high heating values to use high velocities. The final
standards present equations for calculating the maximum permitted
velocity for flares to provide for velocities up to 122 meters per
second (m/sec) (400 feet per second (ft/sec)) depending on the gas heat
content. The purpose of the equations is to allow streams with heat
contents greater than 11.2 megajoules per standard cubic meter (MJ/scm)
(300 British thermal units per standard cubic foot (Btu/scf)) to be
flared at higher velocities, while ensuring a VOC destruction efficiency
that reflects best demonstrated technology (BDT). If the net heating
value of the gas being combusted is greater than 37.3 MJ/scm (1,000
Btu/scf), then a flare exit velocity of 122 m/sec (400 ft/sec) will be
accepted. The basis for these changes in the flare requirements is
discussed in Section 4.7.
1.2.3 Definition of "In VOC Service"
The EPA received numerous requests from commenters for raising the
VOC concentration for "in VOC service" from 1 weight percent to 10
weight percent VOC. The commenters stated that a 1 weight percent
VOC limit would cause many dry (residue) gas streams with low VOC content
to be regulated, and, as a result, poor cost effectiveness.
The EPA intended to exempt dry gas in the proposed standards due
to the fact that dry gas has very low (generally less than 1.0 weight
percent) VOC content and, therefore, is generally not cost effective to
control. The EPA did, however, intend for wet gas (inlet or field gas)
components to be regulated, since components in wet gas service have
a high VOC content and are cost effective to control. At proposal,
EPA selected 1.0 weight percent VOC as the VOC service definition to
exclude dry gas, while assuring that wet gas streams would be regulated.
Commenters on the proposed standards provided data indicating that
1 weight percent was not an appropriate limit, since dry gas streams
can contain more than 1 weight percent VOC. The EPA agrees that it is
difficult to define a range of VOC concentrations for either wet gas
or dry gas streams and, therefore, has decided to include equipment in
wet jas service by covering them as a class.
Considering that gas plant streams, other than wet gas streams,
containing less than 10 weight percent VOC (dry gas or VOC/non-VOC
1-2
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mixtures) would not be cost effective to control, a VOC concentration
limit of 10 weight percent was selected as a representative limit for
the "in VOC service" definition. Therefore, the definition of "in VOC
service" has been changed in the promulgated standards to refer to a
10 we-ight percent VOC content.
1.2.4 Monitoring Requirements for Pressure Relief Devices
Since proposal, EPA has reviewed comments concerning the
monitoring of pressure relief devices following pressure release.
Commenters representing small nonfractionating gas plants claimed
that the requirement to monitor pressure relief devices within 5
days of a pressure release was burdensome because of the unavailability
of monitoring instruments at the plant and problems in scheduling
contractor assistance in such a short time. Based on these comments,
EPA decided to allow owners and operators of nonfractionating
plants which are monitored only by non-plant personnel to monitor
pressure relief devices the next time the monitoring personnel are on-
site or within 30 days of a pressure release, whichever cornes first,
instead of within 5 days.
1.2.5 Provision for Difficult-to-monitor Valves in New Units
At proposal, EPA allowed annual monitoring of difficult-to-monitor
valves in units covered by the modification or reconstruction
provisions, but there was no similar provision for difficult-to-monitor
valves in new units. Commenters stated that all new units could not
be designed to eliminate difficult-to-monitor valves. Upon reviewing
these comments, EPA decided to allow plant owners or operators to
designate up to 3 percent of the total number of valves in a new unit
as difficult to monitor. Based on existing units, about 3 percent of
the total number of valves may be difficult to design to be accessible
in new units without significant additional costs.
1.2.6 Leak Detection and Repair Requirements for Natural Gas
Processing Plants Located in the North Slope of Alaska
The EPA reviewed comments concerning natural gas plant operations
in the North Slope of Alaska and detennined that the costs to comply
with certain aspects of the proposed standards can be unreasonable.
Leak detection and repair programs incur higher labor, administrative,
and support costs at plants that are located at great distances from
major population centers and particularly those that experience extremely
low temperatures as in the arctic. Thus, EPA decided to exempt
plants located in the North Slope of Alaska from the routine leak
detection and repair requirements. The EPA excluded these plants only
from the routine leak detection and repair requirements because the
costs of the other requirements are reasonable.
1.2.7 Alternative for Determining a "Capital Expenditure"
The annual asset guidel i ne repair allowance (AAGRA]~and the
original cost basis are used to define capital expenditures (see 40 CFR
60.2). The definition of AAGRA is specified by the Internal Revenue
Service (IRS), and its use has not changed despite tax law revisions in
1-3
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1982. In response to comments concerning the basis for determining d
capital expenditure, EPA has amended the definition of a capital
expenditure to provide an alternative procedure for determining the
original cost basis. This procedure will allow plant personnel to use
a percentage of replacement costs rather than original costs to determine
capital expenditure; however, this procedure does not affect the coverage
of the standards. Details of the alternative are discussed in Chapter 9.
1.3 SUMMARY OF IMPACTS OF PROMULGATED ACTION
1.3.1 Alternatives to Promulgated Action
The regulatory alternatives are discussed in Chapter 6 of the
background information document (BID) for the proposed standards
EPA-450/3-82-024a. These regulatory alternatives reflect the different
levels of emission control that were used in the selection of best
demonstrated technology (BDT), considering costs, nonair quality health,
and environmental and economic impacts for sources of equipment leaks
of VOC in the natural gas processing industry. No changes have been
made in the regulatory alternatives since proposal.
1.3.2 Environmental Impacts of Promulgated Action
Environmental impacts of the standards are described in Chapter
7 of the BID for the proposed standards. Changes made in the standards
since proposal affect the estimated VOC emission reduction. These
changes, which will reduce the industry-wide emission reduction of the
standards, include a change in the estimated compressor service split,
the exemption for reciprocating compressors in wet gas service, and the
effects of the Control Techniques Guideline (CTG) requirements
(EPA-450/3-83-007), which have been published since proposal of the
standards. The EPA has revised the estimate of VOC emissions that
will be reduced by the standards.
The promulgated standards will reduce equipment leaks of VOC from
newly constructed, modified, and reconstructed facilities by 16,100
megagrams (Mg) in the fifth year of implementation of the standards, a
reduction of emissions from 22,000 Mg of VOC per year (Mg/yr) to 5,900
Mg/yr. This reduction represents a 73 percent decrease in emissions
from the current industry baseline level of emissions. The basis of
the revised estimate of VOC emissions that will be reduced by the
standards is discussed in Docket Item IV-B-9. The water quality and
solid waste impacts have not changed significantly as a result of the
revised emission estimates.
With the changes noted above, the analysis of the environmental
impacts in the BID for the proposed standards now becomes the final
Environmental Impact Statement for the promulgated standards.
1.3.3 Energy and Economic Impacts of Promulgated Action
Section 7.5 of the BID for the proposed standards describes the
energy impacts of the standards. The revisions made in the standards
do not change significantly the energy impacts of the standards
1-4
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because the energy value and crude oil equivalent of VOC emission
reductions are about the same as they were at proposal.
Chapters 8 and 9 of the BID for the proposed standards describe
the cost and economic impacts of the proposed standards. Since
proposal, the cost analysis of the standards has been revised to reflect
the changes discussed above that have been made since proposal. The
industry-wide cost of the standards is lower than the estimate at
proposal because of the effects of CTG requirements for onshore natural
gas processing plants (published since proposal) in the fifth year of
the standards and because of the exemption of reciprocating compressors
in wet gas service from the standards since proposal. The promulgated
standards will require an industry-wide capital investment and net
annualized cost of approximately $6.2 million and $1.5 million,
respectively, for newly constructed, modified, and reconstructed facili-
ties in the fifth year of implementation of the standards. The basis
of the revised industry-wide costs is discussed in Docket Item IV-B-9.
As discussed in Chapter 8 of this document, the economic impact of the
promulgated standards remains reasonable.
1.3.4 Other Considerations
1-3.4.1 Irreversible and Irretrievable Commitment. Section 7.6.1
of the BID for the proposed standards concludes that the standards
will not result in any irreversible or irretrievable commitment of
resources. It was also concluded that the standards should help to
save resources due to the energy savings associated with the reduction
in emissions. These conclusions remain unchanged since proposal.
1.3.4.2 Environmental Impacts of Delayed Standards. Table 1-1
of this document summarizes the environmental impacts associated
with delaying promulgation of the standards. The air impacts have
been revised since proposal as explained in Table 1-1. Uncontrolled
and controlled emissions would occur at the rates shown for each of
the 5 years. Fifth-year emission reductions from the uncontrolled
level and baseline level are presented.
1.4 SUMMARY OF PUBLIC COMMENTS
EPA received 37 comment letters and statements from five speakers
at the public hearing on the proposed standards and the BID for the
proposed standards. Comments from the public hearing on the proposed
standards were recorded, and a transcript of the public hearing was
placed in the project docket along with all public comment letters.
At the request of some of the commenters, the comment period was
extended 60 days to allow more time for review and comment. A list
of commenters, their affiliations, and the EPA docket item number
assigned to their correspondence is given in Table 1-2.
1-5
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TABLE 1-1. PROJECTED VOC EQUIPMENT LEAK EMISSIONS
FROM UNCONTROLLED, BASELINE, AND NSPS CONTROL LEVELS
(Proposal Basis) (Promulgation Basis)
YEAR Uncontrolled*
1983 5.1
1984 10.2
1985 15.3
1986 19.5
1987 23.6
5th year (1987)
Emission Reduc-
tion from
Uncontrol led
5th year (1987)
Emission Reduc-
tion from Base-
line
Cost
effectiveness
($/Mg)
Proposed
NSPSb Uncontrol ledc
1.2 5.1
2.4 10.1
3.6 15.2
4.5 19.3
5.5 23.5
18.1
~ ~~
140
Proposed
Basel 1ned NSPSe
4.7 1.2
9.5 2.5
14.2 3.7
18.1 4.7
22.0 5.7
1.5 17.8
16.3
150
Final
NSPSf
1.3
2.6
3.9
4.9
5.9
17.6
16.1
93
From Docket Item IV-B-9. The uncontrolled emissions assumed at proposal that all
natural gas processing plants are operated with no regulations for control of
equipment leaks of VOC.
b
Emission levels under the proposed standards are based on Docket Item II-B-38,
which presents the controlled emission levels for each model plant, and Table 7-5
of the BID for the proposed standards, which presents the anticipated number of
model plants affected. The memo did not take Into account, however, that one-half
of all reciprocating compressors in wet gas service would be exempt, which was
assumed at proposal. Also assumes that 34 percent of all compressors are in NGL
service and that 66 percent are in wet gas service.
Since proposal, as explained in Docket Item IV-B-9. the uncontrolled emission estimates
have been revised due to a change In the assumed distribution of compressor service.
This results In a change In emissions of 100 Mg/yr in 1987 from the uncontrolled level
reported at proposal as there are now assumed to be more compressors In wet gas
service and less in NGL service.
1-6
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TABLE 1-1
PROJECTED VOC EQUIPMENT LEAK EMISSIONS
FROM UNCONTROLLED, BASELINE, AND NSPS CONTROL LEVELS (Concluded)
d
The baseline level of control assumes that 10 percent of new gas plants will be
built in ozone nonattainment areas and will be subject to requirements similar to
those in the CTG for natural gas processing plants (Docket Item II-J-1). Calculated as
described in Docket Item IV-B-9.
e
Emission levels under the proposed standards reflect the fact that wet gas
reciprocating compressors in plants with an existing control device were required
to be controlled. The final NSPS does not require controls on these compressors.
However, emissions'under the proposed standards are higher than assumed at
proposal because of a change in the ratio of compressors in NGL and wet gas
service (i.e., 50% of all compressors are exempt wet gas reciprocating units,
and the remaining 50% are split equally between wet gas centrifugal units and NGL
units of both types). Under these conditions, 25 percent of all compressors
would be exempt from the proposed standards, since they would be wet gas
reciprocating units at plants without a control device.
Revised emission levels from implementing the final standards are based on
Docket Item IV-B-9 and are slightly higher than the emission levels under the
proposed standards as a result of the exemption of all wet gas reciprocating
compressors. This exemption decreases the emission reduction from the proposal
level by 200 Mg/yr in 1987, resulting in a total emission reduction of 16,100
Mg/yr from the baseline level of control.
1-7
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TABLE 1-2. LIST OF COMMENTERS ON PROPOSED STANDARDS OF PERFORMANCE
FOR EQUIPMENT LEAKS OF VOC FROM ONSHORE
NATURAL GAS PROCESSING PLANTS
Commenter and Affiliation Docket Item No.
1. Mr. J.D. Reed IV-D-1
Standard Oil Company (Indiana)
200 East Randolf Drive
Chicago, IL 60601
2. Mr. Louis R. Harris IV-D-2
BS & B Safety Systems, Inc.
7455 East 46th Street
P.O. Box 470590
Tulsa, OK 74147-0590
3. Mr. Rodney D. Long IV-D-3
Minerals, Inc.
P.O. Box 1320
Hobbs, NM 88240
4. Mr. Greg Lewis IV-D-4
Liquid Energy Corporation IV-D-21
2001 Timberlock Place
P.O. Box 4000
The Woodlands, TX 77380
5. Mr. J.D. Geiger IV-D-5
Aminoil , USA IV-D-23
P.O. Box 94193
Houston, TX 77292
6. Mr. R.E. Cannon IV-D-6
Gas Processors Association IV-D-26
1812 First Place
Tulsa, OK 74103
7. Mr. John J. Moon IV-D-7
Phillips Petroleum Company IV-D-31
Bartlesville, OK 74004
8. Mrs. Laura G. Daniel IV-D-8
Conoco, Inc. IV-D-36
P.O. Box 2197, Suite 450 RT
Houston, TX 77252
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TABLE 1-2. LIST OF COMMENTERS ON PROPOSED STANDARDS OF PERFORMANCE
FOR EQUIPMENT LEAKS OF VOC FROM ONSHORE
NATURAL GAS PROCESSING PLANTS
(conti nued)
Commenter and Affiliation
Docket Item No.
9. Mr. H.K. Holland, Jr.
Mobil Oil Corporation
150 East 42nd Street
New York, NY 10017
10. Mr. A.G. Smith
Shell Oil Company
One Shell Plaza
P.O. Box 4320
Houston, TX 77210
11. Mr. Robert H. Lovell
Mountain Fuel Supply Company
180 East First South
P.O. Box 11368
Salt Lake City, UT 84139
12. Mr. A.E. Middents
Western Slope Gas Company
One Park Central - 1515 Arapahoe Street
P.O. Box 840
Denver, CO 80201
13. Mr. Peter W. McCallum
The Standard Oil Company (Ohio)
Midland Building
Cleveland , OH 44115-1098
14. Mr. B.L. Walters, Jr.
Marathon Oil Company
Findlay, OH 45840
15. Mr. H.B. Barton
Exxon Company, U.S.A.
P.O. Box 2180
Houston, TX 77001
16. Mr. W.W. Cofield
Transco Energy Company
2700 Post Oak Boulevard
P.O. Box 1396
Houston, TX 77251
IV-D-9
IV-D-10
IV-D-11
IV-D-lla
IV-D-12
IV-D-13
IV-D-14
IV-D-15
IV-D-16
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TABLE 1-2. LIST OF COMMENTERS ON PROPOSED STANDARDS OF PERFORMANCE
FOR EQUIPMENT LEAKS OF VOC FROM ONSHORE
NATURAL GAS PROCESSING PLANTS
(continued)
Commenter and Affiliation Docket Item No.
17. Mr. Steven E. Kurmas, P.E. IV-D-17
Michigan Consolidated Gas Company
500 Grinswold Street
Detroit, MI 48226
18. Mr. P.K. Smith, Jr. IV-D-18
Kerr-McGee Corporation
Kerr-McGee Center
Oklahoma City, OK 73125
19. Mr. H. Schuyten IV-D-19
Chevron U.S.A., Inc.
575 Market Street
P.O. Box 7643
San Francisco, CA 94120-7643
20. Mr. J.P. Keehan IV-D-20
Mobil Oil Corporation
150 East 42nd Street
New York, NY 10017
21. Mr. L. James Anderson ' IV-D-22
Union Oil of California
Union Oil Center
Box 7600
Los Angeles, CA 90051
22. Mr. J. Donald Annett IV-D-24
Texaco U.S.A.
1050 17th Street, N.W.
Suite 500
Washington, D.C. 20036
23. Mr. George H. Lawrence IV-D-25
The American Gas Association
1515 Wilson Boulevard
Arlington, VA 22209
24. Mr. Jack Swenson IV-D-27
Rocky Mountain Oil and Gas
Association, Inc.
345 Petroleum Building
Denver, CO 80202
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TABLE 1-2. LIST OF COMMENTERS ON PROPOSED STANDARDS OF PERFORMANCE
FOR EQUIPMENT LEAKS OF VOC FROM ONSHORE
NATURAL GAS PROCESSING PLANTS
(conti nued)
Commenter and Affiliation
25. Mr. Stuart C. Mut
ARCO Oil and Gas Company
P.O. Box 2819
Dallas, TX 75221
26. Mr. Frank J. Duffy
Northern Gas Products Company
2223 Dodge Street
Omaha, NE 68102
27. Mr. R.J. Cinq-Mars
Cities Service Oil and Gas Corporation
Box 300
Tulsa, OK 74102
28. Dr. Howard Reiquam, Ph.D.
El Paso Natural Gas Company
P.O. Box 1492
El Paso, TX 79978
29. Mr. P.J. Early
Amoco Production Company
200 East Randolf Drive
P.O. Box 5340A
Chicago, IL 60680
30. Mr. Lawrence J. Ogden
Interstate Natural Gas Association
of America
1660 L Street, N.W.
Washington, D.C. 20036-5611
31. Mr. John G. Blackburn, Jr.
American Petroleum Institute
1220 L Street, N.W.
Washington, D.C. 20005
32. Mr. L.T. Reed
Warren Petroleum Company
P.O. Box 1589
Tulsa, OK 74102
Docket Item No.
IV-D-28
IV-D-29
IV-D-30
IV-D-32
IV-D-33
IV-D-34
IV-D-35
IV-D-37
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TABLE 1-2. LIST OF COMMENTERS ON PROPOSED STANDARDS OF PERFORMANCE
FOR EQUIPMENT LEAKS OF VOC FROM ONSHORE
NATURAL GAS PROCESSING PLANTS
(concluded)
Commenter and Affiliation Docket Item No.
Public Hearing
33. Mr. Jim Anderson IV-F-la
Gas Processors Association
1812 First Place
Tulsa, OK 74103
34. Mr. William S. Taylor IV-F-lb
Union Texas Petroleum Corporation
P.O. Box 2120
Houston, TX 77252
35. Mr. Gary Reed IV-F-lc
(Representing the Independent Petroleum
Association of America)
Texas Oil & Gas Corp.
First City Center
Lock Box No. 10
Dallas, TX 75201
36. Mr. Scott Ronzio iV-F-ld
ARCO Alaska, Inc.
Anchorage, Alaska 99510
37. Mr. W.J. Woodruff IV-F-le*
(Representing American Petroleum Institute)
Phillips Petroleum Company
Bartlesville, OK 74004
*At the public hearing, API requested that its oral and written comments to
EPA on the proposed standard and the related CTG be incorporated in the
record. These API comments relevant to the basis of the promulgated standards
have been included in this document. The docket items are listed in
parentheses as "II-B-xx" or "II-D-xx" in the appropriate comment summaries.
1-12
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The comments have been categorized under the following
topics:
Need for Standards (Section 2)
Basis for Standards (Section 3)
Format and Requirements of Standards (Section 4)
Applicability of Standards (Section 5)
Environmental Impacts (Section 6)
Control Costs (Section 7)
Economic Impacts (Section 8)
Modification and Reconstruction (Section 9)
Test Methods (Section 10)
Recordkeeping and Reporting (Section 11)
Miscellaneous (Section 12)
The comments, the issues they address, and EPA's responses are
discussed in the following sections of this document.
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2.0 NELL) FOR STANDARDS
This chapter summarizes public comments and responses to comments
on the need for the standards. Included are comments on the significance
of emissions and public health benefit of the standards, the adequacy
of current controls and regulations, industry growth and mobility, and
effects of seasonal variations in ozone formation.
2.1 SIGNIFICANCE OF EMISSIONS AND PUBLIC HEALTH IMPACT
Comment: Many commenters (IV-D-3; IV-D-20; IV-D-29; IV-D-31;
IV-F-4) questioned the significance of VOC emissions from yas plants.
The commenters questioned EPA's contention (or judgment) that VOC
emissions from natural gas plants contribute to air pollution signifi-
cantly enough to reasonably be expected to endanger the public health
and welfare and to violate the National Ambient Air Quality Standards
(NAAQS) for ozone. Commenter IV-D-3 questioned whether propane and
heavier gases break down in sunlight and air or whether they are
dispersed sufficiently so as to be of no significance. Commenter IV-F-4
claimed that natural gas processing plants are not large emitters of
VOC, particularly with the exclusion of methane and ethane. Commenter
IV-D-27 specifically felt that the oil and gas industry in the Rocky
Mountain region is not a significant contributor of VOC emissions.
Commenter IV-D-31 added that VOC as a class of compounds are not
criteria pollutants. Hydrocarbons as a class of pollutants under
the NAAQS were determined by EPA not to pose a direct threat to the
public health or welfare at typical ambient levels, and the NAAQS for
hydrocarbons were revoked on January 5, 1983.
Response: In response to the commenter's (IV-D-3) question about
the fate of propane and heavier gases when exposed to sunlight and air,
these gases do break down in the presence of sunlight and air; however,
they remain in the atmosphere long enough to participate in photochemical
reactions. Consequently, propane and heavier gases pose a significant
threat to the environment.
As reported in Table 1-1 of this document, an estimated 20,100 meyagrams
of VOC per year (Mg/yr) would be emitted from about 220 new, modified,
or reconstructed onshore natural gas processing plants in 1987 if no
additional controls were implemented by the industry. On an individual
plant basis, a typical medium-sized gas plant having nonfractionating
refrigeration units or fractionating cryogenic units is estimated to emit
about 100 Mg/yr assuming no additional controls. EPA considers both
nationwide and individual plant emissions from natural gas processing
plants to be significant based on the above estimates and on the listing
of crude oil and natural gas production on the EPA Priority List
(40 CFR 60.16, amended at 47 FR 951, January 8, 1982).
In consideration of the significant quantity of VOC emissions from
natural gas processing plants, EPA examined the "public health and
welfare" effects associated with these emissions. The Administrator
clearly documented the need to regulate VOC to protect public
health and welfare in the EPA publication "Air Quality Criteria for
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Ozone and Other Photochemical Oxidants" (EPA-600/8-78-004, April 1978).
VOC emissions are precursors to ozone formation, and ozone has been
determined to be harmful to human health and has been shown to have
environmental effects on vegetation and materials as well as other
damage to the ecosystem. Some of the health and welfare effects
associated with ozone exposure are the following:
Human health effects - Ozone exposure has been shown to cause
increased rates of respiratory symptoms, such as coughing, wheezing,
sneezing, and shortness of breath; increased rates of headache, eye
irritation, and throat irritation; and physiological damage to red
blood cells. Experimental data link ozone exposure to human cell damages
known as chromosomal aberrations.
Vegetation effects - Reduced crop yields as a result of damages to
leaves and/or plants are documented for several crops, including citrus,
grapes, and cotton. The reduction in crop yields is shown to be linked
to the level and duration of ozone exposure.
Materials effects - Ozone exposure is shown to accelerate the
deterioration of organic materials, such as plastics and rubber
(elastomers), textile dyes, fibers, and certain paints and coatings.
Ecosystem effects - Continued ozone exposure is linked to structural
changes of forests, such as the disappearance of certain tree species
(Ponderosa and Jeffrey pines) and death of some types of vegetation.
Hence, ozone causes stress to the ecosystem.
Commenter IV-D-31 correctly states that the NAAQS for hydrocarbons
were revoked. The revocation notice (48 FR 628), however, clearly
points out that " nonetheless, hydrocarbons should continue to be
controlled or restricted because of their contribution to the formation
of ozone and the resultant health and welfare effects of this pollutant
and other photochemical oxidant products." In addition, the notice
states that specific hydrocarbons (including VOC) which are shown to
cause adverse effects can be regulated separately. The notice does not
restrict EPA or State authority in regulating emissions of hydrocarbon
as a class, particularly hydrocarbon compounds or any other VOC that
may be found to pose a threat to public health or welfare.
Comment: One commenter (IV-D-3) questioned if the judgment of the
Administrator was a valid reason for implementing standards and asked
what facts back up this judgment.
Response: The judgment of the Administrator is a valid reason for
implementing standards. The Clean Air Act mandates that the
Administrator list a source category "... if in his judgment it [the
source category] causes, or contributes significantly to, air pollution
which may reasonably be anticipated to endanger public health or welfare"
[Section lll(b)(1)(A)]. The facts considered by the Administrator in
making this judgment include, but are not limited to, the quantity of
pollutant(s) emitted and the health and welfare effects associated
with the pollutant. The quantity of VOC emitted by the natural gas
2-2
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processing industry and the health and welfare effects associated with
ozone exposure are discussed in the response to the previous comment.
2.2 ADEQUACY OF CURRENT CONTROLS AND REGULATIONS
Comment: A number of commenters questioned the need for the
standards because, in their opinions, equipment leaks of VOC in this
industry may be adequately controlled by other regulations or approaches.
Several commenters (IV-D-12; IV-D-20; IV-D-31) felt that the proposed
standards are not necessary in areas where ozone ambient air standards
and Prevention of Significant Deterioration (PSD) requirements are
being met. Commenters IV-D-12 and IV-D-20 maintained that, while
large, urban, non-attainment areas might need to control VOC emissions
strictly, most natural gas plants (particularly in the West) are located
in remote, rural areas far from major population centers or ozone
nonattainment areas. Similarly, another commenter (IV-F-la) claimed
that the effects of the proposed standards would be regional, citing a
statement from the Oil and Gas Journal (July 18, 1983) that 90 percent
of allgas plants and industry capacity is located in five States.
Commenter IV-D-24 maintained that a State and local approach to
regulating gas plants would better take into account the many differ-
ences among gas plants and result in cheaper and more effective pollution
controls. The commenter noted that Ventura County, California, has a
fugitive emissions program covering gas plants and that the South Coast
Air Quality Management District (Los Angeles, Orange, Riverside, and
San Bernardino Counties) and Kern County are in the process of establishing
similar type regulations. The commenter was also concerned that the
proposed standards could remove a potential source of hydrocarbon
offsets in counties currently or predicted to become attainment for
ozone (i.e., Santa Barbara and San Luis Obispo). Commenter IV-D-31
added that there is ample EPA technical guidance (e.g., CTG and BID
documents for VOC equipment leaks from natural gas processing plants)
available to enable States and local agencies to make reasoned determi-
nations of best available control technology (BACT) under PSD regulations
if located in an attainment area and lowest achievable emission rate
(LAER) if located in a nonattainment area.
Response: In setting new source performance standards under
Section 111 of the Clean Air Act, location of the industry in attainment
or nonattainment areas is not relevant. Location of an industry in an
attainment or nonattainment area is relevant to achieving the National
Ambient Air Quality Standards (NAAQS) under Sections 109 and 110 of the
Clean Air Act. The NSPS complements the ambient air quality-based
rules as a means of achieving and maintaining the NAAQS and PSD
requirements, while on a broader basis it prevents new sources from
making air pollution problems worse, regardless of the existing quality
of ambient air. Similarly, in most cases State and local regulations
complement the NSPS. The intent of Congress in establishing NSPS was
to establish a uniform level of stringency nationwide, thereby preventing
States with lenient air pollution requirements from attracting new
industry construction. The standards will limit VOC emissions from
newly constructed, modified, and reconstructed facilities in natural
gas processing plants and will result in emission reductions well into
2-3
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the future. Even though these reductions may not bear directly now on
attainment or nonattainment of NAAQS for ozone, they will make room for
future industrial growth while attainment and nonattainment areas would
benefit from these standards.
Comment: One commenter (IV-D-3) stated that, in his opinion, the
proposed standards represent a prime example of government intervention
in an industry that is already overtaxed and overburdened with rules
and regulations. The industry has proven it can regulate itself and
has done a commendable job of self-regulation.
Response: The commenter's assertions regarding overtaxation,
overburdening, and self-regulation are unclear, and he provided no
supporting information about his claims. In the absence of the standards,
the natural gas processing industry will emit about 20,100 Mg/yr of VOC
emissions from equipment leaks, which reflects normal existing gas
plant operations with self-regulation plus State regulations (Table 1-1).
Uith the control requirements that will be implemented by the standards,
gas plants can achieve significant emission reductions at reasonable
costs. A total of 14,600 Mg/yr of VOC emissions are expected to be
reduced nationwide as a result of implementation of the control tech-
niques required by the standards. This represents an emission reduction
of 74 percent from existing levels, which already reflect self-regulation
plus State regulations.
Comment: One comrnenter (IV-D-12) pointed out that the industry
has several incentives to control VOC emissions. The entire justifi-
cation of the processing plant, according to the commenter, is to
extract liquid and heavy gaseous hydrocarbons for sale. Given the
current value of these hydrocarbons, the commenter maintained that the
industry has a large incentive to capture and sell as large a quantity
as reasonably possible. The commenter also noted the incentive of
preventing safety hazards associated with leak control.
Another commenter (IV-D-11) indicated that his company had spent
considerable time, effort, and money to establish leak prevention and
control procedures to comply with current regulations, and thus felt
that natural gas plant VOC leaks were adequately controlled already.
Similarly, another commenter (IV-D-22) noted that plant personnel
will detect most significant leaks visually or by sound during routine
daily inspections, and that it is standard operating procedure to repair
leaking equipment as soon as possible. The commenter added that
individual component surveys using a hydrocarbon detector or any other
type of instrument would be extremely time consuming and in many cases
impractical.
Response: EPA concurs with the first commenter on the industry
incentives to control emissions. These incentives form the basis for
the recovery credits used by EPA in calculating the net costs for
compliance with the standards.
The commenters imply that the standards are unnecessary due to
the industry's own safety and economic incentives to eliminate leaks
2-4
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or due to industry practices that have been implemented to comply with
current regulations. However, the data base used in development of the
standards shows that significant emissions do occur from equipment
leaks at natural gas processing plants. As given in Table 7-2 of the
BID for proposed standards, adjusted for the revised compressor seal
emission factor, the baseline emissions for a typical new gas plant
(Model Plant B) would be 274 kg VOC/day (100 Mg/yr). The data were based on
field testing of currently operating gas plants and reflect the emission
levels remaining after industry leak prevention measures have been
taken. The leak detection and repair programs and equipment requirements
of the standards are aimed at reducing as many of the leaks as possible
in a cost-effective manner and are expected to reduce VOC emissions by
about 74 percent.
The commenter's questions on the practical aspects of leak monitoring
are addressed in Chapters 4, 7, and 10.
2.3 INDUSTRY GROWTH, INDUSTRY MOBILITY, AND SEASONAL CONSIDERATIONS
Comment: Two commenters (IV-D-3; IV-D-29) questioned the need to
implement VOC regulations based on projections of growth in the industry.
One commenter (IV-D-3) reasoned that if natural gas production is
expected to decline as stated in Chapter 9 of the BID for the proposed
standards, air quality would improve without regulations.
The other commenter (IV-D-29) indicated that although a few additional
plants may be built, liquid gas production is on the decline. In the
commenter's opinion growth projections should be based on liquids pro-
duction, which are the source of VOC leaks, and not the number of plants.
Response: The commenters1 opinions are that the standards are not
necessary because emissions will decrease without standards due to an
expected decline in natural gas production and that growth projections
should be based on production instead of number of plants. The decrease
in natural gas production is not relevant to the need for new source
performance standards. The necessity of the standards is based on
projected growth within the industry and the potential for long-term
improvement in air quality. Even though older gas plants may be shut-
down, new gas plants will be built, as the second commenter correctly
pointed out. Contrary to the commenter's opinion, the projected
number of new plants is the appropriate measure for the impacts of the
standards, as emissions reductions are achievable as new facilities
become regulated. The general goal of NSPS is to require new facilities
to incorporate best demonstrated technology as they are being constructed.
EPA has estimated that 180 newly constructed and 40 modified and
reconstructed gas plants will be affected by the standards through
1987. These plants can achieve significant emission reductions at
reasonable costs.
Comment: Several commenters (IV-D-26, IV-D-29; IV-D-31; IV-D-35)
contended that national standards for natural gas processing are not
mandated because, among other reasons, natural gas plants are not geo-
graphically mobile and must locate near the source of gas. As such,
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States cannot compete for gas processing plants based on relaxed air
quality standards.
Response: The considerations upon which the standards are based,
as required by Section 111, include the quantity of air pollutant emissions
from the source category, the extent to which the pollutant may reasonably
be anticipated to endanger public health or welfare, and the availability
of a demonstrated system of continuous emission reduction considering
costs, nonair quality health and environmental impacts, and energy
requirements. Therefore, mobility and competitive nature of the industry
are not the only criteria that were considered. The first two factors,
quantity of emissions and public health and welfare impacts, support
the listing of this source category as discussed in Section 2.1.
Comment: One commenter (IV-D-31) stated that ozone formation is
accepted by the scientific community as being a seasonal phenomenon,
and that a review of the information pertaining to the formation of
ozone and the demonstrated lack of adverse public health or welfare
effects due to VOC emissions per se would lead to the conclusion that
VOC emissions cannot be considered to endanger the public health or
welfare during the months of October through April.
Since one of the underlying premises of the NSPS program as
embodied in Section 111 of the Clean Air Act is that the source category
being regulated emits a* pollutant which can reasonably be anticipated
to endanger the public health or welfare, the commenter recommended
that, at a minimum, the scope of the NSPS be limited to the months of
May through September, during which time there would at least be some
potential for environmental benefit.
Response: Sections lll(a)(l) and 302(1) of the Clean Air Act
require that NSPS reflect systems of continuous emission reduction.
As explained elsewhere, these standards reflect such systems, which are
operable throughout the year.
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3.0 BASIS FOR STANDARDS
3.1 INTRODUCTION
Section 111 of the Clean Air Act, as amended, requires that
standards of performance be based on the best system of continuous
emission reduction that has been adequately demonstrated, considering
costs, nonair quality health and environmental impacts, and energy
requirements. The following sections present the basis for the promul-
gated standards for each type of equipment and any changes in the basis
since proposal. The selection of the basis for the promulgated standards
was based on an analysis of the VOC emission reductions, control costs,
the cost effectiveness, and the incremental cost effectiveness for the
control techniques considered. These impacts are summarized in Table 3-1.
3.2 VALVES
In selecting the basis of the standards for valves, EPA considered
quarterly and monthly monitoring periods. Each of these intervals was
compared in terms of the emission reduction achievable and cost
effectiveness of the leak detection and repair program as presented in
Appendix H of the BID for the proposed standards. At proposal , monthly
monitoring was selected as the basis of the standards for valves
because it achieves the largest emission reduction, 40.4 Mg per year
for Model Plant B. The EPA also judged that monthly monitoring has a
reasonable cost effectiveness, $7 per Mg. However, EPA also recognized
at proposal that some valves have lower leak occurrence rates than
others. Monthly monitoring of valves that do not leak for 2 consecutive
months was judged to be unreasonable when compared to the additional
emission reduction achieved by monthly monitoring over quarterly
monitoring. Therefore, although EPA proposed that leak detection and
repair programs include monthly monitoring for valves, the proposed
standards allowed quarterly monitoring for valves that have been found
not to leak for 2 successive months. The annual emission reduction
achieved by this monthly/quarterly implementation would be 37.7 Mg for
Model Plant B. The cost effectiveness and incremental cost effectiveness
would be a credit of $100/Mg and a cost of $240/Mg, respectively. The
promulgated standards are based on monthly/quarterly implementation,
which was allowed at proposal.
3.3 PUMPS
In selecting the basis for pump requirements, EPA considered
quarterly leak detection and repair, monthly leak detection and repair,
and the installation of dual mechanical seals. As with valves, the
three alternative control levels were examined to determine the
achievable emission reduction, the net cost of the control technique,
and the resulting cost effectiveness. Also examined was the incremental
cost effectiveness resulting from dividing the increased cost of the
next more stringent control technique by the resulting emission reduction
i ncrease.
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Although dual mechanical seals provided the greatest emission
reduction (2.6 Mg/yr for Model Plant B) for pumps, the cost effectiveness
($4,900/Mg) and incremental cost effectiveness ($31,000/Mg) were considered
unreasonable. Monthly monitoring, however, resulted in emission reductions
of 2.3 Mg/yr, at a cost effectiveness of $610/Mg, which EPA considered
reasonable. The incremental cost effectiveness of monthly monitoring
over quarterly monitoring, $800/Mg, was also considered reasonable. As
such, monthly monitoring was selected as the basis for the proposed
standards, and remains the basis for the promulgated standards.
3.4 COMPRESSORS
The requirements for compressors have been changed since proposal
to exempt all reciprocating compressors in wet gas (field gas) service.
In preparing the basis for the proposed standards, EPA averaged the
cost effectiveness for reciprocating and centrifugal compressors (based
on one half of all compressors being centrifugal), and wet gas and
natural gas liquids (NGL) service (based on 34 percent of all compressors
being in NGL service and 66 percent of all compressors being in wet gas
service). Since the resulting cost effectiveness ($460/Mg) was considered
reasonable, EPA required the installation of closed vent systems on all
compressors except wet gas reciprocating compressors in plants without
a control device.
Table 3-1 shows the emission reductions and cost effectiveness for
a closed vent system for wet gas and NGL reciprocating and centrifugal
compressors. The EPA considers the average cost effectiveness ($1950/Mg)
of control systems on all wet gas reciprocating compressors at plants
with and without a control device to be unreasonable and, therefore,
has exempted these compressors from the promulgated standards.
Reciprocating compressors in NGL service and centrifugal compressors in
wet gas or NGL service can be equipped with closed vent and control
systems at a reasonable cost effectiveness ($250/Mg, $500/Mg, and
$64/Mg, respectively) and remain subject to the requirements of the
promulgated standards.
3.5 OPEN-ENDED LINES
The basis for the promulgated standards for open-ended lines
remains the same as the basis at proposal. The EPA estimated that
capping or adding a second valve to all open-ended lines will reduce
emissions from a typical (Model Plant B) plant by 19 Mg/yr, while
saving the industry $103/Mg.
3.6 PRESSURE RELIEF DEVICES
The basis for the standards for pressure relief devices is a
routine leak detection and repair program with quarterly monitoring.
In selecting standards for pressure relief devices, EPA considered
three regulatory alternatives, including the selected quarterly leak
detection and repair program, a monthly leak detection and repair
program, and the installation of rupture disks upstream of relief
devices to prevent emissions.
3-2
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TABLE 3-1. CONTROL COSTS PER MEGAGRAM OF VOC REDUCED0
Fugitive Emission Source
Pressure relief devices
Compressors'1
reclproca ting-wet gas
rec1procating-NGL
centrifugal -wet gas
centrifugal -NGL
Open-ended valves and lines
Sampling connections
Valves
Pumps
Control technique1"
Quarterly leak detection and
repair'
Monthly leak detection and
repair
Rupture disks
Closed vent and seal system
Closed vent and seal systemf
Closed vent and seal system^
tiosed vent and seal systemr
Caps on open endsf
Closed purge sampling1
Quarterly leak detection and
repair
Monthly/Quarterly leakf
detection and repair
Monthly leak detection
and repair
Quarterly leak detection
and repair
Monthly leak detect1onf
and repair
Dual mechanical seals
Emission
Reduct1onc,
Mg/yr
0.95
1.0
1.5
4.2
33
4.2
33
19
0.22
7.3
7.7
0.4
2.0
2.3
2.6
Average'',
$/Mg
(610)9
0
6,800
1.950J
250J
500J
64J
(103)
7,000
(104)
(100)
7
590
610
4,900
Incremental e,
S/Mg
(610)
5 800
22,000
1,950
250
500
64
(103)
7,000
(104)
240
1,450
590
800
31,000
aThe control costs per VOC emission reduction are considered typical of control techniques for
equipment leaks 1n gas processing plants and are used 1n selecting the level of control required
by the standards. H
further discussion of control techniques used can be found In Chapter 4.
^Emission reductions are for Model Plant B: 12 pressure relief valves. 6 compressor seals
150 open-ended valves or lines, 6 liquid service and 6 gas service sampling connections '
750 valves, and 6 pump seals.
<*Average dollars per megagram - (net annual cost of the control technique - emission reduction
of the control technique).
elncremental dollars per megagram = (net annual cost of the control technique - net annual cost
of the next ess restrictive control technique) (annual emission reduction of control technique -
annual emission reduction of the next less restrictive control technique).
fControl techniques selected as basis for the final standards are underlined.
9Parentheses denote cost savings.
"Emission reduction and costs for compressors are from the BID for the proposed standards
Appendix H, Table 3. Costs based on half of all compressors requiring a dedicated control device.
iCosts and emission reduction for closed purge sampling represent both Inlet gas
sampling and product liquids sampling. S
JThese mjmbers are based on an average of the cost-effectiveness numbers for compressors
with and without a control device (BID for proposed standard. Appendix G, Table 1).
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Although monthly leak detection and repair provided greater emis-
sions reduction (1.0 Mg/yr) than quarterly leak detection and repair
(0.95 Mg/yr), and the average cost effectiveness was reasonable ($0/Mg),
the incremental cost effectiveness was not reasonable. The incremental
cost effectiveness of $5,800/Mg between monthly monitoring and quarterly
monitoring indicates that, since 0.95 Mg/yr VOC emissions can be reduced
with quarterly monitoring at an industry savings of $610/Mg, the
remaining 0.05 Mg/yr attributable to monthly monitoring requires an
industry expenditure of $5,800/Mg.
The EPA also considered the installation of upstream rupture disks
as a regulatory alternative. Rupture disks would result in essentially
100 percent emissions reduction, or 1.5 Mg/yr for a typical plant.
However, the average ($6,800/Mg) and incremental ($22,000/Mg) cost
effectiveness values were not considered reasonable.
Based on all of these data, EPA selected quarterly leak detection,
and repair as the basis for the promulgated standards for pressure
relief devices.
3.7 SAMPLING CONNECTIONS
The EPA considered a single regulatory alternative, closed purge
sampling, to control VOC emissions during purging of sampling systems.
However, examination of the costs and emissions reductions for closed
purge sampling indicated that the cost effectiveness ($7,000/Mg) was
unreasonable. Therefore, there are no requirements in the standards
for sampling connections.
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4.0 FORMAT AND REQUIREMENTS OF STANDARDS
4.1 FORMAT OF STANDARDS
Comment: One coinmenter (IV-D-12) stated that the approach taken
by F.PA in setting standards for various pieces of equipment to control
VOC emissions is unnecessary, noting that in other industries EPA has
allowed a bubble concept for the aggregation of total emissions from
large facilities.
The cornmenter indicated that if EPA can demonstrate that total VOC
emissions from a specific plant need to be controlled due to an ambient
ozone violation in the area, the Agency should provide a total VOC
emissions limit for the plant and let the plant determine the most
appropriate means of meeting the emissions limit.
The coinmenter specifically suggested that EPA revise the proposed
standards to set a total emission standard for a plant of approximately
150 pounds per day of VOC from valves and process equipment. In using
this limit, the commenter stated that a plant operator could choose
technology and operating procedures tailored for the specific plant
design and could decide on necessary recordkeeping and maintenance
scheduling as appropriate to meet the limit. The commenter believed
that several other industries are regulated in this way under 40 CFR 60.
Response: A combination of equipment, work practice, design, and
operational standards was selected as the format of the standards for
process units and compressors (i.e., the affected facilities). Different
formats are required for different types of leaking equipment because
characteristics of the equipment, the available emission control
techniques, and the applicability of the measurement method used for
equipment leaks differ.
Setting a single emission limit for a given plant would be
impracticable because the cost associated with measuring emissions from
each potentially leaking piece of equipment would be unreasonable for
most plants. In addition, the emissions limit (if one were set for the
entire plant) would likely be nearly zero because most pieces of equip-
ment do not leak. (The emissions from a few pieces of equipment that
may leak averaged with emissions from the majority of equipment that may
not leak would be close to zero.)
The EPA is developing a policy for approving NSPS bubbles on a
case-by-case basis. This policy will be proposed in the Federal Register
in the near future. Applications for NSPS bubbles will be considired
in accordance with this policy.
4.2 VALVES
4.2.1 Difficult-to-Monitor Valves
CommentlOne commenter (IV-D-30) stated that difficult-to-monitor
valves can not be eliminated from new facilities, and recommended that
difficult-to-monitor valves in new facilities be subject to the same
annual inspection requirements as those in modified or reconstructed
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facilities. The comrnenter noted that block valves under relief valves,
open-ended valves for testing of relief devices, and certain open-ended
valves for purging equipment at start-up must be placed in high locations.
Another commenter (IV-D-37) suggested that up to 10 percent of valves
in general should be considered difficult to monitor and should be
exempted from monitoring requirements except annual visual inspections.
Response: Upon reviewing the comments on the proposed standards,
EPA accepts that eliminating all difficult-to-monitor valves from new
facilities may substantially increase the costs of constructing new
facilities, for example, due to the necessity for additional fixed
ladders and platforms. Estimation of these additional costs is not
possible due to the wide variability of factors such as the height of
the valves and the ability to co-locate di ff icul t-to-rnonitor valves.
Commenter IV-D-30 did not provide any data to indicate how many
valves in new gas processing plants would be difficult to monitor.
Although commenter IV-D-37 suggested that 10 percent of valves in
general should be considered difficult to monitor, no basis for this
number was given. The EPA expects the proportion of diff icul t-to-rnoni tor
valves in gas plants to be similar to that of refineries. A refinery
maintenance study (Docket Item II-A-11) found that about 3 percent of
over 8,000 total valves investigated could not be reached without
extraordinary aids such as scaffolding or cherry pickers. Based o-n
this study and on telephone conversations with refinery process design
engineers (Docket Item IV-B-8), the Agency believes the 3 percent
figure is accurate representation for gas plants. Therefore, the
promulgated standards allow the owner or operator of a newly constructed
facility to designate up to 3 percent of its valves as difficult to
monitor. The standards require annual monitoring of these valves.
Limiting the percentage of allowable valves that may be difficult to
monitor provides the incentive to minimize the number of such valves in
new units, while ensuring that an owner .or operator would not incur
unreasonable costs by attempting to eliminate all difficult-to-monitor
valves in new units.
Comment: One commenter (II-D-10) noted difficulties in performing
monitoring of valves located atop gas plant towers since they are not
equipped with platforms. In addition, the commenter remarked that not
all valves are accessible, and many valves cannot be reached or monitored
in 1 minute. The commenter also noted that the economic analysis in
the draft NAPCTAC BID did not consider relocation of components to
eliminate "difficult-to-monitor" valves.
Response: Provisions for difficult-to-monitor valves have been
added to the standards since this comment was written in May 1981.
Less frequent monitoring (annual) for difficult-to-monitor valves was
allowed for existing plants in the proposed standards, while annual
monitoring for all di ff icul t-to-inoni tor valves is being allowed
in the final standards, since monitoring of these valves on a monthly
basis is not cost effective. The EPA used 1 minute per valve as an
average monitoring time based on actual process unit testing. Since
the 1 minute value represents an average monitoring time for all valves,
some valves may take longer, while others will take less time. The
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cost of monitoring valves is based on the 1-minute average; therefore,
1 minute is considered to be a reasonable monitoring time for all valves.
4.2.2 A1ternative Standards
Comment: One commenter (IV-D-20) commended EPA for developing
alternative standards for valves in VOC service. However, the cornmenter
stated that 2.0 percent allowable leakers may not be an attainable
standard. The commenter stated that his company operates several gas
plants with less than 20 valves in VOC service, and that a leak in only
one valve would therefore result in a violation. The commenter recommended
that the standard be changed to 10 percent allowable leakers or at
least one valve leaking over the inspection interval at each facility.
The commenter recommended that the second alternative standard for
valves (skip-period monitoring) be retained except for changing the
allowed 2 percent leakers to 10 percent.
Response: Alternative standards for valves have been provided in
the standards because EPA judged that the emission reduction and the
annual cost relationship is unreasonably high for process units that
have fewer than 1.0 percent of valves leaking over an extended period.
Due to the variability in valve leak detection, process units that
average less than 1.0 percent of valves leaking will have, at times,
more than 1.0 percent of valves leaking. Therefore, to provide for the
variability in leak detection, EPA set the allowable percentage of valves
leaking for any point in time at 2.0 percent. (A complete description
of the methodology used to determine the allowable percentage of valves
leaking is presented in Docket Item II-B-43.)
The allowable percentage of valves leaking applies to alternative
standards for valves, hence, owners or operators are not required to meet
a percentage of valves leaking unless they elect to do so. Also, under
the skip monitoring alternative standards, if greater than 2.0 percent
valves are detected leaking, a violation has not necessarily occurred.
Owners or operators would simply be required to return to monthly/quarterly
leak detection and repair. If, as the commenter claims, a gas plant has
less than 20 valves in VOC service, the owner or operator may elect to
follow an alternative standard for valves. However, one valve leaking
would exceed the allowable percentage (2.0) of valves leaking. Since
20 valves would require very little time to monitor, alternative
standards are really unnecessary. The EPA does not expect many gas plants
processing more than 10 MMscfd with 20 valves or less.
Comment: One cornmenter (II-B-23) requested that a "reference leak
detection program" be defined in Section 60.633-2 of the regulation.
Response: A "reference leak detection program" is simply the
requirements for valves in Section 60.632-6, namely, a monthly/quarterly
leak detection and repair program. The required standards serve as the
basis for the skip period leak detection and repair alternative standards.
After an owner or operator has demonstrated that he can maintain a
performance level of 2 percent or less for either 2 or 5 consecutive
quarters using the required standards as the "reference leak detection
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program, " then the owner or operator Cdn reduce the monitoring f re
-------
Response: Visual inspection of pumps is necessary to check for
liquids dripping from the seal. As the seal wears over time, VOC
leakage is likely to increase, so it is important to monitor pumps on a
regular basis. As stated in Table 8-3 of the BID for the proposed
standards, weekly visual inspections would take about one-half minute
per pump or about 10 minutes per week (9 hours per year) for one person
at a large plant with about 20 pumps. The annual cost of these visual
inspections would be about $160 (June 1980 dollars). The cost of weekly
visual inspection is reasonable. The EPA has concluded that this
situation is not likely to occur.
4.4 COMPRESSORS
Comment: Several commenters (II-B-23; II-D-10; II-D-30; IV-D-13;
IV-D-15; IV-D-19; IV-D-21; IV-D-23; IV-D-24; IV-D-26; IV-D-27; IV-D-29;
IV-D-30; IV-D-31; IV-D-35; IV-D-33; IV-D-34; IV-D-36; IV-F-la; IV-F-lc;
IV-F-le) expressed concerns about potential safety hazards associated
with the installation of closed vent systems on reciprocating compressors.
The commenters stated that compressors must be equipped with
foolproof systems to prevent pressurizing the distance piece and must
absolutely prevent the intrusion of air and backpressure from the flare
header. Additionally, flow of the compressed gas into the compressor
driver crankcase must be prevented.
Other commenters stated that, where existing control devices do
exist, they are often used to control sour gas. Since the gas-contacting
surfaces of the compressors are not metallurgically compatible with
sour gas, tie-in to the existing control device would not be possible
due to potential corrosion problems.
Similarly, other commenters (IV-D-33; IV-D-36) said their experience
shows the only times they would consider it a safe practice of tying a
distance piece into a closed vent system to a control device is when a
low pressure flare system is available.
The commenter further noted that some gas plants use flare systems
solely for high pressure process vessel relief, such as straddle type
plants, plants processing naturally occurring high pressure field gas,
or plants where compression is done in the field prior to plant
processing. The commenter stated that their experience shows that d
check valve is not sufficient to prevent backpressure on the flare
header from pressurizing the distance piece. The commenter recommended,
at the very least, that the requirement for tying the distance piece
into a closed vent system be evaluated on a case-by-case basis. In
addition, the commenter had no objection from a safety viewpoint to
tying the packing vent into a closed vent system and maintained that
the majority of compressor VOC emissions would be controlled with
just the packing vents tied to a closed vent system. The commenter
cited a letter (Docket No. II-D-44) previously submitted that supports
their safety concern for pressurizing single distance pieces.
Another commenter (II-D-10) stated that tying seal emissions back
into the compressor inlet was not viable because of pressure considerations,
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All of these commenters recommended that EPA exempt reciprocauny
compressors from the standards.
Response: The commenters1 primary concerns are pressurization of
the compressor distance piece and flow of the compressed product into
the driver crankcase. The EPA cost analysis was based on equipping the
compressors with two-compartment distance pieces, which are designed to
collect hazardous or toxic gases. The two-compartment distance pieces
allow for the compressor side compartment to be sealed and vented to a
control device, while the crankcase side compartment may remain open to
the atmosphere. By allowing the crankcase side to remain open, the
"break" between the compressor and the driver crankcase is maintained,
preventing the flow of compressed gases into the crankcase. Double
distance pieces have been recognized by the industry as a safe method
of seal gas collection for at least 10 years, as evidenced by the 1974
API Reciprocating Compressor Standard.1
Given that the flow of gas into the compressor crankcase may
be prevented using double distance pieces, the remaining concern of the
commenters was that the distance pieces might become pressurized from
the flare header or develop explosive atmospheres due to air intrusion.
In order to ensure that the distance pieces did not become over-
pressurized, EPA recommended several safety features, as follows:
Distance pieces should be routed to the flare through a separate
flare line, and not the plant's main flare header. The EPA
included the cost of-100 meters (300 feet) of 2-inch pipe
for this purpose.
Each distance piece would be equipped with a check valve to
prevent backflow, and the flare line would be equipped with a
low-burst pressure rupture disk to relieve any catastrophic
failures.
The system should be pressurized. A water-sealed trap was
included in the flare line to prevent air intrusion.
Although no system can be made entirely failsafe, EPA has estimated the
costs for a control system for compressors which, although simple in
design, was designed with safety as the primary consideration.
Several commenters indicated that, where existing flares were in
sour gas service or high-pressure service, a dedicated control device
could be required for the compressor vent control system. The EPA
recognized at proposal that, in many cases, yas plants would not have a
control device present, and exempted wet gas reciprocating compressors
in plants where a control device was not already present. However,
based on the comments received since proposal, and the unreasonable
cost effectiveness of wet gas reciprocating compressor controls used at
more plants than EPA estimated at proposal, EPA has decided to exempt
1
API Standard 618, 2nd Edition, July 1974. Docket Item No. II-I-35.
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all wet gas reciprocating compressors from the promulgated standards
(see Section 7.2). However, since installation of a control device is
cost effective for wet gas centrifugal compressors and all compressors
in natural gas liquids service, control of these compressors is still
required by the promulgated standards (Docket Item IV-B-7).
Numerous control techniques are available for compressor seal
emissions. Some plants may not be able to pipe emissions into a
compressor inlet, as noted by the commenter. The EPA also recognizes
that some plants do not have suitable flares available, as use of a
high pressure flare would require an auxiliary compressor. Hence, EPA
included the cost of a suitable low pressure flare, which would not
require an auxiliary compressor, in the cost analysis presented in the
BID for the proposed standards (Appendix G).
Comment: One commenter (IV-F-la) stated that compressors should
be exempt from the standards because the control of emissions from them
requires the greatest capital investments while providing the lowest
cost effectiveness.
Similarly, another commenter (IV-D-24) noted that Table 3-2 of the
BID for the proposed standards shows that compressors represent only
2 percent of the EPA's total estimated VOC leakage. He concluded that
the increased risk and cost of controlling compressor emissions is not
justified.
Response: Compressor emissions, as shown in the BID for the pro-
posed standards, Appendix H, are 15.8 percent of all gas plant emissions.
When examining the selection of best demonstrated technology (BDT)
considering costs for the standards, EPA compared available demonstrated
controls for each type of source. For compressor seals, closed vent
and seal systems were considered as the only available demonstrated
technology. Since the use of closed vent and seal systems can be
accomplished at reasonable cost and cost effectiveness, the controls
are required. The EPA does, however, consider the costs of controlling
reciprocating compressors in wet gas service to be unreasonable and has
exempted those compressors from the promulgated standards.
4.5 OPEN-ENDED LINES
Comment: Two commenters (IV-D-15 and IV-D-24) opposed the require-
ments in Section 60.632-5 to plug open-ended valves or lines because they
present a potential safety hazard. The open end is frequently some
distance downstream from the valve, and there could be significant
safety hazards if the operator fails to remove the covering prior to
opening the drain valve or purging valve. One commenter (IV-D-15)
said there was a need to include an alternative standard for frequently
used valves, such as to sample the outlet quarterly. One commenter
(IV-D-24) questioned the accessibility of the open ends noting that a
vent line may be on a riser pipe well above the work area or a drain
line may dump into a sump tank. He further questioned the benefit of
the open-ended line requirements because many lines must be routinely
opened to vent, purge, sample or drain some system, and any fugitive
emissions would be released at that time.
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In contrast, one commenter (IV-D-20) agreed with the use of caps,
plugs, and second valves to control leakage from open-ended lines. The
commenter stated that the practice was already being done in his
company's gas plants.
Response: The standards for open-ended valves or lines provide
operators the flexibility to add either a cap, blind flange, plug, or a
second valve, depending upon the individual application. The EPA
acknowledges that plugging open-ended valves or lines may present
a potential safety hazard in certain situations. Accordingly, if a
second valve is used, the standards require that the upstream valve be
closed before closing the downstream valve. This operational requirement
is merely sound practice that plant operators currently follow to
prevent process fluid from being trapped between the valves. If hot
(or cold) product is trapped between the two valves, as it contracts
(expands) from cooling (heating) to ambient temperature, it could cause
the pipe, the valve stem, or the valve seat to fail. Should the inner
valve leak through the valve seat, however, the product will eventually
fill the piping between the valves with ambient temperature fluid
without stressing the valve seat.
The standards provide sufficient flexibility for the operator's
concern with plugging frequently used valves. Adding a second
valve avoids the risk of premature failure of pipe connections caused
by the frequent removal of a cap or plug.
Leak detection and repair for the control of VOC emissions from
open-ended valves or lines is inappropriate because it would achieve
less emission reduction and may cost more to implement than the equipment
and operational standards for open-ended valves because of repeated
inspections of nonleaking sources.
Comment: One commenter (II-D-10) questioned EPA's recommendation
to use teflon tape to seal threaded connections. The commenter noted
that teflon tape works well for small sizes (2-inch nominal diameter
and smaller); however, the sealing ability on larger sizes has not
proved satisfactory.
Response: Joints larger than 2 inches in diameter are usually
either flanged or welded, and not threaded. The EPA's point discussed
in the BID for the proposed standards is reiterated by the commenter,
namely, that leaks from small threaded connections can be reduced by
using teflon tape on the threads before the connection is made. The EPA
makes no claim that the tape is effective on larger connections.
Most open-ended lines subject to the standards would be 2 inches
or smaller in diameter. These lines could be sealed with teflon tape
on the appropriate cap or plug. Although the standards would require
the closure of larger open-ended lines, which would require more costly
control, the cost of plugging open-ended lines is based on the addition
of a second valve instead of a cap or plug. In most cases, small
open-ended lines can be capped or plugged at significantly lower cost
than with the second valve assumed by EPA. Large blind flanges cost
about the same as small valves and, therefore, are reasonable.
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4.6 PRESSURE RELIEF DEVICES
4.6.1 Annual Certification
Comment: One commenter (IV-D-15) offered an alternative method of
achieving at least equivalent emission control of pressure relief devices
because he thought the testing, reporting, and recordkeeping of the
hundreds of relief valves that would typically be installed in a new
plant would be an immense burden. Also, the additional investment to
tie all relief valves into a closed system to gain exemption from
monitoring would be large. The commenter preferred to follow certain
design criteria and test practices to verify relief set pressures.
The commenter proposed that an operator annually certify that these
conditions are met. The commenter also stated that relief valves should
be exempt when burst-heads and test inserts are installed. The commenter
further wrote that if such installations are made for operator design
considerations, then control effectiveness should be acknowledged, and
the relief valve should be exempt from monitoring, compliance testing,
and reporting.
Response: The EPA considered alternative control techniques,
including rupture disk (burst-heat) installations, leak detection and
repair, and no control (baseline) for pressure relief devices prior to
proposing the standards. The routine leak detection and repair require-
ments selected for inclusion in the proposed standards were estimated
(BID for proposed standards, page H-4) to reduce VOC emissions from
relief devices by 0.076 Mg/yr per valve, with a savings to industry of
$46/device-year. As such, the quarterly leak detection and repair
program required by the standards will result in a savings to industry
while reducing VOC emissions.
The commenter offered an alternative control technique for relief
devices based on verification of set pressure and certain relief device
design criteria, apparently based on the assumption that relief device
leaks are the result of valve openings during operation. However, most
relief device leaks are from "closed" valves and are the result of
corrosion and/or improper reseating after a pressure release. As such,
set-pressure verification would not ensure that a pressure relief
device would not leak. The standards, therefore, remain unchanged.
The commenter also requested a blanket exclusion for relief devices
equipped with rupture disks and test inserts. The EPA considers rupture
disk systems to be effective control devices for emissions from
pressure relief devices. Relief devices equipped with rupture disks
may be designated for "no detectable emissions" and require only an
initial acceptance test and annual compliance tests to ensure proper
installation and operation. Since rupture disks may burst or develop
leaks through corrosion, annual performance tests, as well as rapid
(5-day) replacement after they burst, are necessary; therefore, the
standards remain unchanged.
4.6.2 Rupture Disks
Comment: One commenter (IV-D-20) stated that control of VOC
emissions from pressure relief devices by installation of a rupture disk
upstream or downstream creates potential safety problems. Furthermore,
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the commenter claimed that pressure relief devices are already checked
and maintained in as leak-free condition as possible since leaks would
result in the loss of valuable hydrocarbon products.
Response: The standards for pressure relief devices are based on
quarterly leak detection and repair; however, the standards allow
operators to use control techniques that achieve emission reductions
equivalent to quarterly leak detection and repair. The EPA has determined
that pressure relief devices that comply with the "no detectable emissions"
limit and pressure relief devices that are controlled through a closed
vent system to a control device would achieve equivalent emission
reductions.
Rupture disks eliminate equipment leaks of VOC through the relief
device unless an overpressure occurs. After an overpressure release,
replacement of the rupture disk once again eliminates equipment leaks.
Pressure relief devices are required to operate with no detectable
emissions as indicated by an instrument reading of less than 500 ppm
above background and are required to return to this condition within
5 days following a pressure release.
While it is possible that operators would not use rupture disks
because of safety concerns, rupture disks are allowed in the standards
and they are presently used in gas plants. If a rupture disk is used,
a pressure sensor could be installed to warn operators if a pressure
increase has occurred between the disk and relief valve.
4.6.3 Accessibility Rechecks
Comment: Several commenters (IV-D-19, IV-D-21, IV-D-23, IV-D-26,
IV-D-30, IV-D-36, and IV-F-4) requested that EPA revise the monitoring
requirements for pressure relief devices. The commenters stated that
relief devices cannot be placed in accessible locations for safety
reasons. Commenters (IV-D-23 and IV-D-30) contended that elevating
relief valves (i.e., atop towers and columns) provides for better
atmospheric dispersion of any released hydrocarbons to minimize explosion
hazards. Therefore, relief devices are accessible only by adding
ladders and platforms or by crane, and these costs were not included in
considering the economic costs of this rule. One commenter (IV-D-30)
also pointed out that elevated relief valves will have fewer emissions
than relief valves at lower locations in equipment processing both gas
and liquid phases because a smaller mass of gas would be released to
provide the same pressure drop.
One commenter (IV-D-23) thought that there was no benefit to the
requirement that pressure relief devices be monitored within 5 days of
relieving because leaking pressure relief valves cannot be repaired until
the unit is shutdown. Also, at an unmanned or partially manned plant, a
relief valve could relieve without anyone's knowledge. Other commenters
(IV-D-36 and IV-D-26) suggested retesting relief valves after over-
pressures at the next scheduled monitoring of valves and pumps. These
commenters pointed out that many facilities will be utilizing contract
services to handle their leak detection and repair, and a special trip
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(costing in excess of $1,000) would be required to recheck a pressure
relief device after an overpressure. Another commenter (IV-F-4) requested
that EPA allow a 14-day period for retesting of relief devices after
overpressures. One commenter (IV-D-21) added that inspection of pressure
relief valves following each pressure release is difficult to arrange
since the economics of small to mid-size plants will not allow either
the necessary instruments or the instrument technicians to be available
at all times.
One commenter (IV-D-19) recommended monitoring pressure relief
devices 1 week after each pressure relief and disregard quarterly
monitoring because relief devices will leak within the first week after
relieving, or not at all. This commenter argued that quarterly monitoring
would be an unnecessary duplication of effort. Another commenter (IV-D-30)
suggested that relief valves be subject to annual leak detection and
repair as are difficult-to-monitor valves.
Response: As presented in the background information document for
the proposed standards, emissions from pressure relief devices in natural
gas plants can be reduced by 0.076 Mg/year per pressure relief device
by implementing quarterly leak detection and repair. This emission
reduction value, which was based on emission measurements at gas
processing plants, resulted in the product savings ($73/device-year)
being almost triple the costs ($27/device-year) of monitoring. The
statement made by commenter IV-D-30 is not relevant since the elevation
of a pressure relief device for gas phase service does not affect the
amount of gas released. An elevated relief device in liquid phase
service would affect the mass of emissions. However, very few, if any,
pressure relief devices at gas plants would be in liquid service, and
the standards apply only to gas service relief devices. The EPA based
the emission factor for pressure relief devices on gas phase releases
only' because few relief devices are used in liquid phase service.
Commenter IV-D-19 is incorrect in stating that relief devices will
leak within 1 week or not at all. While it may be true that significant
leakage due to improper seating or unseating of the relief valve occurs
relatively soon after a release, minor leaks may develop over longer
periods due to corrosion or valve "chatter". Since safety regulations
already require most pressure relief devices to be inspected annually,
EPA requires only three additional inspections per year. Pressure
relief devices could be monitored at each quarterly inspection using
the same equipment that is used during the current annual inspections.
Quarterly inspections could improve plant safety through both leak
detection and detection of closed block valves.
One commenter contended that relief valves cannot be repaired
without a shutdown. While this is true in some cases, most relief
valves are equipped with upstream block valves to allow testing or
replacement of the relief valve while the unit is in operation. These
relief valves may be repaired with the unit in operation.
Several commenters expressed concern about performing rechecks on
pressure relief devices within 5 days of a pressure release, since
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monitoring personnel and instruments may not be available. The EPA
recognizes that many small plants will use contractors or central
office personnel to perform routine monitoring and that in these cases
the monitoring team is not available except during scheduled test periods.
In these situations, EPA believes that the cost of obtaining the
monitoring services for a single relief valve would be unreasonably
high. Therefore, the final standards allow small plants that are not
monitored by on-site personnel to delay rechecks up to 30 days after a
pressure release.
Comment: One commenter (II-D-10) questioned the benefit of monitoring
safety valves/rupture disks considering the inherent danger in monitoring
them. In support of his concern, the commenter added that a person who
is monitoring when a high pressure release occurs could be injured or
killed, particularly if the person is holding onto a ladder near the
top of the vessel and is handling all the paraphernalia required for
monitoring. The commenter noted that gas plants normally have relief
valves and/or rupture disks installed on top of vessels or columns
without access platforms.
Response: The standards for gas service pressure relief devices
in natural gas processing plants are work practices consisting of a
quarterly leak detection and repair program. The pressure relief
devices are also required to be monitored within 5 days after each
overpressure to determine if a leak has occurred as a result of the
overpressure. Monitoring of these devices should be performed by
personnel who understand the precautions and practices recommended by
industry and ASME codes. If a pressure relief device is likely to
relieve when monitoring occurs, then special precautions, such as
monitoring of process conditions (temperature and pressures), should be
taken by the owner or operator. Based on EPA's experience in collect-
ing data for pressure relief devices, these devices can be monitored
safely. As mentioned earlier, most plants already perform annual relief
valve tests, further indicating that monitoring can be performed safely.
Comment: One commenter (II-D-10) stated that EPA's requirement
for capping all open-ended lines suggests capping relief valve discharge
lines that must remain open to provide a path for discharging the
fluids from the valve in case of an emergency. Another commenter
(IV-D-34) requested that a new paragraph be added to the standards for
open-ended valves or lines:
(c) Open-ended valves which serve as automatic or manually
actuated emergency shutdown systems for gas processing plants
are exempt from the provisions of the section and shall comply
with the provisions of §60.632-6.
The commenter noted that emergency shutdown (ESD) systems are required
to protect people and equipment. ESD systems dump gas to atmosphere by
automatic or manual actuation through a series of open-ended valves.
The commenter maintained that as a safer alternative open-ended valves
or lines in ESD systems should be subject to the valve standards rather
than to the open-ended valve or line provisions of Section 60.632-5 of
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the proposed standards. The commenter added that leakage in a pressured
ESD system is self-monitoring, since a drop in system pressure actuates
the ESD system.
Response: As stated in the definition of "open-ended line"
(Section 60.631 of the proposed standards), open-ended lines do not
include pressure relief valves. Relief valve discharge lines are
exempt from the capping requirement because relief valve horns must
always remain open for the relief valve to function. Assuming ESD
systems are relief valves, they would be exempt from the standards for
open-ended lines because they are excluded from the definition of
open-ended lines.
4.7 CONTROL DEVICES
4.7.1 Efficiency Requirements
Comment: One commenter (II-B-23) stated that vapor recovery
compressors are more representative of gas plant applications than
condensers or absorbers and should be the appropriate standard for gas
plants.
Response: Control devices are not limited to flares, incinerators,
condensers, or absorbers. They are given as examples of acceptable
systems. Control devices must have a VOC control efficiency of at
least 95 percent. If a recovery compressor were designed and operated
with greater than 95 percent reduction efficiency, it would be an
acceptable control device for natural gas processing plants.
Comment: Several commenters (II-B-23, IV-D-10, IV-D-13 IV-D-15
IV-D-20, IV-D-24, IV-D-31, IV-D-33, IV-D-35, IV-F-lc, IV-F-le) took '
issue with the velocity and heat content limits for flares, and requested
they be deleted from the standards. Many of these commenters maintained
that existing emergency flares are capable of greater than 98 percent
combustion efficiency if properly operated.
Some of the commenters specifically questioned limiting heat content
values provided by the standards. One commenter (IV-D-33) stated that
gases with heat contents of about 5.6 MJ/scm (150 Btu/scf) could be
flared successfully, while others (IV-D-24 and IV-D-35) noted that
produced (field) gas often has low heat values due to N2 and CO?
entrainment, especially in the latter stages of enhanced recovery.
Several commenters indicated that studies available to EPA showed
that flares operating over a wide range of gas heat content values and
flare exit velocities have destruction efficiencies in excess of
98 percent. One of the commenters (IV-D-10) maintained that EPA based
the flare exit velocity limit on test data used for the SOCMI NSPS,
with the testing limited to velocities of less than 18.3 rn/sec (60 ft/sec)
The commenter did not agree with EPA's conclusion from these data that
higher velocities would result in lower efficiencies, stating that EPA
should require that flame stability be maintained rather than limiting
the heating value and velocity of the gas stream. Many commenters
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(IV-D-21, IV-D-23, IV-D-26, IV-D-33, IV-D-36, IV-F-la) were concerned
that API Recommended Practice (RP) 521 was ignored, noting that RP 521
recommends a flare tip velocity of 0.2 Mach for continuous flaring and
0.5 Mach for short-term flaring for sizing the flare. Several
commenters indicated that to design a flare for maximum exit velocities
of 18.3 m/sec (60 ft/sec) under emergency conditions would result in
very large flare tips, increasing the chance of air migration and stack
explosions during normal operation.
Four commenters (II-B-23, IV-D-27, IV-D-29, IV-D-35) favored a
20 percent opacity level (except for 5 minutes in any 2 consecutive
hours) and contended that the "no visible emissions" requirement was
too stringent.
Response: As noted above, EPA selected control devices that
achieve at least 95 percent reduction efficiency as the "best demon-
strated technology" (BDT) for control devices used in complying with
the standards. In reflecting this selection of BDT, EPA proposed
specific design and operational requirements to ensure that flares used
to comply with the standards achieve at least 95 percent reduction
efficiency. The proposed design and operational requirements were, in
EPA's judgment, the only set of limits that ensure at least 95 percent
reduction efficiency. The EPA considered setting requirements that
better reflect 95 percent reduction efficiency but rejected this because
data do not support setting design and operational requirements that
would distinguish between 95 and 98 percent reduction efficiency. The
EPA agrees with the commenters who stated that existing flares in this
industry are capable of greater than 98 percent reduction efficiency if
properly operated. However, the only way EPA knows to ensure this
judgment is to set limits on design and operation of the flares that
reflect BDT.
Since proposal, EPA further examined previously available and
new flare studies cited by the commenters (Palmer (1972); Siegel (1980);
Lee and Whipple (1981); Howes (1981); McDaniel (1983)), and concluded
that flares with exit velocities up to 122 m/sec (400 ft/sec) can
achieve 98 percent destruction efficiency, as suggested by one commenter,
if the gas heat content is sufficiently high. Therefore, the final
standards provide an additional equation for determining velocities up
to 122 m/sec (400 ft/sec) depending on the gas heat content, as follows:
Logio (Vmax) = (HT + 28.8)/31.7
where Vmax = maximum permitted velocity, m/sec
and Hj = the net heating value of the gas, MJ/scm
This equation was based on flare efficiency data available to EPA,
primarily from a study conducted by Energy and Environmental Research
Corporation, entitled "Evaluation of the Efficiency of Industrial
Flares-Test Results," " Pohl , et. al. (1984), Docket Item IV-A-1. This
equation will allow streams with net heating values greater than 11.2
MJ/scm (300 Btu/scf) to be flared at higher velocities, while ensuring
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an effective reduction efficiency that reflects BDT. These limits do
not allow flares to be used that burn streams with a net heating value
of 5.6 MJ/ scm (150 Btu/scf), as suggested by one of the commenters.
In EPA's judgment, flares burning streams with this net heating value
can not be considered to be effective control devices. The available
data do not support revising the lower net heating value limit (i.e.,
300 Btu/scf).
An underlying concern of the commenters appears to result from a
misunderstanding that flares must never exceed the maximum permitted
velocity (e.g., an 18 in/sec (60 ft/sec) tip velocity) for steam-
assisted and nonassisted flares. As can be determined by reviewing
40 CFR 60.8, emergency releases to the flare are not considered normal
operation and, therefore, the velocity limits do not apply in such
circumstances. The specifications described in API RP 521 ("...a
velocity of up to 0.5 Mach for a peak, short-term, infrequent flow...")
are intended to be used in emergency situations, whereas the maximum
velocity requirements for flares specified in the EPA standards are
intended to be used during normal flare operation.
With respect to the "no visible emissions" limit placed on flares,
EPA considers a requirement for no visible emissions, with the exception
of 5 minutes in any 2-hour period, to be reasonable. Smokeless
flares have been regulated in States with limits similar to the proposed
opacity limits. The commenters offered no appropriate basis for changing
the limits to another level. In addition, most streams in natural gas
processing plants are highly volatile gases or light liquids, and are
readily burned in smokeless flares. Some commenters indicated that
continuous smokeless operation would require either automatic or manual
control of the flare on a continuous basis. However, EPA believes that
if this type of control is needed to ensure the use of BDT, it is
reasonable, and that most gas plants would have little difficulty in
obtaining smokeless combustion.
Comment: One commenter (IV-D-31) thought that the establishment
of operating criteria is not permissible under Section 111 of the Clean
Air Act. Section 111 specifically precludes the Administrator from
adopting design or work practice requirements unless it is not feasible
to prescribe or enforce a performance standard. According to the
commenter, a performance standard is readily available in the case of
controlling VOC emissions by combustion and is included in the proposed
standards, namely, an opacity limit.
Response: As indicated by the commenter, the "no visible emissions"
requirement for flares does constitute a performance type standard. However.
this portion of the flare requirements only partially reflects BDT.
All of the requirements as promulgated are needed to reflect BUT.
Since unburned hydrocarbons can be colorless and can be emitted without
being visible, the opacity requirement does not provide a complete
measure of VOC destruction efficiency. The EPA could set a performance
standard at a specific destruction efficiency level. However, available
data indicate that, unless flares are operated within the velocity and
heating value requirements of the standards, they would likely not meet
performance specifications. More importantly, performance testing for
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flares is extremely complex and costly, so that a standard requiring
demonstration of a given efficiency level is, in fact, not practicable.
Comment: One commenter (IV-D-24) claimed that the proposed
standards will force extensive design changes to existing flare systems
at a cost that would adversely affect the economics of modification
projects. The commenter stated that his company did not have any gas
plants equipped with flares that meet the provisions of Section 60.632-9
of the proposed standards.
Response: If an existing flare does not achieve the required
limits of the promulgated standards, then EPA would not recommend using
the flare as a control device because such a flare is not likely to be
effective in burning VOC emissions. However, flares are not the only
control devices suitable for use in controlling gas plant emissions.
The EPA believes that, in most cases, existing flares will meet the
requirements of the standards where installed. In addition, the
velocity limits for flares have been expanded (allowing more flares to
comply with the standards) and are not required to be maintained during
emergency releases.
For plants that do not have suitable flares, EPA has determined
that it is cost effective to install a new flare solely for VOC control
purposes if the plant decides that another control device is not
available (Docket Item IV-B-7).
Comment: One commenter (IV-D-33) noted that API Publication 931,
Chapter 14, states that residence times of 0.2 to 0.7 seconds at 1150
to 1400°F are sufficient to obtain satisfactory combustion and
decomposition in most applications. The commenters1 experience confirms
the API parameters as sufficient to incinerate waste gases. The commenter
favored deletion of the residence time and temperature requirements
from the standards in favor of a 95 percent efficiency requirement.
Another commenter (IV-D-15) recognized that the residence time and
temperature parameters were provided in the standards as alternatives
to demonstration of 95 percent control efficiency, but was concerned
that the parameters could be treated as requirements for some new
processes where they would not be necessary for 95 percent destruction
efficiency. The commenter also noted that the control device require-
ments should only apply during normal design conditions.
Response: As correctly noted by commenter IV-D-15, the temperature
and residence time specifications presented in the standards were provided
to allow demonstration of 95 percent efficiency through accepted design
parameters rather than emissions testing. Incineration systems based
on other design parameters may be used subject to demonstration of
control efficiency by source emissions testing or suitable engineering
calculations. Although the EPA parameters of 0.75 seconds and 816°C
(1500°F) are somewhat higher than those stated in API Publication 931,
the EPA parameters are based on known 95 percent destruction efficiencies
for all cases, rather than "most applications" so that the use of the
EPA parameters can be accepted as proof of 95 percent efficiency. The
EPA realizes that, in some cases, shorter residence times and/or lower
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temperatures can provide 95 percent efficiency. An owner/operator,
therefore, can provide design information such as emission rates and
gas stream component analyses, and incinerator design specifications,
for approval as an acceptable control device.
4.7.2 Flares
Comment: Commenters IV-F-la; IV-D-29; and IV-D-23 stated that most
companies will not include a smokeless flare in their new plant designs.
Commenters IV-F-la and IV-D-23 also noted, however, that in plants that
have a flare system, the flare design would not adequately accommodate
the seal leakage and/or would not meet the requirements of the proposed
standards.
Response: Flares are one of several VOC control devices that
might be used to comply with the standards. Flares are not required
under the standards, but they are included because they can be used to
reduce emissions of VOC at conditions that reflect BDT. Flares operated
in accordance with the operating conditions provided in the regulation
are acceptable alternatives to other control devices used to comply
with the standards. Although EPA allowed for plants that did not
include flares as a part of their initial design in setting the compressor
standards, many plants are expected to include flares because gas plants
are major sources of VOC; and in selecting best available control
technology (BACT) and lowest achievable emissions reduction (LAER),
smokeless flares are likely alternatives for the control of VOC emissions
from emergency venting.
Comment: One commenter (IV-F-lc) indicated that the cost of
equipment to monitor flare pilot lights is high, and the equipment is
unreliable. Another commenter (IV-F-le) noted that EPA provided no
cost estimates for flare monitoring equipment.
Response: The presence of a flare pilot may be monitored with a
thermocouple and appropriate transmitter. Contrary to the commenter's
suggestion, thermocouples are highly reliable and are used throughout
the petroleum industry.
The costs associated with the flare requirements are discussed in
Chapter 7.
4.7.3 Continuous Operation
Comment: Two comrnenters (IV-D-15 and IV-D-20) questioned the
requirement in Section 60.632-9(d)(g) of the proposed standards
for full-time operation of vent systems and control devices. The
commenters wrote that the operation of vent systems and control devices
should not apply during shutdown and start-up operations. One commenter
(IV-D-20) aryued this is necessary because during such times the gas
composition may be highly variable. Consequently, it would be difficult
to design a flare to handle such a wide range of flows and compositions.
Another commenter (IV-D-15) requested that the requirements for a
continuous burning pilot in Section 60.632-9(d)(2) , include "... or an
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acceptable reignition device." The commenter stated that automatic
ignition devices should be allowed as an alternative to monitoring the
presence of a flare pilot. Other commenters (IV-D-29, IV-F-la) stated
that the fuel wasted to keep the flare burning would cost more than
could ever be saved from implementing the standards.
Response: Start-up and shutdown operations are described in the
General Provisions. Section 60.8(c) states that "Operations during
periods of start-up, shutdown, and malfunctions shall not constitute
representative conditions for the purpose of a performance test nor
shall emissions in excess of the level of the applicable emission limit
during periods of start-up, shutdown, and malfunction be considered a
violation of the applicable emission limit unless otherwise specified
in the applicable standard."
The EPA concurs that there is no basis for operating the flare when
no leakage is emitted. The proposed standards (Section 60.632-9(g))
required closed-vent systems and control devices (including flares)
to be operated at all times when emissions are vented J,p_ these devices.
Therefore, the commenter's suggestion is not~ necessaryT" This provi-
sion will allow the use of a flare header flow detector and automatic
ignition system to prevent waste of pilot fuel. However, when a flare
is operating, the pilot light must be burning at all times to ensure
the destruction of VOC emissions that may be released.
4.8 LEAK DETECTION AND REPAIR
4.8.1 Monitoring Frequency
Comment: Several commenters (II-B-23; IV-F-lc ;IV-F-le; IV-D-14;
IV-D-15; IV-D-19; IV-D-27) stated that monthly monitoring of valves in
light liquid and gas/vapor service is too frequent.
Three of the commenters (IV-F-le; IV-D-14; IV-D-15) urged EPA to
adopt quarterly monitoring for valve leaks, indicating that the small
additional emissions decrease does not justify increased cost for
monthly monitoring. Another (IV-D-24) urged EPA to adopt quarterly
monitoring at most, yet recommend annual monitoring due to the mammoth
paperwork burden the standards create.
One commenter (II-B-23) requested that EPA present an evaluation
of more extended inspection frequencies as supported by the API-Rockwell
study. Another commenter (IV-F-lc) requested that the monitoring
period for valves be changed to annual, stating that the cost
effectiveness of monthly monitoring is questionable due to the large
number of valves and the manhours involved, while still other commenters
(IV-D-13 and IV-D-23) said that, even though the standards allow
quarterly monitoring, the initial frequency should be reduced to
(IV-D-23) noted that it will not always be possible to reach facilities
in North Dakota for monthly monitoring, whereas quarterly testing could
be scheduled around the weather. In addition, quarterly monitoring
would reduce yearly travel expenses by two-thirds; in North Dakota this
is a $16,000-per-year savings.
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Response: As stated in the preamble to the proposed standards,
EPA considered monthly, monthly/quarterly, and quarterly monitoring
intervals for valves. Each of these alternatives was compared in terms
of the emission reduction achievable and the cost effectiveness of the
leak detection and repair programs. At proposal , the standards were
based on monthly monitoring because it provided the greatest emission
reduction at reasonable costs.
The EPA recognized, however, that some valves have lower leak
occurrence rates than others. Monthly monitoring of valves that do not
leak for 2 consecutive months was judged to be unreasonable when
compared to the additional emission reduction achieved by monthly
monitoring over quarterly monitoring. Therefore, EPA proposed to allow
a monthly/quarterly implementation program, whereby valves that do not
leak for 2 successive months may be monitored quarterly until a leak is
found. Also, under one of the alternative standards for valves, an
owner or operator can skip from the monthly/quarterly program to less
frequent leak detection (semiannually or annually) if a performance
test level of 2.0 percent is achieved on a continuous basis (for either
2 or 5 consecutive quarters). The EPA expects that most gas plants
would implement a monthly/quarterly leak detection and repair program
for valves. In addition, the incremental cost effectiveness between
monthly/quarterly and quarterly leak detection and repair is reasonable
(see Table 3-1). Therefore, the standards still allow a monthly/
quarterly program for valves, which has not changed since proposal.
One of the commenters suggested that valves be monitored quarterly
from the onset of the program due to the remoteness of gas plants. As
shown in the BID for the proposed standards, Appendix G, EPA carefully
analyzed the cost effectiveness of monitoring small remote plants using
central office or contract personnel. These analyses for small plants
indicated that, for plants smaller than 10 MMscfd, monthly monitoring
was not cost effective.
Comment: One commenter (II-B-23) questioned the validity of the
leak detection and repair (LDAR) model upon which the economics of con-
trolling emissions from valves and pump seals is based. The commenter
asserted that the model was not developed using any gas plant data
based on information presented in the AID (Docket Item II-A-25),
Table 4-10.
Another commenter (IV-D-19) wrote that EPA's use of the leak
occurrence rate function in the LDAR model is faulty. The commenter
disagreed with the use of the 1.3 percent per month leak occurrence
rate based on limited tests in chemical plants. The commenter noted
that his company's refinery experience indicates a leak occurrence
rate of 0.3 percent leakers per month. The commenter acknowledged that
gas plant valves may be expected to leak slightly more than refinery
valves, but not by a factor of four.
The commenter also disagreed with the LDAR model's assumption that
the number of leakers increases linearly with time. As an example, the
commenter said that the model estimates the percentage of leakers for an
annual program to be at least 16 percent (1.3% x 12 months, plus minimum
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level). The commenter stated that this high rate is why EPA does nut
believe it is reasonable to (allow leakers to) accumulate for greater
than 1 year.
Response: In response to the first commenter's remarks, the LDAR
model does not contain any data; it is merely an algorithm to "model" a
leak detection and repair program. To use the model, monitoring data
must be provided as input. The LDAR model as presented in the AID is
the basis for the cost analysis of controlling valve and pump seal
emissions. However, the use of the model for natural gas processing
plants was based on the best leak data available, including gas plant
emission factors. These model results are presented in Table E-l of
the BID for the proposed standards and in Docket Item II-B-18.
The second commenter contends that the rate of leak occurrence for
valves used by EPA as inputs to the LDAR model is high; and the model
assumes that the number of leakers increases linearly with time. The
1.3 percent rate of leak occurrence for valves is based largely on data
from SOCMI plants and has been corroborated by API valve maintenance
data from petroleum production operations (II-I-20, II-I-21). The
EPA analyzed the API valve maintenance data and concluded that the API
data support the estimates of leak occurrence and recurrence used by
EPA for gas plants (II-A-9).
The LDAR model- assumes a constant valve leak occurrence rate as
mentioned by the commenter. However, this rate is applied by the model
on only the non-leaking sources after each month. For example, the
1.3 percent occurrence rate mentioned by the commenter would result in
13 leaks per month during the first 6 months (for a plant with 1,000
valves), 12 leaks per month during the next 6 months and so forth until
all 1,000 valves were leaking, which would require over 40 years at a
1.3 percent/month rate. Although another description of the rate at
which leaks develop might be slightly more accurate, the method used in
the LDAR model is based on reasonable assumptions necessary for modeling
an average case. For example, valves within a plant may have different
leak occurrence rates due to different designs, services, manufacturers,
or frequencies of use. Modeling of such factors would require extremely
complex information over long periods of time for every plant analyzed.
Consequently, the LDAR model attempts to simplify the leak occurrence
phenomena to represent an average case for all plants based on test
data from typical processing plants.
The second commenter indicated that his company's refinery
experience indicated a leak occurrence rate of 0.3 percent leakers per
month, and that gas plants may be expected to have slightly higher
occurrence rates. However, data provided by another commenter (IV-D-26)
showed a 3.74 percent monthly occurrence rate at a gas plant recently
tested, three times the occurrence rate used by EPA for the LDAR model
input. Therefore, EPA considers these comments to confirm the reason-
ing used by EPA that, although occurrence rates will be widely variable,
average valve leak occurrence rates can be used in developing model
programs for cost-effectiveness analyses.
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Comment: One commenter (II-B-23) stated that the LDAR model
generates negative control efficiencies for some inspection frequencies.
Response: The commenter is pointing out an incorrect use of the
LDAR model.A negative control efficiency theoretically is generated
when the occurrence rate for a given inspection interval is greater
than the initial leak frequency. This may occur at a plant with an
overall occurrence rate of 1.3 percent, in which the leak rate
increases after leak detection and repair.
4.8.2 Delay of Repair
Comment: Two commenters (IV-D-15; IV-D-35) requested that the
delay of repair provisions in Section 60.632-8(a) be revised to read,
in part, "Repair ... shall occur, however, at the first scheduled
process unit shutdown." The commenter held that during unplanned
shutdowns, operating personnel are trying to make repairs due to upsets
or equipment malfunctions.
Response: The EPA agrees with the commenter that, during brief
emergency shutdowns, operating personnel may not be available for
repair of leaking components due to the importance of restarting the
process. To make allowances for delay of repairs beyond an unscheduled
shutdown in the case of shutdowns of too short a duration for operating
personnel to make repairs, a process unit shutdown has been defined as
longer than 24 hours. Since proposal, the definition of "process unit
shutdown" has been revised to exclude from the definition any unscheduled
work practices or operational procedures that stop production from a
process unit or part of a process unit for less than 24 hours. This
definition is in Subpart VV, standards for equipment leaks of VOC in
SOCMI, and is considered reasonable for gas plants as well.
Comment: One commenter (IV-F-4) stated that Section 60.632-8
of the proposed standards should have provisions to extend the repair
interval beyond 15 days in the event that replacement parts, equipment,
or personnel are unavailable. The commenter held that the delay of
repair requirements should be revised because these provisions unfairly
penalize the small gas processor. The commenter claimed that large
inventories of spare parts cannot be maintained at small plants due to
the high capital costs, tax considerations, and space requirements
i nvolved.
Response: The provisions of Section 60.632-8 of the proposed
standards allow for delay of repair beyond a process unit shutdown in
the event sufficient supplies were stocked and then depleted. As
recognized by the commenter, this "parts depletion" provision does not
apply to the normal 15-day repair period for sources not requiring a
process unit shutdown. Many smaller gas plants are remotely located
and may maintain little, if any, stock of spare parts. However, many
of these plants would have an existing source of readily available
parts to prevent unnecessary plant downtime. Most parts should be
available on an immediate-delivery basis, either from a central
location from the company owning the plant, or from parts distributors.
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Even though it is conceivable that a plant could have a monitoring
period in which a greater than normal number of repairs requiring spare
parts was necessary and depleted the inventory of spare parts, such
situations should be rare. In any event, provisions for delay of
repair beyond the normal 15-day period should not be necessary. Since
most repairs requiring parts replacement would require that the leaking
component be removed from service, the component requiring the parts
would either be one which can be isolated from the process for repair
or one which could not be repaired until the next shutdown. In the
latter case, the delay of repair provisions allow for delay beyond
shutdown if sufficient stock of spare parts is depleted.
For components isolated from the process for repair, the leaking
component may remain isolated until parts are acquired. Repair of
these components legally could be delayed indefinitely (provided there
are no VOC in the line), and no provision for spare parts, other than
the one provided in Section 60.632-8(b), is required.
4.8.3 Sealless Equipment
Comment: One commenter (IV-D-20) noted that EPA discusses seal less
pumps as not having a potential leak area and then requires initial
and annual performance tests. The commenter questioned why leakless
equipment requires any monitoring and suggested that the requirements
for monitoring leakless equipment be deleted.
Response: The standards require an initial performance test to
verify that a piece of leakless equipment meets the "no detectable
emissions" limit and annual rechecks to ensure continued operation with
"no detectable emissions." The EPA believes that these requirements are
necessary to verify the integrity of the equipment at installation and
throughout its operation. Leakless equipment may fail, for example,
as a result of corrosion or wear. For these reasons, EPA has determined
that initial and annual performance tests are necessary.
4.8.4 Repair Period
Comment: Several commenters (II-B-23, II-D-10, II-D-30, IV-D-19,
IV-D-20, IV-D-27, IV-D-30, IV-D-34, and IV-D-35) objected to the repair
period requirements. Commenters II-B-23, IV-D-27, IV-D-34, and IV-D-35
requested an extension of the first attempted repair period from 5
calendar days to 7 and 15 days. Another commenter (IV-D-19) requested
that the final repair requirements be changed to at least 30 days.
Reasons offered for these changes include:
1. Replacement parts are not available within 15 days, therefore,
gas plants would have to maintain an expensive inventory
with no significant air quality benefit (IV-D-19),
2. Remoteness of plants, inclement weather, and manpower
availability at small plants justify extending the repair time
(IV-D-27),
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3. An extension would allow a regularly scheduled maintenance
crew to handle repairs, whereas retention of the 5-day limit
would require contractor maintenance personnel to be paid for
expensive overtime and holiday work and create scheduling
problems (IV-D-34 and IV-D-35), and
4. At most gas processing plants personnel are not available to
repair all leaks within a 5-day period. Most new plants are
designed to run unattended for most of the day.
Another commenter (IV-D-20) asked that the 5-and 15-day repair
time limits not apply to equipment for critical valves, pumps, and
compressors used to keep the process operational. There is no reason
to specify a repair period for equipment that can be taken out of
service.
Response: The standards require that a first attempt at repairing
a leaking equipment should be accomplished as soon as practicable but
no later than 5 days after detection of a leak. Attempting a first repair
of the leak within 5 days will help maintenance personnel identify the
leaks which can be repaired without shutdown of the process unit.
Equipment that continue to leak after simple field repair attempts must
be repaired within 15 days following initial leak detection. This
interval provides time for properly isolating equipment that require
more than simple field repair. The 15 days provides sufficient time to
schedule and effect on-line repairs that a shorter period might not
allow. Provisions have been made for delaying repair of valves in
critical service that cannot be bypassed. The two repair period require-
ments provide efficient reduction of emissions and allow sufficient
time for flexibility in scheduling repairs of leaking equipment. A
15-day period for initial repair would simply permit delays in repairs
that could otherwise be accomplished quickly.
Most valve repairs can be done quickly and involve simple mainte-
nance procedures, such as packing gland tightening and grease injection.
This is evident from compliance experience of refineries with the South
Coast Air Quality Management District Rule (Rule 466.1) for valves
which require repair within 2 working days. A 5-day period for initial
attempts provides sufficient time to schedule field repair.
Valves that require off-line repair (25 percent is estimated in
the BID for the proposed standards, Chapter 8) may require new packing
or valve parts (i.e., gland flange or nut); however, these spare parts
and others would be stocked on-site for routine maintenance. Therefore,
stocking of these parts does not represent a burden imposed by the
standards.
The EPA realizes that many gas processing plants would be located in
remote areas, have limited manpower availability, and subject workers
to inclement weather. Consequently, EPA has exempted small nonfraction-
ating plants from the leak detection and repair requirements based on
the cost effectiveness to employ corporate office personnel or contractors
to perform the leak detection and repair program. The EPA believes that
the leak detection and repair requirements, including the repair periods,
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are reasonable for all fractionating plants and nonfractionating plants
with a capacity of 10 MMscfd or more.
4.8.5 Process Unit Shutdown
Comment: One commenter (II-D-10) remarked that some sources of
emissions in gas plants cannot be repaired until there is complete
plant shutdown, adding that a mandated routine shutdown for leak repair
would result in greater emissions than would be saved by repair. The
commenter noted that the majority of gas plants do not have periodic
turnarounds as refineries do because gas plants process gas as it is
produced from field wells; otherwise gas products are lost.
Response: The standards do not require routine shutdown for repair
of leaks for the reason cited by the commenter that a mandated routine
shutdown could result in greater emissions than would be reduced by
repair. The EPA does allow owners or operators to delay repair of
leaking valves, pumps, and relief valves beyond 15 days after leak
detection if the component cannot be repaired without a shutdown. For
valves, EPA allows a delay of repair beyond a facility shutdown if the
entire valve assembly is required to be replaced, provided the plant
owner or operator can demonstrate that sufficient stock of spare valve
assemblies was maintained before depletion of the stock of spare parts.
Comment: One commenter (IV-D-29) requested that the word
"production" in the definition of "process unit shutdown" be amended so
that it is clear it means production of natural gas and/or liquids.
Response: The definition of "process unit shutdown" clearly states
that a shutdown is a termination of "production from a process unit or
part of a process unit." Since a "process unit" is also defined as
equipment assembled for the extration and fractionation of natural gas
liquids, the word "production" in the definition clearly means the
extraction or fractionation of natural gas products.
It should be noted that natural gas production from the field can
continue while the processing plant is shut down.
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5.0 APPLICABILITY OF STANDARDS
5.1 DEFINITIONS
5.1.1 Natural Gas Processing Plant
Comment: Eleven commenters (IV-D-10; IV-D-11; IV-D-14; IV-D-15;
IV-D-16; IV-D-17; IV-D-19; IV-D-34; IV-D-35; IV-F-lc; and IV-F-le)
requested that the definitions of "natural gas processing plant" and
"processing unit" in Section 60.631 of the proposed standards be clarified
to exclude units that EPA intended to exempt, such as field separators
and well site production facilities. Most of these commenters suggested
that changing the word "separation" in the definition of natural gas
processing plant to "extraction" would imply units operating with a
forced process, while "separation" implies simple removal by gravity or
natural condensation.
Another cornmenter (IV-D-11) asked that EPA confirm in the promul-
gated standards that the regulations do not apply to facilities such as
sour gas treatment facilities that separate impurities other than
natural gas liquids from the field gas. Other commenters (IV-D-14;
IV-D-16; IV-D-34; and IV-F-le) asked that facilities not intended to be
covered by the regulation be clearly excluded. One commenter (IV-D-19)
asked that the exemption given in Section 60.630(e) clarify that "not
located at" means not within the boundaries of the gas plant.
One commenter (IV-D-15) requested deleting subparagraphs (1), (2),
and (3) of Section 60.630(a), and stating in paragraph (a) that "The
provisions of this subpart apply to specific process units within
natural gas processing plants." The cornmenter favored this change
because it eliminates the need for the field facility exclusion in
paragraph (e) of Section 60.630 and because, he argued, compressors
should not be designated as affected facilities, but should be
specifically excluded.
Response: In the proposed standards, a "natural gas processing
plant" (gas plant) is defined as "any processing site engaged in
the separation of natural gas liquids from field gas, fractionation of
mixed natural gas liquids to natural gas products, or both." The
definition was intended to exclude facilities that remove liquids from
field gas by means other than a forced process (e.g., gravity or
natural condensation). Therefore, EPA has revised the definition of
"natural gas processing plant" in the promulgated standards to read
"... any processing site that extracts natural gas liquids from field
gas." The definition of "process unit" has also been revised by substituting
the word "extraction" for the word "separation."
The EPA considers sour gas treatment facilities to be affected
facilities (i.e., subject to the standards) unless they are not located
at an onshore natural gas processing plant. The EPA knows of no reason
(and the commenters did not provide any reasons) why sour gas treatment
facilities should be exempted from the standards. If these facilities
have equipment in VOC service, then they should be covered by the standards.
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Subparagraphs (1), (2), and (3) of Section 60.630(a) clearly
define the affected facilities for natural gas processing plants.
Compressors are affected facilities, as explained in Section 60.630;
therefore, subparagraph (2) is necessary. Paragraph (e) is also necessary,
regardless of how paragraph (a) is worded, to make it clear which process
units and compressors are exempt from the requirements of the standards.
5.1.2 Liquified Petroleum Gas and Natural Gas Liquids
Comment: One commenter (IY-D-10) suggested adding the following
definitions to the standards:
"Liquified petroleum gases" mean ethane, propane, normal
butane, and/or iso-butanes or mixtures of these liquified
gases.
"Natural gasoline" means a liquid composed of pentanes and
heavier hydrocarbons or mixtures of pentanes, heavier hydrocarbons,
and/or lighter hydrocarbons.
Another commenter (IV-F-1; No. 5) suggested changing the term
"natural gas products" to "liquified petroleum gases."
Response: As noted by the first commenter, liquified petroleum
gases (LPG) generally consist primarily of propane and butane, while
"natural gasoline" consists of pentanes and/or heavier hydrocarbons.
Both of these streams are considered VOC by EPA and are, therefore,
subject to the requirements of the standards. The EPA used the terms
"field gas" and "natural gas liquids" to define the feedstock and
product streams in natural gas processing plants, and the term "natural
gas products" to define the individual products (such as LPG or natural
gasoline) resulting from the fractionation of natural gas liquids. As
such, both liquified petroleum gases and natural gasoline as defined by
the commenter would be included in the term "natural gas products,"
which is contained in the definition of "natural gas processing plant."
Since "LPG" and "natural gasoline" could have specific meanings, the
use of these terms could result in exclusion of other natural gas
products that were intended to be included. Therefore, EPA will continue
to use the terms "natural gas liquids" and "natural gas products" as
generic terms for natural gas processing plant product streams.
5.1.3 VOC
Comment: One commenter (IV-D-20) requested that ethane handling
equipment be exempt from the requirements of the standards. The
commenter stated that the preamble indicated that methane and ethane have
negligible photochemical reactivity, but the definition for natural gas
liquids does not exclude ethane. The commenter indicated that this lack
of exclusion would result in requiring inspection of ethane handling
components.
Another commenter (IV-D-25) requested that EPA revise the definition
of VOC in Section 60.2 of the General Provisions to specifically exclude
methane and ethane. The commenter thought a revised definition was
necessary because Reference Method 21 detects any organic compound and
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nonreactive organic compounds (such as methane and ethane which are not
considered VOC by EPA). The commenter noted that methane is used as a
calibration gas in Reference Method 21.
Response: The first commenter is correct in stating that the
definition for natural gas liquids (NGL) does not exclude ethane.
However, a piece of equipment is covered by the standards if the
stream is in VOC service, not NGL service. The standards allow the
exclusion of substances not considered photochemically reactive by EPA
when determining the percent VOC in the process fluid (i.e., determining
whether a piece of equipment is in VOC service). The VOC content is
determined by the ASTM methods E-260, E-168, and E-169, not by Reference
Method 21. Therefore, the fact that ethane is included as an NGL does
not necessarily mean that ethane-handling components are covered by the
standards. Thus, the exclusion of ethane from the definition of NGL or
a revision to the definition of VOC in the General Provisions is
unnecessary.
5.1.4 Control Device
Comment: One commenter (IV-D-36) recommended that EPA revise the
definition of a control device to read that a control device "means an
enclosed combustion device, vapor recovery system, or flare, designed in
accordance with the provisions of Section 60.632-9."
Response: The EPA does not believe that it is necessary to amend
the definition of control device as recommended by the commenter.
Section 60.631 of the proposed standards provides a definition for a
"control device," and control device requirements are given in Section
60.632-9, which has been revised as discussed in Section 4.7.
5.1.5 Heavy and Light Liquid Service
Comment: One commenter (IV-D-35) recommended changes in the
definitions of "heavy liquid service" and "light liquid service." The
commenter indicated that all liquid service streams are currently excluded
from the "heavy liquid service" definition. For light liquid service,
the commenter suggested using the ASTM test methods incorporated in
Section 60.635(d)(2) instead of the stream VOC content as used in
Section 60.635(e).
Response: The commenter has correctly noted two errors in the
regulation, which have been corrected in the promulgated standards.
One error, the definition for "in heavy liquid service," was corrected
to read "... means that a piece of equipment is not in gas/vapor service
or in light liquid service." The word "light" was inadvertently omitted
from the definition.
The second error noted by the commenter is in the definition for
"in light liquid service." The EPA incorrectly cited paragraph (e) of
Section 60.635 instead of paragraph (d)(2) in referring to the determination
of equipment in light liquid service. This error has also been corrected
in the promulgated standards by incorporating the definition in Subpart
VV, as amended.
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5.1.6 Quarter
Comment: Two commenters (IV-D-35 and IV-D-36) requested that EPA
change the definition of "quarter." One commenter (IV-D-36) recommended
that the definition read that quarter "... means a 3-month period,
commencing on January 1, April 1, July 1, and October 1 of each year"
because the gas processing industry generally uses this definition for
all other internal, State, and Federal reporting requirements and,
consequently, standardization of the NSPS reporting requirements with
industry practices would facilitate compliance with these requirements.
The second commenter (IV-D-35) recommended that NSPS monitoring
start with the first quarter after the first 180 days have elapsed.
The commenter suggested changing the definition of "quarter" in the
standards from "The first quarter concludes on the last day ..." to
"The first quarter commences the next day after the last day of the
last full month during the 180 days following initial startup." The
commenter wrote that ending the first quarter during the 180-day startup
period essentially reduces the startup period to 90 days while gas plants
typically require about 180 days to startup, debug, balance and establish
routine operations.
Response: The EPA does not wish to force industry into specific
calendar dates for monitoring activity. Therefore, calendar dates are
not used for defining quarters; however, a plant owner or operator may
choose to use the calendar quarters suggested by the commenter provided
the first date of the calendar quarter is no later than the day after
the last day of the last full month during the 180 days following
initial startup.
The regulation specifies that the plant be in compliance with the
standards within 180 days of initial startup, not after the 180-day
period. The EPA has been given no data or documented information in
support of the second commenter's claim that gas plants typically
require the full 180 days to prepare to be in compliance with the
standards. Startup times for gas plants are not expected to be any
different from startup times for refineries or chemical plants.
5.1.7 In VOC Service
Comment: Numerous commenters (II-B-23; II-D-30; IV-D-13; IV-D-14;
IV-D-15; IV-D-16; IV-D-17; IV-D-19; IV-D-21; IV-D-23; IV-D-24; IV-D-25;
IV-D-26; IV-D-27; IV-D-29; IV-D-30; IV-D-31; IV-D-33; IV-D-34; IV-D-35;
IV-D-36; IV-D-37; IV-F-la; IV-F-lb; IV-F-le) requested that EPA raise
the VOC concentration limit for "VOC service" from 1 weight percent
VOC to either 10 volume percent VOC or 10 weight percent VOC. Several
reasons were presented by the commenters, including:
Use of a 10 weight percent VOC limit would make the standards
consistent with other equipment leak standards.
Raising the limit on VOC concentration would concentrate
attention on equipment that is more likely to exhibit VOC
leaks and would result in more cost effective control.
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Under the current limit of 1 weight percent, the commenters
indicated that many "residue gas" streams, which EPA intended
to exempt, would be covered. Other commenters (IV-F-la; IV-D-
26; IV-D-36) stated that an industry-wide survey indicated
that a 10 weight percent cutoff would exclude dry gas service
components at most of the plants surveyed, and that EPA's data
base for establishing a 1 weight percent limit was inadequate.
One commenter provided plant size and residue gas VOC content
data for over 100 plants to illustrate his point. Similarly,
another commenter (IV-D-21) wrote that only 13 out of 36 of
his company's operating plants produce residue gas that is
less than 1.0 weight percent VOC, while 29 of these same
36 plants have residue gases that are less than 10 weight percent
VOC.
Another of the commenters (IV-F-le) said that a 1 weight
percent limit implied an uncommonly high degree of liquid removal.
Two commenters (IV-D-15, IV-D-35) wrote that the API/Rockwell
Study shows primarily methane streams (residual or sales gas),
a non-VOC, would be exempt by this 10 percent criterion.
One commenter (IV-D-17) indicated that "pipeline quality" gas
often contains more than 1 weight percent VOC and indicated
that EPA had told him that pipeline gas was intended to be
excluded.
Other commenters (IV-D-31; IV-D-35) suggested, as an alternative
to or in addition to changing the definition of VOC service,
that residue gas be classed a priori not in VOC service.
One commenter (IV-D-19) stated that a refinery valve handling
a 10 weight percent VOC stream has roughly the same health
effects and control costs as does a valve in a gas plant
handling a 10 weight percent VOC stream. The commenter added
that EPA's argument that 1 to 10 weight percent streams
contribute a significant portion of gas plant emissions is not
sufficient justification to control that portion, especially
when the total source category emits very little.
One commenter (IV-D-24) remarked that many automatic control
valves are operated using "natural gas" with VOC content
greater than 1.0 percent by weight. Consequently, these valves
have to be replaced or a new instrument air compressor must
be purchased. The commenter also stated that product natural
gas from the average yas plant has a VOC content in the range
of 3 to 8 percent by weight. The commenter thought the VOC
content should be raised to 4 mole percent or 8 weight percent.
Response: In setting the VOC concentration limit, EPA took into
consideration the VOC content below which equipment leak controls may
not be cost effective. In the case of synthetic organic chemical
plants and petroleum refineries, the costs of controlling the small
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number of streams containing less than 10 weight percent VOC appeared
to be unreasonable in light of the emission reduction potential.
Therfore, EPA considered 10 weight percent VOC to be an appropriate VOC
concentration limit for those standards. In contrast, gas processing
plants can have a large number of components in streams containing
between 1 weight percent and 10 weight percent VOC, and the cost
effectiveness of controlling emissions from these components is
reasonable. Thus, the lower VOC concentration limit appeared to be
warranted as a way to cover these streams.
The underlying concern of the commenters was that, while EPA
stated in the preamble that product natural gas (residue ("dry") gas)
was to be excluded, the 1.0 weight percent VOC limit was so low that
many residue gas streams would be covered by the standards. To support
this contention, the Gas Processors Association (GPA) provided data for
throughput, non-organic content, and VOC content for the residue gas
streams from over 100 plants. An analysis of these data is presented
in Docket Item IV-B-10. Some of the plants listed in the GPA survey had
residue gas VOC contents below 1.0 weight percent VOC, with many less
than 0.1 weight percent VOC. Most of the plants had residue gas streams
containing between 1.0 percent and 10 weight percent VOC, and a few
plants had residue gas streams exceeding 10.0 weight percent VOC.
The GPA data illustrated to EPA that 1 weight percent VOC was not
an appropriate limit to exclude residue gas streams, since residue gas
streams can often contain more than 1 weight percent VOC. Therefore,
the Administrator decided to raise the limit. Considering that the
costs of controlling most gas plant streams, other than wet gas streams,
containing less than 10 weight percent VOC would be too high for the
emission reduction that would be achieved, a VOC concentration limit of
10 weight percent was selected as a representative limit for the "in
VOC service" definition. Therefore, the definition of "in VOC service"
has been changed in the promulgated standards to refer to a 10 weight
percent VOC content.
However, the original intent in utilizing a 1.0 weight percent VOC
limit was to ensure that inlet (wet) gas streams were subject to NSPS
control, since emissions can be reduced at reasonable costs from inlet
gases. Therefore, the promulgated standards require that all equipment
in wet gas service be controlled (except wet gas reciprocating compressors),
regardless of VOC content. Since wet gas streams may vary around 10 weight
percent VOC, this requirement will prevent repeated testing to determine
VOC service and will clarify the intent of the standards for plant
owners, operators and enforcement personnel.
Comment: One commenter (IV-D-37) recommended that Section
60.635(e)(l) be revised to require that a detennination that a piece of
equipment is not in VOC service should only apply during normal and
ordinary operations. According to the commenter, this change is
necessary to eliminate brief periods during upset conditions when the
line may contain heavier hydrocarbons than nonndl.
Response: The General Provisions, Section 60.8(c) of the Clean
Air Act, cover operations during upset conditions. Specifically,
Section 60.8(c) states that:
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Operations during periods of start-up, shutdown, and malfunctions
shall not constitute representative conditions for the purpose
of a performance test nor shall emissions in excess of the level
of the applicable emission limit during periods of startup, shut-
down, and malfunction be considered a violation of the applicable
emission limit unless otherwise specified in the applicable standard.
Therefore, the commenter's suggested revision is unnecessary.
5.1.8 Vacuum Service Components
Comment: One commenter (IV-D-20) agreed with the exclusion for
vacuum equipment. The commenter requested that common English equivalents
of measurement be included in parenthesis where SI units are given.
Response: The EPA has not found it necessary to revise the definition
for "in vacuum service" by including the appropriate English equivalent
measure to the SI units given. The conversion from kilopascals (kPa)
to the appropriate English equivalent, pounds per square inch (psi), is
6.895 kPa = 1 psi. Therefore, the definition for in vacuum service
expressed in English units would mean equipment operating at an internal
pressure that is at least 0.725 psi below ambient pressure.
5.1.9 Connectors
Comment: One commenter (IV-D-20) stated that requirements to
repair leaking pumps and valves in heavy liquid service, relief valves
in light and heavy liquid service, and flanges and other connectors are
generally reasonable. The commenter did not agree that it is reasonable
to define a "connector" as a welded joint. The commenter argued that
such connections do not leak and should not be subject to these
requi rements.
Response: The EPA maintains that it is reasonable to include a
welded joint in the definition of a "connector". Welded joints may
leak due to an improper seal or fitting, or leaks may develop over time
due to corrosion or deterioration of the weld. Therefore, welded
joints, like other connections, are subject to the standards as specified
in Section 60.632-7 of the proposed standards. If evidence of a potential
leak is found by visual, audible, olfactory, or other detection method,
the connection must be monitored within 5 calendar days (or assumed to
be a leaker), a first attempt at repair must be made within 5 days of
detection; and repair must be completed as soon as practicable, but no
later than 15 calendar days after the leak is detected.
5.2 SELECTION 01 SOURCES
b.2.1 .VdJ_v_e_s jin_d jDpen-Ended Lines
Comment: One commenter (IV-D-3) noted that valves and open-ended
lines account for 79 percent of the VOC emissions from gas plants and
questioned why the standards are not limited to these two sources.
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Response: Based on the use of the revised compressor seal emission
factors (BID for proposed standards, Appendix G), valves and open-ended
lines represent approximately 70 percent (191 Mg/yr for valves and
open-ended lines and 82.8 Mg/yr for other sources combined from Model
Plant B) of VOC emissions from gas plants.
The EPA agrees that valves and open-ended lines represent the
largest sources of gas plant emissions. However, the baseline emission
factors in the BID for the proposed standards, Table 7-2, as corrected
in the appendices, show that pressure relief devices, compressor seals,
and pump seals are also significant emission sources. Together these
sources account for 49.2 Mg/yr of VOC emissions from a typical plant.
The emissions from these sources are reasonable to control as shown in
Table 3-1.
In selecting best demonstrated technology (BDT), EPA selected
standards for each type of component in gas plants with demonstrated,
cost-effective control techniques. Since the general purpose of NSPS
is to require new facilities to incorporate best demonstrated technology
as they are being constructed, and cost-effective controls are available
for compressors, pumps, and pressure relief devices, these sources are
also included.
5.2.2 Heavy Liquids '
Comment: One commenter (IV-D-15) wrote that the standards should
delete the monitoring requirements for components "in heavy liquid
service." The commenter noted that these components have a low potential
for VOC emissions.
Response: The proposed standards (Section 60.632-7) do not require
routine monitoring of components in heavy liquid service. Components in
heavy liquid service are not as likely to develop leaks as are gas
service or light liquid service components. However, heavy liquid
service components that do "leak have emission rates comparable to
components in gas or light liquid service. Therefore, the standards do
require that leaks detected by visual, audible, or olfactory means be
measured to determine if the leak results in an instrument reading of
10,000 ppm or greater and, if so, that the leaks be repaired as soon as
possible within 15 days, with a first attempt at repair within 5 days.
The operator could repair any leaks found in heavy liquid service
without prior instrument measurement, if desired.
5.2.3 Small Valves or Lines
Comment: Several commenters (IV-D-15, IV-D-20, IV-D-22, IV-D-23,
IV-D-26, IV-D-36, and IV-D-37) wrote that small valves or lines should
be exempt from the standards. Commenters requested exemptions for
valves ranging from 2 inches or less to 1/2-inch or less. The commenters
contended that eliminating small valves from the routine monitoring
requirements would greatly reduce recordkeeping, identification, and
reporting requirements. The commenters claimed that small valves
tend to leak less, both in frequency and amount of leakage, and
contribute a relatively small percentage of total fugitive VOC emissions
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at gas processing plants. The commenters also argued that exempting
these valves from monitoring requirements would reduce overall plant
monitoring costs.
Response: In developing similar standards for petroleum refineries,
EPA analyzed both the costs of small valve repair as compared to the
BID average repair cost estimates and the emission factor dependency
on valve size (Docket Item IV-B-11). These analyses indicate that the
emission rates from leaking valves are independent of valve size and
that repair of small valves is no more difficult or costly than repair
of larger valves. The EPA concluded that, since both the environmental
benefits and cost of control for small valves are the same as larger
valves, small valves are cost effective to control.
The emission source test data presented in Appendix C of the BID
for the proposed standards were collected at six natural gas/gasoline
processing plants by EPA and industry. Valves of all sizes were
monitored in these tests, and valve size was determined not to be a
factor. The emission factors developed from these test data are based
on all valves in gas processing plants. The basis of the standards for
valves included all valve sizes and was determined to be cost effective.
Therefore, an exclusion for small lines and valves is not 'warranted and
is not included in the promulgated standards.
5.2.4 Small Compressors
Comment: One commenter (IV-D-21) was concerned that the standards
for compressors apply to all sizes of compressors including those used
to recompress vapor from storage tanks, refrigerate gas, boost regen-
eration gas, and even collect emissions from a larger compressor. The
commenter complained that without a horsepower cut-off in the designation
of a compressor as an affected facility, the replacement or modification
of a small compressor at an existing plant could require installation
of a complete vent control system for all the compressors at a plant.
Response: As with other fugitive emission sources, EPA has found
no relationship between component size and emissions. Emission test
data were collected from all sizes of components and compressors, so
that the emissions and cost effectiveness of controlling compressors
are based on compressors of all sizes. Consequently, EPA knows of no
reason to exempt small compressors based on horsepower.
5.2.5 Difficult-to-monitor Valves
Comment: A number of commenters (IV-D-23; IV-D-26; IV-D-30;
IV-D-33 and IV-D-36) recommended that EPA exempt insulated valves' from
the monitoring requirements of the proposed standards. The commenters
stated that some valves in natural gas plants require insulation because
they are in very hot or very cold service. Monitoring of these valves
would require removal and replacement of the insulation, often by an
insulation contractor, which would be both time consuming and costly
Two commenters (IV-D-30; IV-D-33) noted problems with icing on some
cryogenic temperature valves, delaying replacement of the insulation
until a shutdown so that components may warm up.
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Response: The EPA recognizes that additional time would be required
to remove and replace valve insulation to monitor or repair these
components. There may be problems associated with removing insulation
(e.g., ice formation). Nevertheless, insulated valves can be monitored
as close to the potential leak source as possible without removing the
insulation. If a leak is detected, repairs can be scheduled within
15 days without having to delay repair until the next turnaround.
The EPA determined that it is cost effective to repair insulated
valves that leak rather than delay repair until the next unit turnaround
(Docket Item IV-B-12). Therefore, the standards for valves, including
insulated valves, require that these components be monitored as close
to the source as practicable without requiring removal of the insulation.
If a leak is detected, as with other valves, repair of insulated valves
must be attempted as soon as possible within 15 days with a first
attempt at repair within 5 days.
5.3 SELECTION OF AFFECTED FACILITIES
Comment: One commenter (II-B-23) suggested that the list of VOC
fugitive emission source categories that are excluded from coverage by
the gas plants standards should also include other VOC sources such as
VOL storage and benzene storage tanks.
Response: The purpose of the list was to exclude sources from the
gas plants standards if they were also subject to other standards for
equipment leaks of VOC. These standards include promulgated standards
for equipment leaks from petroleum refineries (Subpart GGG), SOCHI
plants (Subpart VV), and benzene equipment leaks (Part 61, Subpart J).
The volatile organic liquid (VOL) storage standard is based on emissions
from process vents rather than equipment leaks. As a result, a VOL
storage tank (such as an NGL receiver tank) at a natural gas processing
plant would be covered by Subpart K (VOL storage) for vented emissions
and by Subpart KKK for equipment leaks from valves, pumps, compressors,
open-ended lines, and pressure relief devices.
Comment: One commenter (IV-D-20) took issue with EPA's presumption
that a narrower designation of the affected facility was proper in deter-
mining regulatory applicability. The commenter claimed that a narrow
definition may be proper at gas plants located in ozone nonattainment
areas and subject to New Source Review, but is improper when applied to
all gas plants. The commenter stated that the application of NSPS by
way of I3ACT requirements associated with PSD permitting is subject to
the PSD source definition and, therefore, requested that the narrower
designation of affected facilities be removed from the NSPS. The
commenter specifically requested that each compressor train rather than
each individual compressor be defined as the affected facility, because
the enclosing of distance pieces would create potential explosion
problems on certain affected units. The commenter suggested that each
compressor train be considered as modified only if aggregate emissions
from that train increase.
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Response: The EPA uses the term "affected facility" in NSPS to
designate either the individual piece of equipment or groups of
equipment within a plant chosen as the "source" affected by a given
standard. The term "affected facility" is used in NSPS to effect the
greatest emission reduction at reasonable costs and cost effectiveness.
This may result in a designation different from that used in PSD. The
designation of affected facilities is based on EPA's interpretation of
Section 111 of the Clean Air Act and on the judicial construction of
its meaning [ASARCO, Inc., v. EPA, 578 F. 2d 319 (D.C. Cir. 1978)].
The designation of the affected facilities is fully explained in the
preamble to the proposed standards (49 FR 2637-38). Furthermore, since
proposal, EPA has excluded certain compressors from coverage under the
standards (e.g., wet gas reciprocating compressors) that are generally
located in trains or groups. The compressors that are still covered by
the promulgated standards (e.g., NGL compressors) are generally isolated
and are not located in trains. Therefore, EPA does not agree that a
broader designation of compressors as an affected facility is appropriate.
Instead, EPA has concluded that it is appropriate to designate each
individual compressor as an affected facility.
Comment: One commenter requested a clarification to Section
60.632-l(f) of the proposed standards to protect owners of existing
plants which have certain equipment designed for purposes other than
control of emissions from arbitrary subjection to high emission control
costs. The commenter offered the following revision: (f) Reciprocating
compressors in wet gas service that are located at an onshore natural
gas processing plant that does not have a control device designed for_
VOC emission control present at the plant site are exempt from the
compressor seal control requirements of Section 60.632-3.
Response: As provided in the promulgated standards, EPA has
exempted all reciprocating compressors in wet gas service. Therefore,
the presence or design of a control device for these compressors is no
longer relevant.
Comment: One commenter (IV-F-6) requested that the exemption for
compressors that cannot be economically or technologically retrofitted
with emission controls, as discussed in the preamble to the proposed
standards, be incorporated as a specific paragraph in the standards.
Response: Because compressors are a separate affected facility,
they would be exempt from reconstruction if controls are technically or
economically infeasible as specified by the General Provisions (see
Section 60.15(e)). Therefore, a specific paragraph exempting these
compressors is not necessary. The determination of whether a
reconstruction or replacement of a compressor is technologically or
economically infeasible will be made by the Administrator on a
case-by-case basis. Unlike the reconstruction provisions, modification
does not consider technical or economic feasibility.
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5.4 -APPLICABILITY DATE
5.4.1 Applicability Date of Standards
Comment: One commenter (IV-D-35) recommended that the Administrator
publish in the Federal Register notice of the retraction of the January 20,
1984, applicability date for purposes of the definition of a "new
source." He stated that the history of other standards which have been
promulgated indicates that careful review of comments by the Agency can
result in substantial delay beyond the 90-day period imposed for promul-
gation by the Clean Air Act. The commenter further wrote that such
action by the Administrator would be well within his inherent power and
in keeping with the rationale of the Act, Section 111, while failure to
take such action would impose severe and unnecessary burdens on industry,
which the Clean Air Act intended to be mitigated.
Another commenter (IV-D-20) suggested that the promulgated standards
be applicable to plants starting construction 180 days after promulgation
rather than on the date of proposal. The commenter indicated that plants
with existing construction permits, but not yet constructed, could require
redesign or re-permitting. The commenter indicated that EPA should
consider the potential economic impacts of the earlier applicability date.
Response: Proposal of the standards is legal notification that an
owner or operator of a source will be subject to a standard. The Clean
Air Act (Section lll(a)(2)) clearly states the Congressional intent
that the proposal date will be the applicability date. Section lll(a)(2)
defines the new sources subject to an NSPS as those sources built or
modified after proposal, not after promulgation or some later event.
The proposal date is the applicability date unless the promulgated
(or revised) standard is not based on, and achievable by, the same
technology specified at proposal. This decision is consistent with
EPA's practice of applying NSPS's to all sources built after proposal
where the promulgated (or revised) standards are based on and achievable
by the same technology as the proposed standards.
Section lll(a)(2) implements the basic Congressional objective of
preventing new pollution problems and improving air quality as industry
changes by requiring all new sources (built or modified after proposal)
to use best demonstrated technology (BDT) in achieving emission reductions.
Congress recognized the existence of some uncertainty as to the final
standards that this technology must meet (S. Rep. No. 91-1196, 91st Cong.
2d Sess. (Senate Bill, §113(b)(2)). The passage of time between
identification of BDT as the basis of a standard and the final specifi-
cation of the performance required of that technology, therefore, is not
relevant by itself. Under Sections lll(b)(l)(B) and 307(d)(10), an
NSPS should be promulgated within 6 months of proposal. However,
Congress did not intend that if promulgation took longer, the category
of new sources should change. Commonwealth of Pennsylvania v. EPA, 618
F. 2d 991, 1000 (3rd Cir. 1980); 45 FR 8210, 8232 (February 6, 1980);
United States v. City of Painesville, 644 F. 2d 1186 (6th Cir. 1931),
cert. den. 102 S. Ct. 392 (1981); 49 FR 18076 (April 26, 1984).
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5.4.2 Existing Sources
Comment: One commenter (IV-D-3) noted that the statement in
Section 2.3 of the BIO for the proposed standards indicates that
"Standards of performance must... (3) be applicable to existing sources
..." and asked if the proposed standards might be modified at a later
date to include existing plants.
Response: Section 2.3 of the BID for the proposed standards makes
it clear that the standards are applicable to existing sources that are
modified or reconstructed. The terms "modification" and "reconstruction"
are defined in the General Provisions (see Sections 60.14 and 60.15,
respectively). The definitions and their applicability to the standards
are discussed in Chapter 5 of the BID for the proposed standards.
Comment: One cornmenter (IV-D-20) proposed that all compressors
manufactured before the effective date of the standards be exempt
from the vapor recovery system requirements of the standards. The
commenter noted that EPA stated in the preamble that compressors are
supplied with enclosed distance pieces and vented seals. The commenter
disagreed with EPA's assumption that all new compression capacity results
from installation of new units. The cornmenter pointed out that many
newly installed compressors are existing units that have been rebuilt.
Hence, retrofitting controls onto these rebuilt compressors may result
in considerable delay and expense.
Response: The effective date of the standards is the date of
promulgation; however, all newly installed compressors at a plant,
rebuilt compressors and factory new compressors, are subject to the
standards if they are constructed after the applicability (proposal)
date of the standards (January 20, 1984), unless they are specifically
exempted (e.g., wet gas reciprocating compressors, or not "in VOC service"),
The EPA made no attempt to correlate the number of new compressors with
the amount of new gas to be produced. New compressors will be well
controlled, and rebuilt compressors will be controlled as well.
As stated in a previous response to comment, compressors would be
exempt from the reconstruction provisions of the General Provisions if
controls are technically or economically infeasible (Section 60.15(e)
of the General Provisions).
Furthermore, since proposal, EPA has decided to exempt all recipro-
cating compressors in wet gas service. Therefore, the only reciprocating
compressors covered by the standards are those in NGL service.
5.5 ALASKAN NORTH SLOPE
Comment: One commenter (iV-F-ld; IV-D-2H), in both written
comments and public hearing testimony, requested that natural gas
processing plants located north of the Arctic Circle be exempted from
the proposed standards. The commenter based his request on higher
control costs per unit of emission reduction, as follows:
5-13
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1. The commenter cited the higher cost of operation in arctic
regions. Due to the extreme environment, processing facilities
must be completely enclosed. Since plants are enclosed;
space is limited, and safety is of paramount importance.
Consequently, any design changes or retrofitting in arctic
facilities is extremely expensive. Another important factor
that increases the costs of operation in the Arctic is the
high cost of labor. The commenter indicated that a technician
in the Arctic costs approximately $124 per hour in 1980 (based
on $33.50 per hour wage plus 370 percent administrative and
overhead) due to the requirement for extensive life support
systems and area labor costs.
2. The commenter thought that the basic rationale for uniform
national VOC standards, to prevent the creation of local
pollution shelters, is inapplicable in the Arctic. The degree
of low solar insolation, the low concentration of photochemical
precursors, and the cold ambient temperatures lead to a lack
of photochemical ozone formation. Additionally, since processing
facilities are enclosed, sophisticated gas detection systems
are utilized to ensure safety which would detect leaks of VOC
from processing equipment. Based on these factors, the
commenter concluded that the standards would provide no
emission reduction.
Response: The presence of an in-place hydrocarbon gas detection
system does not necessarily ensure emission reductions. Several rnega-
grams of VOC could be released to the atmosphere annually without the
use of specific control techniques like those required by the standards.
The commenter did not demonstrate that their system resulted in at .
least equivalent emission reductions as the standards. Based on EPA's
experience, gas detection systems alone are ineffective for reducing
equipment leaks of VOC. Thus, EPA has not exempted process units using
these systems from the standards. The promulgated standards do, however,
allow an existing control program to be continued if EPA determines
that the program is at least equivalent to the requirements of the
standards. 40 CFR 60.634
The EPA has studied the commenter's concerns and acknowledges that
there are several unique aspects to the operation of natural gas processing
plants north of the Arctic Circle. Because of the unique aspects of
natural gas processing plants north of the Arctic Circle, the increased
costs to perform routine leak detection and repair may result in an
unreasonable cost effectiveness. These operations incur higher labor,
administrative, and support costs associated with leak detection and
repair programs because (1) they are located at great distances from
major population centers, (2) they must necessarily deal with the
long-term, extremely low temperatures of the Arctic, and, consequently,
(3) they must provide extraordinary services for plant personnel.
Therefore, EPA has decided that natural gas processing plants in the
North Slope of Alaska are exempt from the routine leak detection and
repair requirements of the standards. This exemption does not include
the equipment requirements in the standards because installation of
equipment controls is common practice in the region.
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5.6 SMALL PLANTS
Comment: Several commenters (iV-F-la, IV-D-15, IV-D-20; IV-D-21, IV-D-23,
IV-D-26, IV-D-29, IV-D-30, IV-D-31, IV-D-36) requested that the small
plant exemption size limit be revised. One commenter (IV-D-15) agreed
with the small plant size limit of 10 MMscfd, but he, along with commenter
IV-D-20, stated that the plant size exemption should be based on throughput
instead of capacity. The commenter indicated that the same staff and
economic considerations used by EPA to determine the appropriate cutoff
apply to a throughput-based cutoff. Other commenters requested that the
plant size limit be raised. Two commenters (IV-F-la and IV-D-29)
requested that the 10 MMscfd or less plant exemption include fractionating
plants, and that the exemption be extended to somewhere between 35 to 50
MMscfd for nonfractionating plants.
Other commenters argued that the small plant size limit should be
raised to 35 MMscfd. Several commenters (IV-D-21; IV-D-26; IV-D-36)
provided cost and emission reduction data from a recently completed leak
detection and repair program in support of a 35 MMscfd cutoff. One
commenter (IV-D-30) offered several reasons for raising the small plant
size limit to 35 MMscfd, including that EPA had overstated the potential
emissions reduction, tha-t the cost to implement the standards was
underestimated by EPA due to the ignoring of the substantial clerical
requirements, and EPA ignored the remoteness and lack of personnel at
small facilities. Another commenter (IV-D-23) based his request
to raise the small plant cutoff to 35 MMscfd (including fractionation)
on EPA misconceptions of the average gas processing plant size. The
average plant size, he contends, is biased by a few extremely large gas
plants processing billions of standard cubic feet per day of natural gas.
Commenter IV-D-33 requested that EPA consider the extra travel
time in getting to remote plant sites in setting the cutoff and the
effect of extreme climatic conditions on travel schedule. In addition,
the commenter stated that many gas plants with capacities of 10 MMscfd or
less, whether they fractionate or not, are only j>artial ly attended or
unattended. The commenter cited as examples two types of gas plants,
straddle plants and casinghead plants, that differ in their staffing
requirements and profitability because of their different numbers of
pieces of equipment and feed rates. The commenter further stated that if
his company hires an outside contractor, the recordkeeping and reporting
requirements alone would be sufficient to warrant hiring a person at a
cost of about $36,000 per year for each central office. The commenter
concluded that there would be an obvious negative impact on plant efforts
to improve manpower productivity.
Response: As presented in Appendix F of the BID for the proposed
standards, EPA carefully analyzed the cost effectiveness of routine
leak detection and repair programs for small, nonfractionating plants.
The cost effectiveness values derived were presented graphically on
page F-7 and are reproduced in Figure 5-1 on the next page. The graph
in Figure 5-1 shows that the cost per megagrarn VOC reduced begins to
increase rapidly as the plant throughput falls below 10 MMscfd. There-
fore, 10 MMscfd represents an appropriate cutoff, and nonfractionating
plants processing more than 10 MMscfd are subject to the monitoring
requirements of the standards.
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10-
B
8 6-\
o
3 4-J
>
8
0
Appendix F of BID for proposed standards
r r
10 IS 20
PLANT SI2E (MHscfd) -
I
25
30
35
45
so
Figure 5-1. Cost Effectiveness versus Plant Size for Small Plants
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Figure 5-1 also shows that the basis for the siilall plant leak
detection and repair programs has been changed slightly since proposal.
The primary revision to the cost basis was in changing the instrument
cost. The analysis presented in Appendix F of the BID for the proposed
standards was based on the assumption that each plant would maintain
two monitoring instruments. However, if the monitoring is to be performed
by contractors or central office personnel, it is likely that the
instrument cost would be distributed among several plants. The revised
cost is based on the assumption that the contractor or central office
personnel would maintain two instruments but would use these instruments
among five plants. Complete details of the revised costs are available
in Docket Item IV-B-6.
The cost effectiveness values presented in Figure 5-1 are based on
the cost of performing the required leak detection and repair program
using either contractor or central office personnel. These costs
include travel costs, as well as additional rnanhours for travel time.
Since fractionating plants are more complex than nonfractionating
plants, both physically and operationally, plants having fractionation
trains are likely to have full-time operating and maintenance personnel
available to perform the monitoring program "in house." The costs of
such an "in house" program would be greatly reduced from a program
requiring expenses for outside personnel and travel; consequently, an
"in-house" program would result in a much better cost effectiveness.
Fractionating plants are subject, therefore, to the requirements for
routine monitoring regardless of capacity.
Some commenters requested that the small plant exclusion be
based on throughput rather than capacity. Although the economics
(as well as the emissions) of plant operation is highly dependent on
the process throughput, capacity is the appropriate defining factor for
excluding small plants. Throughput may vary from day to day; therefore,
a small plant exclusion based on throughput would be unmanageable. An
affected facility within the plant may be covered by the standards
while operating under one capacity, but as the throughput decreases,
the facility may be exempt. This system would require extensive
recordkeeping and would be difficult to enforce. Since the plant
capacity remains constant, and the plant throughput is limited by the
capacity, the exclusion is based on plant capacity.
Comment: One commenter (IV-D-35) recommended that all intermit-
tently attended gas plants be exempted from the proposed standards. The
commenter claimed that in both casually attended and partially attended
plant situations, the proposed standards could force premature
abandonment of many remote or marginal wells, while plants manned 24
hours per day would, in all likelihood, have sufficient personnel to
perform the monitoring, recordkeeping, and reporting required by the
standards.
Response: The standards have an insignificant effect on the
abandonment of wells because the costs of compliance with the standards
are very small compared to the operating costs of a plant and the
revenues generated by a plant. The LPA agrees with the commenter that
there are some relatively small plants that operate without technically
trained personnel being present because of the type of process that is
5-17
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performed there. The EPA was aware of such plants and considered the
burden imposed upon small plants subject to the standards. At proposal,
EPA exempted small nonfractionating plants (capacity of 10 MMscfd or
less) from the standards. Assuming that nonfractionating plants would
hire contractors or use central office personnel to perform the leak
detection and repair program, EPA determined that it would not be cost
effective to require these plants with 10 MMscfd or less capacity to
perform the routine leak detection and repair requirements. The LPA
believes, however, that fractionating plants require the presence of
technically trained personnel having the ability to carry out responsibly
a leak detection and repair program.
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6.0 ENVIRONMENTAL IMPACTS
6.1 EMISSION REDUCTIONS
Comment: One commenter (IV-D-20) did not agree with the EPA
estimates of the environmental benefit from implementation of the
standards. The commenter wrote that EPA's assumptions regarding typical
plant size, inventories of valves, and the number of plants to be built
in the future overestimate emission reductions. The commenter requested
that EPA re-evaluate the estimates.
The commenter noted that the emission reduction estimates are based
on Model Plant 13 and argued that Model Plant B is not reflective of
future gas plant sizes and designs. The commenter stated that most new
gas plants will be cryogenic plants due to operational and economic
reasons, and cryogenic plants have at least 50 percent fewer valves than
EPA estimated for a "typical" Model Plant (3.
The commenter also took issue with EPA's average emission factor
of 6.3 kg/day for compressors, stating that since few new plants will
have compressors in NGL service, the emission factor of 1.9 kg/day
given by EPA for wet gas compressors should be used for all compressor
calculations. Another commenter (IV-D-35) indicated that the Rockwell
study (Docket Item II-I-20) showed the maximum compressor VOC emission
factor is 1.5 Ib/day (0.68 kg/day).
The commenter recalculated the emission reductions and estimated
that the standards would control only 5,159 Mg/yr based on his assumptions
that (1) Model Plant B contains 250 valves, (2) 1983 plant construction
is not included, (3) compressor emission factor for Model Plants A, B, and
C is 1.90 kg/day, and (4) emission reductions from capping open-ended lines
are not included. The commenter also presented valve counts and plant
capacity for four gas processing plants to support his argument that
new gas plants would have fewer valves than EPA estimates. Based on data
from 1982-1983 Hydrocarbon Processing Construction, the commenter stated
that more than 60 percent of the new plants constructed were 25 MMscfd
or less in contrast to EPA's estimated average capacity of 90 MMscfd.
Response: The EPA provides nationwide environmental impacts
to illustrate the potential emission reduction associated with the
standards on emission levels anticipated in the future. Promulgation
of the standards, however, is based on the availability of demonstrated
cost-effective control techniques. Even if the nationwide impacts
presented in the preamble to the proposed standards were overstated,
the point is that significant emissions are attributable to natural
gas processing plants and that growth is predicted in the industry.
In addition, cost-effective controls are available to reduce these
emissions significantly. Therefore, new source performance standards
should be promulgated for the industry.
The EPA noted several misconceptions in the conlinenter's analysis of
nationwide impacts. Primarily, these faults are as follows:
6-1
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The commenter suggested using a compressor emission factor of
1.9 kg/day for all compressors, based on emissions from wet gas
compressors, because few plants would have compressors in NGL
service. Test data used by EPA in developing the proposed
standards (as given in Appendix G of the BID for the proposed
standards) showed that 34 percent of all compressors were in
NGL service. Thus, the basis for using 34 percent NGL service
compressors was actual test data rather than assumption.
The commenter claimed that emission reductions from open-ended
lines should not be considered a result of the NSPS, since lines
in his plants are capped already. As evidenced by EPA plant
visits and other comments pointing out difficulties in capping
open-ended lines, most gas plants do not cap or plug open-ended
lines. Therefore, it is unrealistic to exclude open-ended
line emissions from the environmental impacts of the standards.
The commenter based his emission reduction impacts on 250 valves
in Model Plant B. The EPA recognizes that different designs for
the same plant process will utilize widely variable numbers
of components due to the level of control desired and the
economics of construction. The valve counts used in the BID
for the proposed standards were based on actual operating
plants and represent average values. Since Model Plant B is
intended to represent a relatively complex plant, such as a
fractionating cryogenic plant or a nonfractionating refrigerated
absorption plant, 750 valves is an appropriate count. Test
data supplied by the Gas Processors Association for the Conoco
Cashion plant showed 540 components (mostly valves) for a
30 MMscfd nonfractionating cryogenic plant, which would be a
Model Plant A.
The commenter disagreed with the inclusion of 1983 emission
reductions. The emission reductions are presented to show a
fifth-year impact, rather than the impacts by given calendar
years. Although 1983 emission reductions will not occur, a new
5-year impact analysis would include 1987 reductions with
the same results. The projected emissions and emission
reductions from baseline levels of control through 1987 are
presented in Table 1-1.
Comment: Another commenter (IV-D-22) believed that the emission
reduction estimates were overstated. The commenter based his argument
on the premise that most of the VOC emission reduction resulting from
the standards will be achieved during the initial testing and that
subsequent monthly tests are not justified. The commenter noted that
initial testing at a gas plant found many leaking valves (over
100,000 ppm). The second test at this plant found 19 leaks out of 508
components. Of these, more than 50 percent had readings less than
50,000 ppm arid only 1 greater than 100,000 ppm. Similarly, initial
testing at another plant found many leaks with a soap score over 4,
while a second test 19 months later found only two leaks with a soap
score of 4.
6-2
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The commenter presented a comparison between soap solution test
results and results obtained using a Foxboro OVA-108 monitoring
instrument as his method of establishing a relationship between measured
VOC concentrations and leak rate. The commenter estimated that a
monthly program would achieve an incremental reduction of 1,709 kg/yr
more than an annual monitoring program. Therefore, the commenter
concluded that annual monitoring of all components would serve both
EPA's goal of establishing standards that will improve and maintain the
environment and industry's goal of supplying the public with competitively
priced products.
Response: The commenter contends that, although the leak frequencies
used by EPA may be correct, new leaks occurring or recurring during the
period between tests will be smaller than leaks found during initial
testing. The assumption that more recent leaks will be smaller is
true, as evidenced by the data presented by the commenter. However,
the leak detection and repair programs are not intended as a means of
repairing massive leaks, but rather as a means of preventing such
leaks. The leaks discovered in each followup inspection are likely to
be smaller than those found in the initial inspection which have developed
over an extended period. This fact is the reason for shortening the
monitoring period to monthly, as significant emissions can be prevented
from occurring. If the leak detection and repair program were not
performed, the leaks left undiscovered and unrepaired would eventually
return to the magnitude found during the initial inspection. The
commenter is partially correct in stating that most of the emission
reductions occur in the initial monitoring period. In fact, the ongoing
program provides the work practice to prevent these emissions from
occurring again.
In response to the commenter's claims of low incremental emission
reduction between monthly and annual monitoring, the standards allow
special provisions to prevent the unwarranted monitoring of nonleaking
sources. These provisions include monthly/quarterly monitoring for all
plants and skip-period monitoring, or alternative standards, for low
leak rate plants, which are discussed in detail in Section 6.2.
Comment: One commenter (II-D-10) noted that there is no scientific
basis for assuming a "significant emissions reduction," since there is
no definitive quantitative study demonstrating fugitive emission
reduction from an inspection and maintenance program for refineries or
gas plants. Furthermore, the commenter added that EPA had no technical
basis for the transfer of chemical plant or refinery VOC emissions
data to gas plants.
Response: This comment was made in Hay 1981 by API and is included
at their request (IV-F-le). Since that time, several leak detection
and repair programs have been conducted by both EPA and industry.
To assess the potential effects of leak detection and repair programs,
EPA conducted emissions testing at gas plants and related facilities.
The results of the EPA gas plant emissions tests, combined with the
results of the API/Rockwell study, formed the basis for the gas plant
emission factors (Docket Item II-A-23) and subsequent emission estimates.
To assess the control technique (leak detection and repair) for valve,
6-3
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pump, and relief device emissions, EPA has performed a maintenance
effectiveness study (Docket Item II-A-11) and has examined the results
of on-yoing State and local equipment leak rules. These studies all
support the effectiveness of leak detection and repair for reducing
emissions. Although most of the studies were performed for refineries,
the components regulated in gas plants are identical or very similar,
and the same results are expected. Therefore, transfer of refinery/
chemical data to gas plants is reasonable.
6.2 LEAK FREQUENCIES
Comment: One commenter (IV-F-2) submitted in-plant leak screening
test data for a 20 MMscfd fractionating plant, a plant the commenter
considered as typical of current industry design and construction. The
first test was conducted on 4,195 components, including flanged and
screwed connections. Using the API Soap Score Method and recording
scores of 3 or greater as a leak, 61 components or 1.45 percent were
found leaking. A second test was performed 18 months later on 722
components covered by the proposed standards (omitting flanged and
screwed connections) using API soap and instrument methods. Each test
method found 5 leaking components, all of which were valves corre-
sponding to a 0.68 percent leak rate. The commenter also provided the
total time taken to perform monitoring in each of these tests.
Based on these data, the commenter claimed EPA had both over-
estimated the emission reductions for the standards and underestimated
the control cost.
Response: The EPA recognizes that some plants will have a low
rate of leaks, either due to good maintenance practices or other factors,
and also recognizes that frequent leak monitoring for such low leak
facilities is not cost effective. Consequently, EPA provided standards
for valves in which nonleaking valves may be monitored less frequently.
For example, in the commenter's case, the second test resulted in only
5 leaks out of 722 components. If a test the next month gave the same
results, the nonleaking valves, which are likely to be most of the 717
nonleaking sources, would then be monitored quarterly. The plant would
also be a likely candidate for the "allowable percentage of valves
leaking" alternative provided in Section 60.633-1 of the proposed
standards. After the initial performance test, the facility could
elect to use annual perfonnance tests to demonstrate that less than
2 percent of all valves were leaking. Otherwise, the plant could use
the skip-period monitoring program, as specified in Section 60.633-2,
to reduce the monitoring frequency for valves to semiannually or
annually. The standards provide enough flexibility to increase cost
effectiveness and avoid the unnecessary monitoring of nonleakers.
The commenter indicated that the total monitoring time for 722
components using the hydrocarbon monitoring instrument was 14.4 hours.
Assuming a two-man crew performed the monitoring, this equates to
approximately 2.4 man-minutes per source. As shown in Table 8-3 of the
BID for the proposed standards, Model Plant B has 774 components, which
were estimated to require 121 labor hours per year on a quarterly
basis, or 30.25 man-hours per monitoring cycle. This results in an
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average monitoring time of 2.34 man-minutes per component. These two
values are nearly identical, so that the commenter's monitoring time
supports EPA's estimated monitoring time.
6.3 EMISSION FACTORS
Comment: API (II-D-10) stated that EPA's assertion that the
Rockwell compressor seal factor "probably underestimates emissions" is
speculation and is untrue, according to the Rockwell research team
leader.
Response: The Rockwell compressor emission factor is based on EPA
and API testing of emissions into the distance piece area from only
open frame compressors. The factor does not include emissions into the
seal packing vent or into enclosed distance pieces. Therefore, the
Rockwell emission factor is probably understated substantially. A
revised emission factor, discussed in the BID for the proposed standards
(Appendix G), was necessary because a review of the data used in developing
the 1 kg/day emission factor showed that a large portion of the data
were from residue (dry) gas compressors, which EPA intended to exempt.
Therefore, the overall emission factor of 1 kg/day was not representative
of the population of compressors to be regulated. The revised emission
factor (6.4 kg/day) is based on a weighted average of emission factors
for compressors in both wet gas and NGL service because there is a
large difference in process stream VOC concentration between wet gas
and NGL service compressors.
Comment: Two comrnenters (IV-D-13 and IV-D-19) stated that EPA
had overestimated the number of centrifugal compressors in assuming
that 50 percent of all compressors would be centrifugal. One commenter
wrote that about 10 percent are centrifugal and 90 percent are
reciprocating. Commenter IV-D-13 stated that, because of this assumption,
EPA overestimated compressor VOC emissions, which are minor compared to
total VOC emissions. The commenter suggested that the compressor
requirements be eliminated.
Response: In all analyses of compressor controls, EPA used an
average emission factor for all types of compressors, including
centrifugal and reciprocating ones. Emissions are related to the
compressor service (NGL and wet gas), but not to the type or operation
of compressors (centrifugal and reciprocating). Therefore, the fraction
of compressors assumed to be centrifugal has no bearing on the compressor
emissions estimate. At proposal, EPA assumed that 50 percent of all
compressors would be centrifugal only in order to determine an average
cost for compressor control systems.
Comment: One commenter (IV-F-lb) stated that nonfractionating
plants will not use compressors in NGL service (unless a propane
refrigerant system is required to optimize plant recoveries). Therefore,
the commenter stated it would be more appropriate to base compressor
seal leakage on wet gas compressors only.
Response: As used in the HID for the proposed standards, as well
as the proposed standards, NGL service streams are considered to be
6-b
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a1! hydrocarbon streams that contain greater than 50 weight percent
VOC. Since the purpose of the natural gas plant is to extract hydro-
carbons from the methane residue gas, all natural gas plants have NGL
streams. Based on the content and physical characteristics of the NGL
produced, the NGL stream may be moved by either pumps (for low vapor
pressure products) or compressors (for high vapor pressure products).
For nonfractionating plants, the NGL stream produced is typically
either ethane and heavier hydrocarbons or propane and heavier hydro-
carbons. Either of these mixtures would likely be high vapor pressure
streams and would be transported from the process with compressors.
Therefore, EPA does not necessarily agree that nonfractionating plants
will not employ NGL compressors. Since an exemption for all wet gas
reciprocating compressors has been added to the promulgated standards,
NGL compressors represent an even larger portion of the affected
compressors than assumed at proposal.
Comment: Three commenters (IV-F-le; IV-D-31; IV-D-34) urged
that compressors be exempt from the standards because of the small
amount of reactive hydrocarbons emitted from compressors. Comrnenter
IV-F-le noted that compressors constitute less than 4 percent of
the total gas plant emission inventory.
Response: Compressor seal emissions were estimated in Appendix G
of the BID for the proposed standards to be 2.3 Mg/yr per seal, the
highest emission factor of all VOC emission sources in natural gas
plants. This average emission value was based on wet gas compressors
having emissions of 0.7 Mg/yr, and NGL compressors having emissions of
5.5 Mg/yr.
As shown in Table H-l of the BID for the proposed standards,
compressors represent 17.8 percent of the emission reduction from
implementing the standards for a typical new plant. Contrary to the
commenter's statement that compressors represent 4 percent of the gas
plant emission inventory, the Model Plant C compressor emissions (37.8
Kg/day) are 13.8 percent of the total uncontrolled Model Plant B
emissions.
Comment: One cornmenter (IV-D-33) saw no justification for the
baseline emission factors developed in Radian's July 1982 report (Docket
Item II-A-23). The commenter claimed, as an example, that the VOC
emission factor for valves (0.18 kg/day) was too high and should be
0.09 kg/day based on Table 1-2 of the Radian report and on the 95 percent
upper bound curve. The commenter determined that leak occurrence rates
of 18 percent at 100,000 ppmv (0.3b kg/day) and 82 percent at 500 ppmv
(0.03 kg/day) resulted in an emission factor of 0.09 ky/day.
Response: The commenter contends that, based on the data presented
in the EPA report "Frequency of Leak Occurrence and Emission Factors for
Natural Gas Liquid Plants" (80-FOL-l), the average emission factor for
valves should be 0.09 kg/day, rather than 0.18 kg/day used by EPA.
It is true that an average leak rate calculated from the commenter's
values of 500 ppmv and 100,000 ppmv would be 0.09 ky/day. However, the
arithmetic average of these values does not represent a true average
emission factor for all valves due to the log normal distribution of
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leak rates. Chapter 4 and Appendix C of the referenced document describe
in detail the statistical techniques used by EPA in developing the
final emission factor for valves (0.18 kg/day), which is presented in
Table C-2 of the document.
6.4 MODEL PLANTS
Comment: One cornmenter (II-D-10, II-D-30) questioned the basis for
the model plant analysis. The cornmenter questioned the use of components
per vessel in developing model plants since different vessels have
different functions and require different controls. In addition, the
cornmenter said the use of industry-tested plants to determine the
ratios of numbers of vessels is unrealistic because the API/Rockwell
study did not attempt to assess emissions from typical gas plants. The
Rockwell study, according to the cornmenter, was designed to assess
emissions from typical components in gas plants; and Rockwell determined
the number and variety of components after a preliminary site visit to
the facilities.
Response: Since this comment was submitted in Hay 1981, EPA has
incorporated data from test programs at two additional plants into the
analysis. The model plants used in the analysis represent different
levels of process complexity based on numbers of components in the
process rather than on the function of the vessel. Vessels do vary in
terms of function and control required, but the function or process
method (e.g., refrigerated absorption, cryogenic) is not as appropriate
in describing plant complexity as are numbers of components. Appendix B
of the CTG for the natural gas production industry discusses the basis
for the analysis, including a description of the ratio calculations and
derivation of the component counts.
It should be noted that the cost and emission reductions on a per
piece of equipment basis for equipment leak prevention programs, with
the exception of compressor controls, is relatively independent of
component count. The regulatory alternatives presented in Chapters 7
through 9 of the BID for the proposed standards were used primarily to
illustrate the impacts of various available control strategies on typical
plants. The standards do not correspond with any one of the available
"regulatory alternatives," but are based on individually selected
control techniques for each component class. For this reason, prior to
proposing the standards, EPA performed a second cost analysis (Appendix H
of the BID for the proposed standards) based on different control techniques
for each component type rather than for model plants. This single component
control cost analysis served as the basis for the standards rather than the
model plants, which are used solely to estimate nationwide impacts.
6.5 NONAIR ENVIRONMENTAL IMPACTS
Comment: Two cornmenters (IV-F-lb and IV-D-15) disagreed with
EPA's claim of a positive impact on water quality from the standards.
The first cornmenter stated that most plant operators are required to
formulate and implement spill prevention control systems and measures.
He also noted that any VOC spills prevented would be likely to evaporate
before causing an impact on water quality. The second commenter indicated
6-7
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that liquid leaks that may affect water treatment systems are not the
principal focus of the proposed standards.
Response: The EPA realizes that most gas plant streams consist of
high vapor pressure components that, as indicated by the commenter,
will evaporate before entering drainage systems. However, some yas
plants do produce light liquid products. Leaks from the sources
handling light liquid products could be reasonably expected to enter
plant drainage systems. Although water quality impacts are probably
very minor, the impacts of the promulgated standards are positive.
The Clean Air Act directs EPA to consider the environmental impacts
that result from promulgation of new source performance standards.
Section 111 states that:
... a standard of performance shall reflect the degree of emission
limitation and the percentage reduction achievable through application
of the best technological system of continuous emission reduction which
(taking into consideration the cost of achieving such emission energy
reduction, any nonair quality health and environmental impact and
energy requirements) the Administrator determines has been adequately
demonstrated.
Hence, it is appropriate for EPA to have considered the water quality
impacts of the standards.
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7.0 COST OF CONTROL
7.1 GENERAL
Comment: One commenter (IV-D-3) claimed that all of the capital
costs presented in Table 8-1 of the BID for the proposed standards
are low. As an example, the commenter presented costs for compressor
distance piece flare piping. The commenter argued that very few com-
pressors in gas processing plants have only one cylinder and that most
compressors have four cylinders. The commenter reasoned, therefore,
that the capital cost of compressor distance piece piping ($2,451)
should be increased to $9,804 per compressor. The commenter maintained
that the same reasoning applies to the seal piping, gas supply system,
and the rest of the cost data.
Response: The capital costs for control equipment presented in
Table 8-1 of the BID for the proposed standards were all obtained from
vendors or industry sources. In developing the capital costs, EPA
attempted to generate cost estimates for control systems that would be
representative of the "worst-case" cost situations (for example, offset
mounting costs were included in the rupture disk installation cost
estimate). Consequently, other commenters believed the average actual
control costs should not exceed those- in the BID for the proposed
standards.
The commenter indicated that the capital costs for control of
compressor distance piece piping would be low by a factor of four if
the plant had four-cylinder compressors. The commenter is correct in
realizing that, since the items included in the "distance piece piping"
cost must be installed on each distance piece, a four-cylinder
"compressor" would actually cost four times as much. However, the
capital costs in the BID for the proposed standards are presented
on an "emission source" basis, which, for the case of compressors, is
each compressor seal. Since the four-cylinder compressors would have
four controlled seals, the emission reductions would also be quadrupled,
with no change in the control cost effectiveness.
Comment: One commenter (IV-D-3) indicated that the energy savings
or recovery credits for hydrocarbons are very misleading. The commenter
indicated that, according to Table 7-5 of the BID for the proposed
standards, the equivalent of 750,000 barrels of oil over 5 years would
would be recovered under Regulatory Alternative II. The commenter
stated that this recovery would barely cover the cost of the necessary
additional compression and operational costs to recover the hydrocarbons.
Response: The data presented in Table 7-5 of the BID for the
proposed standards indicate the energy impacts of the NSPS. These data
are not intended to illustrate the economic impacts of the energy
supplies recovered, but are intended to show the impacts of the standards
on the national energy reserves.
For standards requiring add-on control devices for vented process
streams (such as condensers or adsorbers), energy expenditures for
operation of the control equipment would be included in the analysis of
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the regulatory impacts. For example, a condenser system for control of
a VOC vent stream, while recovering energy potential, would expend
energy for operating recovery pumps, the refrigeration system, etc.
For the equipment leaks NSPS, however, no additional equipment is
required in order to prevent losses of hydrocarbons from valves, relief
devices, pumps, or open-ended lines. The energy values "recovered" by
preventing leak losses from these sources, therefore, are not offset by
operational energy requirements.
EPA concurs with the cormnenter that the energy values saved do not
completely offset the monetary cost of performing the programs required
by the standards. However, the net cost effectiveness, as presented in
Appendix H of the BID for the proposed standards, is reasonable.
Comment: One commenter (II-D-10) stated that in using recovery
credits for demonstrating cost effectiveness, it is misleading to include
quarterly or monthly monitoring results with total recovery on an annual
basis. The commenter further stated that credits gained after the initial
baseline screening and repair are relatively small and are only 10 percent
per quarter or 5 percent per month (according to EPA estimates of percent
leaks initially detected for quarterly and monthly monitoring).
Response: API submitted this comment prior to proposal and requested
that it be included in the rulemaking (IV-F-le). API contends that,
since fewer leaks are found during follow-up inspections than during
the initial inspections, the recovery credits should be based on the
quantity of emissions reduced during a follow-up test, rather than
the reductions from the initial inspection.
As explained in Section 6.1, the leak detection and repair programs
required by the standards are intended to prevent leakage from occurring.
The initial inspection of a facility demonstrates the emission rate
from the facility in the absence of a routine leak and repair program.
A leak detection and repair program providing nearly 100 percent
control would have almost no leaks detected during follow-up inspections
and, therefore, would provide an emission reduction equal to the uncon-
trolled emissions on a continuous basi.s. The EPA considers this reduction
from the uncontrolled leak rates to be the proper basis for the calculation
of recovery credits.
Comment: One commenter (II-D-30) remarked that "front-end costs"
should not be equated with "capital costs." For example, double valving
open-ended lines and initial leak repair are front-end expenses that
should be considered as operating costs. The commenter added that only
the VOC analyzer and the compressor piping should be defined as capital
costs and that remaining costs incurred are classified as expenses.
According to the commenter, expense and capital costs cannot be combined
without using an amortization schedule.
Response: API submitted this comment prior to proposal and requested
that it be included in the rulemaking (IV-F-le). Although the control
cost of open-ended lines and initial leak repair could be treated as
operating expenses, they are treated as though they were capital costs
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and are amortized for the purposes of these standards, because they are
one-time, start-up costs. This assumes capital would be borrowed
to pay these initial costs.
Comment: One cornrnenter (IV-D-30), stating that most new, small
plants are designed to operate unattended, claimed that the costs
associated with repair have been grossly underestimated in the BID for
the proposed standards. Similarly, another cornmenter (IV-D-29) stated
that the effect of the proposed standards on the small, partially-
attended plants is not cost effective. The commenter quoted an annual
monitoring cost of $39,191.52 compared to EPA's estimate of $970 for
the direct monitoring cost for Model Plant A and indicated that EPA
failed to include costs for training labor, scheduling, preparation,
travel, direct management, supply personnel, reporting, recordkeeping,
setting up a system of compliance, tagging, and problem-solving. The
commenter said that, given that gas processing plants do not contribute
significantly to air pollution, these anticipated related costs are
disproportionate to the marginal benefit derived and, hence, are not
cost effective.
Response: The commenters contend that, since small plants are
minimally attended, the costs of the standards presented by EPA are
unrealistic. The cost analyses presented in Chapter 8 of the BID for
the proposed standards were based on leak detection and repair programs
being performed by plant personnel. The EPA recognized, prior to
proposing the standards, that small gas plants may not have adequate
staffing to perform the leak detection and repair program. Therefore,
based on industry supplied data, EPA performed a separate cost analysis
for small, unattended plants based on leak detection and repair programs
being performed by corporate office personnel. These analyses were
presented in Appendix F of the BID for the proposed standards and
showed that the cost effectiveness of monitoring programs deteriorated
rapidly for plants smaller than 10 MMscfd. Consequently, plants with
capacities of 10 MMscfd and less were exempted from routine leak detection
and repair programs at proposal.
The commenters mentioned numerous administrative items not
specifically included in the EPA cost analyses. In preparing cost
analyses for regulatory alternatives, EPA includes a percentage add-on
to all control labor costs to account for administrative costs. Although
EPA added 40 percent of the direct labor cost for general and adminis-
trative costs in analyzing the cost of the standards, the Agency believes
that once the program is established, administrative costs will be much
1ower.
7.2 COMPRESSORS
Comment: One commenter (IV-D-21) thought that the costs to control
emissions from compressor seals are unreasonable, considering the small
return (emissions reduction) from emission control and, therefore,
recommended that compressor seal control system requirements be deleted.
The commenter also argued that the costs of controlling compressors are
particularly high, considering the nature of the emission sources which
include several small compressors. The commenter also remarked that
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the burden of compliance will fall on existing as well as new -jar;
plants since replacement of a single compressor will result in dn
affected facility. Existing plants with some portion of a control
system, such as a flare, will require new systems since the existing
equipment is not designed for VOC emission control. Thus, the marginal
operating economics of these facilities makes the costs unreasonably high.
Response: The commenter contends that all compressors should be
excluded from the promulgated standards because the emission reductions
achieved do not justify the control cost. The selection of the require-
ments of the standards was based on control cost effectiveness, that
is, the cost per unit mass of emission reduction. At proposal, the
control cost effectiveness for compressors was based on a weighted
average emission factor assuming 66 percent of all compressors are in
wet gas service and 34 percent of all compressors are in natural gas
liquids (NGL) service. These weighting factors were based on component
inventories observed during testing at operating gas plants. Given
compressor emission factors of 0.7 Mg/yr and 5.5 Mg/yr for wet gas and
NGL service, respectively, a weighted average emission factor of
2.3 Mg/yr was used in analyzing the compressor control cost effectiveness
(Docket Item II-B-35).
Since control costs for reciprocating compressors were higher than
those for centrifugal compressors, EPA averaged the costs for the two
compressor types to obtain an average compressor control cost of $6,400/yr
based on one-half of all compressors requiring an add-on control device
as explained in Appendix H of the BID for the proposed standards. Using
these cost and emission reduction values, the cost effectiveness of compressor
seal vent control systems was $460/Mg, which EPA considered reasonable.
Since proposal, as discussed in the response to the next comment,
EPA decided to exempt all wet gas reciprocating compressors from the
promulgated standards. As shown in Table 7-1, the control cost-
effectiveness values of all other compressors are reasonable. Therefore,
all compressors except wet gas reciprocating compressors are covered by
the promulgated standards.
Comment: Several cornmenters (II-D-30; IV-D-13; IV-D-23; IV-D-26;
IV-D-29; IV-D-33; IV-F-la; IV-F-lb) indicated that EPA had underestimated
the average cost of compressor seal vent control systems by assuming
that 50 percent of the compressors used will be of the centrifugal type.
One of these commenters (IV-D-26) provided a recent industry survey
showing that out of over 3,000 compressors, centrifugal compressors are
utilized in only 9.8 percent of the applications of the companies
surveyed. Another commenter (IV-F-lb) stated that small plants will
almost exclusively utilize reciprocating compressors for technical and
economic reasons. One commenter (IV-D-33) estimated that the cost for
a reciprocating compressor seal vent system would be about $28,000
(including installation, foundation, and flare support). When factored
into EPA's revised cost analysis (Docket Item II-B-37 and BID Appendix
G), the commenter felt his estimate will justify the exemptions for
reciprocating compressors in NGL or 100 percent VOC service when no
control device is present. Another commenter (IV-D-34) stated that
control costs were extremely high and unjustified and recommended that
all compressors be exempt from the standards.
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TABLE 7-1
COST EFFECTIVENESS OF COMPRESSOR VENT
CONTROL SYSTEMS FOR MODEL PLANT B*
Control Device
Compressor Type Present Cost Effectiveness ($/Mg)
Centrifugal - Wet Gas No 710
Yes 280
Centrifugal - NGL No 91
Yes 36
Reciprocating - NGL No 280
Yes 200
*From the BID for the proposed standards, Appendix G, Table 1, page G-14.
These comrnenters recommended that compressor requirements be
eliminated from the standards, since a cost analysis based on recipro-
cating compressors only would show the cost effectiveness of compressor
controls to be marginal.
Response: In determining the costs and cost effectiveness
associated with controlling VOC emissions from compressors at proposal,
EPA considered the costs for eight individual compressor control
configurations. Specifically, EPA calculated the costs for two types
of compressors (reciprocating and centrifugal) in two different VOC
services (wet gas or NGL at plants either with or without an already
existing control device). The resulting compressor control configurations
and the cost effectiveness for each one are presented in Appendix G,
Table 1 of the BID for the proposed standards. The cost effectiveness
for each configuration ranged from $36/Mg, for a centrifugal compressor
in NGL service at a plant with an existing control device, to $2,200/Mg
for a reciprocating compressor in wet gas service at a plant without an
existing control device. The $2,200/Mg cost includes the cost of
installing and operating a flare as the control device.
The cost effectiveness of controlling reciprocating compressors in
wet gas service at a plant without a control device ($2,200/Mg) was
judged to be unreasonably high and, therefore, these compressors were
exempted from the proposed standards. The cost effectiveness of
controlling this same type of compressor at a plant with an existing
control device was $l,700/Mg. This cost effectiveness was considered
to be borderline in terms of whether it was reasonable or unreasonably
high. In making this judgment, EPA assumed that typical gas plants
would employ both centrifugal and reciprocating compressors (about
50 percent centrifugal and 50 percent reciprocating). About one-
third of these compressors would be used in NGL service and the other
two-thirds would be used in wet gas service. Because these other
compressors can be controlled at much lower costs, the average cost
7-5
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effectiveness for the plant to control compressor emissions would be
closer to $460/Mg than it would be to $l,700/Hg. This cost effectiveness
was judged to be reasonable. Thus, EPA decided not to exempt from the
proposed standards reciprocating compressors in wet yas service at a
plant with a control device present.
Since proposal, the comrnenters have indicated that many plants,
especially small plants, may have significantly more reciprocating
compressors than centrifugal compressors, and, in some cases, an
individual plant may have only reciprocating compressors. In addition,
other commenters stated that all compressors at some plants would be
in wet gas service (i.e., there would be no compressors in NGL service
at some plants). For plants like the examples cited by the commenters,
the overall compressor control cost effectiveness would be $l,700/Mg
rather than the $460/Mg assumed at proposal. The $l,700/Mg cost
effectiveness was judged to be unreasonably high as an average control
cost effectiveness for wet yas reciprocating compressors at plants with
an existing control device. For this reason, all wet gas reciprocating
compressors, including those located at a plant without a control device,
are exempt from the promulgated standards.
However, reciprocating compressors used in NGL service and all
centrifugal compressors in wet gas or NGL service are still required to
be equipped with closed vent systems because they can be controlled at
a reasonable cost effectiveness, as shown in Table 7-1.
The average cost-effectiveness values for the compressor config-
urations (wet gas reciprocating, wet gas centrifugal, NGL reciprocating,
and NGL centrifugal) are shown in Table 3-1. The values in Table 3-1
are based on averaging the costs for each compressor configuration
(average cost of compressor with a control device and cost of compressor
without a control device) as presented in Appendix G, Table 1, of the
BID for the proposed standards. These values show that controls are
cost effective for all compressors except wet gas reciprocating
compressors. The promulgated standards, therefore, exempt all reciprocating
compressors in wet gas service.
7.3 PRESSURE RELIEF DEVICES
Comment: One commenter (IV-D-2) indicated that the offset-mounted
pressure reli ef valve/rupture disk configuration shown in Figure 4-1 of
the BID for the proposed standards is rarely used in industry. The
commenter said that current industry practice is to mount the rupture
disk directly under the relief valve except where fragmenting graphite
disks are used. The commenter noted that the offset was used before
the availability of nonfragmenting rupture disks and that nearly all
disk manufacturers now recommend a nonfraginenting rupture disk. This
mounting method is also recommended by American Petroleum Institute,
American Society of Mechanical Engineers, and Insurance Service Office
standards for rupture disk installation.
Response: The commenter, a rupture disk manufacturer, is concerned
that rupture disks may have been considered too costly by EPA due to
the assumption that offset mounting of the rupture disk and relief
7-6
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valve would be necessary. The cominenter is correct that EPA did assume
offset mounting of a rupture disk and that offset mounting would not
be required in many cases. However, the capital costs shown in Table 8-1
of the BID for the proposed standards show that the additional capital
cost for offset mounting is $21, which is less than 1 percent of the
total average capital cost ($3,100) for new rupture disk installations.
Since many rupture disks are of the fragmenting type, and offset mounting
would be required, EPA included the minor cost of offset mounting in
the cost estimates for pressure relief devices.
The EPA maintains the use of rupture disks as an alternative to leak
detection and repair, however, as provided in Section 60.632(d) of the
proposed standards. The use of rupture disks does allow for designation
of pressure relief devices equipped with rupture disks as leakless
equipment. In certain situations, plant operators may find rupture
disks preferable to routine monitoring of relief devices. Pressure
relief devices equipped with rupture disks require annual compliance
testing. The compliance test for relief devices can coincide with the
annual relief device safety tests normally performed by most gas plants.
Comment: One comrnenter (IV-D-2) requested that EPA change the
language for rupture disk system costs to delete the phrase "at
relatively high cost" in the preamble to the proposed standards:
"installation of the rupture disk controls an additional 500 kg/yr
but at the relatively high cost of $6,700/Mg" (49 FR page 2639).
The commenter agreed with EPA's cost calculations for rupture disk
systems, but preferred that plant owners or operators be allowed to
decide what is relatively high.
Response: The phrase "at relatively high cost" relates the cost
of rupture disk installations to that of routine leak detection and
repair for pressure relief devices. The EPA does not intend to
imply that rupture disks are overly expensive or of high cost, but
merely that rupture disks have relatively high cost compared to a leak
detection and repair program.
7.4 CONTROL DEVICES
Comment: Several commenters (IV-D-21, IV-D-23, IV-D-24, IV-D-29,
IV-D-31, IV-D-33, IV-F-la and b) indicated that EPA had substantially
understated the cost of a suitable dedicated flare system. One commenter
(IV-F-lb) indicated that a suitable flare system would cost over $60,000
(1980 dollars) compared to EPA's estimate of $11,000 shown on page G-9
of the BID for the proposed standards. Another (IV-D-23) provided a
minimum cost of $100,000 to install a new flare including a smokeless
flare tip, flare stack, foundation for the flare stack, and related
valving and piping based on actual new smokeless flares that have been
installed at his company's facilities. Other commenters (IV-D-24,
IV-F-la and IV-F-lb) stated that the cost analysis in the BID for the
proposed standards does not account for the flare velocity requirements
and fails to consider costs for the additional utility consumption
(i.e., steam, pilot and purge gases) and ancillary control systems.
One commenter (IV-D-33) could not determine from the EPA cost analysis
whether the cost of the larger flare had been included.
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Response: As discussed in Chapter 4, the velocity requirements
for flares do not apply during malfunctions. The EPA believes that most
emergency flares will have velocities below 60 ft/sec during normal
operating periods. The EPA has costed other available control devices for
compressors. The results of these analyses (Docket Item IV-B-7) show
that flares and other control devices are cost effective when used to
control emissions from wet gas and NGL centrifugal compressors, as well
as NGL reciprocating compressors.
Comment: One commenter (IV-D-21) pointed out limitations in using
process heaters as a VOC control device at his company. The commenter
noted that, as a control device, heaters would have hiyh operating
costs (since heaters normally operate only about 50 percent of the time
during the heating cycle of the regeneration process) and would not
meet the design and operating standards specified in Section 60.632-9(c)
of the proposed standards for efficiency, minimum residence time, or
minimum temperature. In addition, since heaters usually operate at 25
to 35 psig, all vents to the heater would have to be compressed, creating
greater costs and safety hazards.
Response: The EPA recognizes that, in many cases, process heaters
operate on a cyclical basis and are unsuitable for use as VOC control
devices. In those cases, the owner or operator would probably utilize
either a flare or other control device as opposed to continuously firing
the process heater (Docket Item IV-B-7). The 25 to 35 psig pressures
mentioned by the commenter are typical of process heater fuel lines.
However, the heater combustion chambers are normally close to atmospheric
pressures, and the vent stream may be routed directly to the combustion
chamber for control.
As discussed in Chapter 4, the temperature and residence time
parameters for incineration are provided as acceptable design parameters
to show compliance with the combustion efficiency requirement. These
parameters are not required; other temperatures and/or residence times
may be used.
Comment: One commenter (II-D-30) said that costs for adding double
valves on open-ended lines are underestimated because these costs should
include recordkeeping, vehicle use, and source identification and
tagging. In addition, the commenter wrote that the cost estimate for
capping open-ended lines is based on the price of a 1-inch, screw-on
type globe valve and the incorrect assumption that any lines larger
than 1 inch can be reduced to 1 inch. The commenter suggested that EPA
review the 721 open-ended lines tested as reported in Appendix A of the
CTG for equipment leaks of VOC in natural gas plants and base the costs
on a distribution of line sizes.
Response: API submitted this comment prior to proposal and requested
that it be included in the rulemaking (IV-F-le). Double valving an
open-ended line does not require additional recordkeeping or tagging
because the second valve would not be subject to the valve leak detection
and repair requirements.
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Complying with the standards does not necessitate installation of
a second valve. Open-ended lines may be capped or plugged at much
lower costs. The basis for the cost estimate is the price of a one-inch,
screw-on type globe valve, which reflects the maximum cost likely to be
incurred for control of open-ended line emissions. Larger lines would
likely have a blind flange installed at a similar cost, and smaller
lines would be capped or plugged at a much lower cost.
7.5 LEAK DETECTION AND REPAIR
Comment: One commenter (II-D-30) stated that the costs for the
labor associated with leak detection are severely underestimated, they
do not -apply to gas plants, and they are out of date. Monitoring time,
according to the commenter, is a function of such factors as plant
configuration, the monitoring method, the personnel, the weather, and
the location of the component. Monitoring labor charges of $4 per
source for contractor labor and $3.50 per source for plant personnel
(not including leak repair, resampling after repair, or initial design,
acquisition, or implementation of the monitoring network) were offered.
It was also argued that front-end set-up costs, equipment depreciation,
and instrument maintenance should be included, as well as cost of
platform for inaccessible sources [Note: This comment was made in
March 1982; therefore, the costs reflect that date].
Response: API submitted this comment prior to proposal and requested
that it be included in the rulemaking (IV-F-le). The monitoring time
estimates for plant equipment are based on the results of refinery
inspections and have been corroborated in chemical plant testing.
Since gas plants are similar in construction, and even more compact
than refineries, the monitoring time estimates are valid for gas plants.
Set-up costs, equipment depreciation, and instrument maintenance costs
are included in the cost analysis. Leak detection costs account for
field labor time only. Administrative, support, and instrument costs
to implement the standards are itemized separately. The leak detection
and repair costs are based on field monitoring under all weather conditions.
For Model Plant B, EPA's estimated costs fall within the range of costs
the commenter quotes. With 750 valves maintained at 2 man-minutes per
inspection and one-fourth the annual instrument cost of $5,500, the
cost per valve inspection is $2.67. The date the estimates were made
is unimportant, as a fixed-year basis is always used for making cost
comparisons. A comparison of costs for leak detection and repair
between industry and EPA estimates is presented in Docket Item IV-B-5.
Comment: Four commenters (IV-D-20; IV-D-21; IV-D-26; IV-D-36)
stated that the cost effectiveness of monthly monitoring for valves and
pumps is unreasonable and recommended that the monitoring frequency be
reduced to quarterly or annual. One commenter (IV-D-20) noted that
Table 1 of the preamble to the proposed standards shows that the
incremental emission reductions from quarterly to monthly monitoring
would be 7 percent for valves and 15 percent for pumps. The commenter
believed that this increase in emission reduction does not justify a
300 percent increase in monitoring time and costs. A second commenter
(IV-D-36) argued that a monthly program cannot be justified as cost
effective based on the costs incurred at Conoco's Cdshion plant, the
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significantly lower repair rate achieved, and the low leak rate which
occurred at the second test. A third commenter derived cost effective-
ness values of $1984/Mg (monthly), $768/Mg (quarterly), and $160/Mg
(annually) from monitoring program net annual costs and emission
reductions. The commenter based his cost estimates on the average bid
price of several leak detection contractors, and the emission reductions
(in part) for Regulatory Alternative III in Table 8-8 of the BID for
the proposed standards.
A fourth commenter (IV-D-21) said that an annual leak detection
and repair program for valves, relief devices, and pumps with a
corresponding annual report, would reduce industry's compliance cost
and still meet the goals of the Clean Air Act. The commenter thought
that a monthly leak detection and repair program is excessively burden-
some without much VOC emission reduction. In particular, scheduling
monthly monitoring is difficult because it would depend upon the
availability of outside personnel, weather problems, and unscheduled
plant problems.
Response: The goal of the Clean Air Act is to apply best
demonstrated technology (BDT) to newly constructed, modified, or
reconstructed sources. The Act requires that standards of performance
reflect the degree of emission limitation achievable through application
of the best adequately demonstrated technological system of continuous
emission reduction, taking into consideration the cost of achieving
such emission reduction, any nonair quality health and environmental
impacts and energy requirements. In selecting the basis of the standards
for valves, EPA considered quarterly and monthly monitoring as discussed
in Section 3.2. Each of these intervals was compared in tenns of the
emission reduction achievable and cost effectiveness of the leak detection
and repair programs as presented in Appendix H of the BID for the
proposed standards. Monthly monitoring was selected at proposal as the
basis for the standards for valves because it achieves the largest
emission reduction at reasonable costs and cost effectiveness.
Based on these estimates EPA considers monthly monitoring BDT for
valves.
Available data (Docket Items II-A-25 and II-A-37) indicate that
leak recurrence is an important factor in predicting leaks from valves.
If a valve leaks, then it is more likely to leak in the future than a
valve that has not leaked. These data also show that some valves leak
less frequently than others. Because leak recurrence can be important
in predicting leaks, EPA considers the annual cost of monthly monitoring
of valves that leak infrequently to be unreasonably high in comparison
to the annual cost of quarterly monitoring, considering the emission
reduction achieved by monthly and quarterly monitoring. Therefore, the
proposed standards allowed quarterly monitoring for valves that have
been found not to leak for 2 successive months, resulting in a monthly/
quarterly implementation program. The EPA expects that most affected
facilities would follow the monthly/quarterly schedule and that most
valves would be on the quarterly inspection schedule. The annual
emission reduction achieved by monthly/quarterly monitoring is 37.7 Mg
for a Model Plant B, and the cost effectiveness is a credit of $100/Mg.
The incremental cost effectiveness of monthly/quarterly from quarterly
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leak detection and repair is $240 per Mg (see Table 3-1). As stated
above, the selection of the standards was based on emission reduction,
cost effectiveness, and incremental cost effectiveness and not on the
percent increase between monthly and quarterly monitoring. Additionally,
the actual costs for valves under the standards is likely to be more
closely represented by the costs estimated for quarterly monitoring.
Consequently, the actual percent increase in cost will be far less than
the 300 percent increase claimed by one commenter.
In reviewing the data submitted by the commenters (Docket Item
IV-B-5), it was found that the commenters estimated total annual cost
to perform the leak detection and repair requirements of the standards
were generally in agreement with EPA's cost estimates. Costs projected
by commenters IV-D-21 and IV-D-22 were lower than the costs estimates
using the calculation method presented in the BID for the proposed
standards. The projected costs presented by commenter IV-D-26 from
contractor bids and the actual costs for one-time leak survey are
higher than costs estimated by EPA. However, these costs are similar
after correcting the GPA projections for several misconceptions in
the requirements of the standards and correcting accounting errors.
Table 7-2 presents a summary of the total annual cost estimates to
perform a leak detection and repair program at a 500-component gas plant.
The commenter included the costs to tag each component, record and
report more information than required, and other activities that would
not occur at a typical plant inspection. The contractor bids were also
based on 1984 dollars and did not consider that most components (i.e.,
valves) would be monitored on a quarterly rather than monthly basis.
Some of the contractors providing bids may not have had any experience
in leak detection and repair work (Docket Item IV-E-1), and could have
overestimated the cost of performing the work.
Comment: One commenter (IV-F-lb) stated that EPA had failed to
include several cost elements in their analyses of leak detection and
repair program costs. These items included:
t The initial setup costs for special flowsheets and component
identification,
The additional costs of the "more elaborate" recordkeeping and
reporting contained in the proposal, and
* The cost of lost product associated with any special shutdowns
required to repair minor valve leaks.
Response: The EPA disagrees with the commenter's contention that EPA
failed to include several cost elements in their analysis. The
comrnenter's first example cites initial setup costs for special flow-
sheets and component identification. As discussed in Chapter 11,
detailed schematics, design specifications, and piping and instrumenta-
tion diagrams are included in the recordkeeping requirements for closed
vent systems and control devices as specified in Section 60.636(d)(l)
of the proposed standards. However, this information should already be
available to operators and, consequently, little burden would be incurred
by plants as a result of the standards.
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TABLE 7-2. SUMMARY OF TOTAL ANNUAL COSTS TO PERFORM LEAK
DETECTION AND REPAIR PROGRAM AT A 500-COMPONENT GAS PLANT
Source of Estimate3 Total Annual Cost, 1980 dollars
EPA Proposal BIDb 36,000
GPA Testing at Conoco
Cashion gas plant0 34,800
Union Oil Companyd 28,000
EPA-corrected value for
GPA estimate 35,250
Docket Item IV-B-5.
b
Costs are based on monthly leak detection and repair for pumps, quarterly
for pressure relief devices, and monthly/quarterly for valves. Inspections
are performed by a two-person team (one plant person and one contractor).
Based on 500 total components, the equipment distribution is proportionate
to Model Plant A equipment count: 490 valves, 5 pressure relief devices,
and 5 pump seals. On the average, EPA estimates about 1.1 minutes to
monitor a component. Hence, about 3 hours would be required to monitor
the gas plant during a typical inspection. This assumes contractor or
central office will purchase two monitoring instruments and use them to
inspect 5 plants.
c
Itemized cost submitted by GPA represents second-year costs (corrected to
1980 dollars) which are based on the ratio of Chemical Engineering cost
indices (263.2/319.3. First-year costs (corrected to 1980 dollars) are
$37,100, which are higher than subsequent years because the cost of
the first test is not amortized by GPA.
d
Docket Item IV-D-22. Costs adjusted to 1980 dollars using cost index factor
of 263.2/319.3 from Chemical Engineering. Costs submitted by Union
are based on a monthly monitoring program for an average plant (35 MMcfd),
508 components tested at a rate of 2.6 man-minutes per component.
e
Docket Item IV-B-5, Table 3. Based on Chemical Engineering cost indices
(263.2/319.3) calculated from 1984 dollar values"
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Component identification is also required under the recordkeeping
requirements. Section 60.636(b) of the proposed standards clearly
states, however, that an identification number is to be attached to
leaking equipment and is not required for all equipment. This
requirement has not changed since proposal. Identification can be
accomplished by monitoring teams affixing inexpensive tags to leaking
components. The cost for tags for leaking components is very small.
The commenter's reference to "more elaborate" recordkeepiny and
reporting contained in the proposal may be interpreted as EPA's failure
to attach a cost to gathering each individual piece of information that
must be recorded or reported. In this case, EPA has responded to
similar comments in Chapter 11, Recordkeeping and Reporting. However,
the commenter may also be referring to very elaborate recordkeeping and
reporting practices presently implemented in the petroleum refining
industry. The commenter would be correct by inferring that facilities
may implement more elaborate information systems than required under
the standards. Several refineries collect far more information than
required by existing State and local regulations because their
experience has demonstrated the usefulness of the information. Added
benefits include minimizing product loss, information to make better
future purchases of equipment by manufacturer and type, and developing
more efficient maintenance practices.
Furthermore, EPA has not accounted for lost product associated
with special shutdowns because the standards do not require special
shutdowns as the commenter remarked. The EPA has included provisions
(Section 60.632-8 of the proposed standards) allowing the delay of
repair for equipment leaks whenever repair is technically infeasible
without a process unit shutdown.
Comment: One commenter (II-D-10) expressed concern that monitoring
time estimates do not include time for personnel travel to the work
site or for reaching the component once on site. As an example, the
commenter stated that relief valves located on top of gas plant vessels
might be 50 to 120 feet high, accessible by a ladder. According to the
commenter, climbing up and down a 50-foot column requires more than
8 mi nutes.
Response: The EPA recognizes that some components will require more
time to monitor than the estimates used in the cost analysis. The cost
of monitoring is based on average monitoring times, measured during
actual test programs. Most sources will require less than average
times to monitor, so that a few sources requiring greater than average
time will result in the total monitoring time being that presented in
the BID for the proposed standards.
Comment: Two commenters (IV-D-11; IV-D-34) maintained that the
proposed standards would be burdensome in view of the instrumentation
involved in monitoring. As an example, the commenter wrote that the
cost of a typical VOC analyzer is approximately $5,000, with an annual
operating cost for supplies and labor of $4,000. This $9,000 first-year
cost is exorbitant compared to the cost of current (audible, visual,
and olfactory) leak detection practices in the commenter's opinion.'
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Response: The EPA based the cost for instrument monitoring on one of
the available VOC analyzers at $4,600 per instrument (in 1980 dollars).
This cost is similar to the $5,000 (assumed to be in 1984 dollars)
presented by the commenter. Although less expensive VOC analyzers are
available, EPA used the higher cost to estimate the cost impacts of the
standards. In addition, the cost analysis, presented in Chapter 8 of
the BID for the proposed standards, includes the cost of two instruments.
The standards only require one instrument; however, a second instrument
is included in the cost analysis because plant operators may need to
purchase a second instrument as a spare in the event the first becomes
inoperable. Alternatively, operators could simply stock spare parts
for the instrument. The total estimated capital cost for instrument
monitors per gas processing unit is $9,200.
Annual costs for monitoring instruments include annualized capital
costs and annual operating costs. The EPA estimated annualized capital
costs at $2,100 per gas processing unit. This cost is based on a
6-year life for the instruments and an annual interest rate of 10 percent.
Estimated annual operating costs include $3,000 for materials and labor
to maintain and calibrate the instruments and $370 for rni seel laneous
costs. The EPA's estimated total operating costs are $3,370 which compares
closely with the commenter's estimate of $4,000 (assumed to be 1984
dollars). The EPA's total annual cost, therefore, is approximately $5,500.
Given the commenter's operating costs and annualizing the commenter's
purchase price for two instruments adjusted for the cost year basis
results in a lower annual cost than estimated by EPA. The Chemical
Engineering cost index for June 1980 represents about 75 percent of the
cost index in December 1983 dollars. Therefore, the commenter's purchase
price for two instruments amounts to $7,500 in 1980 dollars, and
annualized over 6 years at 10 percent interest at $1,725. The commenter's
operating costs would equate to about $3,000 (assuming that the operating
costs would be the same for one instrument as two). The commenter's
total annualized cost would be nearly $4,700 or only 85 percent of the
cost EPA used as the basis for the cost and economic impact analysis of
the standards.
Actual annual instrument costs may be significantly less than EPA
estimated. As mentioned, less expensive VOC analyzers are available
and operators may use a soap solution to screen components as provided
in Method 21. Soaping may reduce labor time during inspections and
reduce wear on instruments. Operators may also find it more economical
to stock spare parts than to purchase a spare instrument. Nevertheless,
the purchase of a VOC analyzer is necessary to detect for leaking
equipment in order to determine compliance with the 10,000 ppm leak
definition or the 500 ppm no detectable emissions limit. The commenter's
current practices of audible, visual, and olfactory leak detection are
ineffective in discerning all equipment leaks. Also, soaping is not
applicable to all equipment types (i.e., rotating or reciprocating
shafts). As mentioned, the cost analyses in the BID for the proposed
standards assume two instruments are purchased for each plant. Most
plants would be able to share monitoring instruments with other plants
within the same corporation or, where contractors are utilized, with
other companies. A second possibility is for a company to purchase one
7-14
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instrument for each plant, and one or two spare instruments to be
shared by all of its plants. Where monitoring is to be performed by
central office personnel, the company would probably purchase two or
three instruments to be used for all plants.
Although the instrument cost may appear high to the commenter, the
majority of the costs are offset by the value of the products saved
through loss prevention. For example, Model Plant B has annual recovery
credits due to leak detection and repair programs of $13,230/yr with
annual program gross costs of $13,944/yr (based on values for labor and
recovery credits presented in Appendix H of the BID for the proposed
standards). Therefore, the leak detection repair program net cost is
less than $800/yr, while reducing emissions by 45.7 Mg/yr.
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8.0 ECONOMIC IMPACTS
8.1 PRICES
Comment: One commenter on two occasions (IV-F-la; IV-U-26)
contended that natural yas processors will have to bear the full costs
of compliance with the standards and will not be able to recover these
costs. The comrnenter cited that natural gas processing economics is
based on the margin between the value of natural gas liquids components
as a fuel in natural gas compared to the value as a petrochemical
feedstock or liquid fuels. The economics is not based on general
energy costs as assumed in the EPA analysis. The commenter added that
these margins are quite small, particularly for ethane and propane
components, such that additional operating costs could make new plant
construction uneconomical. The comrnenter went on to indicate that
natural gas is sold on long-term, fixed-price contracts.
Response: The commenter raises two issues that are discussed below:
(1) the role of long-term contracts in predetermining natural
gas prices, and
(2) the relevant process economics for an economic impact analysis.
1. Natural Gas Pricing
The NSPS will affect primarily new sources of natural gas, but
some existing sources of natural gas are also expected to be affected.
Long-term, fixed contract prices have been negotiated for some of the
output of existing wells. The term of some of these contracts, from
date of origin to date of termination, is as much as 25 years. However,
in recent years (since the rnid-1970's) a great deal of new natural gas
output has been sold on the basis of prices negotiated in contracts
with a much shorter term of completion (2 to 3 years). Furthermore,
over the same time period, increasing amounts of natural gas have been
sold on the spot market at spot, or current, market prices. In addition,
many of the long-term gas contracts under which natural gas used to be
marketed (which were negotiated during the 1950's and early 1960's)
have been or will shortly be terminated. Thus it is reasonable to
assume either that the output from natural gas wells will be marketed
in the future at current prices or at prices negotiated under medium
term contracts that are closely tied to expected or actual future spot
prices for natural yas (or perhaps linked to a general energy price
index; for example, a 6-month moving average index for oil prices).
2. Process Economics
The commenter contends that the relevant process economics for
natural gas plants should involve a comparison of the profitability of
natural gas liquids in its alternative end uses. The commenter
identifies three general categories of end use:
8-1
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Natural gas liquids components as a fuel in natural gas
Natural gas liquids as a petrochemical feedstock
Natural gas liquids as a liquid fuels
If the standards were likoly to have a measurable effect on the
cost of natural gas as a feedstock to any of the above uses, then the
relative economic impacts of the regulation on each of these indirectly
affected markets would have to be estimated. However, the economic
impact analysis indicates that the market price for natural gas is not
likely to increase measurably as a result of the fiSPS. Therefore, the
process economics issues raised by the commenter concerning processes
that utilize natural gas as a feedstock do not have to be taken into
account in the economic analysis as the NSPS is estimated to have no
significant impacts on the economic conditions under which firms involved
in those markets operate.
It is possible that the commenter is concerned about the effects
of the NSPS on vertically integrated firms involved in gas exploration
and well head production in addition to downstream activities, such as
the manufacture of petrochemicals or liquid fuels. These firms, however,
have the option of selling or buying natural gas on the open market.
Thus the opportunity cost to them of natural gas as a feedstock in
their downstream operations is in fact the market price of that gas.
Thus the process economics of and profitability of downstream activities
involving natural gas will be unchanged by the NSPS for the reasons
discussed above.
Comment: One commenter (IV-D-3) claimed that the assumption by
EPA (page 9-12 in the BID for the proposed standards) is untrue that
gas deregulation would be in effect and gas prices, along with liquid
prices, will increase. The commenter maintained that if prices decrease
or usage of natural gas decreases, the impact of the standards would be
greater and perhaps could slow or stop growth in the industry.
Response: The EPA acknowledges that the price of natural gas in the
future will likely fluctuate. In all likelihood the price will be
relatively low in the 1985-1990 time frame but will then begin to slowly
increase into the mid-19901s. In any case, the price of methane-ethane
(Table 8-5 in the BID for the proposed standards) used to calculate
recovery credits is based on a natural gas price of $1.46/Mcf. This
price is very low and is, in fact, considerably lower than even the low
projections for the 1985-1990 time frame.
Comment: One commenter (IV-D-12) expressed concern that the
additional cost burden imposed on the gas industry by the proposed
standards must be paid eventually by the consumer. The commenter added
that the negative effect on the environment of switching from gas to
other fuels (because of increased gas costs), which would occur mainly
in populated areas, would more than offset the environmental benefit to
any remote rural areas.
8-2
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Response: The EPA economic analyses, prepared prior to proposing the
VOC equipment leak standards, are presented in Chapter 9 of the BID for
the proposed standards. These analyses, as discussed in Section 9.2 of
the BID for the proposed standards are used to determine the maximum
price increases required to maintain the same profitability as would be
present in the absence of the standards. Page 9-30 of the BID for the
proposed standards indicates that changes in natural gas prices would
be less than 0.5 percent for the most stringent of the regulatory
alternatives considered. Based on the ratio of the cost of the actual
standards to the cost of the most stringent regulatory alternative, the
standards will cause less than a 0.07 percent increase in gas prices.
The actual natural gas cost increase due to the effects of the standards
is expected to be less than 0.3 <|:/Mcf.
Since the price increases are very small, and the demand for
natural gas is relatively inelastic, it is highly unlikely that such
small increases in prices would have any effect on natural gas usage.
Alternative fuels (as shown in Table 9-12 of the BID for the proposed
standards are more expensive than natural gas, even if the price
increases are understated. Therefore, no adverse environmental impacts
from fuel switching are likely.
Comment: One cornmenter (IV-D-30) stated that EPA's assessment of
the economic impacts of the standards based on natural gas prices was
not accurate. The effect of the proposed standards on certain petro-
chemical feedstocks, propane for rural heating, and butane and natural
gasoline for motor fuels should be considered. The commenter noted
that gas plants are built because natural gas liquids are worth more in
a separate liquid phase than in a vapor phase mingled with lighter
natural gas components, and that this difference (the margin) is often
slight and changes rapidly.
Response: The commenter contends that, since the purpose of
natural gas processing plants is to produce natural gas liquids by
extraction from the natural gas, the economic analysis should be based
on natural gas liquids prices rather than natural gas prices. The EPA
realizes that in some situations, natural gas liquids prices could be
affected by the proposed standards. However, most of the impacts would
be very slight due to the small compliance costs with the standards.
It should also be pointed out that one of the primary goals of examining
natural gas prices was the determination of product recovery credit.
The recovery credits calculated are lower than actual, since they are
based on a combination of natural gas and natural gas liquids prices, and
natural gas prices are expected to be higher than the $1.46/Mcf used by
EPA.
8.2 INDUSTRY IMPACTS
Comment: One commenter (IV-D-3) stated that the annual costs of
implementing the standards would be in the neighborhood of 2 percent
to 13 percent of annual revenues for two plants owned by his company,
compared to less than 0.01 percent claimed by EPA in the preamble to
the proposed standards. The commenter did not provide any explanation
of the calculation of the relative cost values claimed.
8-3
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Response: The EPA indicated in the preamble to the proposed btdndurd
a value of 0.1 percent as the maximum increase in consumer gas prices,
rather than 0.01 percent as indicated by the commenter. The estimated
cost to industry of less than 0.1 percent of revenues is based on
industry average values and, therefore, could be higher or lower for
individual plants. The EPA expects that costs could be as high as
2 percent of revenues at only a few plants; however, EPA does not think
that the costs of the standards could be as high as 13 percent of
revenues at any plant.
8.3 SMALL BUSINESSES
Comment: Two commenters (II-B-23; IV-D-3) stated that, contrary
to EPA assertions, many gas plants would qualify as a small business
based on a criterion of less than 500 employees.
Response: The EPA recognizes that, based on a criterion of less than
500 employees, some companies producing natural gas qualify as small
businesses. However, the standards are based on cost-effective control
techniques for significant emission sources, with the cost effectiveness
based on the product values of gas plant products. In general, the
standards are as cost effective for small businesses as for large
businesses since the costs and emissions reductions are independent of
business size.
Small nonfractionating plants (<10 MMscfd) are excluded from leak
detection and repair programs due to poor cost effectiveness. This
exclusion applies to small plants owned by large businesses as well as
those owned by small businesses.
The Regulatory Flexibility Act states that if there are a significant
number of "small gas companies" that will incur adverse economic impacts
as a result of the regulation, a regulatory flexibility analysis is
required. Since small businesses are not expected to incur adverse
impacts, no analysis is required for these standards.
Comment: One commenter (IV-D-23) remarked that a large majority
of compressors are fitted with open distance pieces and cannot be
fitted with closed and sealed distance pieces. Some of the smaller
compressor manufacturers do not offer the accessory equipment, such as
double distance pieces. Consequently, the standards for compressors
will cause the smaller compressor manufacturers to go out of business.
Since only large manufacturers will be able to supply compressors to
the gas industry, the standards will force a limited competition
si tuation.
Response: The EPA recognizes that some existing compressor designs
cannot be technologically or economically retrofitted with double
distance pieces. Since proposal, EPA has decided to exclude all wet
gas reciprocating compressors, so that the only reciprocating compressors
subject to the standards are those in natural jas liquids service.
Compressors of any size may be fitted with double distance pieces
since the physical size of the enclosed compartment may bo small.
8-4
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Alternative sealing techniques, such as doubly-vented barrier fluid
packings or single compartment distance pieces with improved seals may
also be used. Threfore, small compressor manufacturers are provided
with sufficient leeway to adapt compressors to meet the requirements
of the standards.
8-5
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9.0 MODIFICATION AND RECONSTRUCTION
9.1 CAPITAL EXPENDITURE
Comment: Two commenters (IV-D-14 and IV-D-19) recommended that a
definition for "capital expenditure" should be added to the standards
before promulgation. The commenters suggested that "capital expenditure"
be defined as 10 percent of the replacement cost of the affected facility
at the time the process improvement is made. Replacement cost should
be based upon the Chemical Engineering Construction Index or another
suitable cost index. The comenters thought that this approach would make
the modification provision in the NSPS more comprehensible and workable.
Another commenter (IV-D-35) recommended raising the fixed percentage
AAGRA for natural gas plants from 4.5 percent to 10 percent. According
to the commenter, this would bring the repair allowance threshold in
line with onshore drilling and avoid discouraging process improvement
modifications at existing gas plants. The commenter stated that the
application of a tax rule which sets an arbitrary break point between
an expense and capitalization requirements for these facilities is
impractical and ignores real world problems. The commenter reasoned
that gas plants are typically designed for declining production rates
and, therefore, are not frequently expanded or added to as are other
facilities, and thus the cost basis is normally low.
Response: The EPA agrees with the comrnenter's suggestion that
capital expenditure can be based, in part, on a certain percentage of
the replacement cost of the affected facility. After reviewing similar
comments on other standards of performance (e.g., Equipment Leaks of
VOC in SOCMI, Subpart VV, and Petroleum Refineries, Subpart GGG), EPA
decided to provide an alternative for the definition of "capital expenditure"
in 40 CFR 60.2 of the General Provisions. Although the implementation
of the capital expenditure definition has been made more practicable,
the original intent of the definition has been maintained.
The alternative uses an adjusted annual asset guideline repair
allowance (AAGRA) and the replacement cost to determine capital
expenditure. Details of the alternative, which is applicable to plants
built prior to 1982, are discussed in the BID for the promulgated
standards for equipment leaks of VOC in petroleum refineries
(EPA-450/3-81-015b). A definition for capital expenditure was added to
40 CFR Part 60, Subpart VV (Standards of Performance for Equipment
Leaks of VOC in the Synthetic Organic Chemical Manufacturing Industry),
Section 60.481 (49 FR 22607, Hay 30, 1984) and, therefore, is incorporated
by reference into the promulgated standards for natural jas processing
plants. "Capital expenditure" means, in addition to the definition in
40 CFR 60.2, an expenditure for a physical or operational change to an
existing facility that exceeds P, the product of the facility's replacement
cost, R, and an adjusted AAGRA, A, as reflected by the following equation:
P = R x A
The replacement cost, R, means the capital needed to purchase all the
depreciable components in a facility. The adjusted AAGRA, A, is a
9-1
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product of the age-adjusted percentage, Y, of the replacement cost,
and the applicable basic AAGRA, B, as reflected by the following equation:
A = Y x (B -i 100)
For Subpart KKK, B is equal to 4.5. The percent Y is determined from
the following equation:
Y = 1.0 - 0.575 log X, where
X = 198Z - the year of construction
and X > 0.
The relationship between replacement and original costs was derived
using inflation indexes (Docket Items 1I-B-50 and 1I-B-51).
In response to the request of the second commenter, the 4.5 percent
AAGRA for natural gas processing plants is established by the Internal
Revenue Service, and its application to NSPS is established by the
General Provisions for NSPS. EPA recognizes that other industries use
different AAGRA percentages (for example, the AAGRA for petroleum
refineries is 7.0 percent). The AAGRA values are industry specific
based on the type of operations performed by the industry and the
expected repair expenses an industry is likely to incur. Consequently,
the AAGRA would require adjustment by the IRS and not EPA.
9.2 MODIFICATION OF EXISTING SOURCES
Comment: One commenter (II-B-23) suggested that "modification" be
defined and included in the preamble due to several uses of the term.
Response: The definition for modification is included in the
General Provisions, 40 CFR 60.14; therefore, it does not need to be
defined in each separate subpart.
Comment: One commenter (IV-D-37) suggested that the provisions
for process improvements without a capital expenditure (Section 60.630(c))
be revised to "... process improvement that is accomplished without an
increase of emissions shall not by itself be considered a modification."
The commenter explained that this would give older facilities the
incentive to modernize and reduce emissions if modernization did not
trigger NSPS.
Response: The EPA stated its intent in Section 60.630(c) of the
proposed standards that minor modifications would not be covered by the
standards:
Addition or replacement of equipment for
the purpose of process improvement that is
accomplished without capital expenditure
shall not by itself be considered a modifi-
cation under this subpart.
The capital expenditure criterion was included so that minor process
improvements in a process unit that cause an increase in emissions
9-2
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would not subject an existing facility to the requirements of the
standards.
It should be noted that any potential emission increase that results
from changes in operation that require the addition of a few fugitive
emission sources could be offset or nullified by controlling existing
equipment or installing components with no fugitive emissions.
Accordingly, there would be no modification in such a case even if the
emissions occurred with a capital expenditure. The standards do not
require that process improvements be made without a capital expenditure.
They merely provide an exemption when the process improvements are made
with such an expenditure.
As described in Chapter 5 of the BID for the proposed standards,
Section 60.14 of the General Provisions limits the modification
provisions to changes which result in an increase in emissions.
9.3 MISCELLANEOUS
Comment: One commenter (IV-D-19) wrote that it would be helpful if
EPA would clarify that facilities under different ownership are separate
sources. The commenter gave as an example the following situation. If
company X modifies its C02 removal plant (sweetening unit) which is
adjacent to and serving company Y's gas plant, the NSPS should not be
triggered.
Response: The NSPS defines an affected facility as either an
individual compressor or all equipment in a process unit. If an
individual process unit (such as a dehydrator) is modified, the process
unit is then subject to the requirements of the standards. However,
the remainder of the plant would not become subject to the standards.
In the commenter's example, the sweetening unit would become subject to
the standards, but the remainder of the plant would not.
9-3
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10.0 TEST METHODS
10.1 LEAK DETECTION METHODS
Comment: Numerous commenters (IV-D-35; II-B-23; II-D-20; II-D-30;
II-E-8) stated that EPA should recognize the validity of less costly,
faster, easier, and more accurate leak detection using soap scoring.
One commenter (IV-D-35) noted that several factors lead to the conclusion
that soap scoring is better than instrument monitoring:
Cost - a small trigger-activated pump bottle ( $1.75) can be
used for soap scoring as opposed to a $6,000 instrument for
instrument monitoring.
Ease of testing - the soap solution bottle is much lighter
( 1/2 to 1 kg) than the monitoring instrument ( 7 to 8 kg),
which is important when the operator must climb over pipes,
climb ladders, or traverse walkways.
Accuracy - the commenter noted that industry demonstrated, by
statistically comparing the soap score with volumetric leak rate
and concentration measurements, the absolute accuracy of the
soap test (Eaton, et. al . 1980). The EPA, according to the
commenter, attempted to show that the detection instrument is
as accurate as the soap test (DuBose, et. al. , 1982). However,
EPA performed their analysis by comparing instrument readings
with soap scores rather than actual leak rates. Thus, the
validity of EPA's claims of accurate leak detection using the
instrument is not supported by gas plant data.
In one test (Eaton, 1980), commenter IV-D-35 reported that 81 percent
of all OVA-detected leaks were found to have a soap score of three or
greater. Union Oil Company data (Anderson, 1984) showed identical
results for the two methods, but soap scoring was almost twice as fast.
Based on these reasons, the commenter suggested the proposed standards
be modified to allow use of soap testing, with a soap score of three or
more indicating a leak.
Another commenter (IV-D-10) also recommended that EPA allow the
use of soap scoring at natural gas plants to quantify VOC leaks from
components for which soap scoring is effective. The commenter wrote
that, while soap scoring is subjective, the method has been shown to
correlate accurately with leak rate and concentration measurements.
Commenters IV-D-30 and IV-D-35 provided results of a 1982 Western Oil
and Gas Association (UOGA) training session in which 500 measurements
were made using 10 hexane-calibrated OVA's. The data indicated that
81 percent of all OVA-detected leaks received soap scores of 3 or
greater, while 92 percent of all OVA-detected leaks received soap
scores of 2 or greater. Commenter IV-D-10 felt that due to the vari-
ability of OVA readings, the correlation between OVA readings and soap
scores is probably better than the data indicate.
[Note: OVA is a registered trademark, use of which does not imply
endorsement by LPA.J
10-1
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Response: Prior to promulgation of Method 21, an alternative soap
screening procedure was added for sources that can be tested with a
soap solution. These sources are restricted to ones with non-moving
seals, moderate surface temperatures, without large openings to atmosphere,
and without evidence of liquid leakage. The soap solution is sprayed
on all applicable sources, and the potential leak sites are observed to
determine if bubbles are formed. If no bubbles are formed, then no
detectable emissions or leaks exist. If any bubbles are formed, then
the instrument measurement techniques must be used to determine if a
leak exists, or no detectable emissions exist, as defined in the regulation,
The alternative soap solution procedure does not apply to pump
seals, components with surface temperatures greater than the boiling
point or less than the freezing point of the soap solution, components
such as open-ended lines or valves, pressure relief device horns, vents
with large openings to atmosphere, or any component where liquid leakage
is present. The instrument technique specified in the method must be
used for these components.
The alternative of establishing a soap scoring leak definition
equivalent to a concentration-based leak definition is not included
in the method and is not recommended for inclusion in an applicable
regulation because of the difficulty of calibrating and normalizing a
scoring technique based on bubble formation rates. A scoring technique
would be based on estimated ranges of volumetric leak rates. These
estimates depend on the bubble size and formation rate, which are
subjective judgments of an observer. These subjective judgments could
be calibrated or normalized only by requiring that the observers
correctly identify and score a standard series of test bubbles. It has
been reported that trained observers can correctly and repeatedly
classify ranges of volumetric leak rates. However, because soap scoring
requires subjective observations and since an objective concentration
measurement procedure is available, a soap scoring equivalent leak
definition is not recommended for this standard. The alternative
procedure that has been included will allow more rapid identification
of potential leaks for more rigorous concentration measurement using a
monitoring instrument.
Comment: One commenter (II-D-30) listed limitations of the portable
hydrocarbon detector in pointing out that the instrument is not the best
survey method, as EPA claims:
Extreme delicacy of the instrument;
Sensitivity to correct calibration;
Weight and inconvenience of the instrument;
Poor repeatability;
Lack of demonstrated accuracy;
Time delay in achieving a reading; and
Difficulty in receiving timely repairs of the instrument.
10-2
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Response: The EPA recognizes that portable hydrocarbon detectors
have limitations; however, none of the limitations prevent the use of
instrument monitoring from being the recommended method of leak
detection. Although typical monitoring instruments can be damaged by
accidental dropping or misuse, they are not considered "extremely
delicate." These instruments have been in routine use in refineries
subject to State or local leak detection and repair requirements with
few problems.
The absolute accuracy of the instruments is not a real concern.
Since the purpose of the instrument monitoring is to locate failures of
seal mechanisms, the readings observed by the instrument operator are
normally much lower or much higher than the 10,000 ppm leak definition.
Consequently, a minor change in the calibration of the instrument makes
little difference in the number of leaks detected.
The response time of the hydrocarbon detector is required by
Method 21 to be less than 30 seconds. However, 3 to 10 seconds is more
representative of currently available instruments. The EPA recognizes
that the instruments may be cumbersome in certain situations. However,
as mentioned before, use of the instruments has been demonstrated
through routine use in regulated refineries. Additionally, since this
comment was written, EPA has added soap screening procedures to Method 21
The use of soap screening will allow the operator to minimize the
use of the instrument, since instrument monitoring is only required for
sources producing visible bubbles during soap screening. Limited use
of the instrument can result in extending the instrument life as well
as minimizing operator fatigue.
The instrument can be repaired by either the manufacturer or
qualified repair services. Most instruments are relatively simple in
design; therefore, most problems can be repaired in the field by the
operator. The EPA expects the plants to maintain spare parts as
recommended by the instrument manufacturer. Costs for a second
(backup) instrument are included in the cost analyses of the BID for
the proposed standards.
Comment: One commenter (IV-D-20) mentioned that hydrocarbons are
measured using the Flame lonization Detector (FID) principle. Such
analyzers are not capable of distinguishing methane and ethane from
heavier hydrocarbons. Thus, there is no way to determine the actual
level of regulated hydrocarbons in either the background air or from a
leak. Consequently, the commenter stated that industry and EPA will
have a difficult time complying with and enforcing the proposed standards.
One commenter (IV-D-25) requested that EPA revise the definition
of VOC in Section 60.2 of the General Provisions to exclude specifically
methane and ethane. The commenter reasoned that Reference Method 21
detects any organic compound including methane and ethane. In fact,
methane is used as a calibration gas in Reference Method 21.
Response: In selecting the affected facilities as only equipment
in VOC service or wet jds service, the program limitb testing of
equipment to those sources with the potential to emit VOC, that is,
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those components in wet gas service or ones containing at least
10 weight percent VOC as determined by ASTM Methods E-260, E-168, or
E-169. The purpose of Method 21 is, therefore, to detect whether a
regulated component is leaking, and not to quantify either the leak
rates or the composition of the leaking material. Therefore, there
is no reason to require VOC leaks to be distinguished from methane/ethane
leaks, as any component found leaking will be leaking VOC.
The 10,000 ppm leak definition represents methane/ethane and VOC
combined. The leak rates presented throughout the BID for the proposed
standards are based on measurements of total hydrocarbon concentrations
to determine leaking/nonleaking status. As such, the testing requirements
for the standards are also based on total hydrocarbon concentrations.
10.2 LEAK DEFINITION
Comment: One commenter (II-D-10) stated that there is no justifi-
cation for selecting 10,000 ppm as the action level.
Response: API submitted this comment prior to proposal and
requested that it be included in the rulemaking (IV-F-le). The selection
of the action level, or "leak definition," for the definition of a leak
was based on several factors, which are discussed in Section 4.2.3.1 of
the BID and in the preamble to the proposed standards. The rationale
for the selection of the action level for valves is different from the
rationale for pumps because of differences in the cause of leakage.
The best leak definition would be the one that achieved the most
emission reduction at reasonable costs. Within practical limits, the
emission reduction achieved would increase as the leak definition
decreased, due to the increasing number of components that would be
found leaking and, therefore, repaired. At a leak definition of
10,000 ppm, approximately 90 percent of all VOC leaks from valves would
be detected. It is well documented that valves that have been found
leaking at levels of 10,000 ppm or greater can be brought to levels
below 10,000 ppm with proper maintenance. Also, as a practical matter,
most commonly available hydrocarbon detectors that are considered
intrinsically safe have a maximum reading of 10,000 ppm. Leak definitions
higher than 10,000 ppm could, nevertheless, be selected (and dilution
probes could be used with portable detectors); however, there would be
less emission reduction than with the 10,000 ppm definition and no substantial
associated cost savings. Consequently, there is no basis for selecting
a leak definition greater than 10,000 ppm. A leak definition lower
than 10,000 ppm may be practicable in the sense that leaks can be
repaired to levels less than 10,000 ppm. However, EPA is unable to
conclude that a leak definition lower than 10,000 ppm would provide
additional emission reductions and, therefore, would be reasonable.
Because the 10,000 ppm leak definition would address approximately
90 percent of the VOC leaks from valves at reasonable costs and at
reasonable cost effectiveness, and because safe, available hydrocarbon
detectors can read 10,000 ppm, the 10,000 ppm level was selected as the
leak definition for valves. In contrast to valves, which generally
have zero leakage, most pump seals leak to a certain extent while
operating normally. These seals would tend to have low instrument
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meter readings. With time, however, as the seal begins to wear, the
concentration and emission rate are likely to increase. At any time,
catastrophic seal failure can occur with a large increase in the
instrument meter reading and emission rate. As shown in Table 4-2 of
the BID for the proposed standards, over 80 percent of the emissions
from pump seals are from sources with instrument meter readings greater
than or equal to 10,000 ppm. Properly designed, installed, and operated
seals should have low instrument meter readings. Furthermore, the bulk
of the pump seal emissions are from seals that have worn out or failed
so that they have a concentration equal to or greater than 10,000 ppm.
Therefore, 10,000 ppm was chosen as a reasonable action level.
It should be noted that the purpose of instrument monitoring is to
detect seal failures (leaks), and not to quantify the leak rate.
Although any leak definition could be selected, EPA for the reasons
given believes 10,000 ppm is the appropriate level of hydrocarbon
concentration to distinguish between leaking and nonleaking sources.
Comment: Two commenters remarked about the safety of testing flares.
One commenter (IV-D-35) recommended deleting the requirement for compliance
testing of flares using Methods 2, 2A, or 2C. The commenter stated
that Methods 2, 2A or 2C expose personnel to risk of death if, during
the test, a component attached to the flare relieves. The commenter
claimed that requiring this test is likely to bring a challenge from
the Occupational Safety and Health Administration. The second commenter
(IV-D-31) added that since flares are designed to handle intermittent
releases from relief valves, it is uncertain how representative velocity
and gas stream Btu content determination could be made and how such
measurements could be performed without endangering the safety of the
testing personnel.
Response: Testing of flares should not require any measurements
to be made at the flare, other than monitoring for the presence of a
flame with a permanently mounted thermocouple. The velocity measurements
and no substantial associated cost savings. Consequently, there is no
made in Method 2 or its alternates can be made in the flare header at a
distance from the flare. Therefore, no climbing or exposure to the flare
is necessary. Since Method 22 requires only that the flare be observed
from a distance to determine if visible emissions are occurring, no
exposure to the flare is required. The standards require that flares
be operated within specific velocity guidelines. The stream Btu content
can be based on engineering calculations of vessel or equipment contents.
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11.0 RECORDKEEPING AND REPORTING
11.1 GENERAL
Comment: Several commenters (IV-D-3, IV-D-5, IV-D-19, IV-D-20
IV-D-21, IV-D-22, IY-D-25, IV-D-26. IV-D-29, IV-D-30, IV-D-34, IV-D-36,
IV-F-la) urged EPA to reconsider the proposed recordkeeping and reporting
requirements. Some of these commenters (IV-D-5; IV-D-21; IV-F-la)
expressed concern that the proposed standards included more extensive
recordkeeping and reporting requirements than the previous (NAPCTAC)
draft. One commenter (IV-D-25) thought the requirements should be
eliminated because they are far too complicated for the small emission
reductions that will result from a leak detection and repair program.
Another commenter (IV-D-30) said that the recordkeeping and reporting
requirements are totally counterproductive to the Federal government
goals of reducing paperwork. Other commenters thought the requirements
were excessive. Some commenters (IV-D-3, IV-D-34, and IV-F-la)
indicated that it will be unusually burdensome for the small plant
operator to comply with these requirements because of minimal staffing.
One (IV-D-3) argued that small plants would need to hire additional
employees just to comply with the recordkeeping, and these additional
employees could make the difference between operating and shutting
down. Another commenter (IV-F-la) did not think that EPA considered
increased costs for recordkeeping, reporting, and allowances for setting
up a system to comply adequately with these requirements.
Several of the commenters took exception to the semiannual reports
and thought that annual reports would be sufficient. The commenters
questioned the ability of EPA to review and analyze the data submitted
over the next several years and noted that annual reports would be
consistent with State and other Federal regulations.
Response: The commenters are incorrect in stating that record-
keeping requirements of the proposed standards are more extensive than
the recordkeeping requirements of the NAPCTAC draft.
In both NAPCTAC draft and proposal standards, EPA selected the
same recordkeeping requirements that would provide the necessary records
for managing implementation of the required programs while ensuring
effective implementation and maintenance of the proposed standards.
The commenters are correct in stating that reporting requirements at
proposal are more extensive than the reporting requirements at NAPCTAC.
After evaluating three alternatives, EPA selected the first alternative
as the reporting requirement at NAPCTAC, which provided no routine
reporting of compliance other than the requirements of the General
Provisions of Subpart A of 40 CFR Part 60 (notifications of construction,
anticipated startup and actual startup), the requirements for notification
of intention to comply with one of the alternative standards for valves,
and the reports necessary for determination of equivalence of alternative
means of emission limitations. Compliance under this alternative would
be assessed through in-plant inspections.
Since NAPCTAC, however, EPA re-evaluated the alternatives for
reporting requirements of the proposed standards. The reporting require-
ments under the first alternative (no routine reporting) would not
11-1
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provide a mechanism for checking the thoroughness of the industry's
efforts to reduce equipment leaks of VOC. Facilities not complying
with the standards would not be using BDT as required by the Clean Air
Act. The EPA believes that reporting is necessary for the effective
enforcement of the standards. Reporting will reduce the necessity for
many in-plant inspections, while improving the enforceabi 1 ity of the
standards. The EPA's conclusion that reports are useful is also based
on the experience of State and local air quality control boards. The EPA
concluded, therefore, that reporting is necessary to assess implementation
of the work practice and equipment requirements of the standards without
requiring excessive resources from industry and enforcement personnel
and proposed that certain information be reported (i.e., submittal of
semiannual reports to summarize information on leaking equipment and
the number of leaks detected and repaired).
One of the commenters asserted that EPA did not consider increased
costs for recordkeeping and reporting and for setting up a system for
compliance with these requirements. On the contrary, these costs are
included in the cost analysis of the standards as administrative costs.
In addition, contrary to the commenter's remarks, EPA did make allowances
for the costs of setting up a system to ensure compliance with these
requirements. The EPA is required under the Paperwork Reduction Act of
1980 (PL-511) to submit a request to the Office of Management and
Budget (OMB) for approval of recordkeeping and reporting requirements
that qualify as an "information collection request" (ICR). For the
purposes of OMB's review, an analysis was presented of the need for
information, methods of ensuring the quality of data obtained, alternatives
to the information collection, and estimated burden hours and cost to
the industry and to EPA of complying with the requirements. The costs
of recordkeeping and reporting for both industry and EPA at proposal
are presented in Docket Item II-F-3. Since proposal, EPA costs of
reviewing reports and compliance inspections have been revised because
of errors made in the estimates at proposal and because of revisions in
ICR collection procedures as discussed in the next response to comment.
The revised costs are presented in Docket Item IV-H-2.
The commenters also expressed concern that the recordkeeping and
reporting requirements would be burdensome for small plant operators
and that additional employees would need to be hired just to comply
with the recordkeeping requirements. The EPA considered the staffing
needs of plants in implementing the standards and analyzed the impacts
of the standards on small plants. The EPA recognizes that some small
plants operate without technically trained personnel because of the
type of process that is performed there. In particular, small nonfrac-
tionating plants often operate either unmanned or without a staff
having the technical ability to conduct a leak detection and repair
program and to maintain the associated records and reports. In these
cases, EPA analyzed the additional cost of hiring an outside consultant
or using central office personnel that would be needed and judged the
costs to be unreasonable at nonfractionating plants having capacities
below 10 million standard cubic feet per day (MMscfd). The EPA decided,
therefore, to exempt any nonfractionating plant whose capacity is
10 million scfd or less of field gas from the routine monitoring requirements
11-2
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(and the associated recordkeeping and reporting requirements) for
valves, pumps, and pressure relief devices. All fractionating plants,
however, regardless of capacity are required to implement the routine*
monitoring requirements because these plants require the presence of
technically trained personnel. The recordkeeping and reporting requirements
have little impact on the cost of the standards; therefore, EPA does
not anticipate any disruption in plant operations or closings attributable
to these requirements. These requirements are considered the minimum
consistent with adequate enforcement; therefore, the burden on owners
and operators is the minimum necessary to enforce the standards adequately.
Comment: One commenter stated that the reporting and recordkeeping
requirements of 0.15 person-years per plant given in the preamble to
the proposed standards (p. 2648-2) are low. The commenter offered what
he considered more realistic impacts than the EPA estimates. The
commenter estimated that the initial monitoring, recordkeeping, and
reporting for a typical cryogenic plant will require 0.5 person-years
The commenter also offered that a plant representative of the 90 MMscfd/
day gas plant referenced in the regulations includes over 1,000 valves
5 pumps, and 4 compressors. The commenter also disagreed with the
nationwide recordkeeping and reporting burden estimate given on page
2648 of the preamble to the proposed standards. The commenter noted
that the recordkeeping and reporting impact of 6.6 person-years reported
in the preamble is based on the number of plants (44) per year affected
in the first 2-year period. The commenter argued that the impacts are
cumulative and would, therefore, affect 220 plants in 1987. The
commenter also used his 0.5 person-years per plant impact to estimate
the nationwide annual burden at 22 person-years; the first 5-year
average at 55 person-years, and that at the end of 5 years, the
annual burden would be 110 person-years.
Response: The 0.15 person-years per plant estimate shown in the
preamble to the proposed standards represents 312 labor hours/year for
recordkeeping and reporting, or 26 hours per monthly monitoring period
Since most required records are generated during the actual monitoring"
period by the monitoring team, little additional recordkeeping and
reporting effort is required. The amount of labor (26 hours) costed in
the preamble for the proposed standards should be more than adequate
for the average plant.
As discussed above, EPA is required to submit recordkeeping and
reporting burden estimates to OMB for approval. At proposal, these
estimates were required to be performed for the first 2 years of the
regulations. The commenter is correct in recognizing that the fifth-year
impacts would be greater, but the total burden for 220 plants would be
33 person-years, based on 0.15 person-years per plants.
It should be noted that, since proposal, OMB has revised the
information collection reporting period from 2 to 3 years, so that EPA
is required to submit recordkeeping and reporting burden estimates
calculated over the first 3 years of the regulation. This change, how-
ever, does not affect the industry burden estimates presented at proposal
because they were calculated on an annual basis
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11.2 REPORTING
Comment: Two commenters (IV-D-22 and IV-D-26) suggested eliminating
the following information from the reporting requirements:
1. Instrument Identification Number - EPA would need to verify
each daily calibration of the instrument for absolute control
over instrument use,
2. Operator Identification Number - it should be sufficient for
the operator to sign a log or report often-taken readings,
3. Date each repair was attempted if unsuccessful - only if the
leak was not repairable within the 15 days allowed should any
notation be made,
4. Repair method - the information EPA derives from this will not
justify the burden on industry, and
5. Expected date of repair - in small plants and many large ones,
there are no scheduled shutdowns or the date is unknown.
Similarly, another commenter (IV-D-23) held that the information
reported should be kept as simple as possible to be useful. The
commenter provided an example of information a report should contain:
1. The number and size of valves, including relief valves, found
leaking, the number repaired and the number of valves that
were unable to be repaired without shutting down the plant.
2. The number of leaks found in affected equipment, the number of
valves that were unable to be repaired without shutting down
the plant.
The commenters also thought only leaking components should be
reported. One commenter (IV-D-19) thought that this information could
be maintained at the plant and made available for inspection on request
as is done in many other federal and State regulations. Another commenter
(IV-D-20) stated that it was unnecessary to report immediately repaired
components because such information does not affect the emission reductions
obtained by the inspections. In addition, exemption of the reporting
requirement would reduce the compliance burden on industry. One commenter
(IV-D-22) added that the reporting requirements should be kept to a
minimum because they reduce morale by taking time away from more productive
pursuits, and that the greater the volume of detail required, the lower
the quality of the information.
Response: All of these commenters contend that EPA requires excess
information to be included in the required reports. In selecting the
reporting requirements, EPA carefully considered what information would
be required to assess adequately a plant's compliance with the standards.
The resulting requirements, as proposed, represent the minimum acceptable
reports.
11-4
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For example, the instrument number is necessary to show that the
calibrations reported are done on the same instrument used for monitoring.
The number may be assigned by the plant, as instrument 1, 2, 3, etc. or
may be an actual serial number. Similarly, the operator identification
It should be noted that, since proposal, OMB has revised the
will serve to indicate if one operator detects consistently fewer (or
consistently more) leaks than other operators. The dates of unsuccessful
repair show that repair was indeed attempted and, combined with the
repair method, assist both the owner or operator and EPA in determining
which repair techniques are the most successful. The expected date of
repair assists the appropriate enforcement agency in assessing the
environmental impact of the standards by quantifying the long-term
emissions that cannot be prevented.
The EPA concurs with one commenter that the required reports alone
do not increase the emission reduction of the standards. However,
they indicate to EPA the diligence of the plant owner or operator in
complying with the standards and thus help EPA judge the necessary
frequency of inspections. The EPA also concurs with keeping the reports
as simple as possible and has made every effort to do so. Therefore,
elaborate reports with extraneous information are neither required nor
desired.
11.3 RECORDKEEPING
Comment: Several commenters offered specific examples to be
deleted from the recordkeeping requirements. One commenter (IV-D-15)
suggested deleting details such as schematics and design specifications
for flare and alarm sensors. The commenter suggested that an annual
certification of compliance by the operator would be sufficient.
The commenter wrote that since plant design criteria are generally
available through State agencies, EPA, and at each gas plant, there
is no need to include such information in a log.
The commenter also thought that devices found leaking that are
repaired by immediate action (such as tightening of packing) should be
exempt from the recordkeeping requirements of the standards. The
commenter claimed that such an exemption would not affect the emission
reductions obtained by the inspections and would reduce the compliance
burden on industry.
Response: The details of the recordkeeping and reporting require-
ments were discussed in the response to the previous comment.
The commenter questions the necessity of maintaining schematics
and design specifications for control devices and closed vent systems
required by Section 60.636(d) of the proposed standards. The VOC
control effectiveness for compressors, relief devices, pumps, or other
equipment that may be controlled with a closed vent system in lieu of
routine leak detection and repair is dependent on the integrity of the
vent system and control device. The vent system and control device
must be designed and operated properly for the emission reduction of
11-b
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the standards to be realized. In order to demonstrate compliance with
the standards, the operator must be able to show that the vent system
and control device were designed for operation in accordance with the
requirements of the standards. The required design specification and
schematics will provide the necessary demonstration. Likewise, the
design information for the necessary monitoring systems will serve as a
demonstration of the proper operating conditions.
It should be noted that few plants, if any, would purchase either
control or monitoring equipment without first examining the design
specifications and flow schematics prepared by the prospective equipment
vendor. Consequently, the necessary records are available to the
operator when the required equipment is installed, and no expenditure
is necessary to generate these records.
Records should be kept of all leaks, including those repaired
immediately. The standards allow for quarterly monitoring of valves
that were found to be nonleakers for 2 consecutive months. Therefore,
all leakers must be recorded so that monthly monitoring is maintained.
The leaker records may also help the operator identify troublesome
components for replacement, as well as assessing the emission reduction
achieved and the potential for skip period or alternative standards.
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12.0 MISCELLANEOUS
Several comments were received that were not related to the other
topic areas presented in the previous sections. These comments are
discussed in this section. They include comments on determination of
equivalent means of emission limitation, determination of "major rule "
technology transfer, plant construction, energy requirements, effects'
of other regulations, extension of the public comment period, and
request for reproposal of the standards.
Comment: One commenter (IV-D-29) claimed that the procedures for
determining equivalent means of emission limitations are impractical for
gas processing plants. Approval of equivalence would take a year when
many gas plants need to be designed and constructed within 2 to 6
months. Blanket generic equivalency approvals, according to the
commenter, should be allowed since gas plants are relatively small
primarily rural sources.
Responses: The EPA has provided all of the known blanket generic
approvals of adequately demonstrated control techniques. Plant owners
or operators may apply to EPA any time for other alternatives to either
the equipment or work practice standards. Where "general use" alterna
tives are approved, a blanket approval has been provided. Other requests
must be reviewed, evaluated, and processed according to the procedures
required by the Clean Air Act.
Comment: One commenter (II-B-23) remarked that the guides in the
regulation Tor demonstrating equivalence of work practices are unclear as
to how they would be implemented.
Response: Section 60.634 of the proposed standards has been
revised to simplify the wording of the equivalency determination. The
tenn equivalent" has been changed to "alternative" even though the
that * Pl*nt owner or operdtor must stn] show
, . - - _ r . »"""t-iuiufciai,u[iiiu:>iai,iii
the alternative can achieve a reduction in VOC emissions that is
ast equivalent to the VOC emission reduction achieved by the
standard specified in the regulation. For example, if an owner or
. j --_-.... . v . *_^\ VAIM p i \_ , ii U M UVYM C ( U I
operator wishes to implement an alternative program for reducing valve
eaks he must collect, verify, and submit sufficient data (e.g., at
least 12 months of monitoring data) to show that the alternative
technique(s) used to control valve leaks achieves the same or better
emission reduction than the required leak detection and repair program.
The data and a written commitment by the owner or operator to implement
the alternative to achieve equivalence (or better) would be submitted
as an application to the Administrator for his consideration. If the
Administrator determines that the alternative is at least equivalent to
the required standards, then a notice to announce the opportunity for a
public hearing would be published in the Federal Register. After an
opportunity for a public hearing, the AdmTTmtrTtoTllSuTd publish in
the federal Regj^ter a notice permitting the use of the alternative for
the purpose of compliance with the standards.
Coiranent: One commenter (IV-D-35) recommended changing the language
of Section 60.632-1(c)(2). The proposed section reads: "If the
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administrator ...owner or operator shall comply with the requirements
of....", which, according to the commenter, forced compliance by the
owner or operator with the equivalent means of emission reduction.
Since the owner or operator may wish to comply with the standards as
written, the commenter suggested changing the wording of Section
60.632-l(c)(2) to read "owner or operator may substitute the requirements
of that determination."
Response: The owner or operator may always elect to comply with the
standards as written. Proposed Section 60.632-l(c)(2) has been replaced
by Section 60.634.
Comment: One commenter (IV-D-20) stated that he believed that it
was inappropriate for EPA to determine that the proposed standards
are not a major rule.
Response: The proposed standards are not a major rule because
they do not meet the criteria outlined in Executive Order 12291 for a
major rule. In the Order a major rule is any regulation that is likely
to result in:
(1) An annual effect on the economy of $100 million or more;
(2) A major increase in costs or prices for consumers, individual
industries, Federal, State, or local government agencies, or
geographic regions; or
(3) Significant adverse effects on competition, employment,
investment, productivity, innovation, or on the ability of
the United States-based enterprises to compete with foreign-
based enterprises in domestic or export markets.
As stated in Section 1.3 of this document, the industrywide net
annual cost for all new, modified, and reconstructed facilities will be
approximately $1.6 million in 1987. This will not result in a major
increase in costs or prices and will not create a significant adverse
effect on competition, employment, investment, productivity, innovation
or foreign competition. These costs represent a small impact on the
industry and are not expected to deter construction of gas processing
plants.
Comment: One commenter (IV-F-3) stated that a monthly leak
detection and repair program does not constitute a "demonstrated tech-
nology" since he was unable to find any industry or local regulation
that has been effectively implemented at such a frequent interval.
Another commenter (II-B-23) requested that "best demonstrated" be
clearly defined in order to state the intent of the proposed regulations.
Response: A "demonstrated technology" is one which is effective
in reducing emissions to the atmosphere. Essex Chemical Corp. v.
Ruckelshaus 486 F. 2d 427 (D.C. Cir. 1973); Portland Cement Ass'n v.
Ruckelshaus 486 F. 2d 375 (D.C. Cir. 1973). Control technology can be
considered "best demonstrated" technology (BDT) if it can be shown to
be the best system demonstrated for the category of sources, not
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necessarily on the category of sources. The EPA's interpretation of
demonstrated technology means that a technique used in an entirely
different industry using a different process from the one being regulated
can be BDT if its performance would not be affected by the differences
in the sources.
Leak detection and repair programs are currently implemented in
over 100 petroleum refineries throughout the country. These programs
have been demonstrated by industry as a workable, effective technology
to reduce VOC equipment leaks from refineries. The EPA and refinery
personnel have shown that substantial emission reductions are possible
through on-line repair for all valves. These programs are basically a
reflection of the refinery control technique guideline document issued
by EPA in 1978 (EPA-450/2-78-036, OAQPS No. 1.2-111). State and Regional
air pollution control agencies have followed those guidelines to issue
regulations to achieve and maintain the National Ambient Air Quality
Standards for ozone.
The EPA recognizes that there are differences between refineries
and gas plants; however, these differences do not preclude the transfer
of control technology to the gas processing industry. In API testing
of the natural gas processing industry, the process type, operating
temperature and pressure, and line size were determined to be unrelated
to the frequency and magnitude of equipment leaks.
The frequency of the leak detection and repair programs followed
by existing programs varies. Most State Implementation Plans require
quarterly inspections of gas service valves and annual inspections of
light liquid service valves, whereas the Air Quality Management Districts
in California require less frequent (annual) valve inspections, while
requiring more stringent follow-up inspections on leaking valves. The
frequency of leak detection and repair required in the standards is
considered reasonable as discussed in other responses to comments and
is based on valve leak occurrence, leak recurrence, costs, and emission
reductions.
Comment: One commenter (IV-D-20) stated that increased emphasis
will be placed on extended gas gathering systems in the future, resulting
in the construction of fewer plants than estimated by EPA. Extending
gas gathering systems would maintain the throughput at existing plants
and would be done in preference to building new plants due to economic
pressures, according to the commenter.
Response: While it is true that some companies may elect to extend
gas gathering systems to continue operation of existing plants, many
new plants will be constructed. A recent article in the Oil and Gas
Journal states that 21 new U.S. plants were built in 1983, with 20
being built in 1984. Since new plants are often more energy efficient
than older plants, and older plants may be located too far from new
fields, EPA expects the industry to continue to replace older plants
with new plants. Alternately, older plants may be revamped with new
processes or new equipment and become subject to the NSPS requirements
through modification and reconstruction provisions.
12-3
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Comment: One commenter (II-B-23) disagreed with EPA's claims that
the proposed standards do not require energy. The commenter stated
that energy is required for maintaining pressure on compressor barrier
seals, maintaining vacuum on the closed-vent systems, maintaining a
pilot flare, transportation of monitoring equipment by employees, and
additional use of office equipment for increased administrative duties.
Response: API submitted this comment prior to proposal and requested
that it be included in the rulemaking (IV-F-le). Although the proposed
standards state that, in general, the required controls do not require
energy, EPA acknowledges that energy is also required for standards
requiring add-on control devices for vented process streams in addition
to some of the examples cited by the commenter. However, the increase
in energy for these requirements will be minimal. Furthermore, the
effect of the final standards will be to maximize natural gas production
for a given amount of raw material (wet gas), resulting in a net energy
savings. Therefore, the standards potentially save energy rather than
expend energy.
Comment: One commenter (IV-D-12) stated that certain provisions
of the proposed standards are in direct conflict with the requirements
of other Federal agencies with jurisdiction over his facilities. The
commenter indicated that enclosure of compressor distance pieces creates
an explosion hazard and is a violation of Department of Transportation
rules. The commenter claimed that, since his plant was located on U.S.
Bureau of Land Management property, use of a flare is specifically
prohibited.
Response: The EPA knows of no requirements in the standards that
are in conflict with other Federal standards. The Department of
Transportation regulations apply to pipeline transmission of natural
gas and other petroleum products and do not specify requirements for
in-plant compressors. The Bureau of Land Management does regulate
flares burning in some wilderness areas, but flares represent only one
control device option available to the plant owner or operator.
Comment: Nine commenters (IV-D-1, IV-D-4, IV-D-5, IV-D-6, IV-D-7,
IV-D-8, IV-D-9, IV-F-2, IV-F-3) requested that the comment period be
extended to allow more time to review the proposed standards, to collect
additional data to enable commenters to judge the impact of the proposed
standards, or to submit more detailed comments.
Response: In response to the commenters1 requests, EPA extended
the comment period by 60 days. The extension notice was published in
the Federal Register (49 FR 13392, April 4, 1984). The new deadline
for comments was changed to June 6, 1984, to allow time for industry
representatives to obtain additional data and cost estimates for
implementing VOC leak detection and repair programs as well as for
using flares to control compressor seal leakage.
Comment: One commenter (IV-D-32) requested that the regulation be
reproposed if LPA finds the standards to be justified. According to
the commenter, reproposal would afford an accommodation of changes in
the proposed regulation anticipated as a result of comments.
12-4
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Response: Reproposal is not necessary, since the purpose of the
public comment period is to allow for changes in the proposed standards.
The comments received have been considered carefully, and as a result
many changes have been made to the standards as discussed in Section
1.2, "Summary of Changes Since Proposal". The need for national standards
has been documented in Section 2. Because State requirements vary, the
national standards are needed to prevent States with lenient air pollu-
tion requirements from attracting new industries that might deteriorate
the State's air quality, as well as to prevent migration of pollutants
from State to State.
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
I. REPORT NO.
EPA-450/3-82-Q24h
2.
3. RECIPIENT'S ACCESSION NO.
. TITLE AND SUBTITLE
Equipment Leaks of VOC in Natural Gas Production
Industry - Background Information for Promulgated
Standards
5 REPORT DATE
May 1985
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
8. PERFORMING ORGANIZATION REPORT NO
_. PERFORMING ORGANIZATION NAME AND ADDRESS
Office of Air Quality Planning and Standards
U.S. Environmental Protection Agency
Research Triangle Park, NC 27711
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
68-02-3060
12. SPONSORING AGENCY NAME AND ADDRESS
Director for Air Quality Planning and Standards
Office of Air, Noise, and Radiation
U.S. Environmental Protection Agency
Research Triangle Park, NC 27711
13 TYPE OF REPORT AND PERIOD COVERED
14. SPONSORING AGENCY CODE
EPA/200/04
UPPLEMENTARY NOTES
. ---is document presents the background information used by the
Environmental Protection Agency in developing the promulgated new source performance
standards for equipment leaks of VOC in the natural gas production industry
Standards of performance for the control of volatile organic compound (VOC) equip-
ment leaks from the natural gas production industry are being promulgated under Section
111 of the Clean Air Act. These standards will apply to equipment leaks of VOC within
new, modified, and reconstructed gas plant compressors and process units. This
document summarizes the responses to public comments received on the proposed standards
and the basis for changes made in the standards since proposal.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
Ai r Po 11 uTTorT
Fugitive Emissions
Natural Gas Production
Pollution Control
Standards of Performance
Volatile Organic Compounds
(VOC)
b IDENTIFIERS/OPEN ENDED TERMS
Air Pollution Control
COSATI I-tcld/Group
13b
Unlimited - Available to the public free of
charge from U.S. EPA Library (MD-35)
Research Triangle Park, NC 27711
19 SECURITY CLASS (This Report)
Unlimited
20 SECURITY CLASS /This page>
Unlimited
21. NO. OF PAGES
122
22. PRICE
EPA Form 2220-1 (Rev. 4-77) PREVIOUS EDITION i s OBSOLE Tt
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