EPA-450/3-81-015b
Petroleum Fugitive Emissions-
Background Information
for Promulgated Standards
Emission Standards and Engineering Division
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Air, Noise, and Radiation
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
October 1983
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This report has been reviewed by the Emission Standards and Engineering Division of the Office of Air
Quality Planning and Standards, EPA, and approved for publication. Mention of trade names or
commercial products is not intended to constitute endorsement or recommendation for use. Copies of
this report are available through the Library Services Office (MD-35), U.S. Environmental Protection
Agency, Research'Triangle Park, N.C. 27711, or from 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 in Petroleum Refineries
Prepared by:
Farmer
Director, Emission Standards and Engineering Division
U.S. Environmental Protection Agency
Research Triangle Park, North Carolina 27711
(Date)
1. The promulgated standards of performance will limit emissions of VOC
from equipment leaks in new, modified, and reconstructed petroleum
refinery 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 welfare.
2. Copies of this document have been sent to the following Federal
Departments: Labor, Health and Human Services, Defense, Transportation,
Agriculture, Commerce, Interior, and Energy; the National Science
Foundation; 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:
> 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
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IV
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TABLE OF CONTENTS
Title
Page
1.0 SUMMARY !_!
1.1 Summary of Changes Since Proposal . . 1_1
1.2 Summary of Impacts of Promulgated Action 1-6
1.3 Summary of Public Comments 1-8
2.0 STANDARDS. ... 2-1
2.1 General Discussion 2-1
2.2 Valves 2-10
2.3 Pumps 2-35
2.4 Compressors 2-44
2.5 Pressure Relief Devices .... 2-46
2.6 Sampling Systems 2-51
2.7 Open-Ended Lines 2-53
2.8 Flanges, Liquid Service Relief Valves, and
Heavy Liquid Service Valves and Pump Seals 2-54
2.9 Control Devices 2-56
3.0 APPLICABILITY ' ^-l
3.1 Affected Facility 3_1
3.2 Definition of "In VOC Service" 3_8
3.3 Exclusions 3-12
3.4 Small Refiners. . . 3_15
4.0 MODIFIED SOURCES 4-1
4.1 Emission Increase 4_1
4.2 Capital Expenditures 4.3
4.3 Small Facilities 4.3
5.0 RECONSTRUCTION 5_!
6.0 LEGAL 5.!
7.0 TEST METHODS 7_!
8.0 RECORDKEEPING AND REPORTING 8-1
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TABLE OF CONTENTS (concluded)
Page
APPENDIX A - Incremental Cost Effectiveness of
Control Techniques for Equipment
Leaks of VOC
APPENDIX B - Regulatory Decisions Affecting Standards
for SOCMI
APPENDIX C - Evaluation of Available Equipment Leak Data
APPENDIX D - Model Unit and Nationwide Impacts
A-l
B-l
C-l
D-l
VI
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LIST OF TABLES
Title
Page
1-1 Summary of Individual Component Impacts 1-7
1-2 List of Commenters On Proposed Standards of
Performance for Fugitive Emission Sources in the
Petroleum Refining Industry 1-9
2-1 Comparison of CTG Recommendations and NSPS
Requirements .'.... 2-3
2-2 Summary of Individual Component Impacts. ....... 2-5
2-3 Projected VOC Fugitive Emissions from Facilities for
1982-1986 Under Uncontrolled, Baseline, and NSPS ... 2-7
2-4 Revised Emission Reductions and Costs for Leak
Detection and Repair Programs 2-13
2-5 Valve Leak Detection and Repair Cost Estimates .... 2-18
2-6 Derivation of Average Component Monitoring Time. . . . 2-30
A-l Summary of the Individual Component Control
Impacts A-3
A-2 Pressure Relief Device Impacts A-4
A-3 Compressor Seal Impacts A-7
A-4 Open-ended Lines Impacts , . A-8
A-5 Sampling Connection System Impacts A-9
A-6 Valve Emissions and Emission Reductions A-10
A-7 Valve Leak Detection and Repair Costs. ... A-ll
A-8 Sealed Bellows Valve Cost Impacts A-12
A-9 Cost Effectiveness of Valve Controls A-13
A-10 Pump Emissions and Emission Reductions A-14
A-ll Pump Leak Detection and Repair Costs A-15
A-12 Dual Mechanical Seal System Costs for Pumps A-17
A-13 Cost Effectiveness of Pump Controls A-18
VII
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1.0 SUMMARY
On January 4, 1983, the U.S. Environmental Protection Agency (EPA)
proposed standards of performance for fugitive emission sources of
volatile organic compounds (VOC) in the petroleum refining industry
(48 FR 279) under the authority of Section 111 of the Clean Air Act.
Public comments were requested on the proposed standards in the Federal
Register, and 24 commenters responded. Most of the commenters represented
refining companies or industry associations. Other commenters included
an environmental group, the Department of the Interior, and vendors of
equipment used to control fugitive emissions. This summary of comments
and EPA's responses to these comments serve as the basis for the revisions
made to the applicability and the requirements of the proposed standards.
1.1 SUMMARY OF CHANGES SINCE PROPOSAL
The proposed standards were revised as a result of reviewing
public comments. The major revisions concern the following:
• Leak Detection and Repair for Refineries Located in the
North Slope of Alaska
• Alternative for Determining a "Capital Expenditure"
• Clarification of Reconstruction Provisions
• Provision for Difficult-to-Monitor Valves in New Units
• Exemptions for Compressors
• Addition of Reporting Requirements
• Open-ended Lines on Double Block and Bleed Valves
1-1-1 Leak Detection and Repair for Refineries Located in the North
Slope of Alaska ~~'
Since proposal, EPA has reviewed comments concerning refining
operations in the North Slope of Alaska and determined 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
1-1
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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. EPA excluded these plants only from the
routine leak detection and repair requirements because the costs of
the other requirements are reasonable.
1.1.2 Alternative for Determining a "Capital Expenditure"
The General Provisions (Subpart A) of 40 CFR'Part 60, require that
increases in emissions of a pollutant covered by applicable standards
trigger the application of standards of performance for existing facilities,
These increases make a source covered by standards a modified source, '
as set forth in Section 111 of the Act. EPA has interpreted Section
111 so that production rate increases accomplished without a capital
expenditure do not trigger these provisions even though they might be
accompanied by an increase in emissions (See 40 CFR 60.14(e)(2)) Capital
expenditure is defined in 40 CFR 60.2. In the proposed standards, EPA
also excluded increases in emissions resulting from process improve-
ments accomplished without a capital expenditure from being considered
a modification. The intent was to exclude minor changes in operations
as indicated by changes not accompanied by a capital expenditure.
The annual asset guideline repair allowance (AA6RA) and the original
cost basis are used to define capital expenditure (see 40 CFR 60.2).
The definition of AA6RA is specified by the Internal Revenue Service
(IRS) and its use has not changed despite tax law changes in 1982. In
response to the comments concerning the difficulties of using the AAGRA
and the original cost basis, EPA is providing in the standards for
equipment leaks an alternative procedure for determining capital
expenditure. The purpose of the alternative is to make the determination
of capital expenditure more practicable, yet maintain the original
intent of the definition. This alternative provides that a capital
expenditure would be incurred if actual costs exceed the product,- P, of
the existing facility's (that is, the equipment covered by the standards)
replacement cost A, the AAGRA basis and an inflation factor, Y, as shown
in the following equation:
1-2
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P = A x Y x 0.07, where
A = existing facility replacement cost,
Y = the percent of the present replacement cost which is
equivalent to the original cost,
= 1.0 - 0.575 log (X), and
X = the year of construction.
1.1.3 Clarification of Reconstruction Provisions
The provisions for reconstruction (40 CFR 60.15) imply that costs
are accumulated over an unlimited time period. Commenters, however,
objected to a continuous accumulation of costs because refineries are
continually replacing components. To clarify the application of Section
60.15, EPA is defining "proposed replacement" under this standard to
include components which are replaced pursuant to all continuous programs
of component replacement which commence (but are not necessarily completed)
within a 2-year period. Thus, EPA will count toward the 50 percent
reconstruction threshold the "fixed capital cost" of all depreciable
components replaced pursuant to all continuous programs of reconstruction
which commmence within any 2-year period following proposal of these
standards.
EPA is further clarifying the intent or the reconstruction provisions
based on comments concerning routine equipment replacement. In response
to these comments, EPA is clarifying that certain routine replacements
are not considered in the basis for reconstruction. The routine replace-
ments excluded by the final standards from reconstruction are valve
packings, pump seals, nuts and bolts, and rupture disks. Replacement
of equipment pieces, such as valves and pumps, at turnaround or at
other times must be included when considering whether a reconstruction
will take place.
1.1.4 Provision for Difficult-to-Monitor Valves in New Units
At proposal, there was no exemption for difficult-to-monitor valves
in new units, although difficult-to-monitor valves were exempt from
routine monitoring in units covered through the modification or
reconstruction provisions. Commenters argued that while the number of
difficult-to-monitor valves can be substantially reduced in number for
new units, they cannot be totally eliminated. Upon reviewing the
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confluent letters, EPA decided to permit an allowable percentage of
valves in a new unit to be designated as difficult-to-monitor. Based on
existing units, about 3 percent of the total number of valves may be
impossible to eliminate without additional costs. Therefore, EPA is
allowing up to 3 percent of total numbers of valves to be treated as
difficult-to-monitor valves for new units.
1.1.5 Exemptions for Compressors
Commenters were concerned that process streams with a high
hydrogen content would be subject to the standards. The commenters
contended that such streams would have a lower percentage of VOC and,
consequently, the controls required by the proposed standards would
achieve lower emission reductions and have a higher cost effectiveness
($/Mg of VOC emission reduction).
Upon analyzing the cost effectiveness of valves and compressors
in hydrogen service (greater than 50 volume percent hydrogen) (Document
Reference No. IV-B-9), EPA determined that significant emission reduc-
tions are achieved for valves in hydrogen service at a reasonable cost
($l06/Mg VOC). However, control of compressors in hydrogen service
results in a cost effectiveness of $4,600/Mg VOC. EPA, therefore,
decided to exempt these compressors from the standards.
Commenters also implied that EPA had provided an exemption from
the standards for existing compressors. EPA provided no blanket exemp-
tion in the proposed standards even though EPA discussed that certain
reciprocating compressors might not be covered under the reconstruction
provisions if retrofitting the required equipment was technologically
or economically infeasible (See 40 CFR 60.15(e)). To make EPA's intent
clear and to reduce the burden of reviewing reconstruction determinations,
EPA is explicitly exempting reciprocating compressors that become
affected by the standards through 40 CFR 60.14 or 60.15 from the stan-
dards for compressors provided the owner or operator demonstrates that
recasting the distance piece or replacing the compressor are the only
options available to bring the compressor into compliance. If an owner
or operator is replacing a compressor or recasting the distance piece
for some other reason than to reduce emissions and comply with the
standards or if these actions occur later, then a modified or recon-
structed compressor would not be exempt from the standards.
1-4
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1.1.6 Addition of Reporting Requirements
The proposed standards did not require routine reporting. The
preamble to the proposed standards addressed three alternative levels
of reporting requirements. The alternative of no routine reporting
was selected because State or local agencies, who usually are delegated
the responsibility for enforcement of the standards, could require
routine reporting.
In response to comments on the enforceability of the standards and
comments on the need for routine reporting, EPA decided to require
routine reporting in these standards of performance rather than relying
on individual State requirements. Compliance with the leak detection
and repair program and equipment requirements will be assessed through
semiannual reports, review of records, and by inspection. The semi-
annual reports provide a summary of the data recorded on leak detection
and repair of valves, pumps, and other equipment types. Notifications
are still required as described in the General Provisions for new
source standards (40 CFR 60.7). However, the semiannual reports may be
waived for affected facilities in States where the regulatory program
has been delegated, if EPA, in the course of delegating such authority,
approves reporting requirements or an alternative means of source
surveillance adopted by the State. In these cases, such sources would
be required to comply with the requirements adopted by the State.
1.1.7 Open-Ended Lines on Double Block and Bleed Valves
The proposed standards required all open-ended lines or valves
to be capped except when they are being used. In some cases, however,
open-ended valves are installed in a "double block-and-bleed" arrangement
such that emissions must occur to the atmosphere through the open end
of the bleed valve. In such cases, the open end of the bleed valve was
not required to be capped because they are used to vent the line between
the block valves. However, when the bleed valve is not open, then it
must be capped. This was not as clear as it could have been in the
proposed standards and, therefore, a specific provision has been
added to the standards.
1-5
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1.2 SUMMARY OF IMPACTS OF PROMULGATED ACTION,
1.2.1 Alternatives to Promulgated Action
The regulatory alternatives discussed in Chapter 6 of the BID for
the proposed standards generally reflect the different levels of emission
control. They were used to help in selection of the best demonstrated
technology, considering costs and nonair quality health, environmental,
and economic impacts for fugitive emission sources in the petroleum
refining industry. These alternatives remain the same; however, the
costs, emission reductions, cost effectiveness, and incremental cost
effectiveness for the various levels of control included in the regulatory
alternatives, which were estimated and then summarized in the preamble
to the proposed standards, have been reevaluated and are now summarized
on a per component basis as presented in Table 1-1. These estimates
served as the basis for determining the impacts of the standards.
Model Unit and nationwide impacts of the promulgated standards are
documented in Appendix D.
1.2.2 Environmental Impacts of Promulgated Action
Environmental impacts of the proposed standards are described in
48 FR 279. The revisions to the applicability and provisions of the
proposed standards (described in Section 1.1) will have a minimal
effect on the environmental impacts of the standards.
1.2.3 Energy and Economic Impacts of Promulgated Action
The energy and economic impacts of the standards are described in
Chapters 8 and 9 and Appendix F of the BID for the proposed standards.
In general, there has been little change in these impacts since proposal.
The nationwide cost impacts reported in the preamble to the
promulgated standards are lower than the impacts reported at proposal.
At proposal, the nationwide cost impacts were based on refineries not
subject to State or regional regulations to control equipment leaks of
VOC. However, the nationwide impacts have subsequently been revised
(as shown in Appendix D) based upon the baseline control costs to
comply with existing regulations for equipment leaks of VOC.
1.2.4 Other Considerations
1.2.4.1 Irreversible and Irretrievable Commitment of Resources.
Section 7.6.1 of the BID for the proposed standards concluded that the
1-6
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standards will not result in any irreversible or irretrievable commit-
ment 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.
1.2.4.2 Environmental and Energy Impacts of Delayed Standards.
Table F-li of the BID for the proposed standards summarizes the
environmental and energy impacts associated with delaying promulgation
of the standards. The emission reductions and associated energy savings
shown would be irretrievably lost at the rates shown for each of the
5 years.
1.3 SUMMARY OF PUBLIC COMMENTS
Letters were received from 24 commenters commenting on the
proposed standards and the BID for the proposed standards. There was
one request for a public hearing, however, these commenters were request-
ing a meeting with EPA for clarification of the proposed standards.
Minutes of this meeting are contained in the project docket. A list
of commenters, their affiliations, and the EPA docket number assigned
to their correspondence is given in Table 1-2.
The comments have been categorized under the following topics:
Standards (Section 2)
Applicability (Section 3)
Modification (Section 4)
Reconstruction (Section 5)
Legal (Section 6)
Test Methods (Section 7)
Recordkeeping and Reporting (Section 8)
Appendix A - Incremental Cost Effectiveness of Control Techniques
for Equipment Leaks of VOC
Appendix B - Regulatory Decisions Affecting Standards
for SOCMI
Appendix C - Evaluation of Available Equipment Leak Data
Appendix D - Model Unit and Nationwide Impacts
1-8
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TABLE 1-2. LIST OF COMMENTERS ON PROPOSED STANDARDS OF PERFORMANCE
FOR FUGITIVE EMISSION SOURCES
IN THE PETROLEUM. REFINING
INDUSTRY
COMMENTER AND AFFlTTATfON
1. Mr. B.T. McMillan
Allied Chemical
P.O. Box 1053R
Morristown, NJ 07960
2. Mr. C.H. Barre
Marathon Petroleum Company
Findlay, Ohio 45840
3. Mr. R.E. Farrell
Standard Oil Company of Ohio
Midland Building
Cleveland, Ohio 44115
4. Mr. A.H. Nickolaus
Texas Chemical Council
100 Brazos, Suite 200
Austin, TX 78701-2476
5. Ms. Geraldine V. Cox
Chemical Manufacturers' Association
2501 M. Street, North West
Washington, DC 20037
6. Mr. Robert N. Harrison
Western Oil and Gas Association
727 West Seventh Street
Los Angeles, CA 90017
7. Mr. James A. Young
Independent Refiners' Association
900 Wilshire Boulevard, Suite 1024
Los Angeles, CA 90017
8. Mr. Phillip L. Youngblood
Conoco, Inc.
Suite 2136, Post Office Box 2197
Houston, TX 77252
9. Mr. Roger Noble
John Zink Company
4401 S. Peoria
Tulsa, OK 74105
DOCKET ITEM'
IV-D-3
IV-D-4
IV-D-5
IV-D-6
IV-D-7
IV-D-8;
IV-D-8a;
IV-D-1;
IV-D-2
IV-D-9
IV-D-10
IV-D-11
1-9
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COMMENTER AND AFFILIATION
TABLE 1-2. LIST OF COMMENTERS ON PROPOSED
STANDARDS OF PERFORMANCE
FOR FUGITIVE EMISSION SOURCES
IN THE PETROLEUM REFINING
INDUSTRY (Continued)
10. Mr. Herman A. Fritschen
Cities Service Company .
Post Office Box 300
Tulsa, OK 74102
11. Mr. Alan J. Schuyler
ARCO Alaska, Inc.
Post Office Box 360
Anchorage, Alaska 99510
12. Mr. Paul M. Kaplow
Atlantic Richfield Company
Post Office Box 2679-T.A.
Los Angeles, CA 90051
13. Mr. William F. O'Keefe
American Petroleum Institute
201 L Street, Northwest
Washington, DC 20037
14. Mr. A.G. Smith
Shell Oil Company
One Shell Plaza
Post Office Box 4320
Houston, TX 77210
15.. Mr. J.D. Reed
Standard Oil Company (Indiana)
200 East Randolf Drive
Chicago, IL 60601
16. Mr. J.J. Moon
Phillips Petroleum Company
Bartlesville, OK 74004
17. Mr. Louis R. Harris
B S & B Safety Systems, Inc.
7455 East 46th Street
Post Office Box 45590
Tulsa, OK 74145
18. Mr. R.H. Murray
Mobil Oil Corporation
3225 Gallows Road
Fairfax, VA 22037
DOCKET ITEM NO.
IV-D-12
IV-D-13
IV-D-14
IV-D-15
IV-D-16
IV-D-17
IV-D-18
IV-D-19
IV-D-21
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COMMENTER AND AFFILIATION
TABLE 1-2 LIST OF COMMENTERS ON PROPOSED
STANDARDS OF PERFORMANCE
FOR FUGITIVE EMISSION SOURCES
IN THE PETROLEUM REFINING
INDUSTRY (Concluded)
DOCKET ITEM NO.
19. Mr. M.W. Anderson
Kerr-McGee Corporation
Kerr-McGee Center
Oklahoma City, OK 73125
20. Mr. J.H. Leonard
Beacon Oil Company
525 West Third Street
Hanford, CA 93230
21. Mr. William L. Rogers
Gulf Oil Corporation
Post Office Drawer 2038
Pittsburgh, PA 15230
22. Mr. Joseph M. Macrum
Texaco U.S.A.
Post Office Box 52332
Houston, TX 77052
23. Mr. Bruce Blanchard
U.S. Department of the Interior
Washington, DC 20240
24. Mr. David D. Doniger
National Resources Defense Council, Inc.
1725 I Street, N.W.
Washington, D.C. 20006
IV-D-22
IV-D-23
IV-D-24
IV-D-25
IV-D-25a
IV-D-26
IV-D-30
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2.0 STANDARDS
This chapter summarizes public comments and responses to comments
pertaining to the proposed standards. Section 2.1 presents those
comments and responses that pertain to the standards in general;
Sections 2.2 through 2.8 present comments and responses that pertain to
particular requirements for each piece of equipment covered by the
standards; and Section 2.9 presents comments and responses on control
devices. In Chapter 2 and the following chapters, information used in
responding to the public comments is referenced according to document
number within the project docket, Docket No. A-80-44.
2.1 GENERAL DISCUSSION
Comment:
Commenters (IV-D-5, IV-D-12, and IV-D-25) wrote that the standards
should be the same as State requirements. Commenters (IV-D-22 and
IV-D-24) argued that the proposed standards would be redundant and
conflict with existing State regulations. For example, States may
presently require leak detection and repair of compressor seals while
the NSPS would require equipment specifications. One commenter (IV-D-12)
thought the standards would require the abandonment of existing programs.
Response: .
The Clean Air Act Amendments of 1977 require each State in which
there are areas where the national ambient air quality standards (NAAQS)
are exceeded to adopt and submit revised State implementation plans
(SIP's) to EPA. Sections 172(a)(2) and (b)(3) of the Clean Air Act
require that nonattainment area SIP's include reasonably available
control technology (RACT) requirements for stationary sources. EPA
issues Control Techniques Guidelines (CTG) documents to provide State
and local air pollution control agencies with an initial information
base for proceeding with their own assessment of RACT for specific
stationary sources.
2-1
-------
Most State regulations for fugitive VOC emissions are based on the
"Control of Volatile Organic Compound Leaks for Petroleum Refinery
Equipment," EPA-450/2-78-036, released by EPA in June 1978 (Document
No. II-A-6). This CTG was issued by EPA to provide information and
guidance to State and local air pollution control agencies for their
use in regulating VOC emissions in oxidant nonattainment areas. The
CTG identifies RACT that can be applied to existing refineries to control
VOC from equipment leaks.
The Clean Air Act requires that standards of performance for
stationary sources reflect the degree of emission limitation achievable
through application of the best adequately demonstrated technological
system of continuous emission reduction (best demonstrated technology,
BDT), taking into consideration the cost of achieving such emission
reduction, any nonair quality health and environmental impacts, and
energy requirements. NSPS applies to newly contructed, modified, or
reconstructed facilities in both attainment and non-attainment areas.
Because the purpose of the NSPS and the purpose of the State regulations,
as reflected in the Clean Air Act, differ EPA believes that it would be
inappropriate for the requirements to be necessarily the same.
The standards are not redundant, and no substantial conflict
occurs between the NSPS and State requirements. The NSPS requirements
and the CTG recommendations are identified and compared in Table 2-1.
The NSPS require monthly/quarterly leak detection and repair of gas and
light liquid valves and monthly leak detection and repair for light
liquid pumps, while the CTG recommends less frequent leak detection and
repair (quarterly leak detection and repair for gas valves and yearly
leak detection and repair for light liquid valves and pumps). The
increased monitoring frequencies of the NSPS are reasonable because the
incremental cost and emission reduction are reasonable.
The standards for pressure relief devices and compressors are based
on the use of equipment, whereas the CTG recommends leak detection and
repair for pressure relief devices and compressors.: The CTG includes
no recommendation for sampling connections. The standards require
equipment and work practices for sampling connections; again, there is
no conflict between the NSPS and State requirements. The standards
2-2
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-------
also provide alternatives for valves that allow an owner or operator
to continue the CTG control level for process units with less than
2.0 percent of the valves leaking. Other alternatives are allowed for
valves, and three alternatives are allowed for pumps. EPA does not
believe th.at the standards would conflict with most existing State
regulations. The standards apply only to affected facilities (compressors
are one of the facilities covered by the standards) that commence
construction or modification after January 4, 1983. A conflict may
occur if State agencies require leak detection and repair. The conflict
is requiring unneeded leak detection and repair for compressors equipped
with the controls required by the standards. Most State air pollution
control regulations include variance procedures that owners or operators
can assess. In the few cases where it occurs, costs would not
be unreasonable. These procedures could be used to eliminate the
conflict. After considering the differences between the CTG and NSPS,
EPA concluded that the NSPS requirements are not redundant and do not
substantially conflict with existing State regulations.
EPA also judged that the standards do not require or motivate
refiners to abandon existing plant leak detection and repair programs.
In making these judgments, EPA noted that the CTG was based on RACT,
whereas the NSPS is based on BDT, considering costs. In determining
BDT, EPA analyzed the cost effectiveness and incremental cost effec-
tiveness of a variety of control techniques (presented in Table 2-2),
including those presently required by State regulations. EPA also
included existing programs in assessing the impacts of the NSPS.
Based on this, EPA determined that the costs of the control techniques
selected as the basis for the standards are reasonable. The final
standards and existing programs should work together, yet to the extent
that some existing regulations may conflict with the NSPS, refiners can
request a variance for existing programs as discussed in the previous
paragraph.
Comment:
Some commenters (IV-D-5, IV-D-16, and IV-D-25) contended that EPA
overstated the emission reductions of the proposed standards by under-
stating baseline emissions. The emission reductions should reflect the
sources covered by State regulations. Another commenter (IV-D-15)
2-4
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Table 2-2. SUMMARY OF THE INDIVIDUAL COMPONENT CONTROL IMPACTS*
Fugitive Emission
Source
Pressure relief devices
Compressors
Open-ended valves
Sampling connection
systems
Valves
Pumps
Control Technique
Quarterly LDR
Monthly LDR
Rupture disksd
Controlled degassing
vents
Caps on open ends
Closed purge sampling-
Quarterly LDR
Monthly LDR
Sealed bellows valves
Annual LDR
Quarterly LDR
Monthly LDR
Dual mechanical seal
system
Emission Reduction
(Mg/yr)
4.4
5.3
9.8
16.5
2.8
2.6
66
77
110
3.0
9.8
11.5
13.9
Average Cost
Effectiveness
($/Mg)b
(170)
(110)
410
150
460
810
(110)
(60)
4,700
860
157
158
2,000
Incremental Cost
Effectiveness
($/Mg)c
(170)
250
1,000
150
460
810
(110)
310
16,700
860
(140)
170
10,900
(xx) = Cost savings
LDR = Leak detection and repair
acosts and emission reductions are based on fugitive emission component counts in Model B from the BID
for the proposed standards, EPA-450/3-81-015a, page 6-3, and from Tables A-2 through A-13 of Appendix A.
^Average Cost Effectiveness = net annualized costs per component * annual VOC emission reduction oer
component.
clncremental Cost Effectiveness = (net annualized cost of the control technique - net annualized cost
of the next less restrictive control technique) * (annual emission reduction of control technique -
annual emission reduction of the next less restrictive control technique).
dUnder!1ned control techniques were selected as basis for standards.
2-5
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wrote that it was not clear whether the baseline emissions represent
existing levels of control or no control.
Response:
Promulgation of the Priority List (40 CFR 60.16, 44 FR 4922,
August 21, 1979), reflects EPA's determination that refinery fugitive
emissions are a major source category which contribute significantly to
air pollution. As discussed in Chapter 7 of the BID for the proposed
standards, baseline reflects a weighted average of refineries in
attainment (no regulations) and nonattainment (recommendations of the
refinery CTG) areas and, therefore, does account for sources covered
by State regulations. Table 2-3, taken from the BID for the proposed
standards, compares the projected VOC emissions under baseline level of
control for 1982-1986 with projected emissions under both the uncontrolled
level and the level of control obtained by the standards.
Comment:
One commenter (IV-D-6) stated that the proposed regulations are
difficult to follow because of the exemptions, alternatives, and the
Federal Register format, which requires almost continuous "cross-checking."
The commenter suggested that the requirements for a specific component
appear as a separate section to improve the readability of the regulations.
Response:
The format of the standards does require some cross-checking as the
commenter mentions. However, the standards do present individual component
requirements in separate sections as requested by the commenter and
discuss common aspects of these individual component requirements in
other sections (e.g., Section 60.595 Test Method and Procedures). This
format greatly reduces the redundancy in presenting the regulations.
Comment:
One commenter (IV-D-14) maintained that the standards should apply
only to valves because they are the largest single source, and annua]
inspection and repair programs are cost effective in reducing emissions
only from valves. In addition, the commenter wrote that limiting the
standards to valves would result in a more efficient and practicable
approach to reducing emissions from new, modified, and reconstructed
sources. Other fugitive emission components comprise a smaller source
of emissions, and control for these components either has not been
demonstrated or has not been shown to be cost effective.
2-6
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Table 2-3. PROJECTED VOC FUGITIVE EMISSIONS FROM FACILITIES FOR
1982-1986 UNDER UNCONTROLLED, BASELINE, AND NSPSa
Year
Total Fugitive Emissions Projected (Gg/yr)
Uncontrolled13 Baseline0 NSPSd
1982
1983
1984
1985
1986
12
24
37
51
64
9.2
19
29
39
49
3.4
7.1
11
14
18
o
The emissions estimates are taken from Table F-10 of the BID for the
proposed standards. The estimates are based on projected new, modified,
and reconstructed model units.
b ' ' •
The uncontrolled emissions projection assumes all refineries are
operating in the absence of regulations (Regulatory Alternative I).
c - • '
The baseline emissions projection reflects normal existing operations
in refineries nationwide in the absence of any new regulations. The
baseline assumes that refineries in nonattainment areas for ozone are
subject to regulations similar to those recommended in the refinery
Control Techniques Guideline document (Document No. II-A-6), Regulatory
Alternative II in the Blip for the proposed standard. Baseline emissions
are calculated as the weighted sum of the proportion of refineries i,n
attainment and nonattainment areas for ozone: (0.56)(Regulatory
Alternative II) + (0.44) (Regulatory Alternative I).
i
Emissions projected under promulgated standards.
2-7
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Response:
EPA agrees with the commenter that valves represent the largest
source of fugitive VOC by component type in a refinery. However,
the uncontrolled emission factors presented in the BID for the proposed
standards,-Table 3-1, clearly show that pressure relief devices, com-
pressors, and light liquid service pumps also have relatively high
emission rates. EPA has determined that fugitive emission sources in
petroleum refinery equipment contribute significantly to ozone pollution
and, therefore, were included in a source category on the NSPS Priority
List in 40 CFR 60.16. Under Section lll(b)(l), EPA is now required to
set standards of performance for all new sources within this listed
category for which EPA can identify BDT (considering costs). EPA is
selecting BDT (considering costs) based on cost-effective control
techniques for the source. Several types of refinery equipment may
emit VOC leaks, and, therefore, each is a subset of the entire source.
In selecting BDT, EPA is setting standards for each fugitive emission
component with demonstrated, cost-effective controls (see Table 2-2).
Because EPA maintains that the standards provide cost-effective control
for other sources as well as valves, equipment other than valves will
be covered by the standards.
Comment:
Commenters (IV-D-12 and IV-D-25) indicated that the proposed
standards are inflexible, manpower intensive, and not cost effective.
Response:
EPA has expended considerable effort to make these standards as
definitive and flexible as possible. As discussed in the preamble for
the proposed standards, different formats are required for different
fugitive emission sources because the characteristics of the emission
sources and the availability of the measurement method used for fugitive
emission sources differ among the sources. Performance standards allow
some flexibility, because any control technique may be used if it achieves
the required level of emission reduction. However, for most refinery
equipment, it is not feasible to prescribe a performance standard. EPA
has selected performance standards for certain equipment, where practi-
cable, and has provided alternative standards when equipment, work
practice, design or operational standards have been used. Hence,
2-8
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multiple control options are allowed wherever practicable and are
considered equivalent to the control techniques selected as BDT. In
contrast to the comment, EPA considers the manpower requirements of the
standards worthwhile and a prudent use of resources as evidenced by the
cost effectiveness of the control techniques presented in Table 2-2.
The overall cost effectiveness of the standards is approximately $130/Mg,
which EPA considers reasonable.
Comment:
A commenter (IV-D-15) expressed some confusion on the cost-
effectiveness information presented in Table 1 of the preamble to
the proposed standards. The values presented in Table 1, the commenter
said, cannot be generated from the emissions, labor, and cost information
presented in the BID. The commenter added that since the BID for
the proposed standards does not contain a cost-effectiveness analysis
for each component as given in Table 1 of the preamble to the proposed
standard, a supplemental document should be prepared by EPA showing
calculations and should be made available for public comment prior to
promulgating the standards.
Response:
Upon reviewing the calculations that were performed to generate the
cost-effectiveness information presented in Table 1 of the preamble to
the proposed standards, it was determined that a mistake was made in the
valve emission reduction calculations. This is explained in Section 2.2.1,
In addition, the analysis for pumps was changed as discussed in the AID
(Document No. II-A-41) and Section 2.3.1. The corrected valve and
revised pump calculations are presented in Appendix A and the results
are summarized in Table 2-2.
The commenter is correct in that individual cost-effectiveness
estimates are not presented in the BID for the proposed standard; instead,
the proposal BID presents cost-effectiveness estimates for regulatory
alternatives. The proposal BID does, however, present the method for
calculating the cost, emission reduction, and cost effectiveness for
the various levels of control from which individual component impacts
can be derived. In addition, a previous supplemental information
document (Document No. IV-D-41) has been issued by EPA that explicitly
presents the method for calculating individual component impact estimates.
2-9
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EPA is also providing the derivation of individual component impacts in
Appendix A.
EPA does not believe that a supplemental information document is
warranted. In September 1980, EPA requested public comments on the
preliminary model units and regulatory alternatives; in May 1981, the
preliminary draft BID was distributed to the National Air Pollution
Control Techniques Advisory Committee, industry, environmental groups,
and other interested persons; and in April 1982, EPA announced the
availability of and invited comments on an additional information
document on the emissions, emission reductions, and costs for control
of fugitive emission sources of organic compounds. Because the commenters
did not question EPA's method of analysis and EPA's review of the
comment did not change its analysis, an additional information document
is not warranted.
2.2 VALVES
2.2.1 Basis for Standards
Comment:
One commenter (IV-D-15) wrote that it was not clear whether the
cost-effectiveness values presented in Table 1 of the proposal preamble
are based on a continuing monthly monitoring schedule or the reference
leak detection and repair program for valves that allows less frequent
monitoring of non-leakers.
Responses:
In selecting the basis of the standards for valves, EPA considered
different alternative monitoring periods for valves: annual, quarterly,
and monthly monitoring. In reviewing the public comments, EPA re-
examined the incremental impacts of the three monitoring intervals
(Document No. IV-B-10). Each of these intervals was compared in terms
of the emission reduction achievable and cost-effectiveness of the leak
detection and repair programs as presented in Appendix F of the BID for
the proposed standards. Monthly monitoring was selected because it
achieves the largest emission reduction, 77 Mg per year for a Model
Unit B. EPA also judged that monthly monitoring has a reasonable cost
effectiveness, a credit of $60/Mg, and that the incremental cost effec-
tiveness of $310/Mg VOC for monthly versus quarterly monitoring is
2-10
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reasonable. Based on these estimates EPA considers monthly monitoring
BDT for valves.
Available data (II-A-21 and II-A-26) indicate that leak recurrence
is an important factor in predicting leaks from valves. That is, 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 is important in predicting
leaks, EPA considers that the annual cost of monthly monitoring of
valves that leak infrequently would probably be unreasonably high in
comparison to the annual cost of quarterly monitoring, considering the
emission reduction achieved by monthly and quarterly monitoring.
Therefore, the standards allow quarterly monitoring for valves which
have been found not to leak for two successive months resulting in a
hybrid monthly/quarterly monitoring program.
It is possible that basing the standards on monthly monitoring,
but allowing monthly/quarterly monitoring, has led to confusion. The
basis of the standards remain monthly so the cost-effectiveness estimates
for valves given in the proposal preamble are based on continuing
monthly monitoring. By basing the cost analysis on monthly monitoring
rather than monthly/quarterly, a maximum cost impact estimate was
evaluated. It is important to note, however, that the actual cost
effectiveness of the standards for valves is likely to be even better
because the standards allow quarterly monitoring for valves that have
been found not to leak for two successive months (monthly/quarterly
monitoring). EPA expects that most affected facilities would follow
the monthly/quarterly reference leak detection and repair program
and, further, that most valves would be on.the quarterly inspection
schedule. Hence, the actual costs for valves under the standards is
likely to be more closely represented by the costs estimated for
quarterly monitoring.
Upon reviewing the calculations that were performed to generate
the information presented in Table 1 of the preamble to the proposed
standards, it was determined (Document No. IV-B-3) that an error was
made in the valve emission reduction calculations. This is likely what
caused the commenter's confusion on the calculation of the impacts of
the valve standards. Valve impacts are calculated based upon a Model
2-11
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Unit B refinery unit component inventory (260 gas/vapor service valves
and 500 light liquid service valves). The valve emission reductions
were underestimated by mistakenly using a weighted average of the
emission reductions for the two types of valves, gas/vapor and light
liquid, rather than the total emissions from the two types of valves.
The corrected emission reductions impacts are presented in Table 2-4.
In rechecking the cost and emission reduction calculations, rounding
resulted in a slight differences in the cost effectiveness and incremental
cost effectiveness values. The revised emission reduction and cost
effectiveness for monthly leak detection and repair are 77 Mg/year
and a savings of $60/Mg VOC emission reduction, respectively. The
incremental cost-effectiveness from quarterly to monthly monitoring now
shown is $310/Mg of VOC emission reduction. The revised numbers have
been incorporated into the analysis of the final standards and did not
affect any of the decisions on the proposed standards.
Comment:
A number of commenters (IV-D-8, IV-D-12, IV-D-14, IV-D-16, IV-D-
17, IV-D-18, IV-D-21, and IV-D-25) wrote that monthly monitoring of valves
is not cost effective. Commenters contended that their experience with
less frequent monitoring intervals (quarterly and annual monitoring)
shows that these intervals are more reasonable. Some commenters recom-
mended annual monitoring for valves because the results of programs
performed at West Coast (California) refineries indicate that leak
occurrence rates for valves under annual monitoring are lower than
EPA's assumed estimate of 3.8 percent on a quarterly basis. Two com-
menters (IV-D-8 and IV-D-14) stated that their refinery-wide leak
occurrence rate'was only 1 to 2 percent on an annual basis. Similarly,
another commenter (IV-D-21) stated that annual inspection programs
result in leak occurrence frequencies as low as 0.3 percent.
One commenter (IV-D-15) recommended that EPA obtain leak detection
and repair program data generated in California. Other commenters (IV-
D-14, IV-D-25a, and IV-D-31) provided data on leak detection and repair
programs. In particular, information was provided EPA concerning leak
frequency, leak occurrence and recurrence rates, and monitoring and
maintenance costs.
2-12
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Table 2-4. REVISED EMISSION REDUCTIONS AND COST FOR VALVE
LEAK DETECTION AND REPAIR PROGRAMS9
Monitoring Interval
Quarterly
Monthly
Emission Reduction
(Mg/yr)b
Proposed0
Revised3
Average $/Mgd
Proposed0"
Revised3
Incremental $/Mge
Proposed0
Revised3
31.7
66
(90)
(110)
---
37.1
77
(40)
(60)
300
310
(xx) = Cost savings.
Memorandum from T.W. Rhoads, PES, Inc., to Docket A-80-44.
VOC Emission Reduction and Cost-Effectiveness Estimates.
July 14, 1983. Document No. IV-B-3.
bBased on Model Unit B component counts, BID for proposed standards.
°From Table 1 preamble for proposed regulation.
dAverage dollars per megagram (cost effectiveness) = net annualized
cost per component * annual VOC emission reduction per component.
Incremental dollars per megagram = (net annualized cost of monthly
monitoring - net annualized cost of quarterly monitoring) 4 (annual
emission reduction of monthly monitoring - annual emission reduction
of quarterly monitoring).
2-13
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Response:
As discussed in the previous response, EPA evaluated three
monitoring intervals for valves: annual, quarterly, and monthly. Each
of these intervals was compared in terms of the emission reduction
achievable and the cost effectiveness of the leak detection and repair
programs. Annual and quarterly monitoring are more cost effective than
monthly monitoring, however, the standards require monthly monitoring
because it provided the greatest emission reduction at a reasonable
cost effectiveness and incremental cost effectiveness.
The commenters are questioning the cost effectiveness estimates
used by EPA based mostly on their experiences with monitoring required
by State implementation plans in California. However, the effectiveness
of leak detection and repair programs in California is not strictly
comparable with the regulatory alternative used in the BID for the
proposed standards. The commenters refer to the South Coast Air Quality
Management District (SCAQMD) Rule 466.1 on leakage from valves and
flanges. Contrary to the commenter's contention, monitoring under Rule
466.1 is not strictly on an annual basis, but rather biannual for the
first year and annual in the following years. Like the final standards,
Rule 466.1 focuses on recurring leakers; Rule 466.1 requires follow-up
inspections on leaking equipment at 3 months and, if they are still
leaking at this inspection, follow-up inspections at successively
shorter periods, and in addition, Rule 466.1 requires all repairs to
be completed within 2 working days unless a variance is obtained. In
contrast, the standards require that repairs be made as soon as practi-
cable with an initial attempt within 5 days and completion within 15
days. The standards also provide for automatic delay of repairs to a
process unit turnaround. Another important distinction is distance at
which monitoring measurements are taken. The standards require measure-
ment at the source, whereas the SCAQMD Rule 466.1 allows measurement at
1 cm from the surface. Thus, simple comparison of data from refineries
subject to the SCAQMD rules to EPA's data base is misleading.
In response to these comments, EPA reviewed and compared equipment
leak data from current industry leak detection and repair programs to
the,data used in developing the standards. The results of this analysis
2-14
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are presented in Appendix C. Where these data relate to specific
comments on the standards, they are also incorporated into the response
to the comment.
Section C.I.2 of Appendix C presents occurrence rate data obtained
, from industry leak detection and repair programs. An EPA study found
(Document No. IV-B-11 and Section C.4) that the occurrence rates
observed at two refineries in the South Coast Air Quality Management
District (SCAQMD) are similar to the occurrence rates EPA used to
estimate the national average for evaluating the effectiveness of leak
detection and repair programs. Other existing leak detection and repair
programs, however, have resulted in low annual occurrence rates as the
commenters argued. However, the occurrence rate data obtained from
refineries with existing leak detection and repair programs may be
underestimated as a result of differences, as discussed above, in the
requirements of existing regulations and those considered in developing
the standards.
To the extent EPA data dp not reflect certain process units covered
by current plant practices (State regulation or otherwise), the standards
have been developed to define BDT (considering costs) appropriately taking
this into account. As discussed in the first response in this section
and in the presentation before the National Air Pollution Control
Techniques Advisory Committee (NAPCTAC) in June of 1981 (Document No.
II-B-34) and in the preamble to the proposed standards, EPA believes
that monthly monitoring for valves with a history of low leak rates is
unnecessary. The final standards, therefore, allow monthly/quarterly
monitoring, and alternative standards are provided for units with low
rates. EPA believes the standards and the alternative standards
represent BDT for all units covered by the standards.
Comment:
One commenter (IV-D-14) submitted the results of an LDAR Model run
which calculated an incremental cost effectiveness from annual to
monthly monitoring of $5,900/Mg. In addition, this commenter added
that this LDAR Model run predicted emission reductions from the annual
inspection program at a West Coast refinery would achieve a greater
emission reduction than EPA's estimate for monthly monitoring, 72 percent
versus 70 percent, respectively.
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Response:
EPA reviewed (Document No. IV-B-16) the commenter's LDAR Model run
and found several problems with the data inputs used by the commenter.
The commenter used 1982 costs, rather than May 1980 costs that were
used for the basis of the standards. Also, the commenter's use of
occurrence rates in the analysis was incorrect. The commenter substi-
tuted different (2.0 percent annual) occurrence rates without also
correcting the initial leak frequency and emission factors, which are a
function of the occurrence rate. In lowering the occurrence rate, a
corresponding reduction in the initial leak frequency and average
emission factor should occur (Document Nos. II-B-43 and II-B-7). The
commenter wrote that the 2.0 percent occurrence rate represents the
West Coast annual inspection program, yet, as discussed in the previous
response, direct comparison of annual monitoring under Rule 466.1 with
the standards for valves is misleading. Also, the commenter did not
use the LDAR Model input values that they indicated. The commenter's
occurrence rates were purportedly 2.0 percent annual occurrence rates
for annual and monthly monitoring, yet, in reviewing the commenter's
analysis, it was found that an 8 percent annual occurrence rate was
used to evaluate monthly monitoring. In addition, the commenter failed
to use half the inputs the commenter said would provide a better estimate
of the impacts of leak detection and repair programs. Correcting just
the occurrence rate (to 2.0 percent annual occurrence for both annual
and monthly monitoring) and the cost basis (to 1980 dollars) in the
commenter's data inputs results in an 80 percent emission reduction for
monthly monitoring (significantly more than the 72 percent reduction
achieved by annual monitoring in the comment) and a cost effectiveness
of monthly monitoring of $500/Mg and an incremental cost effectiveness
between annual and monthly monitoring of $l,900/Mg. EPA and the
reported source of the commenter's estimates do not believe the inputs
the commenter used are representative.
Comment;
Two commenters submitted that monthly monitoring .would be more
costly than EPA estimated. One commenter (IV-D-24) wrote that the
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costs for monthly monitoring at one refinery would increase from $6.40
per component per year for quarterly monitoring to approximately $19
per component per year for monthly monitoring. Another commenter
(IV-D-25) and IV-D-25a wrote that the cost per component given in the
April 1981 preliminary draft BID, $0.82, is far below the $2.57 per
component monitoring cost experienced at his refinery in 1982. The
commenter further stated that they had a total program cost of $4.82
per component.
Response: '
EPA calculated the costs per valve based on the data and information
discussed in "Fugitive Emission Sources of Organic Compounds - Additional
Information on Emissions, Emission Reductions, and Costs" (AID), April
1982, EPA-450/3-82-010. EPA requested public comments on the monitoring
labor requirement and cost estimates in the AID. EPA has previously
received specific comments at the June 1981 meeting of the National Air
Pollution Control Techniques Advisory Committee (NAPCTAC) on the information
in the BID for the proposed standards. After reviewing the NAPCTAC
comments and comments on the AID, EPA added some provisions making them
more practicable where possible, however, the standards remain essentially
the same.
To compare the first commenter1s cost estimates to the EPA's
estimates, it was necessary to contact the commenter to determine the
basis of his costs. From the additional information obtained (IV-F-28),
EPA learned that the leak detection and repair costs submitted were
mostly for valves (about 90 percent), but included some components
other than valves. Thus, the commenter was comparing the costs for
leak detection and repair for all components to the EPA's cost estimates
for valves. Since the cost to monitor and repair components other than
valves are typically higher than that for valves, the commenter's costs
overestimate the actual cost per valve he incurred. EPA also learned
that the costs provided reflect a contractor's total labor costs for
monitoring and repairs from a refinery inspection in 1982 dollars. The
costs submitted did not include the refiner's overhead.
The first commenter's costs were adjusted for 1980 dollars (to be
consistent with the EPA's cost estimates) by using cost indexes from
Chemical Engineering (Document Nos. II-I-58 and IV-J-2). An overhead
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rate was also applied to the commenter's costs consistent with EPA's
estimates. The results, compared in Table 2-5, show that EPA's cost
for quarterly monitoring is somewhat higher, $5.91 per valve compared
to $4.22 per valve. The commenters adjusted estimate for monthly
monitoring, however, is somewhat higher than EPA's, $17.5 per valve
compared to $16.00 per valve. The comparison of the commenters' costs
and EPA's estimates indicates that the EPA's estimates are reasonably
close to the plant's expenditures for leak detection and repair. This
commenter did not comment on the basis for the EPA cost estimates.
Also, to the extent that an individual plant's costs may be higher than
the EPA estimates, the EPA costs appropriately reflect the nationwide
average costs to comply with the standards, such that any individual
plant costs may be somewhat higher or lower.
Table 2-5. COMPARISON OF COMMENTER AND EPA ANNUAL COSTS FOR
LEAK DETECTION AND REPAIR
Commenter Estimates-
For Components9
EPA Estimates
For Valvesb
Monitoring
Period
Quarterly
Monthly
1982
Dollars
6.40
19.00
1980
Dollars
4.22
12.50
1980
Dollars
plus
Overhead
5.90
17.50
1980
Dollars
9.20
16.00
From Document Nos. IV-D-24 and IV-E-28. Cost are adjusted to 1980
dollars using cost indexes (Document Nos. II-I-58 and IV-J-2). Costs
presented in the comment letter are based on 1982 dollars. .Overhead
is estimated as 0.40 x monitoring and repair labor cost.
b
From Document No. IV-B-10.
The second commenter's costs are based on first year costs to
implement a leak detection and repair program similar to Regulatory
Alternative II in the BID for the proposed standards, which specifies,
quarterly inspections of gas service components and annual inspections
of 1-iquid service components. A review of the commenter's cost data
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(see Section C.I.5 of Appendix C) found the commenter's actual costs to
be similar to EPA's cost estimates when compared on a common basis
(e.g., adjusting to a 1980 cost basis, overhead rate). The commenter's
total leak detection and repair costs in 1980 dollars, about $71,100
per year, compare to an EPA estimate of about $60,900 per year for a
similar scenario. Here again, the comparison is not strictly valid
because the two estimates are based on different component populations.
The commenter's data include an unknown number of component types not
included in the CT6 recommendations such as valve flanges and capped
open ended lines.
The information EPA received from the commenters did not lead EPA
to change the cost estimation methods. Therefore, EPA has not changed
the basis for the costs and considers the costs of a monthly leak
detection and repair program for valves to be reasonable (i.e., an
average cost effectiveness (credit) of $60/Mg and an incremental cost
of $310/Mg compared to quarterly monitoring.
2.2.2 Alternative Standards .
Comment:
Some commenters (IV-D-5, IV-D-10, IV-D-24, and IV-D-30) wrote that
they support the alternative standards for valves as they provide
incentive for a facility to maintain a low incidence of leaking sources.
One of the commenters (IV-D-10) wrote that the addition of alternative
standards for valves was an improvement from the proposed standards for
valves in the synthetic organic chemical manufacturing industry (SOCMI).
Another commenter (IV-D-30), however, questioned the basis for allowing
a 2.0 percent leaking valve rate when the objective is to keep the real
leak rate below an average of 1.0 percent because most facilities would
operate with a real leaking valve rate well above 1.0 percent.
Response:
EPA believes that monthly monitoring does not have a reasonable
cost effectiveness for process units with a low percentage of valves
leaking. EPA judged at proposal that for units with less than (on the
average) 1.0 percent valves leaking, monthly monitoring is unreasonable.
EPA has, therefore, included alternative standards for valves in units
with a low percentage of leakers: (1) two skip period monitoring
programs and (2) an allowable percentage of valves leaking (performance
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limit). This approach addresses the comment that, if annual leak
detection and repair or some other reduction program reduces leak rates
to an average of well under EPA's estimates, the cost effectiveness of
monthly monitoring is unreasonable.
The alternative standards apply on an affected facility basis,
(i.e., individual process unit). As was explained at proposal, the
allowable percent (2.0 percent) of valves leaking was selected (Document
No. II-B-43) after considering the costs and emission reductions of
monthly monitoring of low leak units and the variability inherent in
leak detection of valves. The variability in the number of valves
which are found leaking at any one time (e.g., variability in the
monitoring instrument, instrument operators, the piece of equipment,
leak occurrence, and recurrence) in leak detection of valves can be
characterized as a binominal distribution around the average percent of
valves leaking. Inclusion of the variability in leak detection of
valves is accomplished by straightforward statistical techniques based
on the binominal distribution. An allowable percent of valves leaking
of 2.0 percent, to be achieved at any point in time, would provide an
owner or operator a risk of about 5 percent that greater than 2.0
percent of valves would be determined leaking when the average of 1.0
percent was actually being achieved. Based on these considerations,
EPA considers an allowable percent of valves leaking of 2.0 percent to
represent about one percent of valves leaking.
The first alternative specifies two statistically based skip-period
leak detection and repair programs. Under skip-period monitoring programs,
an owner or operator can skip from routine monitoring to less frequent
monitoring after" completing a number of consecutive monitoring intervals
with performance levels less than 2.0 percent of valves leaking. The
first skip-period program provides that after 2 consecutive quarterly
leak detection periods with the percent of valves leaking equal to or
less than 2.0, an owner may begin to skip one of the quarterly leak
detection periods (semiannual monitoring). The second skip-period
program provides that after 5 consecutive quarterly leak detection
periods with the percent of valves leaking equal to or less than than
2.0, an owner or operator may begin to skip 3 of the quarterly leak
detection periods (annual monitoring). This skip period alternative
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standard also requires that, if an affected facility exceeds the 2.0
percent limit of valves leaking during the semiannual or annual inspec-
tion, the owner or operator must revert to the monthly/quarterly leak
detection and repair program that is specified in the standards. The
original criteria for skip monitoring would again have to be met before
owners and operators can again skip monitoring periods.
The second alternative standard for valves is a performance standard
that specifies a 2.0 percent limitation as the maximum percent of
valves leaking within a process unit. This alternative standard would
require a minimum of one performance test per year. This alternative
provides an incentive for maintaining a low percentage of leaking valves
level by implementing any type of leak detection and repair program or
engineering controls at the discretion of the owner or operator.
Comment:
Several (IV-D-8, IV-D-12, IV-D-14, IV-D-16, IV-D-17, IV-D-18, and
IV-D-21.) commenters suggested that the regulations should begin with
annual inspections.and require more frequent inspections only if needed.
Another commenter (IV-D-25) wrote that industry would be reluctant to
use the alternative standards due to noncompliance penalties.
Response:
Based on evaluation of data that EPA considers representative of
petroleum refineries, EPA selected standards for valves that require
monthly/quarterly monitoring. The standards, however, also provide
alternatives for facilities (process units) with relatively low leak
frequencies. The commenters are asking that the standards be structured
to allow increasing the frequency of monitoring in high-leak units
rather than decreasing the monitoring in low-leak units (as currently
structured).
The standards for valves (monthly/quarterly monitoring) and the
alternative standards are structured to assure that best demonstrated
technology for valves is achieved initially and throughout implementation
of the standards. The data (II-A-19) indicate that about 10 percent of
the valves in a facility would be found leaking on an initial inspection.
Hence, the standards are structured to identify and control leaking
valves through relatively frequent monitoring initially, and once
recurring leakers are identified and controlled, allow less frequent
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monitoring. If the standards were structured as the commenters propose
(based on increasing monitoring frequency), less emission reduction
would result by allowing longer time intervals before recurring leakers
are controlled.-
EPA agrees with the commenters in that owners and operators might
be reluctant to use the alternative standard for allowable percentage
of valves leaking. Use of this alternative standard would subject an
affected facility to non-compliance penalties. The owner or operator of
a process unit selecting the allowable percentage of valves leaking
alternative would have to do performance tests initially, annually, and
at other times requested by the EPA Administrator. If more than two
percent of the valves are found leaking, the facility would not be in
compliance with the regulation.
For many facilities it may be impossible to guarantee that the
facility will always have less than 2.0 percent valves leaking. These
facilities should consider implementing the skip-period monitoring
programs outlined in the previous response. For facilities following
the skip-period monitoring alternative standard, the "penalty" for
having greater than 2.0 percent valves leaking is more frequent
monitoring rather than non-compliance with the standard.
2.2.3 Special Provisions
The following comments and responses pertain to specific groups of
valves and provisions in the standards for valves relating to them.
2.2.3.1 Difficult-to-monitor valves
Comment:
Two commenters (IV-D-12 and IV-D-15) maintained that difficult-to-
monitor valves can not be eliminated in new units, even though they can
be reduced in number. Therefore, the difficult-to-monitor provisions
should be allowed for new facilities as well as existing facilities.
Conversely, another commenter (IV-D-30) objected "to the exception from
the monitoring requirements for supposedly difficult-to-monitor valves,"
claiming that, "it simply is not a significant burden for the monitoring
personnel to use a ladder to reach valves higher than 2 meters off the
ground." One commenter (IV-D-4) remarked that requiring monitoring
personnel to carry equipment and climb a ladder to inspect difficult-
to-monitor valves could double the cost of the monitoring program.
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Furthermore, comm'enters (IV-D-8, IV-D-15, IV-D-21, and IV-D-25) maintained
building new units without difficult-to-monitor valves will substantially
increase unit costs because of extra ladders and platforms. The commenters
added that it is too costly to monitor difficult-to-monitor valves.
Another commenter (IV-D-24) requested that the EPA include a statement
that would require annual monitoring "if practicable." . •
Response:
The intent of the standards is to monitor those valves that can be
reached with the use of portable ladders or with existing supports such
as platforms and fixed ladders. EPA defines valves that cannot be
reached without extraordinary means, difficult-to-monitor valves, as
those valves that cannot be monitored without elevating the monitoring
personnel more than 2 meters above a support surface. EPA does not :
consider valves that can be reached from a portable ladder to be difficult-
to-monitor, and hence the standards require operators to use portable ladders
to monitor such valves.
EPA has estimated the cost for monitoring difficult-to-monitor
valves in existing units (Document No. II-B-46) and determined that the
cost effectiveness of monthly monitoring of difficult-to-monitor valves
may be unreasonable, and that the average cost effectiveness for annual
monitoring is reasonable. Hence, EPA proposed annual monitoring of
difficult-to-monitor valves in existing facilities. The provision was
not allowed for newly constructed affected facilities because commenters
on the proposed standards for VOC fugitive emission in the synthetic
organic chemicals manufacturing industry (Document No. IV-A-5, Section
4.2.4) wrote that difficult-to-monitor valves can be eliminated in new
units. A refinery design engineer (IV-E-15) also indicated that new
units can be designed with no difficult-to-monitor valves.
Upon reviewing the comments received on the proposed standards,
EPA agrees with the commenters in that eliminating all difficult-to-
monitor valves in new units may substantially increase the costs of
constructing a new unit, for example, due to the necessity for
additional fixed ladders and platforms. Yet, 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 difficult-
to-monitor valves (Document No. IV-B-13).
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A refinery maintenance study (Document No. IV-A-3) 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 on these data and contacts with petroleum refinery design engineers
(Document No. IV-B-13) the final standards allow the owner or operator
of a newly constructed process unit to designate no more than 3 percent
of its valves as difficult-to-monitor. The standards require annual
monitoring of those valves. Limiting the percent 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:
Other commenters (IV-D-8, IV-D-21, and IV-D-24) wrote that it is
unreasonable to stand on any elevated object and reach overhead to
monitor for leaks because the practice is unsafe.
Response:
EPA does not believe that it is necessary to include a provision
for valves that require operators to "reach overhead." The standards
require operators to monitor valves and to repair leakers that can be
reached safely with or without the aid of a ladder. The practice of
reaching overhead to perform monitoring is not generally unsafe, and,
to the extent this can be unsafe, personnel should be provided proper
equipment (e.g., head and eye protection, ladders) and training as
required by the Occupational Safety and Health Administration and
refinery safety guidelines.
2.2.3.2 Unsafe-to-Monitor Valves
Comment:
Four commenters (IV-D-8, IV-D-15, IV-D-21, and IV-D-25) wrote that
unsafe valves should never be monitored because they are no less safe to
monitor annually -than monthly. These valves are only safe-to-monitor
when they are out of service, and it makes little sense to monitor
components not in service. One commenter (IV-D-24) wrote that the
proposed exemption of valves in unsafe locations, §60.5927(g)(2),
should have a qualifying statement added so that it reads "required
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monitoring of the valve as frequent as practicable during safe-to-monitor
times but not more than quarterly."
Response:
EPA agrees with the commenters that valves should never be
monitored during unsafe-to-monitor conditions, that is, during periods
of extreme temperature, pressure, or explosive process conditions that
make these areas off-limits to all personnel. Accordingly, the standards
do not require monitoring during unsafe periods. Valves that are
considered imsafe-to-tnonitor are not unsafe-to-monitor all the time.
Monitoring can conform to the requirements of the standards as much as
possible, but monitoring does not need to occur during unsafe conditions.
Valves that are routinely operated under safe conditions would be
subject to the routine monthly monitoring required by the standards.
Valves that are only safe-to-monitor once per quarter or year would be
subject to quarterly or annual monitoring, respectively. The standards
require an owner or operator to explain why a valve is unsafe-to-monitor
and to develop a plan to monitor the valve when it is safe, as often as
possible but not more than monthly. For valves that are safe-to-monitor
only when they are out of service (for example, during a process unit
shutdown), pressure testing such as is specified by API Standard 598 for
new valves could be part of an owner's or operator's monitoring plan.
The provisions for unsafe-to-monitor valves were included in the
proposed standards of performance for equipment leaks of VOC in the
Synthetic Organic Chemicals Manufacturing Industry (46 FR 1136,
January 5, 1981) because a few valves may be unsafe-to-monitor; the same
provisions were proposed in these refinery standards. EPA believes that
very few such valves exist in refineries.
Comment:
Another commenter (IV-D-16) requested that EPA delete the requirement
to demonstrate that valves are unsafe-to-monitor and the need for a
written plan for monitoring unsafe valves.
Response:
EPA is providing the exception for unsafe-to-monitor valves and
does not believe other valves should be allowed to use this exception.
Very few, if any, valves in a refinery would be considered unsafe-
to-monitor by EPA. Thus, a demonstration that particular valves are
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unsafe-to-monitor and a written plan for monitoring these valves is not
a significant burden upon owners or operators. These demonstrations
and plans are needed to ensure compliance with the intent of the standards,
which is use of best demonstrated technology, considering costs, on all
new sources.
2.2.3.3 Small Valves
Comment:
One commenter (IV-D-22) stated that small valves, in general, have
lower mass Emissions at 10,000 ppm than larger valves and suggested
that EPA provide a small valve exemption such as that in the State of
Texas. In a refinery as many as 50 percent of all valves are 2 inches
and smaller, and eliminating the monitoring requirement for these
valves would lessen the monitoring burden. Another commenter (IV-D-15)
wrote that a large number of the refinery valves are small valves
servicing instruments or control system bypasses and that the repair of
these small valves cannot be performed while in service. Hence, it was
recommended that the standards apply only to valves 3/4 inch size or
larger since repair costs for small valves is greater than for large
valves.
Response:
The first commenter's request for a small valve exemption is
predicated on his contention that small valves have lower emissions at
10,000 ppm than large valves. EPA contends, however, that the relation-
ship between valve size and mass emissions at 10,000 ppm is not relevant,
although the relationship for the average emissions per valve at or
greater than 10,000 ppm is relevant in assessing the need for a small
valve exemption. Nevertheless, the commenter's contention that valve
size relates to valve emissions is not supported in any test data. On
the contrary, EPA test data indicate that valve emissions are essentially
independent of valve size. An EPA study (Document No. II-A-19) found
only a slighly positive correlation between mass emissions from valves
and valve line size (correlation coefficients (r) equal to or less than
0.150). Also, data from facilities with existing leak detection and
repair programs, presented in Section C.I.3 of Appendix C, further demon-
strate that small valves account for a significant portion of leaking
valves. This data indicates that small valves (less than or equal to
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3.8 cm or 1.5 inches) represent nearly half the valves found leaking.
The commenter noted that the Texas State Implementation Plan exempts
all valves that are 2 inches or smaller; however, he failed to add that
the exemption is contingent upon demonstration that emissions would not
increase by more than 5 percent as. a result.
EPA agrees that some small valves may need to be replaced for repair,
but the cost of repair for these valves is reasonable. EPA has estimated
valve repair to require 1.13 labor hours based on 75 percent of all
valves being repaired on-line and in service with a repair time of 10
minutes, and 25 percent of the valves requiring off line repair requiring
4 hours per repair (BID for the proposed standards, Chapter 8). EPA
anticipates that most instrument valves are not in yOC service and
would therefore not be covered by the standards. However, if they are
in VOC service, small valves servicing instruments and control systems
are normally field repairable. Most repairs would consist simply of
replacing the stem packing ring. For valves in corrosive service, the
stem may be deteriorated to the extent that an entire stem assembly
(stem, packing, and stem tip seal) must be replaced. Repair time in
either case would be less than 30 minutes (Document No. IV-B-8).
Hence, small valves are no more expensive to repair than large valves.
The data presented and discussed in Section C.I.3 also indicate that :
small valves are as repairable on-line as large valves. For those
valves in critical service (i.e., those that cannot be isolated from
the process), the standards provide for delay of repair until a process
unit shutdown.
2.2.4 Monitoring Time
Comment. .
A number of commenters (IV-D-4, IV-D-15, IV-D-18) were concerned
with the EPA estimates of monitoring time. Two commenters (IV-D-4 and
IV-D-15) stated that monitoring would require 2 minutes per valve.
Another commenter (IV-D-18) reported that their experience found
that a two-man team averages one valve every 3 minutes, so that 160
valves could be monitored in one 8-hour day. This commenter also noted
problems with hiring part-time or full-time employees to conduct moni-
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toring for the alternative standards; with training personnel; and with
purchasing additional monitoring instruments.
Response:
The EPA monitoring time estimate of 1 minute per valve was taken
initially from information provided by Exxon Company, U.S.A. (Docket
No. II-D-22) based on an "in-depth study to determine the monitoring
manpower requirements." The average monitoring time for a leak detec-
tion survey for valves was found to be 1 minute per valve for a two-man
team (2 man-minutes). In another study conducted by Union Carbide
Corporation (Document No. II-I-57) an estimated 400 to 500 sources
(valves and other equipment) were screened per day. Although this
estimate was based on a three-man team, the third person was a unit
operator who provided process data. For a two-man monitoring team,
this corresponds to 1.9 to 2.4 man-minutes per source (0.95 to 1.2 man-
minutes per source per monitoring person). Information from other
studies, including EPA studies, shows that monitoring times are generally
less than 2 man-minutes. Phillips Petroleum Company conducted a study
(Document No. IV-B-10) of a petroleum refinery and petrochemical complex
in which 70,000 components were screened in about 936 manhours with a
two-man team. This represents an average of 0.8 man-minutes per component.
EPA also reviewed the results of recent California Air Resources Board
(CARB) inspections of refineries in the South Coast Air Quality Manage-
ment District (SCAQMD) and the Bay Area Air Quality Mangement District
(BAAQMD). The data (presented in Section C.I.6 of Appendix C), submitted
in part by one commenter (IV-D-31) and in part obtained from BAAQMD
and SCAQMD (Document No. II-B-18) revealed that monitoring time averaged
about 1 minute per valve for the more than 6,400 valves monitored in 12
refineries. In this effort, 2 monitoring instruments were used and
more information than required under the standard was recorded, such as
line size, time of monitoring, and valve type and function. Considering
these data, the time estimate of 1 man-minute per valve (2 man-minutes
per valve for a two-person team) used for costing purposes is reasonable.
In further reviewing the commenters's claim that EPA underestimated
the time required to monitor a valve, EPA examined the effect on the
cost effectiveness of monthly monitoring for valves assuming that twice
the monitoring time (2 minutes per source) is needed (Document No.
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IV-B-4). The results obtained from the LDAR Model show that monthly
monitoring would have a cost effectiveness of $42/Mg and an incremental
cost effectiveness from quarterly monitoring of $768/Mg. Hence, monthly
monitoring would, nevertheless, be reasonable even if 4 man-minutes per
valve were required.
The cost impacts presented in the background information document
for the proposed standards (Chapter 8) included the cost for two moni-
toring instruments per model unit plus $3,000 per year. (1980 dollars)
for instrument calibration and maintenance. Therefore, the cost of
additional monitoring instruments is accounted for in the cost impacts.
Furthermore, the actual monitoring instrument costs incurred by a
refinery may be less since monitoring instruments may be used for more
than one process unit. The cost impacts are based on 2 monitoring
instruments per process unit (affected facility). However, when there
are several affected facilities in a refinery, it is likely that the
refiner will not purchase two monitoring units for each of them.
Training plant personnel to use the monitoring instruments and
perform equipment monitoring is also considered in the cost analysis.
These costs are included as "Administrative and Support" costs
(40 percent of the total monitoring labor and maintenance labor costs).
Owners/operators may, however, choose to employ consultants to perform
equipment monitoring. Use of consulting firms would eliminate the need
to hire part-time or full-time employees for a short period of time (e.g.,
half a year), for example, if monitoring requirements are reduced
through use of the alternative standards for valves.
It is noteworthy to reiterate that promulgation of Method 21
(48 FR 37598) provides an alternative monitoring technique, soap screening.
Soap screening, although restricted to those valves with moderate
surface temperatures, may significantly lower the average monitoring
time. By soap screening valves, owners/operators will experience lower
costs for monitoring instrument maintenance. Further, the standards
provide for quarterly monitoring of valves which are found not leaking
for two consecutive inspections. Hence, monthly/quarterly, monitoring
will lower costs as a result of reduced monitoring labor requirements
and instrument wear.
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Comment:
Some commenters (IV-D-17, IV-D-18 and IV-D-25) contended that the
monthly monitoring requirements will not permit sufficient time for all
of the components in a unit to be monitored and repaired. One commenter
(IV-D-18) noted'that it would be impossible for one two-man crew to
complete all inspection work, process work orders, and complete record-
keeping requirements within the one-month time frame.
Another commenter (IV-D-25) offered the example of a facility
having about 14,000 components to be monitored. Based on a crew moni-
toring 200 components per day, it would take 24 days for three crews to
check the components (not including the time for repairs and rechecks).
Response;
The basis for the EPA time estimate for performing leak detection
and repair is found in Table 8-3 of the BID for the proposed standards.
An average (for valves, pumps, and pressure relief devices) monitoring
time requirement per component can be estimated based upon the component
distribution for Model Plant B, as shown in Table 2-6. The resulting
average component monitoring requirement is about 2.3 man-minutes.
Based on this estimate, a two-man monitoring team can inspect about
420 components in an 8-hour day. Hence, a single two-man monitoring
team can inspect a Model Unit A in about 1 day, Model Unit B in 2 days,
and Model Unit C in 5 days. Actual industry and EPA testing (Document
No. II-A-41) has demonstrated that a two-man monitoring team can inspect
between 400 and 500 components per day.
Table 2-6. Derivation of Average Component Monitoring Time
Component
type
Valves
Pumps
Relief valves
Number of
components
760
14
7
Time to
monitor
(min.)
1
5
8
Persons
2
2
2
Total
time
(man-mi n.)
1520
140
112
Total
781 1772
Average =2.3 man-minutes per component.
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EPA believes that a month provides more than enough time to complete
leak detection and repair of an affected facility. As previously
pointed out, even a large process unit, Model Unit C, can be monitored
within a week by a single monitoring team, allowing three weeks to
complete repairs, rechecks, process work orders, and recordkeeping
within the one-month period. There are several other factors that also
indicate that a month permits sufficient time to comply with the leak
detection and repair requirements: (1) repairs are commenced concurrent
with the onset of monitoring as specified in the repair requirements;
(2) more than one monitoring team may be employed to perform the inspec-
tions; and (3) the use of soap screening may reduce the monitoring time
required. In addition, since the standards for valves allow quarterly
monitoring of valves not found leaking for 2 consecutive monthly
inspections, most valves are likely to be monitored on a quarterly
basis.
EPA recognizes that it is possible for individual facilities to
expend less time monitoring than the EPA estimate of two man-minutes
per valve, as discussed above, and possible to expend more time monitoring
as the commenters imply. Nevertheless, EPA maintains that the basis
for estimating labor hour requirements as presented in the BID for the
proposed standards appropriately reflect the monitoring requirements
for the petroleum refining industry. Hence, EPA believes that sufficient
time is allowed in the period of one month to complete the leak detection
and repair requirements.
2.2.5 Repair
Comment;
Several commenters wrote that the 5 and 15 day repair intervals
should be extended. Some (IV-D-8 and IV-D-15) argued that an initial
attempt at repair within 5 days should be extended because of holidays
and weekends. Others (IV-D-5, IV-D-12, IV-D-16, IV-D-17, and IV-D-24)
thought that the 5-day requirement was unnecessary provided repair was
accomplished within 15 days. Another commenter (IV-D-18) requested
that the repair intervals be extended to 15 days for initial repair and
30 days for final repair.
Conversely, another commenter (IV-D-30) contended that the first
attempt at repair for valves and pumps should be made within 24 hours
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instead of 5 days. The commenter wrote that repair personnel should
either accompany or trail the monitoring personnel and, therefore, the
minor repairs (e.g., tightening a valve bonnet) could be completed (and
rechecked) immediately.
Response:
The standards require that a first attempt at repairing a leaking
valve or pump should be accomplished as soon as practicable but no
later than 5 days after detection of a leak. Attempting to repair the
leak within 5 days will help maintenance personnel identify the leaks
which can be repaired without shutdown of the process unit. Valves or
pumps 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 leaking valves that require more
than simple field repair. The 15 days provides sufficient time to sche-
dule and effect on-line repairs that a shorter period might not allow.
Provisions have been made for delaying repair of those valves which are
in critical service and cannot be bypassed. The two repair period
requirements provide efficient reduction of emissions and allow suffi-
cient time for flexibility in scheduling repairs of leaking equipment.
A single period would simply permit delays in repairs that could
otherwise be accomplished quickly.
Most valve repairs can be done quickly. This is evident from
compliance experience of refineries with the South Coast Air Quality
Management District Rule (Rule 466.1) for valves which requires repair
within 2 working days. A 5-day period for initial attempts provides
sufficient time to schedule field repair. Originally, EPA was considering
a 3-day limit, but decided to increase the limit to 5 days to allow for
holidays and weekends.
Requiring an initial attempt at repair within a shorter time
period (e.g., 24 hours as suggested by one commenter) may, however,
pose a significant problem to owners. With shorter repair periods, a
repair crew would have to accompany or closely follow a monitoring
crew, repairing leakers as they are detected in order to perform all
initial attempts at repair within the required time interval. Although
this is a repair technique often employed, some repairs cannot be
performed as described in the comment. For example, a pump seal that
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is. leaking may not be repairable while the pump is in operation due to
casings which must be removed or safety hazards due to the shaft motion.
In other instances, parts (such as a valve bonnet pressure plate) may
be cracked and require replacement, making "on-the-spot" repair attempts
impossible. In addition, shorter time periods may increase the cost
of leak detection and repair. Because very few valves leak (about
10 percent initially and about 2 percent leaking per month in subsequent
inspections), repair crews may spend much of the time on an inspection
with few repairs to perform if they were to accompany the monitoring
personnel. The logistics of coordinating monitoring and repair is
further complicated when considering union regulations that may apply
and that certain repairs require specially trained personnel to perform
(e.g., control valves). EPA considers 5 days to be a reasonable time
constraint for first repair attempts on leaking valves or pumps.
Comment:
One commenter (IV-D-30) indicated that EPA chose the 10,000 ppm
leak definition because undirected repair attempts for leaks less than
10,000 ppm would lead to an increase in emissions. The commenter
claimed that lowering the 10,000 ppm leak definition and requiring a
directed repair program would not significantly increase the cost
impacts of the standards and would produce a substantial reduction in
emissions.
Response:
The "leak definition" is the instrument reading observed during
monitoring that defines which sources require repair. The best leak
definition would be the one that achieved the most emission reduction
at reasonable costs. At a leak definition of 10,000 ppm, approximately
90 percent of the mass emissions from valves would be detected. EPA
has determined (Document Nos. II-A-21, II-A-26 and II-A-42) that valves
found leaking at levels of 10,000 ppm or greater can be brought to
levels below 10,000 ppm with proper maintenance. A leak definition
lower than 10,000 ppm may be practicable in a 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.
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The commenter suggested that EPA require directed repair, whereby
the tightening of packing is monitored simultaneously and continued
until no further reduction of leak is observed from the valve. However,
there is no evidence to support the commenters contention that directed
maintenance will provide greater emission reductions than the requirements
of the standards. The standards require owners/operators to continue to
attempt repair if the initial attempt to repair a leaker fails to reduce
emissions below 10,000 ppm. The standards require monitoring of a
valve following attempted repair to determine if the repair attempt was
successful. EPA also believes that requiring directed repair could be
too costly. Directed repair may unreasonably complicate coordination
of monitoring and repair personnel, especially in refineries where
repair personnel are governed by union regulations.
Upon reviewing the. comments, EPA has maintained the 10,000 ppm
leak definition because it would address approximately 90 percent of
the VOC emissions from valves at reasonable costs and reasonable cost
effectiveness. Also, the final standards for valve repair remain
unchanged from proposal in requiring the best practices, including
monitoring following repair, because directed repair has not been
demonstrated to be more effective in emission reduction and may have
higher costs.
Comment;
One commenter (IV-D-30) was concerned that plant owners or operators
may abuse the delay of repair provision that can be used when stocks of
spare valves have been depleted. The commenter stated that this provision
invites operators to maintain very small inventories of spare parts. A
better approach suggested by the commenter is to require the operators
to maintain sufficient stocks, and the inventory required should be
readily determinable after monitoring several times.
Response:
The commenter appears to misinterpret the intent of the delay of
repair provision. The standards require that owners or operators must
show that valve assembly supplies had been sufficiently stocked before
the supplies were depleted. This includes custom-order and unique parts,
as well, to avoid delays of repair due to unavailability of parts.
Despite what the commenter says, the provision does not invite operators
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to maintain small inventories of spare parts. Plant experience with
delays will be considered if delay was reasonable.
2.3 PUMPS
2.3.1 Basis for Standards
Comment:
One commenter (IV-D-4) recommended that the EPA decrease the
monitoring frequency for pumps based on the lower percentage of pumps
found leaking during a recent refinery inspection. The commenter also
suggested a skip-period alternative for pumps.
Response:
The basis of the standards for pumps is monthly leak detection and
repair. One month provides the most effective leak .detection and repair
program for pumps, reducing emissions from a Model Unit B by 11.5 Mg
per year, without imposing difficulties or unreasonable costs in
implementing the program. EPA has determined (Document No. IV-B-2)
that monthly monitoring has reasonable cost effectiveness, $158/Mg, and
incremental cost effectiveness, $170/Mg between quarterly and
monthly monitoring.
EPA data collected during screening studies on pump seals represent
plants with and without existing control programs. EPA data represent
pumps found in refineries throughout the nation. No data were submitted
by the commenter to substantiate the contention that some pumps have
distinctly lower leak frequencies. There may be many reasons that the
lower leak frequency was found in his plant. One reason may be that a
control program was recently implemented.
Skip-period monitoring for pumps has not been included in the
standards for two reasons. The first is that pump seal failures are
sudden events independent of prior leak history. Valve leaks (where
skip-period monitoring has been used), in contrast, gradually increase
over time, so that leak history is a factor in the leak status of any
one valve. A skip-period monitoring program for valves achieves
emissions reduction because the number of valves leaking gradually
(and very slowly for process units that can use this alternative)
increases over the monitoring period. However, skip-period monitoring
for pumps would allow large emitters to leak for a long period of time
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because pump seals begin to leak suddenly. Secondly, the number of
pump seals that must be monitored is not. large enough to develop a
meaningful statistical program. For example, a large process unit
(Model Unit C) would only have about 40 pump seals in light liquid
service. Hence, an allowable percentage of pumps leaking, for example
2.0 percent, would not even allow a single pump leaking. EPA has
provided other alternatives to monthly monitoring, which include
(1) installation of a properly designed dual mechanical seal as specified
in Section 60.592(d), (2) installation of an enclosed capture/conveyance/
control system as described in Section 60.592(f), and (3) use of leakless
equipment as provided in Section 60.592(c).
Since proposal, the cost basis of leak detection and repair programs
for pump seals has been revised to assess pump repair on a consistent
basis with information presented in the AID (Document No. II-A-41). In
the proposal BID, pump seal repair costs are based on 80 labor hours
per pump seal repair. This basis has been revised to 16 labor hours
per seal repair plus the cost of a replacement seal ($140/seal, May 1980
dollars). The cost effectiveness which appears in the preamble for the
proposed standards has been revised to $158/Mg VOC emission reduction
(Document No. IV-B-2). EPA believes the revised cost effectiveness for
pumps is reasonable.
Comment:
Two commenters requested that there be exemptions for pumps. One
of these commenters (IV-D-8) indicated that "some pumps may not be able
to accommodate dual seals. Accordingly, the standards should provide
exemptions from the requirement to install dual seals if 1) dual seals
cannot be retrofitted to the existing pump, i.e., the pump would have
to be replaced to install dual seals; and 2) if a compatible barrier
fluid cannot be found." The other commenter (IV-D-12) indicated that
certain reciprocating pumps should be exempt due to the prohibitive
cost of bringing-reconstructed reciprocating pumps into compliance.
Also, if an owner or operator installs a dual seal, that pump should be
exempt from routine monitoring.
Response:
EPA recognizes that some pumps may not be readily retrofitted with
dual mechanical seals, although circumstances where a dual mechanical
seal cannot be retrofitted without replacing the entire pump are rare.
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An exemption for these few pumps is necessary. The standards do not
require dual mechanical seals, but only require satisfactory performance
under the leak detection and repair program. Leak levels below 10,000
ppm organic concentration at the surface (which remains,the only require-
ment for pumps) may be obtained by replacing the original seal or the
original seal packing. Should these measures fail to reduce the leak
rate to an acceptable level (an intrument reading of less .that 10,000
ppm), the seal area may be enclosed, and the enclosure vented to a
control device.
Availability of compatible barrier fluids should rarely pose a
problem. As discussed in the BID for the proposed standards (pp 3-4
through 3-6) dual mechanical seals may be arranged in either of two
configurations, back-to-back or tandem. The tandem arrangement utilizes
a barrier fluid pressure lower than the process fluid pressure at the
pump seal, such that any leakage at the primary pump seal results in a
leakage of process fluid into the barrier fluid. Such a sealing arrange-
ment will prevent contamination of the process fluid by the barrier
fluid. The barrier fluid must be purged, however, to a controlled
degassing reservoir to prevent the leaked process fluid from eventually
being emitted to the atmosphere. In the back-to-back arrangement the
two seals provide a closed cavity between them and a barrier fluid is
circulated through the cavity at an operating pressure greater than the
stuffing box. Barrier fluid leaking across the primary pump seal will
enter the stuffing box and mix with the process fluid. Barrier fluid
going across the secondary seal would release to atmosphere unless
captured by a vent control system.
Reciprocating pumps may also be maintained in compliance with the
leak detection and repair program requirements. EPA recognizes, however,
that maintaining adequate sealing for less than 10,000 ppm organics
concentration around linear motion shafts may be difficult. However,
the seal area (or distance piece) of such pumps may be enclosed, and
the enclosure vented to a control device. As such, an exmption for
these pumps is not necessary. The commenter provided no information or
data to support the statement that costs of compliance for reciprocating
pumps is prohibitive.
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If an owner or operator chooses to utilize an alternative control
technique for pumps such as dual seals or enclosed and vented seal
areas rather than monthly monitoring, these pumps are exempt from the
routine instrument monitoring. However, several criteria would need to
be met for these alternative controls such as weekly visual inspections,
continuous monitoring of the barrier fluid system for seal failure
detection, and daily barrier fluid level checks. These are required to
ensure the integrity of the alternative control system and to remain
exempt from monthly monitoring. In order to clarify the intent of this
requirement, the final regulation will include a definition for
"stuffing box pressure" as "the pumped product pressure at the primary
seal interface."
Comment:
One commenter (IV-D-14) expressed concern that the alternative
standards for pumps "are essentially a barrier fluid standard because
in the dual seal system, one mechanical seal is still exposed to the
atmosphere, as is the case with a single mechanical seal. But requiring
a dual seal system rather than defining the standard as the use of a
non-VOC barrier fluid on the seal exposed to atmosphere, precludes the
use of a single mechanical seal with the same barrier fluid even
though the two are equivalent from the standpoint of emissions."
The same commenter suggested that EPA simply establish a no detectable
emissions limit for the barrier fluid system.
Response:
The commenter appears to be requesting an exemption from the
routine leak detection and repair program for single seal pumps with
non-VOC barrier fluids. EPA does not have enough information to use in
evaluating such an approach, and the commenter did not suggest a means
of ensuring continued compliance with the standards such as the barrier
fluid requirements of the proposed standards. EPA does not know how to
do this either. For these reasons, single seal/barrier fluid systems
are not exempt from the standards.
The standards, however, allow owners or operators to use equivalent
means of emission limitation as provided for in Section 60.484. An
owner or operator subject to the standards may apply to the EPA for
determination of equivalence for any means of emission limitation that
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achieves a reduction in emissions of VOC at least equivalent to the
reduction in emissions of VOC achieved by the controls required by the
standards. Each owner or operator applying for an equivalence determination
is responsible for collecting and verifying test data to demonstrate
equivalence.
EPA did not require a "no detectable emissions" limit for pump
seals because with the control technique specified (monthly leak detection
and repair) as the basis for the standards, pumps can still leak.
Several types of pumps with auxiliary equipment (e.g., dual mechanical
seals that utilize a barrier, fluid system, and enclosure of the pump
seal area), however, can achieve emission reductions of VOC at least
equivalent to that achieved by a monthly leak detection and repair
program for pumps provided that they are operated under certain conditions.
Seal less pumps do not have a potential leak area and, therefore, are at
least equivalent to monthly leak detection and repair and dual seal
systems. As with other leakless equipment, seal less pumps would be
subject to an initial performance test (using procedures specified in
Reference Method 21) to verify that the piece of leakless equipment
meets the "no detectable emissions" limit, and annual rechecks to
ensure continued operation with "no detectable emissions."
Comment:
One commenter (IV-D-21) questioned Section 60.592.2(d)(i) that
he said creates the requirement that barrier fluid be at a higher
pressure than the stuffing box. The commenter said that this, requirement
is impossible because the "barrier fluid pressure is the stuffing box
pressure."
Response:
As discussed in Chapters 3 and 4 of the BID for the proposed
standards, dual mechanical seals consist of two seal elements with a
barrier fluid between them. By pressurizing the barrier fluid to a
pressure greater than the process pressure, any leakage in the primary
seal would result in the leakage of barrier fluid into the process,
while any leakage in the secondary (outer) seal would result in leakage
of barrier fluid to the atmosphere. Provided a non-VOC barrier fluid
is used, no VOC leakage to the atmosphere can occur.
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The intent of §60.592-2(d)(l)(i) is that the barrier fluid be
maintained at a higher pressure than the pumped product as discussed.
above. Where dual mechanical seals are used, several pressures are
associated with the stuffing box, including the pumped product, the
barrier fluid pressure, and the atmospheric pressure on the outside of
secondary seal. Originally EPA intended to require that the barrier
fluid be maintained at a pressure higher than the pumped product outlet
pressure. However, the pressure of the pumped product at the primary
seal face (i.e., at the stuffing box) may be different from the outlet
pressure. As such, EPA decided to clarify the requirement by requiring
that the barrier fluid pressure be greater than the pressure of the
pumped product at the stuffing box. The terminology used by the EPA has
led to the commenter's confusion. To clarify the requirement, in
response to this comment, EPA will add a definition of "stuffing box
pressure" to the final standards to indicate that the stuffing box
pressure, for purposes of the standards, is the pressure of the product
at the primary seal face.
2.3.2 Monitoring
Comment:
Two commenters (IV-D-8 and IV-D-21) wrote that the criteria for
visual pump inspections should be revised. One commenter (IV-D-21) stated
that liquid leakage from pumps should be defined in a more quantitative
manner. The commenter suggested that the criteria be three drops per
minute rather than the subjective "indications." Another commenter
(IV-D-8) maintained that monitoring with an analyzer should be the sole
criteria for determining a leak. In contrast, another commenter
(IV-D-24) thought that monitoring of pumps is excessive and unnecessary
because emission concentrations measured with a portable analyzer are
erratic for mechanical seals. The commenter held that visual checks
alone were an adequate means of detecting leakers.
Response;
The purpose of visual inspections of pump seals and barrier fluid
systems is to detect leaks. Liquids dripping from the seal area indicate
seal wear and may signal the beginning of seal failure or actual failure
of the barrier fluid system. To prevent excessive wear that could
possibly result in catastrophic seal failure, the seal should be repaired
2-40
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soon after leakage is detected. Visual inspections detect the leaks
associated with such failures of seal systems. Therefore, any visible
leakage from the seal area is considered a leak. A more quantitative
approach, "such as three drops per minute," would be no more indicative
of a leak than the approach proposed by EPA. However, to define better
what EPA considers "liquids dripping," a definition has been added to
the standards. "Liquids dripping" means any visible leakage from the
seal including spraying, misting, clouding, and ice formation.
The results of the Western Oil and Gas Association (WOGA) testing
of petroleum refining industry pumps (Document No. II-A-42) have shown
that 44 percent of light liquid service pumps found exceeding the
10,000 ppm action level also had liquid leaks that were visually detected.
Hence, visual inspections do find a significant proportion of "leakers"
and are an effective supplement to instrument monitoring. However,
large quantities of VOC can be emitted from leaking pump seals even
when there is no visual indication of leakage. Large leaks can occur
without forming liquid drops or obvious indications of liquids dripping.
For example, emissions may be sprayed as a fine mist, vaporize, or may
condense as ice. Thus, pumps require a more precise measurement method
(i.e., the use of a monitoring instrument) to determine if emissions
are equal to or greater than 10,000 ppm.
There is a relatively high degree of certainty whether a pump seal
has an organics concentration at greater than or less than 10,000 ppm
using Reference Method 21. Pump seal failures are usually sudden (not
a deterioration effect), such that emission concentrations are either
well above or below the 10,000 ppm leak definition for pump seals.
Further, no data were provided by the commenters to support the contention
that instrument measurements are erratic for pump seals. Hence, EPA
maintains that instrument monitoring is effective and necessary to
identify leaking pump seals.
2.3.3 Repai rs
Comment:
Several commenters expressed concern about the repair of pump
seals. Two commenters (IV-D-8 and IV-D-14) were concerned that a high
portion of pump seals continue to leak in excess of 10,000 ppmv following
attempted repair. Two commenters recalled that in the WOGA study
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(Document No. II-A-42), the previously referenced industry pump seal
testing, 40 percent of the pumps continued to leak after attempted
repair, whereas, the cost effectiveness of the control technique is
based on the presumption of 100 percent successful repair. Some
commenters (IV-D-8, IV-D-15, and IV-D-18) requested that the regulations
allow delay of repair for pump seals. One commenter noted that more
than 6 months (as allowed in the proposed standards) is sometimes
needed to retrofit dual seals. Also, delay beyond unit shutdowns
should be allowed for pumps if there is a delay in equipment delivery.
Response:
Pump seal manufacturers have indicated (Document No. IV-E-4) that
their emissions testing shows 10,000 ppm to be a proper leak definition
criteria and that properly installed and operated seals should easily
meet it. However, EPA recognized before the standards were proposed
that repairing pump seals to achieve VOC emission concentrations to
below 10,000 ppm may be difficult in some instances. The specific
reference to the WOGA study (Document No. II-A-42), that "40 percent of
the pumps repaired continued to leak", does not necessarily apply to
the standards for pumps. Pumps with new seals, especially seals of
harder material, may have a run-in time of up to 48 hours of operation
to seat properly (Document No. IV-B-17). There is no evidence given in
the WOGA study to indicate that some of the pump seals that continued
to leak following repair were not monitored within the run-in period.
Seal replacement may in fact have been a much more successful means of
repairs, and reported as such, if pump rechecks were measured after the
run-in period. Also, in this study, pump seal repair was not always seal
replacement (e.g., tightening of seal packing), whereas the EPA cost
analysis was based on seal replacement.
EPA analyzed control techniques for pumps that might not be
repairable to below 10,000 ppm. The cost effectiveness of installing a
dual mechanical seal with a barrier fluid system was examined for pump
seals that (1) are known to be leaking and (2) cannot be repaired by
relatively simple procedures (such as replacing a seal). Based on
this, EPA found the cost effectiveness of installing dual seals to
reduce pump emissions to be reasonable (Document No. IV-B-5). EPA
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expects the use of dual seal systems to comply with the repair require-
ments of the proposed standards. However, because retrofitting these
systems cannot be completed in 15 days, EPA provided 6 months to complete
the repair. Owners and operators also have the option of enclosing the
pump seal and venting the emissions to a control device.
In response to the second group of commenters, EPA recognizes the
need for delay of repair if the repair necessitates process unit shutdown*
However, delay of repair for pumps beyond unit shutdown is not necessary
because the plant owner or operator can stock (without unreasonable costs)
enough spare seals and seal parts for repair to prevent shortage of
seal parts due to a delay in equipment delivery. EPA proposed to allow
delay of repair beyond shutdown for valves that require replacement of
the entire valve assembly _vf the owner or operator shows that a sufficient
stock of these assemblies had been maintained before the stock was
depleted. However, there are substantially fewer pumps in process
units than valves, so stocking spare seals is not unreasonable. In
addition, most refineries have a spare pump in place that can be operated
while the leaking pump is being repaired so it is not clear why many
repairs.would ever need to be delayed to a process unit shutdown. EPA,
therefore, does not consider it necessary to incorporate the delay of
repair provision into the final standards for pumps.
Commenters were concerned that they would not be able to retrofit
dual mechanical seal systems within the required 6-month period (Section
60.592-2(c)(3)) for leaking pumps that cannot be repaired to achieve ;,
emission concentrations below 10,000 ppm. However, pump seal manufac-
turers (IV-E-6 and IV-E-8) have indicated that the 6-month requirement
to retrofit a dual mechanical seal system is reasonable. Most dual
mechanical seals can be shipped from the manufacturer the day they are
ordered, and, in the event of an unusual or special order, dual seal
systems can be manufactured in 16 to 18 weeks. Twenty-four weeks (6
months) would allow for engineering and installation. A refinery may
have some difficulty with installing more than 10 dual seal systems in
a given 6-month period. However, EPA does not expect that more than 10
dual seals will be installed in a single process unit during a given
six-month period. Thus, EPA considers the decision to allow owners or
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operators to delay repair of pumps up to 6 months reasonable if a dual
seal system must be used.
2.4 COMPRESSORS
Comment;
One commenter (IV-D-12) commended EPA for providing exemptions for
existing reciprocating compressors.
Response;
EPA did not provide a blanket exemption for existing compressors in
the proposed standards as the commenter implied even though EPA discussed
that certain reciprocating compressors might not be covered under the
reconstruction provisions if retrofitting the required equipment was
technologically or economically infeasible (see 40 CFR 60.15(e)). To
make EPA's intent clear and to reduce the burden of reviewing recon-
struction determinations, EPA is explicitly exempting existing recipro-
cating compressors provided the owner or operator demonstrates that
recasting the distance piece or replacing the compressor are the only
options available to bring the compressor into compliance. This exemption
is necessary because the cost impact of installing the required control
equipment or replacing the compressor is unreasonable. These compressors
will be exempt from the standards until they are replaced by new compressors
or the distance pieces are replaced.
Comment:
Another commenter (IV-D-30) was concerned that a case-by-case
determination of the feasibility of putting controls on reconstructed
reciprocating compressors would be burdensome to EPA or the States and
would probably result in a blanket exemption. The commenter requested
that EPA reexamine whether a specific definition of the compressors that
are appropriate to exempt can be written in lieu of the case-by-case
determination.
Response:
It is impossible to fully define all applications of reconstruction
considered for existing reciprocating compressors. EPA maintains,
however, that the determination of technological or economic feasibility
(or infeasibility) to meet the standards would not be burdensome for
EPA (or State agencies delegated enforcement authority), considering
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the few compressors that might fit into this exemption. The exemption
applies only to those specific instances where the seal area cannot be
enclosed and vented without recasting the distance piece or replacing
the compressor.
EPA has evaluated (Document No. IV-B-20) means of controlling
compressor leaks that may comply with the standards for compressors at
reasonable cost. Based on the availability of reasonable.control
options, EPA does not believe that the provisions for reciprocating
compressors'wi11 result in a blanket exemption of all such compressors.
Comment:
A commenter (IV-D-14) argued that the standards for compressors
do not provide an incentive to improve existing control technology.
Another commenter (IV-D-8) wrote that "there is no justification for
establishing a separate and arbitrary definition of leak for compressors,"
thus EPA should use the 10,000 ppm leak definition. Other commenters
(IV-D-14 and IV-D-16) asked EPA to allow quarterly monitoring as in the
refinery CTG (Document No. II-A-6).
Response:
The standards for compressors do not deter the incentive to
^improve existing control technology. Refiners have the option of
employing mechanical seals with barrier fluid systems and controlled
degassing vents or may alternatively enclose the seal area and vent the
captured emissions to a control device. These are generally the only
techniques available to reduce VOC emissions from compressor seals. In
addition, the standards provide additional flexibility and incentive to
improve upon existing technology through the provisions of Section
60.592-3(i) that allow an automatic equivalence for no detectable
emissions. Furthermore, an owner or operator may apply equipment or
procedures that achieve a reduction in VOC emissions at least equivalent
to the reductions achieved by the compressor control requirements.
The standards for compressors require the use of mechanical seals
with barrier fluid systems and controlled degassing vents. Leakless
equipment is allowed as an alternative to the mechanical seal system.
Leakless equipment is considered at least equivalent to mechanical
seals if they can be shown to have no emissions. Method 21 defines no
emissions, or "no detectable emissions," as a minimal deflection of the
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portable instrument meter. In the case of the proposed standards, this
is a reading of 500 ppm or less. Hence, the 500 ppm is not a leak
definition as misconstrued by the commenter, but an instrument limited
definition of no detectable emissions as specified in Reference
Method 21.
Quarterly monitoring is not allowed under the standards because it
would achieve significantly less emission reductions than the mechanical
seal system, other leakless control, or enclosure and venting to a
control device. Even as noted in the refinery CTG published in June
1978 (Document No. II-A-6), EPA has concluded that a leak detection and
repair program for compressors in refineries is generally not an effec-
tive control technique and, therefore, EPA did not consider it a viable
option as the basis for the standards. Quarterly monitoring was recom-
mended in the refinery.CTG due to the limitations of retrofitting
equipment controls on existing compressors. The effectiveness of a
leak detection and repair program for compressors is limited because
repair of leaks for most compressors could not be accomplished without
a process unit shutdown and because some seals must leak to operate
properly. Because shutdowns generally occur infrequently, limiting the
emission reduction obtained from maintenance, and because repair of a
compressor seal would often involve the use of mechanical seal systems
or enclosure and venting to a control device, equipment controls are
used as the basis for the standards. These equipment controls have a
reasonable cost effectiveness (see preamble for the proposed standards,
Table 1).
2.5 PRESSURE RELIEF DEVICES
Comment:
One commenter (IV-D-19) was concerned that the costs for rupture
disks are overestimated in the BID for the proposed standards. The
commenter said: (1) EPA costs are based on relief valves with the
rupture disk offset under it; this practice and cost is not necessary
and violates recommended industry codes; (2) the added cost for retro-
fitting a disk and valve is only valid for half of the field installations
because the downrating of a valve as an ASME requirement is only mandatory
for. new installations and is not required for retrofit installations;
and (3) in a recent API survey, half of the companies responded that
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they already use block valves under relief valves; therefore, the block
valve really should not be included in the cost of installing a rupture
disk under a relief valve. Another commenter (IV-D-12) disagreed with
EPA's decision to require rupture disks for pressure relief valves.
The commenter thought the incremental cost of $930 per megagram emission
reduction from quarterly leak detection and repair to the use of rupture
disks was unreasonable. The commenter recommended quarterly leak
detection and repair as an alternative control for pressure relief
valves.
Other commenters remarked concerning disk sizing. One commenter
(IV-D-14) urged EPA to consider a case-by-case standard for pressure
relief devices because problems in sizing spool and .piping are likely
to arise as a result of added pressure drop in retrofit installations.
Another commenter (IV-D-19) in contrast wrote that most rupture disks
manufactured have flow coefficients (0.95 and higher) compatible with
relief valves manufactured, so that it is becoming common practice not
to downrate relief valves upon retrofitting rupture disks. :
Response:
The basis of the standards selected for pressure relief devices in
gas service is the use of rupture disks. Rupture disks eliminate
fugitive emissions of VOC through the relief device unless an overpressure
occurs. After an overpressure release, replacement of the rupture disk
once again eliminates fugitive emissions of VOC through the pressure
relief device. Therefore, a "no detectable emissions" standard was
selected for pressure relief devices. The proposed standards for
pressure relief devices require that they be operated with no detectable
emissions as indicated by an instrument reading of less than 500 ppm
above background and that they return to this condition within 5 days
following pressure release.
At proposal, EPA considered the incremental cost effectiveness ,
between quarterly monitoring (required by State implementation plans)
and rupture disks (see preamble for the proposed standards, Table 1)
and determined that the resulting value, $930/Mg VOC, was reasonable.
The commenter disagreeing with the reasonableness of this incremental
cost effectiveness has offered no specific information suggesting that
this cost effectiveness level is unreasonable.
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In reviewing the public comments, EPA re-evaluated (Document No.
IV-B-2) the cost effectiveness and incremental cost effectiveness of
different levels of control (quarterly and monthly leak detection and
repair and the use of rupture disks) for pressure relief devices as
shown in Table A-2 of Appendix A. The cost effectiveness for quarterly
and monthly leak detection and repair was estimated to result in savings
of $170/Mg VOC and $110/Mg VOC, respectively. The use of rupture disks
has a cost effectiveness of about $410/Mg VOC. The incremental cost
effectiveness between quarterly and monthly leak detection and repair
is about $250/Mg VOC. The incremental cost effectiveness between
monthly leak detection and repair and rupture disks is about $l,000/Mg
VOC.
' At proposal, EPA cost estimates were based on rupture disks with
offset mounting to prevent damage to the relief valve by disk fragments
as stated in the BID for the proposed standards, Table 8-1. EPA
recognizes that the offset mounting may not be necessary, and that it
could present a safety problem if it added significant pressure drop to
the system. In these cases, EPA agrees that an offset mounting would
not or should not be used. However, since owners or operators might
use the rupture disks with offset mounting, EPA did not revise the basis
for the rupture disk system costs, realizing that the estimated costs
to comply with the standards may be overestimated.
The first commenter was also concerned that block valves should
not be included in the cost analysis because they are already installed
in half the refineries surveyed by API. Even though the use of block
valves may already be widespread, EPA expects that some refiners would
use them in the absence of the standards, and, therefore, EPA decided
to continue to include them in the cost analysis. This will result in
an overestimate of the nationwide cost impact of the standards for
pressure relief devices.
Sizing problems in retrofitting rupture disks can be avoided
through the selection of compatible disks and disk holders; therefore,
there is no reason to establish special requirements for pressure
relief devices in process units affected through modification or
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reconstruction. In addition, refiners have the option of venting
pressure relief valve emissions to a VOC control device, such as a
flare.
Comment:
Two commenters (IV-D-8 and IV-D-21) stated that rupture disks
should not be used as the basis for judging the leak rate of pressure
relief valves because rupture disks are not common in the.industry as
mentioned in the BID for the proposed standards.
Response:
EPA is required to establish new source performance standards
based upon best demonstrated technology (BDT), not common technology.
EPA has determined that rupture disks represent BDT for pressure relief
devices.
The standards for pressure relief devices are based on the use of
rupture disks. Because rupture disks eliminate emissions, EPA selected
a performance standard of "no detectable emissions."
Comment:
Commenters (IV-D-5, IV-D-8, and IV-D-18) were concerned with the
safety of the standards for pressure relief devices. Monitoring pressure
relief devices is inherently unsafe. In addition, these components are
frequently difficult-to-monitor. The practice of employing rupture disks
is unsafe due to the pressure build-up between the disk and relief device.
Response:
Refineries routinely inspect pressure relief devices approximately
on an annual basis as a part of normal safety and maintenance procedures
to ensure the set pressure is correct (Document No. II-D-22); therefore,
the standards are not requiring refineries to do a new task. The
standards implicitly require performance tests using Method 21 to
verify that the device is maintained at no detectable emissions. This
test is similar to testing done by EPA and EPA contractors in collecting
data for development of the standards and similar to testing required
by States under implementation plans. This test could be scheduled
during periodic inspections of pressure relief devices, which are
typical of many industry safety practices. Monitoring should be done
by personnel who understand the precautions needed when monitoring
pressure relief devices. Evidence that operators can safely monitor
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pressure relief devices is further indicated by one refiner's (Document
No. IV-D-33) practice of removing pressure relief devices (for repair/
replacement and testing) following overpressure releases. Based on
this information and EPA's experience in collecting data for pressure
relief devices, monitoring of these devices can be done safely.
The standards for pressure relief devices are based on the use of
rupture disks; however, the standards do not require their use. Alter-
natively, pressure relief device emissions can be routed to a VOC control
device, such as a flare. If a rupture disk is used, a pressure sensor
should be installed to warn operators if a pressure increase has
occurred between the disk and relief valve. The cost of a such a
sensor (0.6 cm pressure gauge) has been included in the cost analysis
that is presented in the BID for the proposed standards, Chapter 8,
Table 8-1. .
Comment;
Two commenters (IV-D-8 and IV-D-21) disagreed with the leak definition
for pressure relief devices stating that there is no justification for
a different leak definition than 10,000 ppm.
Response:
The standards for pressure relief devices are based on the use of
certain equipment. This equipment, as explained in the preamble to the
proposed standards, results in no detectable emissions. The no detectable
emissions limit is 500 ppm according to Method 21 and is related to
monitoring instrument capabilities. The 10,000 ppm leak definition for
pumps and valves was chosen based on different considerations and is
unrelated to standards that require no detectable emissions, such as
the standards for pressure relief devices. A 10,000 ppm or greater
concentration indicates a pump seal failure or deterioration of a
valve packing, and concentrations below 10,000 ppm are allowed. The no
detectable emissions level (500 ppm) indicates no emissions.
Comment:
Another commenter (IV-D-21) requested the addition of a qualifying
phrase to the standards, Section 60.592-4(b), such that pressure relief
valve monitoring only be required "after each pressure relief, of which
the operator has knowledge." The commenter wrote that this clause is
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necessary because pressure relief to the atmosphere is not always known
by the owner or operator.
Response:
The intent of the standards for pressure relief valves is to
control emissions at all times except during an overpressure relief.
Therefore, the standards require that pressure relief valves return to
no detectable emissions as soon as practicable, but no later than 5
calendar days after the pressure relief. Pressure sensors between the
rupture disk and pressure relief device can alert operators in the event
of a pressure relief. Owners or operators may also be alerted that
pressure release has occurred from instrumentation in a unit control
room or by visually or audibly detecting a release.
2.6 SAMPLING SYSTEMS
Comment:
A commenter (IV-D-14) wrote that an exemption in the proposed
standards for sampling systems should be allowed when for example, a
sample might be drawn after a heat exchanger or cooler, and there is ,,;
not enough pressure available to return it to a lower pressure source;
The commenter suggested an alternative to closed loop sampling. He
recommended simply to require accumulation of the purged material in
another container for proper disposal. Another commenter (IV-D-4) :
maintained that the application of the standards for sampling connection
systems for "low vapor pressure liquid streams is not cost effective
with respect to reduction of VOC emissions."
Response:
The standards do not require "closed loop" sampling (although
it may be used to comply with the standards) but do require a "closed
purge system" as one commenter suggested. Using closed purge sampling,
an owner or operator could simply collect purged materials and properly
dispose of them by any system that collects the VOC and destroys or
recovers the VOC without emissions to atmosphere.
EPA recognizes that some sampling connections are located at
points that would have insufficient pressure to return purged fluid in
a closed loop. For example, low line pressure (resulting from pressure
drop in the final product coolers or a phase change) is characteristic
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near plant boundaries. Hence, EPA expects that owners/operators would
use closed purge to comply with the standards. If a plant owner or
operator chooses to retrofit a closed loop sampling connection in these
instances at a location of higher pressure (e.g., near a pump), and if a
sample cooler is not in place at the selected location, a cooler may
have to be installed to ensure safe handling of hot materials.
Retrofitting a closed loop sampling connection at a location
that necessitates a cooler, however, is not expected to occur often.
Most sampling connections are located near pumps where line pressure is
not a problem and where cooling systems are already in place (Document
No. IV-B-6). Nevertheless, EPA has estimated the additional cost
of retrofitting a closed loop sampling system with a cooler. The
addition of a sample cooling system increases the cost effectiveness of
the sampling system from $810/Mg to $l,450/Mg.
The standards for sampling connections include low vapor pressure
liquid streams. Heavy liquid streams have the potential to emit VOC's
to atmosphere, particularly from purged sampling materials that are
likely at elevated temperatures. The emission factor developed for
sampling connections is based on both light liquid and heavy liquid
streams. The cost effectiveness estimate of $810/Mg is based on closed
loop sampling. However, the standards allow closed purge sampling
which would likely be used for low vapor pressure streams at an even
more reasonable cost effectiveness.
Comment;
Another commenter (IV-D-4) suggested an exemption for sampling
connections in units that become affected facilities through modifi-
cation or reconstruction if retrofit costs exceed that of a comparable
installation in a new unit.
Response:
The control costs presented in Chapter 8 of the BID for the proposed
standards for sampling systems are likely overstated because they are
based on closed loop sampling. These costs included retrofit conside-
rations. The cost effectiveness of closed loop sampling is estimated
to be $810 per Mg (preamble to the proposed standards). It is possible,
however, that in some situations retrofit costs for using closed loop
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sampling will exceed that of the cost of a new sampling system. [The
example given in the previous comment indicated that owners/operators
may retrofit a closed loop sampling system by adding a sampler cooler.
Although it is unlikely that retrofitting a closed loop sampling con-
nection at a location that necessitates a cooler would occur very
often, EPA evaluated the cost effectiveness to retrofit a closed loop
sampling system by adding the cost of a dedicated sample cooler. EPA
determined that the cost effectiveness of the system is still reasonable,
$1,450 per Mg VOC (Document No. IV-B-6).] If a specific plant would
incur extra costs, EPA would not consider this unreasonable.
2.7 OPEN-ENDED LINES
Comment:
One commenter (IV-D-8) questioned the operational requirement of
closing the inner valve prior to closing an outer valve on open-ended
lines. The commenter wrote that this requirement is unenforceable and
of no benefit if the inner valve leaks.
Response:
The standards require open-ended valves to be equipped with a cap,
plug, or a second valve. If a second valve is used, the upstream valve
is required to be closed first 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. While it is true that this and many other sound practices
are not 100 percent enforceable, this requirement is enforceable if an
inspector finds that the upstream valve has not been closed at all.
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. In this situation the second
valve would control VOC emissions.
Comment:
Another commenter (IV-D-14) recommended that open-ended valves
and lines be included in the valve standards (i.e., leak detection and
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repair) with an exemption for plugged valves. The commenter was concerned
that any open-ended valve could result in a violation. Concern was
also expressed that requiring plugs on pump case valves could cause
premature failure of the welded connection at the pump case. Also, the
standards would require plugging bleed valves "out-of-service" in a
block and bleed arrangement.
Response:
Open-ended valves are not included in the valve standards because
leak detection and repair for open-ended valves does not represent BDT.
Leak detection and repair would achieve less emissions reduction and
may cost more to implement than the equipment and operational standards
for open-ended valves because of repeated inspections of nonleaking
sources. The use of a leak detection and repair program for the control
of VOC emissions from open-ended valves or lines would be inappropriate.
The standards for open-ended valves provide refineries with the
flexibility to add either a cap, plug, blind flange, or a second valve
depending upon the individual application. Pump case valves, for
example, could be double valved to avoid the risk of premature failure
of the welded connection at the pump case caused by frequent removal of
a cap or plug.
Upon reviewing the comment that the standards would require plugging
bleed valves "out-of-service" in a block and bleed arrangement, EPA
decided to provide an exemption in the final standards for open ended
lines in a double block and bleed arrangement when venting the space
between the two block valves. However, when the bleed valve is not
opened, it must be capped.
2.8 FLANGES, LIQUID SERVICE RELIEF VALVES, AND HEAVY LIQUID SERVICE
VALVES AND PUMP SEALS
Comment:
One commenter (IV-D-8) maintained that the results of a number of
studies support an exemption for equipment in low vapor pressure service.
The commenter noted that an EPA study (Document No. II-A-19) of two
refineries in the South Coast Air Basin had monitored 664 components in
light and heavy liquid service (which were exempt from South Coast Air
Quality Management District rules) and found only four leaking components,
none of which were in heavy liquid service. Another study found only
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one leaking valve out of 519 in heavy liquid service and only
3.8 percent of the pumps leaked. Another commenter (IV-D-15) also
supported excluding pumps in heavy liquid service, pressure relief
valves in light liquid service, flanges, and connections from routine
monitoring.
Another commenter (IV-D-21) wrote that there is no demonstrable
cost effectiveness to the inclusion of pumps and valves in heavy liquid
service, pressure relief devices in both light and heavy liquid service,
and flanges and other connections, and further, these sources should be
exempt from all requirements as indicated by EPA at the National Air
Pollution Control Techniques Advisory Committee (NAPCTAC) meeting on
June 3, 1981. ,
Response:
The final standards for valves and pumps in heavy liquid service,
pressure relief valves in liquid service, flanges, and connections ; .
exempt these sources from routine leak detection and repair. Thedow^,
leak frequency and emission factors for these sources compared to ;
sources subject to the leak detection and repair programs, as discussed
at the June 1981 NAPCTAC meeting, indicate that the cost of routine leak
detection and repair is not warranted by emission reduction. However,
Section 60.592-8 provides that if evidence of a potential leak is
found, the piece of equipment must be monitored within 5 days, and
repaired as soon as practicable within 15 days if an instrument reading
of 10,000 ppm or greater is detected. v
For those components that are found leaking, however, EPA has ^ :-
demonstrated that the cost effectiveness of repair is reasonable.
(Document No. IV-B-5). The cost effectiveness of repair for leaking
flanges, heavy liquid pumps, and heavy liquid valves varies from a
savings of about $180/Mg to a savings of about $90/Mg. For pressure
relief devices in liquid service, repair costs are not considered to be
attributable to the standards. These components should be properly
maintained for safety reasons in the absence of a repair requirement.
The SCAQMD regulations for valves, Rule 466.1, do not cover VOC
less than or equal to 1.5 psi RVP. The NSPS, however, includes valves
that are less than 1.5 psi RVP. In reviewing the commenter's request
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to exempt these valves, EPA notes that these valves do leak. An EPA
study [Document No. IV-A-3] found that 3 of the 175 light liquid valves
with vapor pressures less than 1.5 psi RVP leaked. In addition, raising
the heavy liquid service cutoff to 1.5 psi RVP would affect a small
percentage of valves. In the study previously cited, the 175 valves
represented only 2.4 percent of the total valves that would be subject
to the standards. Hence, considering: (1) that the basis of the
heavy liquid/light liquid split is easily determined, (heavy liquids
have vapor pressure equivalent to or heavier than kerosene), (2) that
light liquid valves servicing less than 1.5 psi RVP streams do leak, and
(3) that a small percentage of refinery valves would be affected, EPA
has retained the light liquid definition.
2.9 CONTROL DEVICES
Comment:
One commenter (IV-D-21) wrote that since flares are not an affected
facility or a fugitive emission source they should not be regulated.
Response;
Flares are one of several VOC control devices that might be used
to comply with the standards. These control devices are used to reduce
emissions of VOC that might otherwise be emitted to the atmosphere
uncontrolled. If flares and the other control devices were not
specifically regulated they might be operated at conditions which would
result in inefficient combustion and inadequate emission reductions.
The EPA has determined that a flare can be operated at conditions which
assure better than 95 percent emission reduction. Flares operated in
this way are an acceptable alternative to other control devices used to
comply with the standards. Section lll(h)(l) provides that EPA may
promulgate design and operational requirements (like the requirements in
these standards for other control devices) to assure BDT - level control
and that EPA include such requirements as will assure proper operation
and maintenance of any such element of design or equipment. Therefore,
it is appropriate to specify operational requirements for flares used
to comply with the control device standards developed under Section
Comment:
Several commenters (IV-D-4, IV-D-8, IV-D-12, and IV-D-15) requested
that the requirements for flares be deleted, including the provision
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that compliance be determined by Reference Method 22. They recommended
that they be replaced with provisions that flares function in accordance
with good operating practice with an attached flame and no visible
emissions except for periods not to exceed a total of 5 minutes during
any 2 consecutive hours.
Response:
Data developed by a Chemical Manufacturers Association (CMA) - EPA
flare test program (Document No. II-A-43) show that some types of
flares meeting certain conditions achieve better than 98 percent emission
reduction. Consequently, the EPA concluded that design and operational
standards which require flares to be operated at the conditions determined
by the tests would assure better than the required 95 percent emission
reduction. The term "good operating practice" has no accepted engineering
meaning. There is no evidence that flares give better than the required
95 percent emission reduction at all velocities at which the flame
remains "attached." Therefore, requiring that flares function in accordance
with good engineering practice with an attached flame does not assure
better than the required 95 percent emission reduction. The standards
do require that there be no visible emissions except for periods not to
exceed a total of 5 minutes during any 2 consecutive hours. Reference
Method 22 describes the procedure used to determine whether the flare
meets this visible emission requirement.
Comment:
Several commenters (IV-D-6, IV-D-7, IV-D-8, IV-D-15, and IV-D-16)
wrote that the definition of a "flare" was too restrictive and should
be revised to allow many flare designs Which are currently in use in
refineries. The commenters specifically opposed the definition because:
(1) multiple burner arrays are efficient, (2) there is no relationship
between destruction efficiency and flare elevation, and (3) most flares
operate with turbulent diffusion flames rather than strict diffusion
flames. One commenter also stated that the definition should allow
automatic ignition systems.
Response:
The definition of a flare is restrictive in that the types of flares
permitted are limited to those on which data are available. Other
types of flares may give better than the required 95 percent reduction
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under certain conditions. EPA has underway a program to determine the
efficiencies of some other types of flares used in the petroleum and
SOCMI industries. As this information becomes available to EPA, the
requirements for flares could be changed, if it is appropriate. If an
owner or operator chooses to use another type of flare, he may use the
equivalency procedures to demonstrate that the flare should be allowed
by EPA. EPA accepts that there is no relationship between flare destruction
efficiency and flare elevation. Accordingly, the definition of control
device has been changed to exclude the term "elevated." Also, automatic
ignition systems are not disallowed by the regulation.
Comment:
Other commenters (IV-D-6, IV-D-7, IV-D-15, and IV-D-16) urged
EPA to revise the design and operational requirements for flares. The
commenters noted that the maximum velocity of 22 m/sec would greatly
increase flare costs. It was also suggested that the assignment of
minimum heating values for flares be related to the relief gas composi-
tion.
Response;
The maximum velocity value of 22 m/sec was changed since proposal
to 18 m/sec. This change was based on further evaluation of the data.
The revised exit velocity (for steam assisted flares), is the highest
velocity tested in the flare tests sponsored by CMA and EPA (Document
No. II-A-43). EPA has underway a program to determine if better than
the required 95 percent emission reduction can be maintained at higher
velocities. If EPA concludes that high emission reduction can be
maintained at velocities greater than 18 m/sec, EPA will change the
maximum velocity value accordingly. An operator would have the option
of demonstrating to EPA that use of a flare at conditions other than
those specified, would result in emission reduction equivalent to 95
percent control, the level selected as BDT for control devices.
Comment:
One commenter (IV-D-25) stated that flares should be exempted
during start-up and shut-down periods and for 10 minutes during a
2-hour period. Even under ideal conditions, unit upsets may cause
incidents exceeding the 5 minutes per 2 hours exemption for visible
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emissions. One commenter (IV-D-6) suggested that EPA clarify that a
visible flame does not constitute a visible emission.
Response:
Start-up and shut-down periods and any "unit upset"'due to
malfunctions are covered by the General Provisions. Section 60.8(c)
states that "Operations during periods of start-up, shut-down, and
malfunction 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,
shut-down, and malfuction be considered a violation of the applicable
emission limit unless otherwise specified in the applicable standard."
The 5-minute limit for visible emissions {within any. 2-hour period)
is consistent with the flare requirement of the State of Texas where many
plants with smokeless flares are located. EPA has no information, nor
has any been submitted in this rulemaking, suggesting that these plants
cannot.achieve this time limit.
The standards require that Reference Method 22 [Section 114 of the
Clean Air Act as amended (42 U.S.C. 7414)] be used to determine the
compliance of flares. This method involves the visual determination of
visible smoke emissions from flares. Section 3.4 of Method 22 clearly
states that "smoke occurring within the flame, but not downstream of
the flame, is not considered a smoke emission."
Comment:
Another commenter (IV-D-24) objected to the requirement for
instrumentation to monitor flare operating parameters.
Response:
With respect to instrumentation to monitor flare operating parameters,
an owner or operator is only required to use a heat sensing device to
indicate the continuous presence of a flame. Flares and other control
devices are required to be operated at all times when emissions may be
vented to them. Other measurements for flares are required one-time
only or when requested by enforcement agencies for a compliance
determination.
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Comment:
A commenter (IV-D-8) requested that the requirement of Reference
Method 22 be deleted because fugitive emissions from flares are small,
and existing flares are designed on a different basis.
Response: ,
As explained in the preamble to the proposed standards, EPA selected
design and operational requirements for VOC control devices: flares,
enclosed combustion devices, and vapor recovery systems that reflect
the application of the best technological system of emission reduction
for these control devices. The design and operation requirements for
flares require smokeless operation. Smokeless operation of a flare means
that visible emissions from a flare are to be less than 5 minutes in
any 2-hour period as determined by Reference Method 22. Reference
Method 22, hence, provides guidelines for assessing visible emissions
from flares and is included in the standards to ensure that flares
achieve greater than 95 percent control.
Comment:
One commenter (IV-D-30) believed that EPA has not adequately
justified rejection of flares as the sole basis for the standards for
control devices. The commenter stated there was no cost analysis in
the BID to support EPA's belief that flares are too costly if they are
built solely for fugitive VOC control. The commenter contended that,
where point sources of VOC and fugitive sources are controlled by a
single flare, 98 percent control efficiency should be required.
Response; •
Existing control devices were selected as part of the best
technological system of emission reduction for fugitive emission. EPA
believes that most in-place flares and enclosed combustion devices are
designed and can achieve an average destruction efficiency of about
98 percent. Existing vapor recovery systems can be operated to achieve
at least 95 percent emission reductions and are an attractive control
option in that some product may be recovered and realized as an energy
credit (e.g., process heaters). Flares were not selected as the sole
basis for this portion of the standards, as the commenters requested
because the cost of requiring owners and operators to replace 95 percent
efficient control devices already in place in existing refineries with
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98 percent efficient devices is unreasonably high in light of the
small additional emission reduction achievable from these equipment leaks,
The standards, therefore, require 95 percent control (which allows use
of existing vapor recovery systems that can achieve 95 percent, but not
98 percent control in all cases) although EPA expects that most refiners
will utilize flares and achieve 98 percent or better control.
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3.0 APPLICABILITY
3.1 AFFECTED FACILITY
Comment:
Two commenters (IV-D-8 and IV-D-21) questioned whether an "affected
facility" should be defined as a group of fugitive emission sources of <•"
VOC, noting that (in their opinion) the definition is inconsistent with
the terms of the Clean Air Act. A commenter (IV-D-21); stated that
Regulation 40 CFR 60.2 requires that an "affected facility" be an
apparatus and "a group of fugitive sources is not an apparatus." These '
commenters implied that all equipment (including equipment not affected
by the requirements of the standards) should be included in the affected
facility for process units. One commenter (IV-D-8) stated that the
control of fugitive emissions is significantly different from controlling
emissions from new stationary sources generally covered by NSPS.
Fugitive emissions control "involves continuous tightening or repairing
of thousands of individual components, each of which emits relatively ;
small amounts of emissions," whereas with most other stationary sources
subject to NSPS, "once the control equipment is installed routine
maintenance is generally required." Based on these positions the
commenters stated that control of fugitive emissions through new source
performance standards is unworkable.
Response:
In choosing the designation of affected facilities, EPA examined
fugitive emission sources of VOC in light of the terms and purpose of
Section 111 of the Clean Air Act. The Clean Air Act mandates-the EPA
to set standards for any pollutant emitted from a category of new or
modified "stationary sources." Section lll(a)(3) of the Act defines
the term "stationary source" to mean "any building, structure, facility,
or installation which emits or may emit any air pollutant." The
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pieces in VOC service of equipment in a process unit, viewed in the
aggregate, are a "facility" that may emit air pollutants and, therefore,
are appropriately considered as a "stationary source".* How these
pieces of equipment are or are not aggregated into affected facilities
is carefully considered by EPA.
Since the purpose of Section 111 is to minimize emissions by
application of the best demonstrated system of emission reduction at
new and modified sources (considering cost, nonair quality health and
environmental impacts, and energy requirements), there is a presumption
that the narrowest designation {i.e., individual pieces of equipment)
is proper. However, EPA rejected the equipment component designation
for fugitive emission sources other than compressors; this decision is
discussed in response to another comment in this section (see page 3-6).
Consequently, the next most narrow definition, the group of all equipment
components (except compressors) within a process unit, was considered.
Review of the relevant statutory factors did not lead to the conclusion
that designating each group of equipment components in a process unit
*This agrees with the dictionary definition of "facility," meaning
something designed, built, installed, ect., to serve a specific function
or perform a particular service" (The Random House College Dictionary,
Revised Edition, 1975). The group of equipment in VOC service covered
by these standards is designed and installed to serve the specific
function of handling the processing of petroleum products into
intermediate or more refined materials.
We note in this regard that the Court of Appeals for the District
of Columbia Circuit-has stated that:
In designating what will constitute a facility in each particular
industrial context, EPA is guided by a reasoned application of the
terms of the statute it is charged to enforce, not by an abstract
"dictionary" definition. This court would not remove this
appropriate exercise of the agency's discretion.
578 F.2d 319, 324 n. 17 (1978). EPA's selection of the group of fugitive
VOC emissions-related equipment as the affected facility reflects a
reasoned application of Section 111. It assures that an identifiable
subset of refinery emissions—equipment leaks of VOC— is controlled as
soon as the equipment responsible for those emissions is either modified,
reconstructed, or newly constructed. For the reasons explained in the
text below, a broader definition (e.g., all the components of a process
unit) would simply delay that result.
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as an affected facility would cause adverse impacts. Defining an
affected facility as the group of equipment components, other than
compressors, within a process unit would achieve similar emission
reductions as designating individual components as the affected facility.
(See discussion in comment on this point.) Therefore, the affected
facilities for the standards are (1) compressors in petroleum refineries
and (2) the group of equipment (pressure relief devices, open ended
lines, sampling systems, valves, and pumps) in a process unit.
Some of the commenters appear to be suggesting that the affected
facilities should include equipment within a process unit even though
the equipment is not an apparatus to which the standards apply. Such
an approach would mean equipment affected by the standards would not be
required to use the best demonstrated technology (considering costs).
EPA believes this approach would be inconsistent with Section 111.
(No evaluation of the best demonstrated technology (considering costs)
has taken place for these equipment at this time. EPA may evaluate
this for these equipment later.) Also, if EPA would follow this approach,
increases in emissions from emission points not affected by the standards
and changes in operation not related to the equipment covered by the
standards could result in modifications. In contrast, emission reductions
resulting from the incremental control of emission points not covered
by the standards could be used to offset increases in emissions resulting
from emission points covered by the standards and* therefore, would
preclude what otherwise might have been a modification. EPA believes
this approach would be confusing. Based on this consideration, EPA
rejected this approach.
The commenter stated that control of fugitive emissions through
standards of performance is unworkable because the fugitive emission
sources covered by the standards do not include all of the equipment
within a process unit. This is a practical consideration only when
considering the modification and reconstruction provisions in Part 60.
For newly constructed sources, the standards are clearly practicable.
The standards are well defined and will result in the intended purpose
of requiring the best demonstrated technology for equipment leaks of
VOC (fugitive emission sources of VOC). For an owner or operator who
might be considering or determining a modification or reconstruction,
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however, this definition might pose some difficulties. For example,
determining the basis (see definition of capital expenditure--40 CFR 60.2)
of an existing facility is more difficult for this standard than for
most other standards of performance (See Section 4.0 for more examples).
EPA has provided alternative approaches to reduce the burden associated
with these difficulties. These alternative approaches were not provided
to make this definition usable but to make it easier to use. This
issue and the alternative approaches are discussed further in Section
4.0 and, to the extent it concerns the reconstruction provisions, in
Section 5.0.
Comment:
Another commenter (IV-D-30) contended that EPA should define the
affected facility as each individual fugitive emissions component based
on "Section Ill's presumption for inclusiveness." In addition, the
commenter did not believe that EPA provided convincing reasons to
support the decision to treat compressors individually and other
components collectively (process units) in defining "affected facility."
The commenter contended that EPA's first reason for rejecting individual
components (the cost of tracking individually covered sources) is not
persuasive because a simple color coding or tagging of new and existing
components could be used. Additionally, in response to EPA's second
reason for rejecting individual components as the basis for the affected
facility, the commenter indicated that it does not appear that there
would be a significant difference in leak detection and repair costs
between the "process unit" definition and the "individual component"
definition of affected facility. This commenter also stated that he
found no evidence in the preamble or the BID for the proposed standards
for EPA's assertion that the "process unit" definition of affected
facility would achieve as much emission reduction as the "individual
component" definition. The commenter believed that as individual
components are added to a unit, they are covered earlier and achieve
further emission reductions than fugitive emission sources within
process units, which are not covered by the standards until the entire
unit is replaced.
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Response:
In selecting the basis for the affected facility, EPA considered
the effects of keeping track of individually covered sources. As
discussed in the preamble to the proposed standards, components in
existing plants would be replaced one at a time and, therefore, would
be covered by the standards one at a time. Because components in
existing plants are infrequently replaced, many adjacent components
would not be covered by the standards. This would mean that a plant
would be required to inventory all the components in a plant and then
keep track of all activities for each component. Even though individual
components could be color coded or tagged, EPA believes that the effort
to keep track of and record activities for a mixture of individual
components within a plant would be tedious and costly. In addition, as
discussed below, EPA believes that this effort would not likely result
in additional emission reductions, in particular, during earlier
implementation of this approach. In contrast to the recordkeeping
effort for individually covered sources, the effort for components
within process units would be less and would still result in more
immediate emission reductions. Thus, EPA judged that maintaining, an ,,r
inventory of individual components for an entire plant would be unreasonably
burdensome, but maintaining an inventory for compressors or evaluating
components occasionally within process units would not be unreasonably
burdensome.
The commenter appears to have misunderstood the techniques used to
determine the cost effectiveness for leak detection and repair programs.
The costs incurred for implementing such a program include fixed costs,
for example, the monitoring instrument and calibration costs which are
shared by the components monitored. The fixed costs can be unreasonably
high if only a few components are monitored. Additionally, EPA costs
are based on a specific time required for monitoring each component.
These monitoring times are based on the normal physical distribution of
components in petroleum refining process units. If only a few components
scattered throughout a plant are monitored, the time required per
component would be greatly increased. These monitoring costs would be
unreasonable until enough components would be covered within a certain
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area of a plant. This area may be smaller than a process unit but not
significantly smaller than a process unit.
In response to the commenter's concern about emission reductions,
EPA attempted to select a basis for the affected facility definition
that would provide the largest emission reduction that is reasonable.
As discussed above, EPA most seriously considered two approaches in
defining the affected facility—the individual "component" approach and
the "process unit" approach. The largest emission reductions are
usually associated with a component basis. However, for these standards
the difference between emission reductions of the component and process
unit approaches are unclear. Based on the "component" approach all new
components—covered by the standards—and all replaced components would
be affected by the standards. A modified component would be unlikely.
[The replaced components would be scattered throughout the plant and
would become affected by the standards one at a time as existing components
are replaced.] In contrast, under the process unit approach, all new
components within "new" process units would be covered by the standards,
but individually replaced components would not be covered. Most
importantly, many components (not actually increasing emissions or
being replaced) in modified process units or reconstructed process
units would be covered ("captured") based on the "process unit" approach.
The difference between the emission reduction potential for the
two approaches can be based on the difference in the number of individually
replaced components and the number of components that are "captured" in
modified or reconstructed process units. EPA believes that, in this
case, the numbers are similar. However, there is no reliable procedure
to approximate these numbers. Based on EPA's belief that the emission
reductions between the component approach and the process unit approach
are similar and based on the burden associated with maintaining records
of individual components for an entire plant, EPA selected the process
unit as the basi.s of the affected facility for all the equipment covered
by the standards except compressors.
Comment;
Three comments were received concerning the designation of compressors
as a separate affected facility. One commenter (IV-D-10) supported
compressors as a separate affected facility; however, others (IV-D-5
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and IV-D-12) maintained that when compressors are an integral part of a
process unit they should be considered part of the "process unit"
affected facility. When compressors are not considered an integral
part of a process unit, they should be considered separately. Also,
commenters said designating compressors as a separate affected facility
could lead to.confusion and would likely make them subject to standards
sooner because they are often replaced at shutdown.
Response:
As discussed in the preamble to the proposed standards, compressors
(unlike other fugitive emission sources in petroleum refineries) are
major pieces of equipment and are readily identifiable. Since compressors
are relatively few in number, tracking of those subject to NSPS requirements
and those not subject to these requirements would not be difficult. As
mentioned above, there is a presumption that the narrowest definition
of an affected facility is proper unless there is a statutory factor
that leads EPA to a less narrow definition. Commenters did not present
any of these factors. The fact that compressors are integral to the
process unit does not preclude EPA from defining them as separate
affected facilities. By extension, the commenter's reasoning would
prohibit EPA from defining different emitting sources within a plant as
separate affected facilities because they are integral to the plant.
It is clear, however, that EPA has authority under Section 111 to define
each as a separate source. Moreover, EPA has often chosen such plant
subsets as separate affected facilities. (For example, see Subpart Da
of 40 CFR Part 60 — each boiler at the utility station is a separate
affected facility). Focusing on whether equipment is integral to a
process simply is not helpful or relevant to the selection of the
affected facility for purposes of standards of performance.
It should be noted that by making compressors a separate affected
facility, compressors are not likely to be covered by modification
provisions. However, as one of the commenters stated, when a compressor
is refurbished or replaced it would likely be a reconstruction and,
therefore, covered by the NSPS. EPA considers this appropriate. EPA
considered the comments received regarding designation of compressors
as separate affected facilities and concluded that the designation
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should remain for the same reasons originally stated in the preamble to
the proposed standards.
Comment:
One commenter (IV-D-10) recognized that the definition of process
unit includes flexibility and that determinations of an affected facility
may be on a case-by-case basis. The commenter wrote that the identity
of a "process unit" is not always clear or equally transferable from
one refinery to another.
Response:
EPA agrees with the commenter that there will be differences in
"process unit" affected facilities, even among processes producing
the same petroleum product. Thus there is flexibility in the definition
of process unit. These differences are mainly caused by differences in
design and construction of process units. Typically, equipment within
a process area is functionally related and associated with a single
process unit. However, some equipment pieces (generally, very few)
within an area may be functionally associated with a second process
unit that is not located in the area. Hence, equipment function will
be a determining factor as to which process unit it is considered to be
in. When a piece of equipment can function in more than one process
unit, its location will be a determining factor. It should be noted that
owners and operators may request EPA to review plans for construction
or modification for the purpose of obtaining technical advice, as
provided in the General Provisions of Part 60 (40 CFR 60.6).
3.2 DEFINITION OF "IN VOC SERVICE"
Comment:
Several commenters (IV-D-6, IV-D-8, IV-D-16, IV-D-21, and IY-D-24)
requested that the definition of "volatile organic compound (VOC)"
specifically state which organic compounds are excluded. It was also
recommended that the definition include the phrase, "or as measured by
the applicable test methods described in Reference Method 21."
Response:
Volatile organic compounds (VOC) are defined as organic compounds
that participate in photochemical reactions. Any organic compound is
presumed to participate in atmospheric reactions unless the Administrator
determines that it does not. EPA considers several organic compounds
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to have negligible photochemical reactivity. These are methane, ethane,
1,1,1-trichloroethane, methylene chloride, trichlorofluoromethane,
dichlorodi f1uoromethane, chlorodi f1uoromethane, tri f1uoromethane,
trichlorotrifluoroethane, dichlorotetrafluoroethane, and chloropenta-
fluoroethane.
The standards provide for the exclusion of substances considered
non-photochemically reactive by EPA from the percent VOC in the process
fluid when determining whether a piece of equipment is not in VOC
service. The purpose of this is to avoid covering those sources that
have only small amounts of photochemically reactive substances in the
line and to establish the standards consistent with the data base.
In determining whether the VOC in a process line is less than 10 percent
of the total mass in the line {as a prerequisite to determining that a
piece of equipment is not in VOC service), quantities of compounds
present in the line that are considered nonphotochemically reactive by
EPA may be excluded from the total quantity of organic material.
Section 60.595(d) of the standards requires that VOC content is to
be determined by the referenced ASTM methods, not by Reference Method 21,
The referenced ASTM methods can be used to distinguish among compounds
and, therefore, allow the determination of the amount of photochemically
reactive compounds in a process stream. In contrast, Reference Method 21
is a method for determining leaks. This method requires that monitors
used in complying with the standards respond to the organic compounds
in the process streams. Thus, there is no reason to include the phrase
requested by the commenter.
Comment:
Several commenters (IV-D-8, IV-D-12, IV-D-18, IV-D-21, IV-D-22, and
IV-D-24) requested that the proposed definition of "in VOC service" be
revised. The commenters suggested raising the weight percent cutoff
from 10 to 20 weight percent VOC to exclude coverage of hydrogen service
compressors and to provide more reasonable operating flexibility.
Excluding 75 volume percent or greater hydrogen streams and changing
the 10 weight percent VOC to 10 volume percent VOC were also recommended.
The commenters contend that such streams would have a lower percentage of
VOC and, consequently, the controls would achieve lower VOC emission
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reductions and have a higher cost effectiveness ($/Mg VOC emission
reduction).
Response:
The commenters are suggesting that EPA exempt equipment that,
because they contain so few VOC, are not cost effective to control.
In response to this comment, EPA analyzed the control of valves
and compressors in hydrogen service (Document No. IV-B-9). Most
process streams affected by the standards are clearly above 10 weight
percent VOC, and many are nearly 100 weight percent VOC. Process streams
less than 10 weight percent are almost always much less than 10 weight
percent VOC. Only a few process streams may be near 10 weight percent
VOC, and these are generally those that would be considered in hydrogen
service. Thus, EPA analyzed the control of equipment that, based on
EPA's data, could be found in hydrogen service. This would allow EPA
to exempt control of equipment if it is not cost effective. In hydrogen
service is defined as greater than 50 volume percent hydrogen based on
EPA's data. The analysis is explained in docket item IV-B-9. Emission
reductions are achieved for valves in hydrogen service at reasonable
costs ($106/Mg VOC). However, application of equipment controls for
compressors in hydrogen service results in a cost effectiveness of
$4,600/Mg VOC. EPA, therefore, decided to exclude compressors in
hydrogen service from the standards.
In EPA's judgment, determination of-VOC content in a given stream
is a routine analytical procedure. The test method, ASTM E-260, gives
quantitative measures of each component proportional to their concentration.
Hence, the results are expressed as a weight percent. The commenter
recommending that the VOC content expressed in weight percent be changed
to a volume percent did not provide any basis for this change. Hence,
EPA maintains that the VOC content expressed in weight percent is a
reasonable approach.
Comment:
Another commenter (IV-D-21) remarked that the definition of VOC
fails to establish a de minimi's level for volatile materials which do
not contribute to atmospheric emissions. A "heavy liquid" definition
was considered necessary because it would avoid unnecessary monitoring of
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components processing materials that are unlikely to register a 10,000 ppm
concentration.
Response:
The definition of VOC does not exclude compounds based on volatility.
Processes that produce relatively non-volatile products can involve
high temperature and pressure conditions, thus producing emissions of
VOC. These VOC contribute to ozone formation. A de minimis level
would not be appropriate. EPA has tailored the standards (in part,
based on volatility) to require the best demonstrated technology. As a
consequence, EPA concluded that routine leak detection and repair is
not warranted for components in heavy liquid service because they have
low leak rates and, as a group, control is not cost effective (Docket
No. IV-B-5).
Heavy liquid streams are generally a mixture of heavy hydrocarbons
(e.g., crude oil) with very little light hydrocarbons. Nevertheless, these
streams have the potential to leak VOC (determined by concentrations in
excess of 10,000 ppm), and these VOC would contribute to ozone formation.
Data reviewed by EPA (Document No. II-A-19) show that a few components
in heavy liquid service do have emission concentrations greater than
10,000 ppm and, therefore, do leak emissions of VOC. When these leaks
occur, repair is cost effective (Document No. IV-B-5). If an operator
sees, hears, smells, or otherwise suspects a leak, it is appropriate
that the component be monitored and, if a leak exists based on a greater
concentration, that it be repaired.
Comment:
One commenter (IV-D-12) supported the proposed definition for
"light liquids" as it agrees with findings in their fugitive emissions
program; however, another (IV-D-17) held that the definition was too
restrictive and should include only the heavy naphthas and lighter
materials because as defined, some equipment in light liquid service
would not significantly contribute to fugitive emissions. Excluding
compounds with a Reid Vapor Pressure (RVP) less than 1.5 psi was
recommended.
Response:
The criterion used by EPA for the light liquid definition
(that is, liquids with a vapor pressure greater than that of kerosene)
was based on fugitive emission data gathered in petroleum refinery
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studies (Document No. II-A-19). Equipment processing VOC with vapor
pressures greater than kerosene were found to leak at significantly
higher rates and frequencies than equipment processing VOC with vapor
pressures of kerosene or lower. Therefore, EPA decided to exempt
equipment processing VOC substances with vapor pressures lower than
about the vapor pressure of kerosene from the routine leak detection
and repair requirements of the standards. This is consistent with the
commenter's request to cover only heavy naphthas and lighter compounds.
The RVP cutoff of 1.5 psi that was recommended by the commenter is
based on California regulations for the storage of volatile organic
liquids which are at ambient pressure and temperature. There are no
data to support the 1.5 psi cutoff as it would apply to fugitive emission
sources. EPA considers control of equipment in light liquid service
(based on the proposed definition) cost effective; therefore, based
on these considerations, EPA did not revise the definition of light
liquid service.
3.3 EXCLUSIONS
Comment:
One commenter (IV-D-13) stated that process units with in-place
state-of-the-art hydrocarbon gas detection systems should be exempted.
This commenter requested that units in an arctic environment be exempted
because of several unique aspects of refining in the North Slope of
Alaska. For example, (1) the products are used locally, (2) process
units are totally enclosed at a high cost because of the harsh environment;
therefore, present safety controls (gas detector placed near exhaust
fans with an alarm set at 12,500 ppmv) are adequate and additional
requirements are unwarranted, (3) requiring rupture disks ahead of
pressure relief devices would compromise safety especially under this
application, (4) repair labor is 2 1/2 to 4 times more costly, and (5)
control of VOC has limited benefit in attainment areas, especially in
the arctic where cold ambient temperatures, the degree of insolation,
and a low concentration of photochemical precursors limit ozone
formation.
Response;
The presence of an in-place state-of-the-art hydrocarbon gas
detection system does not necessarily ensure emission reductions. Gas
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detection systems set for 12,500 ppm would permit VOC to be emitted
without notice. Several megagrams of VOC would 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. Upon request by EPA, the commenter explained the specific
control techniques used at their plant, many of which are identical to
those required by 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 final 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.
EPA has studied the commenter's concerns and acknowledges that
there are several unique aspects to refining in the North Slope of
Alaska. Accordingly, EPA concluded only that the costs to comply with
the routine leak detection and repair requirements of the proposed
standards may be unreasonable. 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. These
unique aspects make the cost of routine leak detection and repair
unreasonable (Document Number IV-B-15). Therefore, EPA has decided
that refineries 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
the cost of those requirements is reasonable.
Comment:
One commenter (IV-D-26) recommended that the definition of "petroleum
refinery" be clarified to exclude production and intermediate .facilities
such as wells, drill pads and separation tanks, that may be involved in
onsite processing in oil fields. Similarly, another commenter (IV-D-3)
requested that the definition of "petroleum" be revised to clarify that
coal tar and refined coal tar oils that are by-products of coking
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processes are not covered in these standards because they are not
covered under Subpart J.
Response:
In Section 60.591 (Definitions), the proposed standards defined
"petroleum.refinery" as "any facility engaged in producing gasoline,
kerosene, distillate fuel oils, residual fuel oils, lubricants, or
other products through the distillation of petroleum, through the
redistillation, cracking, or reforming of unfinished petroleum deriva-
tives." This definition does not include production and intermediate
facilities found in oil fields, nor does it include production tar and
tar oils from coal coking processes. The standards apply only to
process units within petroleum refineries. New source performance
standards (NSPS), however, are being developed by EPA for the natural
gas processing industry under another standards development project
(40 CFR Part 60 Subpart KKK - Standards of Performance for Onshore
Natural Gas Processing Plants: Equipment Leaks of VOC). The natural
gas processing industry NSPS may cover fugitive emission sources at
production, and will more likely cover them at intermediate facilities.
EPA has consistently used the term "petroleum"; it does not mean tar
and tar oils from coal coking processes, but it does mean synthetic
petroleum products from processes that use coal as a raw material.
Thus, EPA has not clarified the term "petroleum." It should be noted
that the production of some chemicals (for example, formaldehyde or
phenols) at coal coking processes, however, is covered by NSPS for the
synthetic organic chemical manufacturing industry (Subpart VV).
Comment;
Another commenter (IV-D-8) maintained that the results of a number
of studies support a complete exemption for equipment in low vapor
pressure service. The commenter noted that an EPA study (see Document No.
II-A-41, p. 2-38) of two refineries in the South Coast Air Basin had
monitored 664 components in light and heavy liquid service (which were
exempt from South Coast Air Quality Management District rules) and
found only four leaking components, none of which was in heavy liquid
service. Another study found only one leaking valve out of 519 in
heavy liquid service and only 3.8 percent of the pumps leaked. Another
commenter (IV-D-15) supported excluding pumps in heavy liquid service,
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pressure relief valves in light liquid service, flanges, and connections
from routine monitoring.
Another commenter (IV-D-21) wrote, however, that there is no
demonstrable cost effectiveness to the inclusion of pumps and valves in
heavy liquid service, pressure relief devices in both light and heavy
liquid service, and flanges and other connections, and further, these
sources should be exempt from all requirements as indicated by EPA at
the National Air Pollution Control Techniques Advisory Committee (NAPCTAC)
meeting on June 3, 1981.
Response:
The commenters suggest that certain types of equipment leak so
infrequently that it is not cost effective to monitor them for leaks.
The final standards for pumps in heavy liquid service, pressure
relief devices in light liquid service, flanges, and connections exempt
these sources from routine leak detection and repair because of the low
leak frequency and emission factor for these sources as discussed at the
June 1981 NAPCTAC meeting. However, the commenters have suggested no
reason that this equipment, if found to be leaking, cannot be repaired
cost effectively. EPA has determined that it is cost effective to
repair these components if they are leaking (see Document No. IV-B-5).
Therefore, Section 60.592-8 provides that if evidence of a potential
leak is found, the piece of equipment must be monitored within 5 days,
and repaired as soon as practicable within 15 days if an instrument
reading of 10,000 ppm or greater is detected.
3.4 SMALL REFINERS
Comment:
Commenters (IV-D-9 and IV-D-23) accused EPA of incorporating into
the standards a bias against small refiners. They asserted that small
refiners will be affected more adversely than will large refiners.
There is a bias, they reason, because EPA did not analyze the comparative
impact of the standards on large versus small refineries. The comparative
analysis was not done because EPA, citing elimination of the crude oil
entitlements program, decided that relatively little new unit construc-
tion will occur at small refineries, and even considering modified and
reconstructed units, few small refineries would be subject to the
standards. Thus, the commenters claim, EPA saw no reason to give small
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refineries special attention under the Regulatory Flexibility Act.
Therefore, a bias exists. One commenter (IV-D-9) said some small
refineries have existed for more than 40 years and are viable without
subsidy programs. Thus, both commenters conclude, EPA should have
analyzed the differential impact of the standards on small refineries
compared with large ones.
Response:
To analyze the economic impacts of the standards, EPA defined 12
types of refinery units: crude distillation, hydrotreating, isomeri-
zation, etc. (See BID for the proposed standards, Document No. III-B-1)
Each type was assigned to one of three model unit categories. Model
Unit A has a small number of pumps, valves, and other components; Model
Unit B has a larger number; and Model Unit C has the most. Assignment
of each type of unit to a particular model unit category was based on
equipment counts averaged over units found at a range of refineries.
EPA then assumed a reasonably small throughput (which might be repre-
sentative of some small refineries) for each type of unit, because
small-throughput units would show significant adverse economic impacts
much more readily than large-throughput units would for any given
amount of money to be spent on controlling fugitive leaks. If the
analysis had revealed potential, adverse economic impacts, EPA would
have intensified its examination of the units involved, and possibly
would have changed the standards appropriately. However, no such
impacts were projected. EPA concluded that no adverse economic impacts
would result from the standards and that there was no need to extend
the economic analysis to cover a wider range of throughput levels.
The Regulatory Flexibility Act (Public Law 96-354, September 19,
1980) requires that special consideration be given to the impacts of
standards on small firms. As one criterion for extending loans and
related assistance, the Small Business Administration defines a small
petroleum refining firm as one employing fewer than 1,500 workers (13
CFR Part 121, Schedule A). The 1,500 number applies to the entire
firm, including affiliates, and is tied in with other criteria relating
to throughput capacity, exchange agreements, and the like. EPA accepts
this definition of a small refiner. Based on this definition, EPA
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projected few small firms would be affected by the standards. However,
even for those affected by the standards, EPA concluded that the impacts
would be reasonable.
The commenters implied that small process units or refineries may
be owned by small firms. However, there are no available data that
relate the size of refining firms (number of employees, throughput,
etc.) to the size of their individual refinery units (number of valves,
pumps, etc.). In addition, there is no reason to believe that the size
of a refining firm is necessarily related to the size of its individual
refinery units. EPA, therefore, has no basis to suspect that small
firms will bear greater compliance costs than large firms on an affected
facility-by-affected facility basis. In fact, the impacts are similar
for all sizes of units. The three model units differ only in regard to
their respective equipment counts. Compliance costs for Model Unit A,
the smallest, are lower than compliance costs for Model Unit C, the
largest. Even though the cost effectiveness for Model Unit A is larger
than it is for Model Unit C. However, these cost effectivenesses are
not significantly different. The commenters offered no evidence that
the sizes of their units, measured either by throughput or by equipment
counts, will cause the impact of the standards to fall disproportionately
on small firms, or that small firms will become non-competitive, or
that small firms will be forced to raise prices substantially.
EPA's projection that relatively few units at small refineries will
be affected by the standards by 1987 is still valid. If, for some
reason not now anticipated, the standards were to place a disproportionate
burden on small refineries, the 1987 projects indicate that comparatively
few such refineries would experience that burden and, more importantly,
the cost estimates indicate that none of those refineries would experience
unreasonable costs. [EPA regrets that its statement may have been
interpreted by the commenters as a bias against small refiners.]
Comment:
One commenter (IV-D-22) remarked that economic conditions in the
refinery industry have changed drastically since 1980, that the projected
number of affected facilities is now too high, and that the benefits
of the proposed standards, therefore, are overstated.
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Response:
EPA projected that 100 new and 182 modified or reconstructed units
would become affected facilities during the first 5 years of implemen-
tation of the standards. The commenter offered no alternative
projections to supplement the claim that 282 units are too many. There
are three reasons why EPA believes the projections should not be changed.
First, the projections in no way affect the need for standards or
the selection of the final standards. The projections are offered only
as a guide for understanding the future aggregate costs and emission
impacts of the standards. Ideally, the projections should be conservative.
However, being conservative requires EPA to project minimal growth when
estimating emission impacts, and to project maximal growth when estimating
aggregate costs to the nation. Low projections can understate possible
economic costs, but high projections can overstate emission savings.
The middle ground reflects EPA's best judgment, considering these two
conflicting uses for the projections. Furthermore, if all projected
growth does not occur by the end of the fifth year, it will occur
sometime shortly thereafter.
Second, the projections were made for the calendar years 1982
through 1986. For reasons unforeseen when the projections were prepared,
the proposal of the standards was delayed a year. This means that the
projections should now be interpreted as applying to the years 1983
through 1987. This shift of 1 year moves the projection interval
completely out of the 1981-1982 economic downturn that the commenter
believes caused the projections to be overly optimistic. As general
economic recovery proceeds, there is every reason to believe the recovery
will be felt throughout the refinery industry.
Third, the projection methodology used by EPA excludes modification
and reconstruction at refineries with crude distillation capacity under
2,226 m3 (14,000 bbl) per calendar day. This exclusion was made as a
way of accounting for the possible effect of elimination of the crude oil
entitlement program. Nevertheless, two commenters (IV-D-9 and IV-D-23)
representing small refiners complained that there would in fact be more
modification and reconstruction than EPA projected. Thus, there is an
indication that the projections are, if anything, too low in this area.
For the above reasons, EPA is not revising the projection of new,
modified, and reconstructed refinery units.
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4.0 MODIFIED SOURCES
4.1 EMISSION INCREASE
. Comment:
A number of commenters (IV-D-14, IV-D-15, IV-D-16, and IV-D-21)
requested that the EPA allow an increase of a de minimis level of
emissions b'efore an existing facility would be considered to have
modified. De minimis values of 5 tons per year and 40 tons per year
(as in 40 CFR 51.18(j)) were suggested by the commenters.
Response:
Under the definition in Section lll(a)(4), any physical or
operational change resulting in an increase in emissions constitutes a
"modification." EPA has exempted certain small emissions increases
from consideration in deciding whether there has been an increase in
emissions constituting a "modification" for purposes of PSD applicability
(40 CFR 52.21(b)(2) and (b)(231)). This action followed the decision .
in Alabama Power Co. v. Costle. 636 F.2d 323 (D..C. Cir. 1979), in which
the D.C. Circuit held that EPA has authority to interpret the definition
of "modification" so as to exempt sources with small emissions increases
from PSD review on grounds of administrative necessity (ld_. at 400).
The Alabama Power decision does not require EPA to provide a de
minimis exemption from application of the "modification" deflnltlorTfor
NSPS applicability purposes. Nor has EPA's experience in implementing
the NSPS program suggested an administrative need for relieving existing
sources from NSPS applicability when they undergo changes resulting in
only a small increase in emissions. This differs somewhat from EPA's
implementation of the definition of "modification" for 'PSD applicability
purposes. In that area, the Agency has determined that the administrative
burden of applying the full preconstruction review process to a source
with only a small emissions increase may be unreasonable (45 FR 52705;
August 7, 1980). The administrative burden associated with the NSPS
program, however, is relatively minimal. In contrast to PSD requirements,
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NSPS's are categorically applicable technology-based requirements only;
they do not involve an assessment of ambient effects and do not require
case-by-case review.
Furthermore, EPA believes that the current straightforward
application of the "modification" definition for NSPS purposes best
serves Section Ill's intent. One key purpose of the NSPS program is to
prevent new pollution problems from arising. One way that the statute
seeks to achieve this is by requiring application of the best demonstrated
technology at, and thereby minimizing emissions from, existing facilities
with increased emissions. The current NSPS approach of not providing
an exemption from the "modification" provision based on the size of
the emissions sources is not intended to cover existing plants making
routine and minor additions. The "modification" provisions in the
General Provisions of 40 CFR Part 60 exempt changes such as additions
made to increase production rate (if they can be accomplished without
capital expenditure, as defined in the General Provisions) and routine
replacements (40 CFR 60.14(e)). In addition, these standards would
exempt additions made for process improvements if they are made without
incurring a capital expenditure.
Comment;
Other commenters (IV-D-8 and IV-D-14), concerned about the complexity
of the modification provisions, endorsed revising the modification
provisions such that a modification occurs when the number of components
exceeds 10 percent of the total number of the same type and there is a
net increase in emissions from the process unit.
Response:
As discussed in Section 4.2, EPA is promulgating an alternative
procedure that will reduce the complexity of the modification provisions
(in particular, how to determine a capital expenditure). In EPA's view
40 CFR 60.14 of the General Provisions adequately specifies the categories
of changes to an existing facility that should bring the facility under
NSPS as a "modified" source. It should be noted that, under Section
60.14(e), certain changes made in an affected facility without a capital
expenditure are not considered "changes in operation" by EPA and,
therefore, are not modifications." See, e.g., 40 CFR 60.14(e)(2)--
production rate increases.
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As proposed in the standards, certain changes (process improvements)
made in an affected facility without a capital expenditure are not
considered "changes in operation" by EPA and, therefore, are not modi-
fications. This generally excludes coverage from industry practices
that involve adding a few valves and maybe a sampling system and making
other minor changes in equipment configurations. The 10 percent increase
in the number of fugitive emission components as suggested by the
commenter, would most likely be associated with a VOC emissions increase
of about 10 percent. Making such a change would likely be associated
with capital expenditure and, therefore, EPA considers this a modification,
Therefore, EPA did not revise the modification provision as requested.
Comment:
Another commenter (IV-D-8) maintained that once a "modification"
has occurred, the NSPS requirements should be applied only to those
types of components which trigger the definition of modification.
Response:
Under Section 111 of the Clean Air Act, the application of
modification is inextricably tied to the designation of "new source,"
or in NSPS terminology, an affected facility. Section lll(a)(2) defines
the "new source" subject to NSPS as a source on which modification has
commenced after proposal, not the portion of the source actually changed.
Stated differently, modification provisions are triggered with respect
to the affected facility; therefore, applicability is to all components
affected by the standards within the affected facility. The commenter
is implicitly requesting EPA to define the affected facility as a group
of one type of equipment within a process unit. EPA, as discussed in
Section 3.1, reasonably concluded that affected facilities to which the
standards apply should remain: (1) the group of all fugitive emission
sources (pumps, valves, sampling connections, pressure relief devices,
and open ended lines) within a process unit and (2) compressors.
4.2 CAPITAL EXPENDITURES
Comment:
Commenters requested that the capital expenditure determination
(as it relates to the modification provisions) be revised so that it is
more practicable. Commenters (IV-D-8 and IV-D-15) remarked that the
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capital expenditure guidelines are outdated and would be difficult to
use because units have been substantially rebuilt over the years and
records of costs for determining the cost basis may be kept on a process
unit basis rather than for individual pieces of equipment, or simply
may not exist. It is, therefore, very difficult to reconstruct original
costs.
In support of their concern about using original costs, the commenters
stated that, based on EPA's current interpretation of capital expenditure,
1 to 3 percent of the current replacement costs would subject units to
modification. Another commenter (IV-D-14) claimed that component costs
represent 5 percent of the total original costs and that the addition
of a new pump with several valves could easily exceed the "capital
expenditure" definition. This commenter provided the hypothetical
example of a unit with a total original cost of $16 million and component
cost of $815,000. The addition of a pump with several valves would
exceed 4 percent of the total component costs, around $56,000.
One commenter (IV-D-10) suggested that replacement costs rather
than original costs be used to determine the basis for capital expenditure.
A few commenters (IV-D-4, IV-D-15, and IV-D-16) suggested that capital
expenditure be defined as 7 percent of the replacement cost (based on
the Chemical Engineering Construction Index or other suitable index) of
an affected facility at the time of process improvement.-
Response:
After reviewing the comment letters concerning the difficulties
with using the capital expenditure definition, EPA agrees that the
definition for capital expenditure may be difficult to use for some
refineries. Accordingly, EPA decided to provide an alternative to
the procedures in 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 costs to determine capital
expenditure. The adjusted AAGRA is determined by a formula and is
based on a ratio that reflects inflation of costs over the last several
years. The adjusted AAGRA is multiplied by the replacement costs of
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the equipment within the facility to determine the value of a capital
expenditure.
The burden associated with using the capital expenditure definition
in the proposed standards was not quantified by the commenters; however,
if some of these problems can be resolved without changing the application
of the modification provisions, EPA finds no reason not to do so.
Accordingly, EPA is providing an alternative method to the General
Provisions.
As mentioned above, the alternative method for determining capital
expenditure enables refiners to use replacement costs rather than
original costs. An inflation index can be applied to the replacement
value of an affected facility to approximate the original cost basis of
the affected facility. The relationship between replacement and original
costs has been determined (Document Nos. IV-B-4 and IV-B-14) as:
Y = 1.0 - 0.575 log (X), where:
Y = the percent of the present replacement cost which is
equivalent to the original cost, and
X = the year of construction.
Using the above equations and the annual asset guideline repair allowance
(AAGRA) of 7 percent (see IRS Publication 534, page 20), capital expenditure
can be expressed in replacement dollars as:
Capital Expenditure = R x Y x 0.07, where:
R = existing facility replacement cost.
Another alternative method that was considered is similar to that
of the first in that an inflation index, Y (as defined above), and the
AAGRA basis of 7 percent are used to allow refiners to use replacement
costs. However, this second alternative would also allow refiners to
use the cost of the entire process unit rather than the affected facility
(the fugitive emission components). The second alternative would
reduce the number of units that would use a detailed costing of equipment.
However, the equipment covered by the standards represent a variable
portion of the total costs of all the equipment in a process unit.
Therefore, it is not practicable to assign a single percentage that
would reflect the modification costs contributed by fugitive emission
pieces. Thus, EPA is not adopting this alternative.
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Even though EPA was unable to establish an alternative that would
allow refiners to use the cost of the entire process unit, EPA would
consider estimations from refiners that clearly show that an expenditure
would be less than the quantity associated with a capital expenditure.
There may be a variety of ways that these estimations can be ma.de. For
example, a refiner may have proof that in certain units 5 percent of
the total replacement value at the process unit is the value of the
equipment covered by the standards. If an estimation clearly demonstrates
its results, EPA could quickly decide whether a process improvement
involves a capital expenditure. Based on the example, if the value of
the process improvement may be 0.04 percent of the replacement value of
the process unit, this would be clearly less than 12.5 percent of
5 percent of the value of the total unit. If an estimation does not
clearly show its results, then the time and effort required by EPA in
evaluating the estimation would not provide the owner or operator a
quick response and, therefore, a more-detailed costing of equipment
(either by estimating replacement or accounting existing equipment)
would be the owner or operators best approach. If EPA can judge easily--
through review of a clear demonstration that a process improvement does
not involve a capital expenditure, it will do so. In contrast, if
EPA's review raises concerns or questions, EPA will reject the estimation
unless further convincing support is presented.
Comment:
One commenter (IV-D-8) wrote that the General Provisions exempt
"process improvements" from being considered modifications if made
without incurring a capital expenditure; however, using the proposed
definition of "capital expenditure" limits the exemption. Another
commenter (IV-D-21) recommended deleting the modification provisions
which require that process improvements be accomplished without a
capital expenditure.
Response:
The General Provisions do not include a "process improvement"
exemption. However, in the proposed standards EPA stated its intent
that minor modifications would not be covered by the standards: "addition
or replacement of fugitive emission sources for the purpose of process
improvement which is accomplished without a capital expenditure shall
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not by itself be considered a modification under this subpart." The
capital expenditure criterion was included so that minor process
improvements in a process unit that cause an increase in emissions
would not subject an existing facility to this NSPS. After reviewing
these comments, EPA has maintained the same exemption. EPA considers
any increase in emissions that results from a process improvement with
a capital expenditure a "modification" unless one of the other exceptions
in the General Provisions applies.
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.
Comment:
One commenter (IV-D-30) argued that the "no capital expenditure"
exemption for modifications could be construed by a plant as including,
for example, the addition of fugitive components from existing inventory
of spare parts. The commenter requested that EPA make it clear that
the addition of equipment already in stock is still considered in
determining a capital expenditure.
Response:
As discussed in the response to the previous comment/the capital
expenditure criterion applies to process improvement or production rate
increase exemptions that are considered when determining whether an
increase in emissions at a facility results in a modification. This
criterion is used to judge if the activity results in a change in
operation. As such, a capital expenditure is determined by what is
added to a process unit, not by what is purchased. Accordingly, it
makes no difference whether the item was already in stock when the
process improvement occurred.
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4.3 SMALL FACILITIES
Comment:
Commenters (IV-D-9 and IV-D-23) stated that small refiners more
easily trigger the modification and reconstruction provisions of the
standards than do large refiners. A small capital expenditure on a
small unit would cause the unit to be classified as "modified" more
easily than the same expenditure would cause a large unit to be so
defined. Some commenters (IV-D-8 and IV-D-15) also remarked that the
definition of "capital expenditure" would impact small facilities more
severely.
Response:
The provisions of the standards can be triggered by several different
actions. Some of these actions are relative changes that are considered
important because they involve a certain percent of the cost of the
unit. Other triggering actions are absolute changes that are considered
important because they involve an absolute increase in air pollutant
emissions from the existing unit. Even if the reconstruction and
modification provisions are more burdensome on small refineries, the
overall impact of the standards is still reasonable, however. If the
commenter's claim is true, then there must be a difference between
units at small refineries on the one hand, and those at large refineries
on the other. The difference could be related to size, age, ability to
respond to today's changing markets, or myriad other factors. The
question of unit size, measured by throughput or equipment count, is
discussed in a previous response; the relationship between unit size
and firm size is not clear. In general, small changes can trigger the
provisions for units with comparatively few pumps and valves. However,
it is not clear that the capital expenditure criterion would be exceeded
quicker by a small process unit than by a large process unit. It is
not necessarily true that the cost of a given set of equipment would be
the same for a small and large process unit. Large process units can
use large equipment or small equipment (the costs of which would be
related, in a very general sense, to the size of equipment) and small
process units can use large or small equipment. The value of any one
pump in a process unit may be relatively small or large depending on
the specifications in a particular application, not solely on the size
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of the pump. The commenters did not mention specific small refinery
characteristics that would explain why small refiners might suffer a
greater burden than large refiners. Age and obsolescence of equipment,
the most obvious characteristics, do not appear to be significant
factors. There are no data to indicate that units in need of modernization
are situated predominantly at small refineries. Even if there are
differences and small refineries are disproportionately affected, EPA
does not consider this unreasonable because EPA believes that the
standards are appropriate for all existing facilities that become
affected by the standards.
For these reasons EPA concludes that the modification and reconstruction
provisions of the standards will not subject small refiners to unreasonable
adverse impacts.
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5.0 RECONSTRUCTION
Comment:
Several commenters (IV-D-4, IV-D-14, IV-D-15, and IV-D-21) wrote
that reconstruction costs should not be accumulated. Some commenters
suggested that costs should be considered over a 1-year period.
Response:
Since in enacting Section 111 Congress did not define the term
"construction," the question arose whether NSPS would apply to facilities
being rebuilt. Noncoverage of such facilities would have produced the
incongruity that NSPS would apply to completely new facilities, but not
to facilities that were essentially new because they had undergone
reconstruction of much of their component equipment. This would have
undermined Congress's intent under Section 111 to require strict control
of emissions as the Nation's industrial base is replaced.
EPA promulgated the reconstruction provisions in 1975, after notice
and opportunity for public comment (40 FR 58420, December 16, 1975), to
fulfill this intent of Congress. Since this turnover in the industrial
base may occur independently of whether emissions from the rebuilt
sources have increased, the reconstruction provisions do not focus on
whether the changes that render a source essentially new also result in
increased emissions.
Congress did not attempt to overrule EPA's previous promulgation
of Section 60.15 in passing the Clean Air Act Amendments in 1977. This
indicates that Congress viewed the reconstruction provisions' focus on
component replacement, rather than emissions level, as consistent with
Section 111. See, e.g., Red Lion Broadcasting Co. v. FCC, 395 U.S. 367
(1969); NLRB v. Bell Aerospace Division, 416 U.S. 267 (1974). Nor has
any Court questioned the Agency's authority to subject reconstructed
sources to new source performance standards. In fact, in ASARCO v.
EPA. 578 F. 2d 319, 328 n.31 (D.C. Cir. 1978), the D.C. Circuit suggested
that the reconstruction provisions may not go far enough toward preventing
possible abuses by owners seeking to avoid NSPS by perpetuating the
useful lives of their existing facilities indefinitely.
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Finally, coverage under §60.15 of establishing petroleum refinery
facilities comports well with the intent underlying Section 111. In
such cases, the refurbishment may transform the existing facility into
an essentially new facility. A key goal of Section 111 is to enhance
air quality over the long term and minimize the potential for long-term
growth by minimizing emissions through application of the best demonstrated
technology to new emission sources, concurrent with the turnover of
the Nation's industrial base. If owners are permitted to replace most
of the equipment in their existing facilities without applying the best
demonstrated technology, they will be installing new equipment without
minimizing emissions and maximizing the potential for long-term industrial
growth, as Congress sought in enacting Section 111. For this reason,
NSPS coverage of facilities that undergo substantial component replacement
through conversion accords with Section 111, even where some decrease
in emissions results from the conversion.
EPA promulgated the reconstruction provisions because failure to
require best control at sources that have become essentially new through
extensive component replacement would have undermined Congress's intent
that best technology be applied as the Nation's industrial base is
replaced. Failure to cover facilities that have undergone extensive
component replacement over a long period of time similarly postpones
the enhancement of air quality Congress sought under Section 111. The
D.C. Circuit recognized this when it expressed concern in the ASARCo
case that, absent a provision for aggregating replacement expenditures
"over the years," owners could evade the reconstruction provisions by
continually replacing obsolete or worn-out equipment. 578 F.2d 319,
328 n.31 (D.C. cir. 1978).
Section 60.15 currently defines "reconstruction" as the replacement
of components of an existing facility to such an extent that "the fixed
capital cost of the new components" exceeds 50 percent of the "fixed
capital cost" that would be required to construct a comparable entirely
new facility and EPA determines that it is technologically and economically
feasible to meet the applicable NSPS. Subsection (d) indicates that
the "new components" whose cost would be counted toward the 50 percent
threshold include those components the owner "proposes to replace." It
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is unclear under this wording whether a reconstruction has occurred in
the case of an owner who first seeks to replace components of an existing
facility at a cost equal to 30 percent of the cost of an entirely new
facility and then, shortly after commencing or completing those
replacements, seeks to replace an additional 30 percent. Specifically,
it is uncertain whether the owner should be deemed to have made two
distinct "proposals," or instead a single proposal.
For example, assume that a refinery owner refurbishes part of a
facility and six months later refurbishes other parts of the facility.
If the two actions were interpreted as separate "proposals" under
Section 60.15, neither might exceed the 50 percent replacement
cost threshold. Under this general interpretation, owners could avoid
NSPS coverage under Section 60.15 simply by characterizing their
replacement projects as distinct "proposals," even where the component
replacement is completed within a relatively short period of time.
EPA did not intend, in promulgating the reconstruction provisions,
that the term "propose" exclude from NSPS coverage facilities undergoing
extensive component replacement. Failure to cover these sources serves
to undermine Congress's intent that air quality be enhanced over the
long term by applying best demonstrated technology with the turnover in
the Nation's industrial base.
To eliminate the ambiguity in the current wording of Section
60.15 and further the intent underlying Section 111, the Agency is
clarifying the meaning of "proposed" component replacements in Section
60.15. Specifically, the Agency is interpreting "proposed" replacement
components under Section 60.15 to include components which are replaced
pursuant to all continuous programs of component replacement which
commence (but are not necessarily completed) within the period of time
determined by the Agency to be appropriate for the individual NSPS
involved. The Agency is selecting a 2-year period as the appropriate
period for purposes of the petroleum refinery equipment leak NSPS
(Subpart GGG). Thus, the Agency will count toward the 50 percent
reconstruction threshold the "fixed capital cost" of all depreciable
components (except those described above) replaced pursuant to all
continuous programs of reconstruction which commence within any 2-year
period following proposal of these standards. In the Administrator's
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judgment, the 2-year period provides a reasonable, objective method of
determining whether an owner of one of these facilities is actually
"proposing" extensive component replacement, within the Agency's original
intent in promulgating Section 60.15.
EPA realizes that the petroluem refinery industry is constantly
changing; however, the Agency believes that this 2-year limit will
assure that the owner would have to make a substantial change to the
facility to reach the 50 percent threshold.
The administrative effort to keep the required records should not
be a burden on industry. The recordkeeping required under a cumulative basis
interpretation of reconstruction is the same as the recordkeeping that
would be required under a strictly project-by-project basis interpretation.
In either case, the dollar amount of the component replacement taking
place at the affected facility must be determined and recorded. Once
this dollar amotmt has been determined for each change and conversion,
the additional requirement of keeping this information on file at the
refinery does not appear to be an excessive burden.
Comment:
Two commenters (IV-D-8 and IV-D-14) requested EPA to exclude from
the reconstruction provisions the costs of equipment replacement done
for routine maintenance purposes. Similarly, commenters (IV-D-4 and
IV-D-15) expressed concern with the reconstruction provisions as they
apply to process unit turnarounds. Commenters stated that process unit
turnarounds are maintenance procedures performed to assure efficient
and safe operation and, therefore, turnaround replacements should be
excluded from reconstruction provisions. Another commenter (IV-D-4)
requested that replacements of equipment due to fire, explosions, or
other accidental causes should be exempt from reconstruction.
Response:
As discussed above, reconstruction costs are the fixed capital cost
or the capital needed to provide all the "depreciable" components,
while most routine maintenance practices involve the use of non depreciable
components.
Because routine maintenance items (valve packings, pump seals,
replacement rupture disks, nuts and bolts) cost very little compared to
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the cost of equipment (covered by the standards) in a process unit, it
is very unlikely that routine maintenance would trigger a reconstruction
even if accumulated over several years. The cost of these items is
relatively small. In EPA's judgment, maintaining records of the repair
or replacement of these items may constitute an unnecessary burden.
Moreover, EPA does not consider the replacement of these.items an
element of the turnover in the life of the facility. Therefore, in
accordance with 40 CFR 60.15{g), the final standards (Subpart GGG) will
exempt certain frequently replaced components from consideration in
applying the reconstruction provisions to petroleum refinery process
unit facilities.
The costs of these frequently replaced valve parts will not
be considered in calculating either the "fixed capital cost of the new
components" or the "fixed capital cost that would be required to construct
a comparable, entirely new facility" under Section 60.15. In EPA's
judgment, these items are pump seals, valve packings, nuts and bolts,
and rupture disks. Replacements of pumps, valves, and other fugitive
equipment at turnarounds or at other times are included in reconstruction
costs. For turnarounds that involve significant refurbishment of a
process unit, EPA would likely consider this a reconstruction. EPA
also considers it appropriate to include in reconstruction costs the
replacement of equipment due to the accidental loss of an original
component, since the reason for an owner's refurbishing a facility has no
bearing on whether the facility itself is comparable to a new source
for which application of the best control systems is reasonable.
Comment:
One of the commenters (IV-D-14) requested that the reconstruction
provisions not apply at all, or only when the number of replacement
valves exceeds 50 percent of the number of existing valves. The commenter
reasoned that there is an economic justification for requiring compliance
with NSPS if, for example, reactors, towers, or heaters are replaced,
but not fugitive emission sources.
Response:
The standards apply to fugitive emission sources only. EPA considers
it appropriate to cover process units that are essentially new. The
costs considered are only those associated with the equipment covered
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by the standards. The commenter offered no sypport for his statement
that the standards are not economically justified when applied to
fugitive emission sources only. EPA considers the standards to reflect
BDT (considering costs) for sources that become affected through recon-
struction or modification. In response to the commenter's preference
that the affected facility include valves only, EPA does not disagree
with the concept of using the number of components as the basis for
reconstruction. However, since there are several types of components
covered by the standards, this approach would ignore replacements of
other key portions of the facility. Thus, EPA will use the cost of
replacements for all the equipment covered by the standards to determine
when a reconstruction has occurred.
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6.0 LEGAL
Comment :
One commenter (IV-D-21) requested that facilities commencing
modification or reconstruction should be subject to compliance on the
date of final promulgation rather than January 4, 1983, the date
of proposal.
Response:
Under Section lll(a)(2) of the Clean Air Act, a "new source"
subject to applicable standards is defined to be any source on which
construction or modification commenced after the date on which the
standards were proposed. The standards for equipment leaks of VOC
within petroleum refineries were proposed on January 4, 1983. A
group of process unit equipment (specified in the standards) or a
compressor on which construction or modification commenced after that
date is, therefore, a new source under the Act and subject to the
standards. The commenters suggest that EPA change the applicability
date to the date on which EPA promulgates the standards. Changing the
applicability date of the standards would be inconsistent with the
plain language of the Clean Air Act.
Comment:
Two commenters (IV-D-21 and IV-D-22) argued that the proposed
standards are unnecessary because hydrocarbons generally do not affect
human health as reflected in the EPA's rescinding of the national ambient
air quality standards (NAAQS) for hydrocarbons (HC), and because there is
no consistent quantitative relationship between the concentration of
ambient air ozone and hydrocarbons. Commenters added that there
is no need to regulate VOC in attainment areas.
Response:
The revocation notice for the NAAQS for HC does not directly
affect the development of this NSPS. As explained in the revocation
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notice, the NAAQS for HC were intended only as guides in the development
of State implementation plans (SIP) to attain the original NAAQS for
photochemical oxidants (recast as NAAQS for ozone in 1979). EPA revoked
the NAAQS for HC because EPA determined that there is no single, univer-
sally applicable relationship between HC and ozone and that HC as a
class apparently do not produce any adverse health or welfare effects
at concentrations at or near ambient levels. However, the revocation
was in no way intended to restrict EPA or State authority to limit VOC
emissions (including HC as a class) where necessary to limit the for-
mation of ozone. Since VOC are precursors to ozone, and ozone has been
determined to be harmful to public health, and welfare, significant
sources of VOC are subject to regulation under Section 111 of the Clean
Air Act (46 FR 25656; May 9, 1981).
EPA clearly documented the need to regulate VOC in order to protect
public health and welfare in the EPA publication "Air Quality Criteria
for Ozone and Other Photochemical Oxidants" (Docket No. IV-A-1). VOC
emissions are precursors to the formation of ozone and other oxidants
(ozone). Ozone results in a variety of adverse impacts on health and
welfare, including impaired respiratory function, eye irritation,
necrosis of plant tissues, and the deterioration of synthetic rubber.
In setting new source performance standards, 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 NAAQS under Sections 109 and 110 of the Clean Air Act.
The intent of Congress in establishing NSPS was to establish a single
level of stringency for all State limits, thereby preventing States
from soliciting industry with lenient air pollution requirements and
causing increased air pollution from new sources. The standards will
limit VOC emissions from newly constructed, modified, and reconstructed
refinery process units and will result in emission reductions well into
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 preventing future air quality problems.
Clearly, residents in both attainment and nonattainment areas would
benefit from these standards. The NSPS complements the ambient air
quality-based rules as a means of achieving and maintaining the NAAQS,
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while on a broader basis it prevents new sources from making air
pollution problems worse regardless of the existing quality of ambient
air. Therefore, while new source standards may help in the attainment
of NAAQS, the consideration of attainment or nonattainment of the NAAQS
does not influence directly the decision to set standards of performance,
Comment:
The same commenters (IV-D-21 and IV-D-22) stated that the standards
would place an unreasonable burden upon the industry. The standards
should be considered a major rule and not be exempt from provisions of
Executive Order 12291.
Response:
Executive Order 12291 requires that a regulatory impact analysis,
thoroughly examining costs and benefits of a rule, be prepared in
connection with every major rule. A major rule is any regulation
which 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
United States-based enterprises to compete with foreign-based
enterprises in domestic or export markets.
An economic analysis of these standards was prepared. Economic
impact estimates presented in the background information document for
the proposed standards, and summarized in the preamble to the proposed
regulation (48 FR 279; January 4, 1983), showed that no unreasonable
economic impacts are expected. Because no unreasonable economic impacts
are expected and none of the criteria for a major rule has been met, no
additional regulatory impact analysis has been prepared.
Comment:
One commenter (IV-D-21) further stated that EPA acknowledged that
no new major refineries are likely to be constructed in the U.S. in the
coming decade and, thus, all the emission reductions quantified in the
background information document would occur at existing refineries.
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Response:
Projections of units affected by new source performance standards
are discussed in Appendix E of the BID for the proposed standards. EPA
projected that up to 100 new units and 182 modifications/reconstructions
of existing process units will be subject to the standards. EPA recognizes
that few, if any, grass root refineries will be built. However, EPA
also recognizes that it is appropriate to cover the industry as it
rebuilds through modification and reconstruction and through the addition
of new processing units at existing refineries.
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7.0 TEST METHODS
Comment:
One commenter (IV-D-4) requested that EPA propose the entire
rulemaking, including appropriate reference methods, at one time.
The commenter said that the "failure to provide either Reference Method
21 or Reference Method 22 as appendices to these proposed rules prevents
an accurate analysis of the impact of the proposed rulemaking." The
application of Reference Method 22 to refinery flares was questioned.
Response:
EPA proposed Reference Method 21 on January 5, 1981, as an appendix
to the proposed standards of performance for fugitive VOC emission
sources in the synthetic organic chemicals manufacturing industry (SOCMI).
EPA generally proposes reference methods in conjunction with the first
standards that use the method. Method 21 would normally have been
promulgated with the SOCMI standards. However, after reviewing the
comments and incorporating changes, it was decided to promulgate Method 21
before promulgation of the SOCMI NSPS because several additional regulations
were scheduled for promulgation in the near future that specified the
use of Method 21. EPA considered the comments received during the comment
period for the proposed refinery fugitive standards and decided that no
additional changes to Method 21 were needed. Method 21 was promulgated
on August 18, 1983 (48 FR 37598).
Reference Method 22 was initially promulgated on August 6, 1982.
In the January 4, 1983, preamble to the proposed petroleum refinery
standards, EPA stated that revisions to Method 22 would be published
soon in the Federal Register to broaden its applicability to flares.
This method was revised on October 18, 1983, in the rulemaking on
SOCMI.
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Comment:
Two commenters (IV-D-4 and IV-D-15) requested that EPA clarify
the use of hexane or methane in calibrating the portable analyzer. It
was suggested that a correction factor be provided to put all measurements
on a consistent basis using hexane as the primary standard. The use of
an unconnected methane calibnation would nesult in a highen numben of
leaking components being detected.
Response;
The basis fon selection of the calibnation gases fon the analyzen
was evaluated befone pnoposal. It was necognized that thene ane a
numben of potential pnocess stneam components and compositions that can
be expected. Since all analyzen types do not nespond equally to diffenent
compounds, it was necessany to establish a nefenence calibnation matenial.
Based on the expected compounds and the infonmation available on instnument
nesponse factons, hexane was chosen initially (see Contnol of Volatile
Onganic Compound Leaks fnom Petnoleum Refineny Equipment, EPA-450/2-78-036,
Document No. II-A-6) as the nefenence calibnation gas fon EPA test
pnognams. At that time, the measunement distance was 5 centimetens
(cm), and calibnations using hexane wene conducted at appnoximately 100
on 1,000 ppm levels. Aften initial equipment leak data wene collected
at 5 cm, pnoblems wene identified with the nepnoducibility of nesults
at this distance, as discussed in Appendix D of the BID fon the pnoposed
standands. The monitoning pnocedune was nevised so that measunements
wene made at the sunface of the intenface, on essentially 0 cm. This
change was accompanied by a change in the leak definition to 10,000 ppm.
At this concentnation hexane calibnation standands wene not neadily
available commencially. Also based on a neview of the data, it appeaned
that methane was a mone nepnesentative nefenence calibnation matenial
at 10,000 ppm levels. Based on this conclusion, and the fact that
methane calibnation standands ane neadily available at the necessany
calibnation concentnations, methane was added as an acceptable calibnation
gas.
Since then, studies have been completed that measuned the nesponse
factons fon sevenal instnument types. The nesults of these studies
show that the nesponse factons fon methane and hexane ane similan
enough fon the punposes of this method fon these two gases to be used
7-2
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as calibrants interchangeably. Therefore, the accepted calibration
materials remain as hexane and methane. In response to the commenters,
EPA will likely use methane as the calibration gas. Because EPA does
not consider the difference in the number of leaks found using either
calibration gas to be substantially different, a correlation factor to
put all measurements on a consistent basis was not provided.
Comment;
One commenter (IV-D-22) warned that when used at a concentration
of 10,000 ppm, hexane could condense on the walls of the container,
resulting in distorted calibration results. Also, since the lower
explosive limit for hexane is 12,000 ppm, calibrating with hexane could
be a safety hazard.
Response:
There are a number of difficulties with using hexane as a calibrant.
Based on EPA's experience, methane is the preferred calibrant. The use
of hexane may lead to operators finding more leaks during monitoring
because, if hexane condenses on the walls of the container storing the
instrument calibration gas, the concentration of the gas may fall below
10,000 ppm. In this instance, an instrument would signal that a leak
has occurred although the actual concentration is below 10,000 ppm.
The fact that 10,000 ppm as hexane is close to 12,000 ppm (lower
explosive limit of hexane) can be added to the factors that led EPA to
require the instrument to be intrinsically safe for operation in explosive
atmospheres. .
Comment;
Two commenters (IV-D-6 and IV-D-12) remarked on the reasonableness
of the instrument calibration requirements. It was argued that the
"zero" calibration could be performed adequately_with ambient air.
Also, daily instrument calibration was deemed too burdensome and it
was felt that weekly calibration should suffice.
Response:
The specification of air (less than 10 ppm hydrocarbon) as the
zero air calibrant was intended to allow the use of relatively clean
ambient air. Method 21 now specifies 10 ppm, whereas it specified
3 ppm when the standards were proposed. The use of air with less than
10 ppm hydrocarbon does allow calibration of the instrument at essentially
7-3
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zero reading. This is particulaYly important for "no detectable emission"
requirements and to ensure that the monitor is functioning properly.
Zero air calibrants can be purchased or generated easily (e.g., carbon
filtered drawn air). Thus, there is no need to change the standards to
require the zero air calibrant as ambient air only. There may be
occasions when the ambient air within a refinery could have a significant
VOC (organics) concentration, and calibrating with that ambient air
would be inappropriate.
Instrument calibration is required on each day of its use. This
is not burdensome. The procedure is relatively simple, does not require
a laboratory, and takes only 15 to 30 minutes. The cost of calibrating
the instrument on a daily basis was included in the cost of leak detection
and repair programs. Moreover, the proper use and calibration of the
monitor is vital to effective leak detection and repair. A semiannual
performance evaluation of the instrument is also required by Method 21.
EPA has no reason to believe that weekly calibration would provide
sufficiently stable readings from the monitor. EPA's experience indicates
that daily calibrations are sufficient, and that less frequent calibrations
may not be adequate. Thus, no change in instrument calibration requirements
was made.
Comment:
One commenter (IV-D-22) noted that proposed Reference Method 21
refers to monitoring techniques which do not distinguish between VOC
and non-VOC hydrocarbons. This may result in a component having a
monitor reading greater than 10,000 ppm while actual VOC emissions
would be less.
Response:
The commenter is correct that Method 21 responds to non-reactive
organic compounds (e.g., methane). However, the monitor reading is not
intended to be a quantitative measure of the reactive organic compounds
(VOC) in the leak. Its purpose is rather to indicate whether a leak
exists of sufficient magnitude to warrant remedial action. EPA is
using the "in VOC service" definition to exclude equipment that would
not contain enough reactive organic compounds to warrant coverage by the
standards. Thus, if a piece of equipment is in VOC service and a leak
of 10,000 ppm is detected, EPA judges that repair is warranted. For
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this reason, correcting the 10,000 ppm leak definition to "VOC only"
is unnecessary.
Comment:
A commenter (IV-D-22) suggested that there was inconsistency in
EPA's decision not to allow leak detection using a soap solution because
the magnitude of leak rates is difficult to assess, yet the VOC
monitoring instrument "would yield qualitative indications of leaks."
Response:
Since proposal, an alternative screening procedure has been added
to Method 21 for those sources that can be tested with a soap solution.
These sources are restricted to those 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 appli-
cable sources and the potential leak sites are observed to determine if
bubbles are formed. If no bubbles are formed, then no detectable
emissions or leak exists. If any bubbles are formed, then the instru-
ment measurement techniques must be used to determine whether a leak
exists, 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 valve 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 regu-
lation 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 cor-
rectly identify and score a standard series of test bubbles. It has
been reported that trained observers can correctly and repeatedly
7-5
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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 the applicable regulation. The
alternative procedure that has been included will allow more rapid
identification of potential Teaks for more rigorous concentration
measurement using a monitoring instrument.
Comment;
A commenter (IV-D-8) argued that it is unreasonable to require
annual monitoring of "entire vent or control systems." These piping
systems are typically operated at low pressure (which minimizes the
amount of potential leakage) and are routed overhead in pipe racks and
are, therefore, inaccessible.
Response;
Method 21 is used to monitor closed vent systems used in complying
with the standards. Method 21 requires the use of an organic compound
monitor only where leaks might occur. Where no leaks can occur (like
header-pipes), Method 21 requires only a visual inspection to ensure
the closed vent system has not deteriorated and is not leaking where
leaks are not expected.
Closed vent systems used to comply may be operated at low pressure
or high pressure. Either type of system may leak at connections and,
therefore, the annual test is appropriate. If an owner or operator
uses an" approach of ensuring a leak-free system, such as monitoring
oxygen in a vacuum system, EPA will consider whether this approach can
be used rather than Method 21, as specified in §60.13(i) of the General
Provisions. Like other sources that are difficult-to-monitor, annual
monitoring, if needed, in a pipe rack is not unreasonable in light of
the emissions that would occur from such a leak.
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8.0 RECORDKEEPING AND REPORTING
Comment; '
A number of commenters (IV-D-8, IV-D-12, IV-D-21, and IV-D-22)
wrote that the proposed recordkeeping requirements are needlessly
complex and burdensome. One commenter (IV-D-22) estimated that the
additional paperwork burden would amount to 2 person-months per year
per affected refinery. Two commenters (IV-D-8 and IV-D^12) listed
specific recordkeeping requirements that should be deleted. These
requirements include records of: (1) identification numbers for instru-
ments, operators, fugitive emission components, leaking components,
components in vacuum service, and components designated as difficult-to-
monitor or unsafe-to-monitor; (2) repair methods; (3) logging shutdown
and startup for closed vent systems; (4) signature of owner or operator
(or designee) whose decision it was that repair could not be effected
without a process shutdown; (5) expected date of repair; (6) explanation
for unsafe or difficult-to-monitor designation; and (7) schematics,
design specifications, and operations records on flares used as control
devices.
Response:
Before the standards were proposed, EPA considered three alternative
levels of recordkeeping. The proposed recordkeeping requirements are
considered the minimum consistent with adequate enforcement; thus, the
paperwork burden on owners and operators is the minimum amount necessary
to enforce the standards adequately. At proposal, EPA weighed the
paperwork burden against the enforcement authority (Federal, State and
local) to determine compliance with the standards and selected the
proposed requirements.
Compliance with the final standards will be generally determined
through inspection. However, because the intent of the standards is a
8-1
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continuous reduction in equipment leaks of VOC and continuous inspection
by enforcement authorities is not possible, records must be maintained
if an inspector is to determine retrospectively whether a facility is in
compliance with the standards. EPA considers the required records for
an owner or operator's leak detection and repair program necessary to
document the operator's compliance efforts. These records would likely
be maintained by a prudent owner or operator, and should therefore add
little additional recordkeeping burden.
Commenters did not explain why specific records would not be needed
by enforcement authorities. EPA considers the required records for an
owner or operator's leak detection and repair program necessary to docu-
ment the operator's compliance efforts. For example, when an unsuccessful
repair attempt is made, a record of the attempted or anticipated methods
of repair shows what effort was made by the operator and the reason for
delay. Without such records, EPA and other enforcement authorities
would not be able to determine compliance with the standards. Addi-
tionally, an expected repair date is obviously required in such cases
to prevent a known leak from being allowed to persist. Records, such
as identification numbers for components in vacuum service, can be used
to check compliance with the standards. The same reasons are applicable
to records for operation of control devices. Obviously, a control
device (including flares) serves no function when not operating. As
such, demonstration of shutdown or flame-out periods is necessary to
show compliance. These records would likely already be maintained by a
prudent owner or operator, and should therefore add little additional
recordkeeping burden.
The records required for identifying fugitive emission components,
and control device schematics and design data are not unreasonably
burdensome. This information would be developed only once, and would
require changing or updating only if the facility were changed. The
control device schematics and design data should be available to plant
engineers already, and as such do not represent an added burden. For
new facilities, the reasons why a component must be installed in a
location which makes it difficult or unsafe to monitor must be documented
prior to installing the component in such a position. The number of
difficult-to-monitor or unsafe-to-monitor components will be small and,
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therefore, should not create an excessive recordkeepiny burden. After
considering the comments that the recordkeeping requirements are needlessly
complex and burdensome, EPA decided to promulgate the recordkeeping
requirements as proposed.
Comment: ,
One commenter (IV-D-22) complained that the demonstration required
for a variance from the 15-day repair requirement is a reeordkeeping
nightmare due to the many different types and sizes of valves.
Response:
The proposed standards permit delay of repair beyond the 15-day
period as provided in Section 60.592-9. The provisions for delay for
repair are automatic, and not a variance (as the commenter implied)
that must be applied for as suggested by the commenter. EPA recognizes
that some repairs cannot be performed on line, and that not all compo-
nents can be isolated without a process unit shutdown. These repairs
should be readily understood by the operator. Therefore, a relatively
straightforward response (e.g., the seal must be replaced at a shutdown--
pump cannot be bypassed; there is no spare) sufficiently informs EPA
why repair is delayed for a particular component and, accordingly, can
be used to determine whether compliance with the standards has been
maintained. The intent of the recordkeeping provision is to ensure
that all technically feasible repairs are performed within 15 days.
Comment:
A commenter (IV-D-14) wrote that the actual cost for a leak
detection and repair program as required by the standards would be
higher than EPA estimated because daily recordkeeping of components
replaced frequently is not included, nor are the associated costs
necessary to determine when a process unit becomes an affected facility.
Response:
The recordkeeping associated with frequent replacements and
evaluating changes in operation would be something a plant would typi-
cally do on its own for purposes other than complying with the standards
(e.g., tracking the cost of production or assuring that adequate spare
parts or components are stocked). A small additional increase might be.
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experienced by the owner as a result of these standards. However, the
entire cost of recordkeeping should not be attributed to the standards
as indicated by the commenter. The exclusion of certain routine replace-
ment items from reconstruction calculations (see Section 5) and the
addition of alternative methods for determining capital expenditure
(see Section 4) eases the recordkeeping needs. The cost of pre-
construction efforts, pre-modification efforts, or pre-reconstruction
efforts are not accounted for explicitly in the impacts of the standards
because they are considered part of the overall cost of the owner's
decision to construct, modify, or reconstruct. As such, it would be
very difficult to make reasonable estimates of the cost to determine when
a process unit becomes an affected facility. But, EPA believes that
those costs are insignificant in comparison to the costs associated
with other activities that occur during these efforts. In any cases,
these costs would not raise the overall cost effectiveness ($130/Mg) to
an unreasonable level.
Comment;
Two commenters (IV-D-30 and IV-D-22) remarked that the standards are not
enforceable. As a result one of the commenters (IV-D-22) concluded that
those facilities not following the NSPS would have a competitive advantage
of reduced cost over those facilities complying with the regulations.
Additionally, the other commenter (IV-D-30) strongly opposed the proposal
of no reporting requirements which, the commenter noted, undermines the
effectiveness of the standards and the ability of EPA and the States to
enforce them. Reporting requirements, according to the commenter,
would enhance self-enforcement. The commenter speculated that the
reason for EPA's excluding reporting requirements was OMB's role in
administering the Paperwork Reduction Act, which, the commenter asserted,
does not give OMB or EPA the authority to compromise the effectiveness
of the standards. The commenter was also concerned that no records are
required for equipment not found to be leaking, adding that.a much
better incentive to comply with the regulation would exist if records
were required to be kept on all monitored equipment.
Response:
Reports, records, and inspections will be used to ensure compliance
by all facilities subject to these standards. State and EPA Regional
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air quality control authorities have successfully implemented regulations
similar to the standards. At proposal EPA stated that routine reporting
was not required. Reporting requirements were limited to notifications
of construction, anticipated startup and actual startup, and an intention
to comply with one of the alternative standards. As stated in the
preamble for the proposed standards, these reporting requirements would
not provide a mechanism for checking the thoroughness of the industry's
efforts to reduce fugitive emissions of VOC. As stated in the preamble
to the proposed standards, compliance would be assessed through in-plant
inspections.
EPA has decided that reporting is necessary to assess implementation
of the work practice and equipment requirements of the standards. EPA
agrees with the commenter that facilities not complying with the stan-
dards might have an unfair advantage (albeit, somewhat small). More
importantly, facilities not complying with the standards, would not be
using BDT as required by the Clean Air Act, the purpose of which is to
prevent new air pollution problems. 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 enforceability of the standards. EPA's conclusion that reports are
useful is also based on the experience of the State and local air quality
control boards.
As explained at proposal, three alternatives were considered for
reporting requirements. The three alternatives represented trade-offs
among varying amounts of 'in-plant inspections and report preparation
for enforcement. The first alternative required minimal reporting and
relied on inspections for enforcement. The third alternative relied
almost totally on reports and would require minimum inspections to
judge compliance. The second alternative represented a compromise with
some reporting and some inspections required and is included in the
final regulations. These reporting requirements, however, have been
streamlined to include reporting of data on leak detection and repair
of pumps, valves, and other equipment types only-. In addition, periodic
reports are on a semiannual rather than quarterly basis, and the require-
ment for certification of reports has been eliminated. The semiannual
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reporting requirements may be waived for affected sources in any State
that is delegated authority to enforce these standards, provided EPA
approves reporting requirements or an alternative means of source
surveillance adopted by the State. Such sources would be required to
comply with the requirements adopted by the State.
The following reporting requirements were added to the standards
since proposal:
Each owner or operator must submit semiannual reports,
beginning 6 months after the initial startup date. The initial semi-
annual report includes:
(1) Process unit identification,
(2) Number of valves subject to the requirements excluding those
valves designated for no detectable emissions,
(3) Number of pumps subject to the requirements excluding those
pumps designated for no detectable emissions and those pumps enclosed
and vented to a control device, and
(4) Number of compressors subject to the requirements excluding
those compressors designated for no detectable emissions and those
compressors enclosed and vented to a control device.
All subsequent semiannual reports must include:
(1) Process unit identification, and
(2) For each month during the semiannual reporting period,
the number of valves, pumps, and compressors for which leaks were
detected and the number of valves, pumps, and compressors for which
leaks were not reported.
The semiannual reports will present the facts that explain each
delay of repair and, where appropriate, why a process unit shutdown was
technically infeasible. In addition, the semiannual reports will give
dates of process unit shutdowns which occurred within the semiannual
reporting period, and revisions to items reported according to paragraph
(b) if changes have occurred since the initial report or subsequent
revisions to the initial report.
The Paperwork Reduction Act of 1980 (PL-511) requires clearance
from the Office of Management and Budget (OMB) of reporting and
recordkeeping requirements that qualify as an "information collection
request" (ICR). For the purposes of OMB's review, an analysis of the
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burden associated with the reporting and recordkeeping requirements of
this regulation has been made. During the years 1984 and 1985, the
average annual burden of the reporting and recordkeeping requirements
of this regulation to industry would be about 20 person-years.
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APPENDIX A
INCREMENTAL COST EFFECTIVENESS OF CONTROL TECHNIQUES FOR
EQUIPMENT LEAKS OF VOC
A-l
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APPENDIX A
INCREMENTAL COST EFFECTIVENESS OF CONTROL TECHNIQUES
FOR EQUIPMENT LEAKS OF VOC
Table A-l summarizes the individual component control impacts and
the incremental cost effectiveness for each individual component and
control technique. The individual component control impacts are derived
in Tables A-2 through A-13. The net annualized cost, emission reduction,
cost effectiveness, and incremental cost effectiveness of the control
techniques are discussed in Chapter 2.0.
A-2
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Table A-1. SUMMARY OF THE INDIVIDUAL COMPONENT CONTROL IMPACTS3
Fugitive Emission
Source
Pressure relief devices
Compressors
Open-ended valves
Sampling connection
systems
Valves
Pumps
Control Technique
Quarterly LDR
Monthly LDR
Rupture disks'1
Controlled degassing
vents
Caps on open ends
Closed purge sampling
Quarterly LDR
Monthly LDR
Sealed bellows valves
Annual LDR
Quarterly LDR
Monthly LDR
Dual mechanical seal
system
Emission Reduction
(Mg/yr)
4.4
5.3
9.8
16.5
2.8
2.6
66
77
110
3.0
9.8
11.5
13.9
Average Cost
Effectiveness13
($/Mg)
(170)
(no)
410
150
460
810
(110)
(60)
4,700
.860
157
158
2,000
Incremental Cost
Effectiveness0
($/Mg)
(170)
250
1,000
150
460
810
(110)
310
16,700
860
(140)
170
10,900
(xx) - Cost savings
LDR =• Leak detection and repair.
a • '
Costs and emission reductions are based on fugitive emission component counts in Model B from the BID for the proposed
standards, EPA-450/3-81-015a, page 6-3, and from Tables A-2 through A-13 of this appendix.
b
Average Cost Effectiveness - net annual!zed costs per component + annual VOC emission reduction per component.
c
Incremental Cost Effectiveness » (net annual!zed cost of the control technique - net annualized cost of the next less
restrictive control technique) + (annual emission reduction of control technique - annual emission reduction of the
next less restrictive control technique).
d
Underlined control techniques were selected as basis for standards.
A-3
-------
Table A-2. .PRESSURE RELIEF DEVICE IMPACTS , ._. .
(May 1980
Per Pressure
Relief Device
Item/Control Technique
Installed Capital Cost
Annual i zed Capital Costsc
A. Control Equipment
B. Initial Leak Repaird
Annual i zed Operating Costs
A. Maintenance6
•' B. Miscellaneous^
1. Monitoring9
2. Leak Repaird
3. Administrative
and Support"1
Total Annual Costs
Before Credit
Recovery Credit1
Net Annual i zed Costs J
Total VOC Emission
Reduction (Mg/yr )k
Cost Effectiveness
($/Mg VOC)1
Incremental Cost
Effectiveness11"
($/Mg VOC)
dollars)
Quarterly
LDR
a
0
a
0
a
a
19
0
7.6
27
135
(110)
0.63
(170)
(170)
Monthly
LDR
a
0
a
0
—a
__a
58
0
23
81
161
(80)
0.75
(110)
250
Rupture
Disks
b
3,100
^
600
0 .
160
120
0
0
0
880
300
580
1-4
410
1,000
* V-
(XX) = Cost Savings
(LDR) = Leak Detection and Repair
Model Unit B: 7 pressure relief valves
Emission Reductions
Quarterly LDR = 7 x 0.63 Mg/yr = 4.4 Mg/yr
Monthly LDR = 7 x 0.75 Mg/yr = 5.3 Mg/yr
Rupture Disks = 7 x 1.4 Mg/yr = 9.8 Mg/yr
A-4
-------
Table A*2,. PRESSURE RELIEF DEVICE IMPACTS
(May 1980 dollars)
(Continued)
aCost of monitoring instrument is not included in this analysis.
bCapital cost for rupture disk is from BID. for proposed standards
Table 8-1.
C0btained by multiplying capital recovery factor (2 years, 10 percent
interest = 0.58) by capital cost for rupture disk and capital recovery
factor (10 years, 10 percent interest = 0.163) by .capital cost for all
other equipment (rupture disk holder, piping, valves,- pressure relief
valve). Based on new installation cost 0.163 (3100 - 230) + 0.58
(230) = 600.
dLeaks are corrected by routine maintenance in the absence of the
standards; therefore, no cost is incurred for repair.
e0.05 x capital cost. From BID for proposed standards, Table 8-5.
f0.04 x capital cost. From BID for proposed standards, Table 8-5.
QMonitoring labor hours (i.e., number of workers x number of components
x time to monitor x times monitored per year) x $18 per hour. Assumes
2-man monitoring team per relief valve, 8 minutes monitoring team per
valve.
"0.40 x (monitoring cost t leak repair cost).
standards, Table 8-5.
From BID for proposed
"•Recovery credit based on uncontrolled VOC emission factor of 3.9 kg/day
(BID Table 3-1) and 44 percent control efficiency for quarterly
inspections (BID Table F-7), 53 percent control efficiency for monthly
inspections, and 100 percent for rupture disks. Control efficiency
for monthly inspections is estimated based on the method used to
calculate control efficiency for quarterly inspections in Table F-7
(footnote f) of the BID for the proposed standard. [Ratio of estimated
control efficiency for gas/vapor valve ABCD model (monthly inspections)
to gas/vapor valve LDAR model estimate (BID Table F-3) multiplied by
safety /relief valve ABCD model control effectiveness for monthly
inspections (0.68) based on Table 7-1, BID for proposed standard
ABCD factors: A = 0.74, B = 0.95, C = 0.98, D = 0.98]. Therefore,
control efficiency for monthly inspections = (g 53) (0.703) - Q 53
(0.91)
Recovered product valued at $215/Mg VOC (from BID Table 8-5).
Recovered emissions:
Quarterly LDR = 3.9 kg x 0.44 x 365 days x 1 Mg = 0.63 Mg _
day yr 1000 kg yr-relief device
Monthly LDR = 3.9 kg x 0.53 x 365 days x 1 Mg = Q.75 Mg _
day yr 1000 kg yr-relief device
A-5
-------
Table A~2. PRESSURE RELIEF-DEVICE IMPACTS
(May 1980 dollars)
(Concluded)
Rupture Disk = 3«9 kg
day
365 days x 1 Mg = 1.4 Mg
yr 1000 kg
yr-relief device
JTotal annual cost (before credit) minus recovery credit.
^Based on uncontrolled VOC emission factor and control efficiencies for
each control technique in footnote i.
1 Obtained by dividing net annualized cost by total VOC emission
reduction.
'"•Incremental cost effectiveness =
Net annual!zed cost of
control technique
Net annualized cost of
next less restrictive control
Annual vOC emission reduction
of control technique
Annual VOC emission reduction
of next less restrictive control
A-6
-------
Table A-3, COMPRESSOR SEAL IMPACTS.
1980 dollars)
Per Compressor '
Item/Control Technique
Closed Vent and Seal System
Installed Capital Cost*
Annuallzed Capital Costs
Control Equipment*3
Annualized Operating Costs
8,000
1,300
«. Maintenance4-
B. Miscellaneous*1
Total Annual Costs
Before Credit
Recovery Credit6
Net Annuallzed Costsf
Total VOC Emission
Reduction (Mg/yr)9
Cost Effectiveness
($/Mg VOC)h
400
320
2,020
1,180
840
5.5
150
Model Unit 8: 3 compressors
Emission Reductions:
3 x 5.5 Mg VOC/yr » 16.5 Mg/yr.
Capital cost from BIO for proposed standards, Table 8-1.
b0.163 capital recovery factor x capital cost; from BID
for proposed .*:ndards, Table 8-5.
C0.05 x capital-cost. From BID for proposed standards, Table 8.5.
-------
T^ble A*4, OPEN-ENDED LINES IMPACTS
(May 1980 dollars)
Per Open-ended Line
Item/Control Technique
Caps
Instal led Capital Cost3
AnnualIzed Capital Costs
Control Equipment"
Annuitized Operating Costs
A. Maintenance0
8. Miscellaneous^
Total Annual Costs
Before Credit
Recovery Credit6
Net AnnualIzed Costs'
Total VOC Emission
Reduction (Mg/yr)9
Cost Effectiveness
($/Hg VOC)h
S3
8.6
2.7
2.1
13.4
4.3
9.1
0.020-
460
Model Unit 8: 140 open-ended lines.
Emission Reductions:
140 .x 0.020 Hg/VOC/yr « 2.8 Mg/yr.
BIO for proposed standards, Table 8-1.
b0.163 (capital recovery factor) x capital cost; from 810 for proposed
standards, Table 3-5.
CQ.05 x capital cost. From 810 for proposed standards, Table 3.5.
d0.u4 x capital cost. From BIO for proposed standards, Table 8.5.
'Recovery credit based on uncontrolled VOC emission factor of
0.055 kg/day (from BIO for proposed standards. Table 3-1). Based on 100
pp»-cent control
efficiency for caps and $215/Mg VOC emission reduction (from 310 for
proposed standards, Table 8-5).
treission Reduction:
0.055 kg/day/open-ended line x 365 day/yr x 1 Mg/1,000 kg « 0.020 Mg/yr
Recovery Credit:
0.020 Mg/yr x $215/Mg VOC » S4.3/yr/open-ended line.
'Total annual cost (before credit) minus recovery credit.
SBased on uncontrolled emission factor and control efficiency in
footnote e.
^Obtained by dividing net annualized cost by total VOC emission reduction.
A-8
-------
Table A-5. SAMPLING CONNECTION SYSTEM IMPACTS
(.May 1980 dollars)
Per Sampling Connection System
Item/Control Technique
Closed Purge Sampling System
Installed Capital Cost4
Annualized Capital Costs
Control Equipment0
Annual!zed Operating Costs
A. Maintenance0
B. Miscellaneous"1.
Total Annual Costs
Before Credit
Recovery Credit6
Net Annualized Costsf
Total VOC Emission
Reduction (Mg/yr)9
Cost Effectiveness
($/Ng VOC)h
530
36
26
21
133
28
105
0.13
810
Model Unit B: 20 sampling connections.
Emission Reductions:
20 x 0.13 Mg/VOC/yr « 2.6 Mg/yr.
aFrom BID fop proposed standards, Table 8-1.
Capital recovery factor (0.163) x capital cost; from BID for proposed
standards, Table 8-5.
CO.05 x capital cost. From BID for proposed standards, Table 8.5.
d0.04 x capital cost. From BID for proposed standards, Table 8.5.
eRecovery credit based on uncontrolled VOC emission factor of
0.36 kg/day (from BID for proposed standards. Table 3-1). Based
on 100 percent control efficiency.
Recovered Emissions:
0.36 kg/day x 365 day/yr x 1 Mg/1,000 kg » 0.13 Mg/yr
Recovery Credit:
S215/Mg x 0.13 Mg/yr * $28/yr.
^Total annual cost (before credit) minus recovery credit.
9Based on uncontrolled VOC emission factor and 100 percent control as
shown in footnote e. •
"Obtained by dividing net annualized cost by total VOC emission reduction.
A-9
-------
A«fi, VALVE EMISSIONS AND.EMISSION REDUCTIONS
Emission Per Valve ' Emission Reduction Per Valve
(kg/day) (Mg/yr)a
Control -Service Gas Light
Uncontrolled' 0.64 0
Quarterly LDR 0.262 '0
Monthly LDR 0.192 0
Sealed Bellows
Valves6 0 0
LOR > Leak Detection and Repair
»Ea1ss1on Reductions Per Valve
/Uncontrolled emissions
1 per valve (kg/hr)
liquid uas Light liquid
.26
.098 0.14
.072 0.16
0.23
Calculated as:
Controlled emissions
per valve (kg/hr)
„
0.059
0.069
0.095
\ x 365 days
year
Emission Reduction Per),
Model Unit B (Mg/yr)
Weighted Average1- Gas Light liquid rota I u
„
0.087
0.10
0.14
x 1 Mg
1000 kg
«• •• ••
35.9 29.6 65.5
42.5 34.3 76.8
60.7 47.4 108
(fro* BID Table 3-1)
(from BID Table F-7),
Exanple Calculation: gas service, quarterly LDR - (0.64 - 0.262) x 365 + 1000 « 0.14 Mg/yr
''Based on Model Unit B: 260 gas service valves and 500 light liquid service valves.
Exaaple Calculation: gas service, quarterly LOR - (0.64 - 0.262) x 365 * 1000 x 260 > 35.9 Mg/yr
^Weighted average Is based on Model Unit B valve population. Weighted average 1s calculated
by using the formula:
gas service | + [ 500 x light liquid service)
emission / \260 + 500 emission reduction /
reduction ' x '
/ 2(50
\ 260 + 500
Example calculation: quarterly LDR •
I
\"
260
260 + 500
x 0.14 Mg/yr \ +
500 x 0.059 Mg/yr)
260 + 500 /
0.087 Mg/yr
The emission reductions reported In the proposal preamble are on a per component basis, therefore. It Is necessary to
derive per valve Inpacts by weighting the gas and light liquid service emission reductions by their relative component
counts In Model Unit B. The resulting emission reductions per valve represent a weighted average.
Unit B emission reductions presented In the proposal preamble Table 1 represent a weighted average of the gas and
light liquid emission reductions, calculated as:
Quarterly LOft
/ 260
\-7EO-
Monthly LDR
x 35.9 Mg/yr)
SOO
x 29.6 Mg/yr }
/
* 31.7 Mg/yr
I 260
\~751T
x 42.5 Mg/yr
H
500 x 34.3 Mg/yr)
~75TT /
37.1 Mg/yr
However, total emissions from gas and light liquid service valves 1n Model Unit B should have been reported rather than a
weighted average. 'Individual valve weighted average Impacts are used to determine the per component cost effectiveness.
From BID for proposed standards, Section 4.3.3.
A-10
-------
Table A-7. VALVE LEAK DETECTION AND REPAIR COSTS1
(May 1980 dollars)
Per Valve
Cost Item/LDR-Service
Initial Leak Repair^
Monitoring Labor*!
Recurring Leak Repair Labor6
Administration and Support f
Total Annualized Cost
Product Recovery Credits
Net Annualized Cost"
Quarterly
Gas
0.46
2.4
3.3
2.5
9.2
(30)
(21)
Light
liquid
0.51
2.4
3.8
2.5
9.2
(13)
(4)
Weighted
Average'1
0.49
2.4
3.8
2.5
9.2
(19)
(10)
Gas
0.46
7.1
3.9
4.4
16
(34)
(18)
Monthly
Light
liquid
0.51
7.1
3.9
4.4
16
(15)
1
Weighted
Average'1
0.49
7.1
3.9
4.4
16
(22)
(6)
(XX) > Cost Savings
LDR * Leak Detection and Repair
"Cost of monitoring instrument 1s not Included In this analysis.
bBased on Model Unit B: 260 gas service and 500 light liquid service valves.
Weighted average calculated by using the formula:
(260
\Z60 +
260
Z60 + 500
gas service
cost Item
A + / 500
/ \ 260 + 500
x light liquid service)
cost item I
BID for proposed standards, Tables 8-3, 8-5, and 8-6. Calculated as:
Initial leak frequency x 1.13 hrs/valve x 18/hr x 1.4 x 0.163
dFroa BIO for proposed standards, Tables F-4 and F-12. Calculated as:
Fraction of Sources Screened
(from BIO Table F-4, 2nd
turnaround Annual Average)
x 1 mln x 1 hr x $13.00 x 2 workers
valve 60 mm Hr
Example Calculation: Gas Valves, Monthly LDR • 11.8 x 1/60 x 18.00
$7.1
BID for proposed standards, Tables F-4 and F-12. Calculated as:
Fraction of Sources Operated on, x 1.13 hrs x SIS.00
from BID Table F-4, 2nd valvehr
turnaround annual average
Example calculation: gas service, quarterly LOR >
[(0.1762 + 0.1970J/2] x 1.13 x $18 * $3.80
fFrom BID for proposed standards. Table 8-5.
Calculated as: 0.4 x (monitoring labor + recurring leak repair labor)
Calculated as: $215 x emission reductions (given in Table 6).
"Total annual cost (before credit) minus recovery credit.
A-11
-------
Table A-8. SEALED BELLOWS VALVE COST IMPACTS
(May 1980 dollars)
Per Valve Cost Item
Capital Cost3
Annualized Costb
Capital recovery
Maintenance
Miscellaneous
Total annualized cost
Product recovery credit0
Net annualized cost
2,730
440
140
110
690
" (30)
660
(xx) - Cost Savings
a
From BID for proposed standards, Table 8-1.
Basis for annualized costs from BID for proposed standards, Table 8-5.
Calculated as: $215 x emission reductions (given in Table 6)
A-12
-------
Table A-9. COST EFFECTIVENESS OF VALVE CONTROLS
(May 1980 dollars)
Per Valve
Item/Control
Net Annuali zed Cost3
VOC Emission Reduction
(Mg/yr)b
Cost Effectiveness
($/Mg VOC)C
Incremental Cost
Effectiveness ($/Mg VOC)d
Quarterly
LDR
(10)
0.087
(no)
(110)
Monthly
LDR
(6)
0.10
(60)
310
Sealed Bellows
Valves
660
0.14
4,700
16,700
(xx) = Cost Savings
LDR = Leak Detection and Repair
From Tables 7 and 8.
From Table 6.
Calculated as:
Calculated as:
Net annualized Costs ($/yr)
annual VOC emission reduction (Mg/yr)
Net annualized cost of
control technique
Net annualized cost of next
less restrictive control
Annual VOC emission
reduction of control
technique
Annual VOC emission
- reduction of next less
restrictive control
A-13
-------
Table A-10. PUMP EMISSIONS AND EMISSION REDUCTIONS
Control
Emissions Per
Per Pump (kg/day)
Emission Reductions Per
Pump (Mg/yr)a
Uncontrolled
Annual LDR
Quarterly LDR
Monthly LDR
Dual Seal System
2.12C
0.79C
0.45C
0.21
0.70
0.82
0.99
LDR - Leak Detection and Repair
Model Unit B = 14 pump seals in light liquid service.
Emission reductions:
3.0 Mg/yr
9.8 Mg/yr
11.5 Mg/yr
13.9 Mg/yr
Annual LDR
Quarterly LDR
Monthly LDR
Dual- Seal System
Calculated as:
Uncontrolled
emissions per
pump seal
(kg/hr)
Controlled
emissions per x 365 days x 1 Mg
year 1000 kg
pump seal
(kg/hr)
Example calculation: annual LDR =
(2.7 kg/day - 2.12 kg/day) x 365
From BID for proposed standards, Table 3-1.
From BID for proposed standards, Table F-5.
From BID for proposed standards, Section 4.3.1.1.
1000 = 0.21 Mg/yr
A-14
-------
Table A-ll. PUMP LEAK DETECTION AND REPAIR
COSTS (May 1980 dollars)a
Per Pump Seal
Cost Item/Control
Initial Repair
laborb
Replacement Seals0
Maintenance-ongoing
Replacement Sealsd
Monitoring Labor
Instrument6
Visualf
Recurring Repair LaborS
Administration and Support"
Total Annualized Cost
Product Recovery Credit i
Net Annualized CostJ
LDR
Annual Quarter
' 16 16
5.5 5.5
48 55
3 12
7.8 7.8
9.8 110
44 52
220 260
45 150
180 110
2 Monthly
16
iU
5.5
57
36
7.8
120
66
310
180
130
(XX) = Cost Savings
LDR = Leak Detection and Repair
aPump seal repair costs are based on 16 labor hours per pump repair and includes
5140 per repair for a replacement seal. This analysis does not include the cost
of monitoring instrument.
bFrom BID for proposed standards, Tables 8-3 and 8-5. Calculated as:
Estimated percent of x labor hours x labor x Administration x Capital
""«ID r^EVi?1"9 iper - rate and re«ver*
(BID Table 8-3) seal repair support costs factor
Example calculation: annual LDR =
(0.24) x (16) x ($18) x (1.4) x (0.163) = $16
clnitial replacement seal cost is calculated as:
Estimated percent of x $140/ x 0.163
initial pumps leaking replacement Capital
(BID Table 8-3) seal recovery factor
Ingoing replacement seal cost calculated as:
Fraction of Sources x $140/
operated on replacement
(from BID Table F-6) seal
A-15
-------
Table A-11. PUMP LEAK DETECTION AND REPAIR COSTS
(May 1980 dollars)3
(Concluded)
Example calculation: annual LDR
(0.3397) x ($140) = $48
Calculated as:
fraction of sources x 5 min
screened pump seal
(from BID Table F-6)
Example calculation: annual LDR =
(1) x (5/60) x ($18) x (2) = $3
fCalculated as:
0.5 min
1 hr x $18 x 2 workers
60 min
~RF
x 52 x 1 hr
pump seal yr 60 mirt
x $18 x 1 worker = $7.8
hr
9Calculated as:
fraction of sources
operated on
(from BID Table F-6)
x labor hours
per seal repair
$18
~hT
Example calculation: annual LDR =
(0.3397) x (16 hrs/seal repair) x ($18) = $98
"Administration and support = 0.4 x (monitoring labor + rec-'rring
leak repair labor)
"^Calculated as:
Emission Reduction x $215/Mg
(from Table 10)
JTotal annualized costs (before credit) minus recovery credit.
A-16
-------
Table A-12. DUAL MECHANICAL SEAL SYSTEM COSTS FOR PUMPS
(May 1980 dollars)
Per Pump Seal
Cost Item
Capital Costa
Seal
Seal installation
Barrier fluid system
Barrier fluid degassing vent
Total capital cost
Annualized Costb
Capital recovery
seals0
other capitald
Maintenance charges6
Miscellaneous charges^
Total annualized cost
Product Recovery Credits
Net Annualized Cost n
970
288
1850
4000
7110
560
1000
360
280
2200
(210)
1990
(xx) - Cost Savings
a
From BID for proposed standards, Table 8-1.
b
From BID for proposed standards, Table 8-5.
Calculated as 0.58 x capital cost for seal.
Capital cost for seal = cost for new seal ($1250)
minus credit for old seal ($255 x 328.9/266.6) = $970.
Capital recovery credit per seal = 0.58 x $970 = $560.
d
Calculated as: 0.163 x capital cost.
e
Calculated as: 0.05 x capital cost.
f
Calculated as: 0.04 x capital cost.
g
Calculated as:
Emission Reduction x $215/Mg.
(from Table 10)
h
Total annualized cost (before credit) minus product recovery credit
A-17
-------
Table A*13- COST EFFECTIVENESS QF PUMP CONTROLS
"(May 1980 dollars)
Per pump
Item/Control
Net Annual i zed Costa
VOC Emission Reduction
(Mg/yr)b
Cost Effectiveness
($/Mg VOC)c
Incremental Cost
Effectiveness ($/Mg VOC)d
Annual
LDR
180
0.21
860
860
Quarterly
LDR
110
0.70
157
(140)
Monthly
LDR
130
0.82
158
170
Dual
Seals
1,990
.0.99
2,000
10,900
(xx) s Cost Savings
LDR « Leak Detection and Repair
a
From Tables 11 and 12.
b
From Table 10.
"Calculated as :
Calculated as:
Net annualized costs ($/yr)
annual VOC emission reduction (Mg/yr)
Net annualized cost of
control technique
Annual VOC emission
reduction of control
technique
net annualized cost of next
less restrictive control
Annual VOC emission
reduction of next less
restrictive control
A-18
-------
APPENDIX B
Regulatory Decisions Affecting Standards for SOCMI
Several of the decisions made on these standards (since they were
proposed) affect EPA's position on standards of performance (Subpart
VV) for equipment leaks of VOC within the Synthetic Organic Chemical
Manufacturing Industry (SOCMI). These decisions are the result of new
or additional analysis of the control techniques considered in the
standards for petroleum refineries and SOCMI and, therefore, should be
made consistent for these two standards. The decisions concern:
(1) alternative for determining a "capital expenditure,"
(2) clarification of reconstruction provisions,
(3) difficult-to-monitor valves in new units, and
(4) double block and bleed valve exemption.
The discussions of these decisions are found in Sections 2.2.3.1, 2.7,
4.2, and 5.0 of the BID for promulgated standards as they apply for
petroleum refineries. The basis for the revisions to Subpart VV is
consistent with these discussions. EPA knows of no reason not to make
these revisions to Subpart VV and, therefore, based on a prudent use of
its resources, is promulgating these revisions.
B-l
-------
-------
APPENDIX C
EVALUATION OF AVAILABLE LEAK DETECTION AND REPAIR DATA
C-l
-------
Appendix C - EVALUATION OF AVAILABLE LEAK DETECTION AND REPAIR DATA
C.O INTRODUCTION
As a part of their comments on the proposed NSPS for VOC fugitive
emissions from petroleum refineries, two commenters (IV-D-25, IV-D-14)
presented summary data from their plants and asked EPA to review these
data. EPA requested the raw data for these summaries and requested other
data to evaluate the NSPS in light of data from refinery leak detection
and repair programs. EPA analyzed these data by comparing and con-
trasting, where possible, with the estimates used in preparing the BID
for the proposed standards.
Sections C.2, C.3, and C.4 of this appendix are memoranda that
provide summaries of the data, and describe the techniques used by EPA
in analyzing the data. All of the data received were generated either
as a result of or as a measure of the effectiveness of state or local
regulations and, accordingly, an understanding of these regulations is
needed. Therefore, the regulations on which the data are based are
described in the memoranda. In most cases, data were submitted that
allow direct quantitative comparison to the NSPS estimates. Where
qualitative comparison of these data and the estimates used in the
proposal BID are made, the reasons why the data are not directly related
are presented and the uncertainties with the qualitative comparison are
discussed.
Section C.2 presents data obtained from Texaco, U.S.A. (IV-D-25a,
IV-D-33, IV-D-36). These data were generated under the requirements of
the Louisiana State Implementation Plan, which requires quarterly moni-
toring of gas service components and annual monitoring of liquid service
components. Texaco monitors additional components to those required by
the proposed NSPS, and the data are therefore not directly comparable to
the data used to support the NSPS in many cases. The Texaco data
memorandum includes assumptions made by EPA in analyzing the data.
Section C.3 presents data obtained from facility inspections made
by the South Coast Air Quality Management District (SCAQMD) and the Bay
Area Air Quality Management District (BAAQMD) during a California Air
Resources Board (CARB) petroleum refinery valve inspection program
C-2
-------
(IV-D-31, IV-B-18). These data, as received by EPA, were the field
data sheets from valve inspections at 12 refineries. The data are
not based on inspection of entire process units, but only selected
valves within selected process units. Again, EPA made several assumptions
in analyzing the data, and these assumptions are stated in the memorandum.
Additional data were available from a study of the effectiveness of
the South Coast Air Quality Management District (SCAQMD) Rule 466.1,
performed by the EPA Office of Research and Development (ORD). The
results of-this study are summarized and evaluated in Section C.4.
C.I DATA SUMMARY
Data are available from the memoranda in Sections C.2 through C.4
on initial leak frequency, leak occurrence rates, small valves, repair
effectiveness, program costs, and monitoring time. This section
summarizes these data and provides comparisons with the values used
by EPA in estimating the impacts of the NSPS. The data discussed
in this section have been arranged by topic rather than data source to
provide for ease in locating specific information.
C.I.I Initial Leak Frequency
Information on the initial leak frequencies at a few facilities
can be obtained, by making assumptions, from the data supplied by Texaco
(C.2) and the EPA analysis of the SCAQMD data (C.4). These data are
shown in Table C-l.
For the Texaco data, initial leak frequency for each process unit
was derived by assuming that the first period for which leak monitoring
data was reported was indeed the first time the unit was monitored.
Therefore, the percent of components found leaking at the first monitoring
period is the initial leak frequency. The initial leak frequency for
gas components varied from 0.0 percent to 14.8 percent, with a weighted
average value of 6.5 percent. For liquid service components, the initial
leak frequency varied from 0.0 percent to 17.0 percent, with a weighted
average value of 2.8 percent. It should be noted that Texaco screens
components not included in EPA's NSPS leak detection and repair program,
such as valve flanges and valve bonnets. Since these sources are normally
considered by EPA to have low leak frequencies, and they may represent
C-3
-------
a significant portion of the total number of components, EPA expects the
initial leak frequency determined from the Texaco data to be understated
compared to data based solely on testing of NSPS sources.
The EPA analysis of the SCAQMD data determined initial leak frequencies
for five process units. These data show an initial leak frequency varying
from 1.5 percent to 14.5 percent with an average value of 6.2 percent.
Since the GARB inspection data presented in Section C.3 is from
inspection screening of facilities which have been performing leak
detection and repair routinely, no initial leak frequencies can be
generated.
In estimating the emission reductions for the refinery NSPS, EPA
used an initial leak frequency of 10.5 percent.1 While the Texaco data
shows initial leak frequencies of 6.5 percent for gas service and
2.8 percent for liquid service components, the data can not be expected
to be comparable to the EPA estimate due to the inclusion of infrequently
leaking components as discussed above. The initial leak frequency of
6.2 percent found in the SCAQMD study is the result of a valve popu-
lation identical to the EPA estimate basis, and is the result of 7,263
valve screenings. As the 6.2 percent initial leak frequency calculated
indicates that EPA may have overstated the initial leak frequency for
these plants, the LDAR model was run again using the 6.2 percent value.
This run, which included other deviations from the original EPA estimates,
is discussed in detail in Section C.4, and showed that leak detection
and repair was a cost-effective control technique even with the lowered
initial leak frequency.
3.1.2 Leak Occurrence Rate
Leak occurrence rates may be calculated .for all three data sets..
Table C-2 provides a summary of the average monthly occurrence rates
for all data provided in the three memoranda.
Several factors must be considered when comparing these data with
other information on leak occurrence rates. For the data provided by
Texaco, the occurrence rates stated are for all components screened,
which, as mentioned earlier, include a'significant quantity of low leak
frequency components. Therefore, the Texaco occurrence rates are
probably understated significantly. The data presented for the CARB
inspections represent valves only. However, CARB inspections are
performed by monitoring component leaks at a distance of 1 centimeter
C-4
-------
from the component surface, rather than at the surface as required by
Method 21. Since some leaks causing an instrument reading less than
10,000 ppm organics at 1 cm would likely read greater than 10,000 ppm
at the surface, these occurrence rates are likely to be understated.
In addition, the data from Texaco was presented by quarters and for
the.purpose of estimating occurrence rates, it was assumed that
monitoring occurred on the first day of each quarter although monitoring
may have actually occurred at any time during a 3-month period. Again,
this discrepancy could cause understatement or overstatement of the
occurrence rates.
In estimating the impacts of a leak detection and repair program,
EPA used a leak occurrence rate of 1.27 percent/month, as discussed
in Section C.4. As shown in Table C-2, the occurrence rates determined
in the data memoranda varied from 0.05 to 0.6 percent/month for valves.
The occurrence rates developed from the Texaco data are not compared
to EPA estimates as they include measurement of sources that generally
have a very low leak frequency. Although these occurrence rates
indicate that EPA may have overestimated occurrence rates in the
impacts analysis, it should be noted that EPA analyzed and consequently
provided alternative standards for valves where low leak occurrence is
found. Additionally, as discussed in Section C.4, EPA re-estimated the
impacts of a leak detection and repair program based on a lower (0.6
percent/month) leak occurrence rate, and found the leak detection and
repair program to still be cost effective.
C.I.3 Small Valves
The data provided by Texaco can be used to derive information
on the leak characteristics of small valves. Table C-3 provides a
listing of the leak incidences for small valves for line sizes less
than or equal to 1 1/2 inches. For the three monitoring periods for which
Texaco provided data, small valves accounted for 48 percent, 49 percent,
and 32 percent of all valve leaks found, or an average for the three
monitoring quarters of 45 percent of all valve leaks. Since it has
been shown that valve size is relatively unrelated to the mass emission
rate from a leaking valve,2 the small {
-------
refinery accounted for nearly one half of the valve leak emissions.
Texaco did not provide small valve and large valve equipment counts,
and therefore, the fraction of sources leaking could not be determined.
Data can also be obtained on the difficulty of performing on-line
repairs on small valves. As described above, nearly one half of the
leaking valves were 1 1/2" sizes or smaller. Table C-3 presents a
summary of components in the Texaco program which required off line
repair. As shown in the table, 68 small valves (<2" line size) and 107
large valves (>2" line size) required off-line repair. Therefore, it
appears that small valves are as repairable on-line as their larger
counterparts. It should be noted that Texaco does not attempt to bypass
components for off-line repair prior to unit shutdown, as will be
required by the NSPS, but allows the leakers that are not repaired
in two attempts at simple maintenance in service to continue to leak
until a process unit shutdown occurs. Therefore, some of the components
which were delayed until shutdown for repair in the Texaco program
would be repaired under NSPS by bypassing the leaking valve for off-
line repair. It should also be noted that some of the small valves
listed in the table as requiring off-line repair were listed as large
valves by Texaco due to the cutoff difference of 1 1/2" by Texaco and
2" by EPA. Therefore, the table actually shows a disproportionate
amount of small valves requiring off-line repair.
C.1.4 Repair Effectiveness
Information can also be obtained from the Texaco data on the
various aspects of repair effectiveness. Table 2 of memorandum C-2
provides data summarized from Texaco's listing of components for which
repair was delayed (as explained in C.I.3). As can be seen, 7.4 to
26.5 percent of all leaks were delayed until turnaround for repair during
the first five monitoring periods. For the sixth and seventh monitoring
periods, 42.5 and 91.0 percent of all repairs were listed for turnaround,
apparently because most' of the leaks occurred in process units for
which turnarounds were scheduled within the monitoring quarter. For
the five quarters within which shutdowns of major units were not
scheduled, the weighted average percentage of repairs which required
shut down was 16.0 percent, while the weighted average percentage of
repairs requiring shutdown for all quarters was 24.7 percent. As such,
C-6
-------
it would appear that simple, on-line repair was approximately 75.3 percent
effective in the Texaco program. In estimating the annual repair labor
cost*, EPA assumed 75 percent of all valves can be repaired with simple
on-line maintenance, and 25 percent of all valves require off-line repair.
This basis seems to agree very well with Texaco's experience.
C.I.5 Program Costs
Texaco provided data on the cost of operating a Control Techniques
Guideline (CTG)3 based leak detection and repair program for a 1-year
period. The program underway at Texaco is required by the Louisiana
State Implementation Plan, and includes quarterly leak detection and
repair of gas service components and annual leak detection and repair
of liquid service components. As such, the program is similar to
Regulatory Alternative II in the BID for proposed standards. Section
C.2 provides a comparison of the costs provided by Texaco with the cost
estimates provided in the BID for proposed standards. Due to differences
in costing techniques, the costs cannot be directly compared. However,
by adjusting both the Texaco and EPA costs slightly, as shown in the
memo, some comparisons between the two costs can be made.
For example, Texaco reported a monitoring labor cost (in 1982
dollars) of $72,215/year for the entire refinery. Since EPA costs are
estimated on a model unit basis, the Texaco refinery was broken down
into model units as shown in the memo, and the EPA monitoring labor
costs were totaled for the resulting model units. The resulting EPA
labor cost for monitoring was approximately 50 percent lower than the
Texaco monitoring costs. This is expected, however, as EPA labor
cost estimates normally have other costs added to them to determine the
total monitoring costs, such as recovery of the monitoring instrument
capital costs and instrument calibration/maintenance costs. Since
Texaco1s monitoring program was performed by a contractor, the monitoring
cost reported by Texaco would include these additional costs.
Texaco reported an annual repair cost (in 1982 dollars) of
$5,301/year. While EPA estimates are normally much higher than this
figure, Texaco's costs do not include any off-line repairs, as do the
EPA repair cost estimates. Therefore, the EPA estimate for these costs
were made by assuming a 10-minute repair time for the simple on-line
C-7
-------
repairs attempted by Texaco, and calculating the EPA cost estimate on
the number of leaks encountered by Texaco. Texaco's reported repair
cost of $5,301/year results in a unit cost (for 630 repairs) of $8.41
per component repair. Using the EPA estimate of 10 minutes at $18 per
hour for simple repairs, with 40 percent overhead, results in a unit
cost of $4.20 per repair. Again, the EPA estimate is about one-half
the Texaco cost. Texaco made two repair attempts where necessary,
which is not accounted for the EPA estimate. EPA normally assumes that
25 percent of all valves require off-line repair at 4 hours per valve,
and 16 hours of repair labor is required for every pump seal. Hence,
the EPA estimate used for comparison with Texaco's repair costs is
significantly lower than the costs presented in the BID for the proposed
standards.
The "overhead" cost reported by Texaco ($57,922) included the
costs of tagging the components and setting up the monitoring program.
Obviously, this cost is not recurring and, as such, is amortized over a
10-year period by EPA. As mentioned above, EPA estimates normally
amortize non-recurring costs, including the capital costs of the monitoring
instruments which were included in the "monitoring costs" by Texaco.
As such, the EPA estimate in this case is significantly higher than the
Texaco cost and corrects for the lower monitoring cost in the EPA
estimate.
As shown in Table 4 of Section C.2, the Texaco total program costs
were close to the EPA cost estimates for a similar program ($61,000 EPA
vs. $71,000 Texaco after adjustment to reach the same cost basis),
especially considering the differences in costing techniques employed.
C.I.6 Monitoring Time Data
The data provided on the California Air Resources Board (CARB)
refinery valve inspection program included the "time monitored" for
each component. The CARB data as.presented in Section C.3 includes
data from inspections in 12 refineries with a total of 93 process
units, or 6,497 components. For these process units, monitoring time
varied from 0.61 to 1.1 minutes/valve, with a weighted average value of
0.9 minutes/valve. In the BID for proposed standards, EPA estimated
1 minute/valve, which is nearly identical to that found in the CARB
inspections.
C-8
-------
C.I.7 References for Section C.I
1. VOC Fugitive Emissions in Petroleum Refining Industry - Background
Information for Proposed Standards, EPA 450/3-81-015a, November
1982. Docket Item Number II-B-1.*
2. Memo, T.L. Norwood, PES, Inc., to Docket A-80-44, Small Valve
Repair Cost Effectiveness. September 26, 1983. Docket Item
Number II-B-8.*
3. "Control of Volatile Organic Compound Leaks from Petroleum
Refinery Equipment" EPA450/2-78-036. June 1978. Docket
Item Number IV-A-6.*
4. Assessment of Atmospheric Emissions from Petroleum Refining:
Volume 3 Appendix B. EPA-600/2-80-075c, April 1980. Docket
Item Number II-A-19.*
5. Fugitive Emission Sources of Organic Compounds - Additional
Information on Emissions, Emission Reductions, and Costs.
EPA-450/3-82-010, April 1982. Docket Item Number II-A-41.
*Document numbers refer to entries in Docket A-80-44, which can be
found at the U.S. Environmental Protection Agency Library, Waterside
Mall, Washington, D.C.
C-9
-------
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-------
Table C-2. AVERAGE LEAK OCCURRENCE RATES
Refinery .
Texaco; Convent, La.
Texaco; Convent, La.
Tosco; Bakersfleld, Ca.
Exxon; Benicia, Ca.
Chevron; Richmond, Ca.
ARCO; Carson, Ca.
Mobil; Torrance, Ca.
Fletcher Oil; Carson, Ca.
Champlin Oil; Wilmington, Ca.
Shell Oil ; Carson, Ca.
Chevron; El Segundo, Ca.
Newhall; Newhall , Ca.
Powerine; Sante Fe Springs, Ca.
SCAQMD Summary
Proposal BID Basis
Component Type
All
All
Valves
Val ves
Valves
Valves
Valves
Valves
Val ves
Val ves
Valves
Valves
Valves
Val ves
Valves
Service
Liquid
Gas
Gas and Liquid
Gas- and Liquid
Gas and Liquid
Gas and Liquid
Gas and Liquid
Gas and Liquid
Gas and Liquid
Gas and Liquid
Gas and Liquid
Gas and Liquid
Gas and Liquid
Gas and Liquid
Gas and Liquid
No. of
Sources
10,082
4,736
326
858
803
591
338
317
157
816
602
152
576
7,263
—
Occurrence
Rate3
(Vmonth)
0.08.
0.6
0.05C
0.6C
O.ic
0.2C
0.3=
0.4C
0.2C
0.2C
0.2C.
O.ic
0.4C
0.6d
1.276
a • !
Average values weighted by number of sources as described in Footnote b of Table C-l
b
From Section C-2, Table 1, weighted average for refinery. Leaks defined as greater than
10,000 ppm organics concentration.
From Section C-3, Table 1. Leaks defined as greater than or equal to 10,000 DDID oraanics
concentration at 1 cm from source.
d
From Section C-4, Table 4, weighted average of 5 units in two refineries.
e
From Reference 1.
C-ll
-------
Table C-3. SMALL VALVE DATA SUMMARY
Moni tori ng
Quarter
4Q 1981
1Q 1982
2Q 1982
3Q 1982
1Q 1983
2Q 1983
3Q 1983
Small Valve sb
Requiring
Small Valve3 Large Valve3 Off Line
Leaks Detected Leaks Detected Repair
5
15
93 102 11
51 53 4
- - 2
24 50 11
20
Large Valvesb
Requiring
Off Line
Repai r
10
14
21
2
7
19
34
From Section C.2 Table 3; small valves are those valves less than or
equal to 1 1/2". "-" indicates that no data was provided by Texaco.
Small valves defined as less than or equal to 2". From Section C.2,
Table 2. Therefore, the "small valve" listings in these columns would
include some of the "large valves" from the "leaks detected" listings
(those valves greater than 1 1/2" and less than or equal to 2".
C-12
-------
Section C.2
TEXACO DATA SUBMITTAL SUMMARY
C-13
-------
TO:
FROM:
SUBJECT:
A.-8.0-44 .. •
MEMORANDUM IV-B-22
DATE: November 11, 1983
Docket A-80-44
T.L. Norwood, P.E., Pacific Environmental Services, Inc. /'tj
Review and Summary of Leak Detection and Repair Program
Data Supplied by Texaco, U.S.A.
Introduction
This memorandum summarizes the data supplied by Texaco, U.S.A as
comments on the proposed new source performance standards for fugitive
VOC emissions from petroleum refineries^ and in response to EPA requests
for additional information to clarify their original submittal.2>3
This memorandum summarizes only those data supplied by Texaco that were
sufficiently detailed to allow comparison with estimates provided by
EPA in the background information document (BID) for the proposed
standards.4 The data supplied by Texaco were not supported by listings of
component types for the process units (i.e., Texaco specified how many
components were in each unit but did not break the unit totals into types
of components). Some of the Texaco data, however, were sufficiently
detailed to allow analysis.
Data Assumptions and Deviations with NSPS Programs
The Texaco facility for which the data were generated is subject
to the State Implementation Plan for the State of Louisiana, which is
based on the refinery CTG5 requirements. The leak detection and repair
program underway at the Texaco facility is, therefore, based on quarterly
leak detection and repair of gas service components, annual leak
detection and repair of liquid service components, and weekly visual
inspection of pump seals. This program corresponds roughly to Regulatory
Alternative II in the BID for proposed standards. There are, however,
differences in the Texaco program and the BID Regulatory Alternative II
program, as follows:
o The Texaco program includes screening of certain flanges,
capped lines and other components not required in the
NSPS alternatives. Since EPA believes these components have
very low leak frequencies, their inclusion in a leak detection
program would lower the overall leak frequency from that
expected for a normal NSPS component mix. These "non-leakers"
could represent a very significant portion of the total
components monitored.
C-14
-------
© The Louisiana SIP defines leaking components as those components
with surface organic concentrations of greater than 10,000 pom
while the refinery NSPS defines leaks as greater than or '
equal to 10,000 ppm surface organic concentrations. Those
sources reading 10,000 ppm are thus considered leaks by the
NSPS and not considered leaks by Texaco. Although this
appears to be a minor difference, operators monitoring
components may record the monitoring instrument readings in
rounded numbers, with sources reading across a range beinq
recorded as "10,000" ppm. These sources would be considered
non-leakers by Texaco, reducing the measured leak incidence rate.
• Texaco uses OVA® leak detectors, which are calibrated
with hexane at approximately 5,000 ppm. Method 21, as used
in the refinery NSPS, currently specifies calibration with
methane or hexane at approximately 10,000 ppm. The difference
in calibration technique may result in small differences in
the leak readings (and therefore the number of leaks).
However, EPA feels that the differences in leak readings
caused by the calibration differences should be small if
any. '
Data Summary
Using the assumptions described in the footnotes to the tables
•5uwrn,able.to Summar1ze the data collected by Texaco for comparison
with EPA estimates for several leak detection and repair program
parameters. These data must be used judicially, with careful attention
given to the assumptions and program specifics stated. These data are
presented in Tables 1 through 4, as follows-
Table 1
Table 2
Table 3
Table 4
References
Leak frequency and occurrence rate data
Delay of repair data
Small valve vs. large valve leak count data
Program annual costs.
1. Letter, J.M. McCrum, Texaco USA; to Central Docket Section EPA-
Comments on Proposed NSPS for Fugitive VOC Emissions from Petroleum
Refineries. April 22, 1983. Docket Item Number IV-D-25a.
2. Letter, J.J. Lennox, Texaco, USA to R.E. Rosensteel, U.S. EPA-
September 2, 1983. Docket Item Number IV-D-33.*
3. Letter, J.J. Lennox, Texaco, USA to R.E. Rosensteel, U.S. EPA-
October 14, 1983. Docket Item Number IV-D-36.*
4. BID for proposed standards. Docket Item Number III-B-1.*
C-15
-------
5. "Control of Volatile Organic Compound Leaks from Petroleum Refinery
Equipment." EPA-450/2-78-036. June 1978. Docket Item Number
II-A-6.
*Docket items refer to Docket Number A-80-44 in the EPA Central Docket
Section, Waterside Mall, Washington, D.C.
C-16
-------
Table 1. ESTIMATED RATE OF LEAK OCCURRENCE FOR TEXACO DATA - GAS SERVICE COMPONENTS3
Process Unit
Number of
. Components
VW/V8U/&OU
ton
KCU
US'
HTH-J
(,01
' Date b Percent
Screened Leaking
10/11 1,0
l/?i I.I
f/fi /*
1/11 ~ %
'/M *•*
Y« «,7
V« i. a
i*< i.t
•/to *•**
¥/»! «.«
7/r* 0.*?
'A3 '•»
f/rc «•'*
7/,3 o.n
/o/?i 4.9
'Al A.e
V*J. /.r
7/81 /.I
>/«3 /.«
t^3 0.3
7/j.,
-------
Table 1. ESTIMATED RATE OF LEAK OCCURRENCE FOR TEXACO DATA
GAS SERVICE COMPONENTS (continued)
Process Unit
Hunber of
Components
Cfty
fs-0
Atxr
**3
HTU-l
1A6
/»eu
JS-7
Date h Percent
Screened0 Leaking
10/JI .10.1
1/31 ?."*
*Ax a.«f
7/tt M
i/w '•'
7/w a.*
M/fi /.*» •
lAl *./
7/ti «•*
J/tt W
f/«5 W
7/J3 A4
/«/*! ' 1.3
l/tt 3.3
«*/% -*•
7/>* «
'/ 5i
l/w /^
4/83 •/.00
3 i
"' O.O c) O.oa
& °->l °-(> is- a.o to
3 ** 1* ./9 0.067
3 0.2* 1.2. t
C-18
-------
Table 1, ESTIMATED
6
RATE OF LEAK OCCURRENCE FOR TEXACO DATA
GAS SERVICE COMPONENTS (continued)
Process Unit Date b Percent Months
Number of Screened Leaking Between
Components Tests
T6-TU /r
/pi j /?! O.O J
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7/?i -^
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TffG. lofcl l>2
^LfO //fi JJ 3
^/52. -?*
7/fl tf.M 3
//M tf.3 '6
^AJ ?,s 3
7/?j /.7 3
Test-to-test Cumulative Percent Months from 30-day
30- day Leaking from H Beginning of Occurrence from
Occurrence Beginning of Test" Test Beginning of Teste
— — - - '
0,O O.O 3 °'°
— — ~
o.o o.o 3 o.o
o.o o.o ? °.o
o.o o.o 12. o.o^
O.O ' '"'
-
0.11 O.so 3 0,11
0,23 /.£• 4" 0.2.S
0.0 1.5- 1 0-*7
O.o i.f is- °'lo
OM %.o /J 0.1 1
0,0 2.0 H 0.0°!$
.
0,0 0.0 ' '3 O.O
0.0 0,0 (> 0.0
• -
0.3? a.3 6 o.3^
1.^" fi.? 9 C?.76
0,77 9./ / 2. 0.76f
- - • —
/,; 3.2 '3 A/*
* • «•
0.2.7 0.93 3 0.^7
/./ 7. /3 r 0.7?
^•2 /f.¥ /Z /.i«
0.5-7 J7.J /.r ; /u*
C-19
-------
Table 1. ESTIMATED RATE OF LEAK OCCURRENCE FOR TEXACO DATA
GAS SERVICE COMPONENTS (continued)'
Process Unit 'Date h Percent Months
Huesber of Screened Leaking Between
Components Tests
Test-to-test Cumulative Percent Months from 30-day
30- day Leaking from d Beginning of Occurrence from ^
Occurrence Beginning of Test" Test Beginning of Test5
Pw
1/93
1/93
7/93
-9-
JT.3
6.*
0.0
3
3
0.70
0.10
1.1
0.0
5". 3
11.7
11.7
It
0.10
0.10*
7-30
0.18
C-20
-------
Table 1. ESTIMATED RATE OF LEAK OCCURRENCE FOR TEXACO DATA - LIQUID SERVICE
™
Components
c Date J ^cent
Screened Leaki"9
Months Test-to-test Cumulative Percent
Between 30- day Leaking from :
Tests Occurrence0. Beginning of Testd
Months from 30-day
Beginning of Occurrence from
Test Beginning of Test
YPS/Veu/cou ifa
7/»3
-*
0,10
11-
0.06
PCCU
o.3[
o.31
0.31
If
0.02.1
HTU-1
-------
Table 1. ESTIMATED RATE OF LEAK OCCURRENCE FOR TEXACO DATA
LIQUID SERVICE (concluded)
Process Unit Date b Percent
Nuaber of Screened Leaking
Components
Months Test-to-test Cumulative Percent Months from 30-day
Between 30- day Leaking from ri Beginning of Occurrence from
n i. B—I__.I * -r-^u Test Beginning of Test
Tests
Occurrence Beginning of Test
ETU/COB 7/92. 0.0
91 I A3 0.0
0.0
0,0
LOG-
0-3
1.9
0.3
TK&
169?
.pw
1«
-y
0.0
tf.O
C-22
-------
10
Footnotes to Table 1
aThe number of gas and liquid components during the monitoring periods
October 1981 through September 1983 are assumed to be constant and
are based on the component summary in Table 1 of Docket Number A-80-
44-lV-D-25a (page 8).
bThe date screened is based on the assumption that components were
monitoring the first month of the quarterly monitoring period. In
reality, the components could have been monitored at any time during
the quarter.
cBased on all leaks from the previous inspection being repaired and
an assumption of linear leak occurrence. The leak frequency (percent
•leaking) divided by the number of months between tests estimates the
30-day leak occurrence rate.
dBased on all leaks at initial inspection being repaired and assuming
that if the other inspection had not occurred, the leaks could have
accumulated from inspection to inspection (leaks found are new leaks
at each inspection).
eSame methodology as discussed in footnote b, except based on the
initial inspection.
fThese are the overall average monthly occurrence rates for a continuous
series of screenings.
SThese data could not be determined because the breakdown of gas and
liquid components that were found leaking was not available.
Therefore, this screening date begins a new monitoring period for
the purpose of calculating the cumulative leak occurrence rate.
"Unit not in operation this quarter.
""Unit was shut down or partially shut down.
liquid components monitored in 1983.
C-23
-------
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-------
13
Table 4. COMPARISON OF REPORTED TEXACO LEAK DETECTION
AND REPAIR PROGRAM COSTS WITH EPA COST ESTIMATES
ITEM
TEXACO
(1982 dollars)1
TEXACO
(1980 dollars)2
EPA ESTIMATE
(1980 dollars)
Monitoring Labor
Repair Labor
Overhead/Setup
Total Program Costs
$ 72,215/year
5,301
57,922
$135,488/year
$59,060/year
4,335
7.7205
$71,115/year
$30,740/year3
2,646/year4
27,500/year6
$60,886/year
From Reference.
"1980 dollars calculated using Chemical Engineering Cost Indices:
December 1982 == 316.1; May 1980 = 258.5; Ratio = 0.8178
EPA Monitoring labor based on 4 each of Model Units A, B, and C
per Table 4a, with Proposal BID Table F-12 labor estimates of
33.7 hours/year (A), 68.8 hours/year (B); and 202 hours/year (C).
Labor at $18/hour, with 40% overhead added.
$/year s (33.7 + 68.8 + 202) hours x 4 units x $18/hour x 1.4
= $30,740
EPA estimate based on 630 leaks detected in first 4 quarters (Table 2)
by Texaco, at 10 minutes for each repair attempt. Labor at $18/hour
with 40% added overhead.
$/year = 630 x 18 x 1.4 x 10/60 = $2,646/year
5
EPA estimate based on amortizing initial setup costs for 10 years at
10% interest (capital cost x 0.163) and deflating to 1980 dollars
per footnote 2 method.
EPA estimate based costs of operating and maintaining 5 pairs of
monitoring instruments (at $5,500/year each per BID for proposed
standards Table 8-9) = $27,500/year.
C-26
-------
Table 4a
FUGITIVE EMISSIONS COMPONENTS SUMMARY3
UNIT
Vacuum Pipe Still, Visbreaking
Unit & Gas Oil Unit (VPS)
Fluid Catalytic Cracking
Unit (FCCU)
Hydrotreati ng Unit #1
(HTU-1)
Catalytic Reforming Unit
(CRU)
Alkylation Unit
(ALKY)
Hydrotreati ng Unit #2
(HTU-2)
Amine Regeneration Unit
(ARU)
Tail Gas Treating Unit
(TGTU)
Effluent Treating Unit & Co
Boilers (ETU/COB)
Tank Car & Truck Loading
& Dock (LOG)
Tankage, Flares & Additives
(TKG)
Pipeways
(PW)
TOTAL
No
Gas
1016
715
607
450
263
926
157
24
200
44
240
94
4736
. of Components
Liquid Total
2440
1934
951
401
1203
542
425
68
81
221
1688
128
10082
3456
2649
1558
851
1466
1468
582
92
281
265
1928
222
14818
EPA
Model
Plant
C
C
C
B
B
B
B
A
A
A
C
A
a.
This Table is presented by Texaco as Table 1 in Reference 1.
Model Plant designations added by EPA are based on the similarity
of these model plants to the number of pieces of equipment
shown for the Texaco units.
C-27
-------
SECTION C.3
SUMMARY OF AVAILABLE CALIFORNIA AIR RESOURCES
BOARD INSPECTION DATA
C-28
-------
TO:
FROM:
SUBJECT:
MEMORANDUM
A-80-44
IV-B-18
DATE: November 11, 1983
Docket A-80-44
T.L. Norwood, P.E., Pacific Environmental Services, Inc. /\ tf
Review and Summary of California Air Resources Board (CARB)
Refinery Valves Inspection Program Data
Introduction
This memorandum summarizes the California Air Resources Board (CARB)
eth/nfM-ry fU9itl'Ve emiss1ons Inspection data received by EPA.
sta dar5s foPr Jnr JS??* per °d-for 'he Pr°P°sed "« source performance
standards for VOC fugitive emissions from petroleum refineries
commenters on the standards (IV-D-8, IV-D-14 IV-D-15 IV n ?
anTreoai ^ ™ ^ ani 3nal^e <"« on Calffor'ni "le^k
Is a 2Ii\ ?r°9,rKm- °r the commenters u*ed the California program
as a basis for their comments. EPA received the results of several PARR
inspections, in three separate submittals, as follows:
o Letter from ARCQl with data from four facilities.
H A1r Quality Mana9ement District
with data from four bay area facilities.
-, Coast Ai r Quality Management District
with data from eight facilities.
Data Description
-. the CARB inspections were the field data
1.
2.
3
4.
5.
Source ID #
Time monitored
Date Monitored (for entire process unit)
Date last monitored (for entire process unit)
OVA® leak detector reading
6. TLV® leak detector reading
7. Component line size, rounded to nearest inch
Component type and service
Pre-and post-calibration results.
8.
9.
11, 6re found to Provide information that could be used
ic Hleak occurrence rates and estimate average monitoring times
This memorandum presents these data analyses «» i"a nines.
C-29
-------
GARB Data Analysis
CARB is currently performing a separate analysis of these data, as
they relate to local rules. CARB's analyses will include the following
differences from this analysis:
o CARB is to "correct" the leak readings based on the measured
calibration drift in the monitoring instrument between pre-test
and post-test calibrations.
o Those sources measuring 10,000 ppm are not considered leaks by •
CARB, while those measuring greater than 10,000 ppm are leakers.
EPA defines greater than or equal to 10,000 ppm a leak.
o CARB is attempting to change the calibration basis from methane
to hexane for some data.
CARB should publish the results of their analysis in the near future.
EPA Data Analysis
From the field data received, EPA calculated the leak frequency
based on those valves reading greater than or equal to 10,000 ppm organics
and leak occurrence rate on a process unit and overall refinery basis.
Leak frequency was calculated as the number of leaks divided by the
number of components monitored, and expressed as a percentage. The 30-day
leak occurrence rate was calculated by dividing the leak frequency by the
number of months elapsed since the last inspection, and again expressing
the result as a percentage. It should be noted that the sources were
monitored with the instrument probe at 1 cm from the source. Under NSPS
requirements (Method 21), the instrument probe must be placed at the
surface of the component. While the relationship between the organics
concentration and the distance form the source is not known precisely,
readings at 1 cm from the source should normally be lower, reducing the
measured leak frequency compared to measurements taken at the source.
Table 1 provides a summary of the data received by EPA on a refinery
basis. These data are developed in Tables 2 through 13 for each refinery.
These data should be used judiciously, as suggested by the following
general comments on the CARB data.
Four Century Model 108 OVA were used along with four Bacharach TLV
for this survey. The AQMD expressed concerns on the accuracy of TLV
readings as calibration knobs are easily moved, precalibrations of
TLV's were not always done with gas (however, post-calibration were), two
teams did not use gas for either pre or post-calibrations, probe tips were
sometimes contaminated, TLV's were not allowed to stabilize, and some TLV
readings were potentially questionable due to be saturation of instrument
on low scale. One CARB diTutor had leaks in the diTutor probe resulting
in questionabTe readings and another required odd computations to obtain
a,reading. OVA data from the first day at SheTl and the second day at
Fletcher are questionable because one OVA did not hold calibration well.
These data are footnoted on Tables 8 and 10. Some leaks are noted in
excess of 10,000 ppm when the instrument was calibrated on methane.
C-30
-------
Equivalent readings would be 15,800 ppm for AQMD rule based on 10,000 ppm
hexane. Also, the determination of the background reading varied from
CARB team to team.
As mentioned above, EPA also calculated the monitoring time required
for each process unit. These times were calculated by subtracting the
start time for a given process unit from the end time, and dividing the
result by the number of components in the unit. Where gaps in the
monitoring time from one component to the next of more than 15 or 20
minutes were noted, the time of these gaps was subtracted from the
monitoring time. Shorter gaps (< 15 minutes) were not subtracted, however,
to allow for normal operator breaks, instrument flameouts, and other
normal break periods.
References
1. Letter, P.M/Kaplow, ARCO to Central Docket Section, U.S.E.P.A.;
Results fif Refinery Inspections. June 15, 1982. Docket Item
Number IV-D-31.*
2. Memo, T.L. Norwood, PES, Inc., to Docket A-80-44, Local Air Quality
Management District Refinery Inspection Data. November 21, 1983.
Docket Item Number IV-B-18.*
3. Letter, D.M. Newton, SCAQMD to S.R. Wyatt, U.S. E.P.A.; Refinery
Inspection Data. October 24, 1983. Docket Item Number IV-D-37.* .
*Document numbers refer to entries in Docket A-80-44, which can be
found at the U.S. Environmental Protection Agency Library, Waterside
Mall, Washington, D.C.
C-31
-------
Table 1. SUMMARY OF CALIFORNIA AIR RESOURCES BOARD INSPECTION DATA
REFINERY
LOCATION
Tosco "Corp.
Bakersfield
Shell Oil Co.
Martinez
Exxon Co.
Benicia
Chevron USA
Richmond
Arco
Carson
Mobil Oil Corp.
Torrance
Fletcher Oil
Carson
Champlin Oil
Wilmington
Shell Oil
Carson
Chevron USA
El Segundo
Newhall
Newhall .
Powerine
Santa Fe Springs
TOTAL 6
NUMBER OF
SOURCES
INSPECTED
326
816
858
803
591
338
317
435
683
602
152
576
,497
MONITORING
TIME
(min/source)
0.61
1.1
0.72
1.02
• 0.8
1.1
1.1
0.9
0.9
1.1
1.1
0.8
0.9
OVAd
PERCENT
LEAKING
0.31
3.7
3.6
2.1
1.5
3.6
2.2
1.4
1.3
3.2
0.7
2.1
2.4
b
C
0 -
2.4
2.3
1.1
0.5
1.6
0.6
0.3
0.4
2.4
0.0
0.9
2.0
955L
.1.
0.93
-5.0
- 4.9
- 3.1
- 2.5
- 5.6
- 3.8
- 2.5
- 2.2
- 4.0
- 2.1
- 3.3
- 2.8
30 DAY .
OCCURRENCE0
0.02
1.27
1
.0.50
0.17
0.21
0.31
0.42
0.27.
0.24
0.25
0.14
Q. 51
0.47
' PERCENT5
LEAKING
0.61
4.3
4.0
1.7
1.5
3.3
1.9
1.1
1.2
2.3
0.7
1.6
2.3
TLV
95%
C.I.C
0-1.47
2.9-5.7
2.7-5.3
0.8-2.6
0.5-2.5
1.4-5.2
0.4-3.4
0.1 -2.1
0.4-2.0
1.1 -3.5
0.0-2.1
0.6-2.6
1.9-2.7
30 DAY ,
OCCURRENCE
0.05
1.61
0.56
0.14
0.18
0.29
0.36
0.21
0.21
0.18
0.14
0.39
0.41
a. OVA refers to the Foxboro, Inc. organic vapor analyzer; TLV refers to the Bacarach, Inc. "Sniffer"
organic vapor analyzer.
b. Leaks are defined as those sources measuring greater than or equal to 10,000 ppm organics concentration
at a distance of one centimeter.
C. 95$ C.I. = 95 percent confidence interval of percent leaking. This is estimated as P t'2SD, where P =
percent leaking;
SO » standard deviation = ./ P(IOO-P) , and N = number of sources inspected.
d. The 30-day occurrence rates are calculated using the number of sources inspected, the number of days from
the last plant inspection to the CARB inspection, and the measured percent leaking:
30 day occurrence rate
and Plant-weighted rate = E(Neach process un1t X 30 day occurrence)
periods
N
,total sources inspected
C-32
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SECTION C.4
SOUTH COAST AIR QUALITY MANAGEMENT
DISTRICT STUDY DATA SUMMARY
C-45
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UNITED STATES ENVIRONMENTAL PROTECTION AGENCY
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
SEP 1 5 1983
A-80-44
iv-jB-n
MEMORANDUM
SUBJECT: Review of ORD Study of South Coast Air Quality Management
District Fugitive Emissions
FROM:
TO:
K. C. Hustvedt
Petroleum Section, -CPB/ESED (MD-13)
Games F. Durham, Chief
Petroleum Section, CPB/ESED (MD-13)
BACKGROUND AND CONCLUSIONS
™"*~^"^~"™—™'™~™—"""^"^^^^"™"™-™" ^^™HM^^™M^^^™™«^ ^
Several years ago, we requested that the Office of Research and
Development (ORD) analyze the effectiveness of local rules at reducing
fugitive emissions. The ORD contracted with Radian and GCA to perform
fugitive emission testing at two refineries operating under the South
Coast Air Quality Management District (SCAQMD) Rule 466.1 on leakage from
valves and flanges. As possible, the contractors also gathered historical
data on the implementation of Rule 466.1 and other information. The
results of this study are reported in "Evaluation of the Maintenance
Effect on Fugitive Emissions from Refineries in the South Coast Air
Quality Management District," EPA-600/7-82-049, January 1982.1
An analysis of the absolute effectiveness of local rules based on
the historical Rule 466.1 implementation data is not possible because
of changes in the sample populations from test to test. However,
several general observations can be made from this study. The rate of
leak occurrence found in this study is similar to what the results of the
maintenance study^ would predict for the given initial leak frequencies.
At one of the refineries where maintenance was performed whenever the
contractor found a leak, greater than 99 percent of the leaks were
repaired within 2 days with a resulting calculated emission reduction of
95.7 percent. Further, as an indicator of the reliability of portable
detectors at identifying leaking sources, 97.3 percent of the sources
identified as leaking by the original inspection team were also identified
as leaking by a second inspection team. Overall only 2 of the 521 sources
screened (99.6 percent) by two independent screening teams had different
leak/no leak determinations. Regarding the ability to screen all valves
in a process unit, 12.3 percent of the overall valves were not screened
for various reasons, including high background organics concentration,
location, and instrument problems. Only 3.3 percent of the overall valves
could not be monitored because they were difficult to monitor, without
C-46
-------
extraordinary aids such as scaffolding or a cherry picker. Finally by
assessing pump seal maintenance records, it was determined that pump seal
concentration is essentially independent from seal age and that both -
operating and spare mechanical pump seals are replaced on average every 1
to 1.5 years with 90 percent of the seals replaced within 3 years. All
of these data support the estimates we made in the development of the
proposed refinery equipment leaks new source performance standard (NSPS)
Using the results of the SCAQMD study in Radian's leak detection and
repair (LDAR) model-3, I estimated the cost effectiveness of routine
monitoring programs. This analysis shows that replacing their present
programs with monthly monitoring would have a cost effectiveness of about
50 dollars per megagram ($/Mg) and that the incremental cost effectiveness
quarterl* Storing for these plants would be
DISCUSSION
The analysis of the effectiveness of Rule 466.1 in the SCAQMD study
relies upon historical data developed by the refineries in their imple-
mentation of Rule 466.1. Reviewing the trend in percent of sources
leaking from inspection to inspection should give an indication of the
effectiveness of Rule 466.1 at reducing fugitive emissions. In this
testing, however, the number of sources tested often changed more than
the number of sources found leaking, indicating that some unknown portion
of the leaks detected after the first inspection may have been leaking at
the first inspection but were not screened. For this reason, no attempt
has been made to estimate the overall effectiveness of Rule 466 1 at
reducing fugitive emissions. There are data in the SCAQMD study that can
be compared to numbers we used in the proposed refinery equipment leaks
NSPS and these are discussed in the following sections.
Occurrence Rate - Table 4-16 in the SCAQMD report presents historical
data on the implementation of Rule 466.1. These data are used to estimate
leak occurrence in Table 1 based on the following assumptions:
r* A1' ,A11 Jeaks are screened and repaired on the last day of the month
(to develop the time intervals).
2. Leak recurrence is insignificant because of the follow-up screeninq
and maintenance performed under Rule 466.1 for repaired leaks.
3. Changes in instrument, instrument operator, calibration gas and
number of sources screened have a small effect on the percent of sources
found leaking.
4. If no leak detection and repair were performed, leaks would
accumulate from the previous inspection to the next inspection (to estimate
overall occurrence rates from the beginning to the end of the test period).
All of these assumptions appear reasonable except possibly that there is
only a small effect from the change in number of sources screened.
C-47
-------
Table 1 shows that the 30-day occurrence rate from test to test ranged
from 0.24 to 1.80 percent and that the 30-day occurence rate for the
whole test ranged from 0.35 to 0..94 percent for the five units tested.
Table 2 shows a comparison of these overall occurrence rates to the ones
used In the proposed refinery equipment leak NSPS. As you can see, these
rates compare quite favorably, indicating refineries operating under the
SCAQMD Rule 466.1 have similar occurrence rates to those we estimated on
the national average in developing the refinery equipment leaks NSPS.
Maintenance Effectiveness - Chevron used Radian's testing as their annual
check under SCAQMD Rule 466.1. For this Rule, all .leaks must be repaired
within 2 days. Of the 347 valve leaks detected by Radian, 344 were
repaired by means ranging from simple packing adjustment to sealant
injection and valve replacement. The remaining three valves were taken
out of service. This equates to a maintenance effectiveness of 99.1
percent within 2 days, as opposed to the estimate of 90 percent repaired
within 15 days in the refinery leaks NSPS. The reduction in mass emissions
due to maintenance was estimated based on screening valves to be 95.7
percent. In the refinery leaks NSPS, successful leak repair was estimated
to result in an emission reduction of 97.7 percent. As with occurrence
rates, the estimates of maintenance effectiveness in the SCAQMD study
compare favorably with those used in the refinery leaks NSPS.
Test Method Reliability - As in all research efforts, a quality assurance
(QA) check was performed during the SCAQMD testing by the EPA contractors.
As a part of this QA effort, approximately 5 percent of the sources were
independantly screened by a second screener. In this QA testing, 37
sources were found to be leaking during the initial screening and 36 of
these sources, or 97.3 percent, were also found to leaking during the
•second screening. A total of 521 sources were screened in the QA effort,
and all but 2 of the sources were either found to be leaking by both
screeners or found not to be leaking by both screeners.
Difficult-to-Mom'tor Sources - During fugitive emission screening programs
by the EPA contractors, several sources are not monitored for various
reasons. To assess the magnitude of this problem, Radian identified the
reasons sources were not screened during their testing. Table 3 summarizes
these results from Table 4-1 of the SCAQMD report for gas and light-11quid
service valves only. As shown in Table 3, most of the sources not screened
(8.6 percent of the overall sources and almost 70 percent of those hot
screened) could have been screened if ladders had been provided. An
additional 3.3 percent of the 12.6 percent not screened (about a fourth)
were also not screened because of location, but these sources would have
needed extraordinary aids such as scaffolding or a movable crane (cherry
picker) to have been screened. The remaining few sources, about 0.6 percent
of the total, that were not screened were for temporary reasons, such as
the source out of service, sampling problems, or the plant not allowing
the contractor access to certain areas.
C-48
-------
Pump Seal Replacement - The maintenance history of pump seals was acquired
by examining refinery records. Data were available on 98 pumps with a
total of 544 seal replacements. A comparison of the screening value and
the months since most recent seal replacement indicated a slight positive
relationship (concentration increasing with time), but age was not found to
account for a very significant portion of the total variation in screening
values. These data are consistent with our approach to controlling pump
seal emissions, which is based on random accidents, mistakes, or catastrophic
seal failures causing pump seal leaks rather than gradual deterioration of
the seals. Only a routine inspection program can quickly identify these
unpredictable leaks for replacement. Routine seal replacements or infrequent
seal inspections would not be as cost-effective because routine replacement
would cause properly operating seals to be replaced with.no emission reduc-
1 "U!e infr?^uent inspections would allow seals to remain -leaking
_ An analysis of the historical average length of time between seal
replacements was also performed. It was found that the average length of
time between seal replacement was 1 to 1 and 1/2 years and that 90
percent of the pump seals are replaced within 3.years. In the refinery leaks
NSPS, we estimated that pump seals are routinely replacaed on the average
every 2 years, which compares favorably with these findings.
LDAR Analysis - Several inputs for the LDAR model can be derived from the
fnnnfc f? °f ^T-' J****^™™ "***> *on* with other necessary
inputs as documented iji the AID3, to assess the CQSt effect1veness f y
»n *h10?™n£?n1T0JS f°r ,val Ves 1n SCAQMD refineries. The new inputs based
on the SCAQMD study results are compared to the refinery NSPS inputs in
I*blecJiuJhe 1mtial Percent leaking of 6.2 percent is the average for the
five SCAQMD units tested. The emission factor was derived from this initial
leak frequency using the leak/no leak emission factor calculation techniques
developed in the AID. The leak occurrence rate is the average of the
overall occurrence rates shown in Table 2. The emission reduction and
repair rate are also from the SCAQMD study averages as discussed elsewhere
i n this memo.
Although the SCAQMD and NSPS inputs appear similar, the LDAR model was
used to determine the extent to which the inputs could effect the cost
effectiveness of routine monitoring programs. The complete inputs and
outputs of this analysis are attached and the results are summarized in
Table 5. As you can see, all of the cost effectiveness numbers are rather
low, with the highest one, the incremental cost effectiveness of monthly
over quarterly monitoring, less than 1000 $/Mg. y
C-49
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REFERENCES;
1. Evaluation of the Maintenance Effect on Fugitive Emissions From Refineries
in the South Coast Air Quality Management District, EPA 600/7-82-049,
December 1981.
2. Evaluation of Maintenance For Fugitive VOC Emission Control, EPA-600/2-
81-080, May 1981.
3. Fugitive Emission Sources of Organic Compounds--Additional Information
on Emissions, Emission Reductions, and Costs, EPA-450/3-82-010, April 1982.
4. VOC Fugitive Emissions in Petroleum Refining Industry—Background
Information for Proposed Standards, EPA 450/3-81-015a, November 1982.
Attachments
cc: Fred Dimmick, SDB
Tom Rhoads, PES
Refinery Leaks Docket
C-50
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C-53
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TABLE 4, COMPARISON OF SCAQMD STUDY AND REFINERY NSPS LDAR INPUTS
PARAMETER
SCAQMD STUDY
REFINERY NSPSa
Emission Factor (kg/hr)
Monthly Leak Occurrence Rate (%)
Initial Percent Leaking (%)
Emissions Reduction for Successful Repair (%)
Unsuccessful Repair Rate (%)
0.010&
0.6C
6.2
95.7
. 0.9
0.0163
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10
a - From Reference 4.
b - Calculated based on the average percent leaking and the leak/no leak technique
developed in Reference 3.
c - Average occurrence rate from Table 2. The quarterly occurrence rate would be
3 times the monthly rate and the annual occurrence rate 4 times the quarterly
rate.
C-54
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10
TABLE 5. COST EFFECTIVENESS'OF ROUTINE MONITORING BASED ON
SCAQMD STUDY LDAR INPUTS
Monitoring
Interval
(Mo)
12
3
1
12-33
12-ia
3-ia
Emission
Reduction
(percent)
20.7
47.9 -
54.5
27.2
33.8
6.6
(Mg/yr)
18.1
42
47.8
23.9
29.7
5.8
Net
Cost
($/yr)
- 407
-2870
2580
-2463
2987
5450
Cost
Effectiveness
($/Mg)
- 23
- 68
54
-103
100
940
a - These denote the incremental emission reduction, cost, and cost
effectiveness between the two monitoring intervals shown.
C-55
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APPENDIX D
MODEL UNIT AND NATIONWIDE IMPACTS
Attached as Appendix D is a memorandum dated December 13, 1983
that documents the calculation of model units and nationwide impacts of
the promulgated standards.
D-l
-------
A-80-44
IV-B-24
MEMORANDUM
DATE: December 13, 1983
TO: Docket A-80-44, Petroleum Refinery VOC Fugitive Emissions
NSPS
FROM: Thomas.Rhoads, Pacific Environmental Services, Inc.
SUBJECT: Calculation of Model Unit arid Nationwide Impacts
This memorandum documents the calculation of the capital cost,
net annualized cost, and emission reduction resulting from implementation
of the standards. The impacts are presented for each model unit on a
yearly basis and nationwide in the fifth year of implementation of the
standards. The basis and method for calculating the model unit and
nationwide impacts are from the background information documents for
the proposed standards and promulgated standards.
Tables 1 and 2 show model unit and nationwide emission reductions
achieved between baseline and uncontrolled scenarios. Uncontrolled
means the level of control implemented by refineries in the absence of
any regulations to control equipment leaks of VOC. Baseline, however,
reflects a nationwide average level of control implemented as a result
of existing regulations (i.e., State and regional) to control equipment
leaks of VOC. Tables 3 and 4 show model unit and nationwide emission
reductions resulting from implementation of the final standards as the
increment between baseline emissions and the level of emissions following
promulgation of the standards. As shown in Table 4, 31,100 Mg VOC
emission reduction would be achieved in the fifth year of implementation
of the final standards. The cost impacts of the final standards, likewise,
do not include the baseline product recovery credits and costs for
monitoring instruments (those costs incurred by the industry due to
existing regulations). Net annualized costs to implement the final
standards are derived in Tables 6, 7, and 8. Implementation of the
final standards would cost approximately $4.14 million (1980 dollars)
with a cost effectiveness, therefore, of about $130/Mg VOC emission
reduction. The cumulative nationwide capital costs, calculated in
Tables 8 and 9, are projected at about $17.9 million in the fifth year
of implementation of the.final standards.
D-2
-------
Table 1. MODEL UNIT EMISSION REDUCTION BETWEEN
BASELINE AND UNCONTROLLED
Equipment
Pressure
Relief
Devices
Compressors
Open Ended
Lines
Sampling
Connections
Valves
Gas
Light
Liquid
Pumps
Total Emission
Alternative II
Regul atory
Alternative II
Emission
Reduction per
Component
Control (Mg/yr)a
Quarterly 0.63
LDR
Quarterly*: 4.3
LDR
Cap 0.020
No Control " 0
Quarterly 0.14
LDR
Annual <* 0.019
LDR
Annual 0.21
LDR
Reduction Regulatory
(Mg/yr)
Baseline Emission Reduction (Mg/yr)e
Regulatory Alternative II
Model Unit Emission Reduction
(Mg/yr)b
A B C
Compo- Sub- compo- Sub- Compo- Sub-
nents total nents total nents total
3 1.9 7 4.4 20 12.6
1 4.3 3 12.9 8 34.4
70 1.4 140 2.8 420 8.4
10 0 20 0 60 0
130 18.2 260 36.4 780 109
250 4.8 500 9.5 1,500 28.5
7 1.5 14 2.9 40 8.4
32.1 68.9 201
18.0 38.6 113
LDR = leak detection and repair
Footnotes on next page
D-3
-------
Table 1. MODEL UNIT EMISSION REDUCTION BETWEEN
BASELINE AND UNCONTROLLED (concluded)
aFrom BID for the promulgated standards, Appendix A, pages A-4, 7,8,
9, 10, and 14.
unit equipment counts are found in Table 6-1 of the BID for the
proposed standards. The model unit emission reductions are obtained by
summing the products obtained from the per component emission reductions
and the number of components per model unit.
cFrom Table 7-1, BID for the proposed standards. Uncontrolled emission
factor - 15.0 kg/d. Controlled emission factor for quarterly LDR =
3.2 kg/d.
Emission =
Reduction
(15.0 kg/d - 3.2 kg/d) (365 d/yr)T 1 M9 \
= 4.3 Mg/yr V. 1000 kg/
dFrom Table F-3, BID for the proposed standards. Uncontrolled emission
factor =0.26 kg/d
Controlled emission factor for annual LDR = 0.209 kg/d
Emission = (0.26 kg/d - 0.209 kg/d) 0.365
Reduction = 0.019 Mg/yr
eBaseline emission reduction is achieved by industry using existing
levels of control. About 44 percent of the petroleum refining industry
is located in attainment areas for ozone and not subject to equipment
leak regulations (uncontrolled), and about 56 percent is located in
non-attainment areas and subject to State or local regulations
(Regulatory Alternative II). Baseline emission reduction is, therefore,
calculated as 56 percent of the emission reduction achieved under
Regulatory Alternative II.
D-4
-------
Table 2. NATIONWIDE EMISSION REDUCTION BETWEEN
BASELINE AND UNCONTROLLED
Model
Unit
A
B
C
Emission Reduction
Per Model Unit
(Mg/yr)*
18.0
38.6
113
Projected
Model Unitsb
96
106
80
TOTAL
Subtotal
(Mg/yr)
1,730
4,090
9,040
14,900
aEmission reductions from Table 1.
bFrom BID for the proposed standards, Table 7-4.
D-5
-------
r
Table 3. MODEL UNIT EMISSION REDUCTION BETWEEN
NSPS AND BASELINE
Equipment
Pressure
Relief
Devices
Compressors
Open Ended
Li nes
Sampling
Connections
Val ves
Pumps
Emission
Reduction Per
Component
Between
NSPS and
Uncontrolled
Control (Mg/yr)a
Disk 1.4
Barrier 5.5
Fluid
System
Cap 0.020
Closed 0.13
Purge
Monthly 0.10
LDR
Monthly 0.82
LDR
Emission Reduction From Uncontrolled
to NSPS
Emission Reduction From Uncontrolled
to Basel i neb
Emission Reduction From Baseline to NSPSC
Emission Reduction by Model Unit (Mg/yr)
A B C
Compo- Sub- Compo- Sub- Compo- Sub-,
nents total nents total nents total
3 4.2 7 9.8 20 28.'0
1 5.5 3 16.5 8 44.0
70 1.4 140 2.8 420 8.4
10 1.3 20 2.6 60 7.8
380 38.0 760 76.0 2,280 228
7 5.7 14 11.5 40 32.8
56.1 119 349
18.0 38.6 113
z
38.1 80.4 236
BID for the promulgated standards Appendix A, pages A-4, 7, 8, 9, 10, and 14.
bFrom Table 1.
CRepresents emission reduction per model unit resulting from promulgation of the
standards.
D-6
-------
Table 4. NATIONWIDE EMISSION REDUCTION BETWEEN
NSPS AND BASELINE
Model
Unit
A
B
C
Emission Reduction
Per Model Unit
(Mg/yr)a
38.1
80.4
236
Projected
Model Units5
96
106
80
Subtotal
(Mg/yr)
3,660
8,520
18,900
Total
aEmission reductions from Table 3.
bFrom BID for the proposed standards, Table 7-4.
31,100
D-7
-------
Table 5. MODEL UNIT NET ANNUALIZED COST BETWEEN
BASELINE AND UNCONTROLLED
Net Annuali zed
Cost Per
Component
Between
Regul atory
Alternative II
Equipment Control and Uncontrolled3
($/yr)
Pressure Quarterly (170)
Relief LDR
Devices
Compressors'3 Quarterly0 (690)
LDR
Open Ended Cap 9.1
Lines
Sampling No Control 0
Connections
Val ves
Gasc Quarterly (21)
LDR
Llghtd Annual d 2.04
Liquid LDR
Pumps Annual 180
LDR
Regulatory Alternative II Costs Without
Instruments
Regulatory Alternative II Costs With
Instruments^
Net Annual ized Cost Between Baseline and
Uncontrolled*1
Regulatory Alternative II
Net Annual ized Cost
Per Model Unit ($/yr)
ABC
Compo- Sub- Compo- Sub- Compo- Sub-
nents total nents total nents total
3 (510) 7 (1,190) 20 (3,400)
1 (690) 3 (2,070) 8 (5,520)
70 637 140 1,270 420 3,820
10 0 20 0 60 0
130 (2,730) 260 (5,460) 780 (16,400)
250 510 500 1,020 1,500 3,060
7 1,260 14 2,520 40 7,200
(1,520) (3,910) (11,200)
3,980 1,590 (5,700)
2,230 890 (3,190)
LDR « leak detection and repair
( ) - cost savings
aRegulatory Alternative II costs per component are from the BID for promulgated standards
Appendix A, pages A-4, 7, 8, 11, and 15. . .
D-8
-------
Table 5. MODEL UNIT NET ANNUALIZED COST BETWEEN
BASELINE AND UNCONTROLLED (continued)
Quarterly leak detection and repair for compressors, from BID for
the proposed standards, Table F-12. ;
/Initial \ /Repair\ /LaborA /OverA /Capital V
Initial leak repair = I Leak ] t Time 1 I Rate I Head [ Recovery j
y Frequency/ \ /\ •/ \ / \Factor 1\
= (0.35) (40 hrs) ($18/hr) (1.4) (0.163) i
= $57.50 '
Monitoring Labor = (Monitoring labor hours) (Labor rate) = (1 hr) ($18/hr)
= $18
Repair Labor = (Repair Labor hours) (Labor rate) =6 hr ($18/hr) = $108
Administrative = 0.4/Monitoring RepaiA = 0.4 (18 + 108) = $50.40
and Support I Labor + Labor
TOTAL ANNUAL IZED COST = $234
RECOVERY CREDIT = ($215/Mg) (4.3 Mg/yr) = $924
NET ANNUALIZED COST per compressor = is a cost savings of $690
C6as Service Valves, from BID for promulgated standards Table A-6.
dLight Liquid Service Valves, from BID for proposed standards Table F-27.
Initial Leak Repair =/Initial leak] /RepairW Labor\/Over-\ /Capital \
I Time H Rate j\head j( Recovery)
IFrequency
Ahead / F
/x ' \Factor J
= (0.11) (1.13 hr) ($18/hr) (1.4) (0.163) = $0.51
Monitoring Labor =/Fraction of\ /MonitoringW LaborX
I Sources I I Time )\ Rate )
\Screened / N ' x '
= (0.99) (1/60 hr) ($18/hp) (2) = $0.59
Repair Labor = /Fraction of\ /RepairN /LaborN
I Sources I I Time ) I Rate J
V Operated on / x ' '
= 0.168 (1.13) ($18) = $3.42
D-9
-------
Table 5. MODEL UNIT NET ANNUALIZED COST BETWEEN
BASELINE AND UNCONTROLLED (concluded)
Administrative
and Support
+ Repai r
Labor
= 0.4 [Monitoring
(Labor
= 0.4 ($0.59 + $3.42) = $1.60
TOTAL ANNUALIZED COST = $6.12
RECOVERY CREDIT = (0.019/Mg/yr) ($215) = $4.08
NET ANNUALIZED COST = $2.04 per valve
eAnnualized instrument cost from BID for the proposed standards, Tables 8-1
and 8-5. Annualized cost = Capital recovery Cost + Maintenance Cost +
Miscellaneous Cost.
/
/ A /Capital
Capital Recovery Cost =($9,200/Model Unit J X I Recovery Factor]
= $9,200/unit x 0.23
= $2,100/unit
Maintenance Cost = $3,000
Miscellaneous Cost - 0.04 x $9,200 = $368
Total = $5,500/model unit
footnote e from Table 1. Baseline costs = 0.56 x Regulatory
Alternative II.
D-10
-------
Table
Equipment Control
Pressure Rupture
Relief Disk
Devices
Compressors Barrier
Fluid
System
Open Ended Cap
Li nes
Sampling Closed
Connections Purge
Valves Monthly
LDR
Pumps Monthly
LDR
Costs from Uncontrolled to
w/o Instrument
Costs from Uncontrolled to
Instrument0
Costs from Uncontrolled to
6. MODEL UNIT NET ANNUALIZED COSTS BETWEEN
NSPS AND BASELINE
Net Annual i zed
Costs From
Uncontrolled
To NSPS
($/yr)a
580
840
9.1
105
(6)
130
NSPS
NSPS with
Basel inec
Costs from Baseline to NSPSd
Net Annual ized Cost
Model Unit
A
Compo- Sub-
nents total
°3 1,740
1 840
70 637
10 1,050
380 (2,280)
7 910
2,900
/
8,400
2,230
6,170
B
Compo- Sub-
nents total
7 4,060
3 2,520
140 1,270
20 2,100
760 (4,560)
14 1,820
7,210
12,700
890
11,800
Per
C
Compo- Sub-
nents total
20 11,600
8 6,720
420 3,820
60 6,300
2,280 (13,700)
40 5,200
20,000
25,500
(3,190)
28,700
,, LDR = leak detection and repair
( ) = cost savings
*The basis for the control costs for the individual components represent the costs from
uncontrolled to the control required by the standards. From Appendix A of the BID for
the promulgated standards, pages A-4, 7, 8, 11, and 15.
bSee footnote e of Table 5.
CFrom Table 5.
dRepresents model unit net annualized costs between NSPS and baseline.
D-ll
-------
r
Table 7. NATIONWIDE NET ANNUALIZED COSTS FROM
BASELINE TO NSPS
Model
Unit
A
6
C
Net Annual! zed
Cost Per
Model Unit ($/yr)a
6,170
11,800
28,700
Projected
Model Unitsb
96
106
80
Total
Subtotal
(Mg/yp)
592,000
1,250,000
2,300,000
4,140,000
aNet Annualized Costs per model unit from Table 6.
bFrom BID for the proposed standards, Table 7-4.
D-12
-------
Table 8. MODEL UNIT CAPITAL COSTS
Model Unit Capital Cost
($)
Control
Regulatory Alternative IIa
Basel ineb
NSPS (from uncontrolled)
New Unitc
Modi f ied/Reconstruct edd
Unit
NSPS (from Baseline)6
New Unit
Modi f i ed/Reconstructed
Unit
A
13,000
7,280
35,000
39,000
27,700
31,7.00
B
17,000
' 9,520
73,000
81 ,0.00
63,500
71,500
C
31,000
17,400
190,000
210,000
173,000
193,000
aFrom BID for the proposed standards, Table 8-2.
. bSee footnote e of Table 1. Calculated as 56 percent of Regulatory
Alternative II. Baseline capital costs are incurred by industry using
existing levels of control and, therefore, represents a weighted average
between uncontrolled (no cost) and Regulatory Alternative II, not the
actual capital cost incurred by an individual model unit.
cFrom BID for the proposed standards, Table 8-12. Regulatory AlternatfveTT
capital costs are the same as that for the standards.
dFrom BID for the proposed standards, Table 8-13, corrected to include
closed loop sampling under Regulatory Alternative III.
Calculated as the capital cost from uncontrolled to NSPS minus baseline
capital costs. Represents capital cost incurred per model unit regulting
from promulgation of the standards.
D-13
-------
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing}
1. REPORT NO.
EPA-450/3-81-Q15b
3. RECIPIENT'S ACCESSION NO.
4. TITLE AND SUBTITLE
Equipment Leaks of VOC in the Petroleum Refining
Industry—Background Information for Promulgated
Standards
5. REPORT DATE
December 1983
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
8. PERFORMING ORGANIZATION REPORT NO.
I. PERFORMING ORGANIZATION NAME AND ADDRESS
Office of Air Quality Planning and Standards
U.S. Environmental Protection Agency
Research Triangle Park, North Carolina 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, North Carolina 27711
13. TYPE OF REPORT AND PERIOD COVERED
14. SPONSORING AGENCY CODE
EPA/200/04
is. SUPPLEMENTARY NOTES This document presents the background information used by tne
Environmental Protection Agency in developing the promulgated new source performance
standards for equipment of VOC in the petroleum refining industry.
16. ABSTRACT
Standards of performance for the control of volatile organic compound (VOC)
equipment leaks from the petroleum refining industry are being promulgated under
Section 111 of the Clean Air Act. These standards will apply ep .equiipmene leaks of
VOC within new, modified, and reconstructed petroleum refinery 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.
7.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.IOENTIFIERS/OPEN ENDED TERMS C. COSATI Field/Group
Air Pollution
Petroleum Refining
Pollution Control
Standards of Performance
Volatile Organic Compounds (VOC)
Air Pollution Control
13b
8. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (ThisReport;
Unlimited
21. NO. OF PAGES
214
20. SECURITY GLASS /This page/
Unlimited
22. PRICE
EPA Form 2220-1 (Rev. 4-77) PREVIOUS EDITION i s OBSOLETE
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