[Federal Register Volume 85, Number 179 (Tuesday, September 15, 2020)]
[Rules and Regulations]
[Pages 57398-57460]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2020-18115]
[[Page 57397]]
Vol. 85
Tuesday,
No. 179
September 15, 2020
Part III
Environmental Protection Agency
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40 CFR Part 60
Oil and Natural Gas Sector: Emission Standards for New, Reconstructed,
and Modified Sources Reconsideration; Final Rule
Federal Register / Vol. 85 , No. 179 / Tuesday, September 15, 2020 /
Rules and Regulations
[[Page 57398]]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 60
[EPA-HQ-OAR-2017-0483; FRL-10013-60-OAR]
RIN 2060-AT54
Oil and Natural Gas Sector: Emission Standards for New,
Reconstructed, and Modified Sources Reconsideration
AGENCY: Environmental Protection Agency (EPA).
ACTION: Final rule.
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SUMMARY: This action finalizes amendments to the new source performance
standards (NSPS) for the oil and natural gas sector. The Environmental
Protection Agency (EPA) granted reconsideration on the fugitive
emissions requirements, well site pneumatic pump standards,
requirements for certification of closed vent systems (CVS) by a
professional engineer (PE), and the provisions to apply for the use of
an alternative means of emission limitation (AMEL). This final action
includes amendments as a result of the EPA's reconsideration of the
issues associated with the above mentioned four subject areas and other
issues raised in the reconsideration petitions for the NSPS, as well as
amendments to streamline the implementation of the rule. This action
also includes technical corrections and additional clarifying language
in the regulatory text and/or preamble where the EPA concludes further
clarification is warranted.
DATES: This final rule is effective on November 16, 2020.
ADDRESSES: The EPA has established a docket for this action under
Docket ID No. EPA-HQ-OAR-2017-0483. All documents in the docket are
listed on the https://www.regulations.gov/ website. Although listed,
some information is not publicly available, e.g., Confidential Business
Information or other information whose disclosure is restricted by
statute. Certain other material, such as copyrighted material, is not
placed on the internet and will be publicly available only in hard copy
form. Publicly available docket materials are available electronically
through https://www.regulations.gov. Out of an abundance of caution for
members of the public and our staff, the EPA Docket Center and Reading
Room are closed to the public, with limited exceptions, to reduce the
risk of transmitting COVID-19. Our Docket Center staff will continue to
provide remote customer service via email, phone, and webform. For
further information and updates on EPA Docket Center services, please
visit us online at https://www.epa.gov/dockets. The EPA continues to
carefully and continuously monitor information from the Center for
Disease Control, local area health departments, and our Federal
partners so that we can respond rapidly as conditions change regarding
COVID-19.
FOR FURTHER INFORMATION CONTACT: For questions about this action,
contact Ms. Karen Marsh, Sector Policies and Programs Division (E143-
05), Office of Air Quality Planning and Standards, U.S. Environmental
Protection Agency, Research Triangle Park, North Carolina 27711;
telephone number: (919) 541-1065; fax number: (919) 541-0516; and email
address: [email protected].
SUPPLEMENTARY INFORMATION:
Preamble acronyms and abbreviations. A number of acronyms and terms
are used in this preamble. While this may not be an exhaustive list, to
ease the reading of this preamble and for reference purposes, the
following terms and acronyms are defined:
AMEL Alternative Means of Emission Limitation
ANSI American National Standards Institute
AVO Auditory, Visual, and Olfactory
boe Barrels of Oil Equivalent
BSER Best System of Emissions Reduction
CAA Clean Air Act
CAPP Canadian Association of Petroleum Producers
CEDRI Compliance and Emissions Data Reporting Interface
CFR Code of Federal Regulations
CO2 Eq. Carbon dioxide equivalent
CPI Consumer Price Indices
CVS Closed Vent System
DOE Department of Energy
EAV Equivalent Annualized Value
EPA Environmental Protection Agency
FEAST Fugitive Emissions Abatement Simulation Toolkit
GHG Greenhouse Gases
GHGI Greenhouse Gas Inventory
HAP Hazardous Air Pollutant(s)
ITRC Interstate Technology and Regulatory Council
LDAR Leak Detection and Repair
METEC Methane Emissions Technology Evaluation Center
NEMS National Energy Modeling System
NSPS New Source Performance Standards
NSSN National Standards System Network
NTTAA National Technology Transfer and Advancement Act
OGI Optical Gas Imaging
OMB Office of Management and Budget
PE Professional Engineer
PRA Paperwork Reduction Act
PRD Pressure Relief Device
PRV Pressure Relief Valve
PTE Potential To Emit
PV Present Value
REC Reduced Emissions Completion
RFA Regulatory Flexibility Act
RIA Regulatory Impact Analysis
RTC Responses to Comments
SOCMI Synthetic Organic Chemicals Manufacturing Industry
The Court United States Court of Appeals for the District of
Columbia Circuit
tpy Tons Per Year
TSD Technical Support Document
UIC Underground Injection Control
UMRA Unfunded Mandates Reform Act
VOC Volatile Organic Compounds
Organization of this document. The information presented in this
preamble is presented as follows:
I. Executive Summary
A. Purpose of the Regulatory Action
B. Summary of the Major Provisions of This Final Rule
C. Costs and Benefits
II. General Information
A. Does this action apply to me?
B. Where can I get a copy of this document?
C. What is the Agency's authority for taking this action?
D. Judicial Review
III. Background
IV. Summary of the Final Standards
A. Well Completions
B. Pneumatic Pumps
C. Storage Vessels
D. CVS
E. Fugitive Emissions at Well Sites and Compressor Stations
F. AMEL
G. Onshore Natural Gas Processing Plants
H. Sweetening Units
I. Recordkeeping and Reporting
J. Technical Corrections and Clarifications
V. Significant Changes Since Proposal
A. Storage Vessels
B. Fugitive Emissions at Well Sites and Compressor Stations
C. AMEL
VI. Summary of Significant Comments and Responses
A. Major Comments Concerning Storage Vessels
B. Major Comments Concerning Fugitive Emissions at Well Sites
and Compressor Stations
C. Major Comments Concerning AMELs
VII. Impacts of These Final Amendments
A. What are the air impacts?
B. What are the energy impacts?
C. What are the compliance cost reductions?
D. What are the economic and employment impacts?
E. What are the forgone benefits?
VIII. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and
Executive Order 13563: Improving Regulation and Regulatory Review
B. Executive Order 13771: Reducing Regulations and Controlling
Regulatory Costs
C. Paperwork Reduction Act (PRA)
D. Regulatory Flexibility Act (RFA)
E. Unfunded Mandates Reform Act (UMRA)
F. Executive Order 13132: Federalism
[[Page 57399]]
G. Executive Order 13175: Consultation and Coordination With
Indian Tribal Governments
H. Executive Order 13045: Protection of Children From
Environmental Health Risks and Safety Risks
I. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
J. National Technology Transfer and Advancement Act (NTTAA)
K. Executive Order 12898: Federal Actions To Address
Environmental Justice in Minority Populations and Low-Income
Populations
L. Congressional Review Act (CRA)
I. Executive Summary
A. Purpose of the Regulatory Action
The purpose of this action is to finalize amendments to the NSPS
for the Crude Oil and Natural Gas Production source category (located
at 40 Code of Federal Regulations (CFR) part 60, subpart OOOOa) based
on the EPA's reconsideration of those standards. On June 3, 2016, the
EPA published a final rule titled ``Oil and Natural Gas Sector:
Emission Standards for New, Reconstructed, and Modified Sources; Final
Rule,'' at 81 FR 35824 (``2016 NSPS subpart OOOOa''). The 2016 NSPS
subpart OOOOa set the standards for reducing emissions of greenhouse
gases (GHG), in the form of limitations on methane, and volatile
organic compounds (VOC) from the oil and natural gas sources
constructed, modified, or reconstructed after September 15, 2015.\1\
Following promulgation of the final rule, the Administrator received
petitions for reconsideration of several provisions of the 2016 NSPS
subpart OOOOa.\2\ The EPA granted reconsideration on four issues: (1)
The applicability of the fugitive emissions requirements to low
production well sites, (2) the process and criteria for requesting
approval of an AMEL, (3) the well site pneumatic pump standards, and
(4) the requirements for certification of CVS by a PE. On October 15,
2018, the EPA published a proposed rulemaking titled ``Oil and Natural
Gas Sector: Emission Standards for New, Reconstructed, and Modified
Sources Reconsideration,'' in which we proposed amendments to the 2016
NSPS subpart OOOOa to address the issues for which reconsideration was
granted, as well as other implementation issues and technical
corrections. 83 FR 52056. After considering public comments and new
data submitted by the commenters, the EPA is finalizing certain
amendments to the 2016 NSPS subpart OOOOa as proposed, finalizing other
amendments with changes from the proposal in response to comments and
new data that were received, and not finalizing some of the proposed
amendments in response to comments and new data that were received.
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\1\ Docket ID No. EPA-HQ-OAR-2010-0505.
\2\ Copies of the petitions are provided in Docket ID No. EPA-
HQ-OAR-2017-0483.
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In addition to the amendments described above, this action includes
amendments to address other issues raised in the reconsideration
petitions for the 2016 NSPS subpart OOOOa and to clarify and streamline
implementation of the rule. These amendments relate to the following
provisions: Well completions (location of a separator during flowback,
screenouts, and coil tubing cleanouts), onshore natural gas processing
plants (definition of capital expenditure and monitoring), storage
vessels (applicability), and general clarifications (certifying
official and recordkeeping and reporting). Lastly, in addition to the
amendments addressing reconsideration and implementation issues, the
EPA is finalizing technical corrections of inadvertent errors in the
2016 NSPS subpart OOOOa.
In addition to this action, the EPA has published a separate final
rule in the Federal Register of Monday, September 14, 2020, that
finalizes additional amendments to the 2016 NSPS subpart OOOOa which
are not addressed by this action. That separate final rule, titled
``Oil and Natural Gas Sector: Emission Standards for New,
Reconstructed, and Modified Sources Review: Final Rule'' (FRL-10013-44-
OAR; FR Doc. 2020-18114) is herein referred to as the ``Review Rule.''
Specifically, the Review Rule removes sources in the transmission and
storage segment from the source category by revising the definition of
the Crude Oil and Natural Gas Production source category, rescinds the
standards (including both the VOC and methane requirements) applicable
to those sources, and rescinds the methane-specific requirements of the
NSPS applicable to sources in the production and processing segments.
For further information about these additional amendments, see the
final rule published in the Rules and Regulations section of the
Federal Register of Monday, September 14, 2020. Please refer to the
Regulatory Impact Analysis (RIA) for both this action and the Review
Rule to see the combined impacts of both actions.
B. Summary of the Major Provisions of This Final Rule
Provided below is a summary of each key amendment, clarification,
or correction made to the 2016 NSPS subpart OOOOa that is included in
this final action.
Well completions. The EPA is finalizing its proposed amendment to
40 CFR 60.5375a(a)(1)(iii) to allow the separator to be nearby during
flowback, but the separator must be available and ready for use as soon
as it is technically feasible for the separator to function. We are
also amending 40 CFR 60.5375a(a)(1)(i) to clarify that the separator
that is required during the initial flowback stage may be a production
separator as long as it is designed to accommodate flowback. Finally,
we are amending the definition of flowback at 40 CFR 60.5430a to
exclude screenouts, coil tubing cleanouts, and plug drill outs. As
explained in the preamble to the proposed rulemaking, these are
functional processes that allow for flowback to begin; as such, they
are not part of the flowback. 83 FR 52082.
Pneumatic pumps. The EPA is finalizing an amendment to extend the
exemption from control where it is technically infeasible to route
pneumatic pump emissions to a control device. The final rule extends
this exemption to all pneumatic pump affected facilities at all well
sites by removing the reference to greenfield sites in 40 CFR
60.5393a(b) and the greenfield site definition from 40 CFR 60.5430a.
Additionally, in order to qualify for the technical infeasibility
exemption, the 2016 NSPS subpart OOOOa requires certification by a
qualified PE that routing a pneumatic pump to a control device or a
process is technically infeasible. 40 CFR 60.5393a(b)(5). This final
rule allows certification of technical infeasibility by either a
qualified PE or an in-house engineer with expertise on the design and
operation of the pneumatic pump.
Storage vessels. This final rule amends the applicability criteria
for storage vessel affected facilities by establishing criteria for
calculating potential for VOC emissions under different scenarios.
Specifically, for individual storage vessels that are part of a
controlled tank battery (i.e., two or more storage vessels manifolded
together with piping such that all vapors are shared between the
headspace of the storage vessels, and where emissions are routed
through a CVS to a process or a control device with a destruction
efficiency of at least 95.0 percent for VOC emissions) that is subject
to a
[[Page 57400]]
legally and practicably enforceable limit, potential VOC emissions may
be determined by averaging the emissions from the entire tank battery
across the number of storage vessels in the battery. For a controlled
tank battery described above, if the average per storage vessel VOC
emissions are greater than 6 tons per year (tpy), then all storage
vessels in that battery are storage vessel affected facilities. For
individual storage vessels that do not meet the criteria described
above, the potential VOC emissions is determined according to the
proposed criteria, which the EPA is finalizing in this action; where
the VOC emissions are greater than 6 tpy, the storage vessel is an
affected facility.
CVS. This final rule incorporates the option for owners and
operators to demonstrate that the pneumatic pump CVS is operated with
no detectable emissions by (1) an annual inspection using EPA Method 21
of appendix A-7 of part 60 (``Method 21''), (2) monthly audio/visual/
olfactory (AVO) monitoring, or (3) optical gas imaging (OGI) monitoring
at the frequencies specified for fugitive monitoring. Additionally,
this final rule incorporates the option for a storage vessel CVS to be
monitored by either monthly AVO monitoring or OGI monitoring at the
frequencies specified for fugitive monitoring. Finally, this final rule
allows for certification of the CVS design and capacity assessment by
either a qualified PE or an in-house engineer with expertise on the
design and operation of the CVS.
Fugitive emissions requirements. The EPA is finalizing several
amendments to the requirements for the collection of fugitive emissions
components at well sites and compressor stations. The monitoring
frequencies in this final rule are semiannual for well sites and
compressor stations, and annual for well sites and compressor stations
located on the Alaska North Slope. The final rule excludes low
production well sites (where the total combined oil and natural gas
production for the well site is at or below 15 barrels of oil
equivalent (boe) per day) from fugitive emissions monitoring, as long
as they maintain the records specified in the final rule to demonstrate
that their total well site production is at or below 15 boe per day. A
low production well site that subsequently produces above this
threshold is required to comply with the fugitive emissions
requirements.
This final rule also finalizes separate initial monitoring
requirements for the Alaska North Slope compressor stations, as
proposed. Compressor stations located on the Alaska North Slope that
start up between September and March must conduct initial monitoring
within 6 months of startup or by June 30, whichever is later;
compressor stations that start up between April and August must conduct
initial monitoring within 90 days of startup. This final rule revises
the initial monitoring requirement for well sites and compressor
stations not located on the Alaska North Slope by requiring initial
monitoring within 90 days of startup. Additionally, this final rule
allows fugitive monitoring to stop when all major production and
processing equipment is removed from a well site such that it becomes a
wellhead-only well site.
In addition to the amendments related to monitoring frequencies,
the final rule (1) specifies the events that constitute modifications
to an existing separate tank battery surface site (which is a ``well
site'' for purposes of well site fugitive emissions requirements); (2)
revises the repair requirements to specify that a first attempt at
repair must be made within 30 days of identifying fugitive emissions
and final repair must be made within 30 days of the first attempt at
repair; (3) amends the definition of a well site to exclude third-party
equipment located downstream of the custody meter assembly and
Underground Injection Control (UIC) Class I non-hazardous and UIC Class
II disposal wells from the fugitive emissions requirements; and (4)
revises the requirements for the monitoring plan, recordkeeping, and
reporting associated with the fugitive emissions requirements.
AMEL. This final rule amends the provisions for application of an
AMEL for emerging technologies or for existing state fugitive emissions
programs. Additionally, this final rule provides alternative fugitive
emissions standards for well sites and compressor stations located in
specific states.
Onshore natural gas processing plants. This final rule revises the
definition of ``capital expenditure'' at 40 CFR 60.5430a by replacing
the equation used to determine the percent of replacement cost, ``Y'',
with one that is based on the ratio of consumer price indices (CPI).
Additionally, this final rule exempts components that are in VOC
service for less than 300 hours/year from monitoring. The EPA is also
revising the equipment leak standards for onshore natural gas
processing plants (40 CFR 60.5400a) to include the same initial
compliance provision that is in the original equipment leak standards
for onshore natural gas processing plants. 40 CFR part 60, subpart KKK.
That provision, which is codified at 40 CFR 60.632(a), requires
compliance ``as soon as practicable but no later than 180 days after
initial startup.'' The EPA has not been able to find a record
explaining or otherwise indicating that we intended to change this
initial compliance deadline for the leak standards at onshore natural
gas processing plants when NSPS subparts OOOO and OOOOa were
promulgated; accordingly, in these amendments to NSPS subpart OOOOa,
the EPA is adding this provision back into the leak standards for
onshore natural gas processing plants in NSPS subpart OOOOa at 40 CFR
60.5400a.
Sweetening units. This final rule revises the affected facility
description for the sulfur dioxide (SO2) standards to
correctly define such affected facilities as any onshore sweetening
unit that processes natural gas produced from either onshore or
offshore wells at 40 CFR 60.5365a(g).
C. Costs and Benefits
The EPA has projected the compliance cost reductions, emissions
changes, and forgone benefits that may result from the final
reconsideration. The projected cost reductions and forgone benefits are
presented in detail in the RIA accompanying this final rule. The RIA
focuses on the elements of the final rule--the provisions related to
fugitive emissions requirements and certification by a PE--that are
likely to result in quantifiable cost or emissions changes compared to
a baseline that includes the 2016 NSPS subpart OOOOa requirements. We
estimated the effects of this final rule for all sources that are
projected to change compliance activities under this action for the
analysis years 2021 through 2030. The RIA also presents the present
value (PV) and equivalent annualized value (EAV) of costs, benefits,
and net benefits of this action in 2016 dollars.
A summary of the key results of this final rule is presented in
Table 1. Table 1 presents the PV and EAV, estimated using discount
rates of 7 and 3 percent, of the changes in benefits, costs, and net
benefits, as well as the change in emissions under the final rule.
Here, the EPA refers to the cost reductions as the ``benefits'' of this
rule and the forgone benefits as the ``costs'' of this rule in Table 1.
The net benefits are the benefits (cost reductions) minus the costs
(forgone benefits).
[[Page 57401]]
Table 1--Cost Reductions, Forgone Benefits and Forgone Emissions Reductions of the Final Rule, 2021 Through 2030
[Millions 2016$]
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7-Percent discount rate 3-Percent discount rate
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PV EAV PV EAV
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Benefits (Total Cost Reductions)................ $750 $100 $950 $110
Costs (Forgone Benefits)........................ 19 2.5 71 8.1
Net Benefits \1\................................ 730 97 880 100
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Emissions....................................... Forgone Reductions
Methane (short tons)........................ 450,000
VOC (short tons)............................ 120,000
Hazardous Air Pollutant(s) (HAP) (short
tons)...................................... 4,700
Methane (million metric tons carbon dioxide
equivalent (CO2 Eq.)).......................... 10
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Note: Estimates are rounded to two significant digits and may not sum due to independent rounding.
This final rule is expected to result in benefits (compliance cost
reductions) for affected owners and operators. The PV of these benefits
(cost reductions), discounted at a 7-percent rate, is estimated to be
about $750 million, with an EAV of about $100 million (Table 1). Under
a 3-percent discount rate, the PV of cost reductions is $950 million,
with an EAV of $110 million (Table 1).
The estimated costs (forgone benefits) include the monetized
climate effects of the projected increase in methane emissions under
the final rule. The PV of these climate-related costs (forgone
benefits), discounted at a 7-percent rate, is estimated to be about $19
million, with an EAV of about $2.5 million (Table 1). Under a 3-percent
discount rate, the PV of the climate-related costs (forgone benefits)
is about $71 million, with an EAV of about $8.1 million (Table 1). The
EPA also expects that there will be increases in VOC and HAP emissions
under the proposal. While the EPA expects that the forgone VOC emission
reductions may also degrade air quality and adversely affect health and
welfare effects associated with exposure to ozone, particulate matter
with a diameter of 2.5 micrometers or less (PM2.5), and HAP,
we did not quantify these effects at this time. This omission should
not imply that these forgone benefits do not exist. To the extent that
the EPA were to quantify these ozone and particulate matter (PM)
impacts, the Agency would estimate the number and value of avoided
premature deaths and illnesses using an approach detailed in the
Particulate Matter National Ambient Air Quality Standards (NAAQS) and
Ozone NAAQS RIA (U.S. EPA, 2012; U.S. EPA, 2015). Such an analysis
would account for the distribution of air pollution-attributable risks
among populations most vulnerable and susceptible to PM2.5
and ozone exposure.
The PV of the net benefits of this rule, discounted at a 7-percent
rate, is estimated to be about $730 million, with an EAV of about $97
million (Table 1). Under a 3-percent discount rate, the PV of net
benefits is about $880 million, with an EAV of about $100 million
(Table 1).
II. General Information
A. Does this action apply to me?
Categories and entities potentially affected by this action
include:
Table 2--Industrial Source Categories Affected by This Action
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Examples of
Category NAICS code \1\ regulated entities
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Industry.......................... 211120 Crude Petroleum
Extraction.
211130 Natural Gas
Extraction.
221210 Natural Gas
Distribution.
486110 Pipeline
Distribution of
Crude Oil.
486210 Pipeline
Transportation of
Natural Gas.
Federal Government................ .............. Not affected.
State/local/tribal government..... .............. Not affected.
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\1\ North American Industry Classification System.
This table is not intended to be exhaustive, but rather provides a
guide for readers regarding entities likely to be regulated by this
action. Other types of entities not listed in the table could also be
affected by this action. To determine whether your entity is affected
by this action, you should carefully examine the applicability criteria
found in the final rule. If you have questions regarding the
applicability of this action to a particular entity, consult the person
listed in the FOR FURTHER INFORMATION CONTACT section, your air
permitting authority, or your EPA Regional representative listed in 40
CFR 60.4 (General Provisions).
B. Where can I get a copy of this document?
This final action is available in the docket at https://www.regulations.gov/, Docket ID No. EPA-HQ-OAR-2017-0483. Additionally,
following signature by the Administrator, the EPA will post a copy of
this final action at https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-industry. This website provides information on all of
the EPA's actions related to control of air pollution in the oil and
natural gas industry. Following publication in the Federal Register,
the EPA will post the Federal Register version of the final rule and
key technical documents at this same website. A redline version of the
regulatory language that incorporates the final changes in this action
is available in the docket for this action (Docket ID No. EPA-HQ-OAR-
2017-0483).
[[Page 57402]]
C. What is the Agency's authority for taking this action?
This action, which finalizes amendments to the 2016 NSPS subpart
OOOOa, is based on the same legal authorities that the EPA relied upon
for the original promulgation of the 2016 NSPS subpart OOOOa. The EPA
promulgated the 2016 NSPS subpart OOOOa pursuant to its standard-
setting authority under section 111(b)(1)(B) of the Clean Air Act (CAA)
and in accordance with the rulemaking procedures in section 307(d) of
the CAA. Section 111(b)(1)(B) of the CAA requires the EPA to issue
``standards of performance'' for new sources in a category listed by
the Administrator based on a finding that the category of stationary
sources causes or contributes significantly to air pollution which may
reasonably be anticipated to endanger public health or welfare. In the
Review Rule (published in the Federal Register of Monday, September 14,
2020), the EPA has interpreted CAA section 111(b)(1)(B) to require a
determination that the emissions of any air pollutant not already
subject to an NSPS for the source category (or evaluated in association
with the listing of the source category) cause or contribute
significantly to air pollution which may reasonably be anticipated to
endanger public health or welfare. CAA section 111(a)(1) defines ``a
standard of performance'' as ``a standard for emissions of air
pollutants which reflects the degree of emission limitation achievable
through the application of the best system of emission reduction which
(taking into account the cost of achieving such reduction and any
nonair quality health and environmental impact and energy requirement)
the Administrator determines has been adequately demonstrated.'' The
standard that the EPA develops, based on the best system of emission
reduction (BSER) is commonly a numerical emission limit, expressed as a
performance level (e.g., a rate-based standard). However, CAA section
111(h)(1) authorizes the Administrator to promulgate a work practice
standard or other requirements, which reflect the best technological
system of continuous emission reduction, if it is not feasible to
prescribe or enforce a standard of performance. This action includes
amendments to the fugitive emissions standards for well sites and
compressor stations, which are work practice standards promulgated
pursuant to CAA section 111(h)(1). 81 FR 35829.
The final amendments in this document result from the EPA's
reconsideration of various aspects of the 2016 NSPS subpart OOOOa.
Agencies have inherent authority to reconsider past decisions and to
revise, replace, or repeal a decision to the extent permitted by law
and supported by a reasoned explanation. FCC v. Fox Televisions
Stations, Inc., 556 U.S. 502, 515 (2009); Motor Vehicle Mfrs. Ass'n v.
State Farm Mutual Auto. Ins. Co., 463 U.S. 29, 42 (1983) (``State
Farm''). ``The power to decide in the first instance carries with it
the power to reconsider.'' Trujillo v. Gen. Elec. Co., 621 F.2d 1084,
1086 (10th Cir. 1980); see also, United Gas Improvement Co. v. Callery
Properties, Inc., 382 U.S. 223, 229 (1965); Mazaleski v. Treusdell, 562
F.2d 701, 720 (D.C. Cir. 1977).
D. Judicial Review
Under section 307(b)(1) of the CAA, judicial review of this final
rule is available only by filing a petition for review in the United
Stated Court of Appeals for the District of Columbia Circuit by
November 16, 2020. Moreover, under section 307(b)(2) of the CAA, the
requirements established by this final rule may not be challenged
separately in any civil or criminal proceedings brought by the EPA to
enforce these requirements. Section 307(d)(7)(B) of the CAA further
provides that ``[o]nly an objection to a rule or procedure which was
raised with reasonable specificity during the period for public comment
(including any public hearing) may be raised during judicial review.''
This section also provides a mechanism for the EPA to convene a
proceeding for reconsideration, ``[i]f the person raising an objection
can demonstrate to the EPA that it was impracticable to raise such
objection within [the period for public comment] or if the grounds for
such objection arose after the period for public comment (but within
the time specified for judicial review) and if such objection is of
central relevance to the outcome of the rule.'' Any person seeking to
make such a demonstration to us should submit a Petition for
Reconsideration to the Office of the Administrator, U.S. EPA, Room
3000, EPA WJC, 1200 Pennsylvania Ave. NW, Washington, DC 20460, with a
copy to both the person(s) listed in the preceding FOR FURTHER
INFORMATION CONTACT section, and the Associate General Counsel for the
Air and Radiation Law Office, Office of General Counsel (Mail Code
2344A), U.S. EPA, 1200 Pennsylvania Ave. NW, Washington, DC 20460.
III. Background
On June 3, 2016, the EPA published a final rule titled ``Oil and
Natural Gas Sector: Emission Standards for New, Reconstructed, and
Modified Source; Final Rule,'' at 81 FR 35824 (``2016 NSPS subpart
OOOOa''). The 2016 NSPS subpart OOOOa established standards of
performance for GHG and VOC emissions from new, modified, and
reconstructed sources in the oil and natural gas sector. For further
information on the 2016 NSPS subpart OOOOa, see 81 FR 35824 (June 3,
2016) and associated Docket ID No. EPA-HQ-OAR-2010-0505. Following
promulgation of the final rule, the Administrator received petitions
for reconsideration of several provisions of the 2016 NSPS subpart
OOOOa. Copies of the petitions are provided in the docket for this
final rule (Docket ID No. EPA-HQ-OAR-2017-0483). Several states and
industry associations also sought judicial review of the rule, and that
litigation is currently being held in abeyance. American Petroleum
Institute, et al. v. EPA, No. 13-1108 (D.C. Cir.) (and consolidated
cases).
In a letter to the petitioners dated April 18, 2017, the EPA
granted reconsideration of the fugitive emissions requirements at well
sites and compressor stations.\3\ In a subsequent notification, the EPA
granted reconsideration of two additional issues: Well site pneumatic
pump standards and the requirements for certification of CVS by a
PE.\4\ On October 15, 2018, the EPA proposed amendments and
clarifications to address the issues under reconsideration, as well as
issues related to the implementation of the 2016 NSPS subpart OOOOa
that have come to the EPA's attention. During this rulemaking, the EPA
reviewed additional information, including information in the annual
compliance reports submitted for the 2016 NSPS subpart OOOOa and on
costs associated with fugitive emissions monitoring. The additional
information has allowed the EPA to more accurately assess the emission
reductions and costs associated with the fugitive emissions
requirements of the 2016 NSPS subpart OOOOa before evaluating revisions
in this rulemaking. Further, the EPA used the additional information to
update the overall burden estimates for the 2016 NSPS subpart OOOOa,
thus, providing a more accurate baseline on which to compare any burden
reductions achieved through this final rule. Upon review of the updated
cost estimates,
[[Page 57403]]
the EPA concludes the burden of the 2016 NSPS subpart OOOOa was
underestimated, and this rulemaking provided an opportunity to reduce
the burden of the rule, particularly related to the recordkeeping and
reporting requirements. This action finalizes amendments that would
significantly reduce the recordkeeping and reporting burden of the rule
while continuing to assure compliance. This action also addresses
several other implementation issues that were raised following
promulgation of the 2016 NSPS subpart OOOOa. The EPA is addressing
these issues at the same time to provide clarity and certainty for the
public and the regulated community regarding these requirements.
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\3\ See Docket ID Item No. EPA-HQ-OAR-2010-0505-7730.
\4\ 82 FR 25730.
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IV. Summary of the Final Standards
This final rule amends certain requirements in the 2016 NSPS
subpart OOOOa, as discussed in this section. These amendments are
effective on November 16, 2020. Therefore, the standards in NSPS
subpart OOOOa change from that date forward. Accordingly, after
November 16, 2020, all affected facilities that commenced construction,
reconstruction, or modification after September 18, 2015 must comply
with the 2016 NSPS subpart OOOOa as amended; the previous requirements
no longer apply.
A. Well Completions
The 2016 NSPS subpart OOOOa requires that the owner or operator of
a well affected facility have a separator on site during the entire
flowback period. 40 CFR 60.5375a(a)(1)(iii). The EPA proposed and
received supportive comments on allowing the separator to be located in
close enough proximity to the well site for use as soon as sufficient
flowback is present for the separator to function. Consistent with the
proposal, this final rule amends 40 CFR 60.5375a(a)(1)(iii) to allow
the separator to be at a nearby centralized facility or well pad that
services the well affected facility during flowback as long as the
separator can be utilized as soon as it is technically feasible for the
separator to function. The EPA is also amending 40 CFR
60.5375a(a)(1)(i) to clarify that the separator that is required during
the initial flowback stage may be a production separator as long as it
is also designed to accommodate flowback.
The October 15, 2018, proposal also included proposed amendments to
the definition of flowback. The 2016 NSPS subpart OOOOa, 40 CFR
60.5430a defines flowback as the process of allowing fluids and
entrained solids to flow from a well following a treatment, either in
preparation for a subsequent phase of treatment of in preparation for
cleanup and returning the well to production. The term flowback also
means the fluids and entrained solids that emerge from a well during
the flowback process. The flowback period begins when material
introduced into the well during the treatment returns to the surface
following hydraulic fracturing or refracturing. The flowback period
ends when either the well is shut in and permanently disconnected from
the flowback equipment or at the startup of production. The flowback
period includes the initial flowback stage and the separation flowback
stage.
In the October 15, 2018, proposed rulemaking, the EPA explained
that screenouts, coil tubing cleanouts, and plug drill outs are
functional processes that allow for flowback to begin; as such, they
are not part of the flowback. 83 FR 52082. The proposed rulemaking
included definitions for screenouts, coil tubing cleanouts, and plug
drill outs, as proposed. Specifically, a screenout is an attempt to
clear proppant from the wellbore in order to dislodge the proppant out
of the well. A coil tubing cleanout is a process where an operator runs
a string of coil tubing to the packed proppant within a well and jets
the well to dislodge the proppant and provide sufficient lift energy to
flow it to the surface. A plug drill-out is the removal of a plug (or
plugs) that was used to isolate different sections of the well. The EPA
proposed to exclude screenouts, coil tubing cleanouts, and plug drill
outs from the definition of flowback. This final rule amends the
definition of flowback and finalizes the definitions for screenouts,
coil tubing cleanouts, and plug drill outs, as proposed.
This final rule does not include a definition for a permanent
separator. The EPA proposed such a definition in conjunction with our
proposal to streamline reporting and recordkeeping requirements for
flowback routed through production separators (which we referred to as
``permanent separators'' in the proposed rulemaking). As explained in
the preamble to the proposed rulemaking, when a production separator is
used for both well completions and production, the production separator
is connected at the onset of the flowback and stays on after flowback
and at the startup of production; in that event, certain reporting and
recordkeeping requirements associated with well completions (e.g.,
information about when a separator is hooked up or disconnected during
flowback) would be unnecessary. 83 FR 52082. We, therefore, proposed to
remove such unnecessary data reporting and recordkeeping requirements
when a ``permanent separator'' (as defined in the proposed rulemaking)
is used for flowback. Upon further review, we learned that the term
``permanent separator,'' as defined in our proposed rulemaking, does
not accurately describe production separators that are also used during
flowback because such production separators may not be permanent
fixtures of a site. Therefore, while the final rule streamlines
reporting and recordkeeping requirements for flowback routed through
production separators, on the condition that those separators are
designed to accommodate flowback, it does not include the term
``permanent separator'' or the proposed definition. The details of
these streamlined elements are provided in section IV.I.1 of this
preamble.
B. Pneumatic Pumps
Under the 2016 NSPS subpart OOOOa, a pneumatic pump located at a
non-greenfield site is not required to reduce its emissions by 95
percent if it is technically infeasible to route the pneumatic pump to
a control device or process. This final rule expands the technical
infeasibility exemption to pneumatic pumps at all well sites by
removing the reference to greenfield site in 40 CFR 60.5393a(b) and the
associated definition of greenfield site at 40 CFR 60.5430a. For the
2016 NSPS subpart OOOOa, the EPA concluded that circumstances that
could otherwise make control of a pneumatic pump technically infeasible
at an existing location could be addressed in the design and
construction of a new site. In the proposal, the EPA explained
petitioners' concerns that, even at greenfield sites, certain scenarios
present circumstances where the control of a pneumatic pump may be
technically infeasible despite the site being newly designed and
constructed. 83 FR 52061. We, therefore, proposed to expand the
technical infeasibility provision to apply to pneumatic pumps at all
well sites and solicited comments on scenarios where routing a pump to
a control device or process would be technically infeasible at
greenfield sites. The EPA received numerous comments in support of the
proposal. After consideration of the comments and further review of the
standards, this action finalizes the proposed exemption from control if
it is technically infeasible to route emissions from a pneumatic pump
to a control device at all well sites, including greenfield sites. In
addition to the reasons specified in the proposal, the EPA has
reevaluated
[[Page 57404]]
the 2016 NSPS subpart OOOOa standards for pneumatic pumps, and it is
clear that the EPA did not intend to require the installation of a
control device for the sole purpose of controlling emissions from a
pneumatic pump, even at greenfield sites. Furthermore, in the 2016 NSPS
subpart OOOOa, the assessment of technical infeasibility for a
pneumatic pump is conducted within the context of an existing control
device, not a control device that might be installed to also
accommodate the pneumatic pump emissions. Therefore, the EPA concludes
that when determining technical feasibility at any site, the technical
feasibility is determined for the routing of pneumatic pump emissions
to the controls which are needed for the processes at the site.
Moreover, while it is likely uncommon that an owner or operator cannot
design a greenfield site with a control device to reduce pneumatic pump
emissions (e.g., because the design from conception would be able to
include necessary scenarios), the EPA cannot account for every scenario
that may occur, especially given the potential intermittent nature of
pneumatic pump emissions. Therefore, the EPA agrees with Petitioners
and numerous commenters that it is appropriate to allow the owner or
operator to demonstrate that it is technically infeasible to route
pneumatic pump emissions to a control device or a process at any well
site. The owner or operator must justify and provide professional or
in-house engineering certification for any site where the control of
pneumatic pump emissions is technically infeasible. The expansion of
the technical infeasibility provision is reflected in 40 CFR
60.5393a(b), where we are removing paragraphs (b)(1) and (2).
In addition, we are amending paragraph (b)(5) to state that boilers
and process heaters are not control devices for the purposes of the
pneumatic pump standards. Two commenters stated that boilers and
process heaters located at well sites are not inherently designed for
the control of emissions and raised concerns that routing pneumatic
pump emissions to these devices may result in frequent safety trips and
burner flame instability (i.e., high temperature limit shutdowns, loss
of flame signal, etc.).\5\ The comments further contend that requiring
the technical infeasibility evaluation for every boiler and process
heater located at a wellsite would result in unnecessary administrative
burden since each such evaluation would be raising the same concerns
described above. The EPA agrees with the commenters and has revised the
standards to state that boilers and process heaters are not considered
control devices for the purposes of controlling pneumatic pump
emissions.
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\5\ See Docket ID Item Nos. EPA-HQ-OAR-2017-0483-0781 and EPA-
HQ-OAR-2017-0483-0801.
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Additionally, the EPA is finalizing revisions to the certification
requirements for the determination that it is technically infeasible to
route emissions from pneumatic pumps to a control device or process.
The 2016 NSPS subpart OOOOa requires certification of technical
infeasibility by a qualified PE; however, the EPA proposed allowing
this certification by either a PE or an in-house engineer because in-
house engineers may be more knowledgeable about site design and control
than a third-party PE. After considering the comments, some supporting
and some opposing the proposal, the EPA continues to believe that
certification by an in-house engineer is appropriate. We are,
therefore, amending the rule to allow certification of technical
infeasibility by either a PE or an in-house engineer with expertise on
the design and operation of the pneumatic pump.
C. Storage Vessels
The storage vessel standards apply to individual storage vessels
with the potential for VOC emissions of 6 tpy or greater. The 2016 NSPS
subpart OOOOa requires a calculation of the potential for VOC emissions
from individual storage vessels. In the proposal, the EPA sought to
address instances where storage vessels are designed and operated as a
manifolded battery and to address questions regarding where averaging
emissions may be appropriate for the calculation of potential for VOC
emissions. This final rule addresses the challenges of calculating the
potential for VOC emissions from individual storage vessels that are
part of a controlled battery by specifying separate calculation
requirements for these storage vessels. Specifically, the final rule
allows owners and operators to average the emissions across the number
of storage vessels in a controlled battery provided that specific
design and operational criteria are met. These specific design and
operational criteria include requirements to manifold the vessels such
that all vapors are shared between the headspace of the storage vessels
and route the collected vapors through a CVS to a process or a control
device with a destruction efficiency of at least 95.0 percent for VOC
emissions, and must be included in legally and practicably enforceable
limits in a permit or other requirement established under a Federal,
state, local, or tribal authority. Under the final rule, if these
criteria are met, the owner or operator may calculate the average
emissions from the individual storage vessels in that battery to
determine if the average emissions are greater than 6 tpy. If the
average emissions are greater than 6 tpy, then each of the individual
storage vessels in that battery is a storage vessel affected facility.
However, if the average emissions are less than 6 tpy, then none of the
storage vessels in that battery are a storage vessel affected facility.
In addition, the final rule finalizes the proposed methods for
calculating the potential for VOC emissions for storage vessels that do
not meet the design and operational criteria specified above. Those
storage vessels include individual storage vessels, as well as
manifolded storage vessels that do not meet the criteria specified
(e.g., less than 95-percent control). These storage vessels must
determine applicability by calculating their potential for VOC
emissions in accordance with the methods specified in this final rule.
The calculation of the potential for VOC emissions may take into
account legally and practically enforceable limits on storage vessels
but must be determined on an individual storage vessel basis without
averaging emissions across the number of storage vessels at the site,
even if the storage vessels are manifolded together. If the potential
for VOC emissions from the individual storage vessel is greater than 6
tpy, then that storage vessel is a storage vessel affected facility. If
the potential for VOC emissions from the individual storage vessel is
less than 6 tpy, then that storage vessel is not a storage vessel
affected facility.
The EPA is also amending the applicability criteria to clarify how
owners and operators must determine the potential for VOC emissions for
storage vessels located at onshore natural gas processing plants and
compressor stations. The 2016 NSPS subpart OOOOa specifies that the
calculation is based on the first 30 days of production to an
individual storage vessel. We received comments on the proposal that
this production period is not an accurate reflection of the potential
for VOC emissions from storage vessels not located at a well site.
Specifically, onshore natural gas processing plants and compressor
stations are designed to process or transport a specific capacity of
gas from multiple sites upstream of these facilities. The design
capacity is based on planned growth with additional sites coming online
over time, which means
[[Page 57405]]
the storage vessels at gas processing plants and compressor stations do
not receive the maximum throughput for which they are designed during
the first 30 days of their operation. For these storage vessels, the
commenters indicated they have been utilizing forecasting to predict
future throughput and emissions when applying for an operating permit.
The EPA agrees that the language in the 2016 NSPS subpart OOOOa does
not appropriately capture the information needed to make an informed
applicability determination for these storage vessels. Therefore, we
are revising the final rule to clarify that, for storage vessels
located at onshore natural gas processing plants and compressor
stations, the potential for VOC emissions may be determined based on
the emission limit or throughput limit (as an input for calculating the
potential for VOC emissions), established in a legally and practicably
enforceable limit, or based on the projected maximum average daily
throughput determined using generally accepted engineering models, such
as process simulations based on representative or actual liquid
analysis to determine volumetric condensate rates from the storage
vessels based on the maximum gas throughput capacity of each facility.
D. CVS
The 2016 NSPS subpart OOOOa requires that CVS be operated with no
detectable emissions, as demonstrated through specific monitoring
requirements associated with the specific affected facilities (i.e.,
storage vessels, pneumatic pumps, centrifugal compressors, and
reciprocating compressors). In the October 15, 2018, proposal, the EPA
proposed amending the requirements for CVS associated with pneumatic
pumps to require monthly AVO monitoring instead of the required annual
Method 21 monitoring, thereby aligning the demonstration requirements
for pneumatic pumps with those for storage vessels. 83 FR 52083. The
EPA received comments recommending (1) retaining annual Method 21 as an
option and (2) including OGI monitoring as an additional option because
OGI is already being used to monitor fugitive emissions components at
the well site and the CVS can readily be monitored at the same time.
Based on these public comments, the EPA is amending the requirements
for these no detectable emissions demonstrations for CVS for pneumatic
pumps, with some changes from the proposal. Specifically, we are
incorporating the option to demonstrate the pneumatic pump CVS is
operated with no detectable emissions by an annual inspection using
Method 21, monthly AVO monitoring, or OGI monitoring at the frequencies
specified in section IV.E of this preamble.
The 2016 NSPS subpart OOOOa requires monthly AVO inspections on CVS
for storage vessels to demonstrate operation with no detectable
emissions. Similar to CVS for pneumatic pumps, the EPA is adding OGI
monitoring at the frequencies specified in section IV.E of this
preamble as another option for demonstrating no detectable emissions
from CVS for storage vessels.
While the final rule provides these options for demonstrating the
operation of the CVS with no detectable emissions, it is important to
note that any detection with AVO or any visual image when using OGI is
considered an indication of detected emissions. It is not the EPA's
intent to allow owners and operators to conduct an inspection using OGI
that results in the visual image of emissions, and then follow that
inspection with AVO to conclude no emissions are present. If any of the
options specified result in detected emissions, the standard of ``no
detectable emissions'' is not met.
Additionally, the EPA is finalizing revisions to the certification
requirements for CVS design. Specifically, we are amending the rule to
allow either a PE or an in-house engineer with expertise on the design
and operation of the CVS to certify the design and operation will meet
the requirement to route all vapors to the control device or back to
the process.
E. Fugitive Emissions at Well Sites and Compressor Stations
1. Monitoring Frequency
The 2016 NSPS subpart OOOOa requires semiannual monitoring and
quarterly monitoring for fugitive emissions at well sites and
compressor stations, respectively. The EPA proposed amending these
monitoring frequencies as follows: (1) Annual monitoring for well sites
with total combined production greater than 15 boe per day, (2)
biennial monitoring for well sites with total combined production at or
below 15 boe per day, and (3) co-proposed semiannual and annual
monitoring for compressor stations. Additionally, the EPA proposed to
allow owners and operators to stop monitoring at well sites when all of
the major production and processing equipment is removed, such that the
well site becomes a wellhead-only well site. After considering the
comments and additional data, we are not finalizing the proposed
changes to the monitoring frequencies for fugitive emissions components
at well sites and compressor stations, with two exceptions explained
below. The required fugitive monitoring frequencies for the collection
of fugitive emissions components located at a well site or compressor
station are as follows:
Semiannual monitoring for well sites, excluding well sites
with total production for the site at or below 15 boe per day (herein
referred to as ``low production well sites'') and well sites on the
Alaska North Slope;
Semiannual monitoring for compressor stations, excluding
those on the Alaska North Slope;
Annual monitoring for well sites (excluding low production
well sites) and compressor stations located on the Alaska North Slope;
and
Monitoring may be stopped once all major production and
processing equipment is removed from a well site such that it contains
only one or more wellheads.
Low production well sites are excluded from fugitive
monitoring requirements as long as the total production of the well
site remains at or below 15 boe per day, as determined on a rolling 12-
month basis and demonstrated by the records specified in the final
rule. To determine if a well site is a low production well site, the
EPA is finalizing the following calculation periods:
[cir] For a well site that newly triggers the fugitive emissions
requirements of the NSPS after the effective date of the rule, or a
well site that triggered the 2016 NSPS subpart OOOOa requirements
within 11 months prior to the effective date of the rule but does not
have 12-months' worth of production data, the total well site
production calculation is based on the first 30 days of production;
[cir] For a well site subject to the fugitive emissions
requirements that subsequently has production decline, the total well
site production calculation is based on a rolling 12-month average;
[cir] For a well site that has previously been determined to be low
production but later takes an action (e.g., drills a new well, performs
a well workover, etc.) that may increase production, the total well
site production calculation is based on the first 30 days of production
following completion of the action. This re-determination must be
completed at any time an action occurs, regardless of the original
startup of production date.
2. Modification
The October 15, 2018, proposal did not propose amendments to the
events
[[Page 57406]]
that constitute modifications of the collection of fugitive emissions
components located at a well site or a compressor station but did take
comment on whether additional clarification is necessary. The EPA's
consideration of the comments received did not result in changes to
modifications for well sites and compressor stations, therefore, this
final rule retains the events currently identified in the 2016 NSPS
subpart OOOOa that qualify as modifications of the collection of
fugitive emissions components located at a well site or a compressor
station.
The 2016 NSPS subpart OOOOa specifies that, for the purposes of
fugitive emissions components at a well site, a modification occurs
when (1) a new well is drilled at an existing well site, (2) a well is
hydraulically fractured at an existing well site, or (3) a well is
hydraulically refractured at an existing well site. 40 CFR 60.5365a(i).
Because this provision does not specifically address modifications of a
well site that is a separate tank battery surface site, the EPA
proposed language to address modifications of separate tank battery
surface sites. Specifically, the EPA proposed that a modification of a
well site that is a separate tank battery surface site occurs when (1)
any of the actions listed above for well sites occurs at an existing
separate tank battery surface site, (2) a well modified as described
above sends production to an existing separate tank battery surface
site, or (3) a well site subject to the fugitive emissions requirements
removes all major production and processing equipment such that it
becomes a wellhead-only well site and sends production to an existing
separate tank battery surface site. After considering the comments
received related to the proposed modification language relevant for
separate tank battery surface sites, the EPA is finalizing this
provision as proposed.
3. Initial Monitoring for Well Sites and Compressor Stations
The 2016 NSPS subpart OOOOa requires fugitive emissions monitoring
to begin within 60 days of startup of production (for well sites) or
startup of a compressor station. The October 15, 2018, proposal did not
propose any change to this requirement but solicited comment
identifying specific reasons why a change might be appropriate. 83 FR
52075. We received comments stating that well sites and compressor
stations do not achieve normal operating conditions within the first 60
days of startup. Commenters suggested a range of options from 90 days
to 180 days. Based on these comments, the EPA agrees that maintaining
the requirement to conduct initial monitoring within 60 days of startup
would not provide as effective of a survey as providing additional time
to allow the well site or compressor station to reach normal operating
conditions. The purpose of the initial monitoring is to identify any
issues associated with installation and startup of the well site or
compressor station. By providing sufficient time to allow owners and
operators to conduct the initial monitoring survey during normal
operating conditions, the EPA expects that there will be more
opportunity to identify and repair sources of fugitive emissions,
whereas, a partially operating site may result in missed emissions that
remain unrepaired for a longer period of time. The additional 30 days
provided in this final rule will still allow for identification and
mitigation of fugitive emissions in a timely manner. Therefore, the
final rule requires that initial monitoring be completed within 90 days
after the startup of production for well sites and 90 days after the
startup of a compressor station. Additionally, for low production well
sites that take an action which subsequently increases production above
15 boe per day based on the first 30 days of production following the
action, the final rule requires that initial monitoring be completed
within 90 days after the startup of production following the action.
4. Repair Requirements
This final rule amends the fugitive emissions repair requirements.
The 2016 NSPS subpart OOOOa requires repair within 30 days of
identifying fugitive emissions and a resurvey to verify that the repair
was successful within 30 days of the repair. In the proposal, the EPA
proposed to require a first attempt at repair within 30 days of
identifying fugitive emissions and final repair, including the resurvey
to verify repair, within 60 days of identifying fugitive emissions. We
proposed these revisions because stakeholders raised questions on
whether emissions identified during the resurvey would result in
noncompliance with the repair requirement. The EPA agreed that repairs
should be verified as successful prior to the repair deadline,
therefore, we proposed a definition of repair that includes the
resurvey. The net result of the proposal was that sources would have up
to 60 days to complete repairs, which was an increase from the 2016
NSPS subpart OOOOa requirement of 30 days. We received comments from
owners and operators that a total of 60 days was not necessary to
complete a successful repair, therefore, this final rule amends the
fugitive emissions repair requirements with changes from the proposal.
Specifically, we are finalizing the proposal that a first attempt at
repair is required within 30 days of identifying fugitive emissions and
requiring final repair within 30 days of the first attempt at repair.
While this final rule would still allow up to a total of 60 days to
complete repairs, several owners and operators indicated in their
comments that the majority of repairs are completed onsite during the
time of the monitoring survey. We are also finalizing as proposed
definitions for the terms ``first attempt at repair'' and ``repaired.''
Specifically, the definition of ``repaired'' includes the verification
of successful repair through a resurvey of the fugitive emissions
component.
The EPA is also amending the requirements for when delayed repairs
must be completed. The 2016 NSPS subpart OOOOa, as amended on March 12,
2018,\6\ specifies that where the repair of a fugitive emissions
component is ``technically infeasible, would require a vent blowdown, a
compressor station shutdown, a well shutdown or well shut-in, or would
be unsafe to repair during operation of the unit, the repair must be
completed during the next scheduled compressor station shutdown, well
shutdown, well shut-in, after a planned vent blowdown, or within 2
years, whichever is earlier.'' \7\ The EPA did not propose any
additional revisions to this provision, but solicited comment on
whether additional changes were necessary. 83 FR 52076. We received
comments expressing concerns with requiring repairs during the next
scheduled compressor station shutdown, without regard to whether the
shutdown is for maintenance purposes. The commenters stated that
repairs must be scheduled and that where a planned shutdown is for
reasons other than scheduled maintenance, completion of the repairs
during that shutdown may be difficult and disrupt gas transmission. The
EPA agrees that requiring the completion of delayed repairs only during
those scheduled compressor station shutdowns where maintenance
activities are scheduled is reasonable and anticipates that these
maintenance shutdowns occur on a regular schedule. Therefore, the final
rule requires completion of delayed repairs during the ``next scheduled
compressor station
[[Page 57407]]
shutdown for maintenance, scheduled well shutdown, scheduled well shut-
in, after a scheduled vent blowdown, or within 2 years, whichever is
earliest.''
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\6\ 83 FR 10638.
\7\ 40 CFR 60.5397a(h)(2).
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5. Definitions Related to Fugitive Emissions at Well Sites and
Compressor Stations
The EPA is finalizing, as proposed, amendments to the definition of
well site, for purposes of fugitive emissions monitoring, to exclude
equipment owned by third parties and oilfield wastewater disposal wells
(referred to as saltwater disposal wells in the proposal).
Additionally, based on information received in public comments, the EPA
is also amending the definition to exclude oilfield disposal wells used
for solid waste disposal. The amended definition for ``well site''
excludes third party equipment from the fugitive emissions requirements
by excluding ``the flange immediately upstream of the custody meter
assembly and equipment, including fugitive emissions components located
downstream of this flange.'' To clarify this exclusion, the final rule
defines ``custody meter'' as the meter where natural gas or hydrocarbon
liquids are measured for sales, transfers, and/or royalty
determination, and the ``custody meter assembly'' as an assembly of
fugitive emissions components, including the custody meter, valves,
flanges, and connectors necessary for the proper operation of the
custody meter, as proposed. The exclusion does not extend to other
third-party equipment at a well site that is not associated with the
custody meter and custody meter assembly (e.g., dehydrators).
This final rule further amends the definition of a well site to
exclude UIC Class I oilfield disposal wells and UIC Class II oilfield
wastewater disposal wells. The EPA proposed excluding UIC Class II
oilfield wastewater disposal wells because of our understanding that
they have negligible fugitive emissions. 83 FR 52077. Commenters
suggested that we also should exclude UIC Class I oilfield disposal
wells for the same reasons. Both types of disposal wells are permitted
through UIC programs under the Safe Drinking Water Act for surface and
groundwater protection. The EPA agrees with the commenters that the
potential fugitive methane and VOC emissions from UIC Class I oilfield
disposal wells are low. Therefore, the final rule includes a definition
for UIC Class I oilfield disposal wells. The definition for a UIC Class
I oilfield disposal well is a well with a UIC Class I permit that meets
the definition in 40 CFR 144.6(a)(2) and receives eligible fluids from
oil and natural gas exploration and production operations.
Additionally, the EPA is finalizing, as proposed, the definition of UIC
Class II oilfield wastewater disposal wells. The definition for a UIC
Class II oilfield wastewater disposal well is a well with a UIC Class
II permit where wastewater resulting from oil and natural gas
production operations is injected into underground porous rock
formations not productive of oil or gas, and sealed above and below by
unbroken, impermeable strata. Consequently, UIC Class I and UIC Class
II disposal facilities without wells that produce oil or natural gas
are not considered well sites for the purposes of fugitive emissions
requirements.
The EPA is also finalizing, as proposed, the definition of startup
of production as it relates to fugitive emissions requirements.
Specifically, startup of production is defined as the beginning of
initial flow following the end of flowback when there is continuous
recovery of salable quality gas and separation and recovery of any
crude oil, condensate or produced water, except as otherwise provided
herein. For the purposes of the fugitive monitoring requirements of
Sec. 60.5397a, startup of production means the beginning of the
continuous recovery of salable quality gas and separation and recovery
of any crude oil, condensate or produced water.
F. AMEL
1. Incorporation of Emerging Technologies
The EPA is amending the application requirements for requesting the
use of an AMEL for well completions, reciprocating compressors, and the
collection of fugitive emissions components located at a well site or
compressor station. Applications for an AMEL may be submitted by, among
others, owners or operators of affected facilities, manufacturers or
vendors of leak detection technologies, or trade associations. The
application must provide sufficient information to demonstrate that the
AMEL achieves emission reductions at least equivalent to the work
practice standards in this rule. At a minimum, the application should
include field data that encompass seasonal variations, and may be
supplemented with modeling analyses, test data, and/or other
documentation. The specific work practice(s), including performance
methods, quality assurance, the threshold that triggers action, and the
mitigation thresholds are also required as part of the application. For
example, for a technology designed to detect fugitive emissions,
information such as the detection criteria that indicate fugitive
emissions requiring repair, the time to complete repairs, and any
methods used to verify successful repair would be required.
2. Incorporation of State Fugitive Emissions Programs
This final rule includes alternative fugitive emissions standards
for specific state fugitive emissions programs that the EPA has
concluded are at least equivalent to the fugitive emissions monitoring
and repair requirements at 40 CFR 60.5397a(e), (f), (g), and (h). These
alternative fugitive emissions standards may be adopted for certain
individual well sites or compressor stations that are subject to
fugitive emissions monitoring and repair so long as the source complies
with specified Federal requirements applicable to each approved
alternative state program. For example, a well site that is subject to
the requirements of Pennsylvania General Permit 5A, section G,
effective August 8, 2018, could comply with those standards in lieu of
the monitoring, repair, recordkeeping, and reporting requirements in
the NSPS. However, the company must develop and maintain a fugitive
emissions monitoring plan, as required in 40 CFR 60.5397a(c) and (d),
and must monitor all of the fugitive emissions components, as defined
in 40 CFR 60.5430a, regardless of the components that must be monitored
under the alternative standard. Additionally, the facility must submit,
as an attachment to its annual report for NSPS subpart OOOOa, the
report that is submitted to its state in the format submitted to the
state, or the information required in the report for NSPS subpart OOOOa
if the state report does not include site-level monitoring and repair
information. If a well site is located in the state but is not subject
to the state requirements for monitoring and repair (i.e., not
obligated to monitor or repair fugitive emissions), then the well site
must continue to comply with the requirements of 40 CFR 60.5397a in its
entirety.
In addition to providing alternative fugitive emissions standards
for well sites and compressor stations located in California, Colorado,
Ohio, Pennsylvania, and Texas, and well sites in Utah, these amendments
provide application requirements to request alternative fugitive
emissions standards as state, local, and tribal programs continue to
develop. Applications for alternative fugitive emissions standards
based on state, local, or tribal programs may be submitted by any
interested
[[Page 57408]]
person, including individuals, corporations, partnerships,
associations, states, or municipalities. Similar to the applications
for AMEL for emerging technologies, the application must include
sufficient information to demonstrate that the alternative fugitive
emissions standards achieve emissions reductions at least equivalent to
the fugitive emissions monitoring and repair requirements in this rule.
At a minimum, the application must include the monitoring instrument,
monitoring procedures, monitoring frequency, definition of fugitive
emissions requiring repair, repair requirements, recordkeeping, and
reporting requirements. If any of the sections of the regulations or
permits approved as alternative fugitive emissions standards are
changed at a later date, the state must follow the procedures outlined
in 40 CFR 60.5399a to apply for a new evaluation of equivalency.
G. Onshore Natural Gas Processing Plants
1. Capital Expenditure
The EPA is amending the definition of ``capital expenditure'' at 40
CFR 50.5430a by replacing the equation used to determine the percent of
replacement cost, ``Y.'' The 2016 NSPS subpart OOOOa contains a
definition for ``Y'' that would result in an error, thus, making it
difficult to determine whether a capital expenditure had occurred. The
EPA proposed to revise the base year in the equation for ``Y'' with the
year 2015 and to define ``Y'' as equal to 1 for facilities constructed
in the year 2015. Additionally, we solicited comment on an alternative
approach that would utilize CPI. While the EPA proposed these specific
amendments to the equation used to determine the value of ``Y,'' we
received public comments that supported the alternative approach which
would more appropriately reflect inflation than the original equation.
The EPA solicited comment on this alternative and is finalizing the
alternative because we agree it is appropriate. The final equation for
``Y'' is based on the CPI, where ``Y'' equals the CPI of the date of
construction divided by the most recently available CPI of the date of
the project, or ``CPIN/CPIPD.'' Further, the
final rule specifies that the ``annual average of the consumer price
index for all urban consumers (CPI-U), U.S. city average, all items''
must be used for determining the CPI of the year of construction, and
the ``CPI-U, U.S. city average, all items'' must be used for
determining the CPI of the date of the project. This amendment
clarifies that the comparison of costs is between the original date of
construction of the process unit and the date of the project which adds
equipment to the process unit.
2. Equipment in VOC Service Less Than 300 Hours per Year (hr/yr)
The October 15, 2018, proposal included an exemption from the
requirements for equipment leaks at onshore natural gas processing
plants. Specifically, the EPA proposed an exemption from monitoring for
equipment that an owner or operator designates as being in VOC service
less than 300 hr/yr. 83 FR 52086. The EPA received comments supporting
this proposed exemption; therefore, we are amending the final rule as
proposed. This exemption applies to equipment at onshore natural gas
processing plants that is used only during emergencies, used as a
backup, or that is in service only during startup and shutdown.
3. Initial Compliance Period
The EPA is amending NSPS subpart OOOOa to specify that the initial
compliance deadline for the equipment leak standards for onshore
natural gas processing plants is 180 days. Specifically, the EPA is
including in NSPS subpart OOOOa the provision requiring compliance ``as
soon as practicable, but no later than 180 days after initial startup''
that is already in 40 CFR 60.632(a), which is part of subpart KKK of
the part, ``Standards of Performance for Equipment Leaks of VOC from
Onshore Natural Gas Processing Plants for which Construction,
Reconstruction, or Modification Commenced After January 20, 1984, and
on or before August 23, 2011'' (NSPS subpart KKK). In 2012, the EPA
revised the standards in NSPS subpart KKK with the promulgation of NSPS
subpart OOOO \8\ by lowering the leak definition for valves from 10,000
parts per million (ppm) to 500 ppm and requiring the monitoring of
connectors. 77 FR 49490, 49498. While no changes to the compliance
deadlines were made or discussed in NSPS subpart OOOO, 40 CFR 60.632(a)
was not included in NSPS subpart OOOO and, as a result, was also not
included in NSPS subpart OOOOa. During the rulemaking for NSPS subpart
OOOOa, the EPA declined a request to include the language in 40 CFR
60.632(a) in NSPS subpart OOOOa, explaining that such inclusion was not
necessary because NSPS subpart OOOOa already incorporates by reference
a similar statement (i.e., 40 CFR 60.482-1a(a)) which requires each
owner and operator to ``demonstrate compliance . . . within 180 days of
initial startup,'' 80 FR 56593, 56647-8. In reassessing the issue, the
EPA notes that NSPS subpart KKK includes both 40 CFR 60.632(a) and 40
CFR 60.482-1(a), a provision that is the same as 40 CFR 60.482-1a(a),
suggesting that at the time of promulgation of NSPS subpart KKK, the
EPA did not think that 40 CFR 60.482-1(a) (and 40 CFR 60.482-1a(a))
make 40 CFR 60.632(a) redundant or unnecessary. To remain consistent
with NSPS subpart KKK, the EPA is amending NSPS subpart OOOOa to
include a provision similar to 40 CFR 60.632(a).
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\8\ ``Standards of Performance for Crude Oil and Natural Gas
Production, Transmission and Distribution for Which Construction,
Modification or Reconstruction Commenced After August 23, 2011, and
on or before September 18, 2015.''
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The final rule requires monitoring to begin as soon as practicable,
but no later than 180 days after the initial startup of a new,
modified, or reconstructed process unit at an onshore natural gas
processing plant. Once started, monitoring must continue with the
required schedule. For example, if pumps are monitored by month 3 of
the initial startup period, then monthly monitoring is required from
that point forward. This initial compliance period is different than
the compliance requirements for newly added pumps and valves within a
process unit that is already subject to a leak detection and repair
(LDAR) program. Initial monitoring for those newly added pumps and
valves is required within 30 days of the startup of the pump or valve
(i.e., when the equipment is first in VOC service).
H. Sweetening Units
This final rule revises the applicability criteria for the
SO2 standards for sweetening units to correctly define an
affected facility as any onshore sweetening unit that processes natural
gas produced from either onshore or offshore wells. Sweetening units
are used to convert hydrogen sulfide (H2S) in acid gases
(i.e., H2S and CO2) that are separated from
natural gas by a sweetening process (e.g., amine treatment) into
elemental sulfur in the Claus process.\9\ These units can exist
anywhere in the production and processing segment of the source
category, including as stand-alone processing facilities that do not
extract or fractionate natural gas liquids from field gas. The
SO2 standards for onshore sweetening units were first
promulgated in 1985 and codified in 40 CFR part 60, subpart LLL. In
2012,
[[Page 57409]]
based on our review of the standards, the EPA tightened the
SO2 standards, which were codified in NSPS subpart OOOO and
later carried over to NSPS subpart OOOOa. In the process of finalizing
this current rulemaking to amend NSPS subpart OOOOa, the EPA discovered
that NSPS subpart OOOOa inexplicably limits the applicability of the
SO2 standards to only those sweetening units that are
located at onshore natural gas processing plants, which NSPS subpart
OOOOa defines as ``any processing site engaged in the extraction of
natural gas liquids from field gas, fractionation of mixed natural gas
liquids to natural gas products, or both. . . .'' 40 CFR 60.5430a. NSPS
subpart LLL did not contain this limitation, and the EPA did not offer
any rationale for creating it during the promulgation of either NSPS
subpart OOOO or NSPS subpart OOOOa, nor can we identify any reason why
the extraction of natural gas liquids relates in any way to the
SO2 standards such that the standards should only apply to
sweetening units located at onshore natural gas processing plants
engaged in extraction or fractionation activities. Sweetening units
emit SO2 in the same manner, regardless of whether they are
located at an onshore natural gas processing plant or at processing
facilities without extraction or fractionation activities. Therefore,
the EPA concludes that the limitation was made in error and is now
correcting the error by revising the affected facility description for
the SO2 standards to include all onshore sweetening units
that process natural gas produced from either onshore or offshore
wells.
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\9\ See Docket ID Item No. EPA-HQ-OAR-2010-0505-0045.
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I. Recordkeeping and Reporting
The EPA is amending NSPS subpart OOOOa to streamline the
recordkeeping and reporting requirements as discussed below for the
specified affected facilities. These amendments reflect consideration
of the public comments received on the proposal.
1. Well Completions
For each well site affected facility that routes flowback entirely
through one or more production separators, owners and operators are
only required to record and report the following elements:
Well Completion ID;
Latitude and longitude of the well in decimal degrees to
an accuracy and precision of five (5) decimals of a degree using North
American Datum of 1983;
U.S. Well ID;
The date and time of the onset of flowback following
hydraulic fracturing or refracturing or identification that the well
immediately starts production; and
The date and time of the startup of production.
For periods where salable gas is unable to be separated, owners and
operators will also be required to record and report the date and time
of onset of flowback, the duration and disposition of recovery, the
duration of combustion and venting (if applicable), reasons for venting
(if applicable), and deviations.
2. Fugitive Emissions at Well Sites and Compressor Stations
For each collection of fugitive emissions components located at a
well site or compressor station, the EPA is amending the recordkeeping
and reporting requirements as follows:
Revise the requirements in 40 CFR 60.5397a(d)(1) to
require inclusion of procedures that ensure all fugitive emissions
components are monitored during each survey within the monitoring plan.
Remove the requirement to maintain records of a digital
photo of each monitoring survey performed, captured from the OGI
instrument used for monitoring.
Remove the requirement to maintain records of the number
and type of fugitive emissions components or digital photo of fugitive
emissions components that are not repaired during the monitoring
survey. These records are not required once repair is completed and
verified with a resurvey.
Require records of the total well site production for low
production well sites.
Require records of the date of first attempt at repair and
date of successful repair.
Revise reporting to specify the type of site (i.e., well
site, low production well site, or compressor station) and when the
well site changes status to a wellhead-only well site.
Remove requirement to report the name or ID of operator
performing the monitoring survey.
Remove requirement to report the number and type of
difficult-to-monitor and unsafe-to-monitor components that are
monitored during each monitoring survey.
Remove requirement to report the ambient temperature, sky
conditions, and maximum wind speed.
Remove requirement to report the date of successful
repair.
Remove requirement to report the type of instrument used
for resurvey.
In addition to streamlining the recordkeeping and reporting
requirements, the EPA is also finalizing the form that is used for
submitting annual reports through the Compliance and Emissions Data
Reporting Interface (CEDRI) with this final rule. Per the requirement
in 40 CFR 60.5420a(b)(11), affected facilities must submit all
subsequent reports via CEDRI, once the form has been available in CEDRI
for at least 90 calendar days. The EPA anticipates that the deadline to
begin submitting subsequent annual reports required by 40 CFR
60.5420a(b) through CEDRI will be [INSERT DATE 90 DAYS AFTER DATE OF
PUBLICATION IN THE FEDERAL REGISTER]. However, owners and operators
should verify the date that the form becomes available in CEDRI by
checking the ``Initial Availability Date'' listed on the CEDRI website
(https://www.epa.gov/electronic-reporting-air-emissions/cedri).
J. Technical Corrections and Clarifications
The EPA is revising NSPS subpart OOOOa to include the following
technical corrections and clarifications.
Revise 40 CFR 60.5385a(a)(1), 60.5410a(c)(1),
60.5415a(c)(1), and 60.5420a(b)(4)(i) and (c)(3)(i) to clarify that
hours or months of operation at reciprocating compressor facilities
must be measured beginning with the date of initial startup, the
effective date of the requirement (August 2, 2016), or the last rod
packing replacement, whichever is latest.
Revise 40 CFR 60.5393a(b)(3)(ii) to correctly cross-
reference paragraph (b)(3)(i) of that section.
Revise 40 CFR 60.5397a(c)(8) to clarify the calibration
requirements when Method 21 of appendix A-7 to part 60 is used for
fugitive emissions monitoring.
Revise 40 CFR 60.5397a(d)(3) to correctly cross-reference
paragraphs (g)(3) and (4) of that section.
Revise 40 CFR 60.5401a(e) to remove the word ``routine''
to clarify that pumps in light liquid service, valves in gas/vapor
service and light liquid service, and pressure relief devices in gas/
vapor service within a process unit at an onshore natural gas
processing plant located on the Alaska North Slope are not subject to
any monitoring requirements.
Revise 40 CFR 60.5410a(e) to correctly reference pneumatic
pump affected facilities located at a well site as opposed to pneumatic
pump affected facilities not located at a natural gas processing plant
(which would include those not at a well site). This correction
reflects that the 2016 NSPS subpart OOOOa did not finalize requirements
for pneumatic pumps at gathering and boosting compressor stations. 81
FR 35850.
[[Page 57410]]
Revise 40 CFR 60.5411a(a)(1) to remove the reference to
Sec. 60.5412a(a) and (c) for reciprocating compressor affected
facilities.
Revise 40 CFR 60.5411a(d)(1) to remove the reference to
storage vessels, as this paragraph applies to all the sources listed in
40 CFR 60.5411a(d), not only storage vessels.
Revise 40 CFR 60.5412a(a)(1) and (d)(1)(iv) to clarify
that all boilers and process heaters used as control devices on
centrifugal compressors and storage vessels must introduce the vent
stream into the flame zone. Additionally, revise 40 CFR
60.5412a(a)(1)(iv) and (d)(1)(iv)(D) to clarify that the vent stream
must be introduced with the primary fuel or as the primary fuel to meet
the performance requirement option. This is consistent with the
performance testing exemption in 40 CFR 60.5413a and continuous
monitoring exemption in 40 CFR 60.5417a for boilers and process heaters
that introduce the vent stream with the primary fuel or as the primary
fuel.
Revise 40 CFR 60.5412a(c) to correctly reference both
paragraphs (c)(1) and (2) of that section, for managing carbon in a
carbon adsorption system.
Revise 40 CFR 60.5413a(d)(5)(i) to reference fused silica-
coated stainless steel evacuated canisters instead of a specific name
brand product.
Revise 40 CFR 60.5413a(d)(9)(iii) to clarify the basis for
the total hydrocarbon span for the alternative range is propane, just
as the basis for the recommended total hydrocarbon span is propane.
Revise 40 CFR 60.5413a(d)(12) to clarify that all data
elements must be submitted for each test run.
Revise 40 CFR 60.5415a(b)(3) to reference all applicable
reporting and recordkeeping requirements.
Revise 40 CFR 60.5416a(a)(4) to correctly cross-reference
40 CFR 60.5411a(a)(3)(ii).
Revise 40 CFR 60.5417a(a) to clarify requirements for
controls not specifically listed in paragraph (d) of that section.
Revise 40 CFR 60.5422a(b) to correctly cross-reference 40
CFR 60.487a(b)(1) through (3) and (b)(5).
Revise 40 CFR 60.5422a(c) to correctly cross-reference 40
CFR 60.487a(c)(2)(i) through (iv) and (c)(2)(vii) through (viii).
Revise 40 CFR 60.5423a(b) to simplify the reporting
language and clarify what data are required in the report of excess
emissions for sweetening unit affected facilities.
Revise 40 CFR 60.5430a to remove the phrase ``including
but not limited to'' from the ``fugitive emissions component''
definition. During the 2016 NSPS subpart OOOOa rulemaking, we stated in
a response to comment that we are removing this phrase,\10\ but we did
not do so in that rulemaking and are finalizing that change in this
final rule.
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\10\ See Docket ID Item No. EPA-HQ-OAR-2010-0505-7632, Chapter
4, page 4-319.
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Revise 40 CFR 60.5430a to remove the phrase ``at the sales
meter'' from the ``low pressure well'' definition to clarify that when
determining the low pressure status of a well, pressure is measured
within the flow line, rather than at the sales meter.
Revise Table 3 to correctly indicate that the performance
tests in 40 CFR 60.8 do not apply to pneumatic pump affected
facilities.
Revise Table 3 to include the collection of fugitive
emissions components at a well site and the collection of fugitive
emissions components at a compressor station in the list of exclusions
for notification of reconstruction.
Revise 40 CFR 60.5393a(f), 60.5410a(e)(8), 60.5411a(e),
60.5415a(b) introductory text and (b)(4), 60.5416a(d), 60.5420a(b)
introductory text and (b)(13), and introductory text in Sec. Sec.
60.5411a and 60.5416a, to remove language associated with the
administrative stay we issued under section (d)(7)(B) of the CAA in
``Oil and Natural Gas Sector: Emission Standards for New,
Reconstructed, and Modified Sources; Grant of Reconsideration and
Partial Stay'' (June 5, 2017). The administrative stay was vacated by
the U.S. Court of Appeals for the District Of Columbia Circuit on July
3, 2017.
V. Significant Changes Since Proposal
This section identifies significant changes since the proposed
rulemaking. These changes reflect the EPA's consideration of over
500,000 comments submitted on the proposal and other information
received since the proposal. In this section, we discuss the
significant changes since proposal by affected facility type and the
rationales for those changes. Additional information related to these
changes, such as specific comments and our responses, is in section VI
of this preamble and in materials available in the docket.\11\
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\11\ See Response to Comments (RTC) document and technical
support documents (TSD) in Docket ID No. EPA-HQ-OAR-2017-0483.
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A. Storage Vessels
In the October 15, 2018, proposal, the EPA proposed clarifications
on how to calculate the potential for VOC emissions for purposes of
determining whether a storage vessel has the potential for 6 tpy or
more of VOC emissions and, therefore, is an affected facility subject
to the storage vessels standards under the 2016 NSPS subpart OOOOa.
Specifically, the EPA proposed amendments to the definition of
``maximum average daily throughput'' that provided distinct
methodologies for calculating the throughput of an individual storage
vessel based on how throughput is measured and recorded. We proposed
the amendments because owners and operators continued to express
confusion over how to calculate this throughput.
Numerous commenters \12\ expressed objections to several aspects of
the proposed amendments, particularly to the EPA's assumption that
averaging emissions across storage vessels in a controlled battery
would underestimate a storage vessel's potential VOC emissions. The
commenters explained why averaging across storage vessels in controlled
batteries has a sound basis in engineering and addresses the EPA's
concern about flash emissions, which constitute most of the emissions
from storage vessels.
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\12\ See Docket ID Item Nos. EPA-HQ-OAR-2017-0483-0773, EPA-HQ-
OAR-2017-0483-0775, EPA-HQ-OAR-2017-0483-0780, EPA-HQ-OAR-2017-0483-
0801, EPA-HQ-OAR-2017-0483-0996, EPA-HQ-OAR-2017-0483-0999, EPA-HQ-
OAR-2017-0483-1006, EPA-HQ-OAR-2017-0483-1009, EPA-HQ-OAR-2017-0483-
1236, EPA-HQ-OAR-2017-0483-1243, EPA-HQ-OAR-2017-0483-1248, EPA-HQ-
OAR-2017-0483-1261, EPA-HQ-OAR-2017-0483-1343, and EPA-HQ-OAR-2017-
0483-1578.
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Specifically, the commenters pointed out that tank batteries
typically share vapor space (the tank volume above the liquid) and
joint piping used to collect generated vapors, which are then routed
back to a process or conveyed to a control device, when one is used, or
vented through one common pressure relief valve (PRV). For purposes of
this discussion, the EPA considers this configuration as a manifolded
system that collects and routes vapors across the headspace. (This is
different than liquid manifolded systems where liquids can be
introduced to any tank in the system.) The commenters noted that vapors
flow both into and out of each tank within the battery and into
overflow piping on a continuous basis, and vapors will always flow from
high pressure areas to low pressure areas when flow is mechanically
unrestricted. The commenters explained that, in this configuration, the
flash emissions from the first tank will flow into the other tanks and
vent line space associated with the battery until the total pressure in
the system exceeds the back-pressure of the flare or other control
device, or in systems without controls, the PRV.
[[Page 57411]]
The commenters asserted that only then will the emissions (i.e., the
vapors) be released from the PRV if uncontrolled; routed back to a
process; or combusted by the control equipment. Therefore, the
commenters suggested that because the vapors from individual storage
vessels are comingled and not individually emitted from the originating
storage vessels, it is appropriate to allow sources to average the
emissions across the number of storage vessels in the controlled
battery in order to attribute emissions to individual storage vessels.
After considering these comments and subsequent conversations with
the commenters,\13\ the EPA reevaluated the proposal. Based on this
review, the EPA agrees with the commenters that, in certain situations,
averaging emissions across a controlled battery may be appropriate for
purposes of determining whether to subject the storage vessels in the
tank battery to the storage vessel standards in NSPS subpart OOOOa.
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\13\ See Memoranda for March 27, 2019 Meeting with American
Petroleum Institute, April 9, 2019 Meeting with Hess, and May 1,
2019 Meeting with GPA Midstream located at Docket ID No. EPA-HQ-OAR-
2017-0483.
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In order to fully understand where averaging of emissions across a
controlled battery may be appropriate, under this final rule, for
purposes of determining whether to subject the storage vessels in the
controlled battery to the storage vessel standards in NSPS subpart
OOOOa, the EPA considered the level of control that would be achieved
where uncontrolled potential emissions are greater than 6 tpy. The
standards in the 2016 NSPS subpart OOOOa require reducing uncontrolled
emissions from individual storage vessel affected facilities by 95.0
percent.
For controlled batteries, as liquids are introduced to a storage
vessel in the system, the vapors transfer to the piping, or common
header, enter the common vapor space, and commingle with vapors from
other storage vessels in the manifolded system. When the combined vapor
pressure in the common header reaches a specified set point, the vapors
are typically conveyed through a CVS to either a vapor recovery unit
(which routes vapors back to a process) or a control device. Where this
controlled battery is designed and operated to route the vapors in this
manner, emissions from an individual storage vessel within the
controlled battery are indistinguishable from emissions from other
storage vessels within the controlled battery; each individual storage
vessel does not directly emit (e.g., flash emissions) to the
atmosphere. These controlled batteries are typically subject to
specific design and operational criteria through a legally and
practicably enforceable limit (e.g., through permits or other
requirements established through Federal, state, local, or tribal
authority). To the extent that the control, through the battery's
design and operation, already reduces 95 percent or more of the VOC
emissions, no additional emission reductions would be achieved by
subjecting each individual storage vessel in the controlled battery
operating under legally and practicably enforceable limits to the
storage vessel standards in the 2016 NSPS subpart OOOOa. However, the
2016 NSPS subpart OOOOa considers any storage vessel with the potential
for VOC emissions greater than 6 tpy, including those with legally and
practicably enforceable limits, a storage vessel affected facility.
This final rule does not change that 6 tpy applicability threshold, but
it does include specific criteria that must be included in the legally
and practicably enforceable limit before averaging of emissions will be
allowed for the purposes of determining whether the potential for VOC
emissions from the individual storage vessels in a controlled tank
battery is above the 6 tpy threshold. Specifically, the legally and
practicably enforceable limit must require the storage vessels to be
(1) manifolded together with piping such that all vapors are shared
among the headspaces of the storage vessels, (2) equipped with a CVS
that is designed, operated, and maintained to route vapors back to the
process or to a control device, and (3) designed and operated to route
vapors back to the process or to a control device that reduces VOC
emissions by at least 95.0 percent. The EPA concludes that averaging
emissions across the number of storage vessels in a controlled battery
subject to the design and operational criteria specified above, through
a legally and practicably enforceable limit, is the appropriate way to
determine if the storage vessels in that battery are affected
facilities under NSPS subpart OOOOa. Where the average VOC emissions
across the number of storage vessels in the controlled battery is 6 tpy
or greater, all of the storage vessels in the controlled battery are
storage vessel affected facilities and subject to the requirements for
storage vessels in NSPS subpart OOOOa. However, where the average
emissions are less than 6 tpy, none of the storage vessels in the
controlled battery are storage vessels affected facilities.
For storage vessels that do not meet all of the design and
operational criteria specified in this final rule, which includes
single storage vessels (whether controlled or not) and storage vessels
that are connected in some way but do not meet all of the criteria
described above, the final rule requires owners and operators to
calculate the potential for VOC emissions on an individual storage
vessel basis to determine if the storage vessel is a storage vessel
affected facility, as proposed. Where the potential for VOC emissions
from a storage vessel is 6 tpy or greater, the storage vessel is a
storage vessel affected facility. We have not revised the BSER for
storage vessel affected facilities; as a result, the storage vessel
standards in the 2016 NSPS subpart OOOOa remain applicable to these
storage vessels if their potential for VOC emissions is 6 tpy or
greater, based on each individual storage vessel and without averaging
across the storage vessels at the site.
The final rule continues to require that an owner or operator
calculate the potential for VOC emissions using generally accepted
methods for estimating emissions based on the maximum average daily
throughput. In this final rule, the EPA is amending the definition of
maximum average daily throughput to specify how to determine throughput
for the calculation of the potential for VOC emissions. Specifically,
this amended definition specifies how storage vessels that commence
construction, reconstruction, or modification after the effective date
of this final rule must determine the throughput to each individual
storage vessel in order to calculate the potential for VOC emissions.
This definition is relevant to the individual storage vessels or
connected storage vessels that do not meet the specified design and
operational criteria defined for controlled tank batteries (i.e., tank
batteries that are allowed to average emissions across the tanks in the
battery).
In summary, this final rule amends the definition of ``maximum
average daily throughput,'' to specify how the potential for VOC
emissions are calculated. Additionally, this final rule allows for a
calculation of the average VOC emissions to determine the applicability
of the storage vessel standards to storage vessels in controlled
batteries where specific design and operational criteria are
incorporated as legally and practicably enforceable requirements into a
permit or other requirement established under Federal, state, local, or
tribal authority. The specific design and operational criteria are as
follows: (1) The storage vessels are manifolded together with piping
such that all vapors are shared
[[Page 57412]]
between the headspace of the storage vessels, (2) the storage vessels
are equipped with a CVS that is designed, operated, and maintained to
route collected vapors back to the process or to a control device, and
(3) collected vapors are routed to a process or a control device that
achieves at least 95.0-percent control of VOC emissions. If the
potential for VOC emissions (or average emissions where applicable) is
greater than or equal to 6 tpy, the storage vessel is a storage vessel
affective facility.
The amendments discussed above, including the definition of
``maximum average daily throughput,'' apply to storage vessels that
commence construction, reconstruction, or modification after the
effective date of this final rule, which is November 16, 2020. Owners
and operators of storage vessels that commenced construction,
reconstruction, or modification after September 18, 2015, and on or
before November 16, 2020 may still have uncertainty regarding whether
they determined their applicability appropriately. If so, these owners
and operators should contact the EPA if they have questions regarding
how they previously determined applicability for these sources.
B. Fugitive Emissions at Well Sites and Compressor Stations
The October 15, 2018, proposal included various proposed amendments
to the fugitive emissions standards. Two major aspects of those
proposed amendments were (1) reduction in the monitoring frequency for
well sites and compressor stations and (2) revisions to the monitoring
plan, recordkeeping, and reporting requirements. This final rule
includes changes from the proposal in both areas. First, the EPA is not
finalizing the proposed annual monitoring frequency at non-low
production well sites. As explained in more detail below, the EPA
concluded that the three areas of uncertainty that were the basis for
proposing amendments to the monitoring frequencies for well sites and
compressor stations did not result in an overestimate of the cost-
effectiveness of the monitoring frequencies in the 2016 NSPS subpart
OOOOa, and semiannual monitoring remains cost effective based on the
revised cost estimates for well sites with total production greater
than 15 boe per day, which are presented in the TSD for this final
rule. Therefore, the final rule retains semiannual monitoring for well
sites with total production greater than 15 boe per day.
Additionally, the EPA is neither finalizing the proposed biennial
monitoring frequency at low production well sites (i.e., well sites
with total production at or below 15 boe per day) nor retaining the
current semiannual monitoring requirement because monitoring is not
cost effective at any frequency for these well sites based on the
revised cost estimates. Instead, the final rule requires that a low
production well site either maintain its total production at or below
15 boe per day or conduct semiannual monitoring. This requirement
applies to well sites that produce at or below 15 boe per day during
the first 30 days of production, as well as those sites that experience
a decline in production where the total production for the well site,
based on a rolling 12-month average, is at or below 15 boe per day, as
demonstrated by the records required in the final rule.
Further, the EPA is finalizing the co-proposed semiannual
monitoring frequency for gathering and boosting compressor stations. As
explained in more detail below in section V.B.4 of the preamble, based
on our comparison of the cost-effectiveness of semiannual and quarterly
monitoring and consideration of other cost-related factors, we are
finalizing semiannual monitoring for gathering and boosting compressor
stations. This final rule does not address fugitive emissions
monitoring for transmission and storage compressor stations because the
Review Rule (published in the Federal Register of Monday, September 14,
2020) revises the source category by removing sources in the
transmission and storage segment from the category. As such, the Review
Rule rescinds the GHG and VOC standards for sources in the transmission
and storage segment. Regardless, the TSD for this final action does
include relevant updates to the model plants for the transmission and
storage compressor stations.
The revised cost estimates for fugitive monitoring of well sites
and gathering and boosting compressor stations rely on updates the EPA
made to the model plants, including updates that address the areas of
uncertainty that we identified in the October 15, 2018, proposal, as
well as the revisions to the monitoring plan, recordkeeping, and
reporting requirements we are making in this final rule, which reduce
administrative burden without compromising our ability to determine
compliance with the standards. This section describes the analyses and
resulting amendments to the fugitive emissions standards in this final
rule.
1. Areas of Uncertainty
In the 2016 NSPS subpart OOOOa, the EPA concluded that a fugitive
emissions monitoring and repair program that includes semiannual OGI
monitoring at well sites and quarterly monitoring at compressor
stations and the repair of any components identified with fugitive
emissions was the BSER for the collection of fugitive emissions
components at well sites and compressor stations.\14\ 81 FR 35826.
While the EPA continued to maintain that OGI is the BSER for reducing
fugitive emissions at well sites and compressor stations in the October
15, 2018, proposal, we proposed less frequent monitoring after
identifying three areas of uncertainty that led to concerns that we
might have overestimated the emission reductions, and, therefore, cost
effectiveness, of the monitoring frequencies specified in the 2016 NSPS
subpart OOOOa. We solicited comments on these three areas of
uncertainty, as well as additional information, so that we could better
assess the emission reductions that occur at different monitoring
frequencies. Additional detailed discussion on the areas of uncertainty
is available in the TSD for this final rule.\15\
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\14\ The rule allows the use of Method 21 as an alternative to
OGI but did not conclude Method 21 was BSER because OGI was found to
be more cost effective. See 81 FR 35856.
\15\ See TSD located at Docket ID No. EPA-HQ-OAR-2017-0483.
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In the October 15, 2018, proposal, regarding the EPA's cost
analysis in the 2016 NSPS subpart OOOOa, we stated that the ``EPA
identified three areas of the analysis that raise concerns regarding
the emissions reductions: (1) The percent emission reduction achieved
by OGI, (2) the occurrence rate of fugitive emissions at different
monitoring frequencies, and (3) the initial percentage of fugitive
emissions components identified with fugitive emissions.'' 83 FR 52063.
Given these areas of concern, we solicited information to further
refine our analysis and reduce or eliminate these uncertainties.
Several commenters provided information that the EPA used to evaluate
each of these areas for this final rule.
Reductions using OGI. In the October 15, 2018, proposal, the EPA
maintained the estimates for emissions reductions achieved when using
OGI at any type of site, which are 30 percent for biennial monitoring,
40 percent for annual monitoring, 60 percent for semiannual monitoring,
and 80 percent for quarterly monitoring. As stated in the proposal, one
stakeholder asserted that annual monitoring was more appropriate for
compressor stations than the required quarterly monitoring. This
stakeholder stated that the estimated control
[[Page 57413]]
efficiency for quarterly monitoring should be 90 percent (instead of 80
percent) and annual monitoring should be 80 percent (instead of 40
percent), based on the stakeholder's interpretation of results from a
study conducted by the Canadian Association of Petroleum Producers
(CAPP).\16\ In response to this information, the EPA reviewed the CAPP
report and was unable to conclude that annual OGI monitoring would
achieve 80-percent emissions reductions, as stated by the
stakeholder.\17\ In its submission of public comments on the proposal,
and in subsequent clarifying discussions, the stakeholder continued to
assert that the EPA had understated the emissions reductions achieved
with annual monitoring.\18\ As discussed in the TSD,\19\ we have
reevaluated the information provided in the CAPP report and are still
unable to conclude that the CAPP report demonstrates that annual OGI
monitoring would achieve 80-percent emissions reductions. In brief, we
concluded that the results of the CAPP report indicate that quarterly
monitoring could achieve 92-percent emission reductions while annual
monitoring could achieve 56-percent emission reductions based on
attributing the recommended frequencies at which the components at
compressor stations should be monitored to the emissions reported for
those component types. However, as stated in our discussion in the TSD,
these emissions reductions may also be due to factors such as improved
emissions factors and not actual emissions reductions resulting from
monitoring and repair.
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\16\ CAPP, ``Update of Fugitive Equipment Leak Emission
Factors,'' prepared for CAPP by Clearstone Engineering, Ltd.,
February 2014.
\17\ See memorandum, ``EPA Analysis of Fugitive Emissions Data
Provided by Interstate Natural Gas Association of America (INGAA),''
located at Docket ID Item No. EPA-HQ-OAR-2017-0483-0060. August 21,
2018.
\18\ See Docket ID Item No. EPA-HQ-OAR-2017-0483-1002 and
Memorandum for the April 30, 2019 Meeting with INGAA, located at
Docket ID No. EPA-HQ-OAR-2017-0483.
\19\ See TSD, section 2.4.1.1 for more details at Docket ID No.
EPA-HQ-OAR-2017-0483.
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Another commenter provided information related to the emissions
reductions achieved when using OGI at the various monitoring
frequencies.\20\ The commenter referenced a study performed by Dr.
Arvind Ravikumar as supporting the EPA's estimates of emissions
reductions for annual and semiannual monitoring using OGI.\21\ This
study utilized the Fugitive Emissions Abatement Simulation Toolkit
(FEAST) model that was developed by Stanford University to simulate
emissions reductions achieved at the various monitoring frequencies.
The study used information from the EPA's model plant analysis for the
2016 NSPS subpart OOOOa, including the site-level baseline emissions.
Emissions reductions were estimated at 32 percent for annual
monitoring, 54 percent for semiannual monitoring, and 70 percent for
quarterly monitoring, which the EPA considers to be comparable to the
EPA's estimated reduction efficiencies for OGI at these monitoring
frequencies.
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\20\ See Docket ID Item No. EPA-HQ-OAR-2017-0483-2041.
\21\ See Appendix D to Docket ID Item No. EPA-HQ-OAR-2017-0483-
2041.
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Finally, the EPA updated its analysis of emissions reductions using
Method 21 for comparison to the estimated reductions using OGI. As
previously stated in the proposal TSD,\22\ data from the Synthetic
Organic Chemicals Manufacturing Industry (SOCMI) in the 1995 Equipment
Leak Protocol Document (1995 Protocol) was used to estimate the Method
21 effectiveness at the various monitoring frequencies. In the proposal
TSD, we stated, ``it is not possible to correlate OGI detection
capabilities with a Method 21 instrument reading, provided in ppm.
However, based on the EPA's current understanding of OGI technology and
the types of hydrocarbons found at oil and natural gas well sites and
compressor stations, the emission reductions from an OGI monitoring and
repair program likely correlate to a Method 21 monitoring and repair
program with a fugitive emissions definition somewhere between 2,000 to
10,000 ppm.'' \23\ We received comments asserting that the EPA
inappropriately used Method 21 effectiveness estimates based on SOCMI
to justify the emissions reductions for OGI. In response to these
comments, the EPA updated the Method 21 effectiveness estimates using
information for the oil and gas industry, as described in the TSD for
this final rule.\24\ The revised analysis estimates emissions
reductions when using Method 21 to be 40 percent for annual monitoring,
54 percent for semiannual monitoring, and 67 percent for quarterly
monitoring, when using the average reductions achieved at leak
definitions of 500 ppm and 10,000 ppm. While not a direct comparison,
the EPA estimates emission reductions using OGI would likely be higher
because OGI will detect large emissions, such as emissions from thief
hatches on controlled storage vessels, that Method 21 would otherwise
not detect.
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\22\ See Docket ID Item No. EPA-HQ-OAR-2017-0483-0040.
\23\ See Docket ID Item No. EPA-HQ-OAR-2017-0483-0040, at page
25.
\24\ See TSD at Docket ID No. EPA-HQ-OAR-2017-0483.
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In conclusion, the EPA performed detailed analyses of the CAPP
studies, the FEAST model results, and the updated Method 21 estimates
to determine whether changes to the estimated effectiveness of OGI
monitoring is appropriate. Based on these analyses, we conclude that
the estimated effectiveness percentages of OGI monitoring at the
various frequencies are appropriate and do not need adjustment.
Leak occurrence rates. The second uncertainty identified in the
October 15, 2018, proposal relates to the occurrence rate of fugitive
emissions, or the percentage of components identified with fugitive
emissions during each survey. In the proposal, the EPA stated,
``because the model plants assume that the percentage of components
found with fugitive emissions is the same regardless of the monitoring
frequency, we acknowledge that we may have overestimated the total
number of fugitive emissions components identified during each of the
more frequent monitoring cycles.'' 83 FR 52064. There are numerous ways
the number of leaking components could impact the cost effectiveness of
monitoring, including (1) the amount of baseline emissions, (2) the
potential emission reductions, and (3) the number of repairs required.
In the 2016 analysis, the EPA assumed that each monitoring survey
at a well site would identify four components with fugitive emissions.
That is, when a site is monitored annually, we estimated four total
components leaking for that year, but if that same site were monitored
semiannually, we estimated eight total components leaking for that
year. However, we have found that a constant leak occurrence rate is
not reflected in our analysis of Method 21 monitoring, the information
provided through comments on the proposal, or a review of the annual
compliance reports submitted to the EPA for the NSPS subpart OOOOa.
Rather, the information demonstrates that occurrence rates differ based
on monitoring frequency. For example, the information we reviewed in
the annual compliance reports for well site fugitive emissions
components demonstrated that, on average, three components were
identified as leaking where only one survey had taken place in a 12-
month period, and two components were identified as leaking, per
survey, where more than one survey had occurred in
[[Page 57414]]
a 12-month period.\25\ These values are similar to those provided by
two commenters that provided detailed information on the number of
components identified with fugitive emissions at different monitoring
frequencies.\26\ Therefore, we updated the well site model plant
analysis to include an average of three components per annual survey
and two components per semiannual survey (for a total of four repairs
annually).\27\
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\25\ See TSD located at Docket ID No. EPA-HQ-OAR-2017-0483.
\26\ See Docket ID Item Nos. EPA-HQ-OAR-2017-0483-0801 and EPA-
HQ-OAR-2017-0483-2041.
\27\ The 2016 model plant analysis included an evaluation of
quarterly monitoring for well sites. Because semiannual monitoring
is required, it was not possible to determine the quarterly
occurrence rate for well sites using this information. See TSD for
additional analysis.
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In the 2016 analysis, the EPA assigned each type of compressor
station (i.e., gathering and boosting, transmission, and storage) a
specific leak occurrence rate. While annual compliance reports were
submitted for compressor stations complying with NSPS subpart OOOOa, it
was not possible to determine which stations were which type. However,
for gathering and boosting compressor stations, detailed information
was provided by GPA Midstream.\28\ While the number of reported leaks
varied widely in the dataset, the EPA's analysis of the data
demonstrated that, on average, 11 components were identified as leaking
during a 12-month period, with monitoring frequencies ranging from
monthly to annually.\29\ Therefore, we assumed that a total of 11
components, on average, would be identified as leaking over the course
of a full year's worth of monitoring, regardless of monitoring
frequency. That is, we assumed that if monitoring occurs semiannually,
on average, 11 components will be leaking over the course of the two
surveys in that year. This estimate takes into account the reported
variation in the number of components identified as leaking during each
survey. For example, a gathering and boosting compressor station that
is monitoring quarterly may identify the following number of components
as leaking: Three components in Quarter 1; two components in Quarter 2;
four components in Quarter 3; and two components in Quarter 4. If that
same gathering and boosting compressor station were monitored annually,
then all 11 components would be identified during the one annual
survey. This is different than the assumption used in the 2016 NSPS
subpart OOOOa. Utilizing the estimate of 11 components identified as
leaking over the course of 1 year provides an annual estimate of the
repair costs for gathering and boosting compressor stations which is
independent of the monitoring survey costs. That is, on average, the
same number of repairs are made in a single year, regardless of the
frequency of surveys, which helps account for the variability presented
in the dataset.
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\28\ See Docket ID Item No. EPA-HQ-OAR-2017-0483-1261.
\29\ See TSD located at Docket ID No. EPA-HQ-OAR-2017-0483.
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In summary, the EPA is no longer using a linear function for
occurrence rates as we did in the proposal or the 2016 NSPS subpart
OOOOa. Instead, we have based occurrence rates on available information
that is specific to fugitive emissions monitoring frequencies for each
type of facility. Specifically, we estimate a total of two repairs
(leaking components) at the annual monitoring frequency and three
repairs at the semiannual monitoring frequency for well sites. For
gathering and boosting compressor stations we estimate that, on
average, 11 repairs are necessary over the course of a year. This
updated analysis more directly reflects the reality that leak
occurrence rates are not linear between frequencies and more
appropriately estimates the number of repairs (and, thus, emission
reductions and costs) at more frequent monitoring. Thus, the EPA no
longer considers leak occurrence rates to raise uncertainties with the
analysis or to overestimate emissions.
Initial leak rate. The final uncertainty raised in the October 15,
2018, proposal was the initial percentage of components identified with
fugitive emissions (``initial leak rate''). While the EPA did not use
an initial leak rate in our estimate of the baseline emissions, one
commenter noted that initial leak rate should be considered a key
element for understanding potential baseline emissions. The commenter
stated its belief that the emissions factor the EPA used to estimate
baseline emissions was calculated using an initial leak rate that was
too high, thus, biasing the baseline emissions (and the resulting
emission reductions) high.\30\
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\30\ See Docket ID Item No. EPA-HQ-OAR-2017-0483-0801.
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In the 2016 NSPS subpart OOOOa TSD, the EPA stated incorrectly that
the model plant analysis assumed an initial leak rate of 1.18
percent.\31\ One commenter pointed out that this initial leak rate,
which was also cited in the October 15, 2018, proposal, was not the
actual estimate used for the model plant analysis. The commenter is
correct on this point. The uncontrolled emissions factors for non-thief
hatch fugitive emission components the EPA used to estimate model plant
emissions are based on Table 2-4 of the Protocol for Equipment Leak
Emission Estimates (``Protocol Document'').\32\ While the initial leak
rates that are inherent in these emissions factors are not specifically
stated in the Protocol Document, the commenter performed a back-
calculation of the fraction of leaking components using Table 5-7 of
the Protocol Document and the weighted leak fraction for all components
using the number of each component per model plant. That result, with
which the EPA agrees, shows that when using Method 21 and a leak
definition of 500 ppm, the estimated initial leak rate is 2.5%, and
when using Method 21 and a leak definition of 10,000 ppm, the estimated
initial leak rate is 1.65 percent.\33\ However, the initial leak rate
is only one contributing factor to baseline emissions. Another
contributing factor is the magnitude of emissions.
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\31\ See Docket ID Item No. EPA-HQ-OAR-2010-0505-7631.
\32\ See U.S. EPA, ``1995 Protocol for Equipment Leak Emission
Estimates Emission Standards'' located at Docket ID Item No. EPA-HQ-
OAR-2017-0483-0002.
\33\ See memorandum, ``Summary of Data Received on the October
15, 2018 Proposed Amendments to 40 CFR part 60, subpart OOOOa
Related to Model Plant Fugitive Emissions.'' February 10, 2020.
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While several commenters \34\ provided information on the number or
percentage of components identified with fugitive emissions, no
commenters provided component-level information on the magnitude of
those emissions.\35\ In June 2019, a study was published in Elementa
that examined fugitive emissions from 67 oil and natural gas well sites
and gathering and boosting compressor stations in the Western U.S.\36\
As discussed in the TSD, the study included quantification of fugitive
emissions from components located at well sites and gathering and
boosting compressor stations. The EPA evaluated the measured fugitive
emissions from that study for central production, well production, and
well site facilities, as defined by the study. We then evaluated the
average emissions across those three site types to compare those
emissions to
[[Page 57415]]
the estimated emissions using the average emissions factors from the
EPA Protocol Document. The average well site emissions measured in the
study were comparable to the model plant well site emissions.
Therefore, the EPA determined that the use of the emissions factors
from the 1995 Protocol Document was still appropriate and has
maintained use of these average emissions factors in the model plant
analyses supporting this final rule.
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\34\ See, for example, Docket ID Item Nos. EPA-HQ-OAR-2017-0483-
0801, EPA-HQ-OAR-2017-0483-1261, and EPA-HQ-OAR-2017-0483-2041.
\35\ See memorandum, ``Summary of Data Received on the October
15, 2018 Proposed Amendments to 40 CFR part 60, subpart OOOOa
Related to Model Plant Fugitive Emissions.'' February 10, 2020.
\36\ See Pasci, A.P., Ferrara, T., Schwan, K., Tupper, P., Lev-
On, M., Smith, R., and Ritter, K., 2019. ``Equipment Leak Detection
and Quantification at 67 Oil and Gas Sites in the Western United
States.'' Elem Sci Anth, 7(1), p.29 located at http://doi.org/10.1525/elementa.368.
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In conclusion, we identified three areas of potential uncertainty
in the October 15, 2018, proposal: (1) The effectiveness of OGI at the
various frequencies, (2) the leak occurrence rate for each survey, and
(3) the initial leak rate. The EPA was concerned that we might have
overestimated the emission reductions from the monitoring frequencies
in the 2016 NSPS subpart OOOOa due to these three areas of
uncertainties. However, after evaluating the data provided by
commenters and making the appropriate revisions to our model plant
analysis, the EPA no longer believes that these three areas create
uncertainty or resulted in an overestimation of emissions reductions.
2. Recordkeeping, Reporting, and Other Administrative Burden Associated
With the Fugitive Emissions Program
In addition to proposing reduced monitoring frequencies, the EPA
proposed amending the monitoring plan requirements in the 2016 NSPS
subpart OOOOa. Specifically, we proposed these amendments to address
concerns that the requirements, such as the site map and observation
path, resulted in significant costs that increase over time due to the
increase in the number of facilities subject to the requirements each
year. The EPA proposed allowing alternatives to the site map and
observation path that would also ensure that all fugitive components at
a site are monitored. 83 FR 52078 and 9. The EPA received comments
expressing concern that, in addition to the costs associated with the
development and necessary updates of the monitoring plan, the EPA had
underestimated the administrative burden associated with the extensive
recordkeeping and reporting requirements of the fugitive emissions
standards in the 2016 NSPS subpart OOOOa. These commenters stated that
this burden represents the largest cost of the fugitive emissions
program in the 2016 NSPS subpart OOOOa.\37\ In the October 15, 2018,
proposed rulemaking, the EPA proposed to streamline certain
recordkeeping and reporting requirements in the 2016 NSPS subpart OOOOa
to reduce burden on the industry, including the fugitive emissions
recordkeeping and reporting. 83 FR 52059. In response to these
comments, the EPA re-evaluated the fugitive emissions program, with a
focus on identifying areas to reduce unnecessary administrative burden
and provide flexibility for future innovation, while retaining
sufficient recordkeeping and reporting requirements to assure that
affected facilities are complying with the standards. After concluding
this re-evaluation, we found that certain requirements were unnecessary
and burdensome.
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\37\ See Docket ID Item No. EPA-HQ-OAR-2017-0483-0016.
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First, we examined the commenters' assertion and supporting
information that the EPA underestimated the recordkeeping and reporting
costs in both the 2016 NSPS subpart OOOOa and the October 15, 2018,
proposal. To better understand the commenters' statements regarding the
recordkeeping and reporting costs associated with the 2016 NSPS subpart
OOOOa, we reviewed the specific recordkeeping and reporting
requirements for the fugitive emissions program, including the
monitoring plan. Based on this review, we agree with the commenters
that the recordkeeping and reporting burden was underestimated in both
the 2016 NSPS subpart OOOOa and the October 15, 2018, proposal, as
described below.
In the October 15, 2018, proposal, we had proposed reducing certain
monitoring frequencies. While we updated portions of the model plant
analysis for fugitive emissions to reflect these proposed changes, we
did not make specific changes related to recordkeeping and reporting
costs. As shown in the proposal TSD,\38\ we estimated that the
development of a monitoring plan was a one-time cost of $3,672 per
company-defined area, which is estimated as consisting of 22 well sites
or seven gathering and boosting compressor stations. We estimated
reporting costs to be at $245 per site per year.
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\38\ See TSD at Docket ID Item No. EPA-HQ-OAR-2017-0483-0040.
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Second, we reevaluated the cost burden of the recordkeeping and
reporting requirements associated with the fugitive emissions standards
in the 2016 NSPS subpart OOOOa prior to considering any additional
changes to those standards that might further reduce the cost burden.
This step was necessary to provide a correct baseline for comparison
when evaluating the burden reductions associated with potential changes
to the standards.
Before considering the information provided in the comments, we
removed certain line items from the previous analysis as described. We
removed the initial and subsequent planning activities because these
items were not clearly representative of actual recordkeeping
activities that are associated with the fugitive emissions requirements
of the rule (e.g., records management systems, tracking components,
data review, etc.). We also removed the cost associated with
notification of initial compliance status because such notification is
not required under the 2016 NSPS subpart OOOOa. Next, we considered the
comments and information received on our estimate of the cost to
develop a monitoring plan under the 2016 NSPS subpart OOOOa. One
commenter provided information on the range of costs that have been
incurred by owners and operators to develop a monitoring plan since the
rule has been in place.\39\ These estimated costs range from $5,600 to
$8,800, which is more than our estimate of $3,672. In examining the
information provided by the commenter in further detail, we note that
hourly rates are higher than the standard labor rate used in EPA's
calculations, which would attribute to the difference in costs. Next,
commenters dispute our assumption that the monitoring plan is a one-
time cost for the company. Several commenters stated while most of the
monitoring plan is associated with a one-time cost, the required site
map and observation path require frequent updates as the equipment at
the site changes. One of these commenters provided an estimate of the
cost to develop the initial site map and observation path for an
individual site, and the cost of updating these items for each
monitoring survey.\40\ This information provided estimates that
companies have already spent approximately $650 developing the
individual site map and observation path for each site and an
additional $150 updating these items for each monitoring survey. Based
on this information, we agree it is appropriate to account for the
necessary updates for
[[Page 57416]]
the site map and observation path when estimating the cost burden of
the rule. Therefore, we split the monitoring plan costs into three
items in our model plant analysis: (1) Develop company-wide fugitive
emissions monitoring plan, (2) develop site-specific fugitive
monitoring plan (i.e., site map and observation path), and (3)
management of change (site map and observation path). Additionally, we
applied hourly rates, based on information provided by the commenter,
to estimate costs instead of using the flat cost values provided. The
updated estimates associated with developing a monitoring plan for well
sites under the existing standards are $2,448 to develop the general
company-wide monitoring plan (assumes 22 well sites), $400 to develop
the site map and observation path for each site, and $184 to update the
individual site map and observation path annually (based on semiannual
monitoring). This would result in a total cost for development of the
monitoring plan for the 22 well site company-defined area of $15,296,
including updates to the site map and observation path at the
semiannual surveys conducted that first year. For gathering and
boosting compressor stations, we estimate it costs $1,530 to develop a
company-wide monitoring plan (assumes seven stations per plan), $400 to
develop the site map and observation path for each site, and $367 to
update the individual site map and observation path annually (based on
quarterly monitoring). This would result in a total cost of $6,899 for
development of the monitoring plan for the seven gathering and boosting
compressor station company-defined area, including updates to the site
map and observation path at the quarterly surveys conducted that first
year. Based on available information, we believe these costs are
representative of the costs to develop and maintain the monitoring plan
as required in the 2016 NSPS subpart OOOOa.
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\39\ See Docket ID No. EPA-HQ-OAR-2017-0483; EPA's ``Oil and
Natural Gas Sector: Emission Standards for New, Reconstructed, and
Modified Sources Reconsideration; Proposed Rule''; 83 FR 52056
(October 15, 2018). Dated May 22, 2019, located at Docket ID No.
EPA-HQ-OAR-2017-0483.
\40\ See Docket ID No. EPA-HQ-OAR-2017-0483; EPA's ``Oil and
Natural Gas Sector: Emission Standards for New, Reconstructed, and
Modified Sources Reconsideration; Proposed Rule''; 83 FR 52056
(October 15, 2018). Dated May 22, 2019, located at Docket ID No.
EPA-HQ-OAR-2017-0483.
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We then examined the recordkeeping costs associated with the
fugitive emissions requirements. As stated above, we were unable to
locate clearly defined estimates for recordkeeping costs for the 2016
NSPS subpart OOOOa, therefore, all costs are new in our baseline
estimate of the actual cost of the existing standards and are based on
information received from commenters and previous information collected
by the Agency for similar programs. There are extensive records
required for each survey that is performed, regardless of the
frequency; therefore, we recognize that appropriate data management is
critical to ensuring compliance with the standards. As explained in the
TSD for this final rule,\41\ we evaluated costs for the set-up for a
database system, which ranged from commercially available options to
customized systems. Because there are commercial systems currently
available that allow owners and operators to maintain records in
compliance with the standards, we did not find it appropriate to apply
customized system costs to determine an average or range of costs.
Therefore, our initial database set-up fee is estimated as $18,607 for
22 well sites and seven gathering and boosting compressor stations. In
addition to this initial set-up fee, we recognize that there are annual
licensing fees that include technical support and updates to software.
Therefore, we have incorporated an ongoing annual fee of approximately
$470. Finally, there is recordkeeping associated with tracking observed
fugitive emissions and repairs, such as scheduling repairs and quality
control of the data. Based on information provided by commenters,\42\
we estimate additional recordkeeping costs at $430 for well sites and
$860 for gathering and boosting compressor stations.
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\41\ See TSD at Docket ID No. EPA-HQ-OAR-2017-0483.
\42\ See Re: Docket ID No. EPA-HQ-OAR-2017-0483; EPA's ``Oil and
Natural Gas Sector: Emission Standards for New, Reconstructed, and
Modified Sources Reconsideration; Proposed Rule''; 83 FR 52056
(October 15, 2018). Dated May 22, 2019, located at Docket ID No.
EPA-HQ-OAR-2017-0483. See memorandum for May 1, 2019 meeting with
GPA Midstream located at Docket ID No. EPA-HQ-OAR-2017-0483.
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Finally, we evaluated the current estimate for reporting costs
associated with the 2016 NSPS subpart OOOOa. One commenter asserted
they spent over 500 hours reporting information through the Compliance
and Emissions Data Reporting Interface (CEDRI) for their sources.\43\
We examined the information reported to CEDRI for this commenter and
concluded they have reported information for approximately 100 well
sites, which would equate to 5 hours per site. This is comparable to
our estimate of 4 hours per well site; therefore, we did not update the
cost estimate for reporting associated with the 2016 NSPS subpart
OOOOa.
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\43\ See Docket ID Item No. EPA-HQ-OAR-2017-0483-0757.
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In summary, we updated the cost burden estimates for recordkeeping
based on the 2016 NSPS subpart OOOOa. As updated, the annualized
recordkeeping and reporting costs for the existing rule, on a per site
basis, are approximately $1,500 per well site and $2,500 per gathering
and boosting compressor station. These costs represent the baseline
from which any changes to the cost burden for reporting and
recordkeeping requirements in this final rule are compared. It is
important to note that while these costs represent the costs for each
individual site, the EPA estimates that currently there are over 40,000
well sites and 1,250 compressor stations currently subject to the
fugitive emissions requirements in the 2016 NSPS subpart OOOOa. When
multiplied, the total annualized costs to the industry is estimated to
exceed $60 million per year.
After updating the recordkeeping and reporting costs for the
existing requirements, we evaluated requests by commenters recommending
specific changes to those requirements. Several commenters requested
removal of or amendments to specific line items. These included items
such as the site map and observation path requirement in the monitoring
plan, records related to the date and repair method for each repair
attempt, and name of the operator performing the survey. After further
review of the specific requirements, for the reasons explained below,
we agree with the commenters that some of the items are not critical or
are redundant for demonstrating compliance and, therefore, are an
unnecessary burden.
We are amending the monitoring plan by removing the requirement for
a site map and observation path when OGI is used to perform fugitive
emissions surveys. This requirement was in place to ensure that all
fugitive emissions components could and would be imaged during each
survey. As explained in the TSD,\44\ we agree with the commenters that
a site map and observation path are only one way to ensure all
components are imaged. We are replacing the specified site map and
observation path with a requirement to include procedures to ensure
that all fugitive emissions components are monitored during each survey
in the monitoring plan. These procedures may include a site map and
observation path, an inventory, or narrative of the location of each
fugitive emissions component, but may also include other procedures not
listed here. These company-defined procedures are consistent with other
requirements for procedures in the monitoring plan, such as the
requirement for procedures for determining the maximum viewing distance
and maintaining this viewing distance during a survey. As previously
stated, we had not accurately accounted for the ongoing cost of
updating the site map and observation path as changes
[[Page 57417]]
occur at the site. Based on information provided by one commenter, we
estimate this amendment will save each site $580 with the semiannual
monitoring frequency. These cost reductions are based on an initial
cost of $400 to develop the site map and observation path, plus $180 to
update the site map or observation path each year, based on a
semiannual monitoring frequency.
---------------------------------------------------------------------------
\44\ See TSD at Docket ID No. EPA-HQ-OAR-2017-0483.
---------------------------------------------------------------------------
We are not finalizing the proposed recordkeeping requirement to
keep records of each repair attempt. Instead, the final rule requires
maintaining a record only for the first attempt at repair and the
completion of repair. Other interim repair attempts are not necessary
for demonstrating compliance with the repair requirements.
Additionally, we are removing the requirement to maintain records of
the number and type of components not repaired during the monitoring
survey. The 2016 NSPS subpart OOOOa required maintaining a record of
the number and type of components found with fugitive emissions that
were not repaired during the monitoring survey. After further review,
this information can be derived from, and is, therefore, redundant to,
other records of the survey date and repair dates required for all
fugitive emissions components. While it is difficult to quantify the
reduction in cost burden of the removal of these records, we have
estimated a reduction in cost of 25 percent, or $107 per site per year
as discussed in the TSD.
We are also amending the reporting requirements to streamline
reporting based on comments received and further reconsideration of
what information is essential to demonstrate compliance with the
standards. First, as we are finalizing the electronic reporting form
for the annual report required by 40 CFR 60.5420a(b) concurrently with
this action, we are updating the CEDRI reporting template to reflect
the streamlined reporting requirements in this final action and ease
review of the information contained within the form. Specifically, for
reporting compliance with the fugitive emissions requirements, we have
created dropdown menus for the operator to select the type of site for
which they are reporting (i.e., well site or compressor station), to
indicate whether the well site changed status to a wellhead-only well
site during the reporting period, and identify any approved alternative
fugitive emissions standard that was used during the reporting period
for the site. Second, we are removing specific items from the annual
report as listed in section IV.I.3 of this preamble. We are removing
the requirement to report the name or unique ID of the operator
performing the survey; however, this information must be maintained in
the record, similar to the LDAR requirements for onshore natural gas
processing plants. We are removing the requirement to report the number
and type of difficult-to-monitor and unsafe-to-monitor components that
were monitored during the specified survey. This information is
required to be kept in the record, and the type and number of these
components would already be included in the reported number and type of
components found with fugitive emissions during the survey. The date of
successful repair is being removed from the report because we already
require owners and operators to report the number and type of fugitive
emissions not repaired on time. The date of successful repair will be
maintained in the record. Finally, the type of instrument used for the
resurvey is being removed from the report because the rule allows
either OGI or Method 21 (analyzer or a soap bubbles test). The
information is required to be kept in the record. Similar to the
recordkeeping changes identified in the previous paragraph, it is
difficult to estimate the reduced cost burden of each of these
individual items. That said, as shown in the TSD, we have estimated a
burden reduction of 25 percent, or $61 per site per annual report.
In summary, the amendments to the recordkeeping and reporting
requirements in this final rule will reduce the recordkeeping and
reporting burden for NSPS subpart OOOOa. The estimated annualized
recordkeeping and reporting costs for this final rule, on a per site
basis, are approximately $1,100 per well site and $1,750 per gathering
and boosting compressor station. This results in an annualized burden
reduction of approximately 27 percent for well sites and 30 percent for
gathering and boosting compressor stations.\45\
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\45\ See TSD for additional information on the estimated cost
burden at the individual site level at Docket ID No. EPA-HQ-OAR-
2017-0483.
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3. Additional Updates to the Model Plants
We also received information from commenters that suggested
additional updates beyond those already discussed above. These included
the major equipment counts and survey costs. A detailed discussion of
these updates, which we agree are necessary, is provided in the
TSD.\46\ A summary of these updates is provided below.
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\46\ See TSD at Docket ID No. EPA-HQ-OAR-2017-0483.
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Well sites. In the October 15, 2018, proposal, we maintained the
assumed flat contractor fee of $600 per survey. However, information
from commenters suggested this may be an overestimate of survey costs
if an hourly rate were used. To examine this comment, we analyzed the
CEDRI reports, and evaluated the survey times that were reported. Based
on this information, we estimated it takes operators 3.4 hours to
complete a survey at a well site, including the travel time to and from
the well site. This is based on an average survey time of approximately
1.4 hours. The travel time considers travel between sites and the
shared travel of mobilizing a monitoring operator. We applied an hourly
rate of $134 based on the Regulatory Analysis performed by the Colorado
Department of Public Health and Environment in support of Colorado's
Regulation 7.\47\ We believe this more accurately reflects the costs of
performing the survey than the previously assumed flat rate of $600.
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\47\ Colorado Department of Public Health and Environment,
``Regulatory Analysis for Proposed Revisions to Colorado Air Quality
Control Commission Regulation Numbers 3, 6, and 7'' (5 CCR 1001-5, 5
CCR 1001-8, and CCR 1001-9), February 2014.
---------------------------------------------------------------------------
Low production well sites. The low production well site model
plants (i.e., well sites with total production at or below 15 boe per
day) were updated after further review of the Fort Worth Study, updates
to the Greenhouse Gas Inventory (GHGI), and based on comments received.
First, the counts of wellheads, separators, meters/piping, and
dehydrators were recalculated after removing well sites that listed no
production on the day prior to emissions measurements during the Fort
Worth Study. This resulted in a decrease in the number of separators
and meters/piping for the low production gas well pad. The scaling
factors were also updated based on these revisions and applied to low
production oil well pads and low production associated gas well pads.
Further discussion on these changes are in the TSD. Like the well sites
discussed above, we maintained the estimate of one controlled storage
vessel per low production well site. One commenter provided some
preliminary information regarding component counts, specific to valves
and storage vessels, but also stated in their comments that the
information was not representative.\48\ Therefore, as discussed in the
TSD, it was not appropriate to revise the model plants using
information this commenter provided. We also
[[Page 57418]]
performed an analysis of the survey time and found that on average, the
surveys for low production well sites were approximately 30 minutes.
After accounting for travel time, we estimate that each survey of a low
production well site takes 2.4 hours. We applied the same hourly rate
of $134 to estimate the total cost of each survey.
---------------------------------------------------------------------------
\48\ See Docket ID Item No. EPA-HQ-OAR-2017-0483-1006.
---------------------------------------------------------------------------
Gathering and boosting compressor stations. Information of average
equipment counts were provided by GPA Midstream for gathering and
boosting compressor stations.\49\ We updated the model plant estimate
to use this information. Specifically, we revised the estimated number
of separators from 11 to five, meter/piping from seven to six,
gathering compressors from five to three, in-line heaters from seven to
one, and dehydrators from five to one, which reduces the baseline
emissions estimated for the compressor station. We maintained the cost
for the survey of $2,300 because the commenter indicated this was
appropriate based on implementation of the rule.
---------------------------------------------------------------------------
\49\ See Docket Item ID No. EPA-HQ-OAR-2017-0483-1261.
---------------------------------------------------------------------------
4. Cost Effectiveness of Fugitive Emissions Requirements
With the revisions discussed in sections V.B.1 through 3 of this
preamble incorporated in the model plants, we reexamined the costs and
emission reductions for various monitoring frequencies to determine the
updated costs of control. In evaluating the costs for this final rule,
we also reexamined the decisions made in the 2016 NSPS subpart OOOOa
for comparison. In the 2016 NSPS subpart OOOOa, we evaluated the
controls under different approaches, namely a single pollutant approach
and multipollutant approach.\50\ Further, we stated that a frequency is
considered cost effective if the cost of control for any one scenario
of methane (without consideration of VOC), VOC (without consideration
of methane), or the combination of both pollutants is cost
effective.\51\ That is, if the cost of control for reducing VOC, where
all costs are attributed to VOC control and zero to methane control, is
cost effective, then that frequency is cost effective regardless of the
methane-only or multipollutant costs.
---------------------------------------------------------------------------
\50\ See 80 FR 56616. Under the single pollutant approach, we
assign all costs to the reduction of one pollutant and zero costs
for all other pollutants simultaneously reduced. Under the
multipollutant approach, we allocate the annualized costs across the
pollutant reductions addressed by the control option in proportion
to the relative percentage reduction of each pollutant controlled.
For purposes of the multipollutant approach, we assume that
emissions of methane and VOC are controlled at the same time,
therefore, half of the cost is apportioned to the methane emission
reductions and half of the cost is apportioned to VOC emission
reductions. In this evaluation, we examined both approaches across
the range of identified monitoring frequencies, annual, semiannual,
and quarterly.
\51\ See 80 FR 56617.
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In the Review Rule, finalized in the Federal Register of Monday,
September 14, 2020, we are rescinding the methane standards for NSPS
subpart OOOOa. Therefore, in this final rule, we examined the cost
effectiveness for the control of VOC emissions only. For each frequency
evaluated in this final rule, we examined the total cost effectiveness
of each monitoring frequency (i.e., the cost of control for each
frequency from a baseline of no monitoring). This is consistent with
how costs were examined in the 2016 NSPS subpart OOOOa. For the reason
explained in the preamble to the October 15, 2018, proposal, in
addition to evaluating the total cost effectiveness of the different
monitoring frequencies, this final rule also considers incremental cost
(i.e., the additional cost to achieve the next increment of emission
reduction) to be an appropriate tool for assessing the effects of
different stringency levels of control costs.\52\ 83 FR 52070. It is
important to note that the 2016 NSPS subpart OOOOa analysis did not
present the incremental costs between each of the monitoring
frequencies evaluated. The TSD supporting this final rule presents the
cost of control for annual, semiannual, and quarterly monitoring
frequencies for well sites producing greater than 15 boe per day and
compressor stations, and biennial, annual, and semiannual monitoring
frequencies for low production well sites.
---------------------------------------------------------------------------
\52\ See also, ``Standards of Performance for Equipment Leaks of
VOC in the Synthetic Organic Chemical Manufacturing Industry
(SOCMI); Standards of Performance for Equipment Leaks of VOC in
Petroleum Refineries``; 72 FR 64860, 64864 (``2007 NSPS subparts VV
and VVa'') (in its BSER analysis, the EPA evaluated the additional
cost and emission reduction from lowering the leak definition for
valves and determined that the additional emission reduction for
SOCMI, at $5,700/ton of VOC, is not cost effective.)
---------------------------------------------------------------------------
When examining the costs of each monitoring frequency, we
recognized that a significant percentage of the costs are independent
of the monitoring frequency. That is, when annualized, the
recordkeeping and reporting costs remain unchanged as monitoring
frequencies increase. For example, the annualized cost of semiannual
monitoring is approximately 20 percent higher than the annualized cost
of annual monitoring at well sites. However, the cost effectiveness of
the annual monitoring is a higher $/ton reduced because semiannual
monitoring results in approximately 50 percent more emissions
reductions than annual monitoring. Therefore, while more frequent
monitoring does increase the costs of surveys for the year, the bulk of
the costs are realized regardless of monitoring frequency. In other
words, whereas we assumed during the proposal that reduced monitoring
frequencies would lead to large cost savings, the analyses we performed
for this final rule demonstrate that monitoring frequency is not the
most significant factor in the overall cost of the fugitive emissions
requirements. Below we present the costs of control for the monitoring
frequencies at the model plants for well sites, low production well
sites, and compressor stations.
Table 3 presents the costs of control for VOC emissions at the
monitoring frequencies evaluated in this final rule and compares those
costs to the costs presented for the 2016 NSPS subpart OOOOa. With the
updates to the model plants discussed in section V.B.1 through 3 of
this preamble, the EPA estimates that the semiannual monitoring
currently required by the 2016 NSPS subpart OOOOa for well sites has a
cost-effectiveness value of $4,324/ton of VOC emissions reduced. This
value is $1,135/ton less than was estimated for semiannual monitoring
in 2016, after adjusting for inflation. Therefore, we have determined
that semiannual monitoring remains cost effective for well sites
producing greater than 15 boe per day. We also considered the
incremental cost effectiveness of semiannual monitoring compared to
annual monitoring. This analysis showed that it cost $2,666/ton of
additional VOC emissions reduced between the annual and semiannual
monitoring frequencies. This cost is very reasonable and, therefore,
further supports retaining semiannual monitoring. Finally, the EPA
notes that, while we did not propose or take comment on quarterly
monitoring for well sites, this monitoring frequency results in a total
cost of control of $4,725/ton of VOC emissions reduced, which is also
less than the inflation-adjusted cost-effectiveness value for quarterly
monitoring that was calculated in 2016. However, the incremental cost
to reduce additional emissions by going from semiannual monitoring to
quarterly monitoring is $5,927/ton, which is a value that is higher
than the EPA has previously found to be cost effective in the past.\53\
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\53\ See 2007 NSPS subparts VV and VVa, 72 FR 64864, cited in
the 2016 NSPS subpart OOOOa final rule, 80 FR 56636. See TSD for
additional analysis and cost information, located at Docket ID No.
EPA-HQ-OAR-2017-0483.
[[Page 57419]]
Table 3--Cost-Effectiveness of Control for Well Sites Subject to Fugitive Emissions Standards Under Subpart
OOOOA of 40 CFR Part 60
----------------------------------------------------------------------------------------------------------------
Cost effectiveness ($/ton VOC)
-----------------------------------------------------------
Monitoring frequency 2016 TSD total 2020 TSD total 2020 TSD
cost effectiveness cost effectiveness incremental cost
\1\ \2\ effectiveness
----------------------------------------------------------------------------------------------------------------
Annual.............................................. $4,723 $5,153
Semiannual.......................................... 5,459 4,324 2,666
Quarterly........................................... 7,559 4,725 5,927
----------------------------------------------------------------------------------------------------------------
\1\ Values from the 2016 TSD have been adjusted for inflation for comparison purposes.
\2\ As discussed in section V.B of this preamble, the EPA received comments that our original 2016 estimates
were low, especially for recordkeeping and reporting burden. The 2020 estimates include adjustments to the
2016 estimates based on this information (which is higher than the 2016 TSD) plus include streamlined
recordkeeping and reporting as well as other updates. In addition, the revised analysis found that the
majority of the costs of the fugitive requirements are annual costs and do not vary with the monitoring
frequency. That is, the recordkeeping and reporting burden remain consistent regardless of the monitoring
frequency and the cost of each survey is not directly proportional to the incremental emissions reductions
achieved at more frequent surveys. This is further explained in section V.B.2 of this preamble. Hence, Table 3
shows an increase in cost effectiveness for the annual monitoring frequency, but a decrease in the cost
effectiveness for the semiannual and quarterly cost effectiveness from the 2020 TSD. In contrast, the 2016
values presented here are directly from the 2016 TSD and have not been adjusted based on our new analysis of
what the 2016 rule cost.
As shown in the EPA's revised model plant analysis in the TSD for
this final rule, and consistent with the October 15, 2018, proposal,
there is sufficient evidence that low production well sites are
different than well sites with higher production and, therefore,
warrant a separate evaluation of the cost of control. The EPA did not
include a separate analysis of low production well sites in the 2016
NSPS subpart OOOOa. Therefore, all costs presented above for well sites
from the 2016 analysis also would apply to low production well sites.
The EPA proposed biennial monitoring of low production well sites
(i.e., well sites with total production at or below 15 boe per day).
Based on the revised cost analysis, the EPA estimates that the proposed
biennial monitoring frequency has a cost effectiveness of $6,061/ton of
VOC emissions reduced. In addition, we estimate that annual monitoring
would cost $7,577/ton VOC, and semiannual monitoring currently required
by the 2016 NSPS subpart OOOOa has a cost of $6,116/ton of VOC
emissions reduced. All of these values are higher than the inflation-
adjusted value of $5,459/ton VOC that was estimated for semiannual
monitoring at well sites in 2016. Further, all of these costs are
higher than a value the EPA has previously stated is not cost
effective.\54\ Therefore, we have determined that none of the
monitoring frequencies are cost effective for low production well
sites. Table 4 provides a summary of the costs of control for low
production well sites.
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\54\ See 2007 NSPS subparts VV and VVa, 72 FR 64864, cited in
the 2016 NSPS subpart OOOOa final rule, 80 FR 56636. See TSD for
additional analysis and cost information, located at Docket ID No.
EPA-HQ-OAR-2017-0483.
Table 4--Cost-Effectiveness of Control for Low Production Well Sites Subject to Fugitive Emissions Standards
Under Subpart OOOOA of 40 CFR Part 60
----------------------------------------------------------------------------------------------------------------
Cost effectiveness ($/ton VOC)
-----------------------------------------------------------
Monitoring frequency 2016 TSD total 2020 TSD total 2020 TSD
cost effectiveness cost effectiveness incremental cost
\1\ \2\ effectiveness
----------------------------------------------------------------------------------------------------------------
Biennial \3\........................................ N/A $6,061
Annual.............................................. $4,723 7,577 $12,125
Semiannual.......................................... 5,459 6,116 3,192
----------------------------------------------------------------------------------------------------------------
\1\ Values from the 2016 TSD have been adjusted for inflation for comparison purposes.
\2\ As discussed in section V.B of this preamble, the EPA received comments that our original 2016 estimates
were low, especially for recordkeeping and reporting burden. The 2020 estimates include adjustments to the
2016 estimates based on this information (which is higher than the 2016 TSD) plus include streamlined
recordkeeping and reporting as well as other updates. In addition, the revised analysis found that the
majority of the costs of the fugitive requirements are annual costs and do not vary with the monitoring
frequency. That is, the recordkeeping and reporting burden remain consistent regardless of the monitoring
frequency and the cost of each survey is not directly proportional to the incremental emissions reductions
achieved at more frequent surveys. This is further explained in section V.B.2 of this preamble. Further, low
production well site model plants were not developed as part of the 2016 rulemaking. Therefore, the 2016
values presented here were for all well sites, without consideration of production. Hence, Table 4 shows an
increase in cost effectiveness for the monitoring frequencies presented. In contrast, the 2016 values
presented here are directly from the 2016 TSD and have not been adjusted based on our new analysis of what the
2016 rule cost.
\3\ Biennial monitoring was not evaluated in 2016, therefore, no cost effectiveness is presented in Table 4.
Further, while this final rule does not have to consider the costs
of controlling methane emissions, the EPA did evaluate those costs. The
costs for all of the monitoring frequencies evaluated for low
production well sites are greater
[[Page 57420]]
than the highest value for methane that the EPA determined to be
reasonable in the 2016 NSPS subpart OOOOa for both methane only and
under the multipollutant approach.\55\ In the 2015 proposal for NSPS
subpart OOOOa, the EPA stated that a cost of control of $738 per ton of
methane reduced did not appear excessive when all costs are assigned to
methane reduction and zero to VOC reduction. 80 FR 56624. Based on the
revised analysis, the costs of control of methane emissions under the
single pollutant approach for low production well sites are more than
double this value of $738 per ton at all of the monitoring frequencies
evaluated. This value is also exceeded under a multipollutant approach
where methane reduction only assumes half the cost, as explained in the
TSD.\56\ Therefore, even if we had not rescinded the methane standards
in the Review Rule, we would still conclude that fugitive emissions
monitoring, at any of the frequencies evaluated, is not cost effective
for low production well sites.
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\55\ See Section 2.5.1.1 of the TSD for additional information.
\56\ For the multipollutant approach, the emissions of each
pollutant are calculated based on the relative percentage of each
pollutant in the gas emitted. Since the same control is applied to
the gas emitted, the cost is divided in half to attribute the costs
of control equally between the two pollutants (methane and VOC).
---------------------------------------------------------------------------
While we are concluding that fugitive emissions monitoring is not
cost effective for low production well sites, production at these well
sites could potentially increase to greater than 15 boe per day,
rendering monitoring to be cost effective. For example, a new well may
be drilled at a well site, or the existing wells may be refractured to
increase the production levels. When these actions occur, the final
rule requires a new 30-day calculation of the total well site
production. If the total production remains at or below 15 boe per day,
no monitoring is required as long as the owner or operator continues to
maintain the production at these low levels. However, if the total
production following one of these actions has increased to greater than
15 boe per day, the owner or operator must begin monitoring for
fugitive emissions within 90 days of the startup of production
following such action, the same as the requirement for a modified well
site. Therefore, under the final rule, low production well sites remain
affected facilities; however, they have the option of maintaining
production at or below 15 boe per day on a continuous basis instead of
implementing the fugitive monitoring requirement.
There are three timeframes in which we are requiring sources to
calculate the total production from the well site. First, there are
well sites that have not yet triggered the requirements in NSPS subpart
OOOOa, which are those constructed, reconstructed, or modified after
this final rule becomes effective. The owner or operator of such a well
site has the option to calculate the total well site production based
on the first 30 days of production. If the total production from all of
the wells at the well site is at or below 15 boe per day (combined for
both oil and natural gas produced at the site), then the owner or
operator of the well site may either maintain production at or below
this threshold on a rolling 12-month average or begin the fugitive
emissions program. The owner or operator must comply with one of these
two requirements at any and all times. If the total production of the
well site is above 15 boe per day as determined in the first 30 days of
production, then the site must begin the fugitive emissions program,
including completing the initial monitoring within 90 days of startup
of production. Recognizing that there are some well sites that have
triggered the fugitive emissions requirements that may not have 12-
months' worth of production data yet but are already able to
demonstrate they are low production, the final rule contains a
provision to allow the owner or operator to use production records
based on the first 30 days of production after becoming subject to the
NSPS to determine if the well site is low production. This
determination must be made by December 14, 2020. After that date, the
owner or operator may use the rolling 12-month average, as described
next, for demonstrating the well site is low production.
Next, recognizing that production declines over time, we are also
allowing an option for owners or operators subject to the monitoring
requirement to determine whether the total production for the well site
declines to 15 boe per day or below when calculated on a rolling 12-
month average. If the total well site production is at or below this
threshold on a rolling 12-month average, then the owner or operator has
the option to stop fugitive monitoring and instead maintain total well
site production below this threshold. The owner or operator must comply
with either the fugitive monitoring requirement or maintain total well
site production below this threshold at any and all times.
Finally, the EPA is aware that a low production well site could
later increase production due to subsequent activities, as discussed
above. For example, owners or operators commonly take actions to
increase production as production declines or continue to drill new
wells after the initial startup of production of the well site. If
production subsequently increases to greater than 15 boe per day, it
would be cost effective to implement the fugitive emissions monitoring
requirement. In light of the above, the final rule requires that any
well site that is not conducting fugitive emissions monitoring because
total well site production is at or below the threshold must
redetermine the total well site production following any of the
following actions: A new well is drilled, a well is hydraulically
fractured or re-fractured, a well is stimulated in any manner for the
purpose of increasing production (including well workovers), or a well
at the well site is shut-in for the purposes of increasing production
from the well site. These well sites must recalculate the total well
site production based on the first 30 days of production following the
completion of that action. It is inappropriate to continue to utilize a
rolling 12-month average because the production in the 11 months prior
to the action that increased production would bias the average low.
Like well sites constructed, reconstructed, or modified after this
final rule, these well sites must recalculate the total well site
production based on the first 30 days of production following the
completion of that action to increase production.
We have not calculated the impacts of the production calculation
because owners and operators are already required to track production
for other purposes, regardless of environmental regulation, and we do
not anticipate any additional burden associated with these records for
purposes of this rule.
The final rule also requires semiannual monitoring of gathering and
boosting compressor stations. As with fugitive monitoring of well
sites, based on the revised cost analysis in the TSD for the final
rule, the EPA reexamined the costs and emission reductions, including
incremental cost and emission reductions, for various monitoring
frequencies. In the October 15, 2018, proposed rulemaking, the EPA co-
proposed annual and semiannual monitoring of fugitive emissions at all
compressor stations. As previously discussed, the 2016 NSPS subpart
OOOOa requires quarterly monitoring for compressor stations, including
gathering and boosting stations, transmission stations, and storage
stations. Therefore, the 2016 determination that quarterly monitoring
was cost effective was based on the
[[Page 57421]]
weighted average of the cost-effectiveness values for all of those
station types. In the Review Rule, which was finalized in the Federal
Register of Monday, September 14, 2020, the EPA has removed the
transmission and storage segments from the Crude Oil and Natural Gas
Production source category and rescinded the standards for those
sources. As a consequence, only gathering and boosting compressor
stations remain subject to the standards of NSPS subpart OOOOa.
After updating the compressor station model plants, the EPA
estimates that the quarterly monitoring currently required by the 2016
NSPS subpart OOOOa has a cost effectiveness of $3,221/ton of VOC
emissions reduced at gathering and boosting compressor stations. The
EPA also considered the incremental cost effectiveness of going from
semiannual monitoring to quarterly monitoring. This analysis showed
that it cost $4,988/ton of additional VOC emissions reduced between the
semiannual and quarterly monitoring frequencies. These values (total
and incremental) are considered cost-effective for VOC reduction based
on past EPA decisions, including the 2016 rulemaking. However, the
incremental cost of $4,988/ton of additional VOC reduced is on the high
end of the range that we had previously found to be cost-effective for
VOC.\57\ In contrast, semiannual monitoring is very cost-effective, at
a total cost of $2,632/ton and incremental cost of $2,501/ton between
annual and semiannual monitoring to reduce an additional 2,156 tons of
VOC per year.\58\ We further note that moving from annual to semiannual
monitoring achieves the same incremental reduction in VOC emissions as
moving from semiannual to quarterly monitoring (2,156 tons/year) but at
half the cost per ton of additional VOC reduced ($2,501/ton instead of
$4,988/ton). Moreover, additional factors influence our evaluation of
the appropriateness of selecting quarterly monitoring as compared to
semiannual monitoring for compressor stations. In particular, the oil
and gas industry is currently experiencing significant financial
hardship that may weigh against the appropriateness of imposing the
additional costs associated with more frequent monitoring.\59\ The EPA
also acknowledges that there are potential efficiencies, and potential
cost savings, with applying the same monitoring frequencies for well
sites and compressor stations,\60\ In light of all of these
considerations, the EPA thinks it is reasonable to forgo quarterly
monitoring and choose semiannual monitoring as the BSER for compressor
stations. Table 5 provides a summary and comparison of these costs per
ton of VOC reduced.
---------------------------------------------------------------------------
\57\ See 2007 NSPS subparts VV and VVa, 72 FR 64864, cited in
the 2016 NSPS subpart OOOOa final rule, 80 FR 56636. See TSD for
additional analysis and cost information, located at Docket ID No.
EPA-HQ-OAR-2017-0483.
\58\ See Table 2-35f of the TSD located at Docket ID No. EPA-HQ-
OAR-2017-0483.
\59\ See Iyke, B. N., 2020. ``COVID-19: The reaction of US oil
and gas producers to the pandemic.'' Energy RESEARCH LETTERS, 1(2),
located at https://erl.scholasticahq.com/article/13912.pdf.
See Gil-Alana, L. A., & Monge, M., 2020. ``Crude Oil Prices and
COVID-19: Persistence of the Shock.'' Energy RESEARCH LETTERS, 1(1),
located at https://doi.org/10.46557/001c.13200.
See Sharif, et al., 2020. ``COVID-19 pandemic, oil prices, stock
market, geopolitical risk and policy uncertainty nexus in the US
economy: Fresh evidence from the wavelet-based approach.''
International Review of Financial Analysis, 70, 7101496, located at
https://doi.org/10.1016/j.irfa.2020.101496.
\60\ See Docket ID Nos. EPA-HQ-OAR-2017-0483-0755 and EPA-HQ-
OAR-2017-0483-0773.
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While this final rule does not have to consider the cost-
effectiveness of controlling methane emissions, the EPA did evaluate
those costs per ton of methane reduced. As discussed above for low
production well sites, the highest costs per ton of methane reduced
that we have found to be cost-effective in the past is $738/ton.
Assigning all costs to methane (under the single pollutant approach)
results in a total cost per ton of $895/ton and incremental cost per
ton of $1,387/ton of methane reduced for quarterly monitoring, which
almost doubles the highest cost per ton of methane reduced that we had
previously found to be cost-effective ($738/ton). Under the
multipollutant approach, the incremental cost per ton of additional
methane reduced is $695/ton. While this incremental cost per ton is
cost-effective, it is also at the high end of the range. Therefore,
based on these costs per ton of methane reduced and considering the
current financial hardships being experienced across the oil and gas
industry, we would have similarly required semiannual monitoring even
if methane had remained a regulated pollutant.
Table 5--Cost-Effectiveness of Control for Compressor Stations Subject to Fugitive Emissions Standards Under Subpart OOOOA of 40 CFR Part 60
--------------------------------------------------------------------------------------------------------------------------------------------------------
Cost effectiveness ($/ton VOC)
-----------------------------------------------------------------------------------------------------------------------
Gathering and boosting stations Compressor station weighted-average
Monitoring frequency -----------------------------------------------------------------------------------------------------------------------
2016 TSD total 2020 TSD total 2020 TSD 2016 TSD total 2020 TSD
cost effectiveness cost effectiveness incremental cost cost effectiveness 2020 TSD total incremental cost
\1\ \2\ effectiveness \1\ cost effectiveness effectiveness
--------------------------------------------------------------------------------------------------------------------------------------------------------
Annual.......................... $2,105 $2,698 .................. $3,278 $3,606 ..................
Semiannual...................... 2,443 2,632 $2,501 3,682 3,341 $2,811
Quarterly....................... 3,391 3,221 4,988 5,006 3,908 5,607
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ Values from the 2016 TSD have been adjusted for inflation for comparison purposes.
\2\ As discussed in section V.B of this preamble, the EPA received comments that our original 2016 estimates were low, especially for recordkeeping and
reporting burden. The 2020 estimates include adjustments to the 2016 estimates based on this information (which is higher than the 2016 TSD) plus
include streamlined recordkeeping and reporting as well as other updates. In addition, the revised analysis found that the majority of the costs of
the fugitive requirements are annual costs and do not vary with the monitoring frequency. That is, the recordkeeping and reporting burden remain
consistent regardless of the monitoring frequency and the cost of each survey is not directly proportional to the incremental emissions reductions
achieved at more frequent surveys. This is further explained in section V.B.2 of this preamble. Hence, Table 5 shows an increase in cost effectiveness
for the annual and semiannual monitoring frequencies, but a decrease in the cost effectiveness for the quarterly cost effectiveness from the 2020 TSD.
In contrast, the 2016 values presented here are directly from the 2016 TSD and have not been adjusted based on our new analysis of what the 2016 rule
cost.
C. AMEL
The 2016 NSPS subpart OOOOa contains provisions for requesting an
AMEL for specific work practice standards covering well completions,
reciprocating compressors, and the collection of fugitive emissions
components at well sites and compressor stations. While written with
emerging technologies as the focus, the provisions in the 2016 NSPS
subpart
[[Page 57422]]
OOOOa could also be used for state programs, though the application
requirements were unclear on certain points. Therefore, the EPA
proposed amendments to the application requirements as they relate to
emerging technologies in order to streamline the application process,
and proposed a new section to address state programs, including
proposed alternative fugitive emissions standards based on our review
of existing state programs. This section describes changes, based on
information provided in public comments, to the AMEL provisions.
1. Emerging Technologies
The EPA continues to recognize that new technologies are expected
to enter the market soon that could locate sources of fugitive
emissions sooner and at lower costs than the current technologies
required by the 2016 NSPS subpart OOOOa. While the EPA established a
foundation for approving the use of these emerging technologies in the
2016 NSPS subpart OOOOa, we proposed specific revisions in the October
15, 2018, proposal to help streamline the application requirements and
process. Specifically, we proposed to allow owners and operators to
apply for an AMEL on their own, or in conjunction with manufacturers or
vendors and trade associations. We also proposed to allow the use of
test data, modeling analyses, and other documentation to support field
test data, provided seasonal variations are accounted for in the
analyses. While we received many supportive comments on these specific
proposed amendments, we also received comments asserting that the
application process is still too restrictive and burdensome to promote
innovation.
First, the commenters stated that applications seeking approval of
an alternative should be accepted by the EPA from manufacturers and
vendors independently of owners and operators. We have reviewed the
information provided by the commenters and agree that it is appropriate
in the context of the revisions to 40 CFR 60.5398a to remove language
that previously indicated from whom the Administrator would consider
applications under that section because section 111(h)(3) of the CAA
states ``any person'' can request an AMEL, and if they establish to the
satisfaction of the Administrator that the AMEL will achieve emission
reductions that are at least equivalent with the requirements of the
rule, then the Administrator will allow the alternative. While the
final rule allows any person to submit an application for an AMEL under
this provision, the final rule still includes the minimum information
that must be included in each application in order for the EPA to make
a determination of equivalency and, thus, be able to approve an
alternative. This final rule requires applications for these AMEL to
include site-specific information to demonstrate equivalent emissions
reductions, as well as site-specific procedures for ensuring continuous
compliance.
Next, the commenters generally supported the proposal to allow the
use of test data, modeling analyses, and other documentation to support
field test data. In addition to their support of these supplemental
data, commenters also requested that the final rule allow the use of
information collected during testing at controlled testing facilities
to be considered in lieu of site-specific field testing. The EPA
considered whether it would be appropriate to allow this information
and has concerns related to the representativeness of the information
when compared to actual operating sites. For example, we are aware of
one controlled testing facility located in the U.S., the Methane
Emissions Technology Evaluation Center (METEC) located in Fort Collins,
Colorado.\61\ That facility is equipped with several different
configurations of well pads using equipment that was donated from the
oil and natural gas industry. The test well pads do not produce or
process field gas; in fact, none of the equipment that is onsite is in
contact with field gas. Instead, METEC utilizes compressed natural gas
that is transported from offsite in order to create controlled leaks.
In establishing controlled leaks, METEC uses tubing with leak points
near typical leak interfaces to simulate a leak; however, these
releases are not operated at pressures or temperatures that are
typically encountered at an operating well site in the field. While we
agree that testing at a controlled testing facility such as the METEC
site can be helpful to understanding how a technology may perform, and
the information gathered from such controlled test sites can be useful
in supplementing other data, it is inappropriate to rely solely on the
information collected at these types of facilities as being
representative of how the technology would perform at an operating well
site or compressor station. At this time, the EPA does not believe that
it can determine the efficacy of a monitoring or detection technology
where demonstrations take place only under controlled conditions. By
extension, the EPA would be unable to determine the validity of whether
an alternative indeed achieves equivalent emissions reductions if only
presented with data from testing at a controlled testing facility.
Therefore, we are finalizing amendments that require field test data,
but that allow the use of test data, modeling analyses, data collected
at controlled testing facilities, and other documentation to support
and supplement field test data.
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\61\ See https://energy.colostate.edu/metec for more information
on the METEC facility.
---------------------------------------------------------------------------
Next, we solicited comment on whether groups of sites within a
specific area that are operated by the same operator could be grouped
under a single AMEL. We received comments that discussed this broad
application of alternatives in two distinct ways: (1) Allowing the
aggregation of emission sources beyond the individual site in order to
demonstrate equivalent emission reductions, and (2) allowing the use of
approved AMELs at future sites that are designed and operated under the
conditions specified in the approved AMEL. We evaluated both types of
broad approval options raised in the comments by considering the
definitions in the existing rule and the AMEL provisions of section
111(h)(3) of the CAA.
In the first instance, we evaluated whether it would be appropriate
to allow the aggregation of emission sources beyond the individual site
when evaluating the equivalency of an alternative. Specifically, we
considered whether an applicant for an AMEL related to fugitive
emissions monitoring could aggregate the total fugitive emissions
across multiple sites within a specific geographic area, such as a
basin, in order to demonstrate the requested AMEL would achieve at
least equivalent emission reductions as the NSPS requirements for
fugitive emissions monitoring and repair at an individual site. The
work practice standards for the collection of fugitive emissions
components at a well site or at a compressor station were established
pursuant to section 111(h) of the CAA, which allows an opportunity for
an AMEL. In accordance with section 111(h)(3) of the CAA, a source may
use an approved AMEL for purposes of compliance with the established
work practice. The commenters stated that the generic use of the word
``source'' allows aggregation of fugitive emissions components amongst
multiple sites and is not limited to single sites. The EPA does not
agree that aggregating fugitive emissions across multiple sites is a
viable method to determine equivalency with the NSPS provided the
definitions of affected facility in NSPS subpart OOOOa related to the
collection of
[[Page 57423]]
fugitive emissions components. NSPS subpart OOOOa defines the
``source'' that is subject to the work practice standards for fugitive
emissions as the ``collection of fugitive emissions components at a
well site'' and the ``collection of fugitive emissions components at a
compressor station'' in 40 CFR 60.5365a(i) and (j). These terms specify
single-site applicability for the work practice standard. Because the
rule does not define an affected facility or a source to be a
geographic area, such as a basin, it is the EPA's determination that a
demonstration of equivalent emission reductions for purposes of
evaluating alternatives to the BSER has been based on the fugitive
emissions at a single site, and not an aggregation of emissions across
multiple well sites, compressor stations, or a combination of these two
site types with an averaging or trading program akin to what the EPA
has referred to in the past as a ``bubble'' approach. For further
discussion on this topic, see section VI.C.2 of this preamble.
The second point raised by commenters was that requiring site-
specific approvals (i.e., AMELs that list specific well sites or
compressor stations) would result in unnecessary burden as new sites
with the same owner or operator, similar equipment, operating
conditions, and in the same geographic area (e.g., basin) are
constructed. According to commenters, this unnecessary burden results
from the need for the owner or operator to apply for an AMEL for each
of these sites in the future, even though the AMEL would be identical
to the previously approved AMELs for similar sites. We agree with the
commenters that it is possible that AMELs could, where appropriate, be
approved for future use at sites not included in the original
application as discussed below. Commenters also encouraged the EPA to
consider the potential for AMELs applicable to specific types of
facilities with different owners or operators within an industry
category or geographic region.
While the EPA is not amending 40 CFR 60.5398a at this time to
address broad approvals of AMEL applications, we do recognize that the
Agency has discretion in certain circumstances to allow for broad
approval of alternatives via several different paths. First, for
example, an applicant could submit an AMEL application for an
alternative technology (and associated work practice) that includes
specific site characteristics under which the technology (and
associated work practice) has been tested and that demonstrates
equivalent reductions to the standards in the NSPS. The application
would include an explanation of these characteristics (e.g.,
characteristics of the formation, operating conditions at the site,
type of equipment and processes located at the site, and variables that
affect performance of the technology or work practice) and a request
that the EPA consider broad approval of the application such that sites
(including those subject to the NSPS at the time of application and
future sites) that meet the same characteristics could utilize the same
approved alternative without the need for additional application to the
EPA. The scope of such an approval might be limited based on any number
of conditions as appropriate (such as those mentioned above). The EPA
believes that, depending on the facts of the application, some type of
broad approval may be a feasible path forward, but we will need to
evaluate the information specific to the application in hand once
received. As of the date of this final rule, the EPA has received no
applications for AMELs to be able to determine if additional amendments
(beyond those in this final rule) are necessary for such a situation,
and how such potential amendments might be drafted to facilitate such
broad approvals. In summary, if the applicant believes that it is
appropriate to apply the alternative to more sites than those listed in
the application because the proposed alternative can achieve
equivalency for other sites, then the applicant should state this
intent and make this demonstration to the EPA within the application.
If provided with sufficient information, explanation, justification,
and documentation, the EPA may determine under what defined conditions,
if any, it is appropriate to allow the use of the alternative once
approved at any site meeting those conditions, including sites
constructed in the future.
Second, the EPA is interested in developing a framework in the
future for AMEL requests that share similar characteristics (e.g.,
technologies) in order to streamline both applications and approvals.
While the EPA has not received applications related to the work
practice standards in the 2016 NSPS subpart OOOOa, we have evaluated
and approved AMELs for other sources in a few instances for one
specific control technology, pressure assisted multi-point flares (for
further information, see the EPA rulemaking Docket ID No. EPA-HQ-OAR-
2014-0783). In the course of reviewing those applications, the EPA was
able to establish testing criteria for this particular control
technology to demonstrate equivalency with the underlying operational
standards (i.e., 98-percent control efficiency) as well as other
certain design, equipment, and work practice standards, which, if met,
would help streamline approval of applications submitted after that
point. The EPA is committed to working with stakeholders to develop
testing criteria for technologies and work practices for NSPS subpart
OOOOa. However, due to the variability of this sector, as well as the
wide-ranging array of technologies currently being pursued for
development, we are unable to amend the language within this rule and
provide such a framework at this time. For the pressure assisted multi-
point flares, the EPA developed the testing framework in conjunction
with an application and with stakeholder feedback from the first AMEL
requests received and approved for that particular technology. We have
not yet reached that critical first step of an application being
submitted to the EPA to determine what testing framework might be
appropriate, or how that framework might be technology family-specific
(e.g., continuous point monitors, aerial surveys, mobile equipment). We
encourage interested stakeholders to continue engaging with us early in
any application process so additional streamlining measures can be
evaluated. The EPA is committed to improving this process of evaluating
emerging technologies and may publish another request for information
regarding technology innovation and the application process.
Third, if an applicant can demonstrate that a technology has very
broad applicability across the entire industry, then, in addition to
exploring the possibility of an AMEL, the EPA also would consider
whether to undertake a rulemaking process to amend NSPS subpart OOOOa
to allow for widespread use of the technology. As always, the EPA will
review each application individually to determine if it has
demonstrated that the alternative will achieve equivalent or greater
emission reductions than the work practice standard the alternative
would replace.
In summary, we are finalizing amendments to the application
requirements for an AMEL in 40 CFR 60.5398a. We are allowing
applications from any person. Further, we are allowing the use of
supplemental data, such as test data, data collected at controlled
testing facilities, modeling analyses, and other relevant
documentation, to support field data that are collected to demonstrate
the emissions reductions achieved. While
[[Page 57424]]
we are not amending the rule to specifically state an approved AMEL can
be used for future sources, we recognize that it may be possible, where
appropriate, for the EPA to establish specific conditions during the
AMEL process under which an approved alternative may be applied at
sites not specifically listed in the application.
2. State Fugitive Emissions Programs
To reduce duplicative burdens to the industry related to the
fugitive emissions requirements, the EPA proposed alternative fugitive
emissions standards for well sites and compressor stations located in
specific states. These alternative standards were proposed based on the
EPA's review of the monitoring and repair requirements of the
individual state fugitive emissions requirements \62\ relevant to well
sites and compressor stations. In the proposal, we stated that a well
site or compressor station, located in the specified state, could elect
to comply with the specified state program as an alternative to the
monitoring, repair, and recordkeeping requirements in the NSPS.
However, these sites would be required to monitor all fugitive
emissions components, as defined in the NSPS, comply with the
requirement to develop a monitoring plan, and report the information
required by the NSPS because the sites remain affected facilities.
---------------------------------------------------------------------------
\62\ Note, several states refer to the fugitive emissions
standards as LDAR.
---------------------------------------------------------------------------
Similar to the proposed amendments for emerging technologies, we
received support for the proposed amendments for state programs.
However, some commenters stated that the EPA should recognize the
approved state programs as wholly equivalent to the NSPS, including for
all reporting and recordkeeping requirements. The commenters indicated
that the EPA's equivalency determination still leaves the regulated
community in certain states subject to duplicative requirements. They
added that complying with two different reporting and recordkeeping
schemes for the same site is very burdensome and provided no
environmental benefit.
For the proposal, we evaluated 14 existing state programs to
determine whether they are equivalent to the fugitive emissions
requirements in 40 CFR 60.5397a. That evaluation included a qualitative
comparison of the fugitive emissions components covered by the state
programs, monitoring instruments, leak or fugitive emissions
definitions, monitoring frequencies, repair requirements, and
recordkeeping requirements to the requirements of the NSPS.\63\
However, at the time of the proposal, the EPA had not evaluated the
reporting requirements of the 14 individual state programs. We have
completed that evaluation for this final rule for the state programs
that we proposed as alternative standards and the results of that
evaluation are discussed in more detail in section VI.C.2 of this
preamble. We also updated the overall analysis of equivalency.\64\
Through this additional evaluation, we concluded that the recordkeeping
and reporting requirements of the various state programs do not need to
be exactly equivalent to the requirements of the NSPS subpart OOOOa
because the purpose of recordkeeping and reporting requirements is to
ensure compliance with whatever standards apply. Obviously, the state
programs we evaluated are not identical to the NSPS, so it stands to
reason that their associated recordkeeping and reporting requirements
might differ. Therefore, when evaluating the recordkeeping and
reporting requirements in the individual state programs, we focused our
review on the elements of those requirements that we deemed essential
to a demonstration of compliance with the individual alternative
standards. Sites remain subject to the NSPS, because the alternative
standards are standards within the NSPS, therefore, compliance
demonstrations are necessary through recordkeeping and reporting.
---------------------------------------------------------------------------
\63\ See memorandum, ``Equivalency of State Fugitive Emissions
Programs for Well Sites and Compressor Stations to Final Standards
at 40 CFR part 60, subpart OOOOa,'' located at Docket ID No. EPA-HQ-
OAR-2017-0483. January 17, 2020.
\64\ See memorandum, ``Equivalency of State Fugitive Emissions
Programs for Well Sites and Compressor Stations to Final Standards
at 40 CFR part 60, subpart OOOOa,'' located at Docket ID No. EPA-HQ-
OAR-2017-0483. January 17, 2020.
---------------------------------------------------------------------------
At a minimum, the EPA requires reports to include information that
allows a demonstration of compliance for all fugitive emissions
components (as defined in 40 CFR 60.5430a) at the individual site level
(i.e., well site or compressor station). This means the report must
provide information on each individual monitoring survey conducted at
each well site or compressor station adopting the alternative fugitive
emissions standards. We reviewed the reports required under state law
for the six states for which we are finalizing alternative fugitive
emissions standards (i.e., California, Colorado, Ohio, Pennsylvania,
Texas, and Utah) to determine (1) if site-level information is required
in the reports and (2) if the information reported demonstrates
compliance through inclusion of elements such as the date of the
survey, monitoring instrument used, information for each identified
fugitive emission, repair information, and delayed repair information.
For three of the six states (California, Ohio, and Pennsylvania) where
we are finalizing alternative standards, the required state reports are
site-specific and include information that will demonstrate compliance
with the alternative standards. For the other three states (Colorado,
Texas, and Utah), site-specific reporting is not required, or will not
demonstrate compliance with the alternative standards. Therefore, the
sites adopting the alternative standards for Colorado, Texas, and Utah,
would need to provide the site-specific reports required in 40 CFR
60.5420a(b)(7). As discussed in detail in section V.B.2 of this
preamble, the EPA is amending the recordkeeping and reporting
requirements related to the fugitive emissions requirements. The result
of these amendments is an annualized burden reduction of approximately
27 percent for well sites and 30 percent for gathering and boosting
compressor stations, and those same burden reductions will be realized
by sites in these three states.\65\
---------------------------------------------------------------------------
\65\ See TSD for additional information on the estimated cost
burden at the individual site level at Docket ID No. EPA-HQ-OAR-
2017-0483.
---------------------------------------------------------------------------
For the three states that do not require site-specific reporting,
we reviewed the state's recordkeeping requirements to determine if any
additional records would be necessary for reporting the required
information under the NSPS. We found that for each of the three states,
the records are very similar to, if not the same as, the information
required under the NSPS. Given that additional records beyond those
required by the state are not necessary, the EPA concludes that there
is no duplicative recordkeeping burden associated with compliance with
these alternative standards. This, in addition to the significant
reduction in reporting burden discussed in section V.B.2 of this
preamble, allows the EPA to conclude the submission of the reports
required in 40 CFR 60.5420a(b)(7) presents minimal burden for sites in
Colorado, Texas, and Utah.
Therefore, to summarize, the final rule requires reporting of
information to demonstrate site-level compliance with the alternative
fugitive emissions standards as follows:
Where the state report includes site-specific information
for each fugitive emissions survey that demonstrates compliance with
the alternative
[[Page 57425]]
standard, the owner or operator has the option to either (a) provide
the EPA with a copy of the state report, in the format in which is it
submitted to the state, based on the following order of preference: (1)
As a binary file; (2) as an Extensible Markup Language (XML) schema;
(3) as a searchable portable document format (PDF); or (4) as a scanned
PDF of a hard copy, or (b) provide the report required by 40 CFR
60.5420a(b)(7)(i) and (ii) to the EPA in accordance with the applicable
reporting procedures.
Where the state report does not include site-specific
information for each fugitive emissions survey, the owner or operator
must report the information required by 40 CFR 60.5420a(b)(7)(i) and
(ii) to the EPA in accordance with the procedures applicable to such a
submission.
Any owner or operator has the option to complete the information
required by 40 CFR 60.5420a(b)(7) in lieu of submitting a copy of the
state report. As described in section IV.I of this preamble, electronic
reporting through CEDRI is now required for all reports under 40 CFR
60.5420a(b). Thus, the EPA is requiring electronic submission of
reports for the alternative fugitive emissions requirements, regardless
of whether the state continues to allow paper copy submissions.
The EPA believes that adoption of these alternative standards will
further reduce the burden of the fugitive emissions standards on the
industry from this rule. No additional recordkeeping beyond that
required by the alternative standard is necessary. Additional
justification for the EPA's decision to adopt these state programs as
alternative fugitive emission standards is provided in the memorandum
\66\ summarizing the EPA's review of each state program's requirements
and in section VI of this preamble.
---------------------------------------------------------------------------
\66\ See memorandum, ``Equivalency of State Fugitive Emissions
Programs for Well Sites and Compressor Stations to Final Standards
at 40 CFR part 60, subpart OOOOa,'' located at Docket ID No. EPA-HQ-
OAR-2017-0483. January 17, 2020.
---------------------------------------------------------------------------
We note that one commenter expressed concern over the proposed
state equivalency determinations and noted that several of the programs
evaluated have specific applicability thresholds where the standards
only apply to a subset of sources, whereas the NSPS applies to all new,
modified, or reconstructed sources.\67\ We agree that the applicability
thresholds for these state programs are different from the NSPS, but we
do not agree that additional regulatory text is necessary to address
this concern. The regulatory thresholds included in state programs that
limit or reduce monitoring and repair requirements do not affect the
requirements for sources subject to the NSPS. Therefore, if a site
subject to the NSPS is not also subject to the state program because of
the state-specific applicability threshold, the site would still be
required to comply with the requirements of the NSPS. Where
appropriate, we have amended the regulatory text to clearly define the
requirements of the alternative standard. More discussion of this
comment and our response is provided in section VI.C.2 of this
preamble.
---------------------------------------------------------------------------
\67\ See Docket ID Item No. EPA-HQ-OAR-2017-0483-2041.
---------------------------------------------------------------------------
VI. Summary of Significant Comments and Responses
This section summarizes the significant comments on the proposed
amendments and our responses to those comments. Additional comments and
responses are summarized in the RTC document available in the docket.
A. Major Comments Concerning Storage Vessels
The EPA received numerous comments on the proposed amendments to
the definition of ``maximum average daily throughput,'' which is key in
the determination of storage vessel affected facility status under the
2016 NSPS subpart OOOOa. Many of the comments we received were related
to manifolded storage vessel systems. The EPA considered those comments
and is finalizing changes to the rule to address a subset of these
manifolded storage vessel systems (i.e., controlled storage vessel
batteries as described in section V.A of this preamble). A more
detailed summary of the comments regarding controlled storage vessel
batteries, and our responses to those comments, is available in the RTC
document for this action (see Chapter 6).\68\
---------------------------------------------------------------------------
\68\ See Chapter 6 of the RTC document located at Docket ID No.
EPA-HQ-OAR-2017-0483.
---------------------------------------------------------------------------
In addition to the comments the EPA received on controlled storage
vessel batteries, we also received other comments related to storage
vessel applicability determination criteria. Below is a discussion
related to three of these topics: (1) The use of legally and
practicably enforceable limits that maintain VOC emissions from storage
vessels below 6 tpy, (2) the calculation of maximum average daily
throughput based only on the days of actual production in the first 30
days, and (3) the determination of maximum average daily throughput for
storage vessels at gathering and boosting compressor stations, onshore
natural gas processing plants, and transmission and storage compressor
stations.
Comment: Some commenters stated that the EPA proposed additional
parameters on what constitutes a ``legally and practicably
enforceable'' limit; and, therefore, heightened the standard for
allowing use of such limit in estimating a storage vessel's potential
VOC emissions for purposes of determining applicability of the storage
vessel standards at 40 CFR 60.5395a. Specifically, the commenters took
issue with the statement in the preamble to the October 15, 2018,
proposed rulemaking where the EPA stated ``only limits that meet
certain enforceability criteria may be used to restrict a source's
potential to emit, and the permit or requirement must include
sufficient compliance assurance terms and conditions such that the
source cannot lawfully exceed the limit.'' 83 FR 52085. One commenter
claimed that these additional criteria (1) conflict with prior EPA
statements made during earlier oil and gas NSPS rulemakings; (2)
conflict with the EPA's traditional practice of deferring to states
regarding the appropriate mechanisms for limiting potential to emit
(PTE); (3) raise concerns about how this new interpretation/approach
would apply in the title V and New Source Review/Prevention of
Significant Deterioration context where operators are relying on the
same control requirements to limit their PTE; (4) raise significant
concerns about retroactive application; and (5) ignore that the
requirements for fugitive components under the 2016 NSPS subpart OOOOa
are not tied to storage tank applicability and apply regardless of
whether a storage tank is an affected facility under the rule.
Commenters also cited the EPA's ``enforceability criteria''
guidance, which was first introduced in 1995, and asserted that the
EPA's proposed additional criteria were not consistent with that
guidance. One commenter was concerned that the EPA's proposal not only
conflicted with the Agency's traditional and consistent practice, it
also threatened to subject sources to the NSPS that already determined
their potential for VOC emissions was below the 6 tpy threshold by
using the EPA's prior guidance.
Response: The EPA disagrees with the commenters because we did not
propose additional parameters on what would constitute a legally and
practicably enforceable limit. Rather, in the proposal preamble, the
EPA simply summarized its position on this matter based on the existing
substantial body of EPA guidance and administrative
[[Page 57426]]
decisions relating to potential emissions and emissions limits. As the
EPA explained, limits that meet certain enforceability criteria may be
used to restrict a source's potential emissions. For example, any such
emission limit must be enforceable as a practical matter, which
requires that the permit or requirement specifies how emissions will be
measured or determined for purposes of demonstrating compliance with
the limit. The permit or requirement must also include sufficient terms
and conditions such that the source cannot lawfully exceed the limit
(e.g., monitoring, recordkeeping, and reporting). For additional
information and a summary of the EPA's position on establishing legally
and practicably enforceable limits on potential emissions, including
examples of ``enforceability criteria,'' see In the Matter of Yuhuang
Chemical Inc. Methanol Plant St. James Parish, Louisiana, Order on
Petition No. VI-2015-03 (August 31, 2016) at 13-15.
Comment: Under the 2016 NSPS subpart OOOOa, the applicability of
the storage vessel standards is based on a single storage vessel's
potential for VOC emissions, which is calculated using the storage
vessel's ``maximum average daily throughput.'' While ``maximum average
daily throughput'' is defined in 40 CFR 60.5430a of the 2016 NSPS
subpart OOOOa, several stakeholders indicated that clarification of
this definition was needed. As a result, the EPA proposed a revised
definition. 83 FR 52106. The EPA received several comments related to
the proposed definition, which requires that ``production to a single
storage vessel must be averaged over the number of days production was
actually sent to that storage vessel.'' Most of the commenters objected
to this proposed definition, claiming that it would be more appropriate
to average over the entire 30-day evaluation period rather than only
those days when production was sent to the storage vessel. With regard
to tank batteries, one commenter asserted that the proposed definition
would not result in an accurate estimate of the potential emissions
from individual storage vessels because it would overestimate the total
amount of production that each tank could receive over the 30-day
evaluation period. Further, the commenter stated that the proposed
definition would significantly overestimate the volume of flow to the
tank battery as a whole when compounded across multiple tanks and
extrapolated across an entire year. Multiple commenters also generally
stated that the EPA's proposed definition failed to account for the
fact that maximum well production has a limit based on what the wells
can produce. However, the EPA did receive one comment that agreed with
the proposed definition and that owners and operators should not be
able to include days where the storage vessel does not receive
production when determining storage vessel applicability.
Response: The EPA disagrees with the comments suggesting that
``maximum average daily throughput'' should be determined by averaging
across the full 30-day evaluation period instead of the days when
production is actually sent to an individual storage vessel during that
period. As stated in the proposal, the maximum average daily throughput
``was intended to represent the maximum of the average daily production
rates in the first 30-day period to each individual storage vessel,''
83 FR 52084, which is not the same as an average daily production rate
based on averaging total production across a full 30-day period. As
explained further in the proposal, in all possible scenarios for
determining the daily production, only the number of days in which
production is sent to the individual storage vessel is used for
averaging, which may be less than the full 30 days in the evaluation
period. Indeed, including days where no production was received would
reduce the maximum average daily throughput to an individual storage
vessel under any of the scenarios described in the proposal. 83 FR
52084. The commenters did not explain how averaging actual throughput
to a storage vessel across the full 30 days would accurately reflect
the ``maximum average daily production rates,'' therefore, we do not
agree with the commenters' suggestion to use this value for the purpose
of determining a storage vessel's potential for VOC emissions.
The EPA also disagrees with comments suggesting that the EPA's
proposed definition would overestimate the potential for VOC emissions
for individual storage vessels in a tank battery by failing to account
for the overall production to the tank battery during the 30-day
period. In addition to the definition of ``maximum average daily
throughput'' which provided for two operational scenarios, the EPA
further explained in the proposal how to determine the daily or average
daily throughput, from which the maximum average daily throughput is
determined, depending on how throughput is measured. 83 FR 52084. The
EPA's proposed definition is based on either the daily (i.e., directly
measured via automated level gauging or daily manual gauging) or
average daily (i.e., manual gauging at the start and end of loadouts
which occur over more than one day) throughput routed to a storage
vessel while receiving production; the fact that the storage vessel is
receiving that amount daily clearly indicates that it has the potential
to do so. The total throughput to the entire tank battery during the
30-day period is not germane to this determination. Because there are
likely multiple daily throughput or average daily throughput values for
an individual storage vessel during the 30-day evaluation period, the
maximum of those values is used to calculate the potential for VOC
emissions, thus, the use of the term ``maximum average daily
throughput.''
While the EPA is finalizing the definition of ``maximum average
daily throughput'' as proposed, we note that the final rule provides
other mechanisms for determining a storage vessel's applicability
without having to calculate the maximum average daily throughput.
Specifically, the final rule allows owners and operators of controlled
tank batteries meeting specified criteria to average VOC emissions
across the number of storage vessels in the tank battery to determine
applicability for the individual storage vessels in the battery. Also,
as provided in the 2016 NSPS subpart OOOOa, and unchanged by this final
rule, if a facility has a legally and practicably enforceable limit
that restricts production to an individual storage vessel, then it is
acceptable to use this restricted production level as the maximum
average daily throughput for that individual storage vessel.
Comment: Commenters stated that the methods for determining the
potential for VOC emissions from storage vessels in the 2016 NSPS
subpart OOOOa were not appropriate for storage vessels located at
compressor stations (including gathering and boosting compressor
stations) and onshore natural gas processing plants, and they indicated
that the proposed revisions to 40 CFR 60.5365a(e) and the definition of
maximum average daily throughput did not alleviate this problem. More
specifically, commenters noted that the 2016 NSPS subpart OOOOa is
clear that storage vessels at well sites must determine the potential
for VOC emissions based on the maximum average daily throughput based
on the first 30 days that liquids are sent to the storage vessel. The
commenter noted that storage vessels at compressor stations and onshore
natural gas processing plants are designed to receive liquids from
multiple well sites that may start up production over a
[[Page 57427]]
longer period of time. Because these storage vessels may not experience
the same peak in throughput to the storage vessels during the first 30-
days of receiving liquids as storage vessels at well sites, the
commenter indicated that owners or operators may underestimate the
potential emissions using the throughput for the first 30 days.
Therefore, commenters requested that the EPA clarify the appropriate
time period for calculating the maximum average daily throughput for
storage vessels at facilities located downstream of well sites.
Alternatively, commenters suggested that storage vessels at gathering
and boosting compressor stations be allowed to use generally accepted
engineering models that project future throughput. The commenters
explained that compressor stations (including gathering and boosting
compressor stations) and onshore natural gas processing plants
typically utilize process simulations based on representative or actual
liquid analysis to determine potential VOC emissions and volumetric
condensate rates from the storage vessels based on the maximum gas
throughput capacity of each facility. These generally accepted
engineering models and calculation methodologies are then utilized to
obtain Federal, state, local, or tribal authority issued permits to set
legally and practicably enforceable limits to maintain potential VOC
emissions from storage vessels at less than 6 tpy. The commenter
requested that the EPA allow use of these generally accepted models and
calculation methodologies to project future maximum throughput volumes.
Response: The EPA agrees with these commenters that potential VOC
emissions from storage vessels at facilities downstream of well sites
should not be determined based on the first 30 days that liquids are
sent to those storage vessels as they are unlikely to experience the
same peak in throughput during that period as storage vessels at well
sites. It is the EPA's understanding, based on the information provided
by the commenters and subsequent conversations,\69\ that these
midstream and downstream storage vessels may continue to see an
increase in throughput as additional upstream well sites begin sending
fluids to these compressor stations and onshore natural gas processing
plants. Based on the EPA's review and understanding of the generally
accepted engineering models for projecting future throughput to a
storage vessel, the EPA agrees that these engineering models are
appropriate for projecting the maximum throughput for purposes of
calculating the potential for VOC emissions from storage vessels
located downstream of well sites.
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\69\ See memorandum for ``May 1, 2019 Meeting with GPA
Midstream,'' located at Docket ID No. EPA-HQ-OAR-2017-0483.
---------------------------------------------------------------------------
Based on the above reasons, the EPA is amending the 2016 NSPS
subpart OOOOa to specifically provide the following two options for
determining the potential for VOC emissions from storage vessels at
facilities downstream of well sites. The first option, which is already
allowed in the 2016 NSPS subpart OOOOa, allows owners or operators to
take into account throughput and/or emission limits incorporated as
legally and practicably enforceable limits in a permit or other
requirement established under a Federal, state, local, or tribal
authority. The second option allows the use of generally accepted
engineering models (e.g., volumetric condensate rates from the storage
vessels based on the maximum gas throughput capacity of each producing
facility) to project the maximum throughput used to calculate the
potential for VOC emissions.
B. Major Comments Concerning Fugitive Emissions at Well Sites and
Compressor Stations
In section V.B of this preamble, we discuss the significant changes
from the proposal to this final rule related to the fugitive emissions
requirements for well sites and compressor stations. The discussions in
section V.B of this preamble include a summary of the major comments
and our responses related to those changes. Specifically, section V.B
of this preamble discusses the following topics: (1) The three areas of
uncertainty potentially affecting the cost-effectiveness analysis that
were identified in the October 15, 2018, proposal; (2) recordkeeping,
reporting, and other administrative burden from the fugitive emissions
requirements; (3) other updates to the model plants; and (4) cost
effectiveness of fugitive emissions requirements. We also discuss our
re-evaluation of BSER after consideration of all these topics.
In addition to the topics discussed in section V.B of this
preamble, the EPA received comments on other aspects related to the
fugitive emissions requirements. This section provides a discussion of
comments and our responses regarding the following three topics: (1)
The EPA's model plant analysis for low production well sites; (2) the
effect of system pressure on fugitive emissions at low production well
sites; and (3) monitoring of compressors at compressor stations when
operating and not in standby mode. More detailed summaries and
additional comments on the fugitive emissions requirements are included
in Chapter 8 of the RTC document included in the rulemaking docket for
this action.
Comment: The EPA created model plants representing low production
well sites for purposes of analyzing the emissions and costs of a
fugitive emissions monitoring and repair program at these types of well
sites. In the proposal, we also acknowledged that operating pressures
and production volumes are factors that can cause changes in the
fugitive emissions at a well site. 83 FR 52067. However, the EPA was
unable to incorporate these factors into the emission estimates in the
model plants, and, therefore, developed model plants that relied on
equipment and component counts to analyze fugitive emissions from low
production well sites.
Some industry commenters disagreed with the use of model plants
that rely on component counts alone to estimate fugitive emissions from
low production wells due to differences in the type and size of
equipment and operating conditions (e.g., operating pressure) at low
production well sites. The commenters did agree that it is reasonable
to associate the number of components to the potential for leaks.
However, the commenters continued to maintain that emissions from low
production wells are inherently different from large production wells
because of the basic physics of production and how operators change the
physical equipment as production warrants. Commenters indicated that
the fugitive emissions factors used by the EPA, which were developed
for generally predicting emission levels, account for different types
of fugitive emission components, but do not factor in the amount of
production or line pressure.
Response: As stated in the proposal, the EPA continues to recognize
that variations in equipment, operating conditions, and geological
aspects across the country at low production well sites may affect
fugitive emissions from low production well sites. As described in
section V.B of this preamble, we have made updates to the low
production well site model plants and re-evaluated the emissions and
costs of fugitive emissions monitoring and repair requirements at low
production well sites. Based on this updated analysis, the EPA
concludes that fugitive emissions monitoring and repair is not cost
effective at any monitoring frequency for low
[[Page 57428]]
production well sites. See section V.B of this preamble for additional
discussion.
Comment: The EPA received additional comments and data related to
the low production well site model plants developed and analyzed for
the proposal. One commenter conducted a brief survey of its member
companies' gas well site operations in 13 states and provided low
production well site component counts. This commenter pointed out that
the majority of emissions (around 80 percent) from the low production
well site model plants are from valves and storage vessel thief
hatches. Therefore, the commenter only provided counts of these
components, along with the number of wellheads. This commenter
explained that the data show fewer wellheads and valves than assumed in
the proposal model plant for low production gas well sites. The
commenter stated that it did not consider the data to be fully
representative of low production well sites nationwide; nevertheless,
relying on the difference in component counts, the commenter claimed
that the EPA overestimated the fugitive emissions in the low production
model plants used for the proposal.
Response: While the commenter specifically stated that it did not
consider the data to be fully representative of low production well
sites nationwide, we reviewed the information and compared it to the
low production well site model plants used for the proposal analysis.
Specifically, we compared the weighted-average component counts of the
information provided by the commenter to the EPA's low production well
site model plant. The information provided by the commenter showed that
the weighted-average number of storage vessels was approximately the
same as that used in the EPA model plant, the number of well heads was
half (one versus two in the EPA model plant), and the number of valves
was just under 25 percent (23 versus 100 in the EPA model plant). If
the model plant was modified with these adjusted component counts, the
overall difference in emissions would be just over 50 percent.
After consideration of this information, the EPA concluded it
provides an insufficient basis to revise the low production well site
model plant component counts because the information was limited to
valves, connectors, and storage vessels at a sample of sites the
commenter admitted were not fully representative of low production well
sites. However, as discussed above in section V.B of this preamble, we
did conduct further review of the data originally used to develop the
model plant parameters, as well as GHGI data. That review resulted in a
35-percent decrease in the number of valves for the low production gas
well site model plant, as well as decreases in the numbers of the other
components. More detailed information on our analysis of the component
count information submitted by commenters is contained in a technical
memorandum.\70\ As shown in the revised model plant analysis, a
fugitive emissions monitoring program is not cost effective for low
production well sites at any of the frequencies analyzed.
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\70\ Memorandum. ``Summary of Data Received on the October 15,
2018 Proposed Amendments to 40 CFR Part 60, subpart OOOOa Related to
Model Plant Fugitive Emissions.'' February 10, 2020.
---------------------------------------------------------------------------
Comment: The EPA proposed defining low production well sites as
sites where the average combined oil and natural gas production for the
wells at the site is at or below 15 boe per day averaged over the first
30 days of production. 83 FR 52093. Several commenters recommended
changing the definition of a low production well site to be based on
the U.S. Tax Code definition of stripper wells. These commenters also
recommended using 12 months of production to determine if a site is low
production because most well sites newly affected by NSPS subpart OOOOa
will not meet the definition based on the first 30 days of production
and because production declines over time such that eventually all well
sites become low production.
Response: The EPA has not adopted the stripper well definition for
purposes of determining if a well site is low production in this action
because the U.S. Tax Code definition applies to individual wells, not
well sites. The fugitive emissions standards apply to the collection of
fugitive emissions components located at a well site. Adoption of the
stripper well definition could result in a scenario where one well at
the site is considered low production but the other wells are not,
which is inconsistent with the affected facility definition for
fugitive emissions components, where the entire site is treated as one
unit. Therefore, the calculation of production for purposes of
determining if the well site is low production is based on the total
well site production and not the individual well production averaged
across the number of wells at the well site.
However, the EPA does agree with the commenters that determination
of low production status based solely on the first 30 days of
production does not account for decline in production over time.
Therefore, the final rule specifies that a low production well site is
a well site with total well site production of oil and natural gas at
or below 15 boe per day. This calculation can be based on the first 30
days of production for determining initial applicability to the rule
and based on a rolling 12-month average to account for production
decline. See section V.B of this preamble for additional discussion.
Comment: Commenters urged the EPA to use the Department of Energy
(DOE) research program \71\ announced on October 23, 2018, to determine
more accurate assessments of low production well emissions. The
commenters asserted that the DOE study provides the EPA the opportunity
to collect direct emissions data on fugitive emissions at low
production well sites. The commenters concluded that these data would
provide the EPA with a baseline that shows the distinctions between
large wells and low production wells and the differences that may exist
between types of wells and between production regions.
---------------------------------------------------------------------------
\71\ https://www.netl.doe.gov/node/5775.
---------------------------------------------------------------------------
Response: The EPA is regularly updated on the DOE program and
provides technical input on many projects. However, data from the DOE-
funded study on low production wells are not currently available. The
conclusions made in this final rule are based on currently available
information, which includes many data sources that cover low production
wells, such as DrillingInfo, Greenhouse Gas Reporting Program, and
other emission measurement studies. As discussed in this section and in
section V.B of this preamble, the EPA agrees that existing information
shows that low production well sites may have lower emissions than well
sites with higher production. As such, the final rule has separate
requirements for well sites with total production at or below 15 boe
per day, instead of the required fugitive emissions monitoring program
(including semiannual monitoring) for well sites above this production
threshold.
Comment: In addition to co-proposing annual monitoring of fugitive
emissions components located at a compressor station, the EPA proposed
a requirement that each compressor at the station must be monitored at
least once per calendar year when it is operating. The EPA also
solicited comment regarding the effect the compressor operating mode
has on fugitive emissions and the proposal to require at least one
monitoring a year during times that are representative of operating
conditions for the compressor station.
[[Page 57429]]
Several industry commenters opposed the EPA's proposal to require
that each compressor be monitored while in operation (i.e., not in
stand[hyphen]by mode), because if the station is subject to annual
monitoring (which was co-proposed), this requirement would result in a
requirement for every compressor to be operating during the monitoring
survey, even if all of the compressors are not needed at that time to
move gas downstream. The commenters believed that the result of this
requirement would be the generation of emissions from compressor
blowdowns following the monitoring survey in order to return the
compressors to the operating modes they were in prior to the survey.
The requirement would also create unnecessary recordkeeping and
scheduling complexity/burden, according to commenters. Requiring
equipment to be monitored in a specific mode of operation, especially
at less frequent monitoring than quarterly, would increase overall
emissions if that equipment must change its operational status solely
to fulfill that requirement. These commenters recommended that the EPA
allow operators to conduct surveys with facility operations as they are
found when the survey is conducted.
However, another commenter stated that its data suggests that it is
important to conduct monitoring on fully operating compressors to
maximize the number of leaks detected. The commenter stated that beyond
these data, it is also simply common sense that as the ratio of
pressurized to depressurized components increases, so will the number
of leaks detected (depressurized components do not leak). One of the
problems is that operation modes vary seasonally at each compressor
station, and within each compressor station, the operating modes of
each unit can vary daily based on demand. The commenter asserted that
the current quarterly compressor monitoring frequency creates a higher
probability of conducting a survey where each compressor is monitored
in a pressurized mode at least once per year. If the EPA moved to less
frequent monitoring, the commenter recommended that there should be
some condition to ensure that a reasonable effort is made to schedule
the surveys during a time of peak operation.
Response: The EPA reviewed the input provided by the commenters.
While we agree with the one commenter that the opportunity for fugitive
emissions is greater when a compressor is pressurized and operating,
the EPA is not finalizing the proposed requirement that each compressor
must be monitored while in operation (i.e., not in stand-by mode) at
least annually. The EPA has specified in the final rule that the
monitoring survey of fugitive emissions components at a gathering and
boosting compressor station is semiannual after the initial survey and
subsequent semiannual monitoring surveys must be conducted at least
every 4 to 7 months. Therefore, as pointed out by the commenter, the
likelihood that all monitoring events in a year will be when a specific
individual compressor is not operating is relatively low. For the
reason stated above, this final rule does not require monitoring of
each individual compressor at the station while it is in operation
(i.e., not in stand-by mode) at least once per calendar year.
However, the EPA does conclude that it is important that the
operating mode during the monitoring survey be recorded. While we would
not expect that owners or operators would modify their operating
schedules to avoid monitoring when the compressor is operating, or that
they would purposely schedule every monitoring event during shutdown
periods, we believe that this record would inform the Agency if this
were occurring and, if so, how often. This information will provide
valuable points for future analyses on leak rates and operating modes.
Therefore, the final rule requires that owners and operators keep a
record of the operating mode of each compressor at the time of the
monitoring survey.
C. Major Comments Concerning AMELs
1. Emerging Technologies
The EPA received comments related to AMELs for emerging
technologies on several topics. The comments received by the EPA that
resulted in significant rule changes are discussed in section V.C.1 of
this preamble, along with our response and rationale for the changes.
The specific topics were (1) who can submit an AMEL application, (2)
what data can or must be included in an AMEL application, and (3) what
broader applications of alternatives are permitted. Further details on
comments related to the broader applications of AMEL technology,
specifically on the issues of applying AMEL to multiple similar sites
or to categories of sources, are provided below along with the EPA's
responses. Other comments, and more detailed comments covering the
topics discussed in this preamble related to emerging technologies can
be found in the RTC document available in the docket, along with EPA's
responses.
Comment: In the proposal, the EPA reiterated its position that AMEL
approvals would be made on a site-specific basis but noted that
applicants could include multiple sites within one application as
necessary. Many commenters disagreed with that proposal, stating that
the EPA should allow approved AMELs to apply more broadly to multiple
sites, basin-wide, industry-wide, or even based on nation-wide
efficacy. Commenters asserted that restricting AMEL approval to a
specific site is inconsistent with the EPA's past practice for OGI, in
which the EPA determined that OGI achieves emission reductions
equivalent to Method 21 for several industries and source categories in
a single rulemaking.\72\ Some commenters feared that the site-specific
approval process that includes Federal Register notice and comment
requirements is so onerous that it will stifle innovation in new
technology, and another noted that its customers have indicated that
they would not apply for an AMEL if approval is site-specific.
Commenters pointed out that the site-specific approval process could
create a crush of AMEL applications for hundreds or thousands of sites,
but the applications would be limited to only the technologies
previously approved or most likely to be approved as AMEL.
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\72\ See the Alternative Work Practice located at 40 CFR
60.18(g), (h), and (i).
---------------------------------------------------------------------------
In response to the EPA's concern that alternative technologies may
need to be adjusted for site-specific conditions, such as gas
compositions, allowable emissions, or the landscape, several commenters
suggested that the EPA could account for factors affecting variability,
such as the weather or landscaping, by imposing conditions for the use
of the technology and/or require periodic instrument checks,
calibration records, or other actions to ensure equivalent emission
reductions are achieved within the approved AMEL. The commenters also
noted that if there is concern about allowable emissions impacting the
usability of a particular technology, that technology may only be
approvable for use as an approach to direct inspection efforts, but
this factor would not affect the ability for it to be approved for that
use at multiple sites.
Response: The EPA does not seek to stifle innovation of emerging
technologies. In fact, the Agency is actively involved in many multi-
stakeholder groups aimed at developing frameworks and criteria that
will promote the development of possible alternatives. As such, the EPA
strongly encourages interested parties to discuss possible alternatives
with the Agency.
[[Page 57430]]
However, the EPA disagrees that this final rule should be the vehicle
used to make determinations about any particular technology because the
proposed rulemaking did not evaluate any specific technology. The EPA
also disagrees that this rule is inconsistent with the EPA's past
practice for OGI, in which the EPA allowed the use of OGI as an
alternative to Method 21 for several industries and source categories
in a single rulemaking.\73\ The EPA notes that while the AMEL process
provided for in CAA section 111(h)(3) contains elements similar to a
rulemaking (such as notice and opportunity for public hearing),
approval of an alternative does not always require rulemaking. If a
technology is developed that could be broadly applied to oil and gas
sites as an alternative to what is required in NSPS subpart OOOOa, it
may be more appropriate to incorporate such a technology into the rule
through a formal rulemaking process so that every affected facility can
make use of that alternative.
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\73\ See 40 CFR 60.18(g), (h), and (i).
---------------------------------------------------------------------------
As discussed in section V.C.1 of this preamble, the EPA agrees that
in some circumstances, it may be appropriate to apply an approved AMEL
to multiple sites, including future sites. If the applicant of an AMEL
believes that it is appropriate to apply the alternative to more sites
than those listed in the application, the applicant should specify this
within the application and provide any characteristics or variables
that are applicable to the type of sites where the equivalency
demonstration is being made. Specifically, the applicant should provide
relevant information, including any specific conditions (e.g.,
technology-specific variables that affect performance), procedures
(e.g., specific work practice that will be followed to identify
emissions and make repairs), or site characteristics under which the
alternative must be applied (e.g., formation variables, site operating
conditions, equipment at the site, etc.), to demonstrate equivalence
with the emissions reductions that would be achieved under the
requirements of the NSPS. The EPA will evaluate these defined
conditions and additional conditions, if any, under which it might be
appropriate to allow future use of the alternative once approved via
the AMEL process. For example, the EPA might approve the use of a
specific fugitive emissions detection technology that operates with the
same performance under specific work practice requirements,
environmental conditions, and site configurations and operations. In
that example, the EPA might determine it is appropriate to approve the
AMEL and define the specific parameters (e.g., environmental
conditions, site configurations, and operations) within the approval to
allow the use of that alternative at sites meeting those same
conditions without the need for additional future application to the
EPA. However, each of these determinations would necessarily be made on
a case-by-case basis provided the application contains all necessary
information to make such a broad determination for applicability of the
AMEL. Given that these determinations are made on facts and showings
that are specific to each proposed alternative, the EPA has determined
that the best course forward is for an applicant to submit an
application seeking a broadly applicable AMEL and for the Agency to
then use its evaluation of that application as a template for future
applications, thereby streamlining the process.
Comment: Several commenters stated that the EPA should approve the
use of alternative technologies under the Agencies' AMEL authority for
broad categories of sources subject to NSPS subpart OOOOa, such as
fugitive emissions components across multiple sites. They remarked that
there is nothing in the statute that requires the EPA to set source-
specific AMELs, and the EPA's position regarding the necessity of
source-by-source applications and approvals for AMEL is incorrectly
taken from a narrow reading of the language of CAA section 111(h)(3).
The commenters stated that, while the language of CAA section 111(h)(3)
provides that an AMEL is permitted to be used ``by the source'' for
purposes of compliance, the EPA's reading of this provision to disallow
the granting of AMEL for use by multiple sources is inconsistent with
the NSPS approach of developing standards for whole categories of
sources.
Some commenters said that because an AMEL will serve as a
replacement for a category-wide CAA section 111(h)(1) standard, a
demonstration that an AMEL will achieve an emission reduction at least
equivalent to a CAA section 111(h)(1) standard could be made on a
category-wide basis and be applied to an entire source category. These
commenters suggested that allowing for source category-wide AMEL
determinations would be consistent with the overall structure of CAA
section 111 and its focus on category-wide standards under CAA sections
111(b) and (h)(1) and with the limitation prohibiting the EPA from
imposing specific technological emission reduction requirements
pursuant to CAA section 111(b)(5).
These commenters further stated that the EPA's regulation
implementing CAA section 112(h)(3) recognizes that the EPA is
authorized to approve an AMEL for ``source(s) or category(ies) of
sources on which the alternative means will achieve equivalent emission
reductions.'' \74\ They contended that, given the similarities between
the programs authorized under CAA section 111 and CAA section 112, and
particularly the similarity of CAA sections 111(h)(3) and 112(h)(3),
the EPA should adopt a policy of applying an AMEL to source categories
for CAA section 111(h)(3) in the same manner as it has done with
respect to CAA section 112(h)(3). They noted that in other rules, such
as the visibility provisions that require the best available retrofit
technology (BART), the EPA's rules allow the EPA and the states to
authorize BART alternatives that can apply to groups of sources and
that allow emission averaging across sources, even over wide regions,
rather than imposing source-specific emission limits or source-specific
alternatives to such limits. The commenters stated that if alternatives
to emission limits (or work practice standards) for groups of sources
under these provisions are permissible despite the continued references
to the term ``source'' in the statutory language, then a source
category-wide AMEL is surely permissible under CAA section 111(h)(3).
---------------------------------------------------------------------------
\74\ See 40 CFR 63.6(g)(1).
---------------------------------------------------------------------------
Response: On the first point raised by commenters, and as explained
in the EPA's response above, the EPA agrees that in some instances
broad use of an approved alternative may be appropriate. The current
construct of the AMEL application process in NSPS subpart OOOOa does
not prevent the EPA from taking this path as suggested by the
commenters.
The commenters also suggest that the EPA should apply AMEL to a
source category in the same manner in which the EPA has done for
applications submitted through section 112(h)(3) of the CAA. While the
EPA has approved AMEL for sources subject to standards under section
112 of the CAA, these approvals have been made on a site-specific
basis, in which each application specifically lists the facilities that
are applying for approval. Further, while similar, CAA section
112(h)(3) does not apply for purposes of demonstrating equivalence with
work practice standards in the NSPS.
[[Page 57431]]
For purposes of evaluating whether an alternative to fugitives
monitoring provides at least equivalent emission reductions as the
applicable standards in the context of NSPS subpart OOOOa, the EPA
asserts that the emissions from an individual site are the only
appropriate measure for comparison. First, the BSER determination for
the collection of fugitive emissions components is based on a single
well site, or a single compressor station, not a collection of well
sites and/or compressor stations, and not the emissions of the entire
source category. The source category for which NSPS subpart OOOOa sets
standards of performance under CAA section 111 is the Crude Oil and
Natural Gas Production source category. This category is defined in 40
CFR 60.5430a as crude oil production, which includes the well and
extends to the point of custody transfer to the crude oil transmission
pipeline or any other forms of transportation; and natural gas
production and processing, which includes the well and extend to, but
does not include, the point of custody transfer to the natural gas
transmission and storage segment.\75\ Within this source category, the
EPA has set standards of performance (BSER) for individual affected
facilities. These affected facilities are the only emission sources
within the Crude Oil and Natural Gas Production source category for
which these NSPS apply and are defined in 40 CFR 60.5365a.
---------------------------------------------------------------------------
\75\ See the Review Rule published in the Federal Register of
Monday, September 14, 2020 and supporting information located at
Docket ID No. EPA-HQ-OAR-2017-0757.
---------------------------------------------------------------------------
Specifically, the EPA has defined the collection of fugitive
emissions components at a well site and the collection of fugitive
emissions components at a compressor station as individual affected
facilities in the rule. Affected facilities are defined at the
individual site level, and not as the collection of fugitive emissions
components across multiple sites, or a collection of sources within a
basin. Further, the standards that apply to these affected facilities
are specific to the individual well site or compressor station, as
defined in 40 CFR 60.5365a(i) and (j) and 40 CFR 60.5397a. For example,
the collection of fugitive emissions components at an existing well
site become subject to the fugitive emissions requirements when (1) a
new well is drilled at that well site, (2) an existing well at that
well site is hydraulically fractured, or (3) an existing well at that
well site is hydraulically refractured. In all three cases, the event
that triggers the requirements for an existing well site are based on
site-specific changes, and not changes at other nearby sites. Drilling
a new well at a well site within the same basin, for instance, does not
trigger the fugitive emissions requirements for all well sites located
in that basin.
When establishing the requirements for the collection of fugitive
emissions components, the EPA limited the applicability to individual
well sites or compressor stations. The work practice standards set in
accordance with section 111(h)(1) of the CAA were established for the
collection of fugitive emissions components at an individual well site
or compressor station. Since the NSPS does not define the emission
source subject to BSER as a basin, or other aggregation of emission
points, the EPA finds it inappropriate to evaluate alternatives that
seek to implement such a definition. As a practical matter, the EPA
concludes that any determination of equivalent emission reductions
through an AMEL under section 111(h)(3), or for an alternative work
practice under section 111(h)(1), of the CAA for these NSPS should be
determined at the same affected facility level (i.e., collection of
fugitive emissions components at a well site or at a compressor
station) as the original work practice standards.
Similar to the EPA's explanation in the Affordable Clean Energy
rule (``ACE''), here the EPA does not need to determine whether it
would have reasonable grounds to define ``source'' for purposes of the
fugitive emissions monitoring work practice standard as a geographic
area, such as a basin. Because these NSPS define an affected facility
for this purpose as the collection of fugitive emissions components at
a well site, and the collection of fugitive emissions components at a
compressor station, the EPA does not think it is appropriate for AMEL
applications to accommodate the averaging of emissions.\76\
---------------------------------------------------------------------------
\76\ See 81 FR 32520, 32556 and 57 (July 8, 2019) (section
titled ``Averaging and Trading'').
---------------------------------------------------------------------------
Second, it is unclear whether the commenters are suggesting that
such aggregation would take into account emissions from sources within
a basin not subject to these NSPS, such as existing oil and gas well
sites or compressor stations, or sources that emit VOC that are
included in a different source category. In response to this point, the
EPA directs commenters to the discussion of CAA section 111, generation
shifting, and emission offsets included in ACE.\77\ ``[T]he plain
language of CAA section 111 does not authorize the EPA to select as the
BSER a system that is premised on application to the source category as
a whole or to entities entirely outside the regulated source
category.'' \78\ This principle also applies in the context of
evaluating alternatives to the established BSER.
---------------------------------------------------------------------------
\77\ Id. at 32523-26.
\78\ Id. at 32524.
---------------------------------------------------------------------------
Lastly, commenters suggest that averaging should be appropriate
here because the EPA allows averaging in its BART program. However,
that comparison is not appropriate because it fails to consider
differences between BART and the BSER for this NSPS. The BART
requirement is just one component of a larger strategy to make
reasonable progress towards the national goal of remedying visibility
impairment in certain areas. The EPA determined in the BART context
that if a state can demonstrate that an alternative strategy, such as
an emissions trading scheme, will be even more effective at improving
visibility, such a ``better-than-BART'' strategy may be adopted to
fulfill the role that would otherwise by filled by BART. However, in
the context of this NSPS there is less flexibility on this point than
in the BART program because, as explained above, there are no other
components to reducing emissions aside from the BSER, the BSER is not
based on reasonable progress, and this NSPS does not define the
emission source subject to BSER as a basin or other aggregation of
emission points.
2. State Fugitive Emissions Programs
The EPA received comments related to the alternative fugitive
emissions standards on several topics. The comments received by the EPA
that resulted in significant rule changes are discussed in section
V.C.2 of this preamble, along with our response and rationale for the
changes. Specifically, these topics were related to whether the state
regulations/requirements determined to be alternative fugitive
standards to NSPS subpart OOOOa fugitive requirements will provide
adequate coverage of the emission sources in the state and the
potential for duplicative reporting and recordkeeping requirements.
Further details on comments related to these topics are provided below,
along with other significant comments and the EPA's responses. Other
comments, and more detailed comments covering the topics discussed in
this preamble, related to the state fugitive monitoring programs can be
found in the RTC document
[[Page 57432]]
available in the docket, along with the EPA's responses.
Comment: The EPA proposed alternative fugitive emissions standards
based on our determination that certain states had existing
requirements equivalent to the proposed fugitive emissions
requirements. These determinations were based on qualitative
assessments comparing various aspects of the requirements, such as
monitoring frequencies and repair deadlines. Two commenters stated that
the equivalency determinations must be quantitative if the EPA wants to
set alternative standards because they are similar to AMELs. The
commenters indicated that the Agency's analysis evaluated whether a
state has regulations that are similar to the EPA's regulations, rather
than whether the emissions reductions achieved by those regulations are
quantitatively equivalent. One of the commenters stated that the EPA's
qualitative comparison is legally insufficient because it does not meet
the statutory requirement that an applicant ``establish'' that an AMEL
``will achieve'' reductions in emissions ``at least equivalent to'' the
reduction achieved under the Federal standards.\79\ This commenter
stated that, without a quantitative comparison, it is impossible to
determine whether an AMEL will achieve at least an equivalent reduction
in pollutant emissions. The commenter further notes that past AMEL
approvals under this provision were based on detailed quantitative
determinations for each facility to determine the exact emissions
levels that would be achievable at that facility, and then those levels
were compared to the emissions levels achievable under the present
NSPS. The commenter stated that the EPA's policy changes in how
equivalency is determined are inconsistent with the requirements of
section 111(h) of the CAA and also stated that the EPA's approach of
``combining . . . aspects of the state requirements to formulate
alternatives,'' \80\ to determine equivalency is not a permissible or
reasonable approach. The commenter noted that while some aspects of a
state-level program may be more protective than the corresponding
Federal requirements, others may not be, and the commenter stated that
qualitative comparisons cannot determine the net effects of program
elements that point in opposite directions.
---------------------------------------------------------------------------
\79\ See CAA section 111(h)(3).
\80\ See 83 FR 52081.
---------------------------------------------------------------------------
Response: The EPA agrees that in some instances when the EPA is
evaluating an alternative, it would be preferable to use a quantitative
analysis, but we do not agree that such analysis is necessary or
prudent in this instance for determining the equivalency of fugitive
emissions requirements in state regulations. The CAA does not require
the EPA to conduct a quantitative analysis to evaluate an alternative
standard or to determine whether that alternative is equivalent to the
underlying standard. Work practice standards under section 111(h)(1) of
the CAA are set when ``it is not feasible to prescribe or enforce a
standard of performance.'' Section 111(h)(2) of the CAA further defines
that the phrase not feasible to prescribe or enforce a standard of
performance means any situation in which the Administrator determines
that: (A) A pollutant or pollutants cannot be emitted through a
conveyance designed and constructed to emit or capture such pollutant;
or (B) the application of measurement methodology to a particular class
of sources is not practicable due to technological or economic
limitations. Fugitive emissions are not quantified within the rule, and
the technologies used in this rule to detect fugitive emissions do not
quantify the actual emissions that are detected and then remediated
through repair. Further, even if direct quantification were possible
through the currently approved technologies, those quantified emissions
would only represent the fugitive emissions detected on that specific
day and would not offer information related to how long those emissions
were present prior to detection, or account for any emissions that
occur between monitoring surveys. Due to the fact-specific
circumstances of the work practice standard in the existing rule, it is
not practical for the EPA to conduct an accurate and meaningful
quantitative analysis of the alternatives. It is also not necessary for
the EPA to conduct a quantitative analysis. The statute does not
require a quantitative analysis. Therefore, the most practical way to
evaluate the equivalence of a fugitive emissions monitoring and repair
program is through the site-specific qualitative comparison that we
used. It is the EPA's determination that the analysis, which evaluates
the types of components monitored, the frequency of monitoring, the
detection instrument, the threshold that triggers repairs, and the
repair deadline, is sufficient and appropriate for demonstrating that
the six programs identified as alternative fugitive standards are
equivalent to the fugitive emissions requirements of NSPS subpart
OOOOa.\81\ Therefore, we have not conducted a quantitative analysis of
the individual state programs that are finalized in this action as
alternative standards.
---------------------------------------------------------------------------
\81\ See memorandum, ``Equivalency of State Fugitive Emissions
Programs for Well Sites and Compressor Stations to Final Standards
at 40 CFR part 60, subpart OOOOa,'' located at Docket ID No. EPA-HQ-
OAR-2017-0483. January 17, 2020.
---------------------------------------------------------------------------
Comment: One commenter performed its own quantitative assessment of
the state programs that the EPA proposed as equivalent to NSPS subpart
OOOOa with the October 15, 2018, proposal. From this analysis, the
commenter stated that it found differences in the applicability
thresholds for several of the state programs, which results in the
state programs (combined) covering only 34 percent of the total wells
that would be covered by the proposal or the 2016 NSPS subpart OOOOa in
these states. The commenter also stated that state programs vary in
stringency and may not reduce emissions to the same level as the EPA
standards, such as the Ohio and Texas provisions that allow for
inspection frequency to decrease based on the percentage of components
leaking. The commenter asserted that its assessment demonstrates that
both the Ohio and Texas programs reduce emissions to a lesser extent
than the proposed requirements, while California and Colorado meet the
emission reduction levels accomplished by the proposal. Overall, the
commenter said that the state programs will achieve a reduction of
methane emissions that is 36 percent less than the reduction that would
be achieved by the amendments proposed on October 15, 2018. When
compared to the 2016 NSPS subpart OOOOa requirements, the commenter
said that the state programs would result in 58 percent less emissions
reductions. The commenter remarked that these findings demonstrate that
these state programs are not equivalent to either the proposal or the
2016 NSPS subpart OOOOa. Another commenter also remarked that the
California Air Resources Board has performed a preliminary assessment
of state programs against the 2016 NSPS subpart OOOOa and found that
only the California, Colorado, Pennsylvania, Utah, and Texas programs
(within narrow parameters) are likely to be equivalent.
Response: The EPA reviewed the analysis provided by the commenter
but notes that the analysis appears to include an incorrect assumption.
Specifically, the commenter stated that only 34 percent of the wells
covered by the fugitive emissions requirements in NSPS subpart OOOOa
and that are also
[[Page 57433]]
located in one of the six states with proposed alternative fugitive
standards would actually be subject to those alternative fugitive
standards. This is not correct. The assumption by the commenter is that
the alternative standards are deficient because not all of the sites
that are currently subject to NSPS subpart OOOOa would be required to
monitor and, thus, reduce fugitive emissions. This assumption is
incorrect. The applicability criteria found in NSPS subpart OOOOa will
continue to apply regardless of the state's applicability criteria.
Using Texas as an example, the commenters stated that only 5
percent of the sites that are subject to NSPS subpart OOOOa would have
monitoring requirements under the alternative fugitive standards for
well sites located in Texas. While this percentage may represent those
sites in Texas that can utilize the alternative, this does not mean
that the other 95 percent of sites escape regulation under the NSPS. If
a well site is subject to the Texas standards, then that well site may
opt to comply with those State-level standards as an alternative to
certain Federal fugitive emissions requirements in NSPS subpart OOOOa.
However, if a well site located in Texas is not subject to the State-
level requirements and is subject to the NSPS (95 percent of the sites
according to the commenter), then the alternative standard would not be
available to that site, and monitoring would be required through the
requirements in NSPS subpart OOOOa. Put another way, the alternatives
included in this final rule do not alter the applicability criteria of
the NSPS for any sites. If a well site in Texas was required to comply
with the NSPS before the alternative was approved, then that site is
still required to comply with the NSPS, but the final rule affords
certain sites an alternative way to demonstrate that compliance with
the NSPS, if they so choose. Moreover, regardless of whether the site
complies with the fugitive emissions requirements in NSPS subpart
OOOOa, or the alternative fugitive standards for their state, they must
conduct the specific monitoring and repair for the NSPS subpart OOOOa
defined fugitive emissions components at a well site or compressor
station, as applicable.
Comment: Several commenters asserted that the EPA should recognize
the approved state programs as wholly equivalent to the fugitive
emissions requirements in the NSPS and fully delegate the
implementation of those fugitive emissions requirements to those
states, including the states' recordkeeping and reporting requirements.
The commenters noted that the EPA is requiring operators to use the
fugitive emission component definition from the 2016 NSPS subpart OOOOa
and the 2016 NSPS subpart OOOOa reporting and monitoring plan.
Two of the commenters observed that they are required to comply
with both the state requirements and Federal fugitive emissions
programs concurrently. The commenters stated that complying with two
different recordkeeping and reporting schemes for the same site is very
burdensome with no added benefit for the environment. Sites that
operate where they are subject to both the NSPS and a state program
will sometimes be required to keep two very similar sets of records to
comply with both standards. Likewise, sites in this situation may be
required to report similar overlapping information to both the Federal
system and a state system. According to commenters, this overlap in
recordkeeping and reporting (and sometimes in monitoring plans) creates
redundant work that unnecessarily consumes resources. The commenters go
on to assert that requiring the Federal reporting and monitoring plan
defeats the purpose and any benefit from the EPA approving state
programs and suggest that if a state program is not adequate in the
EPA's opinion, then the EPA should address the issue with the
individual state, so it can be approved in whole. Commenters added that
as an alternative, the EPA could require that the fugitive emissions
component definition from NSPS subpart OOOOa be used when following an
alternative standard, even if the state program definitions differ, but
the EPA should not require any duplicative administrative burden.
Further, the commenters stated that CAA Section 111 fits squarely
within the cooperative federalism tradition, with CAA section 111(c)
expressly calling on states to develop ``a procedure for implementing
and enforcing standards of performance for new sources'' and calling on
the Administrator to delegate ``any authority he has . . . to implement
and enforce such standards.'' \82\ Two commenters noted that the EPA
did not evaluate the equivalency of state reporting requirements or
monitoring plans and, thus, did not propose any alternative standards
for these aspects of the NSPS subpart OOOOa fugitive emissions
requirements. These commenters stated that the exclusion of state
reporting and monitoring plan requirements from the EPA's equivalency
evaluation leaves the regulated community in certain states subject to
potentially duplicative regulation.
---------------------------------------------------------------------------
\82\ See CAA section 111(c)(1).
---------------------------------------------------------------------------
Response: It is unclear to the EPA what commenters mean by ``wholly
equivalent'' and ``fully delegate,'' but we are providing a response
based on our interpretation that commenters are requesting approved
alternative standards only require recordkeeping and reporting to the
individual states and not to the EPA. After considering the comments
provided, the EPA reviewed the recordkeeping and reporting requirements
for each of the six states that were proposed for alternative fugitive
standards in the October 15, 2018, proposal (California, Colorado,
Ohio, Pennsylvania, Texas, and Utah). For California, Ohio, and
Pennsylvania, the EPA was able to identify site-specific reporting
requirements in the state reports which, while not identical to the
reporting for NSPS subpart OOOOa, were determined to be appropriate to
demonstrate compliance with the alternative fugitive standards for
those states. Therefore, in this final rule, we are allowing well sites
and compressor stations located in California, Ohio, and Pennsylvania
that adopt the alternative fugitive standards to electronically submit
a copy of the report that is submitted to their state as specified in
40 CFR 60.5420a(b)(7)(iii). As discussed in section V.C of this
preamble, this report must be submitted in the format in which it was
submitted to the state, noting the following order of preference: (1)
As a binary file, (2) as a XML schema, (3) as a searchable PDF, or (4)
as a scanned PDF of a hard copy.
In reviewing the reporting requirements for Colorado, we noted that
the report is a fillable form to the state that summarizes all
monitoring events for that year at the company-level. Therefore, no
site-specific information is available. We then reviewed the
recordkeeping forms for Colorado to identify what information is
required for the individual sites and compared that information to the
required annual report for NSPS subpart OOOOa. We identified one
recordkeeping element required by NSPS subpart OOOOa that was not
already included in the recordkeeping requirements for Colorado:
Deviations from certain requirements in the monitoring plan. Given that
the Federal monitoring plan, and deviations from that plan, are still
required for all sites that adopt the alternative fugitive standards,
there are no additional recordkeeping elements that would be needed
beyond what the State already requires. While the EPA has determined
[[Page 57434]]
that the Colorado program for fugitive emissions requirements is an
acceptable alternative to NSPS subpart OOOOa, the company-level reports
in Colorado are insufficient to demonstrate compliance for individual
sites. Therefore, we are still requiring that well sites and compressor
stations located in Colorado that adopt the alternative fugitive
standard must report the information required by NSPS subpart OOOOa for
fugitive emissions components at well sites and compressor stations.
Our review of the Texas reporting requirements found that sites
only report information when fugitive emissions are found. While this
may be appropriate for demonstrating compliance to the State, it is not
adequate information for the EPA to ensure compliance with the
alternative fugitive standards for well sites and compressor stations
located in Texas. Similar to Colorado, we examined the recordkeeping
requirements and found that sites located in the State are already
required by the State to keep records that facilitate the reporting
required by NSPS subpart OOOOa for fugitive emissions components at
well sites and compressor stations. Therefore, we are requiring that
well sites and compressor stations located in Texas that adopt the
alternative fugitive standards must report the information required in
NSPS subpart OOOOa.
Finally, the requirements in Utah do not include reporting. Similar
to Colorado and Texas, we reviewed the recordkeeping requirements. For
Utah, sites must keep records of the monitoring plan and the monitoring
surveys. We found these records are similar to the information that is
required in the NSPS subpart OOOOa report for fugitive emissions
components and would not require additional recordkeeping. Therefore,
we are requiring that well sites located in Utah that adopt the
alternative fugitive standards must report the information required in
NSPS subpart OOOOa.
VII. Impacts of These Final Amendments
A. What are the air impacts?
The EPA projected that, from 2021 to 2030, relative to the
baseline, the final rule will forgo about 450,000 short tons of methane
emissions reductions (10 million tons CO2 Eq.), 120,000
short tons of VOC emissions reductions, and 4,700 short tons of HAP
emission reductions from facilities affected by this reconsideration.
The EPA estimated regulatory impacts beginning in 2021 as it is the
first full year of implementation of this rule. The EPA estimated
impacts through 2030 to illustrate the accumulating effects of this
rule over a longer period. The EPA did not estimate impacts after 2030
for reasons including limited information, as explained in the RIA.
B. What are the energy impacts?
There will likely be minimal change in emissions control energy
requirements resulting from this rule. Additionally, this final action
continues to encourage the use of emission controls that recover
hydrocarbon products that can be used on-site as fuel or reprocessed
within the production process for sale. The energy impacts described in
this section are those energy requirements associated with the
operation of emission control devices. Potential impacts on the
national energy economy from the rule are discussed in the economic
impacts section.
C. What are the compliance cost reductions?
The PV of the regulatory compliance cost reduction associated with
this final rule over the 2021 to 2030 period was estimated to be $800
million (in 2016 dollars) using a 7-percent discount rate and $1.0
billion using a 3-percent discount rate. The EAV (rounded to two
significant figures) of these cost reductions is estimated to be $110
million per year using either a 7-percent or 3-percent discount rate.
These estimates do not, however, include the forgone producer
revenues associated with the decrease in the recovery of saleable
natural gas, though some of the compliance actions required in the
baseline would likely have captured saleable product that would have
otherwise been emitted to the atmosphere. Estimates of the value of the
recovered product were included in previous regulatory analyses as
offsetting compliance costs. Because of the deregulatory nature of this
final action, the EPA projected a reduction in the recovery of saleable
product. Using the 2020 Annual Energy Outlook (AEO) projection of
natural gas prices to estimate the value of the change in the recovered
gas at the wellhead projected to result from the final action, the EPA
estimated a PV of regulatory compliance cost reductions of the final
rule over the 2021 to 2030 period of $750 million using a 7-percent
discount rate and $950 million using a 3-percent discount rate. The
corresponding estimates of the EAV of cost reductions after accounting
for the forgone revenues were $100 million per year using a 7-percent
discount rate and $110 million per year using a 3-percent discount
rate.
D. What are the economic and employment impacts?
The EPA used the National Energy Modeling System (NEMS) to estimate
the impacts of the 2016 NSPS subpart OOOOa on the U.S. energy system.
The NEMS is a publicly available model of the U.S. energy economy
developed and maintained by the U.S. Energy Information Administration
and is used to produce the AEO, a reference publication that provides
detailed projections of the U.S. energy economy. The EPA estimated
small impacts on crude oil and natural gas markets of the 2016 NSPS
subpart OOOOa rule over the 2020 to 2025 period. This final rule will
result in a decrease in total compliance costs relative to the
baseline. Therefore, the EPA expects that this rule will partially
reduce the impacts estimated for the 2016 NSPS subpart OOOOa in the
2016 NSPS subpart OOOOa RIA.
Executive Order 13563 directs Federal agencies to consider the
effect of regulations on job creation and employment. According to the
Executive order, ``our regulatory system must protect public health,
welfare, safety, and our environment while promoting economic growth,
innovation, competitiveness, and job creation. It must be based on the
best available science.'' (Executive Order 13563, 2011). While a
standalone analysis of employment impacts is not included in a standard
benefit-cost analysis, such an analysis is of concern in the current
economic climate given continued interest in the employment impact of
regulations such as this final rule. The EPA estimated the changes in
compliance-related labor impacts due to the changes finalized in this
rule. As presented in the RIA for this action, the EPA projected there
will be reductions in the labor required for compliance-related
activities associated with the 2016 NSPS subpart OOOOa requirements
relating to fugitive emissions monitoring and certifications of CVS.
E. What are the forgone benefits?
The EPA expects forgone climate and health benefits due to the
forgone emissions reductions projected under this final rule. The EPA
estimated the forgone domestic climate benefits from the forgone
methane emissions reductions using an interim measure of the domestic
social cost of methane (SC-CH4). The SC-CH4
estimates used here were developed under Executive Order 13783 for use
in regulatory analyses until an improved estimate of the impacts of
climate change to the U.S.
[[Page 57435]]
can be developed based on the best available science and economics.
Executive Order 13783 directed agencies to ensure that estimates of the
social cost of GHG used in regulatory analyses ``are based on the best
available science and economics'' and are consistent with the guidance
contained in Office of Management and Budget (OMB) Circular A-4,
``including with respect to the consideration of domestic versus
international impacts and the consideration of appropriate discount
rates'' (Executive Order 13783, Section 5(c)). In addition, Executive
Order 13783 withdrew the TSDs and the August 2016 Addendum to these
TSDs describing the global social cost of GHG estimates developed under
the prior Administration as no longer representative of government
policy. The withdrawn TSDs and Addendum were developed by an
interagency working group that included the EPA and other executive
branch entities and were used in the 2016 NSPS subpart OOOOa RIA.
The EPA estimated the PV of the forgone domestic climate benefits
over the 2021 to 2030 period to be $19 million under a 7-percent
discount rate and $71 million under a 3-percent discount rate. The EAV
of these forgone benefits is estimated $2.5 million per year under a 7-
percent discount rate and $8.1 million per year under a 3-percent
discount rate. These values represent only a partial accounting of
domestic climate impacts from methane emissions and do not account for
health effects of ozone exposure from the increase in methane
emissions.
Under the final rule, the EPA expects that forgone VOC emission
reductions will degrade air quality and are likely to adversely affect
health and welfare associated with exposure to ozone, PM2.5,
and HAP, but we did not quantify these effects at this time due to the
data limitations described below. This omission should not imply that
these forgone benefits may not exist; rather, it reflects the inherent
difficulties in accurately modeling the direct and indirect impacts of
the projected reductions in emissions for this industrial sector. To
the extent that the EPA were to quantify these ozone and PM impacts, it
would estimate the number and value of avoided premature deaths and
illnesses using an approach detailed in the Particulate Matter NAAQS
and Ozone NAAQS RIAs.83 84 This approach relies on full-form
air quality modeling. The Agency is committed to assessing ways of
conducting full-form air quality modeling for the oil and natural gas
sector that would be suitable for use in regulatory analysis in the
context of NSPS, including ways to address the uncertainties regarding
the scope and magnitude of VOC emissions.
---------------------------------------------------------------------------
\83\ U.S. EPA. December 2012. ``Regulatory Impact Analysis for
the Final Revisions to the National Ambient Air Quality Standards
for Particulate Matter.'' EPA-452/R-12-005. Office of Air Quality
Planning and Standards, Health and Environmental Impacts Division.
https://www3.epa.gov/ttnecas1/regdata/RIAs/finalria.pdf. Accessed
January 9, 2020.
\84\ U.S. U.S. EPA. September 2015. ``Regulatory Impact Analysis
of the Final Revisions to the National Ambient Air Quality Standards
for Ground-Level Ozone.'' EPA-452/R-15-007. Office of Air Quality
Planning and Standards, Health and Environmental Impacts Division.
https://www3.epa.gov/ttnecas1/docs/20151001ria.pdf. Accessed January
9, 2020.
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When quantifying the incidence and economic value of the human
health impacts of air quality changes, the Agency sometimes relies upon
alternative approaches to using full-form air quality modeling, called
reduced-form techniques, often reported as ``benefit-per-ton'' values
that relate air pollution impacts to changes in air pollutant precursor
emissions.\85\ A small, but growing, literature characterizes the air
quality and health impacts from the oil and natural gas
sector.86 87 88 The Agency feels more work needs to be done
to vet the analysis and methodologies for all potential approaches for
valuing the health effects of VOC emissions before they are used in
regulatory analysis, but is committed to continuing this work.
Recently, the EPA systematically compared the changes in benefits, and
concentrations where available, from its benefit-per-ton technique and
other reduced-form techniques to the changes in benefits and
concentrations derived from full-form photochemical model
representation of a few different specific emissions scenarios.\89\ The
Agency's goal was to create a methodology by which investigators could
better understand the suitability of alternative reduced-form air
quality modeling techniques for estimating the health impacts of
criteria pollutant emissions changes in the EPA's benefit-cost
analysis, including the extent to which reduced form models may over-
or under-estimate benefits (compared to full-scale modeling) under
different scenarios and air quality concentrations. The EPA Science
Advisory Board (SAB) recently convened a panel to review this
report.\90\ In particular, the SAB will assess the techniques the
Agency used to appraise these tools; the Agency's approach for
depicting the results of reduced-form tools; and, steps the Agency
might take for improving the reliability of reduced-form techniques for
use in future RIAs.
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\85\ U.S. EPA. 2018. ``Technical Support Document: Estimating
the Benefit per Ton of Reducing PM2.5 Precursors from 17
Sectors.'' February. https://www.epa.gov/sites/production/files/2018-02/documents/sourceapportionmentbpttsd_2018.pdf. Accessed
January 9, 2020.
\86\ Fann, N., K.R. Baker, E.A.W. Chan, A. Eyth, A. Macpherson,
E. Miller, and J. Snyder. 2018. ``Assessing Human Health
PM2.5 and Ozone Impacts from U.S. Oil and Natural Gas
Sector Emissions in 2025.'' Environmental Science and Technology
52(15):8095-8103.
\87\ Litovitz, A., A. Curtright, S. Abramzon, N. Burger, and C.
Samaras. 2013. ``Estimation of Regional Air-Quality Damages from
Marcellus Shale Natural Gas Extraction in Pennsylvania.''
Environmental Research Letters 8(1), 014017.
\88\ Loomis, J. and M. Haefele. 2017. ``Quantifying Market and
Non-market Benefits and Costs of Hydraulic Fracturing in the United
States: A Summary of the Literature.'' Ecological Economics 138:160-
167.
\89\ This analysis compared the benefits estimated using full-
form photochemical air quality modeling simulations (CMAQ and CAMx)
against four reduced-form tools, including: InMAP; AP2/3; EASIUR and
the EPA's benefit-per-ton.
\90\ 85 FR 23823 (April 29, 2020).
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VIII. Statutory and Executive Order Reviews
Additional information about these statutes and Executive orders
can be found at https://www.epa.gov/laws-regulations/laws-and-executive-orders.
A. Executive Order 12866: Regulatory Planning and Review and Executive
Order 13563: Improving Regulation and Regulatory Review
This action is an economically significant regulatory action that
was submitted to OMB for review. Any changes made in response to OMB
recommendations have been documented in the docket. The EPA prepared an
analysis of the potential costs and benefits associated with this
action. This RIA is available in the docket. The RIA describes in
detail the basis for the EPA's assumptions and characterizes the
various sources of uncertainties affecting the estimates below.
Table 6 shows the present value and equivalent annualized value of
the costs, benefits, and net benefits of the final rule for the 2021 to
2030 period relative to the baseline using discount rates of 7 and 3
percent, respectively. The table also shows the total forgone emission
reductions projected from 2021 to 2030 relative to the baseline. In the
following table, we refer to the compliance cost reductions as the
``benefits'' and the forgone benefits as the ``costs'' of this final
action. The net benefits are the benefits (total cost
[[Page 57436]]
reductions) minus the costs (forgone domestic climate benefits).
Table 6--Summary of the Present Value and Equivalent Annualized Value of the Monetized Forgone Benefits, Cost
Reductions, and Net Benefits From 2021 to 2030, 7-Percent and 3-Percent Discount Rates
[Millions of 2016$]
----------------------------------------------------------------------------------------------------------------
7-Percent discount rate 3-Percent discount rate
---------------------------------------------------------------
PV EAV PV EAV
----------------------------------------------------------------------------------------------------------------
Benefits (Total Cost Reductions)................ $750 $100 $950 $110
Compliance Cost Reductions...................... 800 110 1,000 110
Forgone Value of Product Recovery............... 44 5.9 57 6.5
Costs (Forgone Domestic Climate Benefits)....... 19 2.5 71 8.1
Net Benefits.................................... 730 97 880 100
---------------------------------------------------------------
Non-monetized Forgone Benefits.................. Non-monetized climate impacts from increases in methane
emissions.
Health effects of PM2.5 and ozone exposure from an increase of
about 120,000 short tons of VOC from 2021 through 2030.
Health effects of HAP exposure from an increase of about 4,700
short tons of HAP from 2021 through 2030.
Health effects of ozone exposure from an increase of about
450,000 short tons of methane from 2021 through 2030.
Visibility impairment.
Vegetation effects.
----------------------------------------------------------------------------------------------------------------
Note: Estimates are rounded to two significant digits and may not sum due to independent rounding.
B. Executive Order 13771: Reducing Regulations and Controlling
Regulatory Costs
This action is considered an Executive Order 13771 deregulatory
action. Details on the estimated cost reductions of this final rule can
be found in the EPA's analysis of the potential costs and benefits
associated with this action.
C. Paperwork Reduction Act (PRA)
The information collection activities in this rule have been
submitted for approval to the OMB under the PRA. The Information
Collection Request (ICR) document that the EPA prepared has been
assigned EPA ICR number 2523.04, Control Number 2060-0721. You can find
a copy of the ICR in the docket for this rule, and it is briefly
summarized here. The information collection requirements are not
enforceable until OMB approves them.
A summary of the information collection activities previously
submitted to the OMB for the final action titled ``Standards of
Performance for Crude Oil and Natural Gas Facilities for which
Construction, Modification, or Reconstruction Commenced After September
18, 2015'' (2016 NSPS subpart OOOOa), under the PRA, and assigned OMB
Control Number 2060-0721, can be found at 81 FR 35890. You can find a
copy of the 2016 ICR in the 2016 NSPS subpart OOOOa docket (EPA-HQ-OAR-
2010-0505-7626). The EPA is revising the information collection
activities as a result of the amendments in this final rule. You can
find a copy of the revised ICR in the docket for this rule (EPA-HQ-OAR-
2017-0483), and it is briefly summarized here.
Comments were received on the October 15, 2018 (83 FR 52056)
proposed rulemaking indicating that the recordkeeping and reporting
burden for the 2016 NSPS subpart OOOOa was significantly
underestimated, as discussed in section V.B.2 of this preamble. After
consideration of these comments, the EPA updated the assessment of the
recordkeeping and reporting burden for the 2016 NSPS subpart OOOOa. The
updated 2016 NSPS subpart OOOOa ICR was used as the ``baseline'' from
which changes in the Review Rule published in the Federal Register of
Monday, September 14, 2020 were compared. Additional information on the
Review Rule can be found at Docket ID No. EPA-HQ-OAR-2017-0757.
This final rule includes additional revisions to the information
collection activities for NSPS subpart OOOOa.
Respondents/affected entities: Owners or operators of onshore oil
and natural gas affected facilities.
Respondent's obligation to respond: Mandatory.
Estimated number of respondents: 519.
Frequency of response: Annually or semiannually, depending on the
requirement.
Total estimated burden: 1,124,965 hours. Burden is defined at 5 CFR
1320.3(b).
Total estimated cost: $215,874,903, includes $2,681,370 annualized
capital or operation and maintenance costs.
An agency may not conduct or sponsor, and a person is not required
to respond to, a collection of information unless it displays a
currently valid OMB control number. The OMB control numbers for the
EPA's regulations in 40 CFR are listed in 40 CFR part 9. When OMB
approves this ICR, the Agency will announce that approval in the
Federal Register and publish a technical amendment to 40 CFR part 9 to
display the OMB control number for the approved information collection
activities contained in this final rule.
D. Regulatory Flexibility Act (RFA)
I certify that this action will not have a significant economic
impact on a substantial number of small entities under the RFA. In
making this determination, the impact of concern is any significant
adverse economic impact on small entities. An agency may certify that a
rule will not have a significant economic impact on a substantial
number of small entities if the rule relieves regulatory burden, has no
net burden, or otherwise has a positive economic effect on the small
entities subject to the rule. This is a deregulatory action, and the
burden on all entities affected by this final rule, including small
entities, is reduced compared to the 2016 NSPS subpart
[[Page 57437]]
OOOOa. See the RIA for details. We have, therefore, concluded that this
action will relieve regulatory burden for all directly regulated small
entities.
E. Unfunded Mandates Reform Act (UMRA)
This action does not contain any unfunded mandate as described in
UMRA, 2 U.S.C. 1531-1538, and does not significantly or uniquely affect
small governments. The action imposes no enforceable duty on any state,
local, or tribal governments, or the private sector.
F. Executive Order 13132: Federalism
This action does not have federalism implications. It will not have
substantial direct effects on the states, on the relationship between
the National Government and the states, or on the distribution of power
and responsibilities among the various levels of government.
G. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments
This action does not have tribal implications, as specified in
Executive Order 13175. It will not have substantial direct effects on
tribal governments, on the relationship between the Federal Government
and Indian tribes, or on the distribution of power and responsibilities
between the Federal Government and Indian tribes, as specified in
Executive Order 13175. Thus, Executive Order 13175 does not apply to
this action.
H. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks
This action is not subject to Executive Order 13045 because the EPA
does not believe the environmental health risks or safety risks
addressed by this action present a disproportionate risk to children.
While children may experience forgone benefits as a result of this
action, the potential forgone emission reductions (and related
benefits) from the final amendments are small compared to the overall
emission reductions (and related benefits) from the 2016 NSPS subpart
OOOOa.
This final action does not affect the level of public health and
environmental protection already being provided by existing NAAQS and
other mechanisms in the CAA. This action does not affect applicable
local, state, or Federal permitting or air quality management programs
that will continue to address areas with degraded air quality and
maintain the air quality in areas meeting current standards. Areas that
need to reduce criteria air pollution to meet the NAAQS will still need
to rely on control strategies to reduce emissions. The EPA does not
believe this decrease in emission reductions projected from this action
will have a disproportionate adverse effect on children's health.
I. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
This action is not a ``significant energy action'' because it is
not likely to have a significant adverse effect on the supply,
distribution, or use of energy. In the RIA accompanying the 2016 NSPS
subpart OOOOa, the EPA used the NEMS to estimate the impacts of the
2016 NSPS subpart OOOOa on the United States energy system. The EPA
estimated small impacts of that rule over the 2020 to 2025 period
relative to the baseline for that rule. This final rule is estimated to
result in a decrease in total compliance costs, with the reduction in
costs affecting a subset of the affected entities under NSPS subpart
OOOOa. Therefore, the EPA expects that this deregulatory action will
reduce the impacts estimated for the final NSPS in the 2016 RIA and, as
such, is not a significant energy action.
J. National Technology Transfer and Advancement Act (NTTAA)
This action involves technical standards.\91\ Therefore, the EPA
conducted searches for the Oil and Natural Gas Sector: Emission
Standards for New, Reconstructed, and Modified Sources Reconsideration
through the Enhanced National Standards Systems Network (NSSN) Database
managed by the American National Standards Institute (ANSI). Searches
were conducted for EPA Methods 1, 1A, 2, 2A, 2C, 2D, 3A, 3B, 3C, 4, 6,
10, 15, 16, 16A, 18, 21, 22, and 25A of 40 CFR part 60, appendix A. No
applicable voluntary consensus standards (VCS) were identified for EPA
Methods 1A, 2A, 2D, 21, and 22 and none were brought to its attention
in comments. All potential standards were reviewed to determine the
practicality of the VCS for this rule.
---------------------------------------------------------------------------
\91\ These technical standards are the same as those previously
finalized at 40 CFR part 60, subpart OOOOa (81 FR 35824). 2016 NSPS
subpart OOOOa also previously incorporated by reference 10 technical
standards. The incorporation by reference remains unchanged in this
action. See Docket ID Item Nos. EPA-HQ-OAR-2010-0505-7657 and EPA-
HQ-OAR-2010-0505-7658.
---------------------------------------------------------------------------
Two VCS were identified as an acceptable alternative to the EPA
test methods for the purpose of this rule. First, ANSI/ASME PTC 19-10-
1981, ``Flue and Exhaust Gas Analyses (Part 10),'' was identified to be
used in lieu of EPA Methods 3B, 6, 6A, 6B, 15A, and 16A manual portions
only and not the instrumental portion. This standard includes manual
and instructional methods of analysis for carbon dioxide, carbon
monoxide, hydrogen sulfide, nitrogen oxides, oxygen, and
SO2. Second, ASTM D6420-99 (2010), ``Test Method for
Determination of Gaseous Organic Compounds by Direct Interface Gas
Chromatography/Mass Spectrometry,'' is an acceptable alternative to EPA
Method 18 with the following caveats; only use when the target
compounds are all known and the target compounds are all listed in ASTM
D6420 as measurable. ASTM D6420 should never be specified as a total
VOC Method. (ASTM D6420-99 (2010) is not incorporated by reference in
40 CFR part 60.) The search identified 19 VCS that were potentially
applicable for this rule in lieu of the EPA reference methods. However,
these have been determined to not be practical due to lack of
equivalency, documentation, validation of data, and other important
technical and policy considerations. For additional information, please
see the memorandum, ``Voluntary Consensus Standard Results for Oil and
Natural Gas Sector: Emission Standards for New, Reconstructed, and
Modified Sources Reconsideration,'' located at Docket ID No. EPA-HQ-
OAR-2017-0483.
K. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations
The EPA believes that this action does not have disproportionately
high and adverse human health or environmental effects on minority
populations, low-income populations, and/or indigenous peoples, as
specified in Executive Order 12898 (59 FR 7629, February 16, 1994).
While these communities may experience forgone benefits as a result of
this action, the potential forgone emission reductions (and related
benefits) from the final amendments are small compared to the overall
emission reductions (and related benefits) from the 2016 NSPS subpart
OOOOa. The amendments in this final action will decrease the projected
emission reductions of the rule it revises by a small degree. Based on
the revisions in this final rule, for the year 2025, we estimate a
decrease in the projected emissions reductions anticipated by the 2016
NSPS subpart OOOOa in the production and processing segments of about
12 to 15 percent for methane and about 7 to 9 percent for VOC.
[[Page 57438]]
Moreover, this action does not affect the level of public health
and environmental protection already being provided by existing NAAQS,
including ozone and PM2.5, and other mechanisms in the CAA.
This action does not affect applicable local, state, or Federal
permitting or air quality management programs that will continue to
address areas with degraded air quality and maintain the air quality in
areas meeting current standards. Areas that need to reduce criteria air
pollution to meet the NAAQS will still need to rely on control
strategies to reduce emissions.
L. Congressional Review Act (CRA)
This action is subject to the CRA, and the EPA will submit a rule
report to each House of the Congress and to the Comptroller General of
the United States. This action is a ``major rule'' as defined by 5
U.S.C. 804(2).
List of Subjects in 40 CFR Part 60
Environmental protection, Administrative practice and procedure,
Air pollution control, Reporting and recordkeeping.
Andrew Wheeler,
Administrator.
For the reasons set out in the preamble, 40 CFR part 60 is amended
as follows:
PART 60--STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES
0
1. The authority citation for part 60 continues to read as follows:
Authority: 42 U.S.C. 7401 et seq.
Subpart OOOOa--Standards of Performance for Crude Oil and Natural
Gas Facilities for Which Construction, Modification or
Reconstruction Commenced After September 18, 2015
0
2. Section 60.5360a is amended by revising paragraph (a) to read as
follows:
Sec. 60.5360a What is the purpose of this subpart?
(a) This subpart establishes emission standards and compliance
schedules for the control of volatile organic compounds (VOC) and
sulfur dioxide (SO2) emissions from affected facilities in
the crude oil and natural gas production source category that commence
construction, modification, or reconstruction after September 18, 2015.
* * * * *
0
3. Section 60.5365a is amended by revising paragraphs (e), (f)
introductory text, (g) introductory text, and (g)(1) and adding
paragraph (i)(4) to read as follows:
Sec. 60.5365a Am I subject to this subpart?
* * * * *
(e) Each storage vessel affected facility, which is a single
storage vessel as specified in paragraph (e)(1), (2), or (3) of this
section.
(1) A single storage vessel that commenced construction,
reconstruction, or modification after September 18, 2015, and on or
before November 16, 2020, is a storage vessel affected facility if its
potential for VOC emissions is equal to or greater than 6 tons per year
(tpy) as determined according to this paragraph (e)(1). The potential
for VOC emissions must be calculated using a generally accepted model
or calculation methodology, based on the maximum average daily
throughput (as defined in Sec. 60.5430a) determined for a 30-day
period prior to the applicable emission determination deadline
specified in paragraphs (e)(2)(i) and (ii) of this section, except as
provided in paragraph (e)(5)(iv). The determination may take into
account requirements under a legally and practicably enforceable limit
in an operating permit or other requirement established under a
Federal, state, local, or tribal authority.
(2) Except as specified in paragraph (e)(3) of this section, a
single storage vessel that commenced construction, reconstruction or
modification after November 16, 2020, is a storage vessel affected
facility if the potential for VOC emissions is equal to or greater than
6 tpy as determined according to paragraph (e)(2)(i) or (ii) of this
section, except as provided in paragraph (e)(5)(iv) of this section.
The determination may take into account requirements under a legally
and practicably enforceable limit in an operating permit or other
requirement established under a Federal, state, local, or tribal
authority. The potential for VOC emissions is calculated on an
individual storage vessel basis and is not averaged across the number
of storage vessels at the site.
(i) For each storage vessel receiving liquids pursuant to the
standards for well affected facilities in Sec. 60.5375a, including
wells subject to Sec. 60.5375a(f), you must determine the potential
for VOC emissions within 30 days after startup of production of the
well, except as provided in paragraph (e)(5)(iv) of this section. The
potential for VOC emissions must be calculated for each individual
storage vessel using a generally accepted model or calculation
methodology, based on the maximum average daily throughput, as defined
in Sec. 60.5430a, determined for a 30-day period of production.
(ii) For each storage vessel located at a compressor station or
onshore natural gas processing plant, you must determine the potential
for VOC emissions prior to startup of the compressor station or onshore
natural gas processing plant using either method described in paragraph
(e)(2)(ii)(A) or (B) of this section.
(A) Determine the potential for VOC emissions using a generally
accepted model or calculation methodology and based on the throughput
established in a legally and practicably enforceable limit in an
operating permit or other requirement established under a Federal,
state, local, or tribal authority; or
(B) Determine the potential for VOC emissions using a generally
accepted model or calculation methodology and based on projected
maximum average daily throughput. Maximum average daily throughput is
determined using a generally accepted engineering model (e.g.,
volumetric condensate rates from the storage vessels based on the
maximum gas throughput capacity of each producing facility) to project
the maximum average daily throughput for the storage vessel.
(3) If a storage vessel battery, which consists of two or more
storage vessels, meets all of the design and operational criteria
specified in paragraphs (e)(3)(i) through (iv) of this section through
legally and practicably enforceable standards in a permit or other
requirement established under Federal, state, local, or tribal
authority, then each storage vessel in such storage vessel battery is a
storage vessel affected facility.
(i) The storage vessels must be manifolded together with piping
such that all vapors are shared among the headspaces of the storage
vessels;
(ii) The storage vessels must be equipped with a closed vent system
that is designed, operated, and maintained to route the vapors back to
the process or to a control device;
(iii) The vapors collected in paragraph (e)(3)(i) of this section
must be routed back to the process or to a control device that reduces
VOC emissions by at least 95.0 percent; and
(iv) The VOC emissions, averaged across the number of storage
vessels in the battery meeting all of the criteria of paragraphs
(e)(3)(i) through (iii) of this section, are equal to or greater than 6
tpy.
(v) If a storage vessel battery meeting all of the criteria
specified in paragraphs (e)(3)(i) through (iii) of this section through
legally and practicably
[[Page 57439]]
enforceable standards in a permit or other requirements established
under Federal, state, local, or tribal authority, emits less than 6 tpy
of VOC emissions averaged across the number of storage vessels in the
battery, none of the storage vessels in the battery are storage vessel
affected facilities.
(4) A storage vessel affected facility that subsequently has its
potential for VOC emissions decrease to less than 6 tpy shall remain an
affected facility under this subpart.
(5) For storage vessels not subject to a legally and practicably
enforceable limit in an operating permit or other requirement
established under Federal, state, local, or tribal authority, any vapor
from the storage vessel that is recovered and routed to a process
through a VRU designed and operated as specified in this section is not
required to be included in the determination of potential for VOC
emissions for purposes of determining affected facility status,
provided you comply with the requirements in paragraphs (e)(5)(i)
through (iv) of this section.
(i) You meet the cover requirements specified in Sec. 60.5411a(b).
(ii) You meet the closed vent system requirements specified in
Sec. 60.5411a(c) and (d).
(iii) You must maintain records that document compliance with
paragraphs (e)(5)(i) and (ii) of this section.
(iv) In the event of removal of apparatus that recovers and routes
vapor to a process, or operation that is inconsistent with the
conditions specified in paragraphs (e)(5)(i) and (ii) of this section,
you must determine the storage vessel's potential for VOC emissions
according to this section within 30 days of such removal or operation.
(6) The requirements of this paragraph (e)(6) apply to each storage
vessel affected facility immediately upon startup, startup of
production, or return to service. A storage vessel affected facility
that is reconnected to the original source of liquids is a storage
vessel affected facility subject to the same requirements that applied
before being removed from service. Any storage vessel that is used to
replace any storage vessel affected facility is subject to the same
requirements that applied to the storage vessel affected facility being
replaced.
(7) A storage vessel with a capacity greater than 100,000 gallons
used to recycle water that has been passed through two stage separation
is not a storage vessel affected facility.
(f) The group of all equipment within a process unit at an onshore
natural gas processing plant is an affected facility.
* * * * *
(g) Sweetening units located at onshore natural gas processing
plants that commenced construction, modification, or reconstruction
after September 18, 2015, and on or before November 16, 2020, and
sweetening units that commence construction, modification, or
reconstruction after November 16, 2020.
(1) Each sweetening unit that processes natural gas produced from
either onshore or offshore wells is an affected facility; and
* * * * *
(i) * * *
(4) For purposes of Sec. 60.5397a, a ``modification'' to an
existing source separate tank battery surface site occurs when:
(i) Any of the actions in paragraphs (i)(3)(i) through (iii) of
this section occurs at an existing source separate tank battery surface
site;
(ii) A well sending production to an existing source separate tank
battery site is modified, as defined in paragraphs (i)(3)(i) through
(iii) of this section; or
(iii) A well site subject to the requirements in Sec. 60.5397a
removes all major production and processing equipment, as defined in
Sec. 60.5430a, such that it becomes a wellhead only well site and
sends production to an existing source separate tank battery surface
site.
* * * * *
0
4. Section 60.5375a is amended by revising paragraphs (a)(1)(i),
(a)(1)(iii) introductory text, and (f)(3)(ii) and adding paragraph
(f)(4) to read as follows:
Sec. 60.5375a What VOC standards apply to well affected facilities?
* * * * *
(a) * * *
(1) * * *
(i) During the initial flowback stage, route the flowback into one
or more well completion vessels or storage vessels and commence
operation of a separator unless it is technically infeasible for a
separator to function. The separator may be a production separator, but
the production separator also must be designed to accommodate flowback.
Any gas present in the initial flowback stage is not subject to control
under this section.
* * * * *
(iii) You must have the separator onsite or otherwise available for
use at a centralized facility or well pad that services the well
affected facility during well completions. The separator must be
available and ready for use to comply with paragraph (a)(1)(ii) of this
section during the entirety of the flowback period, except as provided
in paragraphs (a)(1)(iii)(A) through (C) of this section.
* * * * *
(f) * * *
(3) * * *
(ii) Route all flowback into one or more well completion vessels
and commence operation of a separator unless it is technically
infeasible for a separator to function. Any gas present in the flowback
before the separator can function is not subject to control under this
section. Capture and direct recovered gas to a completion combustion
device, except in conditions that may result in a fire hazard or
explosion, or where high heat emissions from a completion combustion
device may negatively impact tundra, permafrost, or waterways.
Completion combustion devices must be equipped with a reliable
continuous pilot flame.
(4) You must submit the notification as specified in Sec.
60.5420a(a)(2), submit annual reports as specified in Sec.
60.5420a(b)(1) and (2) and maintain records specified in Sec.
60.5420a(c)(1)(iii) for each wildcat and delineation well. You must
submit the notification as specified in Sec. 60.5420a(a)(2), submit
annual reports as specified in Sec. 60.5420a(b)(1) and (2), and
maintain records as specified in Sec. 60.5420a(c)(1)(iii) and (vii)
for each low pressure well.
* * * * *
0
5. Section 60.5385a is amended by revising paragraph (a)(1) to read as
follows:
Sec. 60.5385a What VOC standards apply to reciprocating compressor
affected facilities?
* * * * *
(a) * * *
(1) On or before the compressor has operated for 26,000 hours. The
number of hours of operation must be continuously monitored beginning
upon initial startup of your reciprocating compressor affected
facility, August 2, 2016, or the date of the most recent reciprocating
compressor rod packing replacement, whichever is latest.
* * * * *
0
6. Section 60.5393a is amended by revising paragraphs (b) and (c) and
removing paragraph (f) to read as follows:
Sec. 60.5393a What VOC standards apply to pneumatic pump affected
facilities?
* * * * *
[[Page 57440]]
(b) For each pneumatic pump affected facility at a well site you
must reduce natural gas emissions by 95.0 percent, except as provided
in paragraphs (b)(3), (4), and (5) of this section.
(1)-(2) [Reserved]
(3) You are not required to install a control device solely for the
purpose of complying with the 95.0 percent reduction requirement of
paragraph (b) of this section. If you do not have a control device
installed on site by the compliance date and you do not have the
ability to route to a process, then you must comply instead with the
provisions of paragraphs (b)(3)(i) and (ii) of this section. For the
purposes of this section, boilers and process heaters are not
considered control devices. In addition, routing emissions from
pneumatic pump discharges to boilers and process heaters is not
considered routing to a process.
(i) Submit a certification in accordance with Sec.
60.5420a(b)(8)(i)(A) in your next annual report, certifying that there
is no available control device or process on site and maintain the
records in Sec. 60.5420a(c)(16)(i) and (ii).
(ii) If you subsequently install a control device or have the
ability to route to a process, you are no longer required to comply
with paragraph (b)(3)(i) of this section and must submit the
information in Sec. 60.5420a(b)(8)(ii) in your next annual report and
maintain the records in Sec. 60.5420a(c)(16)(i), (ii), and (iii). You
must be in compliance with the requirements of paragraph (b) of this
section within 30 days of startup of the control device or within 30
days of the ability to route to a process.
(4) If the control device available on site is unable to achieve a
95-percent reduction and there is no ability to route the emissions to
a process, you must still route the pneumatic pump affected facility's
emissions to that control device. If you route the pneumatic pump
affected facility to a control device installed on site that is
designed to achieve less than a 95-percent reduction, you must submit
the information specified in Sec. 60.5420a(b)(8)(i)(C) in your next
annual report and maintain the records in Sec. 60.5420a(c)(16)(iii).
(5) If an owner or operator determines, through an engineering
assessment, that routing a pneumatic pump to a control device or a
process is technically infeasible, the requirements specified in
paragraphs (b)(5)(i) through (iv) of this section must be met.
(i) The owner or operator shall conduct the assessment of technical
infeasibility in accordance with the criteria in paragraph (b)(5)(iii)
of this section and have it certified by either a qualified
professional engineer or an in-house engineer with expertise on the
design and operation of the pneumatic pump in accordance with paragraph
(b)(5)(ii) of this section.
(ii) The following certification, signed and dated by the qualified
professional engineer or in-house engineer, shall state: ``I certify
that the assessment of technical infeasibility was prepared under my
direction or supervision. I further certify that the assessment was
conducted and this report was prepared pursuant to the requirements of
Sec. 60.5393a(b)(5)(iii). Based on my professional knowledge and
experience, and inquiry of personnel involved in the assessment, the
certification submitted herein is true, accurate, and complete.''
(iii) The assessment of technical infeasibility to route emissions
from the pneumatic pump to an existing control device onsite or to a
process shall include, but is not limited to, safety considerations,
distance from the control device or process, pressure losses and
differentials in the closed vent system, and the ability of the control
device or process to handle the pneumatic pump emissions which are
routed to them. The assessment of technical infeasibility shall be
prepared under the direction or supervision of the qualified
professional engineer or in-house engineer who signs the certification
in accordance with paragraph (b)(5)(ii) of this section.
(iv) The owner or operator shall maintain the records specified in
Sec. 60.5420a(c)(16)(iv).
(6) If the pneumatic pump is routed to a control device or a
process and the control device or process is subsequently removed from
the location or is no longer available, you are no longer required to
be in compliance with the requirements of paragraph (b) of this
section, and instead must comply with paragraph (b)(3) of this section
and report the change in the next annual report in accordance with
Sec. 60.5420a(b)(8)(ii).
(c) If you use a control device or route to a process to reduce
emissions, you must connect the pneumatic pump affected facility
through a closed vent system that meets the requirements of Sec. Sec.
60.5411a(d) and (e), 60.5415a(b)(3), and 60.5416a(d).
* * * * *
0
7. Section 60.5395a is amended by revising the introductory text to
read as follows:
Sec. 60.5395a What VOC standards apply to storage vessel affected
facilities?
Each storage vessel affected facility must comply with the VOC
standards in this section, except as provided in paragraph (e) of this
section.
* * * * *
0
8. Section 60.5397a is amended by revising paragraphs (a), (c)(2),
(c)(7)(i) introductory text, and (c)(8) introductory text, adding
paragraph (c)(8)(iii), and revising paragraphs (d), (f), (g)
introductory text, (g)(1), (2), and (5), and (h) to read as follows:
Sec. 60.5397a What fugitive emissions VOC standards apply to the
affected facility which is the collection of fugitive emissions
components at a well site and the affected facility which is the
collection of fugitive emissions components at a compressor station?
* * * * *
(a) You must comply with paragraph (a)(1) of this section, unless
your affected facility under Sec. 60.5365a(i) (i.e., the collection of
fugitive emissions components at a well site) meets the conditions
specified in either paragraph (a)(1)(i) or (ii) of this section. If
your affected facility under Sec. 60.5365a(i) (i.e., the collection of
fugitive emissions components at a well site) meets the conditions
specified in either paragraph (a)(1)(i) or (ii) of this section, you
must comply with either paragraph (a)(1) or (2) of this section.
(1) You must monitor all fugitive emission components, as defined
in Sec. 60.5430a, in accordance with paragraphs (b) through (g) of
this section. You must repair all sources of fugitive emissions in
accordance with paragraph (h) of this section. You must keep records in
accordance with paragraph (i) of this section and report in accordance
with paragraph (j) of this section. For purposes of this section,
fugitive emissions are defined as any visible emission from a fugitive
emissions component observed using optical gas imaging or an instrument
reading of 500 parts per million (ppm) or greater using Method 21 of
appendix A-7 to this part.
(i) First 30-day production. For the collection of fugitive
emissions components at a well site, where the total production of the
well site is at or below 15 barrels of oil equivalent (boe) per day for
the first 30 days of production, according to Sec. 60.5415a(j), you
must comply with the provisions of either paragraph (a)(1) or (2) of
this section. Except as provided in this paragraph (a)(1)(i), the
calculation must be performed within 45 days of the end of the first 30
days of production. To convert gas production to equivalent barrels of
oil, divide the cubic feet of gas produced by 6,000. For well sites
that commenced construction, reconstruction, or modification between
[[Page 57441]]
October 15, 2019, and November 16, 2020, the owner or operator may use
the records of the first 30 days of production after becoming subject
to this subpart, if available, to determine if the total well site
production is at or below 15 boe per day, provided this determination
is completed by December 14, 2020.
(ii) Well site production decline. For the collection of fugitive
emissions components at a well site, where, at any time, the total
production of the well site is at or below 15 boe per day based on a
rolling 12-month average, you must comply with the provisions of either
paragraph (a)(1) or (2) of this section. To convert gas production to
equivalent barrels of oil, divide the cubic feet of gas produced by
6,000.
(2) You must maintain the total production for the well site at or
below 15 boe per day based on a rolling 12-month average, according to
Sec. Sec. 60.5410a(k) and 60.5415a(i), comply with the reporting
requirements in Sec. 60.5420a(b)(7)(i)(C), and the recordkeeping
requirements in Sec. 60.5420a(c)(15)(ii), until such time that you
perform any of the actions in paragraphs (a)(2)(i) through (v) of this
section. If any of the actions listed in paragraphs (a)(2)(i) through
(v) of this section occur, you must comply with paragraph (a)(3) of
this section.
(i) A new well is drilled at the well site;
(ii) A well at the well site is hydraulically fractured;
(iii) A well at the well site is hydraulically refractured;
(iv) A well at the well site is stimulated in any manner for the
purpose of increasing production, including well workovers; or
(v) A well at the well site is shut-in for the purpose of
increasing production from the well.
(3) You must determine the total production for the well site for
the first 30 days after any of the actions listed in paragraphs
(a)(2)(i) through (v) of this section is completed, according to Sec.
60.5415a(j), comply with paragraph (a)(3)(i) or (ii) of this section,
the reporting requirements in Sec. 60.5420a(b)(7)(i)(C), and the
recordkeeping requirements in Sec. 60.5420a(c)(15)(iii).
(i) If the total production for the well site is at or below 15 boe
per day for the first 30 days after the action is completed, according
to Sec. 60.5415a(j), you must either continue to comply with paragraph
(a)(2) of this section or comply with paragraph (a)(1) of this section.
(ii) If the total production for the well site is greater than 15
boe per day for the first 30 days after the action is completed,
according to Sec. 60.5415a(j), you must comply with paragraph (a)(1)
of this section and conduct an initial monitoring survey for the
collection of fugitive emissions components at the well site in
accordance with the same schedule as for modified well sites as
specified in Sec. 60.5397a(f)(1).
* * * * *
(c) * * *
(2) Technique for determining fugitive emissions (i.e., Method 21
of appendix A-7 to this part or optical gas imaging meeting the
requirements in paragraphs (c)(7)(i) through (vii) of this section).
* * * * *
(7) * * *
(i) Verification that your optical gas imaging equipment meets the
specifications of paragraphs (c)(7)(i)(A) and (B) of this section. This
verification is an initial verification, and may either be performed by
the facility, by the manufacturer, or by a third party. For the
purposes of complying with the fugitive emissions monitoring program
with optical gas imaging, a fugitive emission is defined as any visible
emissions observed using optical gas imaging.
* * * * *
(8) If you are using Method 21 of appendix A-7 of this part, your
plan must also include the elements specified in paragraphs (c)(8)(i)
through (iii) of this section. For the purposes of complying with the
fugitive emissions monitoring program using Method 21 of appendix A-7
of this part a fugitive emission is defined as an instrument reading of
500 ppm or greater.
* * * * *
(iii) Procedures for calibration. The instrument must be calibrated
before use each day of its use by the procedures specified in Method 21
of appendix A-7 of this part. At a minimum, you must also conduct
precision tests at the interval specified in Method 21 of appendix A-7
of this part, Section 8.1.2, and a calibration drift assessment at the
end of each monitoring day. The calibration drift assessment must be
conducted as specified in paragraph (c)(8)(iii)(A) of this section.
Corrective action for drift assessments is specified in paragraphs
(c)(8)(iii)(B) and (C) of this section.
(A) Check the instrument using the same calibration gas that was
used to calibrate the instrument before use. Follow the procedures
specified in Method 21 of appendix A-7 of this part, Section 10.1,
except do not adjust the meter readout to correspond to the calibration
gas value. If multiple scales are used, record the instrument reading
for each scale used. Divide the arithmetic difference of the initial
and post-test calibration response by the corresponding calibration gas
value for each scale and multiply by 100 to express the calibration
drift as a percentage.
(B) If a calibration drift assessment shows a negative drift of
more than 10 percent, then all equipment with instrument readings
between the fugitive emission definition multiplied by (100 minus the
percent of negative drift/divided by 100) and the fugitive emission
definition that was monitored since the last calibration must be re-
monitored.
(C) If any calibration drift assessment shows a positive drift of
more than 10 percent from the initial calibration value, then, at the
owner/operator's discretion, all equipment with instrument readings
above the fugitive emission definition and below the fugitive emission
definition multiplied by (100 plus the percent of positive drift/
divided by 100) monitored since the last calibration may be re-
monitored.
(d) Each fugitive emissions monitoring plan must include the
elements specified in paragraphs (d)(1) through (3) of this section, at
a minimum, as applicable.
(1) If you are using optical gas imaging, your plan must include
procedures to ensure that all fugitive emissions components are
monitored during each survey. Example procedures include, but are not
limited to, a sitemap with an observation path, a written narrative of
where the fugitive emissions components are located and how they will
be monitored, or an inventory of fugitive emissions components.
(2) If you are using Method 21 of appendix A-7 of this part, your
plan must include a list of fugitive emissions components to be
monitored and method for determining the location of fugitive emissions
components to be monitored in the field (e.g., tagging, identification
on a process and instrumentation diagram, etc.).
(3) Your fugitive emissions monitoring plan must include the
written plan developed for all of the fugitive emissions components
designated as difficult-to-monitor in accordance with paragraph (g)(3)
of this section, and the written plan for fugitive emissions components
designated as unsafe-to-monitor in accordance with paragraph (g)(4) of
this section.
* * * * *
(f)(1) You must conduct an initial monitoring survey within 90 days
of the startup of production, as defined in
[[Page 57442]]
Sec. 60.5430a, for each collection of fugitive emissions components at
a new well site or by June 3, 2017, whichever is later. For a modified
collection of fugitive emissions components at a well site, the initial
monitoring survey must be conducted within 90 days of the startup of
production for each collection of fugitive emissions components after
the modification or by June 3, 2017, whichever is later.
Notwithstanding the preceding deadlines, for each collection of
fugitive emissions components at a well site located on the Alaskan
North Slope, as defined in Sec. 60.5430a, that starts up production
between September and March, you must conduct an initial monitoring
survey within 6 months of the startup of production for a new well
site, within 6 months of the first day of production after a
modification of the collection of fugitive emission components, or by
the following June 30, whichever is latest.
(2) You must conduct an initial monitoring survey within 90 days of
the startup of a new compressor station for each collection of fugitive
emissions components at the new compressor station or by June 3, 2017,
whichever is later. For a modified collection of fugitive emissions
components at a compressor station, the initial monitoring survey must
be conducted within 90 days of the modification or by June 3, 2017,
whichever is later. Notwithstanding the preceding deadlines, for each
collection of fugitive emissions components at a new compressor station
located on the Alaskan North Slope that starts up between September and
March, you must conduct an initial monitoring survey within 6 months of
the startup date for new compressor stations, within 6 months of the
modification, or by the following June 30, whichever is latest.
(g) A monitoring survey of each collection of fugitive emissions
components at a well site or at a compressor station must be performed
at the frequencies specified in paragraphs (g)(1) and (2) of this
section, with the exceptions noted in paragraphs (g)(3) through (5) of
this section.
(1) Except as provided in this paragraph (g)(1), a monitoring
survey of each collection of fugitive emissions components at a well
site must be conducted at least semiannually after the initial survey.
Consecutive semiannual monitoring surveys must be conducted at least 4
months apart and no more than 7 months apart. A monitoring survey of
each collection of fugitive emissions components at a well site located
on the Alaskan North Slope must be conducted at least annually.
Consecutive annual monitoring surveys must be conducted at least 9
months apart and no more than 13 months apart.
(2) Except as provided in this paragraph (g)(2), a monitoring
survey of the collection of fugitive emissions components at a
compressor station must be conducted at least semiannually after the
initial survey. Consecutive semiannual monitoring surveys must be
conducted at least 4 months apart and no more than 7 months apart. A
monitoring survey of the collection of fugitive emissions components at
a compressor station located on the Alaskan North Slope must be
conducted at least annually. Consecutive annual monitoring surveys must
be conducted at least 9 months apart and no more than 13 months apart.
* * * * *
(5) You are no longer required to comply with the requirements of
paragraph (g)(1) of this section when the owner or operator removes all
major production and processing equipment, as defined in Sec.
60.5430a, such that the well site becomes a wellhead only well site. If
any major production and processing equipment is subsequently added to
the well site, then the owner or operator must comply with the
requirements in paragraphs (f)(1) and (g)(1) of this section.
(h) Each identified source of fugitive emissions shall be repaired,
as defined in Sec. 60.5430a, in accordance with paragraphs (h)(1) and
(2) of this section.
(1) A first attempt at repair shall be made no later than 30
calendar days after detection of the fugitive emissions.
(2) Repair shall be completed as soon as practicable, but no later
than 30 calendar days after the first attempt at repair as required in
paragraph (h)(1) of this section.
(3) If the repair is technically infeasible, would require a vent
blowdown, a compressor station shutdown, a well shutdown or well shut-
in, or would be unsafe to repair during operation of the unit, the
repair must be completed during the next scheduled compressor station
shutdown for maintenance, scheduled well shutdown, scheduled well shut-
in, after a scheduled vent blowdown, or within 2 years, whichever is
earliest. For purposes of this paragraph (h)(3), a vent blowdown is the
opening of one or more blowdown valves to depressurize major production
and processing equipment, other than a storage vessel.
(4) Each identified source of fugitive emissions must be resurveyed
to complete repair according to the requirements in paragraphs
(h)(4)(i) through (iv) of this section, to ensure that there are no
fugitive emissions.
(i) The operator may resurvey the fugitive emissions components to
verify repair using either Method 21 of appendix A-7 of this part or
optical gas imaging.
(ii) For each repair that cannot be made during the monitoring
survey when the fugitive emissions are initially found, a digital
photograph must be taken of that component or the component must be
tagged during the monitoring survey when the fugitives were initially
found for identification purposes and subsequent repair. The digital
photograph must include the date that the photograph was taken and must
clearly identify the component by location within the site (e.g., the
latitude and longitude of the component or by other descriptive
landmarks visible in the picture).
(iii) Operators that use Method 21 of appendix A-7 of this part to
resurvey the repaired fugitive emissions components are subject to the
resurvey provisions specified in paragraphs (h)(4)(iii)(A) and (B) of
this section.
(A) A fugitive emissions component is repaired when the Method 21
instrument indicates a concentration of less than 500 ppm above
background or when no soap bubbles are observed when the alternative
screening procedures specified in section 8.3.3 of Method 21 of
appendix A-7 of this part are used.
(B) Operators must use the Method 21 monitoring requirements
specified in paragraph (c)(8)(ii) of this section or the alternative
screening procedures specified in section 8.3.3 of Method 21 of
appendix A-7 of this part.
(iv) Operators that use optical gas imaging to resurvey the
repaired fugitive emissions components, are subject to the resurvey
provisions specified in paragraphs (h)(4)(iv)(A) and (B) of this
section.
(A) A fugitive emissions component is repaired when the optical gas
imaging instrument shows no indication of visible emissions.
(B) Operators must use the optical gas imaging monitoring
requirements specified in paragraph (c)(7) of this section.
* * * * *
0
9. Section 60.5398a is revised to read as follows:
[[Page 57443]]
Sec. 60.5398a What are the alternative means of emission limitations
for VOC from well completions, reciprocating compressors, the
collection of fugitive emissions components at a well site and the
collection of fugitive emissions components at a compressor station?
(a) If, in the Administrator's judgment, an alternative means of
emission limitation will achieve a reduction in VOC emissions at least
equivalent to the reduction in VOC emissions achieved under Sec.
60.5375a, Sec. 60.5385a, or Sec. 60.5397a, the Administrator will
publish, in the Federal Register, a notice permitting the use of that
alternative means for the purpose of compliance with Sec. 60.5375a,
Sec. 60.5385a, or Sec. 60.5397a. The authority to approve an
alternative means of emission limitation is retained by the
Administrator and shall not be delegated to States under section 111(c)
of the Clean Air Act (CAA).
(b) Any notice under paragraph (a) of this section must be
published only after notice and an opportunity for a public hearing.
(c) Determination of equivalence to the design, equipment, work
practice, or operational requirements of this section will be evaluated
by the following guidelines:
(1) The applicant must provide information that is sufficient for
demonstrating the alternative means of emission limitation achieves
emission reductions that are at least equivalent to the emission
reductions that would be achieved by complying with the relevant
standards. At a minimum, the application must include the following
information:
(i) Details of the specific equipment or components that would be
included in the alternative.
(ii) A description of the alternative work practice, including, as
appropriate, the monitoring method, monitoring instrument or
measurement technology, and the data quality indicators for precision
and bias.
(iii) The method detection limit of the technology, technique, or
process and a description of the procedures used to determine the
method detection limit. At a minimum, the applicant must collect,
verify, and submit field data encompassing seasonal variations to
support the determination of the method detection limit. The field data
may be supplemented with modeling analyses, controlled test site data,
or other documentation.
(iv) Any initial and ongoing quality assurance/quality control
measures necessary for maintaining the technology, technique, or
process, and the timeframes for conducting such measures.
(v) Frequency of measurements. For continuous monitoring
techniques, the minimum data availability.
(vi) Any restrictions for using the technology, technique, or
process.
(vii) Initial and continuous compliance procedures, including
recordkeeping and reporting, if the compliance procedures are different
than those specified in this subpart.
(2) For each technology, technique, or process for which a
determination of equivalency is requested, the application must provide
a demonstration that the emission reduction achieved by the alternative
means of emission limitation is at least equivalent to the emission
reduction that would be achieved by complying with the relevant
standards in this subpart.
(d) Any alternative means of emission limitations approved under
this section shall constitute a required work practice, equipment,
design, or operational standard within the meaning of section 111(h)(1)
of the CAA.
0
10. Add Sec. 60.5399a to read as follows:
Sec. 60.5399a What alternative fugitive emissions standards apply to
the affected facility which is the collection of fugitive emissions
components at a well site and the affected facility which is the
collection of fugitive emissions components at a compressor station:
Equivalency with state, local, and tribal programs?
This section provides alternative fugitive emissions standards
based on programs under state, local, or tribal authorities for the
collection of fugitive emissions components, as defined in Sec.
60.5430a, located at well sites and compressor stations. Paragraphs (a)
through (e) of this section outline the procedure for submittal and
approval of alternative fugitive emissions standards. Paragraphs (f)
through (n) provide approved alternative fugitive emissions standards.
The terms ``fugitive emissions components'' and ``repaired'' are
defined in Sec. 60.5430a and must be applied to the alternative
fugitive emissions standards in this section. The requirements for a
monitoring plan as specified in Sec. 60.5397a(c) and (d) apply to the
alternative fugitive emissions standards in this section.
(a) Alternative fugitive emissions standards. If, in the
Administrator's judgment, an alternative fugitive emissions standard
will achieve a reduction in VOC emissions at least equivalent to the
reductions achieved under Sec. 60.5397a, the Administrator will
publish, in the Federal Register, a notice permitting use of the
alternative fugitive emissions standard for the purpose of compliance
with Sec. 60.5397a. The authority to approve alternative fugitive
emissions standards is retained by the Administrator and shall not be
delegated to States under section 111(c) of the CAA.
(b) Notice. Any notice under paragraph (a) of this section will be
published only after notice and an opportunity for public hearing.
(c) Evaluation guidelines. Determination of alternative fugitive
emissions standards to the design, equipment, work practice, or
operational requirements of Sec. 60.5397a will be evaluated by the
following guidelines:
(1) The monitoring instrument, including the monitoring procedure;
(2) The monitoring frequency;
(3) The fugitive emissions definition;
(4) The repair requirements; and
(5) The recordkeeping and reporting requirements.
(d) Approval of alternative fugitive emissions standard. Any
alternative fugitive emissions standard approved under this section
shall:
(1) Constitute a required design, equipment, work practice, or
operational standard within the meaning of section 111(h)(1) of the
CAA; and
(2) Be made available for use by any owner or operator in meeting
the relevant standards and requirements established for affected
facilities under Sec. 60.5397a.
(e) Notification. (1) An owner or operator must notify the
Administrator of adoption of the alternative fugitive emissions
standards within the first annual report following implementation of
the alternative fugitive emissions standard, as specified in Sec.
60.5420a(a)(3).
(2) An owner or operator implementing one of the alternative
fugitive emissions standards must submit the reports specified in Sec.
60.5420a(b)(7)(iii). An owner or operator must also maintain the
records specified by the specific alternative fugitive emissions
standard for a period of at least 5 years.
(f) Alternative fugitive emissions requirements for the collection
of fugitive emissions components located at a well site or a compressor
station in the State of California. An affected facility, which is the
collection of fugitive emissions components, as defined in Sec.
60.5430a, located at a well site or a compressor station in the State
of California may elect to reduce VOC emissions through compliance with
the monitoring, repair, and recordkeeping
[[Page 57444]]
requirements in the California Code of Regulations, title 17, sections
95665-95667, effective January 1, 2020, as an alternative to complying
with the requirements in Sec. 60.5397a(f)(1) and (2), (g)(1) through
(4), (h), and (i). The information specified in Sec.
60.5420a(b)(7)(iii)(A) and the information specified in either Sec.
60.5420a(b)(7)(iii)(B) or (C) may be provided as an alternative to the
requirements in Sec. 60.5397a(j).
(g) Alternative fugitive emissions requirements for the collection
of fugitive emissions components located at a well site or a compressor
station in the State of Colorado. An affected facility, which is the
collection of fugitive emissions components, as defined in Sec.
60.5430a, located at a well site or a compressor station in the State
of Colorado may elect to comply with the monitoring, repair, and
recordkeeping requirements in Colorado Regulation 7, Part D, section
I.L or II.E, effective February 14, 2020, for well sites and compressor
stations, as an alternative to complying with the requirements in Sec.
60.5397a(f)(1) and (2), (g)(1) through (4), (h), and (i), provided the
monitoring instrument used is an optical gas imaging or a Method 21
instrument (see appendix A-7 of this part). Monitoring must be
conducted on at least a semiannual basis for well sites and compressor
stations. If using the alternative in this paragraph (g), the
information specified in Sec. 60.5420a(b)(7)(iii)(A) and (C) must be
provided in lieu of the requirements in Sec. 60.5397a(j).
(h) Alternative fugitive emissions requirements for the collection
of fugitive emissions components located at a well site in the State of
Ohio. An affected facility, which is the collection of fugitive
emissions components, as defined in Sec. 60.5430a, located at a well
site in the State of Ohio may elect to comply with the monitoring,
repair, and recordkeeping requirements in Ohio General Permits 12.1,
Section C.5 and 12.2, Section C.5, effective April 14, 2014, as an
alternative to complying with the requirements in Sec. 60.5397a(f)(1),
(g)(1), (3), and (4), (h), and (i), provided the monitoring instrument
used is optical gas imaging or a Method 21 instrument (see appendix A-7
of this part) with a leak definition and reading of 500 ppm or greater.
Monitoring must be conducted on at least a semiannual basis and skip
periods cannot be applied. The information specified in Sec.
60.5420a(b)(7)(iii)(A) and the information specified in either Sec.
60.5420a(b)(7)(iii)(B) or (C) may be provided as an alternative to the
requirements in Sec. 60.5397a(j).
(i) Alternative fugitive emissions requirements for the collection
of fugitive emissions components located at a compressor station in the
State of Ohio. An affected facility, which is the collection of
fugitive emissions components, as defined in Sec. 60.5430a, located at
a compressor station in the State of Ohio may elect to comply with the
monitoring, repair, and recordkeeping requirements in Ohio General
Permit 18.1, effective February 7, 2017, as an alternative to complying
with the requirements in Sec. 60.5397a(f)(2), (g)(2) through (4), (h),
and (i), provided the monitoring instrument used is optical gas imaging
or a Method 21 instrument (see appendix A-7 of this part) with a leak
definition and reading of 500 ppm or greater. Monitoring must be
conducted on at least a semiannual basis and skip periods cannot be
applied. The information specified in Sec. 60.5420a(b)(7)(iii)(A) and
the information specified in either Sec. 60.5420a(b)(7)(iii)(B) or (C)
may be provided as an alternative to the requirements in Sec.
60.5397a(j).
(j) Alternative fugitive emissions requirements for the collection
of fugitive emissions components located at a well site in the State of
Pennsylvania. An affected facility, which is the collection of fugitive
emissions components, as defined in Sec. 60.5430a, located at a well
site in the State of Pennsylvania may elect to comply with the
monitoring, repair, and recordkeeping requirements in Pennsylvania
General Permit 5A, section G, effective August 8, 2018, as an
alternative to complying with the requirements in Sec. 60.5397a(f)(2),
(g)(2) through (4), (h), and (i), provided the monitoring instrument
used is an optical gas imaging or a Method 21 instrument (see appendix
A-7 of this part). The information specified in Sec.
60.5420a(b)(7)(iii)(A) and the information specified in either Sec.
60.5420a(b)(7)(iii)(B) or (C) may be provided as an alternative to the
requirements in Sec. 60.5397a(j).
(k) Alternative fugitive emissions requirements for the collection
of fugitive emissions components located at a compressor station in the
State of Pennsylvania. An affected facility, which is the collection of
fugitive emissions components, as defined in Sec. 60.5430a, located at
a compressor station in the State of Pennsylvania may elect to comply
with the monitoring, repair, and recordkeeping requirements in
Pennsylvania General Permit 5, section G, effective August 8, 2018, as
an alternative to complying with the requirements in Sec.
60.5397a(f)(2), (g)(2) through (4), (h), and (i), provided the
monitoring instrument used is an optical gas imaging or a Method 21
instrument (see appendix A-7 of this part). The information specified
in Sec. 60.5420a(b)(7)(iii)(A) and the information specified in either
Sec. 60.5420a(b)(7)(iii)(B) or (C) may be provided as an alternative
to the requirements in Sec. 60.5397a(j).
(l) Alternative fugitive emissions requirements for the collection
of fugitive emissions components located at a well site in the State of
Texas. An affected facility, which is the collection of fugitive
emissions components, as defined in Sec. 60.5430a, located at a well
site in the State of Texas may elect to comply with the monitoring,
repair, and recordkeeping requirements in the Air Quality Standard
Permit for Oil and Gas Handling and Production Facilities, section
(e)(6), effective November 8, 2012, or at 30 Texas Administrative Code
section 116.620, effective September 4, 2000, as an alternative to
complying with the requirements in Sec. 60.5397a(f)(2), (g)(2) through
(4), (h), and (i), provided the monitoring instrument used is optical
gas imaging or a Method 21 instrument (see appendix A-7 of this part)
with a leak definition and reading of 500 ppm or greater. Monitoring
must be conducted on at least a semiannual basis and skip periods may
not be applied. If using the requirement in this paragraph (l), the
information specified in Sec. 60.5420a(b)(7)(iii)(A) and (C) must be
provided in lieu of the requirements in Sec. 60.5397a(j).
(m) Alternative fugitive emissions requirements for the collection
of fugitive emissions components located at a compressor station in the
State of Texas. An affected facility, which is the collection of
fugitive emissions components, as defined in Sec. 60.5430a, located at
a compressor in the State of Texas may elect to comply with the
monitoring, repair, and recordkeeping requirements in the Air Quality
Standard Permit for Oil and Gas Handling and Production Facilities,
section (e)(6), effective November 8, 2012, or at 30 Texas
Administrative Code section 116.620, effective September 4, 2000, as an
alternative to complying with the requirements in Sec. 60.5397a(f)(2),
(g)(2) through (4), (h), and (i), provided the monitoring instrument
used is optical gas imaging or a Method 21 instrument (see appendix A-7
of this part) with a leak definition and reading of 500 ppm or greater.
Monitoring must be conducted on at least a semiannual basis and skip
[[Page 57445]]
periods may not be applied. If using the alternative in this paragraph
(m), the information specified in Sec. 60.5420a(b)(7)(iii)(A) and (C)
must be provided in lieu of the requirements in Sec. 60.5397a(j).
(n) Alternative fugitive emissions requirements for the collection
of fugitive emissions components located at a well site in the State of
Utah. An affected facility, which is the collection of fugitive
emissions components, as defined in Sec. 60.5430a, and is required to
control emissions in accordance with Utah Administrative Code R307-506
and R307-507, located at a well site in the State of Utah may elect to
comply with the monitoring, repair, and recordkeeping requirements in
the Utah Administrative Code R307-509, effective March 2, 2018, as an
alternative to complying with the requirements in Sec. 60.5397a(f)(2),
(g)(2) through (4), (h), and (i). If using the alternative in this
paragraph (n), the information specified in Sec.
60.5420a(b)(7)(iii)(A) and (C) must be provided in lieu of the
requirements in Sec. 60.5397a(j).
0
11. Section 60.5400a is amended by revising the introductory text and
paragraph (a) to read as follows:
Sec. 60.5400a What equipment leak VOC standards apply to affected
facilities at an onshore natural gas processing plant?
This section applies to the group of all equipment, except
compressors, within a process unit located at an onshore natural gas
processing plant.
(a) You must comply with the requirements of Sec. Sec. 60.482-
1a(a), (b), (d), and (e), 60.482-2a, and 60.482-4a through 60.482-11a,
except as provided in Sec. 60.5401a, as soon as practicable but no
later than 180 days after the initial startup of the process unit.
* * * * *
0
12. Section 60.5401a is amended by revising paragraphs (e) and (g) to
read as follows:
Sec. 60.5401a What are the exceptions to the equipment leak VOC
standards for affected facilities at onshore natural gas processing
plants?
* * * * *
(e) Pumps in light liquid service, valves in gas/vapor and light
liquid service, pressure relief devices in gas/vapor service, and
connectors in gas/vapor service and in light liquid service within a
process unit that is located in the Alaskan North Slope are exempt from
the monitoring requirements of Sec. Sec. 60.482-2a(a)(1), 60.482-
7a(a), and 60.482-11a(a) and paragraph (b)(1) of this section.
* * * * *
(g) An owner or operator may use the following provisions instead
of Sec. 60.485a(b)(2): A calibration drift assessment shall be
performed, at a minimum, at the end of each monitoring day. Check the
instrument using the same calibration gas(es) that were used to
calibrate the instrument before use. Follow the procedures specified in
Method 21 of appendix A-7 of this part, Section 10.1, except do not
adjust the meter readout to correspond to the calibration gas value.
Record the instrument reading for each scale used as specified in Sec.
60.486a(e)(8). For each scale, divide the arithmetic difference of the
most recent calibration and the post-test calibration response by the
corresponding calibration gas value, and multiply by 100 to express the
calibration drift as a percentage. If any calibration drift assessment
shows a negative drift of more than 10 percent from the most recent
calibration response, then all equipment monitored since the last
calibration with instrument readings below the appropriate leak
definition and above the leak definition multiplied by (100 minus the
percent of negative drift/divided by 100) must be re-monitored. If any
calibration drift assessment shows a positive drift of more than 10
percent from the most recent calibration response, then, at the owner/
operator's discretion, all equipment since the last calibration with
instrument readings above the appropriate leak definition and below the
leak definition multiplied by (100 plus the percent of positive drift/
divided by 100) may be re-monitored.
0
13. Section 60.5405a is amended by revising the section heading to read
as follows:
Sec. 60.5405a What standards apply to sweetening unit affected
facilities?
* * * * *
0
14. Section 60.5406a is amended by revising the section heading to read
as follows:
Sec. 60.5406a What test methods and procedures must I use for my
sweetening unit affected facilities?
* * * * *
0
15. Section 60.5407a is amended by revising the section heading and
paragraph (a) introductory text to read as follows:
Sec. 60.5407a What are the requirements for monitoring of emissions
and operations from my sweetening unit affected facilities?
(a) If your sweetening unit affected facility is subject to the
provisions of Sec. 60.5405a(a) or (b) you must install, calibrate,
maintain, and operate monitoring devices or perform measurements to
determine the following operations information on a daily basis:
* * * * *
0
16. Section 60.5410a is amended by:
0
a. Revising the section heading, introductory text, and paragraphs
(c)(1) and (e)(2) through (5);
0
b. Removing paragraph (e)(8);
0
c. Revising paragraphs (g) introductory text, (g)(3), (h), (j)
introductory text, and (j)(1); and
0
d. Adding paragraph (k).
The revisions and addition read as follows:
Sec. 60.5410a How do I demonstrate initial compliance with the
standards for my well, centrifugal compressor, reciprocating
compressor, pneumatic controller, pneumatic pump, storage vessel,
collection of fugitive emissions components at a well site, collection
of fugitive emissions components at a compressor station, and equipment
leaks at onshore natural gas processing plants and sweetening unit
affected facilities?
You must determine initial compliance with the standards for each
affected facility using the requirements in paragraphs (a) through (k)
of this section. Except as otherwise provided in this section, the
initial compliance period begins on August 2, 2016, or upon initial
startup, whichever is later, and ends no later than 1 year after the
initial startup date for your affected facility or no later than 1 year
after August 2, 2016. The initial compliance period may be less than 1
full year.
* * * * *
(c) * * *
(1) If complying with Sec. 60.5385a(a)(1) or (2), during the
initial compliance period, you must continuously monitor the number of
hours of operation or track the number of months since initial startup,
since August 2, 2016, or since the last rod packing replacement,
whichever is latest.
* * * * *
(e) * * *
(2) If you own or operate a pneumatic pump affected facility
located at a well site, you must reduce emissions in accordance with
Sec. 60.5393a(b)(1) or (2), and you must collect the pneumatic pump
emissions through a closed vent system that meets the requirements of
Sec. 60.5411a(d) and (e).
(3) If you own or operate a pneumatic pump affected facility
located at a well site and there is no control device or process
available on site, you must submit the certification in Sec.
60.5420a(b)(8)(i)(A).
(4) If you own or operate a pneumatic pump affected facility
located at a well
[[Page 57446]]
site, and you are unable to route to an existing control device or to a
process due to technical infeasibility, you must submit the
certification in Sec. 60.5420a(b)(8)(i)(B).
(5) If you own or operate a pneumatic pump affected facility
located at a well site and you reduce emissions in accordance with
Sec. 60.5393a(b)(4), you must collect the pneumatic pump emissions
through a closed vent system that meets the requirements of Sec.
60.5411a(d) and (e).
* * * * *
(g) For sweetening unit affected facilities, initial compliance is
demonstrated according to paragraphs (g)(1) through (3) of this
section.
* * * * *
(3) You must submit the results of paragraphs (g)(1) and (2) of
this section in the initial annual report submitted for your sweetening
unit affected facilities.
(h) For each storage vessel affected facility you must comply with
paragraphs (h)(1) through (6) of this section. Except as otherwise
provided in this paragraph (h), you must demonstrate initial compliance
by August 2, 2016, or within 60 days after startup, whichever is later.
(1) You must determine the potential VOC emission rate as specified
in Sec. 60.5365a(e).
(2) You must reduce VOC emissions in accordance with Sec.
60.5395a(a).
(3) If you use a control device to reduce emissions, you must equip
the storage vessel with a cover that meets the requirements of Sec.
60.5411a(b) and is connected through a closed vent system that meets
the requirements of Sec. 60.5411a(c) and (d) to a control device that
meets the conditions specified in Sec. 60.5412a(d) within 60 days
after startup for storage vessels constructed, modified, or
reconstructed at well sites with no other wells in production, or upon
startup for storage vessels constructed, modified, or reconstructed at
well sites with one or more wells already in production.
(4) You must conduct an initial performance test as required in
Sec. 60.5413a within 180 days after initial startup or within 180 days
of August 2, 2016, whichever is later, and you must comply with the
continuous compliance requirements in Sec. 60.5415a(e).
(5) You must submit the information required for your storage
vessel affected facility in your initial annual report as specified in
Sec. 60.5420a(b)(1) and (6).
(6) You must maintain the records required for your storage vessel
affected facility, as specified in Sec. 60.5420a(c)(5) through (8),
(12) through (14), and (17), as applicable, for each storage vessel
affected facility.
* * * * *
(j) To achieve initial compliance with the fugitive emission
standards for each collection of fugitive emissions components at a
well site and each collection of fugitive emissions components at a
compressor station you must comply with paragraphs (j)(1) through (5)
of this section.
(1) You must develop a fugitive emissions monitoring plan as
required in Sec. 60.5397a(b), (c), and (d).
* * * * *
(k) To demonstrate initial compliance with the requirement to
maintain the total well site production at or below 15 boe per day
based on a rolling 12-month average, as specified in Sec.
60.5397a(a)(2), you must comply with paragraphs (k)(1) through (3) of
this section.
(1) You must demonstrate that the total daily combined oil and
natural gas production for all wells at the well site is at or below 15
boe per day, based on a 12-month average from the previous 12 months of
operation, according to paragraphs (k)(1)(i) through (iii) of this
section within 45 days of the end of each month. The rolling 12-month
average of the total well site production determined according to
paragraph (k)(1)(iii) of this section must be at or below 15 boe per
day.
(i) Determine the daily combined oil and natural gas production for
each individual well at the well site for the month. To convert gas
production to equivalent barrels of oil, divide the cubic feet of gas
produced by 6,000.
(ii) Sum the daily production for each individual well at the well
site to determine the total well site production and divide by the
number of days in the month. This is the average daily total well site
production for the month.
(iii) Use the result determined in paragraph (k)(1)(ii) of this
section and average with the daily total well site production values
determined for each of the preceding 11 months to calculate the rolling
12-month average of the total well site production.
(2) You must maintain records as specified in Sec.
60.5420a(c)(15)(ii).
(3) You must submit compliance information in the initial and
subsequent annual reports as specified in Sec. 60.5420a(b)(7)(i)(C)
and (b)(7)(iv).
0
17. Section 60.5411a is amended by revising the introductory text and
paragraphs (a) introductory text, (a)(1), (c)(1) and (2), (d)(1), and
(e) to read as follows:
Sec. 60.5411a What additional requirements must I meet to determine
initial compliance for my covers and closed vent systems routing
emissions from centrifugal compressor wet seal fluid degassing systems,
reciprocating compressors, pneumatic pumps and storage vessels?
You must meet the applicable requirements of this section for each
cover and closed vent system used to comply with the emission standards
for your centrifugal compressor wet seal degassing systems,
reciprocating compressors, pneumatic pumps, and storage vessels.
(a) Closed vent system requirements for reciprocating compressors
and centrifugal compressor wet seal degassing systems.
(1) You must design the closed vent system to route all gases,
vapors, and fumes emitted from the reciprocating compressor rod packing
emissions collection system to a process. You must design the closed
vent system to route all gases, vapors, and fumes emitted from the
centrifugal compressor wet seal fluid degassing system to a process or
a control device that meets the requirements specified in Sec.
60.5412a(a) through (c).
* * * * *
(c) * * *
(1) You must design the closed vent system to route all gases,
vapors, and fumes emitted from the material in the storage vessel
affected facility to a control device that meets the requirements
specified in Sec. 60.5412a(c) and (d), or to a process.
(2) You must design and operate a closed vent system with no
detectable emissions, as determined using olfactory, visual, and
auditory inspections or optical gas imaging inspections as specified in
Sec. 60.5416a(c).
* * * * *
(d) * * *
(1) You must conduct an assessment that the closed vent system is
of sufficient design and capacity to ensure that all emissions from the
affected facility are routed to the control device and that the control
device is of sufficient design and capacity to accommodate all
emissions from the affected facility, and have it certified by a
qualified professional engineer or an in-house engineer with expertise
on the design and operation of the closed vent system in accordance
with paragraphs (d)(1)(i) and (ii) of this section.
(i) You must provide the following certification, signed and dated
by a qualified professional engineer or an in-house engineer: ``I
certify that the closed vent system design and capacity assessment was
prepared under my
[[Page 57447]]
direction or supervision. I further certify that the closed vent system
design and capacity assessment was conducted and this report was
prepared pursuant to the requirements of subpart OOOOa of 40 CFR part
60. Based on my professional knowledge and experience, and inquiry of
personnel involved in the assessment, the certification submitted
herein is true, accurate, and complete.''
(ii) The assessment shall be prepared under the direction or
supervision of a qualified professional engineer or an in-house
engineer who signs the certification in paragraph (d)(1)(i) of this
section.
* * * * *
(e) Closed vent system requirements for pneumatic pump affected
facilities using a control device or routing emissions to a process.
(1) You must design the closed vent system to route all gases,
vapors, and fumes emitted from the pneumatic pump to a control device
or a process.
(2) You must design and operate a closed vent system with no
detectable emissions, as demonstrated by Sec. 60.5416a(b), olfactory,
visual, and auditory inspections or optical gas imaging inspections as
specified in Sec. 60.5416a(d).
(3) You must meet the requirements specified in paragraphs
(e)(3)(i) and (ii) of this section if the closed vent system contains
one or more bypass devices that could be used to divert all or a
portion of the gases, vapors, or fumes from entering the control device
or to a process.
(i) Except as provided in paragraph (e)(3)(ii) of this section, you
must comply with either paragraph (e)(3)(i)(A) or (B) of this section
for each bypass device.
(A) You must properly install, calibrate, maintain, and operate a
flow indicator at the inlet to the bypass device that could divert the
stream away from the control device or process to the atmosphere that
sounds an alarm, or initiates notification via remote alarm to the
nearest field office, when the bypass device is open such that the
stream is being, or could be, diverted away from the control device or
process to the atmosphere. You must maintain records of each time the
alarm is activated according to Sec. 60.5420a(c)(8).
(B) You must secure the bypass device valve installed at the inlet
to the bypass device in the non-diverting position using a car-seal or
a lock-and-key type configuration.
(ii) Low leg drains, high point bleeds, analyzer vents, open-ended
valves or lines, and safety devices are not subject to the requirements
of paragraph (e)(3)(i) of this section.
0
18. Section 60.5412a is amended by revising paragraphs (a)(1)
introductory text, (a)(1)(iv), (c) introductory text, (d)(1)(iv)
introductory text, and (d)(1)(iv)(D) to read as follows:
Sec. 60.5412a What additional requirements must I meet for
determining initial compliance with control devices used to comply with
the emission standards for my centrifugal compressor, and storage
vessel affected facilities?
* * * * *
(a) * * *
(1) Each combustion device (e.g., thermal vapor incinerator,
catalytic vapor incinerator, boiler, or process heater) must be
designed and operated in accordance with one of the performance
requirements specified in paragraphs (a)(1)(i) through (iv) of this
section. If a boiler or process heater is used as the control device,
then you must introduce the vent stream into the flame zone of the
boiler or process heater.
* * * * *
(iv) You must introduce the vent stream with the primary fuel or
use the vent stream as the primary fuel in a boiler or process heater.
* * * * *
(c) For each carbon adsorption system used as a control device to
meet the requirements of paragraph (a)(2) or (d)(2) of this section,
you must manage the carbon in accordance with the requirements
specified in paragraphs (c)(1) and (2) of this section.
* * * * *
(d) * * *
(1) * * *
(iv) Each enclosed combustion control device (e.g., thermal vapor
incinerator, catalytic vapor incinerator, boiler, or process heater)
must be designed and operated in accordance with one of the performance
requirements specified in paragraphs (d)(1)(iv)(A) through (D) of this
section. If a boiler or process heater is used as the control device,
then you must introduce the vent stream into the flame zone of the
boiler or process heater.
* * * * *
(D) You must introduce the vent stream with the primary fuel or use
the vent stream as the primary fuel in a boiler or process heater.
* * * * *
0
19. Section 60.5413a is amended by revising paragraphs (d)(5)(i)
introductory text, (d)(9)(iii), and (d)(12) introductory text to read
as follows:
Sec. 60.5413a What are the performance testing procedures for
control devices used to demonstrate compliance at my centrifugal
compressor and storage vessel affected facilities?
* * * * *
(d) * * *
(5) * * *
(i) At the inlet gas sampling location, securely connect a fused
silica-coated stainless steel evacuated canister fitted with a flow
controller sufficient to fill the canister over a 3-hour period.
Filling must be conducted as specified in paragraphs (d)(5)(i)(A)
through (C) of this section.
* * * * *
(9) * * *
(iii) A 0-10 parts per million by volume-wet (ppmvw) (as propane)
measurement range is preferred; as an alternative a 0-30 ppmvw (as
propane) measurement range may be used.
* * * * *
(12) The owner or operator of a combustion control device model
tested under this paragraph (d)(12) must submit the information listed
in paragraphs (d)(12)(i) through (vi) of this section for each test run
in the test report required by this section in accordance with Sec.
60.5420a(b)(10). Owners or operators who claim that any of the
performance test information being submitted is confidential business
information (CBI) must submit a complete file including information
claimed to be CBI, on a compact disc, flash drive, or other commonly
used electronic storage media to the EPA. The electronic media must be
clearly marked as CBI and mailed to Attn: CBI Document Control Officer;
Office of Air Quality Planning and Standards (OAQPS), Room 521; 109
T.W. Alexander Drive; Research Triangle Park, NC 27711. The same file
with the CBI omitted must be submitted to [email protected].
* * * * *
0
20. Section 60.5415a is amended by:
0
a. Revising the section heading and paragraphs (b) introductory text
and (b)(3);
0
b. Removing paragraph (b)(4);
0
c. Revising paragraphs (c)(1), (g) introductory text, (h) introductory
text, and (h)(2); and
0
d. Adding paragraphs (i) and (j).
The revisions and additions read as follows:
[[Page 57448]]
Sec. 60.5415a How do I demonstrate continuous compliance with the
standards for my well, centrifugal compressor, reciprocating
compressor, pneumatic controller, pneumatic pump, storage vessel,
collection of fugitive emissions components at a well site, and
collection of fugitive emissions components at a compressor station
affected facilities, equipment leaks at onshore natural gas processing
plants and sweetening unit affected facilities?
* * * * *
(b) For each centrifugal compressor affected facility and each
pneumatic pump affected facility, you must demonstrate continuous
compliance according to paragraph (b)(3) of this section. For each
centrifugal compressor affected facility, you also must demonstrate
continuous compliance according to paragraphs (b)(1) and (2) of this
section.
* * * * *
(3) You must submit the annual reports required by Sec.
60.5420a(b)(1), (3), and (8) and maintain the records as specified in
Sec. 60.5420a(c)(2), (6) through (11), (16), and (17), as applicable.
* * * * *
(c) * * *
(1) You must continuously monitor the number of hours of operation
for each reciprocating compressor affected facility or track the number
of months since initial startup, since August 2, 2016, or since the
date of the most recent reciprocating compressor rod packing
replacement, whichever is latest.
* * * * *
(g) For each sweetening unit affected facility, you must
demonstrate continuous compliance with the standards for SO2
specified in Sec. 60.5405a(b) according to paragraphs (g)(1) and (2)
of this section.
* * * * *
(h) For each collection of fugitive emissions components at a well
site and each collection of fugitive emissions components at a
compressor station, you must demonstrate continuous compliance with the
fugitive emission standards specified in Sec. 60.5397a(a)(1) according
to paragraphs (h)(1) through (4) of this section.
* * * * *
(2) You must repair each identified source of fugitive emissions as
required in Sec. 60.5397a(h).
* * * * *
(i) For each collection of fugitive emissions components at a well
site complying with Sec. 60.5397a(a)(2), you must demonstrate
continuous compliance according to paragraphs (i)(1) through (4) of
this section. You must perform the calculations shown in paragraphs
(i)(1) through (4) of this section within 45 days of the end of each
month. The rolling 12-month average of the total well site production
determined according to paragraph (i)(4) of this section must be at or
below 15 boe per day.
(1) Begin with the most recent 12-month average.
(2) Determine the daily combined oil and natural gas production of
each individual well at the well site for the month. To convert gas
production to equivalent barrels of oil, divide the cubic feet of gas
produced by 6,000.
(3) Sum the daily production for each individual well at the well
site and divide by the number of days in the month. This is the average
daily total well site production for the month.
(4) Use the result determined in paragraph (i)(3) of this section
and average with the daily total well site production values determined
for each of the preceding 11 months to calculate the rolling 12-month
average of the total well site production.
(j) To demonstrate that the well site produced at or below 15 boe
per day for the first 30 days after startup of production as specified
in Sec. 60.5397a(3), you must calculate the daily production for each
individual well at the well site during the first 30 days of production
after completing any action listed in Sec. 60.5397a(a)(2)(i) through
(v) and sum the individual well production values to obtain the total
well site production. The calculation must be performed within 45 days
of the end of the first 30 days of production after completing any
action listed in Sec. 60.5397a(a)(2)(i) through (v). To convert gas
production to equivalent barrels of oil, divide cubic feet of gas
produced by 6,000.
0
21. Section 60.5416a is amended by revising the introductory text and
paragraphs (a) introductory text, (a)(4) introductory text, (b)
introductory text, (c) introductory text, (c)(1), and (c)(2)
introductory text, adding paragraph (c)(2)(iv), and revising paragraph
(d) to read as follows:
Sec. 60.5416a What are the initial and continuous cover and closed
vent system inspection and monitoring requirements for my centrifugal
compressor, reciprocating compressor, pneumatic pump, and storage
vessel affected facilities?
For each closed vent system or cover at your centrifugal
compressor, reciprocating compressor, pneumatic pump, and storage
vessel affected facilities, you must comply with the applicable
requirements of paragraphs (a) through (d) of this section.
(a) Inspections for closed vent systems and covers installed on
each centrifugal compressor or reciprocating compressor affected
facility. Except as provided in paragraphs (b)(11) and (12) of this
section, you must inspect each closed vent system according to the
procedures and schedule specified in paragraphs (a)(1) and (2) of this
section, inspect each cover according to the procedures and schedule
specified in paragraph (a)(3) of this section, and inspect each bypass
device according to the procedures of paragraph (a)(4) of this section.
* * * * *
(4) For each bypass device, except as provided for in Sec.
60.5411a(a)(3)(ii), you must meet the requirements of paragraph
(a)(4)(i) or (ii) of this section.
* * * * *
(b) No detectable emissions test methods and procedures. If you are
required to conduct an inspection of a closed vent system or cover at
your centrifugal compressor or reciprocating compressor affected
facility as specified in paragraph (a)(1), (2), or (3) of this section,
you must meet the requirements of paragraphs (b)(1) through (13) of
this section.
* * * * *
(c) Cover and closed vent system inspections for storage vessel
affected facilities. If you install a control device or route emissions
to a process, you must comply with the inspection and recordkeeping
requirements for each closed vent system and cover as specified in
paragraphs (c)(1) and (2) of this section. You must also comply with
the requirements of paragraphs (c)(3) through (7) of this section.
(1) Closed vent system inspections. For each closed vent system,
you must conduct an inspection as specified in paragraphs (c)(1)(i)
through (iii) or paragraph (c)(1)(iv) of this section.
(i) You must maintain records of the inspection results as
specified in Sec. 60.5420a(c)(6).
(ii) Conduct olfactory, visual, and auditory inspections at least
once every calendar month for defects that could result in air
emissions. Defects include, but are not limited to, visible cracks,
holes, or gaps in piping; loose connections; liquid leaks; or broken or
missing caps or other closure devices.
(iii) Monthly inspections must be separated by at least 14 calendar
days.
(iv) Conduct optical gas imaging inspections for any visible
emissions at the same frequency as the frequency for the collection of
fugitive emissions components located at the same type of site, as
specified in Sec. 60.5397a(g)(1).
[[Page 57449]]
(2) Cover inspections. For each cover, you must conduct inspections
as specified in paragraphs (c)(2)(i) through (iii) or paragraph
(c)(2)(iv) of this section.
* * * * *
(iv) Conduct optical gas imaging inspections for any visible
emissions at the same frequency as the frequency for the collection of
fugitive emissions components located at the same type of site, as
specified in Sec. 60.5397a(g)(1).
* * * * *
(d) Closed vent system inspections for pneumatic pump affected
facilities. If you install a control device or route emissions to a
process, you must comply with the inspection and recordkeeping
requirements for each closed vent system as specified in paragraph
(d)(1) of this section. You must also comply with the requirements of
paragraphs (c)(3) through (7) of this section.
(1) For each closed vent system, you must conduct an inspection as
specified in paragraphs (d)(1)(i) through (iii), paragraph (d)(1)(iv),
or paragraph (d)(1)(v) of this section.
(i) You must maintain records of the inspection results as
specified in Sec. 60.5420a(c)(6).
(ii) Conduct olfactory, visual, and auditory inspections at least
once every calendar month for defects that could result in air
emissions. Defects include, but are not limited to, visible cracks,
holes, or gaps in piping; loose connections; liquid leaks; or broken or
missing caps or other closure devices.
(iii) Monthly inspections must be separated by at least 14 calendar
days.
(iv) Conduct optical gas imaging inspections for any visible
emissions at the same frequency as the frequency for the collection of
fugitive components located at the same type of site, as specified in
Sec. 60.5397a(g)(1).
(v) Conduct inspections as specified in paragraphs (a)(1) and (2)
of this section.
(2) [Reserved]
0
22. Section 60.5417a is amended by revising the introductory text and
paragraph (a) to read as follows:
Sec. 60.5417a What are the continuous control device monitoring
requirements for my centrifugal compressor and storage vessel affected
facilities?
You must meet the applicable requirements of this section to
demonstrate continuous compliance for each control device used to meet
emission standards for your storage vessel affected facility or
centrifugal compressor affected facility.
(a) For each control device used to comply with the emission
reduction standard for centrifugal compressor affected facilities in
Sec. 60.5380a(a)(1), you must install and operate a continuous
parameter monitoring system for each control device as specified in
paragraphs (c) through (g) of this section, except as provided for in
paragraph (b) of this section. If you install and operate a flare in
accordance with Sec. 60.5412a(a)(3), you are exempt from the
requirements of paragraphs (e) and (f) of this section. If you install
and operate an enclosed combustion device or control device which is
not specifically listed in paragraph (d) of this section, you must
demonstrate continuous compliance according to paragraphs (h)(1)
through (4) of this section.
* * * * *
0
23. Revise Sec. 60.5420a to read as follows:
Sec. 60.5420a What are my notification, reporting, and recordkeeping
requirements?
(a) Notifications. You must submit the notifications according to
paragraphs (a)(1) and (2) of this section if you own or operate one or
more of the affected facilities specified in Sec. 60.5365a that was
constructed, modified, or reconstructed during the reporting period.
(1) If you own or operate an affected facility that is the group of
all equipment within a process unit at an onshore natural gas
processing plant, or a sweetening unit, you must submit the
notifications required in Sec. Sec. 60.7(a)(1), (3), and (4) and
60.15(d). If you own or operate a well, centrifugal compressor,
reciprocating compressor, pneumatic controller, pneumatic pump, storage
vessel, collection of fugitive emissions components at a well site, or
collection of fugitive emissions components at a compressor station,
you are not required to submit the notifications required in Sec. Sec.
60.7(a)(1), (3), and (4) and 60.15(d).
(2)(i) If you own or operate a well affected facility, you must
submit a notification to the Administrator no later than 2 days prior
to the commencement of each well completion operation listing the
anticipated date of the well completion operation. The notification
shall include contact information for the owner or operator; the United
States Well Number; the latitude and longitude coordinates for each
well in decimal degrees to an accuracy and precision of five (5)
decimals of a degree using the North American Datum of 1983; and the
planned date of the beginning of flowback. You may submit the
notification in writing or in electronic format.
(ii) If you are subject to state regulations that require advance
notification of well completions and you have met those notification
requirements, then you are considered to have met the advance
notification requirements of paragraph (a)(2)(i) of this section.
(3) An owner or operator electing to comply with the provisions of
Sec. 60.5399a shall notify the Administrator of the alternative
fugitive emissions standard selected within the annual report, as
specified in paragraph (b)(7) of this section.
(b) Reporting requirements. You must submit annual reports
containing the information specified in paragraphs (b)(1) through (8)
and (12) of this section and performance test reports as specified in
paragraph (b)(9) or (10) of this section, if applicable. You must
submit annual reports following the procedure specified in paragraph
(b)(11) of this section. The initial annual report is due no later than
90 days after the end of the initial compliance period as determined
according to Sec. 60.5410a. Subsequent annual reports are due no later
than same date each year as the initial annual report. If you own or
operate more than one affected facility, you may submit one report for
multiple affected facilities provided the report contains all of the
information required as specified in paragraphs (b)(1) through (8) and
(12) of this section. Annual reports may coincide with title V reports
as long as all the required elements of the annual report are included.
You may arrange with the Administrator a common schedule on which
reports required by this part may be submitted as long as the schedule
does not extend the reporting period.
(1) The general information specified in paragraphs (b)(1)(i)
through (iv) of this section is required for all reports.
(i) The company name, facility site name associated with the
affected facility, U.S. Well ID or U.S. Well ID associated with the
affected facility, if applicable, and address of the affected facility.
If an address is not available for the site, include a description of
the site location and provide the latitude and longitude coordinates of
the site in decimal degrees to an accuracy and precision of five (5)
decimals of a degree using the North American Datum of 1983.
(ii) An identification of each affected facility being included in
the annual report.
(iii) Beginning and ending dates of the reporting period.
(iv) A certification by a certifying official of truth, accuracy,
and completeness. This certification shall
[[Page 57450]]
state that, based on information and belief formed after reasonable
inquiry, the statements and information in the document are true,
accurate, and complete.
(2) For each well affected facility that is subject to Sec.
60.5375a(a) or (f), the records of each well completion operation
conducted during the reporting period, including the information
specified in paragraphs (b)(2)(i) through (xiv) of this section, if
applicable. In lieu of submitting the records specified in paragraphs
(b)(2)(i) through (xiv) of this section, the owner or operator may
submit a list of each well completion with hydraulic fracturing
completed during the reporting period, and the digital photograph
required by paragraph (c)(1)(v) of this section for each well
completion. For each well affected facility that routes flowback
entirely through one or more production separators, only the records
specified in paragraphs (b)(2)(i) through (iv) and (vi) of this section
are required to be reported. For periods where salable gas is unable to
be separated, the records specified in paragraphs (b)(2)(iv) and (viii)
through (xii) of this section must also be reported, as applicable. For
each well affected facility that is subject to Sec. 60.5375a(g), the
record specified in paragraph (b)(2)(xv) of this section is required to
be reported.
(i) Well Completion ID.
(ii) Latitude and longitude of the well in decimal degrees to an
accuracy and precision of five (5) decimals of a degree using North
American Datum of 1983.
(iii) U.S. Well ID.
(iv) The date and time of the onset of flowback following hydraulic
fracturing or refracturing or identification that the well immediately
starts production.
(v) The date and time of each attempt to direct flowback to a
separator as required in Sec. 60.5375a(a)(1)(ii).
(vi) The date and time that the well was shut in and the flowback
equipment was permanently disconnected, or the startup of production.
(vii) The duration (in hours) of flowback.
(viii) The duration (in hours) of recovery and disposition of
recovery (i.e., routed to the gas flow line or collection system, re-
injected into the well or another well, used as an onsite fuel source,
or used for another useful purpose that a purchased fuel or raw
material would serve).
(ix) The duration (in hours) of combustion.
(x) The duration (in hours) of venting.
(xi) The specific reasons for venting in lieu of capture or
combustion.
(xii) For any deviations recorded as specified in paragraph
(c)(1)(ii) of this section, the date and time the deviation began, the
duration of the deviation, and a description of the deviation.
(xiii) For each well affected facility subject to Sec.
60.5375a(f), a record of the well type (i.e., wildcat well, delineation
well, or low pressure well (as defined Sec. 60.5430a)) and supporting
inputs and calculations, if applicable.
(xiv) For each well affected facility for which you claim an
exception under Sec. 60.5375a(a)(3), the specific exception claimed
and reasons why the well meets the claimed exception.
(xv) For each well affected facility with less than 300 scf of gas
per stock tank barrel of oil produced, the supporting analysis that was
performed in order the make that claim, including but not limited to,
GOR values for established leases and data from wells in the same basin
and field.
(3) For each centrifugal compressor affected facility, the
information specified in paragraphs (b)(3)(i) through (v) of this
section.
(i) An identification of each centrifugal compressor using a wet
seal system constructed, modified, or reconstructed during the
reporting period.
(ii) For each deviation that occurred during the reporting period
and recorded as specified in paragraph (c)(2) of this section, the date
and time the deviation began, the duration of the deviation, and a
description of the deviation.
(iii) If required to comply with Sec. 60.5380a(a)(2), the
information in paragraphs (b)(3)(iii)(A) through (C) of this section.
(A) Dates of each inspection required under Sec. 60.5416a(a) and
(b);
(B) Each defect or leak identified during each inspection, date of
repair or the date of anticipated repair if the repair is delayed; and
(C) Date and time of each bypass alarm or each instance the key is
checked out if you are subject to the bypass requirements of Sec.
60.5416a(a)(4).
(iv) If complying with Sec. 60.5380a(a)(1) with a control device
tested under Sec. 60.5413a(d) which meets the criteria in Sec.
60.5413a(d)(11) and (e), the information in paragraphs (b)(3)(iv)(A)
through (D) of this section.
(A) Identification of the compressor with the control device.
(B) Make, model, and date of purchase of the control device.
(C) For each instance where the inlet gas flow rate exceeds the
manufacturer's listed maximum gas flow rate, where there is no
indication of the presence of a pilot flame, or where visible emissions
exceeded 1 minute in any 15-minute period, include the date and time
the deviation began, the duration of the deviation, and a description
of the deviation.
(D) For each visible emissions test following return to operation
from a maintenance or repair activity, the date of the visible
emissions test, the length of the test, and the amount of time for
which visible emissions were present.
(v) If complying with Sec. 60.5380a(a)(1) with a control device
not tested under Sec. 60.5413a(d), identification of the compressor
with the tested control device, the date the performance test was
conducted, and pollutant(s) tested. Submit the performance test report
following the procedures specified in paragraph (b)(9) of this section.
(4) For each reciprocating compressor affected facility, the
information specified in paragraphs (b)(4)(i) through (iii) of this
section.
(i) The cumulative number of hours of operation or the number of
months since initial startup, since August 2, 2016, or since the
previous reciprocating compressor rod packing replacement, whichever is
latest. Alternatively, a statement that emissions from the rod packing
are being routed to a process through a closed vent system under
negative pressure.
(ii) If applicable, for each deviation that occurred during the
reporting period and recorded as specified in paragraph (c)(3)(iii) of
this section, the date and time the deviation began, duration of the
deviation and a description of the deviation.
(iii) If required to comply with Sec. 60.5385a(a)(3), the
information in paragraphs (b)(4)(iii)(A) through (C) of this section.
(A) Dates of each inspection required under Sec. 60.5416a(a) and
(b);
(B) Each defect or leak identified during each inspection, and date
of repair or date of anticipated repair if repair is delayed; and
(C) Date and time of each bypass alarm or each instance the key is
checked out if you are subject to the bypass requirements of Sec.
60.5416a(a)(4).
(5) For each pneumatic controller affected facility, the
information specified in paragraphs (b)(5)(i) through (iii) of this
section.
(i) An identification of each pneumatic controller constructed,
modified, or reconstructed during the reporting period, including the
month and year of installation, reconstruction or modification and
identification information that allows traceability to the records
required in paragraph (c)(4)(iii) or (iv) of this section.
[[Page 57451]]
(ii) If applicable, reason why the use of pneumatic controller
affected facilities with a natural gas bleed rate greater than the
applicable standard are required.
(iii) For each instance where the pneumatic controller was not
operated in compliance with the requirements specified in Sec.
60.5390a, a description of the deviation, the date and time the
deviation began, and the duration of the deviation.
(6) For each storage vessel affected facility, the information in
paragraphs (b)(6)(i) through (ix) of this section.
(i) An identification, including the location, of each storage
vessel affected facility for which construction, modification, or
reconstruction commenced during the reporting period. The location of
the storage vessel shall be in latitude and longitude coordinates in
decimal degrees to an accuracy and precision of five (5) decimals of a
degree using the North American Datum of 1983.
(ii) Documentation of the VOC emission rate determination according
to Sec. 60.5365a(e)(1) for each storage vessel that became an affected
facility during the reporting period or is returned to service during
the reporting period.
(iii) For each deviation that occurred during the reporting period
and recorded as specified in paragraph (c)(5) of this section, the date
and time the deviation began, duration of the deviation and a
description of the deviation.
(iv) A statement that you have met the requirements specified in
Sec. 60.5410a(h)(2) and (3).
(v) For each storage vessel constructed, modified, reconstructed,
or returned to service during the reporting period complying with Sec.
60.5395a(a)(2) with a control device tested under Sec. 60.5413a(d)
which meets the criteria in Sec. 60.5413a(d)(11) and (e), the
information in paragraphs (b)(6)(v)(A) through (D) of this section.
(A) Identification of the storage vessel with the control device.
(B) Make, model, and date of purchase of the control device.
(C) For each instance where the inlet gas flow rate exceeds the
manufacturer's listed maximum gas flow rate, where there is no
indication of the presence of a pilot flame, or where visible emissions
exceeded 1 minute in any 15-minute period, include the date and time
the deviation began, the duration of the deviation, and a description
of the deviation.
(D) For each visible emissions test following return to operation
from a maintenance or repair activity, the date of the visible
emissions test, the length of the test, and the amount of time for
which visible emissions were present.
(vi) If complying with Sec. 60.5395a(a)(2) with a control device
not tested under Sec. 60.5413a(d), identification of the storage
vessel with the tested control device, the date the performance test
was conducted, and pollutant(s) tested. Submit the performance test
report following the procedures specified in paragraph (b)(9) of this
section.
(vii) If required to comply with Sec. 60.5395a(b)(1), the
information in paragraphs (b)(6)(vii)(A) through (C) of this section.
(A) Dates of each inspection required under Sec. 60.5416a(c);
(B) Each defect or leak identified during each inspection, and date
of repair or date of anticipated repair if repair is delayed; and
(C) Date and time of each bypass alarm or each instance the key is
checked out if you are subject to the bypass requirements of Sec.
60.5416a(c)(3).
(viii) You must identify each storage vessel affected facility that
is removed from service during the reporting period as specified in
Sec. 60.5395a(c)(1)(ii), including the date the storage vessel
affected facility was removed from service.
(ix) You must identify each storage vessel affected facility
returned to service during the reporting period as specified in Sec.
60.5395a(c)(3), including the date the storage vessel affected facility
was returned to service.
(7) For the collection of fugitive emissions components at each
well site and the collection of fugitive emissions components at each
compressor station, report the information specified in paragraphs
(b)(7)(i) through (iii) of this section, as applicable.
(i)(A) Designation of the type of site (i.e., well site or
compressor station) at which the collection of fugitive emissions
components is located.
(B) For each collection of fugitive emissions components at a well
site that became an affected facility during the reporting period, you
must include the date of the startup of production or the date of the
first day of production after modification. For each collection of
fugitive emissions components at a compressor station that became an
affected facility during the reporting period, you must include the
date of startup or the date of modification.
(C) For each collection of fugitive emissions components at a well
site that meets the conditions specified in either Sec.
60.5397a(a)(1)(i) or (ii), you must specify the well site is a low
production well site and submit the total production for the well site.
(D) For each collection of fugitive emissions components at a well
site where during the reporting period you complete the removal of all
major production and processing equipment such that the well site
contains only one or more wellheads, you must include the date of the
change to status as a wellhead only well site.
(E) For each collection of fugitive emissions components at a well
site where you previously reported under paragraph (b)(7)(i)(C) of this
section the removal of all major production and processing equipment
and during the reporting period major production and processing
equipment is added back to the well site, the date that the first piece
of major production and processing equipment is added back to the well
site.
(ii) For each fugitive emissions monitoring survey performed during
the annual reporting period, the information specified in paragraphs
(b)(7)(ii)(A) through (G) of this section.
(A) Date of the survey.
(B) Monitoring instrument used.
(C) Any deviations from the monitoring plan elements under Sec.
60.5397a(c)(1), (2), and (7) and (c)(8)(i) or a statement that there
were no deviations from these elements of the monitoring plan.
(D) Number and type of components for which fugitive emissions were
detected.
(E) Number and type of fugitive emissions components that were not
repaired as required in Sec. 60.5397a(h).
(F) Number and type of fugitive emission components (including
designation as difficult-to-monitor or unsafe-to-monitor, if
applicable) on delay of repair and explanation for each delay of
repair.
(G) Date of planned shutdown(s) that occurred during the reporting
period if there are any components that have been placed on delay of
repair.
(iii) For each collection of fugitive emissions components at a
well site or collection of fugitive emissions components at a
compressor station complying with an alternative fugitive emissions
standard under Sec. 60.5399a, in lieu of the information specified in
paragraphs (b)(7)(i) and (ii) of this section, you must provide the
information specified in paragraphs (b)(7)(iii)(A) through (C) of this
section.
(A) The alternative standard with which you are complying.
(B) The site-specific reports specified by the specific alternative
fugitive emissions standard, submitted in the format in which they were
submitted to the state, local, or tribal authority. If the report is in
hard copy, you must scan
[[Page 57452]]
the document and submit it as an electronic attachment to the annual
report required in paragraph (b) of this section.
(C) If the report specified by the specific alternative fugitive
emissions standard is not site-specific, you must submit the
information specified in paragraphs (b)(7)(i) and (ii) of this section
for each individual site complying with the alternative standard.
(8) For each pneumatic pump affected facility, the information
specified in paragraphs (b)(8)(i) through (iv) of this section.
(i) For each pneumatic pump that is constructed, modified or
reconstructed during the reporting period, you must provide
certification that the pneumatic pump meets one of the conditions
described in paragraph (b)(8)(i)(A), (B), or (C) of this section.
(A) No control device or process is available on site.
(B) A control device or process is available on site and the owner
or operator has determined in accordance with Sec. 60.5393a(b)(5) that
it is technically infeasible to capture and route the emissions to the
control device or process.
(C) Emissions from the pneumatic pump are routed to a control
device or process. If the control device is designed to achieve less
than 95 percent emissions reduction, specify the percent emissions
reductions the control device is designed to achieve.
(ii) For any pneumatic pump affected facility which has been
previously reported as required under paragraph (b)(8)(i) of this
section and for which a change in the reported condition has occurred
during the reporting period, provide the identification of the
pneumatic pump affected facility and the date it was previously
reported and a certification that the pneumatic pump meets one of the
conditions described in paragraph (b)(8)(ii)(A), (B), (C), or (D) of
this section.
(A) A control device has been added to the location and the
pneumatic pump now reports according to paragraph (b)(8)(i)(C) of this
section.
(B) A control device has been added to the location and the
pneumatic pump affected facility now reports according to paragraph
(b)(8)(i)(B) of this section.
(C) A control device or process has been removed from the location
or otherwise is no longer available and the pneumatic pump affected
facility now report according to paragraph (b)(8)(i)(A) of this
section.
(D) A control device or process has been removed from the location
or is otherwise no longer available and the owner or operator has
determined in accordance with Sec. 60.5393a(b)(5) through an
engineering evaluation that it is technically infeasible to capture and
route the emissions to another control device or process.
(iii) For each deviation that occurred during the reporting period
and recorded as specified in paragraph (c)(16)(ii) of this section, the
date and time the deviation began, duration of the deviation, and a
description of the deviation.
(iv) If required to comply with Sec. 60.5393a(b), the information
in paragraphs (b)(8)(iv)(A) through (C) of this section.
(A) Dates of each inspection required under Sec. 60.5416a(d);
(B) Each defect or leak identified during each inspection, and date
of repair or date of anticipated repair if repair is delayed; and
(C) Date and time of each bypass alarm or each instance the key is
checked out if you are subject to the bypass requirements of Sec.
60.5416a(c)(3).
(9) Within 60 days after the date of completing each performance
test (see Sec. 60.8) required by this subpart, except testing
conducted by the manufacturer as specified in Sec. 60.5413a(d), you
must submit the results of the performance test following the procedure
specified in either paragraph (b)(9)(i) or (ii) of this section.
(i) For data collected using test methods supported by the EPA's
Electronic Reporting Tool (ERT) as listed on the EPA's ERT website
(https://www.epa.gov/electronic-reporting-air-emissions/electronic-reporting-tool-ert) at the time of the test, you must submit the
results of the performance test to the EPA via the Compliance and
Emissions Data Reporting Interface (CEDRI), except as outlined in this
paragraph (b)(9)(i). (CEDRI can be accessed through the EPA's Central
Data Exchange (CDX) (https://cdx.epa.gov/).) The EPA will make all the
information submitted through CEDRI available to the public without
further notice to you. Do not use CEDRI to submit information you claim
as confidential business information (CBI). Anything submitted using
CEDRI cannot later be claimed CBI. Performance test data must be
submitted in a file format generated through the use of the EPA's ERT
or an alternate electronic file format consistent with the extensible
markup language (XML) schema listed on the EPA's ERT website. Although
we do not expect persons to assert a claim of CBI, if you wish to
assert a CBI claim, you must submit a complete file generated through
the use of the EPA's ERT or an alternate electronic file consistent
with the XML schema listed on the EPA's ERT website, including
information claimed to be CBI, on a compact disc, flash drive, or other
commonly used electronic storage media to the EPA. The electronic media
must be clearly marked as CBI and mailed to U.S. EPA/OAQPS/CORE CBI
Office, Attention: Group Leader, Measurement Policy Group, MD C404-02,
4930 Old Page Rd., Durham, NC 27703. The same ERT or alternate file
with the CBI omitted must be submitted to the EPA via the EPA's CDX as
described earlier in this paragraph (b)(9)(i). All CBI claims must be
asserted at the time of submission. Furthermore, under CAA section
114(c), emissions data is not entitled to confidential treatment, and
the EPA is required to make emissions data available to the public.
Thus, emissions data will not be protected as CBI and will be made
publicly available.
(ii) For data collected using test methods that are not supported
by the EPA's ERT as listed on the EPA's ERT website at the time of the
test, you must submit the results of the performance test to the
Administrator at the appropriate address listed in Sec. 60.4.
(10) For combustion control devices tested by the manufacturer in
accordance with Sec. 60.5413a(d), an electronic copy of the
performance test results required by Sec. 60.5413a(d) shall be
submitted via email to [email protected] unless the test results
for that model of combustion control device are posted at the following
website: epa.gov/airquality/oilandgas/.
(11) You must submit reports to the EPA via CEDRI, except as
outlined in this paragraph (b)(11). (CEDRI can be accessed through the
EPA's CDX (https://cdx.epa.gov/).) The EPA will make all the
information submitted through CEDRI available to the public without
further notice to you. Do not use CEDRI to submit information you claim
as CBI. Anything submitted using CEDRI cannot later be claimed CBI. You
must use the appropriate electronic report in CEDRI for this subpart or
an alternate electronic file format consistent with the extensible
markup language (XML) schema listed on the CEDRI website (https://www.epa.gov/electronic-reporting-air-emissions/cedri/). If the
reporting form specific to this subpart is not available in CEDRI at
the time that the report is due, you must submit the report to the
Administrator at the appropriate address listed in Sec. 60.4. Once the
form has been available in CEDRI for at least 90 calendar days, you
must begin submitting all subsequent reports via CEDRI. The reports
must be submitted by the
[[Page 57453]]
deadlines specified in this subpart, regardless of the method in which
the reports are submitted. Although we do not expect persons to assert
a claim of CBI, if you wish to assert a CBI claim, submit a complete
report generated using the appropriate form in CEDRI or an alternate
electronic file consistent with the XML schema listed on the EPA's
CEDRI website, including information claimed to be CBI, on a compact
disc, flash drive, or other commonly used electronic storage medium to
the EPA. The electronic medium shall be clearly marked as CBI and
mailed to U.S. EPA/OAQPS/CORE CBI Office, Attention: Group Leader,
Fuels and Incineration Group, MD C404-02, 4930 Old Page Rd., Durham, NC
27703. The same file with the CBI omitted shall be submitted to the EPA
via CEDRI. All CBI claims must be asserted at the time of submission.
Furthermore, under CAA section 114(c), emissions data is not entitled
to confidential treatment, and the EPA is required to make emissions
data available to the public. Thus, emissions data will not be
protected as CBI and will be made publicly available.
(12) You must submit the certification signed by the qualified
professional engineer or in-house engineer according to Sec.
60.5411a(d) for each closed vent system routing to a control device or
process.
(13) If you are required to electronically submit a report through
CEDRI in the EPA's CDX, you may assert a claim of EPA system outage for
failure to timely comply with the reporting requirement. To assert a
claim of EPA system outage, you must meet the requirements outlined in
paragraphs (b)(13)(i) through (vii) of this section.
(i) You must have been or will be precluded from accessing CEDRI
and submitting a required report within the time prescribed due to an
outage of either the EPA's CEDRI or CDX systems.
(ii) The outage must have occurred within the period of time
beginning 5 business days prior to the date that the submission is due.
(iii) The outage may be planned or unplanned.
(iv) You must submit notification to the Administrator in writing
as soon as possible following the date you first knew, or through due
diligence should have known, that the event may cause or caused a delay
in reporting.
(v) You must provide to the Administrator a written description
identifying:
(A) The date(s) and time(s) when CDX or CEDRI was accessed and the
system was unavailable;
(B) A rationale for attributing the delay in reporting beyond the
regulatory deadline to the EPA system outage;
(C) Measures taken or to be taken to minimize the delay in
reporting; and
(D) The date by which you propose to report, or if you have already
met the reporting requirement at the time of the notification, the date
you reported.
(vi) The decision to accept the claim of EPA system outage and
allow an extension to the reporting deadline is solely within the
discretion of the Administrator.
(vii) In any circumstance, the report must be submitted
electronically as soon as possible after the outage is resolved.
(14) If you are required to electronically submit a report through
CEDRI in the EPA's CDX, the owner or operator may assert a claim of
force majeure for failure to timely comply with the reporting
requirement. To assert a claim of force majeure, you must meet the
requirements outlined in paragraphs (b)(14)(i) through (v) of this
section.
(i) You may submit a claim if a force majeure event is about to
occur, occurs, or has occurred or there are lingering effects from such
an event within the period of time beginning 5 business days prior to
the date the submission is due. For the purposes of this section, a
force majeure event is defined as an event that will be or has been
caused by circumstances beyond the control of the affected facility,
its contractors, or any entity controlled by the affected facility that
prevents you from complying with the requirement to submit a report
electronically within the time period prescribed. Examples of such
events are acts of nature (e.g., hurricanes, earthquakes, or floods),
acts of war or terrorism, or equipment failure or safety hazard beyond
the control of the affected facility (e.g., large scale power outage).
(ii) You must submit notification to the Administrator in writing
as soon as possible following the date you first knew, or through due
diligence should have known, that the event may cause or caused a delay
in reporting.
(iii) You must provide to the Administrator:
(A) A written description of the force majeure event;
(B) A rationale for attributing the delay in reporting beyond the
regulatory deadline to the force majeure event;
(C) Measures taken or to be taken to minimize the delay in
reporting; and
(D) The date by which you propose to report, or if you have already
met the reporting requirement at the time of the notification, the date
you reported.
(iv) The decision to accept the claim of force majeure and allow an
extension to the reporting deadline is solely within the discretion of
the Administrator.
(v) In any circumstance, the reporting must occur as soon as
possible after the force majeure event occurs.
(c) Recordkeeping requirements. You must maintain the records
identified as specified in Sec. 60.7(f) and in paragraphs (c)(1)
through (18) of this section. All records required by this subpart must
be maintained either onsite or at the nearest local field office for at
least 5 years. Any records required to be maintained by this subpart
that are submitted electronically via the EPA's CDX may be maintained
in electronic format.
(1) The records for each well affected facility as specified in
paragraphs (c)(1)(i) through (vii) of this section, as applicable. For
each well affected facility for which you make a claim that the well
affected facility is not subject to the requirements for well
completions pursuant to Sec. 60.5375a(g), you must maintain the record
in paragraph (c)(1)(vi) of this section, only. For each well affected
facility that routes flowback entirely through one or more production
separators that are designed to accommodate flowback, only records of
the United States Well Number, the latitude and longitude of the well
in decimal degrees to an accuracy and precision of five (5) decimals of
a degree using North American Datum of 1983, the Well Completion ID,
and the date and time of startup of production are required. For
periods where salable gas is unable to be separated, records of the
date and time of onset of flowback, the duration and disposition of
recovery, the duration of combustion and venting (if applicable),
reasons for venting (if applicable), and deviations are required.
(i) Records identifying each well completion operation for each
well affected facility.
(ii) Records of deviations in cases where well completion
operations with hydraulic fracturing were not performed in compliance
with the requirements specified in Sec. 60.5375a, including the date
and time the deviation began, the duration of the deviation, and a
description of the deviation.
(iii) You must maintain the records specified in paragraphs
(c)(1)(iii)(A) through (C) of this section.
(A) For each well affected facility required to comply with the
requirements of Sec. 60.5375a(a), you must record: The latitude and
longitude of the well in decimal degrees to an accuracy and precision
of five (5) decimals of a
[[Page 57454]]
degree using North American Datum of 1983; the United States Well
Number; the date and time of the onset of flowback following hydraulic
fracturing or refracturing; the date and time of each attempt to direct
flowback to a separator as required in Sec. 60.5375a(a)(1)(ii); the
date and time of each occurrence of returning to the initial flowback
stage under Sec. 60.5375a(a)(1)(i); and the date and time that the
well was shut in and the flowback equipment was permanently
disconnected, or the startup of production; the duration of flowback;
duration of recovery and disposition of recovery (i.e., routed to the
gas flow line or collection system, re-injected into the well or
another well, used as an onsite fuel source, or used for another useful
purpose that a purchased fuel or raw material would serve); duration of
combustion; duration of venting; and specific reasons for venting in
lieu of capture or combustion. The duration must be specified in hours.
In addition, for wells where it is technically infeasible to route the
recovered gas as specified in Sec. 60.5375a(a)(1)(ii), you must record
the reasons for the claim of technical infeasibility with respect to
all four options provided in Sec. 60.5375a(a)(1)(ii).
(B) For each well affected facility required to comply with the
requirements of Sec. 60.5375a(f), you must record: Latitude and
longitude of the well in decimal degrees to an accuracy and precision
of five (5) decimals of a degree using North American Datum of 1983;
the United States Well Number; the date and time of the onset of
flowback following hydraulic fracturing or refracturing; the date and
time that the well was shut in and the flowback equipment was
permanently disconnected, or the startup of production; the duration of
flowback; duration of recovery and disposition of recovery (i.e.,
routed to the gas flow line or collection system, re-injected into the
well or another well, used as an onsite fuel source, or used for
another useful purpose that a purchased fuel or raw material would
serve); duration of combustion; duration of venting; and specific
reasons for venting in lieu of capture or combustion. The duration must
be specified in hours.
(C) For each well affected facility for which you make a claim that
it meets the criteria of Sec. 60.5375a(a)(1)(iii)(A), you must
maintain the following:
(1) The latitude and longitude of the well in decimal degrees to an
accuracy and precision of five (5) decimals of a degree using North
American Datum of 1983; the United States Well Number; the date and
time of the onset of flowback following hydraulic fracturing or
refracturing; the date and time that the well was shut in and the
flowback equipment was permanently disconnected, or the startup of
production; the duration of flowback; duration of recovery and
disposition of recovery (i.e., routed to the gas flow line or
collection system, re-injected into the well or another well, used as
an onsite fuel source, or used for another useful purpose that a
purchased fuel or raw material would serve); duration of combustion;
duration of venting; and specific reasons for venting in lieu of
capture or combustion. The duration must be specified in hours.
(2) If applicable, records that the conditions of Sec.
60.5375a(a)(1)(iii)(A) are no longer met and that the well completion
operation has been stopped and a separator installed. The records shall
include the date and time the well completion operation was stopped and
the date and time the separator was installed.
(3) A record of the claim signed by the certifying official that no
liquids collection is at the well site. The claim must include a
certification by a certifying official of truth, accuracy, and
completeness. This certification shall state that, based on information
and belief formed after reasonable inquiry, the statements and
information in the document are true, accurate, and complete.
(iv) For each well affected facility for which you claim an
exception under Sec. 60.5375a(a)(3), you must record: The latitude and
longitude of the well in decimal degrees to an accuracy and precision
of five (5) decimals of a degree using North American Datum of 1983;
the United States Well Number; the specific exception claimed; the
starting date and ending date for the period the well operated under
the exception; and an explanation of why the well meets the claimed
exception.
(v) For each well affected facility required to comply with both
Sec. 60.5375a(a)(1) and (3), if you are using a digital photograph in
lieu of the records required in paragraphs (c)(1)(i) through (iv) of
this section, you must retain the records of the digital photograph as
specified in Sec. 60.5410a(a)(4).
(vi) For each well affected facility for which you make a claim
that the well affected facility is not subject to the well completion
standards according to Sec. 60.5375a(g), you must maintain:
(A) A record of the analysis that was performed in order the make
that claim, including but not limited to, GOR values for established
leases and data from wells in the same basin and field;
(B) the latitude and longitude of the well in decimal degrees to an
accuracy and precision of five (5) decimals of a degree using North
American Datum of 1983; the United States Well Number;
(C) A record of the claim signed by the certifying official. The
claim must include a certification by a certifying official of truth,
accuracy, and completeness. This certification shall state that, based
on information and belief formed after reasonable inquiry, the
statements and information in the document are true, accurate, and
complete.
(vii) For each well affected facility subject to Sec. 60.5375a(f),
a record of the well type (i.e., wildcat well, delineation well, or low
pressure well (as defined Sec. 60.5430a)) and supporting inputs and
calculations, if applicable.
(2) For each centrifugal compressor affected facility, you must
maintain records of deviations in cases where the centrifugal
compressor was not operated in compliance with the requirements
specified in Sec. 60.5380a, including a description of each deviation,
the date and time each deviation began and the duration of each
deviation. Except as specified in paragraph (c)(2)(viii) of this
section, you must maintain the records in paragraphs (c)(2)(i) through
(vii) of this section for each control device tested under Sec.
60.5413a(d) which meets the criteria in Sec. 60.5413a(d)(11) and (e)
and used to comply with Sec. 60.5380a(a)(1) for each centrifugal
compressor.
(i) Make, model, and serial number of purchased device.
(ii) Date of purchase.
(iii) Copy of purchase order.
(iv) Location of the centrifugal compressor and control device in
latitude and longitude coordinates in decimal degrees to an accuracy
and precision of five (5) decimals of a degree using the North American
Datum of 1983.
(v) Inlet gas flow rate.
(vi) Records of continuous compliance requirements in Sec.
60.5413a(e) as specified in paragraphs (c)(2)(vi)(A) through (E) of
this section.
(A) Records that the pilot flame is present at all times of
operation.
(B) Records that the device was operated with no visible emissions
except for periods not to exceed a total of 1 minute during any 15-
minute period.
(C) Records of the maintenance and repair log.
(D) Records of the visible emissions test following return to
operation from a maintenance or repair activity, including the date of
the visible emissions test, the length of the test, and
[[Page 57455]]
the amount of time for which visible emissions were present.
(E) Records of the manufacturer's written operating instructions,
procedures, and maintenance schedule to ensure good air pollution
control practices for minimizing emissions.
(vii) Records of deviations for instances where the inlet gas flow
rate exceeds the manufacturer's listed maximum gas flow rate, where
there is no indication of the presence of a pilot flame, or where
visible emissions exceeded 1 minute in any 15-minute period, including
a description of the deviation, the date and time the deviation began,
and the duration of the deviation.
(viii) As an alternative to the requirements of paragraph
(c)(2)(iv) of this section, you may maintain records of one or more
digital photographs with the date the photograph was taken and the
latitude and longitude of the centrifugal compressor and control device
imbedded within or stored with the digital file. As an alternative to
imbedded latitude and longitude within the digital photograph, the
digital photograph may consist of a photograph of the centrifugal
compressor and control device with a photograph of a separately
operating GPS device within the same digital picture, provided the
latitude and longitude output of the GPS unit can be clearly read in
the digital photograph.
(3) For each reciprocating compressor affected facility, you must
maintain the records in paragraphs (c)(3)(i) through (iii) of this
section.
(i) Records of the cumulative number of hours of operation or
number of months since initial startup, since August 2, 2016, or since
the previous replacement of the reciprocating compressor rod packing,
whichever is latest. Alternatively, a statement that emissions from the
rod packing are being routed to a process through a closed vent system
under negative pressure.
(ii) Records of the date and time of each reciprocating compressor
rod packing replacement, or date of installation of a rod packing
emissions collection system and closed vent system as specified in
Sec. 60.5385a(a)(3).
(iii) Records of deviations in cases where the reciprocating
compressor was not operated in compliance with the requirements
specified in Sec. 60.5385a, including the date and time the deviation
began, duration of the deviation, and a description of the deviation.
(4) For each pneumatic controller affected facility, you must
maintain the records identified in paragraphs (c)(4)(i) through (v) of
this section, as applicable.
(i) Records of the month and year of installation, reconstruction,
or modification, location in latitude and longitude coordinates in
decimal degrees to an accuracy and precision of five (5) decimals of a
degree using the North American Datum of 1983, identification
information that allows traceability to the records required in
paragraph (c)(4)(iii) or (iv) of this section and manufacturer
specifications for each pneumatic controller constructed, modified, or
reconstructed.
(ii) Records of the demonstration that the use of pneumatic
controller affected facilities with a natural gas bleed rate greater
than the applicable standard are required and the reasons why.
(iii) If the pneumatic controller is not located at a natural gas
processing plant, records of the manufacturer's specifications
indicating that the controller is designed such that natural gas bleed
rate is less than or equal to 6 standard cubic feet per hour.
(iv) If the pneumatic controller is located at a natural gas
processing plant, records of the documentation that the natural gas
bleed rate is zero.
(v) For each instance where the pneumatic controller was not
operated in compliance with the requirements specified in Sec.
60.5390a, a description of the deviation, the date and time the
deviation began, and the duration of the deviation.
(5) For each storage vessel affected facility, you must maintain
the records identified in paragraphs (c)(5)(i) through (vii) of this
section.
(i) If required to reduce emissions by complying with Sec.
60.5395a(a)(2), the records specified in Sec. Sec. 60.5420a(c)(6)
through (8) and 60.5416a(c)(6)(ii) and (c)(7)(ii). You must maintain
the records in paragraph (c)(5)(vi) of this section for each control
device tested under Sec. 60.5413a(d) which meets the criteria in Sec.
60.5413a(d)(11) and (e) and used to comply with Sec. 60.5395a(a)(2)
for each storage vessel.
(ii) Records of each VOC emissions determination for each storage
vessel affected facility made under Sec. 60.5365a(e) including
identification of the model or calculation methodology used to
calculate the VOC emission rate.
(iii) For each instance where the storage vessel was not operated
in compliance with the requirements specified in Sec. Sec. 60.5395a,
60.5411a, 60.5412a, and 60.5413a, as applicable, a description of the
deviation, the date and time each deviation began, and the duration of
the deviation.
(iv) For storage vessels that are skid-mounted or permanently
attached to something that is mobile (such as trucks, railcars, barges
or ships), records indicating the number of consecutive days that the
vessel is located at a site in the crude oil and natural gas production
source category. If a storage vessel is removed from a site and, within
30 days, is either returned to the site or replaced by another storage
vessel at the site to serve the same or similar function, then the
entire period since the original storage vessel was first located at
the site, including the days when the storage vessel was removed, will
be added to the count towards the number of consecutive days.
(v) You must maintain records of the identification and location in
latitude and longitude coordinates in decimal degrees to an accuracy
and precision of five (5) decimals of a degree using the North American
Datum of 1983 of each storage vessel affected facility.
(vi) Except as specified in paragraph (c)(5)(vi)(G) of this
section, you must maintain the records specified in paragraphs
(c)(5)(vi)(A) through (H) of this section for each control device
tested under Sec. 60.5413a(d) which meets the criteria in Sec.
60.5413a(d)(11) and (e) and used to comply with Sec. 60.5395a(a)(2)
for each storage vessel.
(A) Make, model, and serial number of purchased device.
(B) Date of purchase.
(C) Copy of purchase order.
(D) Location of the control device in latitude and longitude
coordinates in decimal degrees to an accuracy and precision of five (5)
decimals of a degree using the North American Datum of 1983.
(E) Inlet gas flow rate.
(F) Records of continuous compliance requirements in Sec.
60.5413a(e) as specified in paragraphs (c)(5)(vi)(F)(1) through (5) of
this section.
(1) Records that the pilot flame is present at all times of
operation.
(2) Records that the device was operated with no visible emissions
except for periods not to exceed a total of 1 minute during any 15-
minute period.
(3) Records of the maintenance and repair log.
(4) Records of the visible emissions test following return to
operation from a maintenance or repair activity, including the date of
the visible emissions test, the length of the test, and the amount of
time for which visible emissions were present.
(5) Records of the manufacturer's written operating instructions,
procedures, and maintenance schedule to ensure good air pollution
control practices for minimizing emissions.
[[Page 57456]]
(G) Records of deviations for instances where the inlet gas flow
rate exceeds the manufacturer's listed maximum gas flow rate, where
there is no indication of the presence of a pilot flame, or where
visible emissions exceeded 1 minute in any 15-minute period, including
a description of the deviation, the date and time the deviation began,
and the duration of the deviation.
(H) As an alternative to the requirements of paragraph
(c)(5)(vi)(D) of this section, you may maintain records of one or more
digital photographs with the date the photograph was taken and the
latitude and longitude of the storage vessel and control device
imbedded within or stored with the digital file. As an alternative to
imbedded latitude and longitude within the digital photograph, the
digital photograph may consist of a photograph of the storage vessel
and control device with a photograph of a separately operating GPS
device within the same digital picture, provided the latitude and
longitude output of the GPS unit can be clearly read in the digital
photograph.
(vii) Records of the date that each storage vessel affected
facility is removed from service and returned to service, as
applicable.
(6) Records of each closed vent system inspection required under
Sec. 60.5416a(a)(1) and (2) and (b) for centrifugal compressors and
reciprocating compressors, Sec. 60.5416a(c)(1) for storage vessels, or
Sec. 60.5416a(e) for pneumatic pumps as required in paragraphs
(c)(6)(i) through (iii) of this section.
(i) A record of each closed vent system inspection or no detectable
emissions monitoring survey. You must include an identification number
for each closed vent system (or other unique identification description
selected by you) and the date of the inspection.
(ii) For each defect or leak detected during inspections required
by Sec. 60.5416a(a)(1) and (2), (b), (c)(1), or (d), you must record
the location of the defect or leak, a description of the defect or the
maximum concentration reading obtained if using Method 21 of appendix
A-7 of this part, the date of detection, and the date the repair to
correct the defect or leak is completed.
(iii) If repair of the defect is delayed as described in Sec.
60.5416a(b)(10), you must record the reason for the delay and the date
you expect to complete the repair.
(7) A record of each cover inspection required under Sec.
60.5416a(a)(3) for centrifugal or reciprocating compressors or Sec.
60.5416a(c)(2) for storage vessels as required in paragraphs (c)(7)(i)
through (iii) of this section.
(i) A record of each cover inspection. You must include an
identification number for each cover (or other unique identification
description selected by you) and the date of the inspection.
(ii) For each defect detected during inspections required by Sec.
60.5416a(a)(3) or (c)(2), you must record the location of the defect, a
description of the defect, the date of detection, the corrective action
taken the repair the defect, and the date the repair to correct the
defect is completed.
(iii) If repair of the defect is delayed as described in Sec.
60.5416a(b)(10) or (c)(5), you must record the reason for the delay and
the date you expect to complete the repair.
(8) If you are subject to the bypass requirements of Sec.
60.5416a(a)(4) for centrifugal compressors or reciprocating
compressors, or Sec. 60.5416a(c)(3) for storage vessels or pneumatic
pumps, you must prepare and maintain a record of each inspection or a
record of each time the key is checked out or a record of each time the
alarm is sounded.
(9) [Reserved]
(10) For each centrifugal compressor or pneumatic pump affected
facility, records of the schedule for carbon replacement (as determined
by the design analysis requirements of Sec. 60.5413a(c)(2) or (3)) and
records of each carbon replacement as specified in Sec.
60.5412a(c)(1).
(11) For each centrifugal compressor affected facility subject to
the control device requirements of Sec. 60.5412a(a), (b), and (c),
records of minimum and maximum operating parameter values, continuous
parameter monitoring system data, calculated averages of continuous
parameter monitoring system data, results of all compliance
calculations, and results of all inspections.
(12) For each carbon adsorber installed on storage vessel affected
facilities, records of the schedule for carbon replacement (as
determined by the design analysis requirements of Sec. 60.5412a(d)(2))
and records of each carbon replacement as specified in Sec.
60.5412a(c)(1).
(13) For each storage vessel affected facility subject to the
control device requirements of Sec. 60.5412a(c) and (d), you must
maintain records of the inspections, including any corrective actions
taken, the manufacturers' operating instructions, procedures and
maintenance schedule as specified in Sec. 60.5417a(h)(3). You must
maintain records of EPA Method 22 of appendix A-7 of this part, section
11 results, which include: Company, location, company representative
(name of the person performing the observation), sky conditions,
process unit (type of control device), clock start time, observation
period duration (in minutes and seconds), accumulated emission time (in
minutes and seconds), and clock end time. You may create your own form
including the above information or use Figure 22-1 in EPA Method 22 of
appendix A-7 of this part. Manufacturer's operating instructions,
procedures and maintenance schedule must be available for inspection.
(14) A log of records as specified in Sec. 60.5412a(d)(1)(iii),
for all inspection, repair, and maintenance activities for each control
device failing the visible emissions test.
(15) For each collection of fugitive emissions components at a well
site and each collection of fugitive emissions components at a
compressor station, maintain the records identified in paragraphs
(c)(15)(i) through (viii) of this section.
(i) The date of the startup of production or the date of the first
day of production after modification for each collection of fugitive
emissions components at a well site and the date of startup or the date
of modification for each collection of fugitive emissions components at
a compressor station.
(ii) For each collection of fugitive emissions components at a well
site complying with Sec. 60.5397a(a)(2), you must maintain records of
the daily production and calculations demonstrating that the rolling
12-month average is at or below 15 boe per day no later than 12 months
before complying with Sec. 60.5397a(a)(2).
(iii) For each collection of fugitive emissions components at a
well site complying with Sec. 60.5397a(a)(3)(i), you must keep records
of daily production and calculations for the first 30 days after
completion of any action listed in Sec. 60.5397a(a)(2)(i) through (v)
demonstrating that total production from the well site is at or below
15 boe per day, or maintain records demonstrating the rolling 12-month
average total production for the well site is at or below 15 boe per
day.
(iv) For each collection of fugitive emissions components at a well
site complying with Sec. 60.5397a(a)(3)(ii), you must keep the records
specified in paragraphs (c)(15)(i), (vi), and (vii) of this section.
(v) For each collection of fugitive emissions components at a well
site where you complete the removal of all major production and
processing equipment such that the well site contains only one or more
wellheads, record the date the well site completes
[[Page 57457]]
the removal of all major production and processing equipment from the
well site, and, if the well site is still producing, record the well ID
or separate tank battery ID receiving the production from the well
site. If major production and processing equipment is subsequently
added back to the well site, record the date that the first piece of
major production and processing equipment is added back to the well
site.
(vi) The fugitive emissions monitoring plan as required in Sec.
60.5397a(b), (c), and (d).
(vii) The records of each monitoring survey as specified in
paragraphs (c)(15)(vii)(A) through (I) of this section.
(A) Date of the survey.
(B) Beginning and end time of the survey.
(C) Name of operator(s), training, and experience of the
operator(s) performing the survey.
(D) Monitoring instrument used.
(E) Fugitive emissions component identification when Method 21 of
appendix A-7 of this part is used to perform the monitoring survey.
(F) Ambient temperature, sky conditions, and maximum wind speed at
the time of the survey. For compressor stations, operating mode of each
compressor (i.e., operating, standby pressurized, and not operating-
depressurized modes) at the station at the time of the survey.
(G) Any deviations from the monitoring plan or a statement that
there were no deviations from the monitoring plan.
(H) Records of calibrations for the instrument used during the
monitoring survey.
(I) Documentation of each fugitive emission detected during the
monitoring survey, including the information specified in paragraphs
(c)(15)(vii)(I)(1) through (8) of this section.
(1) Location of each fugitive emission identified.
(2) Type of fugitive emissions component, including designation as
difficult-to-monitor or unsafe-to-monitor, if applicable.
(3) If Method 21 of appendix A-7 of this part is used for
detection, record the component ID and instrument reading.
(4) For each repair that cannot be made during the monitoring
survey when the fugitive emissions are initially found, a digital
photograph or video must be taken of that component or the component
must be tagged for identification purposes. The digital photograph must
include the date that the photograph was taken and must clearly
identify the component by location within the site (e.g., the latitude
and longitude of the component or by other descriptive landmarks
visible in the picture). The digital photograph or identification
(e.g., tag) may be removed after the repair is completed, including
verification of repair with the resurvey.
(5) The date of first attempt at repair of the fugitive emissions
component(s).
(6) The date of successful repair of the fugitive emissions
component, including the resurvey to verify repair and instrument used
for the resurvey.
(7) Identification of each fugitive emission component placed on
delay of repair and explanation for each delay of repair
(8) Date of planned shutdowns that occur while there are any
components that have been placed on delay of repair.
(viii) For each collection of fugitive emissions components at a
well site or collection of fugitive emissions components at a
compressor station complying with an alternative means of emissions
limitation under Sec. 60.5399a, you must maintain the records
specified by the specific alternative fugitive emissions standard for a
period of at least 5 years.
(16) For each pneumatic pump affected facility, you must maintain
the records identified in paragraphs (c)(16)(i) through (v) of this
section.
(i) Records of the date, location, and manufacturer specifications
for each pneumatic pump constructed, modified, or reconstructed.
(ii) Records of deviations in cases where the pneumatic pump was
not operated in compliance with the requirements specified in Sec.
60.5393a, including the date and time the deviation began, duration of
the deviation, and a description of the deviation.
(iii) Records on the control device used for control of emissions
from a pneumatic pump including the installation date, and
manufacturer's specifications. If the control device is designed to
achieve less than 95-percent emission reduction, maintain records of
the design evaluation or manufacturer's specifications which indicate
the percentage reduction the control device is designed to achieve.
(iv) Records substantiating a claim according to Sec.
60.5393a(b)(5) that it is technically infeasible to capture and route
emissions from a pneumatic pump to a control device or process;
including the certification according to Sec. 60.5393a(b)(5)(ii) and
the records of the engineering assessment of technical infeasibility
performed according to Sec. 60.5393a(b)(5)(iii).
(v) You must retain copies of all certifications, engineering
assessments, and related records for a period of five years and make
them available if directed by the implementing agency.
(17) For each closed vent system routing to a control device or
process, the records of the assessment conducted according to Sec.
60.5411a(d):
(i) A copy of the assessment conducted according to Sec.
60.5411a(d)(1);
(ii) A copy of the certification according to Sec.
60.5411a(d)(1)(i); and
(iii) The owner or operator shall retain copies of all
certifications, assessments, and any related records for a period of 5
years, and make them available if directed by the delegated authority.
(18) A copy of each performance test submitted under paragraph
(b)(9) of this section.
0
24. Section 60.5422a is amended by revising paragraphs (a), (b), and
(c) introductory text to read as follows:
Sec. 60.5422a What are my additional reporting requirements for my
affected facility subject to VOC requirements for onshore natural gas
processing plants?
(a) You must comply with the requirements of paragraphs (b) and (c)
of this section in addition to the requirements of Sec. 60.487a(a),
(b)(1) through (3) and (5), and (c)(2)(i) through (iv) and (vii)
through (viii). You must submit semiannual reports to the EPA via the
Compliance and Emissions Data Reporting Interface (CEDRI). (CEDRI can
be accessed through the EPA's Central Data Exchange (CDX) (https://cdx.epa.gov/).) Use the appropriate electronic report in CEDRI for this
subpart or an alternate electronic file format consistent with the
extensible markup language (XML) schema listed on the CEDRI website
(https://www3.epa.gov/ttn/chief/cedri/). If the reporting form specific
to this subpart is not available in CEDRI at the time that the report
is due, submit the report to the Administrator at the appropriate
address listed in Sec. 60.4. Once the form has been available in CEDRI
for at least 90 days, you must begin submitting all subsequent reports
via CEDRI. The report must be submitted by the deadline specified in
this subpart, regardless of the method in which the report is
submitted.
(b) An owner or operator must include the following information in
the initial semiannual report in addition to the information required
in Sec. 60.487a(b)(1) through (3) and (5): Number of pressure relief
devices subject to the requirements of Sec. 60.5401a(b) except for
those pressure relief devices designated for no detectable emissions
under the provisions of Sec. 60.482-4a(a) and those
[[Page 57458]]
pressure relief devices complying with Sec. 60.482-4a(c).
(c) An owner or operator must include the information specified in
paragraphs (c)(1) and (2) of this section in all semiannual reports in
addition to the information required in Sec. 60.487a(c)(2)(i) through
(iv) and (vii) through (viii):
* * * * *
0
25. Section 60.5423a is amended by revising the section heading and
paragraph (b) introductory text and adding paragraph (b)(3) to read as
follows:
Sec. 60.5423a What additional recordkeeping and reporting
requirements apply to my sweetening unit affected facilities?
* * * * *
(b) You must submit a report of excess emissions to the
Administrator in your annual report if you had excess emissions during
the reporting period. The procedures for submitting annual reports are
located in Sec. 60.5420a(b). For the purpose of these reports, excess
emissions are defined as specified in paragraphs (b)(1) and (2) of this
section. The report must contain the information specified in paragraph
(b)(3) of this section.
* * * * *
(3) For each period of excess emissions during the reporting
period, include the following information in your report:
(i) The date and time of commencement and completion of each period
of excess emissions;
(ii) The required minimum efficiency (Z) and the actual average
sulfur emissions reduction (R) for periods defined in paragraph (b)(1)
of this section; and
(iii) The appropriate operating temperature and the actual average
temperature of the gases leaving the combustion zone for periods
defined in paragraph (b)(2) of this section.
* * * * *
0
26. Section 60.5430a is amended by:
0
a. Revising the definitions for ``Capital expenditure'' and
``Certifying official'';
0
b. Adding in alphabetical order the definitions for ``Coil tubing
cleanout,'' ``Custody meter,'' ``Custody meter assembly,'' and ``First
attempt at repair'';
0
c. Revising the definitions for ``Flowback'' and ``Fugitive emissions
component'';
0
d. Removing the definitions for ``Gas processing plant process unit''
and ``Greenfield site'';
0
e. Revising the definition of ``Low pressure well'';
0
f. Adding in alphabetical order the definition for ``Major production
and processing equipment'';
0
g. Revising the definition for ``Maximum average daily throughput'';
0
h. Adding in alphabetical order the definitions for ``Plug drill-out,''
``Repaired,'' and ``Screenout'';
0
i. Revising the definition for ``Startup of production'';
0
j. Adding in alphabetical order the definitions for ``UIC Class I
oilfield disposal well'' and ``UIC Class II oilfield disposal well'';
0
k. Revising the definition for ``Well site''; and
0
l. Adding in alphabetical order the definition for ``Wellhead only well
site''.
The revisions and additions read as follows:
Sec. 60.5430a What definitions apply to this subpart?
* * * * *
Capital expenditure means, in addition to the definition in 40 CFR
60.2, an expenditure for a physical or operational change to an
existing facility that:
(1) Exceeds P, the product of the facility's replacement cost, R,
and an adjusted annual asset guideline repair allowance, A, as
reflected by the following equation: P = R x A, where:
(i) The adjusted annual asset guideline repair allowance, A, is the
product of the percent of the replacement cost, Y, and the applicable
basic annual asset guideline repair allowance, B, divided by 100 as
reflected by the following equation: A = Y x (B / 100);
(ii) The percent Y is determined from the following equation: Y =
(CPI of date of construction/most recently available CPI of date of
project), where the ``CPI-U, U.S. city average, all items'' must be
used for each CPI value; and
(iii) The applicable basic annual asset guideline repair allowance,
B, is 4.5.
* * * * *
Certifying official means one of the following:
(1) For a corporation: A president, secretary, treasurer, or vice-
president of the corporation in charge of a principal business
function, or any other person who performs similar policy or decision-
making functions for the corporation, or a duly authorized
representative of such person if the representative is responsible for
the overall operation of one or more manufacturing, production, or
operating facilities with an affected facility subject to this subpart
and either:
(i) The facilities employ more than 250 persons or have gross
annual sales or expenditures exceeding $25 million (in second quarter
1980 dollars); or
(ii) The Administrator is notified of such delegation of authority
prior to the exercise of that authority. The Administrator reserves the
right to evaluate such delegation;
(2) For a partnership (including but not limited to general
partnerships, limited partnerships, and limited liability partnerships)
or sole proprietorship: A general partner or the proprietor,
respectively. If a general partner is a corporation, the provisions of
paragraph (1) of this definition apply;
(3) For a municipality, State, Federal, or other public agency:
Either a principal executive officer or ranking elected official. For
the purposes of this part, a principal executive officer of a Federal
agency includes the chief executive officer having responsibility for
the overall operations of a principal geographic unit of the agency
(e.g., a Regional Administrator of EPA); or
(4) For affected facilities:
(i) The designated representative in so far as actions, standards,
requirements, or prohibitions under title IV of the CAA or the
regulations promulgated thereunder are concerned; or
(ii) The designated representative for any other purposes under
this part.
Coil tubing cleanout means the process where an operator runs a
string of coil tubing to the packed proppant within a well and jets the
well to dislodge the proppant and provide sufficient lift energy to
flow it to the surface. Coil tubing cleanout includes mechanical
methods to remove solids and/or debris from a wellbore.
* * * * *
Custody meter means the meter where natural gas or hydrocarbon
liquids are measured for sales, transfers, and/or royalty
determination.
Custody meter assembly means an assembly of fugitive emissions
components, including the custody meter, valves, flanges, and
connectors necessary for the proper operation of the custody meter.
* * * * *
First attempt at repair means, for the purposes of fugitive
emissions components, an action taken for the purpose of stopping or
reducing fugitive emissions to the atmosphere. First attempts at repair
include, but are not limited to, the following practices where
practicable and appropriate: Tightening bonnet bolts; replacing bonnet
bolts; tightening packing gland nuts; or injecting lubricant into
lubricated packing.
* * * * *
Flowback means the process of allowing fluids and entrained solids
to flow from a well following a treatment,
[[Page 57459]]
either in preparation for a subsequent phase of treatment or in
preparation for cleanup and returning the well to production. The term
flowback also means the fluids and entrained solids that emerge from a
well during the flowback process. The flowback period begins when
material introduced into the well during the treatment returns to the
surface following hydraulic fracturing or refracturing. The flowback
period ends when either the well is shut in and permanently
disconnected from the flowback equipment or at the startup of
production. The flowback period includes the initial flowback stage and
the separation flowback stage. Screenouts, coil tubing cleanouts, and
plug drill-outs are not considered part of the flowback process.
Fugitive emissions component means any component that has the
potential to emit fugitive emissions of VOC at a well site or
compressor station, including valves, connectors, pressure relief
devices, open-ended lines, flanges, covers and closed vent systems not
subject to Sec. 60.5411 or Sec. 60.5411a, thief hatches or other
openings on a controlled storage vessel not subject to Sec. 60.5395 or
Sec. 60.5395a, compressors, instruments, and meters. Devices that vent
as part of normal operations, such as natural gas-driven pneumatic
controllers or natural gas-driven pumps, are not fugitive emissions
components, insofar as the natural gas discharged from the device's
vent is not considered a fugitive emission. Emissions originating from
other than the device's vent, such as the thief hatch on a controlled
storage vessel, would be considered fugitive emissions.
* * * * *
Low pressure well means a well that satisfies at least one of the
following conditions:
(1) The static pressure at the wellhead following fracturing but
prior to the onset of flowback is less than the flow line pressure;
(2) The pressure of flowback fluid immediately before it enters the
flow line, as determined under Sec. 60.5432a, is less than the flow
line pressure; or
(3) Flowback of the fracture fluids will not occur without the use
of artificial lift equipment.
Major production and processing equipment means reciprocating or
centrifugal compressors, glycol dehydrators, heater/treaters,
separators, and storage vessels collecting crude oil, condensate,
intermediate hydrocarbon liquids, or produced water, for the purpose of
determining whether a well site is a wellhead only well site.
Maximum average daily throughput means the following:
(1) For storage vessels that commenced construction,
reconstruction, or modification after September 18, 2015, and on and
before November 16, 2020, maximum average daily throughput means the
earliest calculation of daily average throughput during the 30-day PTE
evaluation period employing generally accepted methods.
(2) For storage vessels that commenced construction,
reconstruction, or modification after November 16, 2020, maximum
average daily throughput means the earliest calculation of daily
average throughput, determined as described in paragraph (3) or (4) of
this definition, to an individual storage vessel over the days that
production is routed to that storage vessel during the 30-day PTE
evaluation period employing generally accepted methods specified in
Sec. 60.5365a(e)(1).
(3) If throughput to the individual storage vessel is measured on a
daily basis (e.g., via level gauge automation or daily manual gauging),
the maximum average daily throughput is the average of all daily
throughputs for days on which throughput was routed to that storage
vessel during the 30-day evaluation period; or
(4) If throughput to the individual storage vessel is not measured
on a daily basis (e.g., via manual gauging at the start and end of
loadouts), the maximum average daily throughput is the highest, of the
average daily throughputs, determined for any production period to that
storage vessel during the 30-day evaluation period, as determined by
averaging total throughput to that storage vessel over each production
period. A production period begins when production begins to be routed
to a storage vessel and ends either when throughput is routed away from
that storage vessel or when a loadout occurs from that storage vessel,
whichever happens first. Regardless of the determination methodology,
operators must not include days during which throughput is not routed
to an individual storage vessel when calculating maximum average daily
throughput for that storage vessel.
* * * * *
Plug drill-out means the removal of a plug (or plugs) that was used
to isolate different sections of the well.
* * * * *
Repaired means, for the purposes of fugitive emissions components,
that fugitive emissions components are adjusted, replaced, or otherwise
altered, in order to eliminate fugitive emissions as defined in Sec.
60.5397a and resurveyed as specified in Sec. 60.5397a(h)(4) and it is
verified that emissions from the fugitive emissions components are
below the applicable fugitive emissions definition.
* * * * *
Screenout means an attempt to clear proppant from the wellbore to
dislodge the proppant out of the well.
* * * * *
Startup of production means the beginning of initial flow following
the end of flowback when there is continuous recovery of salable
quality gas and separation and recovery of any crude oil, condensate,
or produced water, except as otherwise provided in this definition. For
the purposes of the fugitive monitoring requirements of Sec. 60.5397a,
startup of production means the beginning of the continuous recovery of
salable quality gas and separation and recovery of any crude oil,
condensate, or produced water.
* * * * *
UIC Class I oilfield disposal well means a well with a UIC Class I
permit that meets the definition in 40 CFR 144.6(a)(2) and receives
eligible fluids from oil and natural gas exploration and production
operations.
UIC Class II oilfield disposal well means a well with a UIC Class
II permit where wastewater resulting from oil and natural gas
production operations is injected into underground porous rock
formations not productive of oil or gas, and sealed above and below by
unbroken, impermeable strata.
* * * * *
Well site means one or more surface sites that are constructed for
the drilling and subsequent operation of any oil well, natural gas
well, or injection well. For purposes of the fugitive emissions
standards at Sec. 60.5397a, well site also means a separate tank
battery surface site collecting crude oil, condensate, intermediate
hydrocarbon liquids, or produced water from wells not located at the
well site (e.g., centralized tank batteries). Also, for the purposes of
the fugitive emissions standards at Sec. 60.5397a, a well site does
not include:
(1) UIC Class II oilfield disposal wells and disposal facilities;
(2) UIC Class I oilfield disposal wells; and
(3) The flange immediately upstream of the custody meter assembly
and equipment, including fugitive emissions components, located
downstream of this flange.
* * * * *
Wellhead only well site means, for the purposes of the fugitive
emissions standards at Sec. 60.5397a, a well site that contains one or
more wellheads and no
[[Page 57460]]
major production and processing equipment.
* * * * *
0
27. Table 3 to subpart OOOOa of part 60 is amended by revising the
entries for Sec. Sec. 60.8 and 60.15 to read as follows:
Table 3 to Subpart OOOOa of Part 60--Applicability of General Provisions to Subpart OOOOa
----------------------------------------------------------------------------------------------------------------
General provisions
citation Subject of citation Applies to subpart? Explanation
----------------------------------------------------------------------------------------------------------------
* * * * * * *
Sec. 60.8.............. Performance tests................ Yes.................... Except that the format of
performance test reports
is described in Sec.
60.5420a(b). Performance
testing is required for
control devices used on
storage vessels,
centrifugal compressors,
and pneumatic pumps,
except that performance
testing is not required
for a control device
used solely on pneumatic
pump(s).
* * * * * * *
Sec. 60.15............. Reconstruction................... Yes.................... Except that Sec.
60.15(d) does not apply
to wells, pneumatic
controllers, pneumatic
pumps, centrifugal
compressors,
reciprocating
compressors, storage
vessels, or the
collection of fugitive
emissions components at
a well site or the
collection of fugitive
emissions components at
a compressor station.
* * * * * * *
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[FR Doc. 2020-18115 Filed 9-10-20; 8:45 am]
BILLING CODE 6560-50-P