[Federal Register Volume 86, Number 217 (Monday, November 15, 2021)]
[Proposed Rules]
[Pages 63110-63263]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2021-24202]
[[Page 63109]]
Vol. 86
Monday,
No. 217
November 15, 2021
Part II
Environmental Protection Agency
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40 CFR Part 60
Standards of Performance for New, Reconstructed, and Modified Sources
and Emissions Guidelines for Existing Sources: Oil and Natural Gas
Sector Climate Review; Proposed Rule
Federal Register / Vol. 86 , No. 217 / Monday, November 15, 2021 /
Proposed Rules
[[Page 63110]]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 60
[EPA-HQ-OAR-2021-0317; FRL-8510-02-OAR]
RIN 2060-AV16
Standards of Performance for New, Reconstructed, and Modified
Sources and Emissions Guidelines for Existing Sources: Oil and Natural
Gas Sector Climate Review
AGENCY: Environmental Protection Agency (EPA).
ACTION: Proposed rule.
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SUMMARY: This document comprises three distinct groups of actions under
the Clean Air Act (CAA) which are collectively intended to
significantly reduce emissions of greenhouse gases (GHGs) and other
harmful air pollutants from the Crude Oil and Natural Gas source
category. First, the EPA proposes to revise the new source performance
standards (NSPS) for GHGs and volatile organic compounds (VOCs) for the
Crude Oil and Natural Gas source category under the CAA to reflect the
Agency's most recent review of the feasibility and cost of reducing
emissions from these sources. Second, the EPA proposes emissions
guidelines (EG) under the CAA, for states to follow in developing,
submitting, and implementing state plans to establish performance
standards to limit GHGs from existing sources (designated facilities)
in the Crude Oil and Natural Gas source category. Third, the EPA is
taking several related actions stemming from the joint resolution of
Congress, adopted on June 30, 2021 under the Congressional Review Act
(CRA), disapproving the EPA's final rule titled, ``Oil and Natural Gas
Sector: Emission Standards for New, Reconstructed, and Modified Sources
Review,'' Sept. 14, 2020 (``2020 Policy Rule''). This proposal responds
to the President's January 20, 2021, Executive order (E.O.) titled
``Protecting Public Health and the Environment and Restoring Science to
Tackle the Climate Crisis,'' which directed the EPA to consider taking
the actions proposed here.
DATES:
Comments. Comments must be received on or before January 14, 2022.
Under the Paperwork Reduction Act (PRA), comments on the information
collection provisions are best assured of consideration if the Office
of Management and Budget (OMB) receives a copy of your comments on or
before December 15, 2021.
Public hearing: The EPA will hold a virtual public hearing on
November 30, 2021 and December 1, 2021. See SUPPLEMENTARY INFORMATION
for information on the hearing.
ADDRESSES: You may send comments, identified by Docket ID No. EPA-HQ-
OAR-2021-0317 by any of the following methods:
Federal eRulemaking Portal: https://www.regulations.gov/
(our preferred method). Follow the online instructions for submitting
comments.
Email: [email protected]. Include Docket ID No. EPA-
HQ-OAR-2021-0317 in the subject line of the message.
Fax: (202) 566-9744. Attention Docket ID No. EPA-HQ-OAR-
2021-0317.
Mail: U.S. Environmental Protection Agency, EPA Docket
Center, Docket ID No. EPA-HQ-OAR-2021-0317, Mail Code 28221T, 1200
Pennsylvania Avenue NW, Washington, DC 20460.
Hand/Courier Delivery: EPA Docket Center, WJC West
Building, Room 3334, 1301 Constitution Avenue NW, Washington, DC 20004.
The Docket Center's hours of operation are 8:30 a.m.-4:30 p.m., Monday-
Friday (except Federal holidays).
Instructions: All submissions received must include the Docket ID
No. for this rulemaking. Comments received may be posted without change
to https://www.regulations.gov/, including any personal information
provided. For detailed instructions on sending comments and additional
information on the rulemaking process, see the ``Public Participation''
heading of the SUPPLEMENTARY INFORMATION section of this document. 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. We encourage the public to submit
comments via https://www.regulations.gov/ or email, as there may be a
delay in processing mail and faxes. Hand deliveries and couriers may be
received by scheduled appointment only. For further information on EPA
Docket Center services and the current status, please visit us online
at https://www.epa.gov/dockets.
FOR FURTHER INFORMATION CONTACT: For questions about this proposed
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] or Ms. Amy Hambrick, Sector
Policies and Programs Division (E143-05), Office of Air Quality
Planning and Standards, Environmental Protection Agency, Research
Triangle Park, North Carolina 27711, telephone number: (919) 541-0964;
facsimile number: (919) 541-3470; email address: [email protected].
SUPPLEMENTARY INFORMATION:
Participation in virtual public hearing. Please note that the EPA
is deviating from its typical approach for public hearings, because the
President has declared a national emergency. Due to the current Centers
for Disease Control and Prevention (CDC) recommendations, as well as
state and local orders for social distancing to limit the spread of
COVID-19, the EPA cannot hold in-person public meetings at this time.
The public hearing will be held via virtual platform on November
30, 2021, and December 1, 2021, and will convene at 11:00 a.m. Eastern
Time (ET) and conclude at 9:00 p.m. ET each day. On each hearing day,
the EPA may close a session 15 minutes after the last pre-registered
speaker has testified if there are no additional speakers. The EPA will
announce further details at https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-industry. If the EPA receives a high
volume of registrations for the public hearing, we may continue the
public hearing on December 2, 2021. The EPA does not intend to publish
a document in the Federal Register announcing the potential addition of
a third day for the public hearing or any other updates to the
information on the hearing described in this document. Please monitor
https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-industry for any updates to the information described in this document,
including information about the public hearing. For information or
questions about the public hearing, please contact the public hearing
team at (888) 372-8699 or by email at [email protected].
The EPA will begin pre-registering speakers for the hearing upon
publication of this document in the Federal Register. The EPA will
accept registrations on an individual basis. To register to speak at
the virtual hearing, follow the directions at https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-industry or contact the
public hearing team at (888) 372-
[[Page 63111]]
8699 or by email at [email protected]. The last day to pre-
register to speak at the hearing will be November 24, 2021. Prior to
the hearing, the EPA will post a general agenda that will list pre-
registered speakers in approximate order at: https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-industry.
The EPA will make every effort to follow the schedule as closely as
possible on the day of the hearing; however, please plan for the
hearings to run either ahead of schedule or behind schedule.
Each commenter will have 5 minutes to provide oral testimony. The
EPA encourages commenters to provide the EPA with a copy of their oral
testimony electronically (via email) by emailing it to
[email protected] and [email protected]. The EPA also recommends
submitting the text of your oral testimony as written comments to the
rulemaking docket.
The EPA may ask clarifying questions during the oral presentations
but will not respond to the presentations at that time. Written
statements and supporting information submitted during the comment
period will be considered with the same weight as oral testimony and
supporting information presented at the public hearing.
If you require the services of an interpreter or a special
accommodation such as audio description, please pre-register for the
hearing with the public hearing team and describe your needs by
November 22, 2021. The EPA may not be able to arrange accommodations
without advanced notice.
Docket. The EPA has established a docket for this rulemaking under
Docket ID No. EPA-HQ-OAR-2021-0317. All documents in the docket are
listed in https://www.regulations.gov/. Although listed, some
information is not publicly available, e.g., Confidential Business
Information (CBI) 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. With the exception of such material, publicly available docket
materials are available electronically in https://www.regulations.gov/.
Instructions. Direct your comments to Docket ID No. EPA-HQ-OAR-
2021-0317. The EPA's policy is that all comments received will be
included in the public docket without change and may be made available
online at https://www.regulations.gov/, including any personal
information provided, unless the comment includes information claimed
to be CBI or other information whose disclosure is restricted by
statute. Do not submit information that you consider to be CBI or
otherwise protected through https://www.regulations.gov/ or email. This
type of information should be submitted by mail as discussed below.
The EPA may publish any comment received to its public docket.
Multimedia submissions (audio, video, etc.) must be accompanied by a
written comment. The written comment is considered the official comment
and should include discussion of all points you wish to make. The EPA
will generally not consider comments or comment contents located
outside of the primary submission (i.e., on the Web, cloud, or other
file sharing system). For additional submission methods, the full EPA
public comment policy, information about CBI or multimedia submissions,
and general guidance on making effective comments, please visit https://www.epa.gov/dockets/commenting-epa-dockets.
The https://www.regulations.gov/ website allows you to submit your
comment anonymously, which means the EPA will not know your identity or
contact information unless you provide it in the body of your comment.
If you send an email comment directly to the EPA without going through
https://www.regulations.gov/, your email address will be automatically
captured and included as part of the comment that is placed in the
public docket and made available on the internet. If you submit an
electronic comment, the EPA recommends that you include your name and
other contact information in the body of your comment and with any
digital storage media you submit. If the EPA cannot read your comment
due to technical difficulties and cannot contact you for clarification,
the EPA may not be able to consider your comment. Electronic files
should not include special characters or any form of encryption and be
free of any defects or viruses. For additional information about the
EPA's public docket, visit the EPA Docket Center homepage at https://www.epa.gov/dockets.
The EPA is temporarily suspending its Docket Center and Reading
Room for public visitors, 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. We
encourage the public to submit comments via https://www.regulations.gov/ as there may be a delay in processing mail and
faxes. Hand deliveries or couriers will be received by scheduled
appointment only. 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 CDC, local area health departments, and our Federal partners
so that we can respond rapidly as conditions change regarding COVID-19.
Submitting CBI. Do not submit information containing CBI to the EPA
through https://www.regulations.gov/ or email. Clearly mark the part or
all of the information that you claim to be CBI. For CBI information on
any digital storage media that you mail to the EPA, mark the outside of
the digital storage media as CBI and then identify electronically
within the digital storage media the specific information that is
claimed as CBI. In addition to one complete version of the comments
that includes information claimed as CBI, you must submit a copy of the
comments that does not contain the information claimed as CBI directly
to the public docket through the procedures outlined in Instructions
above. If you submit any digital storage media that does not contain
CBI, mark the outside of the digital storage media clearly that it does
not contain CBI. Information not marked as CBI will be included in the
public docket and the EPA's electronic public docket without prior
notice. Information marked as CBI will not be disclosed except in
accordance with procedures set forth in 40 CFR part 2. Send or deliver
information identified as CBI only to the following address: OAQPS
Document Control Officer (C404-02), OAQPS, U.S. Environmental
Protection Agency, Research Triangle Park, North Carolina 27711,
Attention Docket ID No. EPA-HQ-OAR-2021-0317. Note that written
comments containing CBI submitted by mail may be delayed and no hand
deliveries will be accepted.
Preamble acronyms and abbreviations. We use multiple acronyms and
terms in this preamble. While this list may not be exhaustive, to ease
the reading of this preamble and for reference purposes, the EPA
defines the following terms and acronyms here:
ACE Affordable Clean Energy rule
AEO Annual Energy Outlook
AMEL alternate means of emissions limitation
ANGA American Natural Gas Alliance
ANSI American National Standards Institute
APCD air pollution control devices
API American Petroleum Institute
ARPA-E Advanced Research Projects Agency-Energy
ASME American Society of Mechanical Engineers
[[Page 63112]]
ASTM American Society for Testing and Materials
AVO audio, visual, olfactory
BACT best achievable control technology
BOEM Bureau of Ocean Energy Management
BLM Bureau of Land Management
BMP best management practices
boe barrels of oil equivalents
BSER best system of emission reduction
BTEX benzene, toluene, ethylbenzene, and xylenes
CAA Clean Air Act
CBI Confidential Business Information
CDC Center for Disease Control
CDX EPA's Central Data Exchange
CEDRI Compliance and Emissions Data Reporting Interface
CFR Code of Federal Regulations
CH4 methane
cm centimeter
CPI consumer price index
CPI-U consumer price index urban
CO carbon monoxide
COPD chronic obstructive pulmonary disease
CO2 carbon dioxide
CO2 Eq. carbon dioxide equivalent
COA condition of approval
COS carbonyl sulfide
CRA Congressional Review Act
CS2 carbon disulfide
CVS closed vent systems
DC direct current
DOE Department of Energy
DOI Department of the Interior
DOT Department of Transportation
EAV equivalent annualized value
EDF Environmental Defense Fund
EG emission guidelines
ECOS Environmental Council of the States
EGU electricity generating units
EIA U.S. Energy Information Administration
EJ environmental justice
EO Executive Order
EPA Environmental Protection Agency
ERT Electronic Reporting Tool
FERC The U.S. Federal Energy Regulatory Commission
fpm feet per minute
GC gas chromatograph
GHGs greenhouse gases
GHGI Inventory of U.S. Greenhouse Gas Emissions and Sinks
GHGRP Greenhouse Gas Reporting Program
GRI Gas Research Institute
GWP global warning potential
HAP hazardous air pollutant(s)
HC hydrocarbons
HFC hydrofluorocarbons
H2S hydrogen sulfide
ICR Information Collection Request
IOGCC Interstate Oil and Gas Compact Commission
IPCC Intergovernmental Panel on Climate Change
IR infrared
IRFA initial regulatory flexibility analysis
kt kilotons
kg kilograms
low-e low emission
LDAR leak detection and repair
Mcf thousand cubic feet
MMT million metric tons
MRR monitoring, recordkeeping, and reporting
MW megawatt
NAAQS National Ambient Air Quality Standards
NAICS North American Industry Classification System
NCA4 2017-2018 Fourth National Climate Assessment
NEI National Emissions Inventory
NEMS National Energy Modeling System
NESHAP National Emissions Standards for Hazardous Air Pollutants
NGL natural gas liquid
NGO non-governmental organization
NOAA National Oceanic and Atmospheric Administration
NOX nitrogen oxides
NSPS new source performance standards
NTTAA National Technology Transfer and Advancement Act
OCSLA The Outer Continental Shelf Lands Act
OAQPS Office of Air Quality Planning and Standards
OIG Office of the Inspector General
OGI optical gas imaging
OMB Office of Management and Budget
PE professional engineer
PFCs perfluorocarbons
PHMSA Pipeline and Hazardous Materials Safety Administration
PM particulate matter
PM2.5 PM with a diameter of 2.5 micrometers or less
ppb parts per billion
ppm parts per million
PRA Paperwork Reduction Act
PRD pressure release device
PRV pressure release valve
PSD Prevention of Significant Deterioration
psig pounds per square inch gauge
PTE potential to emit
PV present value
REC reduced emissions completion
RFA Regulatory Flexibility Act
RIA Regulatory Impact Analysis
RTC response to comments
SBAR Small Business Advocacy Review
SC-CH4 social cost of methane
SCF significant contribution finding
scf standard cubic feet
scfh standard cubic feet per hour
scfm standard cubic feet per minute
SF6 sulfur hexafluoride
SIP State Implementation Plan
SO2 sulfur dioxide
SOX sulfur oxides
tpy tons per year
D.C. Circuit U.S. Court of Appeals for the District of Columbia
Circuit
TAR Tribal Authority Rule
TIP Tribal Implementation Plan
TSD technical support document
TTN Technology Transfer Network
UAS unmanned aircraft systems
UIC underground injection control
UMRA Unfunded Mandates Reform Act
U.S. United States
USGCRP U.S. Global Change Research Program
USGS U.S. Geologic Survey
VCS Voluntary Consensus Standards
VOC volatile organic compounds
VRD vapor recovery device
VRU vapor recovery unit
Organization of this document. The information in this preamble is
organized as follows:
I. Executive Summary
A. Purpose of the Regulatory Action
B. Summary of the Major Provisions of This Regulatory Action
C. Costs and Benefits
II. General Information
A. Does this action apply to me?
B. How do I obtain a copy of this document, background
information, other related information?
III. Air Emissions From the Crude Oil and Natural Gas Sector and
Public Health and Welfare
A. Impacts of GHGs, VOC and SO2 Emissions on Public
Health and Welfare
B. Oil and Natural Gas Industry and Its Emissions
IV. Statutory Background and Regulatory History
A. Statutory Background of CAA Sections 111(b), 111(d) and
General Implementing Regulations
B. What is the regulatory history and litigation background of
NSPS and EG for the oil and natural gas industry?
C. Effect of the CRA
V. Related Emissions Reduction Efforts
A. Related State Actions and Other Federal Actions Regulating
Oil and Natural Gas Sources
B. Industry and Voluntary Actions To Address Climate Change
VI. Environmental Justice Considerations, Implications, and
Stakeholder Outreach
A. Environmental Justice and the Impacts of Climate Change
B. Impacted Stakeholders
C. Outreach and Engagement
D. Environmental Justice Considerations
VII. Other Stakeholder Outreach
A. Educating the Public, Listening Sessions, and Stakeholder
Outreach
B. EPA Methane Detection Technology Workshop
C. How is this information being considered in this proposal?
VIII. Legal Basis for Proposal Scope
A. Recent History of the EPA's Regulation of Oil and Gas Sources
and Congress's Response
B. Implications of Congress's Disapproval of the 2020 Policy
Rule
C. Alternative Conclusion Affirming the Legal Interpretations in
the 2016 Rule
D. Impacts on Regulation of Methane Emissions From Existing
Sources
IX. Overview of Control and Control Costs
A. Control of Methane and VOC Emissions in the Crude Oil and
Natural Gas Source Category--Overview
B. How does EPA evaluate control costs in this action?
X. Summary of Proposed Action for NSPS OOOOa
A. Amendments to Fugitive Emissions Monitoring Frequency
B. Technical and Implementation Amendments
XI. Summary of Proposed NSPS OOOOb and EG OOOOc
A. Fugitive Emissions From Well Sites and Compressor Stations
[[Page 63113]]
B. Storage Vessels
C. Pneumatic Controllers
D. Well Liquids Unloading Operations
E. Reciprocating Compressors
F. Centrifugal Compressors
G. Pneumatic Pumps
H. Equipment Leaks at Natural Gas Processing Plants
I. Well Completions
J. Oil Wells With Associated Gas
K. Sweetening Units
L. Centralized Production Facilities
M. Recordkeeping and Reporting
N. Prevention of Significant Deterioration and Title V
Permitting
XII. Rationale for Proposed NSPS OOOOb and EG OOOOc
A. Proposed Standards for Fugitive Emissions From Well Sites and
Compressor Stations
B. Proposed Standards for Storage Vessels
C. Proposed Standards for Pneumatic Controllers
D. Proposed Standards for Well Liquids Unloading Operations
E. Proposed Standards for Reciprocating Compressors
F. Proposed Standards for Centrifugal Compressors
G. Proposed Standards for Pneumatic Pumps
H. Proposed Standards for Equipment Leaks at Natural Gas
Processing Plants
I. Proposed Standards for Well Completions
J. Proposed Standards for Oil Wells With Associated Gas
K. Proposed Standards for Sweetening Units
XIII. Solicitations for Comment on Additional Emission Sources and
Definitions
A. Abandoned Wells
B. Pigging Operations and Related Blowdown Activities
C. Tank Truck Loading
D. Control Device Efficiency and Operation
E. Definition of Hydraulic Fracturing
XIV. State, Tribal, and Federal Plan Development for Existing
Sources
A. Overview
B. Components of EG
C. Establishing Standards of Performance in State Plans
D. Components of State Plan Submission
E. Timing of State Plan Submissions and Compliance Times
F. EPA Action on State Plans and Promulgation of Federal Plans
G. Tribes and The Planning Process Under CAA Section 111(d)
XV. Prevention of Significant Deterioration and Title V Permitting
A. Overview
B. Applicability of Tailoring Rule Thresholds Under the PSD
Program
C. Implications for Title V Program
XVI. Impacts of This Proposed Rule
A. What are the air impacts?
B. What are the energy impacts?
C. What are the compliance costs?
D. What are the economic and employment impacts?
E. What are the benefits of the proposed standards?
XVII. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and
Executive Order 13563: Improving Regulation and Regulatory Review
B. Paperwork Reduction Act (PRA)
C. Regulatory Flexibility Act (RFA)
D. Unfunded Mandates Reform Act (UMRA)
E. Executive Order 13132: Federalism
F. Executive Order 13175: Consultation and Coordination With
Indian Tribal Governments
G. Executive Order 13045: Protection of Children From
Environmental Health Risks and Safety Risks
H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
I. National Technology Transfer and Advancement Act (NTTAA)
J. Executive Order 12898: Federal Actions To Address
Environmental Justice in Minority Populations and Low-Income
Populations
I. Executive Summary
A. Purpose of the Regulatory Action
This proposed rulemaking takes a significant step forward in
mitigating climate-destabilizing pollution and protecting human health
by reducing GHG and VOC emissions from the Oil and Natural Gas
Industry,\1\ specifically the Crude Oil and Natural Gas source
category.\2\ The Oil and Natural Gas Industry is the United States'
largest industrial emitter of methane, a highly potent GHG. Human
activity-related emissions of methane are responsible for about one
third of the warming due to well-mixed GHGs and constitute the second
most important warming agent arising from human activity after carbon
dioxide (a well-mixed gas is one with an atmospheric lifetime longer
than a year or two, which allows the gas to be mixed around the world,
meaning that the location of emission of the gas has little importance
in terms of its impacts). According to the Intergovernmental Panel on
Climate Change (IPCC), strong, rapid, and sustained methane reductions
are critical to reducing near-term disruption of the climate system and
are a vital complement to reductions in other GHGs that are needed to
limit the long-term extent of climate change and its destructive
impacts. The Oil and Natural Gas Industry also emits other harmful
pollutants in varying concentrations and amounts, including carbon
dioxide (CO2), VOC, sulfur dioxide (SO2),
nitrogen oxide (NOX), hydrogen sulfide (H2S),
carbon disulfide (CS2), and carbonyl sulfide (COS), as well
as benzene, toluene, ethylbenzene, and xylenes (this group is commonly
referred to as ``BTEX''), and n-hexane.
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\1\ The EPA characterizes the Oil and Natural Gas Industry
operations as being generally composed of four segments: (1)
Extraction and production of crude oil and natural gas (``oil and
natural gas production''), (2) natural gas processing, (3) natural
gas transmission and storage, and (4) natural gas distribution.
\2\ The EPA defines the Crude Oil and Natural Gas source
category to mean (1) 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 (2)
natural gas production, processing, transmission, and storage, which
include the well and extend to, but do not include, the local
distribution company custody transfer station. For purposes of this
proposed rulemaking, for crude oil, the EPA's focus is on operations
from the well to the point of custody transfer at a petroleum
refinery, while for natural gas, the focus is on all operations from
the well to the local distribution company custody transfer station
commonly referred to as the ``city-gate''.
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Under the authority of CAA section 111, this rulemaking proposes
comprehensive standards of performance for GHG emissions (in the form
of methane limitations) and VOC emissions for new, modified, and
reconstructed sources in the Crude Oil and Natural Gas source category,
including the production, processing, transmission and storage
segments. For designated facilities,\3\ this rulemaking proposes EG
containing presumptive standards for GHG in the form of methane
limitations. When finalized, States shall utilize these EG to submit to
the EPA plans that establish standards of performance for designated
facilities and provide for implementation and enforcement of such
standards. The EPA will provide support for States in developing their
plans to reduce methane emissions from designated facilities within the
Crude Oil and Natural Gas source category.
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\3\ The term ``designated facility'' means ``any existing
facility which emits a designated pollutant and which would be
subject to a standard of performance for that pollutant if the
existing facility were an affected facility.'' See 40 CFR 60.21a(b).
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The EPA is proposing these actions in accordance with its legal
obligations and authorities following a review directed by E.O. 13990,
``Protecting Public Health and the Environment and Restoring Science to
Tackle the Climate Crisis,'' issued on January 20, 2021. The EPA
intends for these proposed actions to address the far-reaching harmful
consequences and real economic costs of climate change. According to
the IPCC AR6 assessment, ``It is unequivocal that human influence has
warmed the atmosphere, ocean and land. Widespread and rapid changes in
the atmosphere, ocean, cryosphere and biosphere have occurred.'' The
IPCC AR6 assessment states these changes have led to increases in heat
waves and wildfire weather, reductions in air quality, more intense
hurricanes and
[[Page 63114]]
rainfall events, and rising sea level. These changes, along with future
projected changes, endanger the physical survival, health, economic
well-being, and quality of life of people living in the United States
(U.S.), especially those in the most vulnerable communities.
Methane is both the main component of natural gas and a potent GHG.
One ton of methane in the atmosphere has 80 times the warming impact of
a ton of CO2, and contributes to the creation of ground-
level ozone which is another greenhouse gas. Because methane has a
shorter lifetime than CO2, it has a smaller relative
impact--although still significantly greater than CO2--when
considering longer time periods. One standard metric is the 100-year
global warming potential (GWP), which is a measure of the climate
impact of emissions of one ton a greenhouse gas over 100 years relative
to the impact of the emissions of one ton of CO2. Even over
this long timeframe, methane has a 100-year GWP of almost 30. The IPCC
AR6 assessment found that ``Over time scales of 10 to 20 years, the
global temperature response to a year's worth of current emissions of
SLCFs (short lived climate forcer) is at least as large as that due to
a year's worth of CO2 emissions.'' \4\ The IPCC estimated
that, depending on the reference scenario, collective reductions in
these SLCFs (methane, ozone precursors, and HFCs) could reduce warming
by 0.2 degrees Celsius ([deg]C) (more than one-third of a degree
Fahrenheit ([deg]F) in 2040 and 0.8 [deg]C (almost 1.5 [deg]F) by the
end of the century, which is important in the context of keeping
warming to well below 2 [deg]C (3.6 [deg]F). As methane is the most
important SLCF, this makes methane mitigation one of the best
opportunities for reducing near term warming. Emissions from human
activities have already more than doubled atmospheric methane
concentrations since 1750, and that concentration has been growing
larger at record rates in recent years.\5\ In the absence of additional
reduction policies, methane emissions are projected to continue rising
through at least 2040.
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\4\ However, the IPCC AR6 assessment cautioned that ``The
effects of the SLCFs decay rapidly over the first few decades after
pulse emission. Consequently, on time scales longer than about 30
years, the net long-term temperature effects of sectors and regions
are dominated by CO2.''
\5\ Naik, V., S. Szopa, B. Adhikary, P. Artaxo, T. Berntsen,
W.D. Collins, S. Fuzzi, L. Gallardo, A. Kiendler 41 Scharr, Z.
Klimont, H. Liao, N. Unger, P. Zanis, 2021, Short-Lived Climate
Forcers. In: Climate Change 42 2021: The Physical Science Basis.
Contribution of Working Group I to the Sixth Assessment Report of
the 43 Intergovernmental Panel on Climate Change [Masson-Delmotte,
V., P. Zhai, A. Pirani, S.L. Connors, C. 44 P[eacute]an, S. Berger,
N. Caud, Y. Chen, L. Goldfarb, M.I. Gomis, M. Huang, K. Leitzell, E.
Lonnoy, J.B.R. 45 Matthews, T.K. Maycock, T. Waterfield, O.
Yelek[ccedil]i, R. Yu and B. Zhou (eds.)]. Cambridge University 46
Press. In Press.
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Methane's radiative efficiency means that immediate reductions in
methane emissions, including from sources in the Crude Oil and Natural
Gas source category, can help reduce near-term warming. As natural gas
is comprised primarily of methane, every natural gas leak, or
intentional release of natural gas through venting or other processes,
constitutes a release of methane. Reducing human-caused methane
emissions, such as controlling natural gas leaks and releases as
proposed in these actions, would contribute substantially to global
efforts to limit temperature rise, aiding efforts to remain well below
2 [deg]C above pre-industrial levels. See preamble section III for
further discussion on the Crude Oil and Natural Gas Emissions and
Climate Change, including discussion of the GHGs, VOCs, and
SO2 Emissions on Public Health and Welfare.
Methane and VOC emissions from the Crude Oil and Natural Gas source
category result from a variety of industry operations across the supply
chain. As natural gas moves through the necessarily interconnected
system of exploration, production, storage, processing, and
transmission that brings it from wellhead to commerce, emissions
primarily result from intentional venting, unintentional gas carry-
through (e.g., vortexing from separator drain, improper liquid level
settings, liquid level control valve on an upstream separator or
scrubber does not seat properly at the end of an automated liquid
dumping event, inefficient separation of gas and liquid phases occurs
upstream of tanks allowing some gas carry-through), routine
maintenance, unintentional fugitive emissions, flaring, malfunctions,
abnormal process conditions, and system upsets. These emissions are
associated with a range of specific equipment and practices, including
leaking valves, connectors, and other components at well sites and
compressor stations; leaks and vented emissions from storage vessels;
releases from natural gas-driven pneumatic pumps and controllers;
liquids unloading at well sites; and venting or under-performing
flaring of associated gas from oil wells. But technical innovations
have produced a range of technologies and best practices to monitor,
eliminate or minimize these emissions, which in many cases have the
benefit of reducing multiple pollutants at once and recovering saleable
product. These technologies and best practices have been deployed by
individual oil and natural gas companies, required by State
regulations, or reflected in regulations issued by the EPA and other
Federal agencies.
In this action, the EPA has taken a comprehensive analysis of the
available data from emission sources in the Crude Oil and Natural Gas
source category and the latest available information on control
measures and techniques to identify achievable, cost-effective measures
to significantly reduce emissions, consistent with the requirements of
section 111 of the CAA. If finalized and implemented, the actions
proposed in this rulemaking would lead to significant and cost-
effective reductions in climate and health-harming pollution and
encourage development and deployment of innovative technologies to
further reduce this pollution in the Crude Oil and Natural Gas source
category. The actions proposed in this rulemaking would:
Update, strengthen, and expand current requirements under
CAA section 111(b) for methane and VOC emissions from new, modified,
and reconstructed facilities,
establish new limits for methane, and VOC emissions from
new, modified, and reconstructed facilities that are not currently
regulated under CAA section 111(b),
establish the first nationwide EG for States to limit
methane pollution from existing designated facilities in the source
category under CAA section 111(d), and
take comment on additional sources of pollution that, with
understanding gained from more information, may offer opportunities for
emission reductions, which the EPA would present in a supplemental
rulemaking proposal under both CAA section 111(b) and (d).
In developing this proposal, the EPA drew on its own prior
experience in regulating sources in the Crude Oil and Natural Gas
source category under section 111 and other CAA programs; applied
lessons learned from States' regulatory efforts, the emission reduction
efforts of leading companies, and the EPA's long-standing voluntary
emission reduction programs; and reviewed the latest available
information about new and developing technologies, as well as, peer-
reviewed research from emission measurement campaigns across the U.S.
Further, the EPA undertook extensive pre-proposal outreach to the
public and to stakeholders, including three full days
[[Page 63115]]
of public listening sessions, roundtables with State energy and
environmental regulators, a two-day workshop on innovative methane
detection technologies, and a nonregulatory docket established in May
2021 to receive written comments. Through this outreach, the EPA heard
from diverse voices and perspectives including State and local
governments, Tribal nations, communities affected by oil and gas
pollution, environmental and public health organizations, and
representatives of the oil and natural gas industry, all of which
provided ideas and information that helped shape and inform this
proposal.
The EPA also considered community and environmental justice
implications in the development of this proposal and sought to ensure
equitable treatment and meaningful involvement of all people regardless
of race, color, national origin, or income in the process. The EPA
engaged and consulted representatives of frontline communities that are
directly affected by and particularly vulnerable to the climate and
health impacts of pollution from this source category through
interactions such as webinars, listening sessions and meetings. These
opportunities allowed the EPA to hear directly from the public,
especially overburdened and underserved communities, on the development
of the proposed rule and to factor these concerns into this proposal.
For example, in addition to establishing EG that extend fugitive
emission requirements to existing oil and natural gas facilities, the
EPA is proposing to expand leak detection programs already in effect
for new sources to include known sources of large emission events and
proposing to require more frequent monitoring at sites with more
emissions. The EPA is also taking comment on innovative mechanisms to
ensure compliance and minimize emissions, including the possibility of
providing a pathway for communities to detect and report large emitting
events that may require follow-up and mitigation by owners and
operators. The extensive pollution reduction measures in this proposal,
if finalized, would collectively reduce a suite of harmful pollutants
and their associated health impacts in communities adjacent to these
emission sources. Further, to help ensure that the needs and
perspectives of communities with environmental justice concerns are
considered as States develop plans to establish and implement standards
of performance for existing sources, the EPA is proposing to require
that States demonstrate they have undertaken meaningful outreach and
engagement with overburdened and underserved communities as part of
their State plan submissions under the EPA. A full discussion of the
Environmental Justice Considerations, Implications, and Stakeholder
Outreach can be found in section VI of the preamble. A full discussion
of Other Stakeholder Outreach is found in section VII of the preamble.
As described in more detail below, the EPA recognizes that several
States and other Federal agencies currently regulate the Oil and
Natural Gas Industry. The EPA also recognizes that these State and
other Federal agency regulatory programs have matured since the EPA
began implementing the current NSPS requirements in 2012 and 2016. The
EPA further acknowledges the technical innovations that the Oil and
Natural Gas Industry has made during the past decade; this industry
operates at a fast pace and changes constantly as technology evolves.
The EPA commends these efforts and recognizes States for their
innovative standards, alternative compliance options, and
implementation strategies, and intends these proposed actions to build
upon progress made by certain States and Federal agencies in reducing
GHG and VOC emissions. See preamble section V for fuller discussion of
Related State Actions and Other Federal Actions Regulating Oil and
Natural Gas Sources and Industry and Voluntary Actions to Address
Climate Change.
The EPA believes that a broad ensemble of mutually leveraging
efforts across all States and all Federal agencies is essential to
meaningfully address climate change effectively. As the Federal agency
with primary responsibility to protect human health and the
environment, the EPA has the unique responsibility and authority to
regulate harmful air pollutants emitted by the Crude Oil and Natural
Gas source category. The EPA recognizes that States and other Federal
agencies regulate in accordance with their respective legal authorities
and within their respective jurisdictions but collectively do not fully
and consistently address the range of sources and emission reduction
measures contained in this proposal. Direct Federal regulation of
methane from new, reconstructed, and modified sources in this category,
combined with approved State plans that are consistent with the EPA's
presumptive standards for designated facilities (existing sources),
will help reduce both climate- and other health-harming pollution from
a large number of sources that are either unregulated or from which
additional, cost-effective reductions are available, level the
regulatory playing field, and help promote technological innovation.
Throughout this action, unless noted otherwise, the EPA is
requesting comments on all aspects of the proposal to enable the EPA to
develop a final rule that, consistent with our responsibilities under
section 111 of the CAA, achieves the greatest possible reductions in
methane and VOC emissions while remaining achievable, cost effective,
and conducive to technological innovation. As a further step in the
rulemaking process and to solicit additional public input, the EPA
plans to issue a supplemental proposal and supplemental RIA for the
supplemental proposal to provide regulatory text for the proposed NSPS
OOOOb and EG OOOOc. In light of certain innovative elements of this
proposed rule and the EPA's request for information that would support
the regulation of additional sources in the Crude Oil and Natural Gas
source category as part of this rulemaking, the EPA is considering
including additional provisions in this supplemental proposal and RIA
based on information and comment collected in response to this
document.
As noted later in this preamble, the supplemental proposal may
address, among other issues: (1) Ways to mitigate methane from
abandoned wells, (2) measures to reduce emissions from pipeline pigging
operations and other pipeline blowdowns, (3) ways to minimize emissions
from tank truck loading operations, and (4) ways to strengthen
requirements to ensure proper operation and optimal performance of
control devices. In addition, and as noted in the solicitations of
comment in this document, the supplemental proposal may revisit and
refine certain provisions of this proposal in response to information
provided by the public. For instance, the EPA is seeking input on
multiple aspects of the proposed approach for fugitive emissions
monitoring at well sites, including the baseline emission threshold and
other criteria (such as the presence of specific types of malfunction-
prone equipment) that should be used to determine whether a well site
is required to undertake ongoing fugitive emissions monitoring; the
methodology for calculating baseline methane emissions and whether it
should account for malfunctions or improper operation of controls at
storage vessels; and ways to ensure that emissions from wells owned by
small businesses are addressed while still recognizing the greater
challenges that small businesses with less dedicated staff and
resources for
[[Page 63116]]
environmental compliance may have. The EPA is also seeking input on
ways to ensure that captured associated gas is collected for a useful
purpose rather than flared, and the feasibility of requiring broader
use of zero-emitting technology for pneumatic pumps.
Finally, the EPA is seeking comment and information on alternative
measurement technologies, which we are proposing to allow in the rule.
We have heard strong interest from various stakeholders on employing
new tools for methane identification and quantification, particularly
for large emission sources (commonly known as ``super-emitters'').
Information provided in response to this proposal may be used to
evaluate whether a change in BSER from the proposed quarterly OGI
monitoring to a monitoring program using alternative measurement
technologies is appropriate. Separate from the role of these
alternative measurement technologies in a regulatory monitoring
program, we are also soliciting comment on ways to structure a pathway
for communities to identify large emission events which owners or
operators would then be required to investigate, and mechanisms for the
collection and public dissemination of this information, for possible
further development as part of a supplemental proposal.
This preamble includes comment solicitations/requests on several
topics and issues. We have prepared a separate memorandum that presents
these comment requests by section and topic as a guide to assist
commenters in preparing comments. This memorandum can be obtained from
the Docket for this action (see Docket ID No. EPA-HQ-OAR-2021-0317).
The title of the memorandum is ``Standards of Performance for New,
Reconstructed, and Modified Sources and Emissions Guidelines for
Existing Sources: Oil and Natural Gas Sector Climate Review--Proposed
Rule Summary of Comment Solicitations.''
B. Summary of the Major Provisions of This Regulatory Action
This proposed rulemaking includes three distinct groups of actions
under the CAA that are each severable from the other. First, pursuant
to CAA 111(b)(1)(B), the EPA has reviewed, and is proposing revisions
to, the standards of performance for the Crude Oil and Natural Gas
source category published in 2016 and amended in 2020, codified at 40
CFR part 60, subpart OOOOa--Standards of Performance for Crude Oil and
Natural Gas Facilities for which Construction, Modification or
Reconstruction Commenced After September 18, 2015 (2016 NSPS OOOOa).
Specifically, the EPA is proposing to update, strengthen, and expand
the current requirements under CAA section 111(b) for methane and VOC
emissions from sources that commenced construction, modification, or
reconstruction after November 15, 2021. These proposed standards of
performance will be in a new subpart, 40 CFR part 60, subpart OOOOb
(NSPS OOOOb), and include standards for emission sources previously not
regulated under the 2016 NSPS OOOOa.
Second, pursuant to CAA 111(d), the EPA is proposing the first
nationwide EG for States to limit methane pollution from designated
facilities in the Crude Oil and Natural Gas source category. The EG
being proposed in this rulemaking will be in a new subpart, 40 CFR part
60, subpart OOOOc (EG OOOOc). The EG are designed to inform States in
the development, submittal, and implementation of State plans that are
required to establish standards of performance for GHGs from their
designated facilities in the Crude Oil and Natural Gas source category.
Third, the EPA is taking several related actions stemming from the
joint resolution of Congress, adopted on June 30, 2021 under the CRA,
disapproving the EPA's final rule titled, ``Oil and Natural Gas Sector:
Emission Standards for New, Reconstructed, and Modified Sources
Review,'' 85 FR 57018 (Sept. 14, 2020) (``2020 Policy Rule''). As
explained in Section X of this action (Summary of Proposed Action for
NSPS OOOOa), the EPA is proposing amendments to the 2016 NSPS OOOOa to
address (1) certain inconsistencies between the VOC and methane
standards resulting from the disapproval of the 2020 Policy Rule, and
(2) certain determinations made in the final rule titled ``Oil and
Natural Gas Sector: Emission Standards for New, Reconstructed, and
Modified Sources Reconsideration,'' 85 FR 57398 (September 15, 2020)
(2020 Technical Rule), specifically with respect to fugitive emissions
monitoring at low production well sites and gathering and boosting
stations. With respect to the latter, as described below, the EPA is
proposing to rescind provisions of the 2020 Technical Rule that were
not supported by the record for that rule, or by our subsequent
information and analysis. The regulatory text for these proposed
amendments is included in the docket for this rulemaking at Docket ID
EPA-HQ-OAR-2021-0317.
In addition, in the final rule for this action, the EPA will update
the NSPS OOOO and NSPS OOOOa provisions in the Code of Federal
Regulations (CFR) to reflect the Congressional Review Act (CRA)
resolution's disapproval of the final 2020 Policy Rule, specifically,
the reinstatement of the NSPS OOOO and NSPS OOOOa requirements that the
2020 Policy Rule repealed but that came back into effect immediately
upon enactment of the CRA resolution. It should be noted that these
requirements have come back into effect already even though the EPA has
not yet updated the CFR text to reflect them.\6\ These updates to the
CFR text are also included in the docket for this rulemaking at Docket
ID EPA-HQ-OAR-2021-0317 for public awareness, but the EPA is not
soliciting comment on them as they merely reflect current law. Under 5
U.S.C. 553(b)(3)(B), notice and comment is not required ``when the
agency for good cause finds . . . that notice and public procedure
thereon are . . . unnecessary . . . ,'' \7\ and, as just noted, notice
and comment is not necessary for these updates. The EPA is waiting to
make these updates to the CFR text until the final rule simply because
it would be more efficient and clearer to amend the CFR once at the end
of this rulemaking process to account for all changes to the 2012 NSPS
OOOO (77 FR 49490, August 16, 2012) and 2016 NSPS OOOOa at the same
time.
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\6\ See Congressional Review Act Resolution to Disapprove EPA's
2020 Oil and Gas Policy Rule Questions and Answers (June 30, 2021)
available at https://www.epa.gov/system/files/documents/2021-07/qa_cra_for_2020_oil_and_gas_policy_rule.6.30.2021.pdf.
\7\ 5 U.S.C. 553(b)(3)(B) is applicable to rules promulgated
under CAA section 111(b), under CAA section 307(d)(1) (flush
language at end).
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As CAA section 111(a)(1) requires, the standards of performance
being proposed in this action reflect ``the degree of emission
limitation achievable through the application of the best system of
emission reduction [BSER] which (taking into account the cost of
achieving such reduction and any non-air quality health and
environmental impact and energy requirement) the Administrator
determines has been adequately demonstrated.'' This action further
proposes EG for designated facilities, under which States must submit
plans which establish standards of performance that reflect the degree
of emission limitation achievable through application of the BSER, as
identified in the final EG. In this proposed rulemaking, we evaluated
potential control measures available for the affected facilities, the
emission reductions achievable through these measures, and employed
multiple approaches to evaluate the reasonableness of control costs
associated with the options under
[[Page 63117]]
consideration. For example, in evaluating controls for reducing VOC and
methane emissions from new sources, we considered a control measure's
cost-effectiveness under both a ``single pollutant cost-effectiveness''
approach and a ``multipollutant cost-effectiveness'' approach, to
appropriately consider that the systems of emission reduction
considered in this rule typically achieve reductions in multiple
pollutants at once and secure a multiplicity of climate and public
health benefits. For a detailed discussion of the EPA's consideration
of this and other BSER statutory elements, please see sections IV and
IX of this preamble.
Table 1--Applicability Dates for Proposed Subparts Addressed in This
Proposed Action
------------------------------------------------------------------------
Subpart Source type Applicable dates
------------------------------------------------------------------------
40 CFR part 60, subpart OOOO New, modified, or After August 23,
reconstructed 2011 and on or
sources. before September
18, 2015.
40 CFR part 60, subpart New, modified, or After September 18,
OOOOa. reconstructed 2015 and on or
sources. before November 15,
2021.
40 CFR part 60, subpart New, modified, or After November 15,
OOOOb. reconstructed 2021.
sources.
40 CFR part 60, subpart Existing sources.... On or before
OOOOc. November 15, 2021.
------------------------------------------------------------------------
1. Proposed Standards for New, Modified and Reconstructed Sources After
November 15, 2021 (Proposed NSPS OOOOb)
As described in sections XI and XII of this preamble, under the
authority of CAA section 111(b)(1)(B) the EPA has reviewed the VOC, GHG
(in the form of limitations on methane), and SO2 standards
in the 2016 NSPS OOOOa (as amended in 2020 by the Technical Rule).
Based on its review, the EPA is proposing revisions to the standards
for certain emissions sources to reflect the updated BSER for those
affected sources. Where our analyses show that the BSER for an affected
source remains the same, the EPA is proposing to retain the current
standard for that affected source. In addition, the EPA is proposing
methane and VOC standards for several new sources that are currently
unregulated. The proposed NSPS described above would apply to new,
modified, and reconstructed emission sources across the Crude Oil and
Natural Gas source category, including the production, processing,
transmission, and storage segments, for which construction,
reconstruction, or modification commenced after November 15, 2021,
which is the date of publication of the proposed revisions to the NSPS.
In particular, this action proposes to retain the 2016 NSPS OOOOa
SO2 performance standard for sweetening units and the 2016
OOOOa VOC and methane performance standards for well completions and
centrifugal compressors; proposes revisions to strengthen the 2016 NSPS
OOOOa VOC and methane standards addressing fugitive emissions from well
sites and compressor stations, storage vessels, pneumatic controllers,
reciprocating compressors, pneumatic pumps, and equipment leaks at
natural gas processing plants; and proposes new VOC and methane
standards for well liquids unloading operations and intermittent vent
pneumatic controllers, and oil wells with associated gas previously not
regulated in the 2016 NSPS OOOOa. A summary of the proposed BSER
determination and proposed NSPS for new, modified, and reconstructed
sources (NSPS OOOOb) is presented in Table 2. See sections XI and XII
of this preamble for a complete discussion of BSER determination and
proposed NSPS requirements.
This proposal also solicits certain information relevant to the
potential identification of additional emissions sources as affected
facilities. Specifically, the EPA is evaluating the potential for
establishing standards for abandoned and unplugged wells, blowdown
emissions associated with pipeline pig launchers and receivers, and
tank truck loading operations. While the EPA has assessed these sources
based on currently available information, we have determined that we
need additional information to evaluate BSER and to propose NSPS for
these emissions sources. A full discussion of the solicitation for
comment regarding these additional emission sources is found in section
XIII of the preamble.
2. Proposed EG for Sources Constructed Prior to November 15, 2021
(Proposed EG OOOOc)
As described in sections XI and XII of this preamble, under the
authority of CAA section 111(d), the EPA is proposing the first
nationwide EG for GHG (in the form of methane limitations) for the
Crude Oil and Natural Gas source category, including the production,
processing, transmission, and storage segments (EG OOOOc). When the EPA
establishes NSPS for a source category, the EPA is required to issue EG
to reduce emissions of certain pollutants from existing sources in that
same source category. In such circumstances, under CAA section 111(d),
the EPA must issue regulations to establish procedures under which
States submit plans to establish, implement, and enforce standards of
performance for existing sources for certain air pollutants to which a
Federal NSPS would apply if such existing source were a new source.
Thus, the issuance of CAA section 111(d) final EG does not impose
binding requirements directly on sources but instead provides
requirements for states in developing their plans. Although State plans
bear the obligation to establish standards of performance, under CAA
sections 111(a)(1) and 111(d), those standards of performance must
reflect the degree of emission limitation achievable through the
application of the BSER as determined by the Administrator. As provided
in section 111(d), a State may choose to take into account remaining
useful life and other factors in applying a standard of performance to
a particular source, consistent with the CAA, the EPA's implementing
regulations, and the final EG.
In this action, the EPA is proposing BSER determinations and the
degree of limitation achievable through application of the BSER for
certain existing equipment, processes, and activities across the Crude
Oil and Natural Gas source category. Section XIV of this preamble
discusses the components of EG, including the steps, requirements, and
considerations associated with the development, submittal, and
implementation of State, Tribal, and Federal plans, as appropriate. For
the EG, the EPA is proposing to translate the degree of emission
limitation achievable through application of the BSER (i.e., level of
stringency) into presumptive standards that States may use in the
development of State plans for specific designated facilities. By doing
this, the EPA has formatted the proposed EG such that if a State
chooses to adopt these
[[Page 63118]]
presumptive standards, once finalized, as the standards of performance
in a State plan, the EPA could approve such a plan as meeting the
requirements of CAA section 111(d) and the finalized EG, if the plan
meets all other applicable requirements. In this way, the presumptive
standards included in the EG serve a function similar to that of a
model rule,\8\ because they are intended to assist States in developing
their plan submissions by providing States with a starting point for
standards that are based on general industry parameters and
assumptions. The EPA believes that providing these presumptive
standards will create a streamlined approach for States in developing
plans and the EPA in evaluating State plans. However, the EPA's action
on each State plan submission is carried out via rulemaking, which
includes public notice and comment. Inclusion of presumptive standards
in the EG does not seek to pre-determine the outcomes of any future
rulemaking.
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\8\ The presumptive standards are not the same as a Federal plan
under CAA section 111(d)(2). The EPA has an obligation to promulgate
a Federal plan if a state fails to submit a satisfactory plan. In
such circumstances, the final EG and presumptive standards would
serve as a guide to the development of a Federal plan. See section
XIV.F. for information on Federal plans.
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Designated facilities located in Indian country would not be
encompassed within a State's CAA section 111(d) plan. Instead, an
eligible Tribe that has one or more designated facilities located in
its area of Indian country would have the opportunity, but not the
obligation, to seek authority and submit a plan that establishes
standards of performance for those facilities on its Tribal lands. If a
Tribe does not submit a plan, or if the EPA does not approve a Tribe's
plan, then the EPA has the authority to establish a Federal plan for
that Tribe. A summary of the proposed EG for existing sources (EG
OOOOc) for the oil and natural gas sector is presented in Table 3. See
sections XI and XII of this preamble for a complete discussion of the
proposed EG requirements.
As discussed above for the proposed NSPS OOOOb, the EPA is
considering including additional sources as affected facilities in a
potential future supplemental rulemaking proposal \9\ under CAA section
111(b). The EPA is also considering including these additional sources
as designated facilities under the EG in OOOOc in a potential future
supplemental rulemaking proposal under CAA section 111(d). As with the
proposed NSPS OOOOb, the EPA is evaluating the potential for
establishing EG applicable to abandoned and unplugged wells, blowdown
emissions associated with pipeline pig launchers and receivers, and
tank truck loading operations (assuming the EPA establishes NSPS for
these emissions points). As described in section XIII of this preamble,
the EPA is soliciting information to assist in this effort.
---------------------------------------------------------------------------
\9\ A supplemental proposal would include an updated RIA.
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3. Proposed Amendments to 2016 NSPS OOOOa, and CRA-Related CFR Updates
The EPA is also proposing certain modifications to the 2016 NSPS
OOOOa to address certain amendments to the VOC standards for sources in
the production and processing segments finalized in the 2020 Technical
Rule. Because the methane standards for the production and processing
segments and all standards for the transmission and storage segment
were removed from the 2016 NSPS OOOOa via the 2020 Policy Rule prior to
the finalization of the 2020 Technical Rule, the latter amendments
apply only to the 2016 NSPS OOOOa VOC standards for the production and
processing segments. In this proposed rulemaking, the EPA also is
proposing to apply some of the 2020 Technical Rule amendments to the
methane standards for all industry segments and to VOC standards for
the transmission and storage segment in the 2016 NSPS OOOOa. These
amendments are associated with the requirements for well completions,
pneumatic pumps, closed vent systems, fugitive emissions, alternative
means of emission limitation (AMELs), onshore natural gas processing
plants, as well as other technical clarifications and corrections. The
EPA also is proposing to repeal the amendments in the 2020 Technical
Rule that (1) exempted low production well sites from monitoring
fugitive emissions and (2) changed monitoring of VOC emissions at
gathering and boosting compressor stations from quarterly to
semiannual, which currently apply only to VOC standards (not methane
standards) from the production and processing segments. A summary of
the proposed amendments to the 2016 OOOOa NSPS is presented in section
X of this preamble.
Lastly, in the final rule for this action, the EPA will update the
NSPS OOOO and OOOOa provisions in the CFR to reflect the CRA
resolution's disapproval of the final 2020 Policy Rule, specifically,
the reinstatement of the OOOO and OOOOa requirements that the 2020
Policy Rule repealed but that came back into effect immediately upon
enactment of the CRA resolution. The EPA is waiting to make the updates
to the CFR text until the final rule simply because it would be more
efficient and clearer to amend the CFR once at the end of this
rulemaking process to account for all changes to the 2012 NSPS OOOO and
2016 NSPS OOOOa at the same time. In accordance with 5 U.S.C.
553(b)(3)(B), the EPA is not soliciting comment on these updates.
Table 2--Summary of Proposed BSER and Proposed Standards of Performance
for GHGS and VOC
[NSPS OOOOb]
------------------------------------------------------------------------
Proposed standards of
Affected source Proposed BSER performance for GHGs
and VOCs
------------------------------------------------------------------------
Fugitive Emissions: Well Sites Demonstrate Perform survey to
with Baseline Emissions >0 to actual site verify that actual
<3 tpy \1\ Methane. emissions are site emissions are
reflected in reflected in
calculation. calculation.
Fugitive Emissions: Well Sites Monitoring and Quarterly OGI
>=3 tpy Methane. repair based on monitoring following
quarterly appendix K.
monitoring using (Optional quarterly
OGI \2\. EPA Method 21
monitoring with 500
ppm defined as a
leak).
First attempt at
repair within 30
days of finding
fugitive emissions.
Final repair within
30 days of first
attempt.
(Co-proposal) Fugitive Monitoring and Semiannual OGI
Emissions: Well Sites with repair based on monitoring following
Baseline Emissions >=3 to <8 semiannual appendix K.
tpy Methane. monitoring using (Optional semiannual
OGI. EPA Method 21
monitoring with 500
ppm defined as a
leak).
First attempt at
repair within 30
days of finding
fugitive emissions.
Final repair within
30 days of first
attempt.
[[Page 63119]]
(Co-proposal) Fugitive Monitoring and Quarterly OGI
Emissions: Well Sites with repair based on monitoring following
Baseline Emissions >=8 tpy quarterly appendix K.
Methane. monitoring using (Optional quarterly
OGI. EPA Method 21
monitoring with 500
ppm \3\ defined as a
leak).
First attempt at
repair within 30
days of finding
fugitive emissions.
Final repair within
30 days of first
attempt.
Fugitive Emissions: Compressor Monitoring and Quarterly OGI
Stations. repair based on monitoring following
quarterly appendix K.
monitoring using (Optional quarterly
OGI. EPA Method 21
monitoring with 500
ppm defined as a
leak).
First attempt at
repair within 30
days of finding
fugitive emissions.
Final repair within
30 days of first
attempt.
Fugitive Emissions: Well Sites Monitoring and Annual OGI monitoring
and Compressor Stations on repair based on following appendix
Alaska North Slope. annual K. (Optional annual
monitoring using EPA Method 21
OGI. monitoring with 500
ppm defined as a
leak).
First attempt at
repair within 30
days of finding
fugitive emissions.
Final repair within
30 days of first
attempt.
Fugitive Emissions: Well Sites (Optional) (Optional)
and Compressor Stations. Screening, Alternative
monitoring, and bimonthly screening
repair based on with advanced
bimonthly measurement
screening using technology with
an advanced annual OGI
measurement monitoring following
technology and appendix K.
annual
monitoring using
OGI.
Storage Vessels: A Single Capture and route 95 percent reduction
Storage Vessel or Tank to a control of VOC and methane.
Battery with PTE \4\ of 6 tpy device.
or More of VOC.
Pneumatic Controllers: Natural Use of zero- VOC and methane
Gas Driven that Vent to the emissions emission rate of
Atmosphere. controllers. zero.
Pneumatic Controllers: Alaska Installation of Natural gas bleed
(at sites where onsite power low-bleed rate no greater than
is not available--continuous pneumatic 6 scfh.\5\
bleed natural gas driven). controllers.
Pneumatic Controllers: Alaska Monitor and OGI monitoring and
(at sites where onsite power repair through repair of emissions
is not available-- fugitive from controller
intermittent natural gas emissions malfunctions.
driven). program.
Well Liquids Unloading........ Perform liquids Each affected well
unloading with that unloads liquids
zero methane or employ techniques or
VOC emissions. technology(ies) that
If this is not eliminate or
feasible for minimize venting of
safety or emissions during
technical liquids unloading
reasons, employ events to the
best management maximum extent.
practices to
minimize venting.
Co Proposal Options:
Option One--Affected
facility would be
defined as every
well that undergoes
liquids unloading.
--If the method is
one that does not
result in any
venting to the
atmosphere, maintain
records specifying
the technology or
technique and record
instances where an
unloading event
results in
emissions.
--For unloading
technologies or
techniques that
result in venting to
the atmosphere,
implement BMPs \6\
to ensure that
venting is
minimized.
--Maintain BMPs as
records, and record
instances when they
were not followed.
Option Two--Affected
facility would be
defined as every
well that undergoes
liquids unloading
using a method that
is not designed to
eliminate venting.
--Wells that utilize
non-venting methods
would not be
affected facilities
that are subject to
the NSPS OOOOb.
Therefore, they
would not have
requirements other
than to maintain
records to document
that they used non-
venting liquids
unloading methods.
--The requirements
for wells that use
methods that vent
would be the same as
described above
under Option 1.
Wet Seal Centrifugal Capture and route Reduce emissions by
Compressors (except for those emissions from 95 percent.
located at single well sites). the wet seal
fluid degassing
system to a
control device
or to a process.
Reciprocating Compressors Replace the Replace the
(except for those located at reciprocating reciprocating
single well sites). compressor rod compressor rod
packing based on packing when
annual measured leak rate
monitoring (when exceeds 2 scfm based
measured leak on the results of
rate exceeds 2 annual monitoring or
scfm \7\) or collect and route
route emissions emissions from the
to a process. rod packing to a
process through a
closed vent system
under negative
pressure.
[[Page 63120]]
Pneumatic Pumps: Natural Gas A natural gas A natural gas
Processing Plants. emission rate of emission rate of
zero. zero from diaphragm
and piston pneumatic
pumps.
Pneumatic Pumps: Production Route diaphragm 95 percent control of
Segment. and piston diaphragm and piston
pneumatic pumps pneumatic pumps if
to an existing there is an existing
control device control or process
or process. on site. 95 percent
control not required
if (1) routed to an
existing control
that achieves less
than 95 percent or
(2) it is
technically
infeasible to route
to the existing
control device or
process.
Pneumatic Pumps: Transmission Route diaphragm 95 percent control of
and Storage Segment. pneumatic pumps diaphragm pneumatic
to an existing pumps if there is an
control device existing control or
or process. process on site. 95
percent control not
required if (1)
routed to an
existing control
that achieves less
than 95 percent or
(2) it is
technically
infeasible to route
to the existing
control device or
process.
Well Completions: Subcategory Combination of Applies to each well
1 (non-wildcat and non- REC \8\ and the completion operation
delineation wells). use of a with hydraulic
completion fracturing.
combustion
device.
REC in combination
with a completion
combustion device;
venting in lieu of
combustion where
combustion would
present safety
hazards.
Initial flowback
stage: Route to a
storage vessel or
completion vessel
(frac tank, lined
pit, or other
vessel) and
separator.
Separation flowback
stage: Route all
salable gas from the
separator to a flow
line or collection
system, re-inject
the gas into the
well or another
well, use the gas as
an onsite fuel
source or use for
another useful
purpose that a
purchased fuel or
raw material would
serve. If
technically
infeasible to route
recovered gas as
specified above,
recovered gas must
be combusted. All
liquids must be
routed to a storage
vessel or well
completion vessel,
collection system,
or be re-injected
into the well or
another well.
The operator is
required to have
(and use) a
separator onsite
during the entire
flowback period.
Well Completions: Subcategory Use of a Applies to each well
2 (exploratory and completion completion operation
delineation wells and low- combustion with hydraulic
pressure wells). device. fracturing.
The operator is not
required to have a
separator onsite.
Either: (1) Route
all flowback to a
completion
combustion device
with a continuous
pilot flame; or (2)
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
with a continuous
pilot flame.
For both options (1)
and (2), combustion
is not required 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.
Equipment Leaks at Natural Gas LDAR \9\ with LDAR with OGI
Processing Plants. bimonthly OGI. following procedures
in appendix K.
Oil Wells with Associated Gas. Route associated Route associated gas
gas to a sales to a sales line. If
line. If access access to a sales
to a sales line line is not
is not available, the gas
available, the can be used as an
gas can be used onsite fuel source,
as an onsite used for another
fuel source, useful purpose that
used for another a purchased fuel or
useful purpose raw material would
that a purchased serve, or routed to
fuel or raw a flare or other
material would control device that
serve, or routed achieves at least 95
to a flare or percent reduction in
other control methane and VOC
device that emissions.
achieves at
least 95 percent
reduction in
methane and VOC
emissions.
Sweetening Units.............. Achieve SO2 Achieve required
emission minimum SO2 emission
reduction reduction
efficiency. efficiency.
------------------------------------------------------------------------
\1\ tpy (tons per year).
[[Page 63121]]
\2\ OGI (optical gas imaging).
\3\ ppm (parts per million).
\4\ PTE (potential to emit).
\5\ scfh (standard cubic feet per hour).
\6\ BMP (best management practices).
\7\ scfm (standard cubic feet per minute).
\8\ REC (reduced emissions completion).
\9\ LDAR (leak detection and repair).
Table 3--Summary of Proposed BSER and Proposed Presumptive Standards for
GHGS From Designated Facilities
[EG OOOOc]
------------------------------------------------------------------------
Proposed presumptive
Designated facility Proposed BSER standards for GHGs
------------------------------------------------------------------------
Fugitive Emissions: Well Sites Demonstrate Perform survey to
>0 to <3 tpy Methane. actual site verify that actual
emissions are site emissions are
reflected in reflected in
calculation. calculation.
Fugitive Emissions: Well Sites Monitoring and Quarterly OGI
>=3 tpy Methane. repair based on monitoring following
quarterly appendix K.
monitoring using (Optional quarterly
OGI. EPA Method 21
monitoring with 500
ppm defined as a
leak).
First attempt at
repair within 30
days of finding
fugitive emissions.
Final repair within
30 days of first
attempt.
(Co-proposal) Fugitive Monitoring and Semiannual OGI
Emissions: Well Sites >=3 to repair based on monitoring following
<8 tpy Methane. semiannual appendix K.
monitoring using (Optional semiannual
OGI. EPA Method 21
monitoring with 500
ppm defined as a
leak).
First attempt at
repair within 30
days of finding
fugitive emissions.
Final repair within
30 days of first
attempt.
(Co-proposal) Fugitive Monitoring and Quarterly OGI
Emissions: Well Sites >=8 tpy repair based on monitoring following
Methane. quarterly appendix K.
monitoring using (Optional quarterly
OGI. EPA Method 21
monitoring with 500
ppm defined as a
leak).
First attempt at
repair within 30
days of finding
fugitive emissions.
Final repair within
30 days of first
attempt.
Fugitive Emissions: Compressor Monitoring and Quarterly OGI
Stations. repair based on monitoring following
quarterly appendix K.
monitoring using (Optional quarterly
OGI. EPA Method 21
monitoring with 500
ppm defined as a
leak).
First attempt at
repair within 30
days of finding
fugitive emissions.
Final repair within
30 days of first
attempt.
Fugitive Emissions: Well Sites Monitoring and Annual OGI monitoring
and Compressor Stations on repair based on following appendix
Alaska North Slope. annual K. (Optional annual
monitoring using EPA Method 21
OGI. monitoring with 500
ppm defined as a
leak).
First attempt at
repair within 30
days of finding
fugitive emissions.
Final repair within
30 days of first
attempt.
Fugitive Emissions: Well Sites (Optional) (Optional)
and Compressor Stations. Screening, Alternative
monitoring, and bimonthly screening
repair based on with advanced
bimonthly measurement
screening using technology with
an advanced annual OGI
measurement monitoring following
technology and appendix K.
annual
monitoring using
OGI.
Storage Vessels: Tank Battery Capture and route 95 percent reduction
with PTE of 20 tpy or More of to a control of methane.
Methane. device.
Pneumatic Controllers: Natural Use of zero- VOC and methane
Gas Driven that Vent to the emissions emission rate of
Atmosphere. controllers. zero.
Pneumatic Controllers: Alaska Installation of Natural gas bleed
(at sites where onsite power low-bleed rate no greater than
is not available--continuous pneumatic 6 scfh.
bleed natural gas driven). controllers.
Pneumatic Controllers: Alaska Monitor and OGI monitoring and
(at sites where onsite power repair through repair of emissions
is not available-- fugitive from controller
intermittent natural gas emissions malfunctions.
driven). program.
Wet Seal Centrifugal Capture and route Reduce emissions by
Compressors (except for those emissions from 95 percent.
located at single well sites). the wet seal
fluid degassing
system to a
control device
or to a process.
Reciprocating Compressors Replace the Replace the
(except for those located at reciprocating reciprocating
single well sites). compressor rod compressor rod
packing based on packing when
annual measured leak rate
monitoring (when exceeds 2 scfm based
measured leak on the results of
rate exceeds 2 annual monitoring,
scfm) or route or collect and route
emissions to a emissions from the
process. rod packing to a
process through a
closed vent system
under negative
pressure.
Pneumatic Pumps: Natural Gas A natural gas Zero natural gas
Processing Plants. emission rate of emissions from
zero. diaphragm and piston
pneumatic pumps.
Pneumatic Pumps: Locations Route diaphragm 95 percent control of
Other Than Natural Gas pumps to an diaphragm pneumatic
Processing Plants. existing control pumps if there is an
device or existing control or
process. process on site. 95
percent control not
required if (1)
routed to an
existing control
that achieves less
than 95 percent or
(2) it is
technically
infeasible to route
to the existing
control device or
process.
Equipment Leaks at Natural Gas LDAR with LDAR with OGI
Processing Plants. bimonthly OGI. following procedures
in appendix K.
[[Page 63122]]
Oil Wells with Associated Gas. Route associated Route associated gas
gas to a sales to a sales line. If
line. If access access to a sales
to a sales line line is not
is not available, the gas
available, the can be used as an
gas can be used onsite fuel source,
as an onsite used for another
fuel source, useful purpose that
used for another a purchased fuel or
useful purpose raw material would
that a purchased serve, or routed to
fuel or raw a flare or other
material would control device that
serve, or routed achieves at least 95
to a flare or percent reduction in
other control methane and VOC
device that emissions.
achieves at
least 95 percent
reduction in
methane and VOC
emissions.
------------------------------------------------------------------------
C. Costs and Benefits
To satisfy requirements of E.O. 12866, the EPA projected the
emissions reductions, costs, and benefits that may result from this
proposed action. These results are presented in detail in the
regulatory impact analysis (RIA) accompanying this proposal developed
in response to E.O. 12866. The RIA focuses on the elements of the
proposed rule that are likely to result in quantifiable cost or
emissions changes compared to a baseline without the proposal that
incorporates changes to regulatory requirements induced by the CRA
resolution. We estimated the cost, emissions, and benefit impacts for
the 2023 to 2035 period. We present the present value (PV) and
equivalent annual value (EAV) of costs, benefits, and net benefits of
this action in 2019 dollars.
The initial analysis year in the RIA is 2023 as we assume the
proposed rule will be finalized towards the end of 2022. The NSPS will
take effect immediately and impact sources constructed after
publication of the proposed rule. The EG will take longer to go into
effect as States will need to develop implementation plans in response
to the rule and have them approved by the EPA. We assume in the RIA
that this process will take three years, and so EG impacts will begin
in 2026. The final analysis year is 2035, which allows us to provide
ten years of projected impacts after the EG is assumed to take effect.
The cost analysis presented in the RIA reflects a nationwide
engineering analysis of compliance cost and emissions reductions, of
which there are two main components. The first component is a set of
representative or model plants for each regulated facility, segment,
and control option. The characteristics of the model plant include
typical equipment, operating characteristics, and representative
factors including baseline emissions and the costs, emissions
reductions, and product recovery resulting from each control option.
The second component is a set of projections of activity data for
affected facilities, distinguished by vintage, year, and other
necessary attributes (e.g., oil versus natural gas wells). Impacts are
calculated by setting parameters on how and when affected facilities
are assumed to respond to a particular regulatory regime, multiplying
activity data by model plant cost and emissions estimates, differencing
from the baseline scenario, and then summing to the desired level of
aggregation. In addition to emissions reductions, some control options
result in natural gas recovery, which can then be combusted in
production or sold. Where applicable, we present projected compliance
costs with and without the projected revenues from product recovery.
The EPA expects climate and health benefits due to the emissions
reductions projected under this proposed rule. The EPA estimated the
global social benefits of CH4 emission reductions expected
from this proposed rule using the SC-CH4 estimates presented
in the ``Technical Support Document: Social Cost of Carbon, Methane,
and Nitrous Oxide Interim Estimates under E.O. 13990 (IWG 2021)''.
These SC-CH4 estimates are interim values developed under
E.O. 13990 for use in benefit-cost analyses until updated estimates of
the impacts of climate change can be developed based on the best
available science and economics.
Under the proposed rule, the EPA expects that VOC emission
reductions will improve air quality and are likely to improve health
and welfare associated with exposure to ozone, PM2.5, and
HAP. Calculating ozone impacts from VOC emissions changes requires
information about the spatial patterns in those emissions changes. In
addition, the ozone health effects from the proposed rule will depend
on the relative proximity of expected VOC and ozone changes to
population. In this analysis, we have not characterized VOC emissions
changes at a finer spatial resolution than the national total. In light
of these uncertainties, we present an illustrative screening analysis
in Appendix B of the RIA based on modeled oil and natural gas VOC
contributions to ozone concentrations as they occurred in 2017 and do
not include the results of this analysis in the estimate of benefits
and net benefits projected from this proposal.
The projected national-level emissions reductions over the 2023 to
2035 period anticipated under the proposed requirements are presented
in Table 4. Table 5 presents the PV and EAV of the projected benefits,
costs, and net benefits over the 2023 to 2035 period under the proposed
requirements using discount rates of 3 and 7 percent.
Table 4--Projected Emissions Reductions Under the Proposed Rule, 2023-
2035 Total
------------------------------------------------------------------------
Emissions reductions
Pollutant (2023-2035 total)
------------------------------------------------------------------------
Methane (million short tons) a.................... 41
VOC (million short tons).......................... 12
Hazardous Air Pollutant (million short tons)...... 0.48
[[Page 63123]]
Methane (million metric tons CO2 Eq.) b........... 920
------------------------------------------------------------------------
a To convert from short tons to metric tons, multiply the short tons by
0.907. Alternatively, to convert metric tons to short tons, multiply
metric tons by 1.102.
b CO2 Eq. calculated using a global warming potential of 25.
Table 5--Benefits, Costs, Net Benefits, and Emissions Reductions of the Proposed Rule, 2023 Through 2035
[Dollar Estimates in Millions of 2019 Dollars] a
----------------------------------------------------------------------------------------------------------------
3 percent discount rate 7 percent discount rate
---------------------------------------------------------------
Equivalent Equivalent
Present value annual value Present value annual value
----------------------------------------------------------------------------------------------------------------
Climate Benefits b.............................. $55,000 $5,200 .............. ..............
Net Compliance Costs............................ 7,200 680 6,300 760
Compliance Costs............................ 13,000 1,200 10,000 1,200
Product Recovery............................ 5,500 520 3,900 470
Net Benefits.................................... 48,000 4,500 49,000 4,500
---------------------------------------------------------------
Non-Monetized Benefits.......................... Climate and ozone health benefits from reducing 41 million
short tons of methane from 2023 to 2035.
PM2.5 and ozone health benefits from reducing 12 million short
tons of VOC from 2023 to 2035 c.
HAP benefits from reducing 480 thousand short tons of HAP from
2023 to 2035.
Visibility benefits.
Reduced vegetation effects.
----------------------------------------------------------------------------------------------------------------
a Values rounded to two significant figures. Totals may not appear to add correctly due to rounding.
b Climate benefits are based on reductions in methane emissions and are calculated using four different
estimates of the social cost of methane (SC-CH4) (model average at 2.5 percent, 3 percent, and 5 percent
discount rates; 95th percentile at 3 percent discount rate). For the presentational purposes of this table, we
show the benefits associated with the average SC-CH4 at a 3 percent discount rate, but the Agency does not
have a single central SC-CH4 point estimate. We emphasize the importance and value of considering the benefits
calculated using all four SC-CH4 estimates; the present value (and equivalent annual value) of the additional
benefit estimates ranges from $22 billion to $150 billion ($2.4 billion to $14 billion) over 2023 to 2035 for
the proposed option. Please see Table 3-5 and Table 3-7 of the RIA for the full range of SC-CH4 estimates. As
discussed in Section 3 of the RIA, a consideration of climate benefits calculated using discount rates below 3
percent, including 2 percent and lower, are also warranted when discounting intergenerational impacts. All net
benefits are calculated using climate benefits discounted at 3 percent.
c A screening-level analysis of ozone benefits from VOC reductions can be found in Appendix B of the RIA, which
is included in the docket.
II. General Information
A. Does this action apply to me?
Categories and entities potentially affected by this action
include:
Table 6--Industrial Source Categories Affected by This Action
----------------------------------------------------------------------------------------------------------------
Category NAICS code 1 Examples of regulated entities
----------------------------------------------------------------------------------------------------------------
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.
----------------------------------------------------------------------------------------------------------------
1 North American Industry Classification System (NAICS).
This table is not intended to be exhaustive, but rather provides a
guide for readers regarding entities likely to be affected 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).
[[Page 63124]]
B. How do I obtain a copy of this document, background information, and
other related information?
In addition to being available in the docket, an electronic copy of
the proposed action is available on the internet. Following signature
by the Administrator, the EPA will post a copy of this proposed action
at https://www.epa.gov/controlling-air-pollution-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 proposed changes described in section X
for NSPS OOOO and NSPS OOOOa is available in the docket for this action
(Docket ID No. EPA-HQ-OAR-2021-0317). The EPA plans to propose the
regulatory language for NSPS OOOOb and EG OOOOc through a supplemental
action.
III. Air Emissions From the Crude Oil and Natural Gas Sector and Public
Health and Welfare
A. Impacts of GHGs, VOCs and SO2 Emissions on Public Health
and Welfare
As noted previously, the Oil and Natural Gas Industry emits a wide
range of pollutants, including GHGs (such as methane and
CO2), VOCs, SO2, NOX, H2S,
CS2, and COS. See 49 FR 2636, 2637 (January 20, 1984). As
noted below, to this point, the EPA has focused its regulatory efforts
on GHGs, VOC, and SO2.\10\
---------------------------------------------------------------------------
\10\ We note that the EPA's focus on GHGs (in particular
methane), VOC, and SO2 in these analyses, does not in any
way limit the EPA's authority to promulgate standards that would
apply to other pollutants emitted from the Crude Oil and Natural Gas
source category, if the EPA determines in the future that such
action is appropriate.
---------------------------------------------------------------------------
1. Climate Change Impacts From GHGs Emissions
Elevated concentrations of GHGs are and have been warming the
planet, leading to changes in the Earth's climate including changes in
the frequency and intensity of heat waves, precipitation, and extreme
weather events; rising seas; and retreating snow and ice. The changes
taking place in the atmosphere as a result of the well-documented
buildup of GHGs due to human activities are changing the climate at a
pace and in a way that threatens human health, society, and the natural
environment. Human induced GHGs, largely derived from our reliance on
fossil fuels, are causing serious and life-threatening environmental
and health impacts.
Extensive additional information on climate change is available in
the scientific assessments and the EPA documents that are briefly
described in this section, as well as in the technical and scientific
information supporting them. One of those documents is the EPA's 2009
Endangerment and Cause or Contribute Findings for GHGs Under Section
202(a) of the CAA (74 FR 66496, December 15, 2009).\11\ In the 2009
Endangerment Findings, the Administrator found under section 202(a) of
the CAA that elevated atmospheric concentrations of six key well-mixed
GHGs--CO2, CH4, N2O,
hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and sulfur
hexafluoride (SF6)--``may reasonably be anticipated to
endanger the public health and welfare of current and future
generations'' (74 FR 66523, December 15, 2009), and the science and
observed changes have confirmed and strengthened the understanding and
concerns regarding the climate risks considered in the Finding. The
2009 Endangerment Findings, together with the extensive scientific and
technical evidence in the supporting record, documented that climate
change caused by human emissions of GHGs threatens the public health of
the U.S. population. It explained that by raising average temperatures,
climate change increases the likelihood of heat waves, which are
associated with increased deaths and illnesses (74 FR 66497, December
15, 2009). While climate change also increases the likelihood of
reductions in cold-related mortality, evidence indicates that the
increases in heat mortality will be larger than the decreases in cold
mortality in the U.S. (74 FR 66525, December 15, 2009). The 2009
Endangerment Findings further explained that compared to a future
without climate change, climate change is expected to increase
tropospheric ozone pollution over broad areas of the U.S., including in
the largest metropolitan areas with the worst tropospheric ozone
problems, and thereby increase the risk of adverse effects on public
health (74 FR 66525, December 15, 2009). Climate change is also
expected to cause more intense hurricanes and more frequent and intense
storms of other types and heavy precipitation, with impacts on other
areas of public health, such as the potential for increased deaths,
injuries, infectious and waterborne diseases, and stress-related
disorders (74 FR 66525, December 15, 2009). Children, the elderly, and
the poor are among the most vulnerable to these climate-related health
effects (74 FR 66498, December 15, 2009).
---------------------------------------------------------------------------
\11\ In describing these 2009 Findings in this proposal, the EPA
is neither reopening nor revisiting them.
---------------------------------------------------------------------------
The 2009 Endangerment Findings also documented, together with the
extensive scientific and technical evidence in the supporting record,
that climate change touches nearly every aspect of public welfare \12\
in the U.S. with resulting economic costs, including: Changes in water
supply and quality due to increased frequency of drought and extreme
rainfall events; increased risk of storm surge and flooding in coastal
areas and land loss due to inundation; increases in peak electricity
demand and risks to electricity infrastructure; and the potential for
significant agricultural disruptions and crop failures (though offset
to some extent by carbon fertilization). These impacts are also global
and may exacerbate problems outside the U.S. that raise humanitarian,
trade, and national security issues for the U.S. (74 FR 66530, December
15, 2009).
---------------------------------------------------------------------------
\12\ The CAA states in section 302(h) that ``[a]ll language
referring to effects on welfare includes, but is not limited to,
effects on soils, water, crops, vegetation, manmade materials,
animals, wildlife, weather, visibility, and climate, damage to and
deterioration of property, and hazards to transportation, as well as
effects on economic values and on personal comfort and well-being,
whether caused by transformation, conversion, or combination with
other air pollutants.'' 42 U.S.C. 7602(h).
---------------------------------------------------------------------------
In 2016, the Administrator similarly issued Endangerment and Cause
or Contribute Findings for GHG emissions from aircraft under section
231(a)(2)(A) of the CAA (81 FR 54422, August 15, 2016).\13\ In the 2016
Endangerment Findings, the Administrator found that the body of
scientific evidence amassed in the record for the 2009 Endangerment
Findings compellingly supported a similar endangerment finding under
CAA section 231(a)(2)(A), and also found that the science assessments
released between the 2009 and the 2016 Findings, ``strengthen and
further support the judgment that GHGs in the atmosphere may reasonably
be anticipated to endanger the public health and welfare of current and
future generations.'' (81 FR 54424, August 15, 2016).
---------------------------------------------------------------------------
\13\ In describing these 2016 Findings in this proposal, the EPA
is neither reopening nor revisiting them.
---------------------------------------------------------------------------
Since the 2016 Endangerment Findings, the climate has continued to
change, with new records being set for several climate indicators such
as global average surface temperatures, GHG concentrations, and sea
level rise. Moreover, heavy precipitation events
[[Page 63125]]
have increased in the eastern U.S. while agricultural and ecological
drought has increased in the western U.S. along with more intense and
larger wildfires.\14\ These and other trends are examples of the risks
discussed the 2009 and 2016 Endangerment Findings that have already
been experienced. Additionally, major scientific assessments continue
to demonstrate advances in our understanding of the climate system and
the impacts that GHGs have on public health and welfare both for
current and future generations. These updated observations and
projections document the rapid rate of current and future climate
change both globally and in the U.S. These assessments include:
---------------------------------------------------------------------------
\14\ See later in this section for specific examples. An
additional resource for indicators can be found at https://www.epa.gov/climate-indicators.
---------------------------------------------------------------------------
U.S. Global Change Research Program's (USGCRP) 2016
Climate and Health Assessment \15\ and 2017-2018 Fourth National
Climate Assessment (NCA4). \16\ \17\
---------------------------------------------------------------------------
\15\ USGCRP, 2016: The Impacts of Climate Change on Human Health
in the United States: A Scientific Assessment. Crimmins, A., J.
Balbus, J.L. Gamble, C.B. Beard, J.E. Bell, D. Dodgen, R.J. Eisen,
N. Fann, M.D. Hawkins, S.C. Herring, L. Jantarasami, D.M. Mills, S.
Saha, M.C. Sarofim, J. Trtanj, and L. Ziska, Eds. U.S. Global Change
Research Program, Washington, DC, 312 pp.
\16\ USGCRP, 2017: Climate Science Special Report: Fourth
National Climate Assessment, Volume I [Wuebbles, D.J., D.W. Fahey,
K.A. Hibbard, D.J. Dokken, B.C. Stewart, and T.K. Maycock (eds.)].
U.S. Global Change Research Program, Washington, DC, USA, 470 pp,
doi: 10.7930/J0J964J6.
\17\ USGCRP, 2018: Impacts, Risks, and Adaptation in the United
States: Fourth National Climate Assessment, Volume II [Reidmiller,
D.R., C.W. Avery, D.R. Easterling, K.E. Kunkel, K.L.M. Lewis, T.K.
Maycock, and B.C. Stewart (eds.)]. U.S. Global Change Research
Program, Washington, DC, USA, 1515 pp. doi: 10.7930/NCA4.2018.
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IPCC's 2018 Global Warming of 1.5 [deg]C,\18\ 2019 Climate
Change and Land,\19\ and the 2019 Ocean and Cryosphere in a Changing
Climate \20\ assessments, as well as the 2021 IPCC Sixth Assessment
Report (AR6).\21\
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\18\ IPCC, 2018: Global Warming of 1.5 [deg]C. An IPCC Special
Report on the impacts of global warming of 1.5 [deg]C above pre-
industrial levels and related global greenhouse gas emission
pathways, in the context of strengthening the global response to the
threat of climate change, sustainable development, and efforts to
eradicate poverty [Masson-Delmotte, V., P. Zhai, H.-O. P[ouml]rtner,
D. Roberts, J. Skea, P.R. Shukla, A. Pirani, W. Moufouma-Okia, C.
P[eacute]an, R. Pidcock, S. Connors, J.B.R. Matthews, Y. Chen, X.
Zhou, M.I. Gomis, E. Lonnoy, T. Maycock, M. Tignor, and T.
Waterfield (eds.)].
\19\ IPCC, 2019: Climate Change and Land: an IPCC special report
on climate change, desertification, land degradation, sustainable
land management, food security, and greenhouse gas fluxes in
terrestrial ecosystems [P.R. Shukla, J. Skea, E. Calvo Buendia, V.
Masson-Delmotte, H.-O. P[ouml]rtner, D.C. Roberts, P. Zhai, R.
Slade, S. Connors, R. van Diemen, M. Ferrat, E. Haughey, S. Luz, S.
Neogi, M. Pathak, J. Petzold, J. Portugal Pereira, P. Vyas, E.
Huntley, K. Kissick, M. Belkacemi, J. Malley, (eds.)].
\20\ IPCC, 2019: IPCC Special Report on the Ocean and Cryosphere
in a Changing Climate [H.-O. P[ouml]rtner, D.C. Roberts, V. Masson-
Delmotte, P. Zhai, M. Tignor, E. Poloczanska, K. Mintenbeck, A.
Alegr[iacute]a, M. Nicolai, A. Okem, J. Petzold, B. Rama, N.M. Weyer
(eds.)].
\21\ IPCC, 2021: Summary for Policymakers. In: Climate Change
2021: The Physical Science Basis. Contribution of Working Group I to
the Sixth Assessment Report of the Intergovernmental Panel on
Climate Change [Masson-Delmotte, V., P. Zhai, A. Pirani, S.L.
Connors, C. P[eacute]an, S. Berger, N. Caud, Y. Chen, L. Goldfarb,
M.I. Gomis, M. Huang, K. Leitzell, E. Lonnoy, J.B.R. Matthews, T.K.
Maycock, T. Waterfield, O. Yelek[ccedil]i, R. Yu and B. Zhou
(eds.)]. Cambridge University Press. In Press.
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The NAS 2016 Attribution of Extreme Weather Events in the
Context of Climate Change,\22\ 2017 Valuing Climate Damages: Updating
Estimation of the Social Cost of Carbon Dioxide,\23\ and 2019 Climate
Change and Ecosystems \24\ assessments.
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\22\ National Academies of Sciences, Engineering, and Medicine.
2016. Attribution of Extreme Weather Events in the Context of
Climate Change. Washington, DC: The National Academies Press.
https://dio.org/10.17226/21852.
\23\ National Academies of Sciences, Engineering, and Medicine.
2017. Valuing Climate Damages: Updating Estimation of the Social
Cost of Carbon Dioxide. Washington, DC: The National Academies
Press. https://doi.org/10.17226/24651.
\24\ National Academies of Sciences, Engineering, and Medicine.
2019. Climate Change and Ecosystems. Washington, DC: The National
Academies Press. https://doi.org/10.17226/25504.
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National Oceanic and Atmospheric Administration's (NOAA)
annual State of the Climate reports published by the Bulletin of the
American Meteorological Society,\25\ most recently in August of 2020.
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\25\ Blunden, J., and D.S. Arndt, Eds., 2020: State of the
Climate in 2019. Bull. Amer. Meteor. Soc, S1-S429, https://doi.org/10.1175/2020BAMSStateoftheClimate.1.
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EPA Climate Change and Social Vulnerability in the United
States: A Focus on Six Impacts (2021).\26\
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\26\ EPA. 2021. Climate Change and Social Vulnerability in the
United States: A Focus on Six Impacts. U.S. Environmental Protection
Agency, EPA 430-R-21-003.
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The most recent information demonstrates that the climate is
continuing to change in response to the human-induced buildup of GHGs
in the atmosphere. These recent assessments show that atmospheric
concentrations of GHGs have risen to a level that has no precedent in
human history and that they continue to climb, primarily as a result of
both historic and current anthropogenic emissions, and that these
elevated concentrations endanger our health by affecting our food and
water sources, the air we breathe, the weather we experience, and our
interactions with the natural and built environments. For example,
atmospheric concentrations of one of these GHGs, CO2,
measured at Mauna Loa in Hawaii and at other sites around the world
reached 414 ppm in 2020 (nearly 50 percent higher than pre-industrial
levels),\27\ and has continued to rise at a rapid rate. Global average
temperature has increased by about 1.1 degrees Celsius ([deg]C) (2.0
degrees Fahrenheit ([deg]F)) in the 2011-2020 decade relative to 1850-
1900.\28\ The years 2014-2020 were the warmest seven years in the 1880-
2020 record, contributing to the warmest decade on record with a
decadal temperature of 0.82 [deg]C (1.48 [deg]F) above the 20th
century.\29\ \30\ The IPCC determined (with medium confidence) that
this past decade was warmer than any multi-century period in at least
the past 100,000 years.\31\ Global average sea level has risen by about
8 inches (about 21 centimeters (cm)) from 1901 to 2018, with the rate
from 2006 to 2018 (0.15 inches/year or 3.7 millimeters (mm)/year)
almost twice the rate over the 1971 to 2006 period, and three times the
rate of the 1901 to 2018 period.\32\ The rate of sea level rise over
the 20th century was higher than in any other century in at least the
last 2,800 years.\33\ Higher CO2 concentrations have led to
acidification of the surface ocean in recent decades to an extent
unusual in the past 2 million years, with negative impacts on marine
organisms that use calcium carbonate to build shells or skeletons.\34\
Arctic sea ice extent continues to decline in all months of the year;
the most rapid reductions occur in September (very likely almost a 13
percent decrease per decade between 1979 and 2018) and are
unprecedented in at least 1,000 years.\35\ Human-induced climate change
has led to heatwaves and heavy precipitation becoming more frequent and
more intense, along with increases in
[[Page 63126]]
agricultural and ecological droughts \36\ in many regions.\37\
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\27\ https://climate.nasa.gov/vital-signs/carbon-dioxide/.
\28\ IPCC, 2021.
\29\ NOAA National Centers for Environmental Information, State
of the Climate: Global Climate Report for Annual 2020, published
online January 2021, retrieved on February 10, 2021 from https://www.ncdc.noaa.gov/sotc/global/202013.
\30\ Blunden, J., and D.S. Arndt, Eds., 2020: State of the
Climate in 2019. Bull. Amer. Meteor. Soc, S1-S429, https://doi.org/10.1175/2020BAMSStateoftheClimate.1.
\31\ IPCC, 2021.
\32\ IPCC, 2021.
\33\ USGCRP, 2018: Impacts, Risks, and Adaptation in the United
States: Fourth National Climate Assessment, Volume II [Reidmiller,
D.R., C.W. Avery, D.R. Easterling, K.E. Kunkel, K.L.M. Lewis, T.K.
Maycock, and B.C. Stewart (eds.)]. U.S. Global Change Research
Program, Washington, DC, USA, 1515 pp. doi: 10.7930/NCA4.2018.
\34\ IPCC, 2021.
\35\ IPCC, 2021.
\36\ These are drought measures based on soil moisture.
\37\ IPCC, 2021.
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The assessment literature demonstrates that modest additional
amounts of warming may lead to a climate different from anything humans
have ever experienced. The present-day CO2 concentration of
414 ppm is already higher than at any time in the last 2 million
years.\38\ If concentrations exceed 450 ppm, they would likely be
higher than any time in the past 23 million years:\39\ at the current
rate of increase of more than 2 ppm a year, this would occur in about
15 years. While GHGs are not the only factor that controls climate, it
is illustrative that 3 million years ago (the last time CO2
concentrations were this high) Greenland was not yet completely covered
by ice and still supported forests, while 23 million years ago (the
last time concentrations were above 450 ppm) the West Antarctic ice
sheet was not yet developed, indicating the possibility that high GHGs
concentrations could lead to a world that looks very different from
today and from the conditions in which human civilization has
developed. If the Greenland and Antarctic ice sheets were to melt
substantially, sea levels would rise dramatically--the IPCC estimated
that over the next 2,000 years, sea level will rise by 7 to 10 feet
even if warming is limited to 1.5 [deg]C (2.7 [deg]F), from 7 to 20
feet if limited to 2 [deg]C (3.6 [deg]F), and by 60 to 70 feet if
warming is allowed to reach 5 [deg]C (9 [deg]F) above preindustrial
levels.\40\ For context, almost all of the city of Miami is less than
25 feet above sea level, and the NCA4 stated that 13 million Americans
would be at risk of migration due to 6 feet of sea level rise.
Moreover, the CO2 being absorbed by the ocean has resulted
in changes in ocean chemistry due to acidification of a magnitude not
seen in 65 million years,\41\ putting many marine species--particularly
calcifying species--at risk.
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\38\ IPCC, 2021.
\39\ IPCC, 2013.
\40\ IPCC, 2021.
\41\ IPCC, 2018.
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The NCA4 found that it is very likely (greater than 90 percent
likelihood) that by mid-century, the Arctic Ocean will be almost
entirely free of sea ice by late summer for the first time in about 2
million years.\42\ Coral reefs will be at risk for almost complete (99
percent) losses with 1 [deg]C (1.8 [deg]F) of additional warming from
today (2 [deg]C or 3.6 [deg]F since preindustrial). At this
temperature, between 8 and 18 percent of animal, plant, and insect
species could lose over half of the geographic area with suitable
climate for their survival, and 7 to 10 percent of rangeland livestock
would be projected to be lost.\43\
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\42\ USGCRP, 2018.
\43\ IPCC, 2018.
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Every additional increment of temperature comes with consequences.
For example, the half degree of warming from 1.5 to 2 [deg]C (0.9
[deg]F of warming from 2.7 [deg]F to 3.6 [deg]F) above preindustrial
temperatures is projected on a global scale to expose 420 million more
people to frequent extreme heatwaves, and 62 million more people to
frequent exceptional heatwaves (where heatwaves are defined based on a
heat wave magnitude index which takes into account duration and
intensity--using this index, the 2003 French heat wave that led to
almost 15,000 deaths would be classified as an ``extreme heatwave'' and
the 2010 Russian heatwave which led to thousands of deaths and
extensive wildfires would be classified as ``exceptional''). It would
increase the frequency of sea-ice-free Arctic summers from once in a
hundred years to once in a decade. It could lead to 4 inches of
additional sea level rise by the end of the century, exposing an
additional 10 million people to risks of inundation, as well as
increasing the probability of triggering instabilities in either the
Greenland or Antarctic ice sheets. Between half a million and a million
additional square miles of permafrost would thaw over several
centuries. Risks to food security would increase from medium to high
for several lower income regions in the Sahel, southern Africa, the
Mediterranean, central Europe, and the Amazon. In addition to food
security issues, this temperature increase would have implications for
human health in terms of increasing ozone concentrations, heatwaves,
and vector-borne diseases (for example, expanding the range of the
mosquitoes which carry dengue fever, chikungunya, yellow fever, and the
Zika virus, or the ticks which carry Lyme. babesiosis, or Rocky
Mountain Spotted Fever).\44\ Moreover, every additional increment in
warming leads to larger changes in extremes, including the potential
for events unprecedented in the observational record. Every additional
degree will intensify extreme precipitation events by about 7 percent.
The peak winds of the most intense tropical cyclones (hurricanes) are
projected to increase with warming. In addition to a higher intensity,
the IPCC found that precipitation and frequency of rapid
intensification of these storms has already increased, while the
movement speed has decreased, and elevated sea levels have increased
coastal flooding, all of which make these tropical cyclones more
damaging.\45\
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\44\ IPCC, 2018.
\45\ IPCC, 2021.
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The NCA4 also evaluated a number of impacts specific to the U.S.
Severe drought and outbreaks of insects like the mountain pine beetle
have killed hundreds of millions of trees in the western U.S. Wildfires
have burned more than 3.7 million acres in 14 of the 17 years between
2000 and 2016, and Federal wildfire suppression costs were about a
billion dollars annually.\46\ The National Interagency Fire Center has
documented U.S. wildfires since 1983, and the ten years with the
largest acreage burned have all occurred since 2004.\47\ Wildfire smoke
degrades air quality increasing health risks, and more frequent and
severe wildfires due to climate change would further diminish air
quality, increase incidences of respiratory illness, impair visibility,
and disrupt outdoor activities, sometimes thousands of miles from the
location of the fire. Meanwhile, sea level rise has amplified coastal
flooding and erosion impacts, requiring the installation of costly pump
stations, flooding streets, and increasing storm surge damages. Tens of
billions of dollars of U.S. real estate could be below sea level by
2050 under some scenarios. Increased frequency and duration of drought
will reduce agricultural productivity in some regions, accelerate
depletion of water supplies for irrigation, and expand the distribution
and incidence of pests and diseases for crops and livestock. The NCA4
also recognized that climate change can increase risks to national
security, both through direct impacts on military infrastructure, but
also by affecting factors such as food and water availability that can
exacerbate conflict outside U.S. borders. Droughts, floods, storm
surges, wildfires, and other extreme events stress nations and people
through loss of life, displacement of populations, and impacts on
livelihoods.\48\
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\46\ USGCRP, 2018
\47\ NIFC (National Interagency Fire Center). 2021. Total
wildland fires and acres (1983-2020). Accessed August 2021.
www.nifc.gov/fireInfo/fireInfo_stats_totalFires.html.
\48\ USGCRP, 2018.
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Some GHGs also have impacts beyond those mediated through climate
change. For example, elevated concentrations of carbon dioxide
stimulate plant growth (which can be positive in the case of beneficial
species, but negative in terms of weeds and invasive species, and can
also lead to a reduction in plant
[[Page 63127]]
micronutrients) \49\ and cause ocean acidification. Nitrous oxide
depletes the levels of protective stratospheric ozone.\50\
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\49\ Ziska, L., A. Crimmins, A. Auclair, S. DeGrasse, J.F.
Garofalo, A.S. Khan, I. Loladze, A.A. P[eacute]rez de Le[oacute]n,
A.Showler, J. Thurston, and I. Walls, 2016: Ch. 7: Food Safety,
Nutrition, and Distribution. The Impacts of Climate Change on Human
Health in the United States: A Scientific Assessment. U.S. Global
Change Research Program, Washington, DC, 189-216. http://dx.doi.org/10.7930/J0ZP4417
\50\ WMO (World Meteorological Organization), Scientific
Assessment of Ozone Depletion: 2018, Global Ozone Research and
Monitoring Project--Report No. 58, 588 pp., Geneva, Switzerland,
2018.
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As methane is the primary GHG addressed in this proposal, it is
relevant to highlight some specific trends and impacts specific to
methane. Concentrations of methane reached 1879 parts per billion (ppb)
in 2020, more than two and a half times the preindustrial concentration
of 722 ppb.\51\ Moreover, the 2020 concentration was an increase of
almost 13 ppb over 2019--the largest annual increase in methane
concentrations of the period since the early 1990s, continuing a trend
of rapid rise since a temporary pause ended in 2007.\52\ Methane has a
high radiative efficiency--almost 30 times that of carbon dioxide per
ppb (and therefore, 80 times as much per unit mass).\53\ In addition,
methane contributes to climate change through chemical reactions in the
atmosphere that produce tropospheric ozone and stratospheric water
vapor. Human emissions of methane are responsible for about one third
of the warming due to well-mixed GHGs, the second most important human
warming agent after carbon dioxide.\54\ Because of the substantial
emissions of methane, and its radiative efficiency, methane mitigation
is one of the best opportunities for reducing near term warming.
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\51\ Blunden et al., 2020.
\52\ NOAA, https://gml.noaa.gov/webdata/ccgg/trends/ch4/ch4_annmean_gl.txt, accessed August 19th, 2021.
\53\ IPCC, 2021.
\54\ IPCC, 2021.
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The tropospheric ozone produced by the reaction of methane in the
atmosphere has harmful effects for human health and plant growth in
addition to its climate effects.\55\ In remote areas, methane is an
important precursor to tropospheric ozone formation.\56\ Approximately
50 percent of the global annual mean ozone increase since preindustrial
times is believed to be due to anthropogenic methane.\57\ Projections
of future emissions also indicate that methane is likely to be a key
contributor to ozone concentrations in the future.\58\ Unlike
NOX and VOC, which affect ozone concentrations regionally
and at hourly time scales, methane emissions affect ozone
concentrations globally and on decadal time scales given methane's long
atmospheric lifetime when compared to these other ozone precursors.\59\
Reducing methane emissions, therefore, will contribute to efforts to
reduce global background ozone concentrations that contribute to the
incidence of ozone-related health effects.\60\ The benefits of such
reductions are global and occur in both urban and rural areas.
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\55\ Nolte, C.G., P.D. Dolwick, N. Fann, L.W. Horowitz, V. Naik,
R.W. Pinder, T.L. Spero, D.A. Winner, and L.H. Ziska, 2018: Air
Quality. In Impacts, Risks, and Adaptation in the United States:
Fourth National Climate Assessment, Volume II [Reidmiller, D.R.,
C.W. Avery, D.R. Easterling, K.E. Kunkel, K.L.M. Lewis, T.K.
Maycock, and B.C. Stewart (eds.)]. U.S. Global Change Research
Program, Washington, DC, USA, pp. 512-538. doi: 10.7930/NCA4. 2018.
CH13
\56\ U.S. EPA. 2013. ``Integrated Science Assessment for Ozone
and Related Photochemical Oxidants (Final Report).'' EPA-600-R-10-
076F. National Center for Environmental Assessment--RTP Division.
Available at http://www.epa.gov/ncea/isa/.
\57\ Myhre, G., D. Shindell, F.-M. Br[eacute]on, W. Collins, J.
Fuglestvedt, J. Huang, D. Koch, J.-F. Lamarque, D. Lee, B. Mendoza,
T. Nakajima, A. Robock, G. Stephens, T. Takemura and H. Zhang, 2013:
Anthropogenic and Natural Radiative Forcing. In: Climate Change
2013: The Physical Science Basis. Contribution of Working Group I to
the Fifth Assessment Report of the Intergovernmental Panel on
Climate Change [Stocker, T.F., D. Qin, G.-K. Plattner, M. Tignor,
S.K. Allen, J. Boschung, A. Nauels, Y. Xia, V. Bex and P.M. Midgley
(eds.)]. Cambridge University Press, Cambridge, United Kingdom and
New York, NY, USA. Pg. 680.
\58\ Ibid.
\59\ Ibid.
\60\ USGCRP, 2018.
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These scientific assessments and documented observed changes in the
climate of the planet and of the U.S. present clear support regarding
the current and future dangers of climate change and the importance of
GHG mitigation.
2. VOC
Many VOC can be classified as HAP (e.g., benzene),\61\ which can
lead to a variety of health concerns such as cancer and noncancer
illnesses (e.g., respiratory, neurological). Further, VOC are one of
the key precursors in the formation of ozone. Tropospheric, or ground-
level, ozone is formed through reactions of VOC and NOX in
the presence of sunlight. Ozone formation can be controlled to some
extent through reductions in emissions of the ozone precursors VOC and
NOX. Recent observational and modeling studies have found
that VOC emissions from oil and natural gas operations can impact ozone
levels.\62\ \63\ \64\ \65\ A significantly expanded body of scientific
evidence shows that ozone can cause a number of harmful effects on
health and the environment. Exposure to ozone can cause respiratory
system effects such as difficulty breathing and airway inflammation.
For people with lung diseases such as asthma and chronic obstructive
pulmonary disease (COPD), these effects can lead to emergency room
visits and hospital admissions. Studies have also found that ozone
exposure is likely to cause premature death from lung or heart
diseases. In addition, evidence indicates that long-term exposure to
ozone is likely to result in harmful respiratory effects, including
respiratory symptoms and the development of asthma. People most at risk
from breathing air containing ozone include children; people with
asthma and other respiratory diseases; older adults; and people who are
active outdoors, especially outdoor workers. An estimated 25.9 million
people have asthma in the U.S., including almost 7.1 million children.
Asthma disproportionately affects children, families with lower
incomes, and minorities, including Puerto Ricans, Native Americans/
Alaska Natives, and African Americans.\66\
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\61\ Benzene Integrated Risk Information System (IRIS)
Assessment: https://cfpub.epa.gov/ncea/iris2/chemicalLanding.cfm?substance_nmbr=276.
\62\ Benedict, K. B., Zhou, Y., Sive, B. C., Prenni, A. J.,
Gebhart, K. A., Fischer, E. V., . . . & Collett Jr, J. L. 2019.
Volatile organic compounds and ozone in Rocky Mountain National Park
during FRAPPE. Atmospheric Chemistry and Physics, 19(1), 499-521.
\63\ Lindaas, J., Farmer, D. K., Pollack, I. B., Abeleira, A.,
Flocke, F., & Fischer, E. V. 2019. Acyl peroxy nitrates link oil and
natural gas emissions to high ozone abundances in the Colorado Front
Range during summer 2015. Journal of Geophysical Research:
Atmospheres, 124(4), 2336-2350.
\64\ McDuffie, E. E., Edwards, P. M., Gilman, J. B., Lerner, B.
M., Dub[eacute], W. P., Trainer, M., . . . & Brown, S. S. 2016.
Influence of oil and gas emissions on summertime ozone in the
Colorado Northern Front Range. Journal of Geophysical Research:
Atmospheres, 121(14), 8712-8729.
\65\ Tzompa[hyphen]Sosa, Z. A., & Fischer, E. V. 2021. Impacts
of emissions of C2[hyphen]C5 alkanes from the US oil and gas sector
on ozone and other secondary species. Journal of Geophysical
Research: Atmospheres, 126(1), e2019JD031935.
\66\ National Health Interview Survey (NHIS) Data, 2011. http://www.cdc.gov/asthma/nhis/2011/data.htm.
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In the EPA's 2020 Integrated Science Assessment (ISA) for Ozone and
Related Photochemical Oxidants,\67\ the EPA estimates the incidence of
air pollution effects for those health endpoints above where the ISA
classified as either causal or likely-to-be-causal. In brief, the ISA
for ozone found short-term (less than one month) exposures to ozone to
be
[[Page 63128]]
causally related to respiratory effects, a ``likely to be causal''
relationship with metabolic effects and a ``suggestive of, but not
sufficient to infer, a causal relationship'' for central nervous system
effects, cardiovascular effects, and total mortality. The ISA reported
that long-term exposures (one month or longer) to ozone are ``likely to
be causal'' for respiratory effects including respiratory mortality,
and a ``suggestive of, but not sufficient to infer, a causal
relationship'' for cardiovascular effects, reproductive effects,
central nervous system effects, metabolic effects, and total mortality.
An example of quantified incidence of ozone health effects can be found
in the Regulatory Impact Analysis for the Final Revised Cross-State Air
Pollution Rule (CSAPR) Update.
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\67\ Integrated Science Assessment (ISA) for Ozone and Related
Photochemical Oxidants (Final Report). U.S. Environmental Protection
Agency, Washington, DC, EPA/600/R-20/012, 2020.
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Scientific evidence also shows that repeated exposure to ozone can
reduce growth and have other harmful effects on sensitive plants and
trees. These types of effects have the potential to impact ecosystems
and the benefits they provide.
3. SO2
Current scientific evidence links short-term exposures to
SO2, ranging from 5 minutes to 24 hours, with an array of
adverse respiratory effects including bronchoconstriction and increased
asthma symptoms. These effects are particularly important for
asthmatics at elevated ventilation rates (e.g., while exercising or
playing).
Studies also show an association between short-term exposure and
increased visits to emergency departments and hospital admissions for
respiratory illnesses, particularly in at-risk populations including
children, the elderly, and asthmatics.
SO2 in the air can also damage the leaves of plants,
decrease their ability to produce food--photosynthesis--and decrease
their growth. In addition to directly affecting plants, SO2,
when deposited on land and in estuaries, lakes, and streams, can
acidify sensitive ecosystems resulting in a range of harmful indirect
effects on plants, soils, water quality, and fish and wildlife (e.g.,
changes in biodiversity and loss of habitat, reduced tree growth, loss
of fish species). Sulfur deposition to waterways also plays a causal
role in the methylation of mercury.\68\
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\68\ U.S. EPA. Integrated Science Assessment (ISA) for Oxides of
Nitrogen and Sulfur Ecological Criteria (2008 Final Report). U.S.
Environmental Protection Agency, Washington, DC, EPA/600/R-08/082F,
2008.
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B. Oil and Natural Gas Industry and Its Emissions
This section generally describes the structure of the Oil and
Natural Gas Industry, the interconnected production, processing,
transmission and storage, and distribution segments that move product
from well to market, and types of emissions sources in each segment and
the industry's emissions.
1. Oil and Natural Gas Industry--Structure
The EPA characterizes the oil and natural gas industry's operations
as being generally composed of four segments: (1) Extraction and
production of crude oil and natural gas (``oil and natural gas
production''), (2) natural gas processing, (3) natural gas transmission
and storage, and (4) natural gas distribution.\69\ \70\ The EPA
regulates oil refineries as a separate source category; accordingly, as
with the previous oil and gas NSPS rulemakings, for purposes of this
proposed rulemaking, for crude oil, the EPA's focus is on operations
from the well to the point of custody transfer at a petroleum refinery,
while for natural gas, the focus is on all operations from the well to
the local distribution company custody transfer station commonly
referred to as the ``city-gate.'' \71\
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\69\ The EPA previously described an overview of the sector in
section 2.0 of the 2011 Background Technical Support Document to 40
CFR part 60, subpart OOOO, located at Docket ID Item No. EPA-HQ-OAR-
2010-0505-0045, and section 2.0 of the 2016 Background Technical
Support Document to 40 CFR part 60, subpart OOOOa, located at Docket
ID Item No. EPA-HQ-OAR-2010-0505-7631.
\70\ While generally oil and natural gas production includes
both onshore and offshore operations, 40 CFR part 60, subpart OOOOa
addresses onshore operations.
\71\ For regulatory purposes, the EPA defines the Crude Oil and
Natural Gas source category to mean (1) 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 (2) Natural gas production, processing,
transmission, and storage, which include the well and extend to, but
do not include, the local distribution company custody transfer
station. The distribution segment is not part of the defined source
category.
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a. Production Segment
The oil and natural gas production segment includes the wells and
all related processes used in the extraction, production, recovery,
lifting, stabilization, and separation or treatment of oil and/or
natural gas (including condensate). Although many wells produce a
combination of oil and natural gas, wells can generally be grouped into
two categories, oil wells and natural gas wells. Oil wells comprise two
types, oil wells that produce crude oil only and oil wells that produce
both crude oil and natural gas (commonly referred to as ``associated''
gas). Production equipment and components located on the well pad may
include, but are not limited to, wells and related casing heads; tubing
heads; ``Christmas tree'' piping, pumps, compressors; heater treaters;
separators; storage vessels; pneumatic devices; and dehydrators.
Production operations include well drilling, completion, and
recompletion processes, including all the portable non-self-propelled
apparatuses associated with those operations.
Other sites that are part of the production segment include
``centralized tank batteries,'' stand-alone sites where oil,
condensate, produced water, and natural gas from several wells may be
separated, stored, or treated. The production segment also includes
gathering pipelines, gathering and boosting compressor stations, and
related components that collect and transport the oil, natural gas, and
other materials and wastes from the wells to the refineries or natural
gas processing plants.
Of these products, crude oil and natural gas undergo successive,
separate processing. Crude oil is separated from water and other
impurities and transported to a refinery via truck, railcar, or
pipeline. As noted above, the EPA treats oil refineries as a separate
source category, accordingly, for present purposes, the oil component
of the production segment ends at the point of custody transfer at the
refinery.\72\
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\72\ See 40 CFR part 60, subparts J and Ja, and 40 CFR part 63,
subparts CC and UUU.
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The separated, unprocessed natural gas is commonly referred to as
field gas and is composed of methane, natural gas liquids (NGL), and
other impurities, such as water vapor, H2S, CO2,
helium, and nitrogen. Ethane, propane, butane, isobutane, and pentane
are all considered NGL and often are sold separately for a variety of
different uses. Natural gas with high methane content is referred to as
``dry gas,'' while natural gas with significant amounts of ethane,
propane, or butane is referred to as ``wet gas.'' Natural gas typically
is sent to gas processing plants in order to separate NGLs for use as
feedstock for petrochemical plants, burned for space heating and
cooking, or blended into vehicle fuel.
b. Processing Segment
The natural gas processing segment consists of separating certain
hydrocarbons (HC) and fluids from the natural gas to produce ``pipeline
quality'' dry natural gas. The degree and
[[Page 63129]]
location of processing is dependent on factors such as the type of
natural gas (e.g., wet or dry gas), market conditions, and company
contract specifications. Typically, processing of natural gas begins in
the field and continues as the gas is moved from the field through
gathering and boosting compressor stations to natural gas processing
plants, where the complete processing of natural gas takes place.
Natural gas processing operations separate and recover NGL or other
non-methane gases and liquids from field gas through one or more of the
following processes: oil and condensate separation, water removal,
separation of NGL, sulfur and CO2 removal, fractionation of
NGL, and other processes, such as the capture of CO2
separated from natural gas streams for delivery outside the facility.
c. Transmission and Storage Segment
Once natural gas processing is complete, the resulting natural gas
exits the natural gas process plant and enters the transmission and
storage segment where it is transmitted to storage and/or distribution
to the end user.
Pipelines in the natural gas transmission and storage segment can
be interstate pipelines, which carry natural gas across state
boundaries, or intrastate pipelines, which transport the gas within a
single state. Basic components of the two types of pipelines are the
same, though interstate pipelines may be of a larger diameter and
operated at a higher pressure. To ensure that the natural gas continues
to flow through the pipeline, the natural gas must periodically be
compressed, thereby increasing its pressure. Compressor stations
perform this function and are usually placed at 40- to 100-mile
intervals along the pipeline. At a compressor station, the natural gas
enters the station, where it is compressed by reciprocating or
centrifugal compressors.
Another part of the transmission and storage segment are
aboveground and underground natural gas storage facilities. Storage
facilities hold natural gas for use during peak seasons. The main
difference between underground and aboveground storage sites is that
storage takes place in storage vessels constructed of non-earthen
materials in aboveground storage. Underground storage of natural gas
typically occurs in depleted natural gas or oil reservoirs and salt
dome caverns. One purpose of this storage is for load balancing
(equalizing the receipt and delivery of natural gas). At an underground
storage site, typically other processes occur, including compression,
dehydration, and flow measurement.
d. Distribution Segment
The distribution segment provides the final step in delivering
natural gas to customers.\73\ The natural gas enters the distribution
segment from delivery points located along interstate and intrastate
transmission pipelines to business and household customers. The
delivery point where the natural gas leaves the transmission and
storage segment and enters the distribution segment is a local
distribution company's custody transfer station, commonly referred to
as the ``city-gate.'' Natural gas distribution systems consist of over
2 million miles of piping, including mains and service pipelines to the
customers. If the distribution network is large, compressor stations
may be necessary to maintain flow; however, these stations are
typically smaller than transmission compressor stations. Distribution
systems include metering stations and regulating stations, which allow
distribution companies to monitor the natural gas as it flows through
the system.
---------------------------------------------------------------------------
\73\ The distribution segment is not included in the definition
of the Crude Oil and Natural Gas source category that is currently
regulated under 40 CFR part 60, subpart OOOOa.
---------------------------------------------------------------------------
2. Oil and Natural Gas Industry--Emissions
The oil and natural gas industry sector is the largest source of
industrial methane emissions in the U.S.\74\ Natural gas is comprised
primarily of methane; every natural gas leak or intentional release
through venting or other industrial processes constitutes a release of
methane. Methane is a potent greenhouse gas; over a 100-year timeframe,
it is nearly 30 times more powerful at trapping climate warming heat
than CO2, and over a 20-year timeframe, it is 83 times more
powerful.\75\ Because methane is a powerful greenhouse gas and is
emitted in large quantities, reductions in methane emissions provide a
significant benefit in reducing near-term warming. Indeed, one third of
the warming due to GHGs that we are experiencing today is due to human
emissions of methane. Additionally, the Crude Oil and Natural Gas
sector emits, in varying concentrations and amounts, a wide range of
other health-harming pollutants, including VOCs, SO2,
NOX, H2S, CS2, and COS. The year 2016
modeling platform produced by U.S. EPA estimated about 3 million tons
of VOC are emitted by oil and gas-related sources.\76\
---------------------------------------------------------------------------
\74\ H.R. Rep. No. 117-64, 4 (2021) (Report by the House
Committee on Energy and Commerce concerning H.J. Res. 34, to
disapprove the 2020 Policy Rule) (House Report).
\75\ IPCC, 2021.
\76\ https://www.epa.gov/sites/default/files/2020-11/documents/2016v1_emismod_tsd_508.pdf.
---------------------------------------------------------------------------
Emissions of methane and these co-pollutants occur in every segment
of the Crude Oil and Natural Gas source category. Many of the processes
and equipment types that contribute to these emissions are found in
every segment of the source category and are highly similar across
segments. Emissions from the crude oil portion of the regulated source
category result primarily from field production operations, such as
venting of associated gas from oil wells, oil storage vessels, and
production-related equipment such as gas dehydrators, pig traps, and
pneumatic devices. Emissions from the natural gas portion of the
industry can occur in all segments. As natural gas moves through the
system, emissions primarily result from intentional venting through
normal operations, routine maintenance, unintentional fugitive
emissions, flaring, malfunctions, and system upsets. Venting can occur
through equipment design or operational practices, such as the
continuous and intermittent bleed of gas from pneumatic controllers
(devices that control gas flows, levels, temperatures, and pressures in
the equipment). In addition to vented emissions, emissions can occur
from leaking equipment (also referred to as fugitive emissions) in all
parts of the infrastructure, including major production and processing
equipment (e.g., separators or storage vessels) and individual
components (e.g., valves or connectors). Flares are commonly used
throughout each segment in the Oil and Natural Gas Industry as a
control device to provide pressure relief to prevent risk of explosions
and to destroy methane, which has a high global warming potential, and
convert it to CO2 which has a lower global warming
potential, and to also control other air pollutants such as VOC.
``Super-emitting'' events, sites, or equipment, where a small
proportion of sources account for a large proportion of overall
emissions, can occur throughout the Oil and Natural Gas Industry and
have been observed to occur in the equipment types and activities
covered by this proposed action. There are a number of definitions for
the term ``super-emitter.'' A 2018 National Academies of Sciences,
Engineering, and Medicine report \77\ on methane discussed three
categories of ``high-emitting'' sources:
---------------------------------------------------------------------------
\77\ https://www.nap.edu/download/24987#.
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[[Page 63130]]
Routine or ``chronic'' high-emitting sources, which
regularly emit at higher rates relative to ``peers'' in a sample.
Examples include large facilities, or large emissions at smaller
facilities caused by poor design or operational practices.
Episodic high-emitting sources, which are typically large
in nature and are generally intentional releases from known maintenance
events at a facility. Examples include gas well liquids unloading, well
workovers and maintenance activities, and compressor station or
pipeline blowdowns.
Malfunctioning high-emitting sources, which can be either
intermittent or prolonged in nature and result from malfunctions and
poor work practices. Examples include malfunctioning intermittent
pneumatic controllers and stuck open dump valves. Another example is
well blowout events. For example, a 2018 well blowout in Ohio was
estimated to have emitted over 60,000 tons of methane.\78\
---------------------------------------------------------------------------
\78\ Pandey et al. (2019). Satellite observations reveal extreme
methane leakage from a natural gas well blowout. PNAS December 26,
2019 116 (52) 26376-26381.
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Super-emitters have been observed at many different scales, from
site-level to component-level, across many research studies.\79\
Studies will often develop a study-specific definition such as a top
percentile of emissions in a study population (e.g., top 10 percent),
emissions exceeding a certain threshold (e.g., 26 kg/day), emissions
over a certain detection threshold (e.g., 1-3 g/s) or as facilities
with the highest proportional emission rate.\80\ For certain equipment
types and activities, the EPA's GHG emission estimates include the full
range of conditions, including ``super-emitters.'' For other
situations, where data are available, emissions estimates for abnormal
events are calculated separately and included in the Inventory of U.S.
Greenhouse Gas Emissions and Sinks (``GHGI'') (e.g., Aliso Canyon leak
event).\81\ Given the variability of practices and technologies across
oil and gas systems and the occurrence of episodic events, it is
possible that the EPA's estimates do not include all methane emissions
from abnormal events. The EPA continues to work through its stakeholder
process to review new data from the EPA's Greenhouse Gas Reporting
Program (``GHGRP'') petroleum and natural gas systems source category
(40 CFR part 98, subpart W, also referred to as ``GHGRP subpart W'')
and research studies to assess how emissions estimates can be improved.
Because lost gas, whether through fugitive emissions, unintentional gas
carry through, or intentional releases, represents lost earning
potential, the industry benefits from capturing and selling emissions
of natural gas (and methane). Limiting super-emitters through actions
included in this rule such as reducing fugitive emissions, using lower
emitting equipment where feasible, and employing best management
practices will not only reduce emissions but reduce the loss of revenue
from this valuable commodity.
---------------------------------------------------------------------------
\79\ See for example, Brandt, A., Heath, G., Cooley, D. (2016)
Methane leaks from natural gas systems follow extreme distributions.
Environ. Sci. Technol., DOI: 10.1021/acs.est.6b04303; Zavala-Araiza,
D., Alvarez, R.A., Lyon, D.R., Allen, D.T., Marchese, A.J.,
Zimmerle, D.J., & Hamburg, S.P. (2017). Super-emitters in natural
gas infrastructure are caused by abnormal process conditions. Nature
communications, 8, 14012; Mitchell, A., et al. (2015), Measurements
of Methane Emissions from Natural Gas Gathering Facilities and
Processing Plants: Measurement Results. Environmental Science &
Technology, 49(5), 3219-3227; Allen, D., et al. (2014), Methane
Emissions from Process Equipment at Natural Gas Production Sites in
the United States: Pneumatic Controllers. Environmental Science &
Technology.
\80\ Caulton et al. (2019). Importance of Super-emitter Natural
Gas Well Pads in the Marcellus Shale. Environ. Sci. Technol. 2019,
53, 4747-4754; Zavala-Araiza, D., Alvarez, R., Lyon, D, et al.
(2016). Super-emitters in natural gas infrastructure are caused by
abnormal process conditions. Nat Commun 8, 14012 (2017). https://www.nature.com/articles/ncomms14012; Lyon, et al. (2016). Aerial
Surveys of Elevated Hydrocarbon Emissions from Oil and Gas
Production Sites. Environ. Sci. Technol. 2016, 50, 4877-4886.
https://pubs.acs.org/doi/10.1021/acs.est.6b00705; and Zavala-Araiza
D, et al. (2015). Toward a functional definition of methane
superemitters: Application to natural gas production sites. 49
ENVTL. SCI. & TECH. 8167, 8168 (2015). https://pubs.acs.org/doi/10.1021/acs.est.5b00133.
\81\ The EPA's emission estimates in the GHGI are developed with
the best data available at the time of their development, including
data from the Greenhouse Gas Reporting Program (GHGRP) in 40 CFR
part 98, subpart W, and from recent research studies. GHGRP subpart
W emissions data used in the GHGI are quantified by reporters using
direct measurements, engineering calculations, or emission factors,
as specified by the regulation. The EPA has a multi-step data
verification process for GHGRP subpart W data, including automatic
checks during data-entry, statistical analyses on completed reports,
and staff review of the reported data. Based on the results of the
verification process, the EPA follows up with facilities to resolve
mistakes that may have occurred.
---------------------------------------------------------------------------
Below we provide estimated emissions of methane, VOC, and
SO2 from Oil and Natural Gas Industry operation sources.
Methane emissions in the U.S. and from the Oil and Natural Gas
industry. Official U.S. estimates of national level GHG emissions and
sinks are developed by the EPA for the GHGI in fulfillment of
commitments under the United Nations Framework Convention on Climate
Change. The GHGI, which includes recent trends, is organized by
industrial sector. The oil and natural gas production, natural gas
processing, and natural gas transmission and storage sectors emit 28
percent of U.S. anthropogenic methane. Table 7 below presents total
U.S. anthropogenic methane emissions for the years 1990, 2010, and
2019.
In accordance with the practice of the EPA GHGI, the EPA GHGRP, and
international reporting standards under the UN Framework Convention on
Climate Change, the 2007 IPCC Fourth Assessment Report value of the
methane 100-year GWP is used for weighting emissions in the following
tables. The 100-year GWP value of 25 for methane indicates that one ton
of methane has approximately as much climate impact over a 100-year
period as 25 tons of carbon dioxide. The most recent IPCC AR6
assessment has estimated a slightly larger 100-year GWP of methane of
almost 30 (specifically, either 27.2 or 29.8 depending on whether the
value includes the carbon dioxide produced by the oxidation of methane
in the atmosphere). As mentioned earlier, because methane has a shorter
lifetime than carbon dioxide, the emissions of a ton of methane will
have more impact earlier in the 100-year timespan and less impact later
in the 100-year timespan relative to the emissions of a 100-year GWP-
equivalent quantity of carbon dioxide: When using the AR6 20-year GWP
of 81, which only looks at impacts over the next 20 years, the total US
emissions of methane in 2019 would be equivalent to about 2140 MMT
CO2.
Table 7--U.S. Methane Emissions by Sector
[Million metric tons carbon dioxide equivalent (MMT CO2 EQ.)]
----------------------------------------------------------------------------------------------------------------
Sector 1990 2010 2019
----------------------------------------------------------------------------------------------------------------
Oil and Natural Gas Production, and Natural Gas Processing and 189 176 182
Transmission and Storage.......................................
Landfills....................................................... 177 124 114
Enteric Fermentation............................................ 165 172 179
[[Page 63131]]
Coal Mining..................................................... 96 82 47
Manure Management............................................... 37 55 62
Other Oil and Gas Sources....................................... 46 17 15
Wastewater Treatment............................................ 20 19 18
Other Methane Sources \82\...................................... 46 47 42
-----------------------------------------------
Total Methane Emissions..................................... 777 692 660
----------------------------------------------------------------------------------------------------------------
Emissions from the Inventory of United States Greenhouse Gas Emissions and Sinks: 1990-2019 (published April 14,
2021), calculated using GWP of 25. Note: Totals may not sum due to rounding.
Table 8 below presents total methane emissions from natural gas
production through transmission and storage and petroleum production,
for years 1990, 2010, and 2019, in MMT CO2 Eq. (or million
metric tons CO2 Eq.) of methane.
---------------------------------------------------------------------------
\82\ Other sources include rice cultivation, forest land,
stationary combustion, abandoned oil and natural gas wells,
abandoned coal mines, mobile combustion, composting, and several
sources emitting less than 1 MMT CO2 Eq. in 2019.
Table 8--U.S. Methane Emissions From Natural Gas and Petroleum Systems
[MMT CO2 EQ.]
----------------------------------------------------------------------------------------------------------------
Sector 1990 2010 2019
----------------------------------------------------------------------------------------------------------------
Natural Gas Production.......................................... 63 97 94
Natural Gas Processing.......................................... 21 10 12
Natural Gas Transmission and Storage............................ 57 30 37
Petroleum Production............................................ 48 39 38
----------------------------------------------------------------------------------------------------------------
Emissions from the Inventory of United States Greenhouse Gas Emissions and Sinks: 1990-2019 (published April 14,
2021), calculated using GWP of 25. Note: Totals may not sum due to rounding.
Global GHG Emissions. For additional background information and
context, we used 2018 World Resources Institute Climate Watch data to
make comparisons between U.S. oil and natural gas production and
natural gas processing and transmission and storage emissions and the
emissions inventories of entire countries and regions.\83\ The U.S.
methane emissions from oil and natural gas production and natural gas
processing and transmission and storage constitute 0.4 percent of total
global emissions of all GHGs (48,601 MMT CO2 Eq.) from all sources.\84\
Ranking U.S. emissions of methane from oil and natural gas production
and natural gas processing and transmission and storage against total
GHG emissions for entire countries (using 2018 Climate Watch data),
shows that these emissions are comparatively large as they exceed the
national-level emissions totals for all GHGs and all anthropogenic
sources for Colombia, the Czech Republic, Chile, Belgium, and over 160
other countries. What that means is that the U.S. emits more of a
single GHG--methane--from a single sector--the oil and gas sector--than
the total combined GHGs emitted by 164 out of 194 total countries.
Furthermore, U.S. emissions of methane from oil and natural gas
production and natural gas processing and transmission and storage are
greater than the sum of total emissions of 64 of the lowest-emitting
countries and territories, using the 2018 Climate Watch data set.
---------------------------------------------------------------------------
\83\ The Climate Watch figures presented here come from the PIK
PRIMAP-hist dataset included on Climate Watch. The PIK PRIMAP-hist
dataset combines the United Nations Framework Convention on Climate
Change (UNFCCC) reported data where available and fills gaps with
other sources. It does not include land use change and forestry but
covers all other sectors. https://www.climatewatchdata.org/ghg-emissions?end_year=2018&source=PIK&start_year=1990.
---------------------------------------------------------------------------
As illustrated by the domestic and global GHGs comparison data
summarized above, the collective GHG emissions from the Crude Oil and
Natural Gas source category are significant, whether the comparison is
domestic (where this sector is the largest source of methane emissions,
accounting for 28 percent of U.S. methane and 3 percent of total U.S.
emissions of all GHGs), global (where this sector, accounting for 0.4
percent of all global GHG emissions, emits more than the total national
emissions of over 160 countries, and combined emissions of over 60
countries), or when both the domestic and global GHG emissions
comparisons are viewed in combination. Consideration of the global
context is important. GHG emissions from U.S. Oil and Natural Gas
production and natural gas processing and transmission and storage will
become globally well-mixed in the atmosphere, and thus will have an
effect on the U.S. regional climate, as well as the global climate as a
whole for years and indeed many decades to come. No single GHG source
category dominates on the global scale. While the Crude Oil and Natural
Gas source category, like many (if not all) individual GHG source
categories, could appear small in comparison to total emissions, in
fact, it is a very important contributor in terms of both absolute
emissions, and in comparison to other source categories globally or
within the U.S.
The IPCC AR6 assessment determined that ``From a physical science
perspective, limiting human-induced global warming to a specific level
requires limiting cumulative CO2 emissions, reaching at
least net zero CO2 emissions, along with strong reductions
in other GHG emissions.'' The report also singled out the importance of
``strong and sustained CH4 emission reductions'' in part due
to the short lifetime of methane leading to the near-term cooling from
reductions in methane emissions, which can offset the warming that will
result due to reductions in emissions of cooling aerosols such as
SO2. Therefore, reducing methane emissions globally is an
important facet in any strategy to limit warming. In the oil and gas
sector,
[[Page 63132]]
methane reductions are highly achievable and cost-effective using
existing and well-known solutions and technologies that actually result
in recovery of saleable product.
VOC and SO2 emissions in the U.S. and from the oil and
natural gas industry. Official U.S. estimates of national level VOC and
SO2 emissions are developed by the EPA for the National
Emissions Inventory (NEI), for which States are required to submit
information under 40 CFR part 51, subpart A. Data in the NEI may be
organized by various data points, including sector, NAICS code, and
Source Classification Code. Tables 9 and 10 below present total U.S.
VOC and SO2 emissions by sector, respectively, for the year
2017, in kilotons (kt) (or thousand metric tons). The oil and natural
gas sector represents the top anthropogenic U.S. sector for VOC
emissions after removing the biogenics and wildfire sectors in Table 9
(about 20% of the total VOC emitting by anthropogenic sources). About
2.5 percent of the total U.S. anthropogenic SO2 comes from
the oil and natural gas sector.
Table 9--U.S. VOC Emissions by Sector
[kt]
------------------------------------------------------------------------
Sector 2017
------------------------------------------------------------------------
Biogenics--Vegetation and Soil.......................... 25,823
Fires--Wildfires........................................ 4,578
Oil and Natural Gas Production, and Natural Gas 2,504
Processing and Transmission............................
Fires--Prescribed Fires................................. 2,042
Solvent--Consumer and Commercial Solvent Use............ 1,610
Mobile--On-Road non-Diesel Light Duty Vehicles.......... 1,507
Mobile--Non-Road Equipment--Gasoline.................... 1,009
Other VOC Sources \85\.................................. 4,045
---------------
Total VOC Emissions................................. 43,118
------------------------------------------------------------------------
Emissions from the 2017 NEI (released April 2020). Note: Totals may not
sum due to rounding.
Table 10--U.S. SO2 Emissions by Sector
[kt]
------------------------------------------------------------------------
Sector 2017
------------------------------------------------------------------------
Fuel Combustion--Electric Generation--Coal.............. 1,319
Fuel Combustion--Industrial Boilers, Internal Combustion 212
Engines--Coal..........................................
Mobile--Commercial Marine Vessels....................... 183
Industrial Processes--Not Elsewhere Classified.......... 138
Fires--Wildfires........................................ 135
Industrial Processes--Chemical Manufacturing............ 123
Oil and Natural Gas Production and Natural Gas 65
Processing and Transmission............................
Other SO2 Sources \86\.................................. 551
---------------
Total SO2 Emissions................................. 2,726
------------------------------------------------------------------------
Emissions from the 2017 NEI (released April 2020). Note: Totals may not
sum due to rounding.
Table 11 below presents total VOC and SO2 emissions from
oil and natural gas production through transmission and storage, for
the year 2017, in kt. The contribution to the total anthropogenic VOC
emissions budget from the oil and gas sector has been increasing in
recent NEI cycles. In the 2017 NEI, the oil and gas sector makes up
about 25 percent of the total VOC emissions from anthropogenic sources.
The SO2 emissions have been declining in just about every
anthropogenic sector, but the oil and gas sector is an exception where
SO2 emissions have been slightly increasing or remaining
steady in some cases in recent years.
---------------------------------------------------------------------------
\85\ Other sources include remaining sources emitting less than
1,000 kt VOC in 2017.
\86\ Other sources include remaining sources emitting less than
100 kt SO2 in 2017.
Table 11--U.S. VOC and SO2 Emissions From Natural Gas and Petroleum
Systems
[kt]
------------------------------------------------------------------------
Sector VOC SO2
------------------------------------------------------------------------
Oil and Natural Gas Production.......... 2,478 41
Natural Gas Processing.................. 12 23
Natural Gas Transmission and Storage.... 14 1
------------------------------------------------------------------------
Emissions from the 2017 NEI, (published April 2020), in kt (or thousand
metric tons). Note: Totals may not sum due to rounding.
[[Page 63133]]
IV. Statutory Background and Regulatory History
A. Statutory Background of CAA Sections 111(b), 111(d) and General
Implementing Regulations
The EPA's authority for this rule is CAA section 111, which governs
the establishment of standards of performance for stationary sources.
This section requires the EPA to list source categories to be
regulated, establish standards of performance for air pollutants
emitted by new sources in that source category, and establish EG for
States to establish standards of performance for certain pollutants
emitted by existing sources in that source category.
Specifically, CAA section 111(b)(1)(A) requires that a source
category be included on the list for regulation if, ``in [the EPA
Administrator's] judgment it causes, or contributes significantly to,
air pollution which may reasonably be anticipated to endanger public
health or welfare.'' This determination is commonly referred to as an
``endangerment finding'' and that phrase encompasses both of the
``causes or contributes significantly to'' component and the ``endanger
public health or welfare'' component of the determination. Once a
source category is listed, CAA section 111(b)(1)(B) requires that the
EPA propose and then promulgate ``standards of performance'' for new
sources in such source category. 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 non-
air quality health and environmental impact and energy requirements)
the Administrator determines has been adequately demonstrated.'' As
long recognized by the D.C. Circuit, ``[b]ecause Congress did not
assign the specific weight the Administrator should accord each of
these factors, the Administrator is free to exercise his discretion in
this area.'' New York v. Reilly, 969 F.2d 1147, 1150 (D.C. Cir. 1992).
See also Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C. Cir.
1999) (``Lignite Energy Council'') (``Because section 111 does not set
forth the weight that be [sic] should assigned to each of these
factors, we have granted the agency a great degree of discretion in
balancing them'').
In determining whether a given system of emission reduction
qualifies as ``the best system of emission reduction . . . adequately
demonstrated,'' or ``BSER,'' CAA section 111(a)(1) requires that the
EPA take into account, among other factors, ``the cost of achieving
such reduction.'' As described in the proposal \87\ for the 2016 Rule
(85 FR 35824, June 3, 2016), the U.S. Court of Appeals for the District
of Columbia Circuit (the D.C. Circuit) has stated that in light of this
provision, the EPA may not adopt a standard the cost of which would be
``exorbitant,'' \88\ ``greater than the industry could bear and
survive,'' \89\ ``excessive,'' \90\ or ``unreasonable.'' \91\ These
formulations appear to be synonymous, and for convenience, in this
rulemaking, as in previous rulemakings, we will use reasonableness as
the standard, so that a control technology may be considered the ``best
system of emission reduction . . . adequately demonstrated'' if its
costs are reasonable, but cannot be considered the BSER if its costs
are unreasonable. See 80 FR 64662, 64720-21 (October 23, 2015).
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\87\ 80 FR 56593, 56616 (September 18, 2015).
\88\ Lignite Energy Council, 198 F.3d at 933.
\89\ Portland Cement Ass'n v. EPA, 513 F.2d 506, 508 (D.C. Cir.
1975).
\90\ Sierra Club v. Costle, 657 F.2d 298, 343 (D.C. Cir. 1981).
\91\ Id.
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CAA section 111(a) does not provide specific direction regarding
what metric or metrics to use in considering costs, affording the EPA
considerable discretion in choosing a means of cost consideration.\92\
In this rulemaking, we evaluated whether a control cost is reasonable
under a number of approaches that we find appropriate for assessing the
types of controls at issue. For example, in evaluating controls for
reducing VOC and methane emissions from new sources, we considered a
control's cost effectiveness under both a ``single pollutant cost-
effectiveness'' approach and a ``multipollutant cost-effectiveness''
approach, in order to appropriately take into account that the systems
of emission reduction considered in this rule typically achieve
reductions in multiple pollutants at once and secure a multiplicity of
climate and public health benefits.\93\ We also evaluated costs at a
sector level by assessing the projected new capital expenditures
required under the proposal (compared to overall new capital
expenditures by the sector) and the projected compliance costs
(compared to overall annual revenue for the sector) if the rule were to
require such controls. For a detailed discussion of these cost
approaches, please see section IX of the proposal preamble.
---------------------------------------------------------------------------
\92\ See, e.g., Husqvarna AB v. EPA, 254 F.3d 195, 200 (D.C.
Cir. 2001) (where CAA section 213 does not mandate a specific method
of cost analysis, the EPA may make a reasoned choice as to how to
analyze costs).
\93\ We believe that both the single and multipollutant
approaches are appropriate for assessing the reasonableness of the
multipollutant controls considered in this action. The EPA has
considered similar approaches in the past when considering multiple
pollutants that are controlled by a given control option. See e.g.,
80 FR 56616-56617; 73 FR 64079-64083 and EPA Document ID Nos. EPA-
HQ-OAR-2004-0022-0622, EPA-HQ-OAR-2004-0022-0447, EPA-HQ-OAR-2004-
0022-0448.
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As defined in CAA section 111(a), the ``standard of performance''
that the EPA develops, based on the BSER, is expressed as a performance
level (typically, a rate-based standard). CAA section 111(b)(5)
precludes the EPA from prescribing a particular technological system
that must be used to comply with a standard of performance. Rather,
sources can select any measure or combination of measures that will
achieve the standard.
CAA section 111(h)(1) authorizes the Administrator to promulgate
``a design, equipment, work practice, or operational standard, or
combination thereof'' if in his or her judgment, ``it is not feasible
to prescribe or enforce a standard of performance.'' CAA section
111(h)(2) provides the circumstances under which prescribing or
enforcing a standard of performance is ``not feasible,'' such as, when
the pollutant cannot be emitted through a conveyance designed to emit
or capture the pollutant, or when there is no practicable measurement
methodology for the particular class of sources.\94\ CAA section
111(b)(1)(B) requires the EPA to ``at least every 8 years review and,
if appropriate, revise'' performance standards unless the
``Administrator determines that such review is not appropriate in light
of readily available information on the efficacy'' of the standard.
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\94\ The EPA notes that design, equipment, work practice or
operational standards established under CAA section 111(h) (commonly
referred to as ``work practice standards'') reflect the ``best
technological system of continuous emission reduction'' and that
this phrasing differs from the ``best system of emission reduction''
phrase in the definition of ``standard of performance'' in CAA
section 111(a)(1). Although the differences in these phrases may be
meaningful in other contexts, for purposes of evaluating the sources
and systems of emission reduction at issue in this rulemaking, the
EPA has applied these concepts in an essentially comparable manner.
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As mentioned above, once the EPA lists a source category under CAA
section 111(b)(1)(A), CAA section 111(b)(1)(B) provides the EPA
discretion to determine the pollutants and sources to be regulated. In
addition, concurrent with the 8-year review (and though not a mandatory
part of the 8-year review), the EPA may examine whether to add
standards for pollutants or emission
[[Page 63134]]
sources not currently regulated for that source category.
Once the EPA establishes NSPS in a particular source category, the
EPA is required in certain circumstances to issue EG to reduce
emissions from existing sources in that same source category.
Specifically, CAA section 111(d) requires that the EPA prescribe
regulations to establish procedures under which States submit plans to
establish, implement, and enforce standards of performance for existing
sources for certain air pollutants to which a Federal NSPS would apply
if such existing source were a new source. The EPA addresses this CAA
requirement both through its promulgation of general implementing
regulations for section 111(d) as well as specific EG. The EPA first
published general implementing regulations in 1975, 40 FR 53340
(November 17, 1975) (codified at 40 CFR part 60, subpart B), and has
revised its section 111(d) implementing regulations several times, most
recently on July 8, 2019, 84 FR 32520 (codified at 40 CFR part 60,
subpart Ba).\95\ In accordance with CAA section 111(d), States are
required to submit plans pursuant to these regulations to establish
standards of performance for existing sources for any air pollutant:
(1) The emission of which is subject to a Federal NSPS; and (2) which
is neither a pollutant regulated under CAA section 108(a) (i.e.,
criteria pollutants such as ground-level ozone and particulate matter,
and their precursors, like VOC) \96\ or a HAP regulated under CAA
section 112. See also definition of ``designated pollutant'' in 40 CFR
60.21a(a). The EPA's general implementing regulations use the term
``designated facility'' to identify those existing sources that may be
subject to regulation under this provision of CAA section 111(d). See
40 CFR 60.21a(b).
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\95\ Subpart Ba provides for the applicability of its provisions
upon final publication of an EG if such EG is published after July
8, 2019. Sec. 60.20a(a). The EPA acknowledges that the D.C. Circuit
has vacated certain timing provisions within subpart Ba. Am. Lung
Assoc. v. EPA, 985 F.3d 914 (D.C. Cir. 2021), petition for cert.
pending, No. 20-1778 (filed June 23, 2001) (Am. Lung Assoc.).
However, the court did not vacate the applicability provision,
therefore subpart Ba applies to any EG finalized from this proposal.
The Agency plans to undertake rulemaking to address the provisions
vacated under the court's decision in the near future.
\96\ VOC are not listed as CAA section 108(a) pollutants, but
they are regulated precursors to photochemical oxidants (e.g.,
ozone) and particulate matter (PM), both of which are listed CAA
section 108(a) pollutants, and VOC therefore fall within the CAA
108(a) exclusion. Accordingly, promulgation of NSPS for VOC does not
trigger the application of CAA section 111(d).
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While States are authorized to establish standards of performance
for designated facilities, there is a fundamental obligation under CAA
section 111(d) that such standards of performance reflect the degree of
emission limitation achievable through the application of the BSER, as
determined by the Administrator. This obligation derives from the
definition of ``standard of performance'' under CAA section 111(a)(1),
which makes no distinction between new-source and existing-source
standards. The EPA identifies the degree of emission limitation
achievable through application of the BSER as part of its EG. See 40
CFR 60.22a(b)(5). While standards of performance must generally reflect
the degree of emission limitation achievable through application of the
BSER, CAA section 111(d)(1) also requires that the EPA regulations
permit the States, in applying a standard of performance to a
particular source, to take into account the source's remaining useful
life and other factors.
After the EPA issues final EG per the requirements under CAA
section 111(d) and 40 CFR part 60, subpart Ba, States are required to
submit plans that establish standards of performance for the designated
facilities as defined in the EPA's guidelines and that contain other
measures to implement and enforce those standards. The EPA's final EG
issued under CAA section 111(d) do not impose binding requirements
directly on sources, but instead provide requirements for States in
developing their plans and criteria for assisting the EPA when judging
the adequacy of such plans. Under CAA section 111(d), and the EPA's
implementing regulations, a State must submit its plan to the EPA for
approval, the EPA will evaluate the plan for completeness in accordance
with enumerated criteria, and then will act on that plan via a
rulemaking process to either approve or disapprove the plan in whole or
in part. If a State does not submit a plan, or if the EPA does not
approve a State's plan because it is not ``satisfactory,'' then the EPA
must establish a Federal plan for that State.\97\ If EPA approves a
State's plan, the provisions in the state plan become federally
enforceable against the designated facility responsible for compliance
in the same manner as the provisions of an approved State
implementation plan under CAA section 110. If no designated facility is
located within a State, the State must submit to the EPA a letter
certifying to that effect in lieu of submitting a State plan. See 40
CFR 60.23a(b).
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\97\ CAA section 111(d)(2)(A).
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Designated facilities located in Indian country would not be
addressed by a State's CAA section 111(d) plan. Instead, an eligible
Tribe that has one or more designated facilities located in its area of
Indian country \98\ would have the opportunity, but not the obligation,
to seek authority and submit a plan that establishes standards of
performance for those facilities on its Tribal lands.\99\ If a Tribe
does not submit a plan, or if the EPA does not approve a Tribe's plan,
then the EPA has the authority to establish a Federal plan for that
Tribe.\100\
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\98\ The EPA is aware of many oil and natural gas operations
located in Indian Country.
\99\ See 40 CFR part 49, subpart A.
\100\ CAA section 111(d)(2)(A).
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B. What is the regulatory history and litigation background of NSPS and
EG for the oil and natural gas industry?
1. 1979 Listing of Source Category
Subsequent to the enactment of the CAA of 1970, the EPA took action
to develop standards of performance for new stationary sources as
directed by Congress in CAA section 111. By 1977, the EPA had
promulgated NSPS for a total of 27 source categories, while NSPS for an
additional 25 source categories were then under development.\101\
However, in amending the CAA that year, Congress expressed
dissatisfaction that the EPA's pace was too slow. Accordingly, the 1977
CAA Amendments included a new subsection (f) in section 111, which
specified a schedule for the EPA to list additional source categories
under CAA section 111(b)(1)(A) and prioritize them for regulation under
CAA section 111(b)(1)(B).
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\101\ See 44 FR 49222 (August 21, 1979).
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In 1979, as required by CAA section 111(f), the EPA published a
list of source categories, which included ``Crude Oil and Natural Gas
Production,'' for which the EPA would promulgate standards of
performance under CAA section 111(b). See Priority List and Additions
to the List of Categories of Stationary Sources, 44 FR 49222 (August
21, 1979) (``1979 Priority List''). That list included, in the order of
priority for promulgating standards, source categories that the EPA
Administrator had determined, pursuant to CAA section 111(b)(1)(A),
contribute significantly to air pollution that may reasonably be
anticipated to endanger public health or welfare. See 44 FR 49223
(August 21, 1979); see also 49 FR 2636-37 (January 20, 1984).
[[Page 63135]]
2. 1985 NSPS for VOC and SO2 Emissions From Natural Gas
Processing Units
On June 24, 1985 (50 FR 26122), the EPA promulgated NSPS for the
Crude Oil and Natural Gas source category that addressed VOC emissions
from equipment leaks at onshore natural gas processing plants (40 CFR
part 60, subpart KKK). On October 1, 1985 (50 FR 40158), the EPA
promulgated additional NSPS for the source category to regulate
SO2 emissions from onshore natural gas processing plants (40
CFR part 60, subpart LLL).
3. 2012 NSPS OOOO Rule and Related Amendments
In 2012, pursuant to its duty under CAA section 111(b)(1)(B) to
review and, if appropriate, revise the 1985 NSPS, the EPA published the
final rule, ``Standards of Performance for Crude Oil and Natural Gas
Production, Transmission and Distribution,'' 77 FR 49490 (August 16,
2012) (40 CFR part 60, subpart OOOO) (``2012 NSPS OOOO''). The 2012
rule updated the SO2 standards for sweetening units and the
VOC standards for equipment leaks at onshore natural gas processing
plants. In addition, it established VOC standards for several oil and
natural gas-related operations emission sources not covered by 40 CFR
part 60, subparts KKK and LLL, including natural gas well completions,
centrifugal and reciprocating compressors, certain natural gas operated
pneumatic controllers in the production and processing segments of the
industry, and storage vessels in the production, processing, and
transmission and storage segments.
In 2013, 2014, and 2015 the EPA amended the 2012 NSPS OOOO rule in
order to address implementation of the standards. ``Oil and Natural Gas
Sector: Reconsideration of Certain Provisions of New Source Performance
Standards,'' 78 FR 58416 (September 23, 2013) (``2013 NSPS OOOO'')
(concerning storage vessel implementation); ``Oil and Natural Gas
Sector: Reconsideration of Additional Provisions of New Source
Performance Standards,'' 79 FR 79018 (December 31, 2014) (``2014 NSPS
OOOO'') (concerning well completion); ``Oil and Natural Gas Sector:
Definitions of Low Pressure Gas Well and Storage Vessel,'' 80 FR 48262
(August 12, 2015) (``2015 NSPS OOOO'') (concerning low pressure gas
wells and storage vessels).
The EPA received petitions for both judicial review and
administrative reconsiderations for the 2012, 2013, and 2014 NSPS OOOO
rules. The EPA denied reconsideration for some issues, see
``Reconsideration of the Oil and Natural Gas Sector: New Source
Performance Standards; Final Action,'' 81 FR 52778 (August 10, 2016),
and, as noted below, granted reconsideration for other issues. As
explained below, all litigation related to NSPS OOOO is currently in
abeyance.
4. 2016 NSPS OOOOa Rule and Related Amendments
Regulatory action. 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 (40
CFR part 60, subpart OOOOa) (``2016 Rule'' or ``2016 NSPS
OOOOa'').102 103 The 2016 NSPS OOOOa rule established NSPS
for sources of GHGs and VOC emissions for certain equipment, processes,
and operations across the Oil and Natural Gas Industry, including in
the transmission and storage segment. 81 FR at 35832. The EPA explained
that the 1979 listing identified the source category broadly enough to
include that segment and, in the alternative, if the listing had
limited the source category to the production and processing segments,
the EPA affirmatively expanded the source category to include the
transmission and storage segment on grounds that operations in those
segments are a sequence of functions that are interrelated and
necessary for getting the recovered gas ready for distribution. 81 FR
at 35832. In addition, because this rule was the first time that the
EPA had promulgated NSPS for GHG emissions from the Crude Oil and
Natural Gas source category, the EPA predicated those NSPS on a
determination that it had a rational basis to regulate GHG emissions
from the source category. 81 FR at 35843. In response to comments, the
EPA explained that it was not required to make an additional pollutant-
specific finding that GHG emissions from the source category contribute
significantly to dangerous air pollution, but in the alternative, the
EPA did make such a finding, relying on the same information that it
relied on when determining that it had a rational basis to promulgate a
GHGs NSPS. 81 FR at 35843.
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\102\ The June 3, 2016, rulemaking also included certain final
amendments to 40 CFR part 60, subpart OOOO, to address issues on
which the EPA had granted reconsideration.
\103\ The EPA review which resulted in the 2016 NSPS OOOOa rule
was instigated by a series of directives from then-President Obama
targeted at reducing GHGs, including methane: The President's
Climate Action Plan (June 2013); the President's Climate Action
Plan: Strategy to Reduce Methane Emissions (``Methane Strategy'')
(March 2014); and the President's goal to address, propose and set
standards for methane and ozone-forming emissions from new and
modified sources in the sector (January 2015, https://obamawhitehouse.archives.gov/the-press-office/2015/01/14/fact-sheet-Administration-takes-steps-forward-climate-action-plan-anno-1).
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Specifically, the 2016 NSPS OOOOa addresses the following emission
sources:
Sources that were unregulated under the 2012 NSPS OOOO
(hydraulically fractured oil well completions, pneumatic pumps, and
fugitive emissions from well sites and compressor stations);
Sources that were regulated under the 2012 NSPS OOOO for
VOC emissions, but not for GHG emissions (hydraulically fractured gas
well completions and equipment leaks at natural gas processing plants);
and
Certain equipment that is used across the source category,
of which the 2012 NSPS OOOO regulated emissions of VOC from only a
subset (pneumatic controllers, centrifugal compressors, and
reciprocating compressors, with the exception of those compressors
located at well sites).
On March 12, 2018 (83 FR 10628), the EPA finalized amendments to
certain aspects of the 2016 NSPS OOOOa requirements for the collection
of fugitive emission components at well sites and compressor stations,
specifically (1) the requirement that components on a delay of repair
must conduct repairs during unscheduled or emergency vent blowdowns,
and (2) the monitoring survey requirements for well sites located on
the Alaska North Slope.
Petitions for judicial review and to reconsider. Following
promulgation of the 2016 NSPS OOOOa rule, several states and industry
associations challenged the rule in the D.C. Circuit. The Administrator
also received five petitions for reconsideration of several provisions
of the final rule. Copies of the petitions are posted in Docket ID No.
EPA-HQ-OAR-2010-0505.\104\ As noted below, the EPA granted
reconsideration as to several issues raised with respect to the 2016
NSPS OOOOa rule and finalized certain modifications discussed in the
next section. As explained below, all litigation challenging the 2016
NSPS OOOOa rule is currently stayed.
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\104\ See Docket ID Item Nos.: EPA-HQ-OAR-2010-0505-7682, EPA-
HQ-OAR-2010-0505-7683, EPA-HQ-OAR-2010-0505-7684, EPA-HQ-OAR-2010-
0505-7685, EPA-HQ-OAR-2010-0505-7686.
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5. 2020 Policy and Technical Rules
Regulatory action. In September 2020, the EPA published two final
rules to amend 2012 NSPS OOOO and 2016 NSPS OOOOa. The first is titled,
``Oil
[[Page 63136]]
and Natural Gas Sector: Emission Standards for New, Reconstructed, and
Modified Sources Review.'' 85 FR 57018 (September 14, 2020). Commonly
referred to as the 2020 Policy Rule, it first rescinded the regulations
applicable to the transmission and storage segment on the basis that
the 1979 listing limited the source category to the production and
processing segments and that the transmission and storage segment is
not ``sufficiently related'' to the production and processing segments,
and therefore cannot be part of the same source category. 85 FR at
57027, 57029. In addition, the 2020 Policy Rule rescinded methane
requirements for the industry's production and processing segments on
two separate bases. The first was that such standards are redundant to
VOC standards for these segments. 85 FR at 57030. The second was that
the rule interpreted section 111 to require, or at least authorize the
Administrator to require, a pollutant-specific ``significant
contribution finding'' (SCF) as a prerequisite to a NSPS for a
pollutant, and to require that such finding be supported by some
identified standard or established set of criteria for determining
which contributions are ``significant.'' 85 FR at 57034. The rule went
on to conclude that the alternative significant-contribution finding
that the EPA made in the 2016 Rule for GHG emissions was flawed because
it accounted for emissions from the transmission and storage segment
and because it was not supported by criteria or a threshold. 85 FR at
57038.\105\
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\105\ Following the promulgation of the 2020 Policy Rule, the
EPA promulgated a final rule that identified a standard or criteria
for determining which contributions are ``significant,'' which the
D.C. Circuit vacated. ``Pollutant-Specific Significant Contribution
Finding for Greenhouse Gas Emissions From New, Modified, and
Reconstructed Stationary Sources: Electric Utility Generating Units,
and Process for Determining Significance of Other New Source
Performance Standards Source Categories.'' 86 FR 2542 (Jan. 13,
2021), vacated by California v. EPA, No. 21-1035 (D.C. Cir.) (Order,
April 5, 2021, Doc. #1893155).
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Published on September 15, 2020, the second of the two rules is
titled, ``Oil and Natural Gas Sector: Emission Standards for New,
Reconstructed, and Modified Sources Reconsideration.'' Commonly
referred to as the 2020 Technical Rule, this second rule made further
amendments to the 2016 NSPS OOOOa following the 2020 Policy Rule to
eliminate or reduce certain monitoring obligations and to address a
range of issues in response to administrative petitions for
reconsideration and other technical and implementation issues brought
to the EPA's attention since the 2016 NSPS OOOOa rulemaking.
Specifically, the 2020 Technical Rule exempted low-production well
sites from fugitives monitoring (previously required semiannually),
required semiannual monitoring at gathering and boosting compressor
stations (previously quarterly), streamlined recordkeeping and
reporting requirements, allowed compliance with certain equivalent
State requirements as an alternative to NSPS fugitive requirements,
streamlined the application process to request the use of new
technologies to monitor for fugitive emissions, addressed storage tank
batteries for applicability determination purposes and finalized
several technical corrections. Because the 2020 Technical Rule was
issued the day after the EPA's rescission of methane regulations in the
2020 Policy Rule, the amendments made in the 2020 Technical Rule
applied only to the requirements to regulate VOC emissions from this
source category. The 2020 Policy Rule amended 40 CFR part 60, subparts
OOOO and OOOOa, as finalized in 2016. The 2020 Technical Rule amended
the 40 CFR part 60, subpart OOOOa, as amended by the 2020 Policy Rule.
Petitions to reconsider. The EPA received three petitions for
reconsideration of the 2020 rulemakings. Two of the petitions sought
reconsideration of the 2020 Policy Rule. As discussed below, on June
30, 2021, the President signed into law S.J. Res. 14, a joint
resolution under the CRA disapproving the 2020 Policy Rule, and as a
result, the petitions for reconsideration on the 2020 Policy Rule are
now moot. All three petitions sought reconsideration of certain
elements of the 2020 Technical Rule.
Litigation. Several States and non-governmental organizations
challenged the 2020 Policy Rule as well as the 2020 Technical Rule. All
petitions for review regarding the 2020 Policy Rule were consolidated
into one case in the D.C. Circuit. State of California, et al. v. EPA,
No. 20-1357. On August 25, 2021, after the enactment of the joint
resolution of Congress disapproving the 2020 Policy Rule (explained in
section VIII below), the court granted petitioners motion to
voluntarily dismiss their cases. Id. ECF Dkt #1911437. All petitions
for review regarding the 2020 Technical Rule were consolidated into a
different case in the D.C. Circuit. Environmental Defense Fund, et al.
v. EPA, No. 20-1360 (D.C. Cir.). On February 19, 2021, the court issued
an order granting a motion by the EPA to hold in abeyance the
consolidated litigation over the 2020 Technical Rule pending EPA's
rulemaking actions in response to E.O. 13990 and pending the conclusion
of EPA's potential reconsideration of the 2020 Technical Rule. Id. ECF
Dkt #1886335.
As mentioned above, the EPA received petitions for judicial review
regarding the 2012, 2013, and 2014 NSPS OOOO rules as well as the 2016
NSPS OOOOa rule. The challenges to the 2012 NSPS OOOO rule (as amended
by the 2013 NSPS OOOO and 2014 NSPS OOOO rules) were consolidated.
American Petroleum Institute v. EPA, No. 13-1108 (D.C. Cir.). The
majority of those cases were further consolidated with the consolidated
challenges to the 2016 NSPS OOOOa rule. West Virginia v. EPA, No. 16-
1264 (D.C. Cir.), see specifically ECF Dkt #1654072. As such, West
Virginia v. EPA includes challenges to the 2012 NSPS OOOO rule (as
amended by the 2013 NSPS OOOO and 2014 NSPS OOOO rules) as well as
challenges to the 2016 NSPS OOOOa rule.\106\ On December 10, 2020, the
court granted a joint motion of the parties in West Virginia v. EPA to
hold that case in abeyance until after the mandate has issued in the
case regarding challenges to the 2020 Technical Rule. West Virginia v.
EPA, ECF Dkt #1875192.
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\106\ When the EPA issued the 2016 NSPS OOOOa rule, a challenge
to the 2012 NSPS OOOO rule for failing to regulate methane was
severed and assigned to a separate case, NRDC v. EPA, No. 16-1425
(D.C. Cir.), pending judicial review of the 2016 NSPS OOOOa in
American Petroleum Institute v. EPA, No. 13-1108 (D.C. Cir.).
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C. Congressional Review Act (CRA) Joint Resolution of Disapproval
On June 30, 2021, the President signed into law a joint resolution
of Congress, S.J. Res. 14, adopted under the CRA,\107\ disapproving the
2020 Policy Rule.\108\ By the terms of the CRA, the signing into law of
the CRA joint resolution of disapproval means that the 2020 Policy Rule
is ``treated as though [it] had never taken effect.'' 5 U.S.C. 801(f).
As a result, the VOC and methane standards for the transmission and
storage segment, as well as the methane standards for the production
and processing segments--all of which had been rescinded in the 2020
Policy Rule--remain in effect. In addition, the EPA's authority and
obligation to require the States to regulate existing sources of
methane in the Crude Oil and
[[Page 63137]]
Natural Gas source category under section 111(d) of the CAA also
remains in effect.
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\107\ The Congressional Review Act was adopted in Subtitle E of
the Small Business Regulatory Enforcement Fairness Act of 1996.
\108\ ``Oil and Natural Gas Sector: Emission Standards for New,
Reconstructed, and Modified Sources Review,'' 85 FR 57018 (Sept. 14,
2020) (``2020 Policy Rule'').
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The CRA resolution did not address the 2020 Technical Rule;
therefore, those amendments remain in effect with respect to the VOC
standards for the production and processing segments in effect at the
time of its enactment. As part of this rulemaking, in sections VIII and
X the EPA discusses the impact of the CRA resolution, and identifies
and proposes appropriate changes to reinstate the regulatory text that
had been rescinded by the 2020 Policy Rule and to resolve any
discrepancies in the regulatory text between the 2016 NSPS OOOOa Rule
and 2020 Technical Rule.
V. Related Emissions Reduction Efforts
This section summarizes related State actions and other Federal
actions regulating oil and natural gas emissions sources and summarizes
industry and voluntary efforts to reduce climate change. The proposed
NSPS OOOOb and EG OOOOc include specific measures that build on the
experience and knowledge the Agency and industry have gained through
voluntary programs, as well as the leadership of the States in
pioneering new regulatory programs. The proposed NSPS OOOOb and EG
OOOOc consists of reasonable, proven, cost-effective technologies and
practices that reflect the evolutionary nature of the Oil and Natural
Gas Industry and proactive regulatory and voluntary efforts. The EPA
intends that the requirements proposed in this document will spur all
industry stakeholders in all parts of the country to apply these
readily available and cost-effective measures.
A. Related State Actions and Other Federal Actions Regulating Oil and
Natural Gas Sources
The EPA recognizes that several States and other Federal agencies
currently regulate the Oil and Natural Gas Industry. The EPA also
recognizes that these State and other Federal agency regulatory
programs have matured since the EPA began implementing its 2012 NSPS
and subsequent 2016 NSPS. The EPA further acknowledges the technical
innovations that the Oil and Natural Gas Industry has made during the
past decade; this industry is fast-paced and constantly changing based
on the latest technology. The EPA commends these efforts and recognizes
States for their innovative standards, alternative compliance options,
and implementation strategies. The EPA recognizes that any one effort
will not be enough to address the increasingly dangerous impacts of
climate change on public health and welfare and believes that
consistent Federal regulation of the Crude Oil and Natural Gas source
category plays an important role. To have a meaningful impact on
climate change and its impact to human health and the environment, a
multifaceted approach needs to be taken to ensure methane reductions
will be realized. The EPA also recognizes that States and other Federal
agencies regulate in accordance with their own authorities and within
their own respective jurisdictions, and collectively do not fully
address the range of sources and emission reduction measures contained
in this proposal. Direct Federal regulation of methane from new sources
combined with the approved State plans that are consistent with the
EPA's EG for existing sources will bring national consistency to level
the regulatory playing field, help promote technological innovation,
and reduce both climate- and other health-harming pollution from a
large number of sources that are either currently unregulated or where
additional cost-effective reductions can be obtained. The EPA is
committed to working within its authority to provide opportunities to
align its programs with other existing State and Federal programs to
reduce unnecessary regulatory redundancy where appropriate.
Among assessing various studies and emissions data, the EPA
reviewed many current and proposed State regulatory programs to
identify potential regulatory options that could be considered for
BSER.\109\ For example, the EPA reviewed California, Colorado, and
Canadian regulations, as well as a pending proposed rule in New Mexico,
that require non-emitting pneumatic devices at certain facilities and
in certain circumstances. The EPA also examined California, Colorado,
New Mexico (proposed), Pennsylvania, Wyoming, and the Bureau of Land
Management (BLM) standards for liquids unloading events. Some of these
States have led the way in regulating emissions sources that were not
yet subject to requirements under the NSPS OOOOa. For example, Colorado
requires the use of best management practices to minimize hydrocarbon
emissions and the need for well venting associated with downhole well
maintenance and liquids unloading, unless venting is necessary for
safety. Other States, such as New Mexico, are evaluating similar
requirements. Other States have requirements for emission sources
currently regulated under NSPS OOOOa that are more stringent. For
example, California and Colorado require continuous bleed natural gas-
driven pneumatic controllers be non-emitting, with specified
exceptions. We recognize that, in some cases, the EPA's proposed NSPS
and/or EG may be more stringent than existing programs and, in other
cases, may be less stringent than existing programs. After careful
review and consideration of State regulatory programs in place and
proposed State regulations, we are proposing NSPS and EG that, when
implemented, will reduce emissions of harmful air pollutants, promote
gas capture and beneficial use, and provide opportunity for flexibility
and expanded transparency in order to yield a consistent and
accountable national program that provides a clear path for States and
other Federal agencies to further partner to ensure their programs work
in conjunction with each other.
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\109\ The NSPS OOOOb and EG TSD provides a high-level summary of
the state programs that the agency assessed for purposes of this
proposal.
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As an example of how the EPA strives to work with sources in States
that have overlapping regulations for the Oil and Natural Gas Industry,
the 2020 Technical Rule included approval of certain State programs as
alternatives to certain requirements in the Federal NSPS. Subject to
certain caveats, the EPA deemed certain fugitive emissions standards
for well sites and compressor stations located in specific States
equivalent to the NSPS in an effort to reduce any regulatory burden
imposed by duplicative State and Federal regulations. See 40 CFR
60.5399a. The EPA worked extensively with States and reviewed many
details of many State programs in this effort. Further, the 2020
Technical Rule amended 40 CFR part 60, subpart OOOOa, to incorporate a
process that allows other States not already listed in 40 CFR 60.5399a
to request approval of their fugitive monitoring program as an
alternative to the NSPS. The EPA is proposing to include a similar
request and approval process in NSPS OOOOb. Further, the EPA plans to
work closely with States as they develop their State plans pursuant to
the EG to look for opportunities to reduce unnecessary administrative
burden imposed by redundant and duplicative regulatory requirements and
help States that want to establish more stringent standards.
In addition to States, certain Federal agencies also regulate
aspects of the oil and natural gas industry pursuant to their own
authorities and have other established programs affecting the industry.
The EPA believes that Federal regulatory actions and efforts will
provide other environmental co-
[[Page 63138]]
benefits, but the EPA recognizes itself to be the Federal agency that
has primary responsibility to protect human health and the environment
and has been given the unique responsibility and authority by Congress
to address the suite of harmful air pollutants associated with this
source category. The EPA further believes that to have a meaningful
impact to address the dangers of climate change, it is going to require
an ``all hands-on deck'' effort across all States and all Federal
agencies. The EPA has maintained an ongoing dialogue with its Federal
partners during the development of this proposed rule to minimize any
potential regulatory conflicts and to minimize confusion and regulatory
burden on the part of owners and operators. The below description
summarizes other agencies' regulations and other established Federal
programs.
The U.S. Department of the Interior (DOI) regulates the extraction
of oil and gas from Federal lands. Bureaus within the DOI include BLM
and the Bureau of Ocean Energy Management (BOEM). The BLM manages the
Federal Government's onshore subsurface mineral estate--about 700
million acres (30 percent of the U.S.)--for the benefit of the American
public. The BLM maintains an oil and gas leasing program pursuant to
the Mineral Leasing Act, the Mineral Leasing Act for Acquired Lands,
the Federal Land Management and Policy Act, and the Federal Oil and Gas
Royalty Management Act. Pursuant to a delegation of Secretarial
authority, the BLM also oversees oil and gas operations on many Indian/
Tribal leases. The BLM's oil and gas operating regulations are found in
43 CFR part 3160. An oil and gas operator's general environmental and
safety obligations are found at 43 CFR 3162.5. The BLM does not
directly regulate emissions for the purposes of air quality. However,
BLM does regulate venting and flaring of natural gas for the purposes
of preventing waste. The governing Resource Management Plan may require
lessees to follow State and the EPA emissions regulations. An operator
may be required to control/mitigate emissions as a condition of
approval (COA) on a drilling permit. The need for such a COA is
determined by the environmental review process. The BLM's rules
governing the venting and flaring of gas are contained in NTL-4A, which
was issued in 1980. Under NTL-4A, limitations on royalty-free venting
and flaring constitute the primary mechanism for addressing the surface
waste of gas. In 2016, the BLM replaced NTL-4A with a new rule
governing venting and flaring (``Waste Prevention Rule''). In addition
to restricting royalty-free flaring, the rule set emissions standards
for tanks and pneumatic equipment and established LDAR requirements. In
2020, a U.S. District Court of Wyoming largely vacated that rule,
thereby reinstating NTL-4A. More detailed information can be found at
the BLM's website: https://www.blm.gov/programs/energy-and-minerals/oil-and-gas/operations-and-production/methane-and-waste-prevention-rule.
The BOEM manages the development of U.S. Outer Continental Shelf
(offshore) energy and mineral resources. BOEM has air quality
jurisdiction in the Gulf of Mexico \110\ and the North Slope Borough of
Alaska.\111\ BOEM also has air jurisdiction in Federal waters on the
Outer Continental Shelf 3-9 miles offshore (depending on State) and
beyond. The Outer Continental Shelf Lands Act (OCSLA) section 5(a)(8)
states, ``The Secretary of the Interior is authorized to prescribe
regulations `for compliance with the national ambient air quality
standards pursuant to the CAA . . . to the extent that activities
authorized under [the Outer Continental Shelf Lands Act] significantly
affect the air quality of any State.' '' The EPA and States have the
air jurisdiction onshore and in State waters, and the EPA has air
jurisdiction offshore in certain areas. More detailed information can
be found at BOEM's website: https://www.boem.gov/.
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\110\ The CAA gave BOEM air jurisdiction west of 87.5[deg]
longitude in the Gulf of Mexico region.
\111\ The Consolidated Appropriations Act of 2012 gave BOEM air
jurisdiction in the North Slope Borough of Alaska.
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The U.S. Department of Transportation (DOT) manages the U.S.
transportation system. Within DOT, the Pipeline and Hazardous Materials
Safety Administration (PHMSA) is responsible for regulating and
ensuring the safe and secure transport of energy and other hazardous
materials to industry and consumers by all modes of transportation,
including pipelines. While PHMSA regulatory requirements for gas
pipeline facilities have focused on human safety, which has attendant
environmental co-benefits, the ``Protecting our Infrastructure of
Pipelines and Enhancing Safety Act of 2020'' (Pub. L. 116-260, Division
R; ``PIPES Act of 2020''), which was signed into law on December 27,
2020, revised PHMSA organic statutes to emphasize the centrality of
environmental safety and protection of the environment in PHMSA
decision making. For example, the PHMSA's Office of Pipeline Safety
ensures safety in the design, construction, operation, maintenance, and
incident response of the U.S.' approximately 2.6 million miles of
natural gas and hazardous liquid transportation pipelines. When
pipelines are maintained, the likelihood of environmental releases like
leaks are reduced.\112\ In addition, the PIPES Act of 2020 contains
several provisions that specifically address the minimization of
releases of natural gas from pipeline facilities, such as a mandate
that the Secretary of Transportation promulgate regulations related to
gas pipeline LDAR programs. More detailed information can be found at
PHMSA's website: https://www.phmsa.dot.gov/.
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\112\ See Final Report on Leak Detection Study to PHMSA.
December 10, 2012. https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/technical-resources/pipeline/16691/leak-detection-study.pdf.
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The U.S. Department of Energy (DOE) develops oil and natural gas
policies and funds research on advanced fuels and monitoring and
measurement technologies. Specifically, the Advanced Research Projects
Agency-Energy (ARPA-E) program advances high-potential, high-impact
energy technologies that are too early for private-sector investment.
APRA-E awardees are unique because they are developing entirely new
technologies. More detailed information can be found at ARPA-E's
website: https://arpa-e.energy.gov/. Also, the U.S. Energy Information
Administration (EIA) compiles data on energy consumption, prices,
including natural gas, and coal. More detailed information can be found
at the EIA's website: https://www.eia.gov/.
The U.S. Federal Energy Regulatory Commission (FERC) is an
independent agency that regulates the interstate transmission of
electricity, natural gas,\113\ and oil.\114\ FERC also reviews
proposals to build liquefied natural gas terminals and interstate
natural gas pipelines as well as licensing hydropower projects. The
Commission's responsibilities for the crude oil industry include the
following: Regulation of rates and practices of oil pipeline companies
engaged in interstate transportation; establishment of equal service
conditions to provide shippers with equal access to pipeline
transportation; and establishment of reasonable rates for transporting
petroleum and petroleum products by pipeline. The Commission's
responsibilities for the natural gas industry include the following:
Regulation of pipeline, storage, and
[[Page 63139]]
liquefied natural gas facility construction; regulation of natural gas
transportation in interstate commerce; issuance of certificates of
public convenience and necessity to prospective companies providing
energy services or constructing and operating interstate pipelines and
storage facilities; regulation of facility abandonment, establishment
of rates for services; regulation of the transportation of natural gas
as authorized by the Natural Gas Policy Act and OCSLA; and oversight of
the construction and operation of pipeline facilities at U.S. points of
entry for the import or export of natural gas. FERC has no jurisdiction
over construction or maintenance of production wells, oil pipelines,
refineries, or storage facilities. More detailed information can be
found at FERC's website: https://www.ferc.gov/.
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\113\ https://www.ferc.gov/industries-data/natural-gas.
\114\ https://www.ferc.gov/industries-data/oil.
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B. Industry and Voluntary Actions To Address Climate Change
Separate from regulatory requirements, some owners or operators of
facilities in the Oil and Natural Gas Industry choose to participate in
voluntary initiatives. Specifically, over 100 oil and natural gas
companies participate in the EPA Natural Gas STAR and Methane Challenge
partnership programs. Owners or operators also participate in a growing
number of voluntary programs unaffiliated with the EPA voluntary
programs. The EPA is aware of at least 19 such initiatives.\115\ Firms
might participate in voluntary environmental programs for a variety of
reasons, including attracting customers, employees, and investors who
value more environmental-responsible goods and services; finding
approaches to improve efficiency and reduce costs; and preparing for or
helping inform future regulations.\116\ \117\
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\115\ Highwood Emissions Management (2021). ``Voluntary
Emissions Reduction Initiatives for Responsibly Sourced Oil and
Gas.'' Available for download at: https://highwoodemissions.com/research/.
\116\ Borck, J.C. and C. Coglianese (2009). ``Voluntary
Environmental Programs: Assessing Their Effectiveness.'' Annual
Review of Environment and Resources 34(1): 305-324.
\117\ Brouhle, K., C. Griffiths, and A. Wolverton. (2009).
``Evaluating the role of EPA policy levers: An examination of a
voluntary program and regulatory threat in the metal-finishing
industry.'' Journal of Environmental Economics and Management.
57(2): 166-181.
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The EPA's Natural Gas STAR Program started in 1993 and seeks to
achieve methane emission reductions through implementation of cost-
effective best practices and technologies. Partner companies document
their voluntary emission reduction activities and can report their
accomplishments to the EPA annually. Natural Gas STAR includes over 90
partners across the natural gas value chain. Through 2019 partner
companies report having eliminated nearly 1.7 trillion cubic feet of
methane emissions since 1993.
The EPA's Methane Challenge Program was launched in 2016 and
expands on the Natural Gas STAR Program with ambitious, quantifiable
commitments and detailed, transparent reporting and partner
recognition. Annually Methane Challenge partners submit facility-level
reports that characterize the methane emission sources at their
facilities and detail voluntary actions taken to reduce methane
emissions. The EPA emphasizes the importance of transparency with the
publication of these facility-level data. Although this program
includes nearly 70 companies from all segments of the industry, most
partners operate in the transmission and distribution segments.
Other voluntary programs for the oil and natural gas industry are
administered by diverse organizations, including trade associations and
non-profits. While the field of voluntary initiatives continues to
grow, it is difficult to understand the present, and potential future,
impact these initiatives will have on reducing methane emissions as the
majority of these initiatives publish aggregated program-level data.
The EPA recognizes the voluntary efforts of industry in reducing
methane emissions beyond what is required by current regulations and in
significantly expanding the understanding of methane mitigation
measures. While progress has been made, there is still considerable
remaining need to further reduce methane emissions from the Industry.
VI. Environmental Justice Considerations, Implications, and Stakeholder
Outreach
To better inform this proposed rulemaking, the EPA assessed the
characteristics of populations living near sources affected by the rule
and conducted extensive outreach to overburdened and underserved
communities and to environmental justice organizations. During our
engagement with communities, concerns were raised regarding health
effects of air pollutants, implications of climate change on lifestyle
changes, water quality, or extreme heat events, and accessibility to
data and information regarding sources near their homes. The EPA then
considered this input along with other stakeholder input in designing
the proposed rule. For example, one key issue identified through
stakeholder input is the use of cutting-edge technologies for methane
detection that can allow for rapid detection of high-emitting sources.
As described below, the EPA is proposing to allow the use of such
technologies in this rule, alongside a rigorous fugitive emissions
monitoring program that is based on traditional OGI technology. Another
key concern the Agency heard is addressing large emission sources
faster, which, in addition to seeking more information on new detection
technologies, the EPA is proposing to address with more frequent
monitoring at sites with more emissions. The EPA also heard that
adjacent communities are concerned about health impacts, and the EPA is
proposing rigorous guidelines for pollution sources at existing
facilities, methane standards for storage vessels, strengthened and
expanded standards for pneumatic controllers, and standards for liquids
unloading events that will further reduce emissions of those
pollutants. These are just a few examples of how this proposed rule
provides benefits to communities; section XII provides a full
explanation and rationale of the proposed actions.
E.O. 12898 directs the EPA to identify the populations of concern
who are most likely to experience unequal burdens from environmental
harms; specifically, minority populations, low-income populations, and
indigenous peoples. 59 FR 7629 (February 16, 1994). Additionally, E.O.
13985 was signed in 2021 to advance racial equity and support
underserved communities--including people of color and others who have
been historically underserved, marginalized, and adversely affected by
persistent poverty and inequality--through Federal Government actions.
86 FR 7009 (January 20, 2021). With respect to climate change, E.O.
14008, titled ``Tackling Climate Change at Home and Abroad,'' was
signed on January 27, 2021, stating that climate considerations shall
be an essential element of United States foreign policy and national
security, working in partnership with foreign governments, States,
territories, and local governments, and communities potentially
impacted by climate change. The EPA defines environmental justice (EJ)
as the fair treatment and meaningful involvement of all people
regardless of race, color, national origin, or income with respect to
the development, implementation, and enforcement of environmental laws,
regulations, and policies. The EPA further defines the term fair
treatment to
[[Page 63140]]
mean that ``no group of people should bear a disproportionate burden of
environmental harms and risks, including those resulting from the
negative environmental consequences of industrial, governmental, and
commercial operations or programs and policies'' (https://www.epa.gov/environmentaljustice). In recognizing that minority and low-income
populations often bear an unequal burden of environmental harms and
risks, the EPA continues to consider ways of protecting them from
adverse public health and environmental effects of air pollution
emitted from sources within the Oil and Natural Gas Industry that are
addressed in this proposed rulemaking.
A. Environmental Justice and the Impacts of Climate Change
In 2009, under the Endangerment and Cause or Contribute Findings
for Greenhouse Gases Under Section 202(a) of the Clean Air Act
(``Endangerment Finding'', 74 FR 66496), the Administrator considered
how climate change threatens the health and welfare of the U.S.
population.\118\ As part of that consideration, she also considered
risks to minority and low-income individuals and communities, finding
that certain parts of the U.S. population may be especially vulnerable
based on their characteristics or circumstances. These groups include
economically and socially disadvantaged communities, including those
that have been historically marginalized or overburdened; individuals
at vulnerable lifestages, such as the elderly, the very young, and
pregnant or nursing women; those already in poor health or with
comorbidities; the disabled; those experiencing homelessness, mental
illness, or substance abuse; and/or Indigenous or minority populations
dependent on one or limited resources for subsistence due to factors
including but not limited to geography, access, and mobility.
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\118\ Earlier studies and reports can be found at https://www.epa.gov/cira/social-vulnerability-report.
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Scientific assessment reports produced over the past decade by the
USGCRP,\119\ \120\ the IPCC,\121\ \122\ \123\ \124\ the National
Academies of Science, Engineering, and Medicine,\125\ \126\ and the EPA
\127\ add more evidence that the impacts of climate change raise
potential EJ concerns. These reports conclude that less-affluent,
traditionally marginalized and predominantly non-White communities can
be especially vulnerable to climate change impacts because they tend to
have limited resources for adaptation, are more dependent on climate-
sensitive resources such as local water and food supplies, or have less
access to social and information resources. Some communities of color,
specifically populations defined jointly by ethnic/racial
characteristics and geographic location (e.g., African-American, Black,
and Hispanic/Latino communities; Native Americans, particularly those
living on Tribal lands and Alaska Natives), may be uniquely vulnerable
to climate change health impacts in the U.S., as discussed below. In
particular, the 2016 scientific assessment on the Impacts of Climate
Change on Human Health \128\ found with high confidence that
vulnerabilities are place- and time-specific, lifestages and ages are
linked to immediate and future health impacts, and social determinants
of health are linked to greater extent and severity of climate change-
related health impacts.
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\119\ USGCRP, 2018: Impacts, Risks, and Adaptation in the United
States: Fourth National Climate Assessment, Volume II [Reidmiller,
D.R., C.W. Avery, D.R. Easterling, K.E. Kunkel, K.L.M. Lewis, T.K.
Maycock, and B.C. Stewart (eds.)]. U.S. Global Change Research
Program, Washington, DC, USA, 1515 pp. doi: 10.7930/NCA4.2018.
\120\ USGCRP, 2016: The Impacts of Climate Change on Human
Health in the United States: A Scientific Assessment. Crimmins, A.,
J. Balbus, J.L. Gamble, C.B. Beard, J.E. Bell, D. Dodgen, R.J.
Eisen, N. Fann, M.D. Hawkins, S.C. Herring, L. Jantarasami, D.M.
Mills, S. Saha, M.C. Sarofim, J. Trtanj, and L. Ziska, Eds. U.S.
Global Change Research Program, Washington, DC, 312 pp. http://dx.doi.org/10.7930/J0R49NQX.
\121\ Oppenheimer, M., M. Campos, R. Warren, J. Birkmann, G.
Luber, B. O'Neill, and K. Takahashi, 2014: Emergent risks and key
vulnerabilities. In: Climate Change 2014: Impacts, Adaptation, and
Vulnerability. Part A: Global and Sectoral Aspects. Contribution of
Working Group II to the Fifth Assessment Report of the
Intergovernmental Panel on Climate Change [Field, C.B., V.R. Barros,
D.J. Dokken, K.J. Mach, M.D. Mastrandrea, T.E. Bilir, M. Chatterjee,
K.L. Ebi, Y.O. Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N.
Levy, S. MacCracken, P.R. Mastrandrea, and L.L. White (eds.)].
Cambridge University Press, Cambridge, United Kingdom and New York,
NY, USA, pp. 1039-1099.
\122\ Porter, J.R., L. Xie, A.J. Challinor, K. Cochrane, S.M.
Howden, M.M. Iqbal, D.B. Lobell, and M.I. Travasso, 2014: Food
security and food production systems. In: Climate Change 2014:
Impacts, Adaptation, and Vulnerability. Part A: Global and Sectoral
Aspects. Contribution of Working Group II to the Fifth Assessment
Report of the Intergovernmental Panel on Climate Change [Field,
C.B., V.R. Barros, D.J. Dokken, K.J. Mach, M.D. Mastrandrea, T.E.
Bilir, M. Chatterjee, K.L. Ebi, Y.O. Estrada, R.C. Genova, B. Girma,
E.S. Kissel, A.N. Levy, S. MacCracken, P.R. Mastrandrea, and L.L.
White (eds.)]. Cambridge University Press, Cambridge, United Kingdom
and New York, NY, USA, pp. 485-533.
\123\ Smith, K.R., A. Woodward, D. Campbell-Lendrum, D.D.
Chadee, Y. Honda, Q. Liu, J.M. Olwoch, B. Revich, and R. Sauerborn,
2014: Human health: impacts, adaptation, and co-benefits. In:
Climate Change 2014: Impacts, Adaptation, and Vulnerability. Part A:
Global and Sectoral Aspects. Contribution of Working Group II to the
Fifth Assessment Report of the Intergovernmental Panel on Climate
Change [Field, C.B., V.R. Barros, D.J. Dokken, K.J. Mach, M.D.
Mastrandrea, T.E. Bilir, M. Chatterjee, K.L. Ebi, Y.O. Estrada, R.C.
Genova, B. Girma, E.S. Kissel, A.N. Levy, S. MacCracken, P.R.
Mastrandrea, and L.L. White (eds.)]. Cambridge University Press,
Cambridge, United Kingdom and New York, NY, USA, pp. 709-754.
\124\ IPCC, 2018: Global Warming of 1.5 [deg]C. An IPCC Special
Report on the impacts of global warming of 1.5 [deg]C above pre-
industrial levels and related global greenhouse gas emission
pathways, in the context of strengthening the global response to the
threat of climate change, sustainable development, and efforts to
eradicate poverty [Masson-Delmotte, V., P. Zhai, H.-O. P[ouml]rtner,
D. Roberts, J. Skea, P.R. Shukla, A. Pirani, W. Moufouma-Okia, C.
P[eacute]an, R. Pidcock, S. Connors, J.B.R. Matthews, Y. Chen, X.
Zhou, M.I. Gomis, E. Lonnoy, T. Maycock, M. Tignor, and T.
Waterfield (eds.)]. In Press.
\125\ National Research Council. 2011. America's Climate
Choices. Washington, DC: The National Academies Press. https://doi.org/10.17226/12781.
\126\ National Academies of Sciences, Engineering, and Medicine.
2017. Communities in Action: Pathways to Health Equity. Washington,
DC: The National Academies Press. https://doi.org/10.17226/24624.
\127\ EPA. 2021. Climate Change and Social Vulnerability in the
United States: A Focus on Six Impacts. U.S. Environmental Protection
Agency, EPA 430-R-21-003.
\128\ USGCRP, 2016: The Impacts of Climate Change on Human
Health in the United States: A Scientific Assessment.
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Per the NCA4, ``Climate change affects human health by altering
exposures to heat waves, floods, droughts, and other extreme events;
vector-, food- and waterborne infectious diseases; changes in the
quality and safety of air, food, and water; and stresses to mental
health and well-being.'' \129\ Many health conditions such as
cardiopulmonary or respiratory illness and other health impacts are
associated with and exacerbated by an increase in GHGs and climate
change outcomes, which is problematic as these diseases occur at higher
rates within vulnerable communities. Importantly, negative public
health outcomes include those that are physical in nature, as well as
mental, emotional, social, and economic.
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\129\ Ebi, K.L., J.M. Balbus, G. Luber, A. Bole, A. Crimmins, G.
Glass, S. Saha, M.M. Shimamoto, J. Trtanj, and J.L. White-Newsome,
2018: Human Health. In Impacts, Risks, and Adaptation in the United
States: Fourth National Climate Assessment, Volume II [Reidmiller,
D.R., C.W. Avery, D.R. Easterling, K.E. Kunkel, K.L.M. Lewis, T.K.
Maycock, and B.C. Stewart (eds.)]. U.S. Global Change Research
Program, Washington, DC, USA, pp. 539-571. doi: 10.7930/
NCA4.2018.CH14.
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The scientific assessment literature, including the aforementioned
reports, demonstrates that there are myriad ways
[[Page 63141]]
in which these populations may be affected at the individual and
community levels. Outdoor workers, such as construction or utility
workers and agricultural laborers, who are frequently part of already
at-risk groups, are exposed to poor air quality and extreme
temperatures without relief. Furthermore, individuals within EJ
populations of concern face greater housing and clean water insecurity
and bear disproportionate economic impacts and health burdens
associated with climate change effects. They also have less or limited
access to healthcare and affordable, adequate health or homeowner
insurance. The urban heat island effect can add additional stress to
vulnerable populations in densely populated cities who do not have
access to air conditioning.\130\ Finally, resiliency and adaptation are
more difficult for economically disadvantaged communities: They tend to
have less liquidity, individually and collectively, to move or to make
the types of infrastructure or policy changes necessary to limit or
reduce the hazards they face. They frequently face systemic,
institutional challenges that limit their power to advocate for and
receive resources that would otherwise aid in resiliency and hazard
reduction and mitigation.
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\130\ USGCRP, 2016.
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The assessment literature cited in the EPA's 2009 Endangerment
Finding, as well as Impacts of Climate Change on Human Health, also
concluded that certain populations and people in particular stages of
life, including children, are most vulnerable to climate-related health
effects. The assessment literature produced from 2016 to the present
strengthens these conclusions by providing more detailed findings
regarding related vulnerabilities and the projected impacts youth may
experience. These assessments--including the NCA4 (2018) and The
Impacts of Climate Change on Human Health in the United States (2016)--
describe how children's unique physiological and developmental factors
contribute to making them particularly vulnerable to climate change.
Impacts to children are expected from air pollution, infectious and
waterborne illnesses, and mental health effects resulting from extreme
weather events. In addition, children are among those especially
susceptible to allergens, as well as health effects associated with
heat waves, storms, and floods. Additional health concerns may arise in
low-income households, especially those with children, if climate
change reduces food availability and increases prices, leading to food
insecurity within households. More generally, these reports note that
extreme weather and flooding can cause or exacerbate poor health
outcomes by affecting mental health because of stress; contributing to
or worsening existing conditions, again due to stress or also as a
consequence of exposures to water and air pollutants; or by impacting
hospital and emergency services operations.\131\ Further, in urban
areas in particular, flooding can have significant economic
consequences due to effects on infrastructure, pollutant exposures, and
drowning dangers. The ability to withstand and recover from flooding is
dependent in part on the social vulnerability of the affected
population and individuals experiencing an event.\132\
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\131\ Ebi, K.L., J.M. Balbus, G. Luber, A. Bole, A. Crimmins, G.
Glass, S. Saha, M.M. Shimamoto, J. Trtanj, and J.L. White-Newsome,
2018: Human Health. In Impacts, Risks, and Adaptation in the United
States: Fourth National Climate Assessment, Volume II [Reidmiller,
D.R., C.W. Avery, D.R. Easterling, K.E. Kunkel, K.L.M. Lewis, T.K.
Maycock, and B.C. Stewart (eds.)]. U.S. Global Change Research
Program, Washington, DC, USA, pp. 539-571. doi: 10.7930/
NCA4.2018.CH14.
\132\ National Academies of Sciences, Engineering, and Medicine
2019. Framing the Challenge of Urban Flooding in the United States.
Washington, DC: The National Academies Press. https://doi.org/10.17226/25381.
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The Impacts of Climate Change on Human Health (USGCRP, 2016) also
found that some communities of color, low-income groups, people with
limited English proficiency, and certain immigrant groups (especially
those who are undocumented) live with many of the factors that
contribute to their vulnerability to the health impacts of climate
change. While difficult to isolate from related socioeconomic factors,
race appears to be an important factor in vulnerability to climate-
related stress, with elevated risks for mortality from high
temperatures reported for Black or African-American individuals
compared to White individuals after controlling for factors such as air
conditioning use. Moreover, people of color are disproportionately
exposed to air pollution based on where they live, and
disproportionately vulnerable due to higher baseline prevalence of
underlying diseases such as asthma, so climate exacerbations of air
pollution are expected to have disproportionate effects on these
communities. Locations with greater health threats include urban areas
(due to, among other factors, the ``heat island'' effect where built
infrastructure and lack of green spaces increases local temperatures),
areas where airborne allergens and other air pollutants already occur
at higher levels, and communities experienced depleted water supplies
or vulnerable energy and transportation infrastructure.
The recent EPA report on climate change and social vulnerability
\133\ examined four socially vulnerable groups (individuals who are low
income, minority, without high school diplomas, and/or 65 years and
older) and their exposure to several different climate impacts (air
quality, coastal flooding, extreme temperatures, and inland flooding).
This report found that Black and African-American individuals were 40%
more likely to currently live in areas with the highest projected
increases in mortality rates due to climate-driven changes in extreme
temperatures, and 34% more likely to live in areas with the highest
projected increases in childhood asthma diagnoses due to climate-driven
changes in particulate air pollution. The report found that Hispanic
and Latino individuals are 43% more likely to live in areas with the
highest projected labor hour losses in weather-exposed industries due
to climate-driven warming, and 50% more likely to live in coastal areas
with the highest projected increases in traffic delays due to increases
in high-tide flooding. The report found that American Indian and Alaska
Native individuals are 48% more likely to live in areas where the
highest percentage of land is projected to be inundated due to sea
level rise, and 37% more likely to live in areas with high projected
labor hour losses. Asian individuals were found to be 23% more likely
to live in coastal areas with projected increases in traffic delays
from high-tide flooding. Those with low income or no high school
diploma are about 25% more likely to live in areas with high projected
losses of labor hours, and 15% more likely to live in areas with the
highest projected increases in asthma due to climate-driven increases
in particulate air pollution, and in areas with high projected
inundation due to sea level rise.
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\133\ EPA. 2021. Climate Change and Social Vulnerability in the
United States: A Focus on Six Impacts. U.S. Environmental Protection
Agency, EPA 430-R-21-003.
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Impacts of Climate Change on Indigenous Communities. Indigenous
communities face disproportionate risks from the impacts of climate
change, particularly those communities impacted by degradation of
natural and cultural resources within established reservation
boundaries and threats to traditional subsistence lifestyles.
Indigenous communities whose health, economic well-being, and cultural
traditions depend upon the natural
[[Page 63142]]
environment will likely be affected by the degradation of ecosystem
goods and services associated with climate change. The IPCC indicates
that losses of customs and historical knowledge may cause communities
to be less resilient or adaptable.\134\ The NCA4 (2018) noted that
while indigenous peoples are diverse and will be impacted by the
climate changes universal to all Americans, there are several ways in
which climate change uniquely threatens indigenous peoples' livelihoods
and economies.\135\ In addition, there can be institutional barriers
(including policy-based limitations and restrictions) to their
management of water, land, and other natural resources that could
impede adaptive measures.
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\134\ Porter et al., 2014: Food security and food production
systems.
\135\ Jantarasami, L.C., R. Novak, R. Delgado, E. Marino, S.
McNeeley, C. Narducci, J. Raymond-Yakoubian, L. Singletary, and K.
Powys Whyte, 2018: Tribes and Indigenous Peoples. In Impacts, Risks,
and Adaptation in the United States: Fourth National Climate
Assessment, Volume II [Reidmiller, D.R., C.W. Avery, D.R.
Easterling, K.E. Kunkel, K.L.M. Lewis, T.K. Maycock, and B.C.
Stewart (eds.)]. U.S. Global Change Research Program, Washington,
DC, USA, pp. 572-603. doi: 10.7930/NCA4. 2018. CH15.
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For example, indigenous agriculture in the Southwest is already
being adversely affected by changing patterns of flooding, drought,
dust storms, and rising temperatures leading to increased soil erosion,
irrigation water demand, and decreased crop quality and herd sizes. The
Confederated Tribes of the Umatilla Indian Reservation in the Northwest
have identified climate risks to salmon, elk, deer, roots, and
huckleberry habitat. Housing and sanitary water supply infrastructure
are vulnerable to disruption from extreme precipitation events.
Confounding general Native American response to natural hazards are
limitations imposed by policies such as the Dawes Act of 1887 and the
Indian Reorganization Act of 1934, which ultimately restrict Indigenous
peoples' autonomy regarding land-management decisions through Federal
trusteeship of certain Tribal lands and mandated Federal oversight of
management decisions. Additionally, NCA4 noted that Indigenous peoples
are subjected to institutional racism effects, such as poor
infrastructure, diminished access to quality healthcare, and greater
risk of exposure to pollutants. Consequently, Native Americans often
have disproportionately higher rates of asthma, cardiovascular disease,
Alzheimer's disease, diabetes, and obesity. These health conditions and
related effects (e.g., disorientation, heightened exposure to
PM2.5, etc.) can all contribute to increased vulnerability
to climate-driven extreme heat and air pollution events, which also may
be exacerbated by stressful situations, such as extreme weather events,
wildfires, and other circumstances.
NCA4 and IPCC's Fifth Assessment Report \136\ also highlighted
several impacts specific to Alaskan Indigenous Peoples. Coastal erosion
and permafrost thaw will lead to more coastal erosion, rendering winter
travel riskier and exacerbating damage to buildings, roads, and other
infrastructure--impacts on archaeological sites, structures, and
objects that will lead to a loss of cultural heritage for Alaska's
indigenous people. In terms of food security, the NCA4 discussed
reductions in suitable ice conditions for hunting, warmer temperatures
impairing the use of traditional ice cellars for food storage, and
declining shellfish populations due to warming and acidification. While
the NCA4 also noted that climate change provided more opportunity to
hunt from boats later in the fall season or earlier in the spring, the
assessment found that the net impact was an overall decrease in food
security.
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\136\ Porter et al., 2014: Food security and food production
systems.
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B. Impacted Stakeholders
Based on analyses of exposed populations, the EPA has determined
that this action, if finalized in a manner similar to what is proposed
in this document, is likely to help reduce adverse effects of air
pollution on minority populations, and/or low-income populations that
have the potential for disproportionate impacts, as specified in E.O.
12898 (59 FR 7629, February 16, 1994) and referenced in E.O. 13985 (86
FR 7009, January 20, 2021). The EPA remains committed to engaging with
communities and stakeholders throughout the development of this
rulemaking and continues to invite comments on how the Agency can
better achieve these goals through this action. For this proposed rule,
we assessed emissions of HAP, criteria pollutants, and pollutants that
cause climate change.
For HAP emissions, we estimated cancer risks and the demographic
breakdown of people living in areas with potentially elevated risk
levels by performing dispersion modeling of the most recent NEI data
from 2017, which indicates nationwide emissions of approximately
110,000 tpy of over 40 HAP (including benzene, toluene, ethylbenzene,
xylenes, and formaldehyde) from the Oil and Natural Gas Industry. Table
12 gives the risk and demographic results for the Oil and Natural Gas
Industry from this screening-level assessment. We estimate there are
39,000 people with cancer risk greater than or equal to 100-in-1
million attributable to oil and natural gas sources, with a maximum
estimated risk of 200-in-1 million occurring in three census blocks (10
people). We estimate there are about 143,000 people with estimated risk
greater than or equal to 50-in-1 million, and about 6.8 million people
with estimated cancer risk greater than 1-in-1 million. It is important
to note that these estimates are subject to various types of
uncertainty related to input parameters and assumptions, including
emissions datasets, exposure modeling and the dose-response
relationships.\137\
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\137\ See `Risk Report Template' at Docket ID No. EPA-HQ-OAR-
2021-0317.
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As shown in Table 12, Hispanic and Latino populations and young
people (ages 0-17) are disproportionately represented in communities
exposed to elevated cancer risks from oil and natural gas sources,
while the proportion of people in other demographic groups with
estimated risks above the specified levels is at or below the national
average. The overall percent minority is about the same as the national
average, but the percentage of people exposed to cancer risks greater
than or equal to the 100-in-1 million and 50-in-1 million thresholds
who are Hispanic or Latino is about 10 percentage points higher than
the national average. The overall minority percentage is not elevated
compared to the national average because the African-American
percentage is much lower than the national average. The demographic
group of people aged 0-17 is slightly higher than the national average.
[[Page 63143]]
Table 12--Cancer Risk and Demographic Population Estimates for 2017 NEI Nonpoint Oil and Natural Gas Emissions
--------------------------------------------------------------------------------------------------------------------------------------------------------
--------------------------------------------------------------------------------------------------------------------------------------------------------
Risks >=100-in-1 million
Risks >=50-in-1 million
Risks >1-in-1 million Nationwide
--------------------------------------------------------------------------------------------------------------------------------------------------------
Total Population 39,000
143,000
6,805,000 ..............
--------------------------------------------------------------------------------------------------------------------------------------------------------
Population % Population % Population % %
--------------------------------------------------------------------------------------------------------------------------------------------------------
Minority................................ 13,268 34.1 52,154 36.5 2,010,161 29.5 39.9
African American........................ 140 0.4 1,434 1.0 535,055 7.9 12.2
Native American......................... 77 0.2 465 0.3 59,087 0.9 0.7
Other and Multiracial................... 1,443 3.7 5,148 3.6 323,397 4.8 8.2
Hispanic or Latino...................... 11,608 29.9 45,107 31.6 1,092,621 16.1 18.8
Age 0-17................................ 10,679 27.5 37,487 26.2 1,463,907 21.5 22.6
Age >=65................................ 4,272 11.0 17,188 12.0 1,085,067 15.9 15.7
Below the Poverty Level................. 2,000 5.1 13,455 9.4 902,472 13.2 13.4
Over 25 Without a High School Diploma... 2,788 7.2 11,320 7.9 488,372 7.2 12.1
Linguistically Isolated................. 808 2.1 4,418 3.1 179,739 2.6 5.4
--------------------------------------------------------------------------------------------------------------------------------------------------------
For criteria pollutants, we assessed exposures to ozone from Oil
and Natural Gas Industry VOC emissions across races/ethnicities, ages,
and sexes in a recent baseline (pre-control) air quality scenario.
Annual air quality was simulated using a photochemical model for the
year 2017, based on emissions from the most recent NEI. The analysis
shows that the distribution of exposures for all demographic groups
except Hispanic and Asian populations are similar to or below the
national average or a reference population. Differences between
exposures in Hispanic and Asian populations versus White or all
populations are modest, and the results are subject to various types of
uncertainty related to input parameters and assumptions.
In addition to climate and air quality impacts, the EPA also
conducted analyses to characterize potential impacts on domestic oil
and natural gas production and prices and to describe the baseline
distribution of employment and energy burdens. Section XVI.d describes
the results for our analysis of prices and production. For the
distribution of baseline employment, we assessed the demographic
characteristics of (1) workers in the oil and gas sector and (2) people
living in oil and natural gas intensive communities.\138\ Comparing
workers in the oil and natural gas sector to workers in other sectors,
oil and natural gas workers may have higher than average incomes, be
more likely to have completed high school, and be disproportionately
Hispanic. People in some oil and gas intensive communities concentrated
in Texas, Oklahoma, and Louisiana have lower average income levels,
lower rates of high school completion, and higher likelihood of being
non-Whites or hispanic than people living in communities that are not
oil and gas intensive. Regarding household energy burden, low-income
households, Hispanic, and Black households' energy expenditures may
comprise a disproportionate share of their total expenditures and
income as compared to higher income, non-Hispanic, and non-Black
households, respectively. Results are presented in detail in the RIA
accompanying this proposal.
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\138\ For this analysis, oil and natural gas intensive
communities are defined as the top 20% of communities with respect
to the proportion of oil and natural gas workers.
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In a proximity analysis of Tribes living within 50 miles of
affected sources, we found 112 unique Tribal lands (Federally
recognized Reservations, Off-Reservation Trust Lands, and Census
Oklahoma Tribal Statistical Areas (OTSA)) located within 50 miles of a
source with 32 Tribes having one or more sources located on Tribal
land.
Finally, the EPA has also analyzed prior enforcement actions
related to air pollution from storage vessels, and identified
improvements in air quality resulting from these actions as
particularly important in communities with EJ concerns (identified
using EJSCREEN).\139\ In a 2021 analysis of resolved enforcement
matters, the EPA determined that communities with EJ concerns
experience a disproportionate level of air pollution burden from
storage vessel emissions. Although only about 25 percent of storage
vessels were located in these communities with EJ concerns, 67 percent
of the total emission reductions of VOCs, methane, PM, and
NOX (about 95 million pounds) achieved through these
enforcement resolutions occurred in communities with EJ concerns. This
analysis suggests that the provisions of this proposed rule requiring
installation of controls at storage vessels and monitoring and
mitigation of fugitive emissions and malfunctions at storage vessels,
would have particular benefits for these communities.
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\139\ See Memorandum ``Analysis of Environmental Justice Impacts
of EPA's Historical Oil and Gas Storage Vessel Enforcement
Resolutions (40 CFR part 60 subpart OOOO and OOOOa),'' located at
Docket ID No. EPA-HQ-OAR-2021-0317.
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C. Outreach and Engagement
The EPA identified stakeholder groups likely to be interested in
this action and engaged with them in several ways including through
meetings, training webinars, and public listening sessions to share
information with stakeholders about this action, on how stakeholders
may comment on the proposed rule, and to hear their input about the
industry and its impacts as we were developing this proposal.
Specifically, on May 27, 2021, the EPA held a webinar-based training
designed for communities affected by this rule.\140\ This training
provided an overview of the Crude Oil and Natural Gas Industry and how
it is regulated and offered information on how to participate in the
rulemaking process. The EPA also held virtual public listening sessions
June 15 through June 17, 2021, and heard various community and health
related themes from speakers who participated.\141\ \142\ Community
themes
[[Page 63144]]
included concerns about protecting communities adjacent to oil and gas
activities, providing monitoring and data so communities know what is
in the air they are breathing, and upholding Tribal trust
responsibilities. Community speakers urged the EPA to adopt stringent
measures to reduce oil and natural gas pollution, and frequently cited
an analysis suggesting such measures could achieve reductions of 65
percent below 2012 levels by 2025.
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\140\ https://www.epa.gov/sites/default/files/2021-05/documents/us_epa_training_webinar_on_oil_and_natural_gas_for_communities.5.27.2021.pdf.
\141\ June 15, 2021 session: https://youtu.be/T8XwDbf-B8g; June
16, 2021 session: https://www.youtube.com/watch?v=l23bKPF-5oc; June
17, 2021 session: https://www.youtube.com/watch?v=R2AZrmfuAXQ.
\142\ Full transcripts for the listening sessions are posted at
EPA Docket ID No. EPA-HQ-OAR-2021-0295.
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Community Access to Emissions Information. Several stakeholders
requested that the rule include requirements that provide communities
with information, including fence line monitoring or ``better
monitoring so people will know the air they are breathing.'' A few
speakers expressed concerned about the correct placement of existing
air monitors. Speakers from Texas described local air monitors
monitoring meteorology and ozone, but not hazardous air pollutants, and
called on the EPA to consider alternative monitoring for oil and
natural gas sources such as fence-line monitors, along with guidance
from the EPA to require monitors of oil and natural gas facilities in
close proximity to parks, schools, and playgrounds.
Health Concerns in Adjacent Communities. Speakers raised concerns
about impacts on frontline communities and those communities adjacent
to oil and natural gas operations. These stakeholders called on the EPA
to propose and promulgate stricter standards or alternative
requirements for sources adjacent to urban communities and close to
where people live and work. Several speakers used the term ``energy
sacrifice zone'' when discussing the disproportionate impacts of oil
and natural gas operations on frontline communities. Speakers advocated
that when developing this regulatory effort, consultation with
frontline communities is essential, and some speakers cited a Center
for Investigative Reporting report stating that 30,000 children in
Arlington, Texas, attend school within half a mile of active oil and
gas sites. Speakers discussed concerns about methane as a formaldehyde
precursor and related health effects and cited examples of health
effects including hydraulic fracturing chemicals being measured in
blood or urine; increases in nosebleeds in people in areas of oil and
natural gas development; headaches and cancer. These speakers included
teenagers from Pennsylvania, who said they live within 1 mile of 33
wellheads and 500 feet of a pipeline. Several people cited a February
2018 blowout and explosion in Belmont County, Ohio, that was reported
to release 60,000 tons of methane in 20 days and said that is more than
some countries emit in a year. Speakers also expressed related
environmental concerns such as water contamination and fresh drinking
water being diverted for hydraulic fracturing. One speaker urged that
information on local water use be provided in languages other than
English, stating that in Big Spring (Howard County), Texas, the local
government only provided information to use tap water ``at your own
risk'' in English.
Additional concerns raised by communities included: Local
compressor stations having numerous planned and unplanned releases into
adjacent communities, which appear to be during startup; whether the
EPA will use a robust cost analysis to address the economic impacts of
labor loss and gas costs resulting from any regulation; if plugged and
abandoned wells included in this action, will this regulation apply to
BLM land; will States be required to use the same emissions calculation
used by the EPA for methane GWP; will there be disclosure of necessary
data collection or technology to be used by the Oil and Natural Gas
Industry to track and reduce methane emissions; and will the EPA
consider the necessity of venting and flaring from a safety standpoint.
Communities also discussed concerns about excess emissions from storage
vessels and the need for clarifying the applicability of the standard
in addition to improving enforceability and compliance at this type of
facility.
In addition to the trainings and listening sessions, the EPA
engaged with community leaders potentially impacted by this proposed
action by hosting a meeting with EJ community leaders on May 14, 2021.
As noted above, the EPA provided the public with factual information to
help them understand the issues addressed by this action. We obtained
input from the public, including communities, about their concerns
about air pollution from the oil and gas industry, including receiving
stakeholder perspectives on alternatives. The EPA considered and
weighed information from communities as the agency developed this
proposed action.
In addition to the engagement conducted prior to this proposal, the
EPA is providing the public, including those communities
disproportionately impacted by the burdens of pollution, opportunities
to engage in the EPA's public comment period for this proposal,
including by hosting public hearings. This public hearing will occur
according to the schedule identified in the DATES and SUPPLEMENTARY
INFORMATION section of this preamble to discuss:
What impacts they are experiencing (i.e., health, noise,
smells, economic),
How the community would like the EPA to address their
concerns,
How the EPA is addressing those concerns in the
rulemaking, and
Any other topics, issues, concerns, etc. that the public
may have regarding this proposal.
For more information about the EPA's pre-proposal outreach
activities, please see EPA Docket ID No. EPA-HQ-OAR-2021-0295. Please
refer to EPA Docket ID No. EPA-HQ-OAR-2021-0317 for submitting public
comments on this proposed rulemaking. For public input to be considered
during the formal rulemaking, please submit comments on this proposed
action to the formal regulatory docket at EPA Docket ID No. EPA-HQ-OAR-
2021-0317 so that the EPA may consider those comments during the
development of the final rule.
D. Environmental Justice Considerations
The EPA considered EJ implications in the development of this
proposed rulemaking process, including the fair treatment and
meaningful involvement of all people regardless of race, color,
national origin, or income. As part of this process, the EPA engaged
and consulted with frontline communities through interactions such as
webinars, listening sessions and meetings. These opportunities gave the
EPA a chance to hear directly from the public, especially overburdened
and underserved communities, on the development of the proposed rule.
The EPA considered these community concerns throughout our internal
development process that resulted in this proposal which, if finalized
in a manner similar to what is being proposed, will reduce emissions of
harmful air pollutants, promote gas capture and beneficial use, and
provide opportunity for flexibility and expanded transparency in order
to yield a consistent and accountable national program. The EPA's
proposed NSPS and EG are summarized in sections XI and XII below.
Anticipated impacts of this action are discussed further in section XVI
of this preamble.
In recognizing that minority and low-income populations often bear
an unequal burden of environmental harms and risks, the EPA continues
to consider
[[Page 63145]]
ways to protect them from adverse public health and environmental
effects of air pollution emitted from sources within the Oil and
Natural Gas Industry that are addressed in this proposed rulemaking.
For these reasons, in section XIV.C the EPA is proposing to include an
additional requirement associated with the adoption and submittal of
State plans pursuant to EG OOOOc (in addition to the current
requirements of Subpart Ba) by requiring States to meaningfully engage
with members of the public, including overburdened and underserved
communities, during the plan development process and prior to adoption
and submission of the plan to the EPA. The EPA is proposing this
specific meaningful engagement requirement to ensure that the State
plan development process is inclusive, effective, and accessible to
all.
Details of the EPA's assessment of EJ considerations can be found
in the RIA for this action. The EPA seeks input on the EJ analyses
contained in the RIA, as well as broader input on other health and
environmental risks the Agency should assess in the comprehensive
development of this proposed action. In particular, the EPA is
soliciting comment on key assumptions underlying the EJ analysis as
well as data and information that would enable the Agency to conduct a
more nuanced analysis of HAP and criteria pollutant exposure and risk,
given the inherent uncertainty regarding risk assessment. More broadly,
the EPA seeks information, analysis, and comment on how the provisions
of this proposed action would affect air pollution and health in
communities with environmental justice concerns, and whether there are
further provisions that EPA should consider as part of a supplemental
proposal or a final rule that would enhance the health and
environmental benefits of this rule for these communities.
VII. Other Stakeholder Outreach
A. Educating the Public, Listening Sessions, and Stakeholder Outreach
The EPA began the development of this proposed action to reduce
methane and other harmful pollutants from new and existing sources in
the Crude Oil and Natural Gas source category with a public outreach
effort to gather a broad range of stakeholder input. This effort
included: Opening a public docket for pre-proposal input; \143\ holding
training sessions providing overviews of the industry, the EPA's
rulemaking process and how to participate in it; and convening
listening sessions for the public, including a wide range of
stakeholders. The EPA additionally held roundtables with State
environmental commissioners through the Environmental Council of the
States, and oil and gas commissioners and staff through the Interstate
Oil and Gas Compact Commission (IOGCC), and met with non-governmental
organizations (NGOs), industry, and the U.S. Climate Alliance, among
others.\144\
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\143\ EPA Docket ID No. EPA-HQ-OAR-2021-0295.
\144\ A full list of pre-proposal meetings the EPA participated
in is included at EPA Docket ID No. EPA-HQ-OAR-2021-0317.
---------------------------------------------------------------------------
In addition to the trainings and listening sessions noted in
section VI above, on May 25 and 26, 2021, the EPA held webinar-based
trainings designed for small business stakeholders \145\ and Tribal
nations.\146\ The training provided an overview of the Oil and Natural
Gas Industry and how it is regulated and offered information on how to
participate in the rulemaking process. A combined total of more than
100 small business stakeholders and Tribal nations participated. During
the training, small business stakeholders expressed interest in
learning more about the EPA's plan to either modify the 2016 NSPS OOOOa
or take more substantial action in this proposal. For Tribal nations,
the EPA has assessed potential impacts on Tribal nations and
populations and has engaged with Tribal stakeholders to hear concerns
associated with air pollution emitted from sources within the Oil and
Natural Gas Industry that are addressed in this proposed rulemaking.
Tribal members mentioned the need for the EPA to uphold its trust
responsibilities, propose and promulgate rules that protect
disproportionately impacted communities, and asked that the EPA
allocate resources for Tribal governments to implement regulations
through Tribal air quality programs.
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\145\ https://www.epa.gov/sites/default/files/2021-05/documents/oil_and_gas_training_webinar_small_businesses_05.25.21.pdf.
\146\ https://www.epa.gov/sites/default/files/2021-05/documents/usepa_training_webinar_on_oil_and_natural_gas_for_tribes.5.26.2021.pdf.
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As noted above, the EPA also heard from a broad range of
stakeholders during virtual public listening sessions held from June 15
through June 17, 2021,\147\ which featured a total of 173
speakers.\148\ Many speakers stressed the urgent need to address
climate change and the importance of reducing methane pollution as part
of the nation's overall response to climate change. In addition to the
community perspectives described above, the Agency also heard from
industry speakers who were generally supportive of the regulation and
stressed the need to provide compliance flexibility and allow industry
the ability to use cutting-edge tools, including measurement tools, to
implement requirements. Technical comments from other speakers also
focused on a need for robust methane monitoring and fugitive emissions
monitoring, a need to strengthen standards for flares as a control for
associated gas, and suggestions to improve compliance. The sections
below provide additional details on the information presented by
stakeholders during these listening sessions.
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\147\ June 15, 2021 session: https://youtu.be/T8XwDbf-B8g; June
16, 2021 session: https://www.youtube.com/watch?v=l23bKPF-5oc; June
17, 2021 session: https://www.youtube.com/watch?v=R2AZrmfuAXQ.
\148\ Full transcripts for the listening sessions are posted in
at EPA Docket ID No. EPA-HQ-OAR-2021-0295.
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1. Technical Themes
Measurement and Monitoring. Stakeholders advocated that the EPA
modernize the rule by employing next-generation tools for methane
identification and quantification, particularly for large emission or
``super-emissions'' events. Stakeholders particularly focused on
allowing the use of remote sensing to help industry more easily comply
with monitoring requirements at well pads, which are numerous and
geographically spread out in some States. Stakeholders specified the
desire to use innovative remote sensing technologies to monitor
fugitive emissions and large emission events, including aerial, truck-
based, satellite, and continuous monitoring. Several speakers focused
on the need for regular monitoring, repair, and reporting, including
ambient air monitoring in oil and natural gas development areas, as
well as suggesting that the EPA pursue more robust methane monitoring
for fugitive emissions, ensure that repair is completed, and pursue
robust monitoring and reporting to verify the efficacy of the
regulations.
Implementation, Compliance, and Enforcement. Numerous stakeholders
raised concerns about flaring of associated gas and advocated for more
stringent standards to ensure that flares used as control devices
perform effectively. One speaker, an OGI expert, noted seeing many
flares that were not operating the way they were intended to and that
were not adequately designed (e.g., unlit flares and ignition gas not
being close enough to the waste gas stream to properly ignite). The
speaker suggested that the EPA consider the concept of `thermal tuning'
of flares by
[[Page 63146]]
using OGI to see if a plume of unburned hydrocarbons extends downwind
from the flare, to ensure that flares are actually operating
effectively; the speaker suggested that this use of OGI could be done
in conjunction with fugitive emissions monitoring to make sure controls
are working. Stakeholders further emphasized the need for recordkeeping
of any inspections that are made (e.g., looking for flare damage from
burned tips, lightning strikes). Some stakeholders also requested that
the EPA consider reducing or eliminating flaring of associated gas and
incentivizing capture. Lastly, one speaker raised concerns about
flaring of associated gas in Texas and how flaring is permitted by the
State. In response to these concerns, the EPA is proposing to reduce
venting and flaring of associated gas and to require monitoring of
flares to detect malfunctions. Further, the EPA is soliciting comment
on whether to adopt additional measures to assure proper design and
operation of control devices, including flares, as discussed in section
XIII.
Stakeholders raised other implementation, compliance, and
enforcement concerns, including calls for the EPA to develop rules that
are easy to apply and implement given States' limited budgets.
Stakeholders cautioned that ``flexibility'' in a rule can be
interpreted as a ``loophole,'' and opined that a rule that sets clear
and uniform expectations will help avoid confusion. At the same time,
speakers stated that a ``prescriptive checklist'' does not work in
today's environment and recommended that the EPA modernize the
regulatory approach. Several speakers, including speakers from Texas
and North Dakota, raised concerns about the limited enforcement
capacity of local and State governments, as well as the EPA and its
regional officials and stated that this may result in implementation
gaps. Speakers called on the EPA to have a third-party verification or
audit requirements for fugitive emissions and cited to Texas's
requirement for third-party audits to evaluate operator LDAR programs
for highly reactive VOC. Speakers also cited to the public-facing
Environmental Defense Fund (EDF) methane map \149\ with geotags of
sources with observed hydrocarbon emissions, which provides operators
an opportunity to respond to posted leak videos and measurements.
Lastly, one speaker requested that the EPA not allow exemptions for
start-up and shutdown emissions events. The EPA is soliciting comment
on ways to utilize credible emissions information obtained from
communities and others, as discussed in section XI.A.1.
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\149\ https://www.permianmap.org.
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Wells and Storage. Some stakeholders requested that the EPA
consider a program for capping abandoned wells to ensure those wells
are properly closed and not leaking. Speakers called on the EPA to
consider abandoned and unplugged wells in the context of EJ communities
adjacent to affected facilities and requested that the EPA incentivize
appropriate well closure. In response to this input and to gather
information that will be needed to inform possible future actions, the
EPA is soliciting comment on ways to address abandoned wells, including
potential closure requirements. See section XIII.B. Stakeholders also
focused on marginal wells and asked that the EPA consider system-wide
reductions be allowed, for example, at the basin level, and expressed
challenges of retrofitting existing well sites and low production well
sites where addition of control devices or closed vent systems would be
necessary. Some speakers raised concern about ensuring that facilities
are engineered for the basin or target formation from which they
produce.
Job Creation. Some speakers stated that this rulemaking is a job
creation rule and encouraged a ``next generation'' approach to methane
standards, such as incentivizing continuous monitoring. Other speakers
cited a study about job creation in the methane mitigation
industry.\150\
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\150\ Stakeholders submitted the following studies to the pre-
proposal docket: https://www.regulations.gov/comment/EPA-HQ-OAR-2021-0295-0016 and https://www.regulations.gov/comment/EPA-HQ-OAR-2021-0295-0017.
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Inventory, Loss Rates, and Methane Global Warming Potential.
Several speakers criticized the EPA's emission inventories stating that
the EPA is not using the correct data in its inventory, that the GHGI
data is inaccurate because it relies on facility reporting of emissions
from calculations and estimation methods rather than measurement and
monitoring, and suggested that the EPA rely on monitoring and
measurement of actual emissions and subsequently make the monitoring
data publicly available. Speakers raised issues with differences in
inventories across Federal agencies, contrasting DOE's Environmental
Impact Statements and EPA's NEI. Stakeholders suggested that the EPA
use data collected by EDF and other researchers, which calculated
methane emissions to be 60 percent higher than the EPA's
estimates.\151\ Speakers also mentioned the amount of methane that is
lost from wells each year, providing varying estimates of these
emissions. Lastly, stakeholders called on the EPA to use the 20-year
GWP for methane, instead of the 100-year value the agency uses.
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\151\ Alvarez et al. 2018. Assessment of methane emissions from
the U.S. oil and gas supply chain. Science 13 Jul 2018: Vol. 361,
Issue 6398, pp. 186-188.
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2. Climate and Other Themes
Several speakers mentioned the effects of climate change from oil
and natural gas methane emissions, such as impacts on farmland,
wildfires, and transmission of tick-borne pathogens. Many speakers
pointed out the extreme heat and drought that currently are affecting
the western U.S. Stakeholders asked that the EPA examine the impacts of
the Oil and Natural Gas Industry on small businesses that are not part
of the regulated community, such as businesses that rely on outdoor
recreation or water flow that could be affected by oil and natural gas
operations. A speaker raised concerns about the impact of the industry
on tourism, saying that 30 percent of their local economy relies on
tourism and outdoor recreation. Lastly, a speaker discussed pipeline
weatherization needs and suggested that the EPA and other Federal
agencies account for seasonal variability.
In addition to the public listening sessions, on June 29, 2021, the
EPA met with environmental commissioners and staff through the
Environmental Council of the States (ECOS). Subsequently, on July 12,
2021, the EPA participated in a roundtable with members of the IOGCC.
The discussions in both roundtables included air emissions monitoring
technologies and interactions between the EPA's requirements and State
rules. For the ECOS roundtable, the EPA also sought feedback on and
implementation of the EPA's current NSPS; for the IOGCC roundtable, the
EPA also requested feedback on compliance with the rules.
Key themes from both roundtables included the following: Allowing
for the use of broad types of methane detection technologies; improving
and streamlining the EPA's AMEL process, such as by structuring it so
it could apply broadly rather than on a site-by-site basis; requests
that expanded aspects of States' rules be deemed equivalent to the
EPA's rule, and requests that the EPA's rule complement State
regulations in a way that would not interrupt the work of State
agencies requiring them to request State legislative approvals. Other
common themes were requests that the rule
[[Page 63147]]
provide flexibility and be easy to implement, particularly for marginal
or low production wells owned by independent small businesses, and that
the EPA coordinate its rules with those of other Federal agencies,
notably the DOI's BLM.
Other input included the need to fill gaps by addressing additional
opportunities to reduce emissions beyond the 2016 NSPS OOOOa, concerns
about the complexity of the calculation for the potential to emit for
storage vessels, a desire that the EPA's rule not slow momentum of
voluntary efforts to reduce emissions, and a desire for regulations
that recognize geographic differences.
B. EPA Methane Detection Technology Workshop
The EPA held a virtual public workshop on August 23 and 24, 2021,
to hear perspectives on innovative technologies that could be used to
detect methane emissions from the Oil and Natural Gas Industry.\152\
The workshop focused on methane-sensing technologies that are not
currently approved for use in the NSPS for the Oil and Natural Gas
Industry, and how those technologies could be applied in the Crude Oil
and Natural Gas sector. Panelists provided twenty-four live
presentations during the workshop. The panelists all had firsthand
experience evaluating innovative methane-sensing technologies or had
used these technologies to identify methane emissions and presented
about their experience. The live presentations were broken into six
panel sessions, each focused on a particular topic, e.g., satellite
measurements, methane sensors, aerial technologies. At the end of each
panel session, the set of panelists participated in a question-and-
answer session. In addition to the live presentations, the workshop
included a virtual exhibit hall for technology vendors to provide video
presentations on their innovative technologies, with a focus on
technology capability, applicability, and data quality. Forty-two
vendors participated in the virtual vendor hall.
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\152\ https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-industry/epa-methane-detection-technology-workshop.
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Nine hundred sixty stakeholders registered to participate in the
workshop. The workshop was also livestreamed, so stakeholders who could
not attend could watch the recorded livestream later at their
convenience. The registrants included a wide range of stakeholders
including, academics, methane detection technology end-user and
vendors, governmental employees (local, State, and Federal), and NGOs.
C. How is this information being considered in this proposal?
The EPA's pre-proposal outreach effort was intended to gather
stakeholder input to assist the Agency with developing this
proposal.\153\ The EPA recognizes that tackling the dangers of climate
change will require an ``all-hands-on deck'' approach through
regulatory, voluntary, and community programs and initiatives.
Throughout the development of this proposed rule, the EPA considered
the stakeholders' experiences and lessons learned to help inform how to
better structure this proposal and consider ongoing challenges that
will require continued collaboration with stakeholders. The EPA will
continue to consider the information obtained in developing this
proposal as we take the next steps on the proposed regulations.
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\153\ The EPA opened a non-regulatory docket for stakeholder to
submit early input. That early input can be found at EPA Docket I.D.
Number EPA-HQ-OAR-2021-0295.
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With this proposal, the EPA seeks further input from the public and
from all stakeholders affected by this rule. Throughout this action,
unless noted otherwise, the EPA is requesting comments on all aspects
of this proposal, including on several themes raised in the pre-
proposal outreach (e.g., innovative technologies for methane detection
and quantification). Please see section XI.A.1 of this preamble for
specific solicitations for comment regarding advanced measurement
technologies and section XIII for solicitations for comments on
additional emission sources. For public input to be considered on this
proposal,\154\ please submit comments on this proposed action to the
regulatory docket at EPA Docket ID No. EPA-HQ-OAR-2021-0317 so that the
EPA may consider those comments during the development of the final
rule.
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\154\ Information submitted to the pre-proposal non-regulatory
docket at Docket ID No. EPA-HQ-OAR-2021-0295 is not automatically
part of the proposal record. For information and materials to be
considered in the proposed rulemaking record, it must be resubmitted
in the rulemaking docket at EPA Docket ID No. EPA-HQ-OAR-2021-0317.
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VIII. Legal Basis for Proposal Scope
The EPA proposes in this rulemaking to revise certain NSPS and to
promulgate additional NSPS for both methane and VOC emissions from new
oil and gas sources in the production, processing, transmission and
storage segments of the industry; and to promulgate EG to require
States to regulate methane emissions from existing sources in those
segments. The large amount of methane emissions from the Oil and
Natural Gas Industry--by far, the largest methane-emitting industry in
the nation--coupled with the adverse effects of methane on the global
climate compel immediate regulatory action. This section explains EPA's
legal justification for proceeding with this proposed action, including
regulating methane and VOCs from sources in all segments of the source
category. The EPA first describes the history of our regulatory actions
for oil and gas sources in 2016 and 2020--including the key legal
interpretations and factual determinations made--as well as Congress's
action in 2021 in response. The EPA then explains the implications of
Congress's action and why we would come to the same conclusion even if
Congress had not acted.
This proposal is in line with our 2016 NSPS OOOOa rule, which
likewise regulated methane and VOCs from all three segments of the
industry. The 2016 NSPS OOOOa rule explained that these three segments
should be regulated as part of the same source category because they
are an interrelated sequence of functions in which pollution is
produced from the same types of sources that can be controlled by the
same techniques and technologies. That rule further explained that the
large amount of methane emissions, coupled with the adverse effects of
GHG air pollution, met the applicable statutory standard for regulating
methane emissions from new sources through NSPS. Furthermore, the rule
explained, this regulation of methane emissions from new sources
triggered the EPA's authority and obligation to set guidelines for
States to develop standards to regulate the overwhelming majority of
oil and gas sources, which the CAA categorizes as ``existing'' sources.
In the 2020 Policy Rule, the Agency reversed course, concluding based
upon new legal interpretations that the rule concluded the EPA had not
made the proper determinations necessary to issue such regulations.
This action eliminated the Agency's authority and obligation to issue
EG for existing sources. In 2021, Congress adopted a joint resolution
to disapprove the EPA's 2020 Policy Rule under the CRA. According to
the terms of CRA, the 2020 Policy Rule is ``treated as though [it] had
never taken effect,'' 5 U.S.C. 801(f), and as a result, the 2016 Rule
is reinstated.
In disapproving the 2020 Policy Rule under the CRA, Congress
explicitly rejected the 2020 Policy Rule interpretations and embraced
EPA's
[[Page 63148]]
rationales for the 2016 NSPS OOOOa rule. The House Committee on Energy
& Commerce emphasized in its report that the source category ``is the
largest industrial emitter of methane in the U.S.,'' and directed that
``regulation of emissions from new and existing oil and gas sources,
including those located in the production, processing, and transmission
and storage segments, is necessary to protect human health and welfare,
including through combatting climate change, and to promote
environmental justice.'' H.R. Rep. No. 117-64, 3-5 (2021) (House
Report). A statement from the Senate cosponsors likewise underscored
that ``methane is a leading contributing cause of climate change,''
whose ``emissions come from all segments of the Oil and Gas Industry,''
and stated that ``we encourage EPA to strengthen the standards we
reinstate and aggressively regulate methane and other pollution
emissions from new, modified, and existing sources throughout the
production, processing, transmission and storage segments of the Oil
and Gas Industry under section 111 of the CAA.'' 167 Cong. Rec. S2282
(April 28, 2021) (statement by Sen. Heinrich) (Senate Statement).\155\
The Senators concluded with a stark statement: ``The welfare of our
planet and of our communities depends on it.'' Id. at S2283.
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\155\ Sen. Heinrich stated that he made this statement on behalf
of ``[Majority [l]eader Chuck Schumer, Chairman Tom Carper of the
Committee on Environment and Public Works, Senator Angus King,
Senator Edward Markey and [himself],'' who he described as ``leading
supporters and sponsors of S.J. Res. 14. . . .'' Senate Statement at
S. 2282. Thus, the Senate Statement should be considered an
authoritative piece of the legislative history. It should be noted
that the Joint Resolution was referred to the Senate Committee on
Environment and Public Works and discharged from the committee by
petition pursuant to 5 U.S.C. 802(c), https://www.congress.gov/bill/117th-congress/senate-joint-resolution/14/all-actions. As a result,
the resolution was not accompanied by a report from the Senate
committee.
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This proposal comports with the EPA's CAA section 111 obligation to
reduce dangerous pollution and responds to the urgency expressed by the
current Congress. With this proposal, the EPA is taking additional
steps in the regulation of the Crude Oil and Natural Gas source
category to protect human health and the environment. Specifically, the
agency is proposing to revise certain of those NSPS, to add NSPS for
additional sources, and to propose EG that, if finalized, would impose
a requirement on States to regulate methane emissions from existing
sources. As the EPA explained in the 2016 Rule, this source category
collectively emits massive quantities of the methane emissions that are
among those driving the grave and growing threat of climate change,
particularly in the near term. 81 FR 35834, June 3, 2016. As discussed
in section III above, since that time, the science has repeatedly
confirmed that climate change is already causing dire health,
environmental, and economic impacts in communities across the United
States.
Because the 2021 CRA resolution automatically reinstated the 2016
Rule, which itself determined that the Crude Oil and Natural Gas Source
Category included the transmission and storage segment and that
regulation of methane emissions was justified, the EPA is authorized to
take the regulatory actions proposed in this rule. As explained below,
we are reaffirming those determinations as clearly authorized under any
reasonable interpretation of section 111. Because the reinstatement of
the 2016 Rule provides the only necessary predicate for this rule, and
because, as described, the interpretations underlying this rule are
sound, the EPA is not reopening them here.
A. Recent History of the EPA's Regulation of Oil and Gas Sources and
Congress's Response
1. 2016 NSPS OOOOa Rule
As described above, the 2016 NSPS OOOOa rule extended the NSPS for
VOCs for new sources in the Crude Oil and Natural Gas source category
and also promulgated NSPS for methane emissions from new sources. This
rule contained several interpretations that were the bases for these
actions, and that are important for present purposes. First, the EPA
confirmed its position in the 2012 NSPS OOOO rule that the scope of the
oil and gas source category included the transmission and storage
segment, in addition to the production and processing segments that the
EPA had regulated since 1984. The agency stated that it believed these
segments were included in the initial listing of the source category,
and to the extent they were not, the agency determined to add them as
appropriately encompassed within the regulated source category. The EPA
based this latter conclusion on the structure of the industry. In
particular, the EPA emphasized that ``[o]perations at production,
processing, transmission, and storage facilities are a sequence of
functions that are interrelated and necessary for getting the recovered
gas ready for distribution,'' and further explained, ``[b]ecause they
are interrelated, segments that follow others are faced with increases
in throughput caused by growth in throughput of the segments preceding
(i.e., feeding) them.'' 81 FR 35832, June 3, 2016. The EPA also
recognized ``that some equipment (e.g., storage vessels, pneumatic
pumps and compressors) are used across the oil and natural gas
industry.'' Id. Having made clear that the Crude Oil and Natural Gas
source category includes the transmission and storage segment, the EPA
proceeded to promulgate NSPS for sources in that segment. Id. at 35826.
Second, in promulgating NSPS for methane emissions for new sources
in the source category, the EPA explained its decision to regulate GHGs
for the first time from the source category. Noting that the plain
language of CAA section 111 requires a significant-contribution
analysis only when EPA regulates a new source category, not a new
pollutant, the Agency stated that it ``interprets CAA section
111(b)(1)(B) to provide authority to establish a standard for
performance for any pollutant emitted by that source category as long
as the EPA has a rational basis for setting a standard for the
pollutant.'' 81 FR 35842, June 3, 2016. In the alternative, if a
rational-basis analysis were deemed insufficient, the EPA explained
that it also concluded that GHG emissions, in the form of methane
emissions, from the regulated Crude Oil and Natural Gas source category
significantly contribute to dangerous pollution. Id. at 81 FR 35843,
and 35877. In making the rational basis and alternative significant
contribution findings, the EPA focused on ``the high quantities of
methane emissions from the Crude Oil and Natural Gas source category.''
Id. The EPA emphasized, among other things, that ``[t]he Oil and
Natural Gas source category is the largest emitter of methane in the
U.S., contributing about 29 percent of total U.S. methane emissions.''
Id. The EPA added that ``[t]he methane that this source category emits
accounts for 3 percent of all U.S. GHG emissions . . . [and] GWP-
weighted emissions of methane from these sources are larger than
emissions of all GHGs from about 150 countries.'' Id. The EPA concluded
that ``the[se] facts . . . along with prior EPA analysis'' concerning
the effect of GHG air pollution on public health and welfare,
``including that found in the 2009 Endangerment Finding, provide a
rational basis for regulating GHG emissions from affected oil and gas
sources . . .'' as well as for concluding in the alternative that oil
and gas methane significantly contributes to dangerous pollution. Id.
at 35843.
In addition, in the 2016 NSPS OOOOa Rule, EPA recognized that
promulgation of NSPS for methane emissions under
[[Page 63149]]
section 111(b)(1)(B) triggered the requirement that EPA promulgate EG
to require States to regulate methane emissions from existing sources
under section 111(d)(1), and described the steps it was taking to lay
the groundwork for that regulation. 81 FR at 35831.
2. 2020 Policy Rule
The 2020 Policy Rule rescinded key elements of the 2016 NSPS OOOOa
rule based on different factual assertions and statutory
interpretations than in the 2016 Rule. Specifically, the 2020 Policy
Rule stated that it ``contains two main actions,'' 85 FR 57019,
September 14, 2020 which it identified as follows: ``First, the EPA is
finalizing a determination that the source category includes only the
production and processing segments of the industry and is rescinding
the standards applicable to the transmission and storage segment of the
industry. . . .'' Id. The rule justified this first action in part on
the grounds that ``the processes and operations found in the
transmission and storage segment are distinct from those found in the
production and processing segments,'' because ``the purposes of the
operations are different'' and because ``the natural gas that enters
the transmission and storage segment has different composition and
characteristics than the natural gas that enters the production and
processing segments.'' Id. at 57028. ``Second, the EPA is separately
rescinding the methane requirements of the NSPS applicable to sources
in the production and processing segments.'' Id. EPA justified the
rescission of the methane NSPS on two grounds. One was the EPA's
``conclu[sion] that those methane requirements are redundant with the
existing NSPS for VOC and, thus, establish no additional health
protections.'' Id. at 57019. The second was a statutory interpretation:
the EPA rejected the rational basis interpretation of the 2016 Rule,
and stated that instead, ``[t]he EPA interprets [the relevant
provisions in CAA section 111] . . . to require, or at least to
authorize the Administrator to require, a pollutant-specific SCF as a
predicate for promulgating a standard of performance for that air
pollutant.'' Id. at 57035. The rule went on to ``determine that the SCF
for methane that the EPA made in the alternative in the 2016 [NSPS
OOOOa] Rule was invalid and did not meet this statutory standard,'' for
two reasons: (i) ``[t]he EPA made that finding on the basis of methane
emissions from the production, processing, and transmission and storage
segments, instead of just the production and processing segments''; and
(ii) ``the EPA failed to support that finding with either established
criteria or some type of reasonably explained and intelligible standard
or threshold for determining when an air pollutant contributes
significantly to dangerous air pollution.'' Id. at 57019. The rule
recognized that ``by rescinding the applicability of the NSPS . . . to
methane emissions for [oil and gas] sources . . . existing sources . .
. will not be subject to regulation under CAA section 111(d).'' Id. at
57040.
3. CRA Resolution Disapproving the 2020 Policy Rule and Reinstating the
2016 NSPS OOOOa Rule
On June 30, 2021, the President signed into law a joint resolution
adopted by Congress under the CRA disapproving the 2020 Policy Rule. By
the terms of the CRA, this disapproval means that the 2020 Policy Rule
is ``treated as though [it] had never taken effect.'' 5 U.S.C. 801(f).
As a result, upon the disapproval, by operation of law, the 2016 NSPS
OOOOa rule was reinstated, including the inclusion of the transmission
and storage segment in the source category, the VOC NSPS for sources in
that segment, and the methane NSPS for sources across the source
category. And with the reinstatement of the methane NSPS, the EPA's
obligation to issue EG to require States to regulate existing sources
for methane emissions was reinstated as well. Moreover, the CRA bars an
agency from promulgating ``a new rule that is substantially the same
as'' a disapproved rule. 5 U.S.C. 801(b)(2).
The accompanying legislative history, specifically a House
Committee report (H.R. Rep. 117-64) and a statement on the Senate floor
by the sponsors of the CRA resolution (Senate Statement at S2282-83),
provides additional specificity regarding Congress's intent in
disapproving 2020 Policy Rule and reinstating the 2016 Rule with regard
to the scope of the source category and the regulation of methane.
a. Regulation of Transmission and Storage Sources
The House Report rejected the 2020 Policy Rule's removal of the
transmission and storage segment from the Crude Oil and Natural Gas
Source Category, and its rescission of the VOC and methane NSPS
promulgated in the 2012 NSPS OOOO and 2016 NSPS OOOOa rules for
transmission and storage sources. House Report at 7; 85 FR 57029,
September 14, 2020 (2020 Policy Rule). The Report recognized that in
authorizing the EPA to list for regulation ``categories of sources''
under section 111(b)(1)(A) of the CAA, Congress ``provided the EPA with
wide latitude to determine the scope of a source category . . . and to
expand the scope of an already-listed source category if the agency
later determines that it is reasonable to do so.'' House Report at 7.
The Report stated that in the 2016 NSPS OOOOa, ``EPA correctly
determined that the equipment and operations at production, processing,
and transmission and storage facilities are a sequence of functions
that are interrelated and necessary for the overall purpose of
extracting, processing, and transporting natural gas for
distribution.'' Id.; see 81 FR 35832, June 3, 2016 (2016 Rule). The
Report added that the 2016 NSPS OOOOa also ``correctly determined that
the types of equipment used and the emissions profile of the natural
gas in the transmission and storage segments do not so distinctly
differ from the types of equipment used and the emissions profile of
the natural gas in the production and processing segments as to require
that the EPA create a separate source category listing.'' House Report
at 7; see 81 FR 35832, June 3, 2016. The Report went on to reject the
2020 Policy Rule's basis for excluding the transmission and storage
segment, finding that the functions of the various segments in the
Crude Oil and Natural Gas sector are all ``interrelated and necessary
for the overall purpose'' of the industry, House Report at 7, and that
EPA correctly determined in 2016 that the source types and emissions
found in the transmission and storage segment are sufficiently similar
to production and processing as to justify regulating these segments in
a single source category. Id.
The Senate Statement was also explicit that the 2020 Policy Rule
erred in rescinding NSPS for sources in the transmission and storage
segment:
[T]he resolution clarifies our intent that EPA should regulate
methane and other pollution emissions from all oil and gas sources,
including production, processing, transmission, and storage segments
under the authority of section 111 of the CAA. In addition, we
intend that section 111 . . . obligates and provides EPA with the
legal authority to regulate existing sources of methane emissions in
all of these segments.
Senate Statement at S2283 (paragraphing revised).
b. Regulation of Methane--Redundancy
The House Report and Senate Statement made clear Congress's view
that in light of the large amount of methane emissions from oil and gas
sources and their impact on global climate, the EPA must regulate those
[[Page 63150]]
emissions under section 111. House Report at 5; Senate Statement at
S2283. Both pieces of legislative history specifically rejected the
2020 Policy Rule's rescission of the methane NSPS. House Report at 7;
Senate Statement at S2283. Moreover, the legislative history
specifically rejected the statutory interpretations of section 111 that
formed the bases of EPA's 2020 rationales for rescinding the methane
NSPS. House Report at 7-10; see Senate Statement at S2283; see 85 FR
57033, 57035-38 (September 14, 2020).
The House Report began by recognizing the critical importance of
regulating methane emissions from oil and gas sources, emphasizing both
the potency of methane in driving global warming, and the massive
amounts of methane emitted each year by the oil and gas industry. House
Report at 3-4. The House Report was clear that the amount of these
emissions and their impact compelled regulatory action. Id. at 5. The
Senate Statement was equally clear:
[M]ethane is a leading contributing cause of climate change. It is
28 to 36 times more powerful than carbon dioxide in raising the
Earth's surface temperature when measured over a 100-year time scale
and about 84 times more powerful when measured over a 20-year
timeframe.
Industrial sources emit GHG in great quantities, and methane
emissions from all segments of the Oil and Gas Industry are
especially significant in their contribution to overall emissions
levels and surface temperature rise. . . .
In fact, with the congressional adoption of this resolution, we
encourage EPA to strengthen the standards we reinstate and
aggressively regulate methane and other pollution emissions from
new, modified, and existing sources throughout the production,
processing, transmission, and storage segments of the Oil and Gas
Industry under section 111 of the Clean Air Act.
The welfare of our planet and of our communities depend on it.
Senate Statement at S2283.
Turning to the 2020 Policy Rule, the House Report rejected the
rule's position that the methane NSPS were redundant to the VOC NSPS,
and therefore unnecessary. House Report at 7. The House Report rejected
the 2020 Policy Rule's ``redundancy'' rationale, explaining that in the
2016 NSPS OOOOa, the EPA had consciously ``formulated [the two sets of
NSPS so as] to impose the same requirements for the same types of
equipment,'' and that the co-extensive nature of the NSPS mean that
``sources could comply with them in an efficient manner,'' not that the
NSPS were redundant. Id. The House report further rejected the 2020
Policy Rule's assertion that it need not take into account the
implications of regulating methane for existing sources, calling it a
``fundamental misinterpretation of section 111, and the critical
importance of section 111(d) in Congress [sic: Congress's] scheme.''
House Report at 8 & n. 27 (The EPA's 2020 ``misinterpretation . . . was
glaring and enormously consequential'' because it precluded regulation
of methane from existing sources). The House Report emphasized that
``existing sources emit the vast majority of methane in the oil and gas
sector,'' id. and pointed out that while the 2016 NSPS ``covered
roughly 60,000 wells constructed since 2015[, t]here are more than
800,000 existing wells in operation. . . .''Id. n.28.
The Senate Statement also made clear that the resolution of
disapproval ``reaffirms that the CAA requires EPA to act to protect
Americans from sources of . . . methane,'' ``reject[s] the [2020 Policy
Rule's] misguided legal interpretations,'' and ``clarifies our intent
that EPA should regulate methane . . . from all oil and gas sources. .
. .'' Senate Statement at 2283.
c. Regulation of Methane--Significant Contribution Finding
The legislative history was explicit that, contrary to the EPA's
statutory interpretation in the 2020 Policy Rule, section 111 of the
CAA, by its plain language, does not require, or authorize the EPA to
require, as a prerequisite for promulgating NSPS for a particular air
pollutant from a listed source category, a separate finding by the EPA
that emissions of the pollutant from the source category contribute
significantly to dangerous air pollution. House Report at 9-10; Senate
Statement at S2283. The House Report rejected this interpretation. It
made clear that instead, consistent with the EPA's statements in the
2016 NSPS OOOOa and the plain language of the CAA, section 111 requires
that the agency must make a SCF only at ``the first step of the
process, the listing of the source category,'' and further requires
that this finding ``must apply to the impact of the `category of
sources' on `air pollution' '' as opposed to individual pollutants.
House Report at 9. The House Report went on to explain that this
provision ``does not require the EPA to make a SCF for individual air
pollutants emitted from the source category, nor does it even mention
individual air pollutants,'' id. at 9. The House Report went on to
explain in some detail the meaning that the EPA should give to section
111, which, consistent with the 2016 Rule, is that section 111
authorizes the agency to promulgate NSPS for particular pollutants as
long as it has a rational basis for doing so. House Report at 8-9. The
report explained that after the EPA lists a source category for
regulation under section 111(b)(1)(A), it is required to determine for
which pollutants to promulgate NSPS, and this determination is subject
to CAA section 307(d)(9)(A) (``In the case of review of any [EPA]
action . . . to which [section 307(d)] applies, the court may reverse
any such action found to be arbitrary, capricious, an abuse of
discretion, or otherwise not in accordance with law'').\156\ The Report
further noted that the U.S. Supreme Court affirmed this interpretation
in American Electric Power Co. Inc. v. Connecticut, 564 U.S. 410, 427
(2011) (American Electric Power) (``EPA may not decline to regulate
carbon-dioxide emissions from powerplants if refusal to act would be
`arbitrary, capricious, an abuse of discretion, or otherwise not in
accordance with law'' (citing section 307(d)(9)(A)). The Report went on
to note that the 2016 NSPS OOOOa had stated that the EPA was authorized
to promulgate a NSPS for a particular pollutant if it had a ``rational
basis'' for doing so, and the Report emphasized that this ``rational
basis'' standard is ``fully consistent with'' the arbitrary and
capricious standard under section 307(d)(9)(A) of the CAA. House Report
at 9.\157\
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\156\ Section 307(d) applies to the promulgation of NSPS, under
section 307(d)(1)(C).
\157\ The House Report dismissed the 2020 Policy Rule's
criticism of the rational basis test as unduly vague by noting that
a court could enforce it. House Report at 11.
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The House Report further explained that, in contrast, the 2020
Policy Rule's statutory interpretation of section 111 to require a
pollutant-specific SCF as a predicate for promulgating NSPS was
foreclosed by ``the plain language of'' section 111--noting that this
interpretation ignored the distinction between the text of section 111
and that of other CAA provisions which do explicitly require a
pollutant-specific cause-or-contribution finding. Id. at 10. Moreover,
the Report added, ``[g]iven that the statute is not ambiguous, the EPA
cannot interpret section 111 to authorize the EPA to exercise
discretion to require . . . a pollutant-specific SCF as a predicate for
promulgating a [NSPS] for the pollutant.'' Id. at 10. The Report went
on to note several other supports for its statutory interpretation,
including the legislative history of section 111. Id. at 10-11.
The Senate Statement took the same approach, stating: ``we do not
intend that section 111 of [the] CAA requires EPA to make a pollutant-
specific
[[Page 63151]]
significant contribution finding before regulating emissions of a new
pollutant from a listed source category. . . .'' Senate Statement at
S2283.\158\
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\158\ Both the House Report and the Senate Statement recognized
that EPA could, if it chose to, make a finding that a particular
pollutant contributes significantly to dangerous air pollution, in
order, for example, to inform the public about the risks of a
pollutant. House Report at 10, Senate Statement at S2283. However,
the House Report made clear that ``it is the rational basis
determination as to the risk a pollutant poses to endangerment of
human health or welfare [and not any such SCF] that remains the
statutory basis for the EPA's action.'' House Report at 10.
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The House Report also expressly disapproved of the 2020 Policy
Rule's interpretation of section 111 to require that the SCF must be
based on some ``identif[ied] standard or established set of criteria,''
and not the facts-and-circumstances approach that EPA has used in
making that finding for the source category. House Report at 10-11; see
2020 Policy Rule at 57038. The Report stated, ``[i]t is fully
appropriate for EPA to exercise its discretion to employ a facts-and-
circumstances approach, particularly in light of the wide range of
source categories and the air pollutants they emit that EPA must
regulate under section 111.'' House Report at 11.
Finally, in reinstating the methane regulations, the legislative
history for the CRA resolution clearly expressed the intent that the
EPA proceed with regulation of existing sources. The House Report was
explicit in this regard, stating that ``[p]assage of the resolution of
disapproval indicates Congress' support and desire to immediately
reinstate . . . EPA's statutory obligation to regulate existing oil and
natural gas sources under [CAA] section 111(d).'' House Report at 3;
see id. at 11-12. The report added that upon enactment of the
resolution of disapproval, ``the Committee strongly encourages the EPA
to take swift action to . . . fulfill its statutory obligation to issue
existing source guidelines under [CAA] section 111(d).'' Id. The Senate
Statement was substantially similar. Senate Statement at S2283 (``By
adopting this resolution of disapproval, it is our view that Congress
reaffirms that the CAA requires EPA to act to protect Americans from
sources of climate pollution like methane, which endangers the public's
health and welfare. . . . [W]e intend that [CAA] section 111 . . .
obligates and provides EPA with the legal authority to regulate
existing sources of methane emissions in [the Crude Oil and Natural Gas
source category].'').
B. Effect of Congress's Disapproval of the 2020 Policy Rule
Under the CRA, the disapproved 2020 Policy Rule is ``treated as
though [it] had never taken effect.'' 5 U.S.C. 801(f). As a result, the
preceding regulation, the 2016 NSPS OOOOa rule, was automatically
reinstated, and treated as though it had never been revised by the 2020
Policy Rule. Moreover, the CRA bars EPA from promulgating ``a new rule
that is substantially the same as'' a disapproved rule. 5 U.S.C.
801(b)(2), for example, a rule that deregulates methane emissions from
the production and processing sectors or deregulates the transmission
and storage sector entirely.
The legislative history of the CRA gives further content to
Congress's disapproval and the bar on substantially similar rulemaking.
The legislative history rejected the EPA's statutory interpretations of
section 111 in the 2020 Policy Rule and endorsed the legal
interpretations contained in the 2016 NSPS OOOOa rule. Specifically,
Congress expressed its intent that the transmission and storage segment
be included in the source category, that sources in that segment remain
subject to NSPS, and that all oil and gas sources be subject to NSPS
for methane emissions.\159\
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\159\ See generally ``Federal-State Unemployment Compensation
Program; Establishing Appropriate Occupations for Drug Testing of
Unemployment Compensation Applicants Under the Middle-Class Tax
Relief and Job Creation Act of 2012: Final Rule,'' 84 FR 53037,
53083 (Oct. 4, 2019) (citing legislative history of CRA resolution
disapproving prior rule in explaining scope of new rule).
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The EPA is now proceeding to propose additional requirements to
reduce emissions from oil and gas sources, consistent with the
statutory factors the EPA is required to consider under section 111 and
with section 111's overarching purpose of protecting against pollution
that endangers health and welfare. While the reinstatement of the 2016
Rule through the CRA joint resolution of disapproval provides the
predicate for this action, the EPA notes that, for the reasons
discussed next, the EPA would reject the positions concerning legal
interpretations taken in the 2020 Policy Rule and reaffirm the
positions the Agency took in the 2016 Rule even absent the CRA
resolution. The EPA provides this information for the purposes of
informing the public and is not re-opening these positions for comment.
C. Affirming the Legal Interpretations in the 2016 NSPS OOOOa Rule
The Agency has reviewed all of the information and analyses in the
2016 NSPS OOOOa and 2020 Policy Rule, and fully reaffirms the positions
it took in the 2016 Rule and rejects the positions taken in the 2020
Policy Rule.\160\ For this rulemaking, the EPA has reviewed its prior
actions, along with newly available information, including recent
information concerning the dangers posed by climate change and the
impact of methane emissions, as described in section III above. Based
on this review, the EPA affirms the statutory interpretations
underlying the 2016 Rule and rejects the different interpretations
informing the congressionally voided 2020 Policy Rule. This section
explains the EPA's views. These views are confirmed by Congress's
reasoning in the legislative history of the CRA resolution and so, for
convenience, this section occasionally refers to that legislative
history.
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\160\ Under F.C.C. v. Fox Television Stations, Inc., 556 U.S.
502 (2009), an agency may revise its policy, but must demonstrate
that the new policy is permissible under the statute and is
supported by good reasons, taking into account the record of the
previous rule. To the extent that this standard applies in this
action--where Congress has disapproved the 2020 Policy Rule--the EPA
believes the explanations provided here satisfy the standard.
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In particular, the EPA reaffirms that the Crude Oil and Natural Gas
Source Category appropriately includes the transmission and storage
segment, along with the production and processing segments. The EPA has
broad discretion in determining the scope of the source category, and
the 2016 Rule correctly identified the most important aspect of the
industry, which is the interrelatedness of the segments and their
common purpose in completing the multi-step process to prepare natural
gas for marketing. 81 FR 35832, June 3, 2016. The 2020 Policy Rule's
objection that the chemical composition of natural gas changes as it
moves from the production and processing segments to the transmission
and storage segment, 85 FR 57028, September 14, 2020, misses the mark
because in every segment methane predominates and the refining of
natural gas in the processing segment, which is what changes its
chemical composition, is appropriately viewed simply as one of the
steps in the marketing of the gas. Further, while it is true that some
of the equipment in each segment differs from the equipment in the
other segments, as the 2020 Policy Rule pointed out, 85 FR 57029
(September 14, 2020), that too simply results from the fact that the
segments represent different steps in the process of preparing natural
gas for marketing. The more salient fact is that most of the polluting
equipment, such as storage
[[Page 63152]]
vessels, pneumatic pumps, and compressors, are found throughout the
segments and emit the same pollutants that can be controlled by the
same techniques and technologies, 81 FR 35832 (June 3, 2016),
underscoring the interrelated functionality of the segments and the
appropriateness of regulating them together as part of a single source
category. The scope of the source category as defined in 2016, and
proposed to be affirmed in this rule, is well within the reasonable
bounds of the EPA's past practice in defining source categories, which
sometimes even contain sources that are located in multiple distinct
industries. See 40 CFR part 60, subpart Db (industrial-commercial-
institutional steam generating units), 40 CFR part 60, subpart IIII
(stationary compression ignition internal combustion engines). In this
regard, the House Report correctly noted that ``even the presence of
large distinctions in equipment type and emissions profile across two
segments would not necessarily preclude EPA from regulating those
segments as a single source category, so long as the EPA could identify
some meaningful relationship between them,'' House Report at 7, as the
EPA did in the 2016 Rule. Thus, the 2020 Policy Rule failed to
articulate appropriate reasons to change the scope of the source
category from what the EPA determined in the 2016 Rule. Having properly
identified the scope of the source category as including the
transmission and storage segment in the 2016 Rule, the EPA lawfully
promulgated NSPS for sources in that segment.
The EPA also affirms that the 2016 Rule established an appropriate
basis for promulgating methane NSPS from oil and gas sources, and that
the 2020 Policy Rule erred on all grounds in rescinding the methane
NSPS. The importance of taking action at this time, in accordance with
the requirements of CAA section 111, to reduce the enormous amount of
methane emissions from oil and gas sources, in light of the impacts on
the climate of this pollution, cannot be overstated. As stated in
section I, the Oil and Natural Gas Industry is the largest industrial
emitter of methane in the U.S. Human emissions of methane, a potent
GHG, are responsible for about one third of the warming due to well-
mixed GHGs, the second most important human warming agent after carbon
dioxide. According to the IPCC, strong, rapid, and sustained methane
reductions are critical to reducing near-term disruption of the climate
system and a vital complement to CO2 reductions critical in
limiting the long-term extent of climate change and its destructive
impacts.\161\ The EPA previously determined, in the 2016 NSPS OOOOa
rule, both that it had a rational basis to regulate methane emissions
from the source category, and, in the alternative, that methane
emissions from the Crude Oil and Natural Gas Source Category,
contribute significantly to dangerous air pollution. 81 FR 35842-43,
(June 3, 2016). The EPA is not reopening those determinations for
comment in the present rulemaking.
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\161\ See preamble section III for further discussion on the
Crude Oil and Natural Gas Emissions and Climate Change, including
discussion of the GHGs, VOCs and SO2 Emissions on Public
Health and Welfare.
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Contrary to the statements in the 2020 Policy Rule, the methane
NSPS promulgated in the 2016 Rule cannot be said to be redundant with
the VOC NSPS and therefore unnecessary. The large contribution of
methane emissions from the source category to dangerous air pollution
driving the grave and growing threat of climate change means that, in
the agency's judgment, it would be highly irresponsible and also
arbitrary and capricious under CAA section 307(d)(9)(A) for the EPA to
decline to promulgate NSPS for methane emissions from the source
category. See American Electric Power, 564 U.S. at 426-27. The fact
that the EPA designed the methane NSPS so that sources could comply
with them efficiently, through the same actions that the sources needed
to take to comply with the VOC NSPS, did not thereby create redundancy.
Further, the fact that methane NSPS but not the VOC NSPS trigger the
regulatory requirements for existing sources makes clear that the two
sets of requirements are not redundant. Indeed, if EPA had only
regulated VOCs, it would only have been authorized to regulate new and
modified sources, which comprise a small subset of polluting sources.
By contrast, because the 2016 Rule also regulated methane, EPA was
authorized and obligated to regulate hundreds of thousands of
additional ``existing'' sources that comprise the vast majority of
polluting sources. Accordingly, methane regulation was not
``redundant'' of VOC regulation. The 2020 Policy Rule's contrary
position was based on a misinterpretation of CAA section 111 which
overlooked that the provision integrates requirements for new and
existing sources. See Nat'l Lime Ass'n v. EPA, 627 F.2d 416, 433 n.48
(D.C. Cir. 1980) (CAA section 111(b)(1)(A) listing of a source category
is based on emissions from new and existing sources).
The EPA also reaffirms the 2016 Rule's statutory interpretation
that the EPA is authorized to promulgate a NSPS for an air pollutant
under CAA section 111(b)(1)(B) in a situation in which the EPA has
previously determined that the source category causes or contributes
significantly to dangerous air pollution and where the EPA has a
rational basis for regulating the particular air pollutant in question
that is emitted by the source category. 81 FR 35842 (June 3, 2016). The
2016 Rule noted the precedent in prior agency actions for the position
that--following the listing of a source category--the EPA need provide
only a rational basis for its exercise of discretion for which
pollutants to regulate under section 111(b)(1)(B). See id. (citing
National Lime Assoc. v. EPA, 627 F.2d 416, 426 & n.27 (D.C. Cir. 1980)
(court discussed, but did not review, the EPA's reasons for not
promulgating standards for NOX, SO2, and CO from
lime plants). In addition, the Supreme Court in American Electric Power
provided support for the rational basis statutory interpretation. 564
U.S. at 426-27 (``EPA [could] decline to regulate carbon-dioxide
emissions altogether at the conclusion of its . . . [CAA section 111]
rulemaking,'' and such a decision ``would not escape judicial review,''
under the ``arbitrary and capricious'' standard of section
307(d)(9)(A)). As the House Report noted, the EPA's rational basis
interpretation ``is fully consistent with the provision[s] of section
111 and the section 307(d)(9) `arbitrary and capricious' standard.''
House Report at 9.
The 2020 Policy Rule correctly noted that the CAA section
111(b)(1)(B) requirement that the EPA ``shall promulgate . . .
standards [of performance]'' for air pollutants, coupled with the CAA
section 111(a)(1) definition for ``standard of performance'' as, in
relevant part, a ``standard for emissions of air pollutants,'' does not
by its terms require that EPA promulgate NSPS for every air pollutant
from the source category. But the rule erred in seeking to graft the
CAA section 111(b)(1)(A) requirement for a SCF into CAA section
111(b)(1)(B). The language of CAA section 111(b)(1)(A) is clear: It
requires the EPA Administrator to ``include a category of sources in
[the list for regulation] if in his judgment it causes, or contributes
to, air pollution which may reasonably be anticipated to endanger
public health or welfare.'' (Emphasis added.) Congress thus specified
that the required SCF is made
[[Page 63153]]
on a category basis, not a pollutant-specific basis, and that once that
finding is made (as it was for the Crude Oil and Natural Gas source
category in 1979), the EPA may establish standards for pollutants
emitted by the source category. In determining for which air pollutants
to promulgate standards of performance, the EPA must act rationally,
which, as noted above, essentially must ensure that the action does not
fail the ``arbitrary and capricious'' standard under CAA section
307(d)(9)(A). The 2020 Policy Rule's objections to the rational basis
standard on grounds that is ``vague and not guided by any statutory
criteria,'' 85 FR 57034 (September 14, 2020), is incorrect. In making a
rational basis determination, the EPA has considered the amount of the
air pollutant emitted by the source category, both in absolute terms
and by drawing comparisons, as well as the availability of control
technologies. See National Lime Assoc. v. EPA, 627 F.2d 416, 426 & n.27
(D.C. Cir. 1980) (discussing EPA's reasons for not promulgating
standards for NOX, SO2 and CO from lime plants);
80 FR 64510, 64530 (October 23, 2015) (rational basis determination for
GHGs from fossil fuel-fired electricity generating power plants); 73 FR
35838, 35859-60 (June 24, 2008) (providing reasons why the EPA was not
promulgating GHG standards for petroleum refineries). Courts routinely
review rules under the ``arbitrary and capricious'' standard, as noted
in the House Report, at 11.
When the EPA is required to make an endangerment finding, the EPA
also affirms that that finding should be made in consideration of the
particular facts and circumstances, not a predetermined threshold.
Accordingly, the EPA rejects the 2020 Policy Rule's position to the
contrary. Section 111(b)(1)(A) of the CAA does not require that the SCF
for the source category be based on ``established criteria'' or
``standard or threshold.'' See Coal. for Responsible Regulation, Inc.
v. EPA, 684 F.3d 102, 122-23 (D.C. Cir. 2012) (``the inquiry [into
whether an air pollutant endangers] necessarily entails a case-by-case,
sliding-scale approach. . . . EPA need not establish a minimum
threshold of risk or harm before determining whether an air pollutant
endangers''). During the 50 years that it has made listing decisions,
the EPA has always relied on the individual facts and circumstances.
See Alaska Dep't of Envtl. Conservation, 540 U.S. 461, 487 (2004)
(explaining, in a case under the CAA, ``[w]e normally accord particular
deference to an agency interpretation of longstanding duration''
(internal quotation marks omitted) (citing Barnhart v. Walton, 535 U.S.
212, 220 (2002)). This approach is appropriate because Congress
intended that CAA section 111 apply to a wide range of source
categories and pollutants, from wood heaters to emergency backup
engines to petroleum refineries. In that context, it reasonable to
interpret section 111 to allow EPA the discretion to determine how best
to assess significant contribution and endangerment based on the
individual circumstances of each source category. On this point, as
well, the EPA is in full agreement with the statements in the House
Report. House Report at 9-10.
Finally, under CAA section 111(d)(1), once the EPA promulgates NSPS
for certain air pollutants, including GHGs, the EPA is required to
promulgate regulations, which the EPA terms EG, 40 CFR 60.22a, that in
turn require States to promulgate standards of performance for existing
sources of those air pollutants. The EPA agrees with the House Report
and Senate statement that it is imperative to regulate methane
emissions from the existing oil and gas sources that comprise the vast
majority of polluting sources expeditiously under the authority of CAA
section 111(d) and is proceeding with the process to do so in this
rulemaking by publishing proposed EG. See section III.B.2. In 2019, the
GHGI estimates for oil and natural gas production, and natural gas
processing and transmission and storage segments that methane emissions
equate to 182 MMT CO2 Eq.\162\ In the U.S. the EPA has
identified over 15,000 oil and gas owners and operators, around 1
million producing onshore oil and gas wells, about 5,000 gathering and
boosting facilities, over 650 natural gas processing facilities, and
about 1,400 transmission compression facilities.
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\162\ The 100-year GWP value of 25 for methane indicates that
one ton of methane has approximately as much climate impact over a
100-year period as 25 tons of CO2. The most recent IPCC
AR6 assessment has estimated a slightly larger 100-year GWP of
methane of almost 30 (specifically, either 27.2 or 29.8 depending on
whether the value includes the CO2 produced by the
oxidation of methane in the atmosphere). As mentioned earlier,
because methane has a shorter lifetime than CO2, the
emissions of a ton of methane will have more impact earlier in the
100-year timespan and less impact later in the 100-year timespan
relative to the emissions of a 100-year GWP-equivalent quantity of
CO2. See preamble section III for further discussion on
the Crude Oil and Natural Gas Emissions and Climate Change,
including discussion of the GHGs, VOCs and SO2 Emissions
on Public Health and Welfare.
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Some stakeholders have raised issues concerning the scope of
pollutants subject to CAA section 111(d) by arguing that the exclusion
in CAA section 111(d) for HAP covers not only those pollutants listed
for regulation under CAA section 112, but also precludes the EPA from
regulating a source category under CAA section 111(d) for any pollutant
if that source category has been regulated under CAA section 112. The
EPA agrees with its longstanding legal interpretation spanning multiple
Administrations that the 111(d) exclusion does not preclude the agency
from regulating a non-HAP pollutant from a source category under
section 111(d) even if that source category is regulated under section
112. See American Lung Ass'n v. EPA, 980 F.3d 914, 980 (D.C. Cir. 2019)
(referring to ``EPA's three-decade-old . . . reading of the statutory
amendments''), petition for cert. pending No. 20-1530 (filed April 29,
2021); 70 FR 15994, 16029 (March 29, 2005) (Clean Air Mercury Rule); 80
FR 64662, 64710 (Oct. 23, 2015) (Clean Power Plan); 84 FR 32520 (July
8, 2019) (Affordable Clean Energy Rule). The House Report agreed with
this interpretation, noting that the contrary position is flawed
because it ignores the overall statutory structure that Congress
created in the CAA and would create regulatory gaps in which the EPA
would not be able to regulate existing sources for some pollutants
(such as methane) under CAA section 111(d) if those sources (but not
pollutants) were already regulated for different pollutants under CAA
section 112. House Report at 11-12. Moreover, the D.C. Circuit recently
considered this precise issue and held that the EPA may both regulate a
source category for HAP under CAA section 112 and regulate that same
source category for different pollutants under CAA section 111(d). Am.
Lung Assoc., 985 F.3d at 977-988. Accordingly, both Congress and the
court have come to the same conclusion after reviewing the statutory
language, a conclusion that is aligned with the EPA's longstanding
position. We therefore proceed in the proposal to propose EGs for
existing sources in the oil and gas source category.
IX. Overview of Control and Control Costs
A. Control of Methane and VOC Emissions in the Crude Oil and Natural
Gas Source Category--Overview
As described in this action, the EPA reviewed the standards in the
2016 NSPS OOOOa pursuant to CAA section 111(b)(1)(B). Based on this
review, the EPA is proposing revisions to the standards for a number of
affected facilities to reflect the updated BSER for those affected
facilities. Where our analyses show that the BSER for an
[[Page 63154]]
affected facility remains the same, the EPA is proposing to retain the
current standard for that affected facility. In addition to the actions
on the standards in the 2016 NSPS OOOOa described in this section, the
EPA is proposing standards for GHGs (in the form of limitation on
methane) and VOCs for a number of new sources that are currently
unregulated. The proposed NSPS OOOOb would apply to new, modified, and
reconstructed emission sources across the Crude Oil and Natural Gas
source category for which construction, reconstruction, or modification
is commenced after November 15, 2021.
Further, pursuant to CAA section 111(d), the EPA is proposing EG,
which include presumptive standards for GHGs (in the form of
limitations on methane) (designated pollutant), for certain existing
emission sources across the Crude Oil and Natural Gas source category
in the proposed EG OOOOc. While the proposed requirements in NSPS OOOOb
would apply directly to new sources, the proposed requirements in EG
OOOOc are for States to use in the development of plans that establish
standards of performance that will apply to existing sources
(designated facilities).
B. How does EPA evaluate control costs in this action?
Section 111 of the CAA requires that the EPA consider a number of
factors, including cost, in determining ``the best system of emission
reduction . . . adequately demonstrated.'' CAA section 111(a)(1). The
D.C. Circuit has long recognized that ``[CAA] section 111 does not set
forth the weight that [ ] should [be] assigned to each of these
factors;'' therefore, ``[the court has] granted the agency a great
degree of discretion in balancing them.'' Lignite Energy Council v.
EPA, 198 F.3d 930, 933 (D.C. Cir. 1999) (``Lignite Energy Council'').
In Essex Chemical Corp. v. Ruckelshaus, 486 F.2d 427 (D.C. Cir. 1973)
(``Essex Chemical''), the court noted that ``it is not unlikely that
the industry and the EPA will disagree on the economic costs of various
control techniques'' and that it ``has no desire or special ability to
settle such a dispute.'' Id. at 437. Rather, the court focused its
review on ``whether the standards as set are the result of reasoned
decision-making.'' Id. at 434. A standard that ``is the result of the
exercise of reasoned discretion by the Administrator [ ] cannot be
upset by this Court.'' Id. at 437.
As noted, CAA section 111 requires that the EPA consider cost in
determining such system (i.e., ``BSER''), but it does not prescribe any
criteria for such consideration. The courts have recognized that the
EPA has ``considerable discretion under [CAA] section 111,'' Lignite
Energy Council, 198 F.3d at 933, on how it considers cost under CAA
section 111(a)(1). For example, in Essex Chemical, the D.C. Circuit
stated that to be ``adequately demonstrated,'' the system must be
``reasonably reliable, reasonably efficient, and . . . reasonably
expected to serve the interests of pollution control without becoming
exorbitantly costly in an economic or environmental way.'' 486 F.2d at
433. The court has reiterated this limit in subsequent case law,
including Lignite Energy Council, in which it stated: ``EPA's choice
will be sustained unless the environmental or economic costs of using
the technology are exorbitant.'' 198 F.3d at 933. In Portland Cement
Association v. Train, the court elaborated by explaining that the
inquiry is whether the costs of the standard are ``greater than the
industry could bear and survive.'' \163\ 513 F.2d 506, 508 (D.C. Cir.
1975). In Sierra Club v. Costle, the court provided a substantially
similar formulation of the cost factor: ``EPA concluded that the
Electric Utilities' forecasted cost was not excessive and did not make
the cost of compliance with the standard unreasonable. This is a
judgment call with which we are not inclined to quarrel.'' 657 F.2d
298, 343 (D.C. Cir. 1981). We believe that these various formulations
of the cost factor--``exorbitant,'' ``greater than the industry could
bear and survive,'' ``excessive,'' and ``unreasonable''--are
synonymous; the D.C. Circuit has made no attempt to distinguish among
them. For convenience, in this rulemaking, we will use the term
``reasonable'' to describe that our evaluation of costs is well within
the boundaries established by this case law.
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\163\ The 1970 Senate Committee Report on the Clean Air Act
stated: ``The implicit consideration of economic factors in
determining whether technology is `available' should not affect the
usefulness of this section. The overriding purpose of this section
would be to prevent new air pollution problems, and toward that end,
maximum feasible control of new sources at the time of their
construction is seen by the committee as the most effective and, in
the long run, the least expensive approach.'' S. Comm. Rep. No. 91-
1196 at 16.
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In evaluating whether the cost of a control is reasonable, the EPA
considers various costs associated with such control, including capital
costs and operating costs, and the emission reductions that the control
can achieve. As discussed further below, the agency considers these
costs in the context of the industry's overall capital expenditures and
revenues. Cost-effectiveness analysis is also a useful metric, and a
means of evaluating whether a given control achieves emission reduction
at a reasonable cost. A cost-effectiveness analysis also allows
comparisons of relative costs and outcomes (effects) of two or more
options. In general, cost-effectiveness is a measure of the outcomes
produced by resources spent. In the context of air pollution control
options, cost-effectiveness typically refers to the annualized cost of
implementing an air pollution control option divided by the amount of
pollutant reductions realized annually. A cost-effectiveness analysis
is not intended to constitute or approximate a benefit-cost analysis in
which monetized benefits are compared to costs, but rather provides a
metric to compare the relative cost and emissions impacts of various
control options.
The estimation and interpretation of cost-effectiveness values is
relatively straightforward when an abatement measure is implemented for
the purpose of controlling a single pollutant, such as for the controls
included as presumptive standards in the proposed EG OOOOc to address
methane emissions from existing sources in the Crude Oil and Natural
Gas source category. In other circumstances, air pollution reduction
programs require reductions in emissions of multiple pollutants, as
with the NSPS for the Crude Oil and Natural Gas source category, which
regulates both GHG and VOC. In such cases, multipollutant controls
(controls that achieve reductions of both pollutants through the same
techniques and technologies) may be employed, and consequently, there
is a need for determining cost-effectiveness for a control option
across multiple pollutants (or classes of multiple pollutants).
During the rulemaking for NSPS OOOOa, we evaluated a number of
approaches for considering the cost-effectiveness of the available
multipollutant controls for reducing both methane and VOC emissions.
See 80 FR 56593, 56616 (September 18, 2015). In that rulemaking, we
used two approaches for considering the cost-effectiveness of control
options that reduce both VOC and methane emissions; we are proposing to
use these same two cost-effectiveness approaches, along with other
factors discussed further below, in considering the cost of requiring
control for the proposed NSPS OOOOb. One approach, which we refer to as
the ``single pollutant cost-effectiveness approach,'' assigns all costs
to the emission reduction of one pollutant and zero to all other
concurrent reductions. If the cost is reasonable for reducing any of
the
[[Page 63155]]
targeted pollutants alone, the cost of such control is clearly
reasonable for the concurrent emission reduction of all the other
regulated pollutants because they are being reduced at no additional
cost. While this approach assigns all costs to only a portion of the
emission reduction and thus may overstate the cost for that assigned
portion, it does not overstate the overall cost. Instead, it
acknowledges that the reductions of the other regulated pollutant are
intended as opposed to incidental. This approach is simple and
straightforward in application: If the multipollutant control is cost
effective for reducing emissions of either of the targeted pollutants,
it is clearly cost effective for reducing all other targeted emissions
that are being achieved simultaneously.
A second approach, which we term for the purpose of this rulemaking
a ``multipollutant cost-effectiveness approach,'' apportions the
annualized cost across the pollutant reductions addressed by the
control option in proportion to the relative percentage reduction of
each pollutant controlled. In the case of the Crude Oil and Natural Gas
source category, both methane and VOC are reduced in equal proportions,
relative to their respective baselines by the multipollutant control
option (i.e., where control is 95 percent reduction, methane and VOC
are both simultaneously reduced by 95 percent by the multipollutant
control). As a result, under the multipollutant cost-effectiveness
approach, half of the control costs are allocated to methane and the
other half to VOC. Under this approach, control is cost effective if it
is cost effective for both VOC and methane.
We believe that both the single pollutant and multipollutant cost-
effectiveness approaches discussed above are appropriate for assessing
the reasonableness of the multipollutant controls considered in this
action for new sources. As such, in the individual BSER analyses in
section XII below, if a device is cost-effective under either of these
two approaches, we find it to be cost-effective. The EPA has considered
similar approaches in the past when considering multiple pollutants
that are controlled by a given control option.\164\ The EPA recognizes,
however, not all situations where multipollutant controls are applied
are the same, and that other types of approaches might be appropriate
in other instances.
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\164\ See, e.g., 73 FR 64079-64083 and EPA Document I.D. EPA-HQ-
OAR-2004-0022-0622, EPA-HQ-OAR-2004-0022-0447, EPA-HQ-OAR- 2004-
0022-0448.
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As mentioned above, as part of its consideration of control costs
in the individual BSER analyses in Section XII, the EPA evaluated cost-
effectiveness using the single pollutant and multipollutant cost-
effectiveness approaches. We estimated the cost-effectiveness values of
the proposed control options using available information, including
various studies, information submitted in previous rulemakings from the
affected industry, and information provided by small businesses. The
EPA provides the cost effectiveness estimates for reducing VOC and
methane emissions for various control options considered in section
XII. As discussed in that section, the EPA finds cost-effectiveness
values up to $5,540/ton of VOC reduction to be reasonable for controls
that we have identified as BSER in this proposal. These VOC values are
within the range of what the EPA has historically considered to
represent cost effective controls for the reduction of VOC emissions,
including in the 2016 NSPS, based on the Agency's long history of
regulating a wide range of industries. With respect to methane, the EPA
finds the cost-effectiveness values up to $1,800/ton of methane
reduction to be reasonable for controls that we have identified as BSER
in this proposal. Unlike VOC, the EPA does not have a long regulatory
history to draw upon in assessing the cost effectiveness of controlling
methane, as the 2016 NSPS OOOOa was the first national standard for
reducing methane emissions. However, as explained below, the EPA has
previously determined that methane cost-effectiveness values for the
controls identified as BSER for the 2016 NSPS OOOOa, which range up to
$2,185/ton of methane reduction, represent reasonable costs for the
industry as a whole to bear; and because the cost-effectiveness
estimates for the proposed standards in this action are comparable to
the cost-effectiveness values estimated for the controls that served as
the basis (i.e., BSER) for the standards in the 2016 NSPS OOOOa, we
consider the proposed standards to also be cost effective and
reasonable.
The BSER determinations from the 2016 NSPS OOOOa also support the
EPA's conclusion that the cost-effectiveness values associated with the
proposed standards in this action are reasonable. As mentioned above,
for 2016 NSPS OOOOa, the highest estimate that the EPA considered cost
effective for methane reduction was $2,185/ton, which was the estimate
for converting a natural gas driven diaphragm pump to an instrument air
pump at a gas processing plant. 165 166 80 FR 56627; see
also, NSPS OOOOa Final TSD at 93, Table 6-7. The EPA estimated that the
cost-effectiveness of this option, a common practice at gas processing
plants, could be up to $2,185/ton of methane reduction under the single
pollutant cost-effectiveness approach and $1,093/ton under the
multipollutant cost effectiveness approach; the EPA found ``the control
to be cost effective under either approach.'' Id. Accordingly, the EPA
finalized requirements in the 2016 NSPS OOOOa that require zero
emissions from diaphragm pumps at gas processing plants, consistent
with the Agency's BSER determination.
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\165\ As discussed in section X.A, the EPA incorrectly stated in
the 2020 Technical Rule that $738/ton of methane reduction was the
highest cost-effectiveness value that the EPA determined to be
reasonable for methane reduction in the 2016 NSPS OOOOa.
\166\ While in that rulemaking the EPA found quarterly
monitoring of fugitive emissions at well sites not cost effective at
$1,960/ton of methane reduced using the single pollutant approach
(and $980 using the multi-pollutant approach), the EPA emphasized
that this conclusion was not intended to ``preclude the EPA from
taking a different approach in the future including requiring more
frequent monitoring (e.g., quarterly).'' 81 FR 35855-6 referencing
Background Technical Support Document for the New Source Performance
Standards 40 CFR part 60 subpart OOOOa (May 2016), at 49, Table 4-11
and 52, Table 4-14. Further, several states have issued regulations
and industry has voluntarily taken steps to reduce emissions. This
combined with greater knowledge and understanding of the industry
leads us to find these values cost-effective. As discussed in this
section IX.B, cost-effectiveness is one--not the only--factor in
EPA's consideration of control costs. In fact, in this action, the
EPA is proposing different monitoring frequencies based on well site
baseline emissions, even though the EPA found quarterly monitoring
to be cost effective for all well sites. Please see section XII.A
for a detailed discussion on this proposal.
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The 2016 NSPS OOOOa also requires 95 percent methane and VOC
emission reduction from wet-seal centrifugal compressors. The BSER for
this standard was capturing and routing the emissions to a control
combustion device, a widely used control in the oil and gas sector for
reducing emissions from storage vessels and pumps, in addition to
centrifugal compressors. 80 FR 56620. The EPA estimated cost-
effectiveness values of up to $1,093/ton of methane reduction for this
option. See NSPS OOOOa Final TSD at 114, Table 7-9. With respect to
other controls identified as BSER in the 2016 NSPS OOOOa, their cost-
effectiveness estimates were comparable to or well below the estimates
from the 2016 NSPS OOOOa rulemaking discussed above. In light of this,
and because sources have been complying with the 2016 NSPS OOOOa for
years, we believe that the cost-effectiveness values for the controls
[[Page 63156]]
identified as BSER for the 2016 NSPS OOOOa, which range up to $2,185/
ton of methane reduction, represent reasonable, rather than excessive,
costs for the industry as a whole to bear. As shown in the individual
BSER analyses in Section XII and the NSPS OOOOb and EG OOOOc TSD for
this proposal, the cost-effectiveness values for the proposed standards
in this action are comparable to the cost-effectiveness values for the
standards in NSPS OOOOa. We, therefore, similarly consider the cost-
effectiveness values for the proposed standards to be reasonable. That
the proposed standards reflect the kinds of controls that many
companies and sources around the country are already implementing
underscore the reasonableness of these control measures.
In addition to evaluating the annual average cost-effectiveness of
a control option, the EPA also considers the incremental costs
associated with increasing the stringency of the standards from one
level of control to another level of control that achieves more
emission reductions. The incremental cost of control provides insight
into how much it costs to achieve the next increment of emission
reductions through application of each increasingly stringent control
options, and thus is a useful tool for distinguishing among the effects
of more and less stringent control options. For example, during the
rulemaking for the 2012 NSPS OOOO, the EPA considered the incremental
cost effectiveness of changing the originally promulgated standards for
leaks at gas processing plants, which were based on NSPS subpart VV, to
the more stringent NSPS subpart VVa-level program. See 76 FR 52738,
52755 (August 23, 2011). The EPA generally finds the incremental cost-
effectiveness to be reasonable if it is consistent with the costs that
the Agency considers reasonable in its evaluation of annual average
cost-effectiveness.
As shown in the NSPS OOOOb and EG OOOOc TSD for this action, the
EPA estimated control costs both with and without savings from
recovered gas that would otherwise be emitted. When determining the
overall costs of implementation of the control technology and the
associated cost-effectiveness, the EPA reasonably takes into account
any expected revenues from the sale of natural gas product that would
be realized as a result of avoided emissions that result from
implementation of a control. Such a sale would offset regulatory costs
and so should be included to accurately assess the overall costs and
the cost-effectiveness of the standard. In our analysis we consider any
natural gas that is either recovered or that is not emitted as a result
of a control option as being ``saved.'' We estimate that one thousand
standard cubic feet (Mcf) of natural gas is valued at $3.13 per
Mcf.\167\ Our cost analysis then applies the monetary value of the
saved natural gas as an offset to the control cost.\168\ This offset
applies where, in our estimation, the monetary savings of the natural
gas saved can be realized by the affected facility owner or operator
and not where the owner or operator does not own the gas and would not
likely realize the monetary value of the natural gas saved (e.g.,
transmission stations and storage facilities). Detailed discussions of
these assumptions are presented in section 2 of the RIA associated with
this action, which is in the docket.
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\167\ This value reflects the forecasted Henry Hub price for
2022 from: U.S. Energy Information Administration. Short-Term Energy
Outlook. https://www.eia.gov/outlooks/steo/archives/may21.pdf.
Release Date: May 11, 2021.
\168\ While the EPA presents cost-effectiveness with and without
cost savings, the BSER is determined based on the cost-effectiveness
without cost savings in all cases.
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We also completed two additional analyses to further inform our
determination of whether the cost of control is reasonable, similar to
compliance cost analyses we have completed for other NSPS.\169\ First,
we compared the capital costs that would be incurred to comply with the
proposed standards to the industry's estimated new annual capital
expenditures. This analysis allowed us to compare the capital costs
that would be incurred to comply with the proposed standards to the
level of new capital expenditures that the industry is incurring in the
absence of the proposed standards. We then determined whether the
capital costs appear reasonable in comparison to the industry's current
level of capital spending. Second, we compared the annualized costs
that would be incurred to comply with the standards to the industry's
estimated annual revenues. This analysis allowed us to evaluate the
annualized costs as a percentage of the revenues being generated by the
industry.
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\169\ For example, see our compliance cost analysis in
``Regulatory Impact Analysis (RIA) for Residential Wood Heaters NSPS
Revision. Final Report.'' U.S. Environmental Protection Agency,
Office of Air Quality Planning and Standards. EPA-452/R-15-001,
February 2015.
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The EPA has evaluated incremental capital costs in a manner similar
to the analyses described above in prior new source performance
standards, and in those prior standards, the Agency's determinations
that the costs were reasonable were upheld by the courts. For example,
the EPA estimated that the costs for the 1971 NSPS for coal-fired
electric utility generating units were $19 million for a 600 MW plant,
consisting of $3.6 million for particulate matter controls, $14.4
million for sulfur dioxide controls, and $1 million for nitrogen oxides
controls, representing a total 15.8 percent increase in capital costs
above the $120 million cost of the plant.\170\ See 1972 Supplemental
Statement, 37 FR 5767, 5769 (March 21, 1972). The D.C. Circuit upheld
the EPA's determination that the costs associated with the final 1971
standard were reasonable, concluding that the EPA had properly taken
costs into consideration. Essex Chemical, 486 F. 2d at 440. Similarly,
in Portland Cement Association v. Ruckelshaus, the D.C. Circuit upheld
the EPA's consideration of costs for a standard of performance that
would increase capital costs by about 12 percent, although the rule was
remanded due to an unrelated procedural issue. 486 F.2d 375, 387-88
(D.C. Cir. 1973). Reviewing the EPA's final rule after remand, the
court again upheld the standards and the EPA's consideration of costs,
noting that ``[t]he industry has not shown inability to adjust itself
in a healthy economic fashion to the end sought by the Act as
represented by the standards prescribed.'' Portland Cement Assn. v.
Train, 513 F. 2d at 508.
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\170\ Assuming these costs were denominated in 1971 dollars,
converting the costs from 1971 to 2019 dollars using the Gross
Domestic Product-Implicit Price Deflator, the costs for the 1971
NSPS for coal-fired electric utility generating units were $94
million for a 600 MW plant, consisting of $18 million for
particulate matter controls, $71 million for sulfur dioxide
controls, and $5 million for nitrogen oxides controls, representing
a 15.8 percent increase in capital costs above the $590 million cost
of the plant.
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In this action, for the capital expenditures analysis, we divide
the nationwide capital expenditures projected to be spent to comply
with the proposed standards by an estimate of the total sector-level
new capital expenditures for a representative year to determine the
percentage that the nationwide capital cost requirements under the
proposal represent of the total capital expenditures by the sector. We
combine the compliance-related capital costs under the proposed
standards for the NSPS and for the presumptive standards in the
proposed EG to analyze the potential aggregate impact of the proposal.
The EAV of the projected compliance-related capital expenditures over
the 2023 to 2035 period is projected to be about $510 million in 2019
dollars. We obtained new capital
[[Page 63157]]
expenditure data for relevant NAICS codes for 2018 from the U.S. Census
2019 Annual Capital Expenditures Survey.\171\ Estimates of new capital
expenditures are available for 2019, but we chose to use 2018 because
the 2019 new capital expenditure data for pipeline transportation of
natural gas (NAICS 4862) are withheld to avoid disclosing data for
individual enterprises, and the withholding of that NAICS causes the
totals for 2019 to be lower than for 2018. According to these data, new
capital expenditures for the sector in 2018 were about $155 billion in
2019 dollars. Comparing the EAV of the projected compliance-related
capital expenditures under the proposal with the 2018 total sector-
level new capital expenditures yields a percentage of about 0.3
percent, which is well below the percentage increase previously upheld
by the courts, as discussed above.
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\171\ U.S. Census Bureau, 2019 Annual Capital Expenditures
Survey, Table 4b. Capital Expenditures for Structures and Equipment
for Companies With Employees by Industry: 2018 Revised, http://www.census.gov/econ/aces/index.html, accessed September 4, 2021.
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For the comparison of compliance costs to revenues, we use the EAV
of the projected compliance costs without and with projected revenues
from product recovery under the proposal for the 2023 to 2035 period
then divided the nationwide annualized costs by the annual revenues for
the appropriate NAICS code(s) for a representative year to determine
the percentage that the nationwide annualized costs represent of annual
revenues. Like we do for capital expenditures, we combine the costs
projected to be expended to comply with the standards for NSPS and the
presumptive standards in the proposed EG to analyze the potential
aggregate impact of the proposal. The EAV of the associated increase in
compliance cost over the 2023 to 2035 period is projected to be about
$1.2 billion without revenues from product recovery and about $760
million with revenues from product recovery (in 2019 dollars). Revenue
data for relevant NAICS codes were obtained from the U.S. Census 2017
County Business Patterns and Economic Census, the most recent revenue
figures available.\172\ According to these data, 2018 receipts for the
sector were about $358 billion in 2019 dollars. Comparing the EAV of
the projected compliance costs under the proposal with the sector-level
receipts figure yields a percentage of about 0.3 percent without
revenues from product recovery and about 0.2 percent with revenues from
product recovery. More data and analysis supporting the comparison of
capital expenditures and annualized costs projected to be incurred
under the rule and the sector-level capital expenditures and receipts
is presented in Chapter 15 of the TSD for this action, which is in the
public docket.
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\172\ 2017 County Business Patterns and Economic Census. The
Number of Firms and Establishments, Employment, Annual Payroll, and
Receipts by Industry and Enterprise Receipts Size: 2017, https://www.census.gov/programs-surveys/susb/data/tables.2017.html, accessed
September 4. 2021.
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In considering the costs of the control options evaluated in this
action, the EPA estimated the control costs under various approaches,
including annual average cost-effectiveness and incremental cost-
effectiveness of a given control. The EPA also performed two broad
comparisons to consider the costs of control: First, we compared the
projected compliance-related capital expenditures to recent sector-
level capital expenditures; second, we compared the projected total
compliance costs to recent sector-level annual revenues. In its cost-
effectiveness analyses, the EPA recognized and took into account that
these multi-pollutant controls reduce both VOC and methane emissions in
equal proportions, as reflected in the single-pollutant and
multipollutant cost effectiveness approaches. The EPA also considered
cost saving from the natural gas recovered instead of vented due to the
proposed controls. Based on all of the considerations described above,
the EPA concludes that the costs of the controls that serve as the
basis of the standards proposed in this action are reasonable. The EPA
solicits comment on its approaches for considering control costs, as
well as the resulting analyses and conclusions.
X. Summary of Proposed Action for NSPS OOOOa
As described above in sections IV and VIII, the 2020 Policy Rule
rescinded all NSPS regulating emissions of VOC and methane from sources
in the natural gas transmission and storage segment of the Oil and
Natural Gas Industry and NSPS regulating methane from sources in the
industry's production and processing segments. As a result, the 2020
Technical Rule only amended the VOC standards for the production and
processing segments in the 2016 NSPS OOOOa, because those were the only
standards that remained at the time that the 2020 Technical Rule was
finalized. The 2020 Technical Rule included amendments to address a
range of technical and implementation issues in response to
administrative petitions for reconsideration and other issues brought
to the EPA's attention since promulgating the 2016 NSPS. These
included, among other issues, those associated with the implementation
of the fugitive emissions requirements and pneumatic pump standards,
provisions to apply for the use of an AMEL, provisions for determining
applicability of the storage vessel standards, and modification to the
engineer certifications. In 2018, the EPA proposed amendments to
address these technical issues for both the methane and VOC standards
in the 2016 NSPS OOOOa, and in some instances for sources in the
transmission and storage segment. 83 FR 52056, October 15, 2018.
However, because the methane standards and all standards for the
transmission and storage segment were removed via the 2020 Policy Rule
prior to the finalization of the 2020 Technical Rule, the final
amendments in the 2020 Technical Rule apply only to the 2016 NSPS OOOOa
VOC standards for the production and processing segments. Additionally,
the 2020 Policy Rule amended the 2012 NSPS OOOO to remove the VOC
requirements for sources in the transmission and storage segment, but
the Technical Rule did not amend the 2012 NSPS OOOO.
Under the CRA, a rule that is subject to a joint resolution of
disapproval ``shall be treated as though such rule had never taken
effect.'' 5 U.S.C. 801(f)(2). Thus, because it was disapproved under
the CRA, the 2020 Policy Rule is treated as never having taken effect.
As a result, the requirements in the 2012 NSPS OOOO and 2016 NSPS OOOOa
that the 2020 Policy Rule repealed (i.e., the VOC and methane standards
for the transmission and storage segment, as well as the methane
standards for the production and processing segments) must be treated
as being in effect immediately upon enactment of the joint resolution
on June 30, 2021. Any new, reconstructed, or modified facility that
would have been subject to the 2012 or 2016 NSPS (``affected
facility'') but for the 2020 Policy Rule was subject to those NSPS as
of that date. The CRA resolution did not address the 2020 Technical
Rule; therefore, the amendments made in the 2020 Technical Rule, which
apply only to the VOC standards for the production and processing
segments in the 2016 NSPS OOOOa, remain in effect. As a result, sources
in the production and processing segments are now subject to two
different sets of standards:\173\ One
[[Page 63158]]
for methane based on the 2016 NSPS OOOOa, and one for VOC that include
the amendments to the 2016 NSPS OOOOa made in the 2020 Technical Rule.
Sources in the transmission and storage segment are subject to the
methane and VOC standards as promulgated in either the 2012 NSPS OOOO
or the 2016 NSPS OOOOa, as applicable.\174\ The EPA recognizes that
certain amendments made to the VOC standards in the 2016 NSPS OOOOa in
the 2020 Technical Rule, which addressed technical and implementation
issues in response to administrative petitions for reconsideration and
other issues brought to the EPA's attention since promulgating the 2016
NSPS OOOOa rule could also be appropriate to address similar
implementation issues associated with the methane standards for the
production and processing segments and the methane and VOC standards
for the transmission and storage segment. In fact, as mentioned above,
such revisions were proposed in 2018 but not finalized because these
standards were removed by the 2020 Policy Rule prior to the EPA's
promulgation of the 2020 Technical Rule. In light of the above, the EPA
is proposing to revise 40 CFR part 60, subpart OOOOa, to apply certain
amendments made in the 2020 Technical Rule to the 2016 NSPS OOOOa for
methane from the production and processing segments and/or the 2016
NSPS OOOOa for methane and VOC from the transmission and storage
segment, as specified in this section.
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\173\ The only exception is storage vessels, for which the EPA
did not promulgate methane standards in the 2016 NSPS OOOOa.
\174\ For the EPA's full explanation of its initial guidance to
stakeholders on the impact of the CRA, please see https://www.epa.gov/system/files/documents/2021-07/qa_cra_for_2020_oil_and_gas_policy_rule.6.30.2021.pdf.
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In this action, the EPA is proposing amendments to the 2016 NSPS
OOOOa to (1) rescind the revisions to the VOC fugitive emissions
monitoring frequencies at well sites and gathering and boosting
compressor stations in the 2020 Technical Rule as those revisions were
not supported by the record for that rule, or by our subsequent
information and analysis, and (2) adjust other modifications made in
the 2020 Technical Rule to address technical and implementation issues
that result from the CRA disapproval of the 2020 Policy Rule. The EPA
is not reopening any of these prior rulemakings for any other purpose
in this proposed action. Specifically, the EPA is not reopening any of
the determinations made in the 2012 NSPS OOOO. In the final rule for
this action, the EPA will update the NSPS OOOO and NSPS OOOOa
regulatory text in the CFR to reflect the CRA resolution's disapproval
of the final 2020 Policy Rule, specifically, the reinstatement of the
NSPS OOOO and NSPS OOOOa requirements that the 2020 Policy Rule
repealed but that came back into effect immediately upon enactment of
the CRA resolution. In accordance with 5 U.S.C. 553(b)(3)(B), the EPA
is not soliciting comment on these updates. Moreover, the EPA is not
reopening the methane standards as finalized in the 2016 NSPS OOOOa,
except as to the specific issues discussed below, nor is the EPA
reopening any other portions of the 2016 Rule. The EPA is also not
reopening any determinations made in the 2020 Technical Rule, except as
to the specific issues discussed below. Finally, the reopening of
determinations made with respect to the VOC standards in the 2020
Technical Rule does not indicate any intent to also reopen the methane
standards for the same affected facilities.
A. Amendments to Fugitive Emissions Monitoring Frequency
The EPA is proposing to repeal its amendments in the 2020 Technical
Rule that (1) exempted low production well sites from monitoring
fugitive emissions and (2) changed from quarterly to semiannual
monitoring of VOC emissions at gathering and boosting compressor
stations. The EPA has authority to reconsider a prior action ``as long
as `the new policy is permissible under the statute. . . , there are
good reasons for it, and . . . the agency believes it to be better.' ''
FCC v. Fox Television Stations, Inc., 556 U.S. 502, 515, 129 S. Ct.
1800, 173 L. Ed. 2d738 (2009).
The 2016 NSPS OOOOa, as initially promulgated, required semiannual
monitoring of VOC and methane emissions at all well sites, including
low production well sites. It also required quarterly monitoring of
compressor stations, including gathering and boosting compressor
stations. After issuing the 2020 Policy Rule, which removed all methane
standards applicable to the production and processing segments and all
methane and VOC standards applicable to the transmission and storage
segment, the EPA promulgated the 2020 Technical Rule that further
amended the VOC standards in the production and processing segment. In
particular, based on its revised cost analyses, the EPA exempted low
production well sites from monitoring VOC fugitive emissions and
changed the frequency of monitoring VOC fugitive emissions from
quarterly to semiannually at gathering and boosting compressor
stations. However, as a result of the CRA disapproval of the 2020
Policy Rule, the low production well sites and the gathering and
boosting compressor stations continue to be subject to semiannual and
quarterly monitoring of methane emissions respectively. While it is
possible for these affected facilities to comply with both the VOC and
methane monitoring standards that are now in effect, as compliance with
the more stringent standard would be deemed compliance with the other,
the EPA reviewed its decisions to amend the VOC monitoring frequencies
for these affected facilities as well as the underlying record and, for
the reasons explained below, no longer believe that the amendments are
appropriate. Therefore, the EPA is proposing to repeal these amendments
and restore the semiannual and quarterly monitoring requirements for
low production well sites and gathering and boosting compressor
stations, as originally promulgated in the 2016 NSPS OOOOa, for both
methane and VOC.
1. Low Production Well Sites
As mentioned above, low production well sites are subject to
semiannual monitoring of fugitive methane emissions. The EPA is
proposing to repeal the amendment in the 2020 Technical Rule exempting
low production well sites from monitoring fugitive VOC emissions
because the analysis for the 2020 Technical Rule supports retaining the
semiannual monitoring requirement when regulating both VOC and methane
emissions. While the 2020 Technical Rule amended only the VOC standards
in the production and processing segments, the EPA evaluated both
methane and VOC reductions in its final technical support document
(TSD) (2020 TSD), including the costs associated with different
monitoring frequencies under the multipollutant approach,\175\ which
the EPA considers a reasonable approach when regulating multiple
pollutants. As shown in the 2020 TSD, under the multipollutant
approach, the cost of semiannual monitoring at low production well
sites is $850 per ton of methane and $3,058 per ton of VOC reduced,
both of which are well within the range of what the
[[Page 63159]]
EPA considers to be cost effective.\176\ Nevertheless, the EPA stated
in the 2020 Technical Rule that ``even if we had not rescinded the
methane standards in the 2020 Policy Rule, we would still conclude that
fugitive emissions monitoring, at any of the frequencies evaluated, is
not cost effective for low production well sites.'' This statement,
however, is inconsistent with the conclusions on what costs are
reasonable for the control of methane emissions as discussed in this
proposal in section IX. More importantly, as an initial matter, this
statement was based on the EPA's observation in the 2020 Technical Rule
that the $850 per ton of methane reduced is ``greater than the highest
value for methane that the EPA determined to be reasonable in the 2016
NSPS subpart OOOOa,'' which the EPA incorrectly identified as $738/ton;
the record for the 2016 NSPS OOOOa shows that the EPA considered value
as high as $2,185/ton to be cost effective for methane reduction. 80 FR
56627; see also, NSPS OOOOa Final TSD at 93, Table 6-7. Further, even
with the incorrect observation, the EPA did not conclude in the 2020
Technical Rule that $850 per ton of methane reduced is therefore
unreasonable. 85 FR 57420. In fact, the EPA reiterated its prior
determination that ``a cost of control of $738 per ton of methane
reduced did not appear excessive,'' and that value was only $112 less
than the value that the EPA had incorrectly identified as the highest
methane cost-effectiveness value from the 2016 NSPS OOOOa. As discussed
above, in fact $738/ton is well within the costs that the EPA concludes
to be reasonable in the 2016 NSPS OOOOa as well as in this document.
Also, as explained in section XI.A.2, due to the wide variation in well
characteristics, types of oil and gas products and production levels,
gas composition, and types of equipment at well sites, there is
considerable uncertainty regarding the relationship between the
fugitive emissions and production levels. Accordingly, the EPA no
longer believes that production levels provide an appropriate threshold
for any exemption from fugitive monitoring. See section XI.A.2 for
additional discussion on the proposed emission thresholds for well site
fugitive emissions in place of production-based model plants. In light
of the above, the EPA is proposing to remove the exemption of low
production well sites from fugitive VOC emissions monitoring, thereby
restoring the semiannual monitoring requirement established in the 2016
NSPS OOOOa.
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\175\ 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.
\176\ See 2020 NSPS OOOOa Technical Rule TSD at Docket ID No.
EPA-HQ-OAR-2017-0483-2291. See also section IX, which provides that
the cost effectiveness values for the controls that we have
identified as BSER in this action range from $2,200/ton to $5,800/
ton VOC reduction and $700/ton to $2,100/ton of methane reduction.
As explained in that section, these controls reflect emission
reduction technologies and methods that many owners and operators in
the oil and gas industry have employed for years, either voluntarily
or due to the 2012 and 2016 NSPS, as well as State or other
requirements.
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2. Gathering and Boosting Compressor Stations
The EPA is proposing to repeal its amendment to the VOC monitoring
frequency for gathering and boosting compressor stations in the 2020
Technical Rule because the EPA believes that amendment was made in
error. In that rule, the EPA noted that, based on its revised cost
analysis, quarterly monitoring has a cost effectiveness of $3,221/ton
of VOC emissions and an incremental cost of $4,988/ton of additional
VOC emissions reduced between the semiannual and quarterly monitoring
frequencies. While the EPA observed that semiannual monitoring is more
cost effective than quarterly, the EPA nevertheless acknowledged that
``these values (total and incremental) are considered cost-effective
for VOC reduction based on past EPA decisions, including the 2016
rulemaking.'' 85 FR 57421, September 15, 2020. The EPA instead
identified two additional factors to support its decision to forgo
quarterly monitoring. First, the EPA stated that 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.'' However, the EPA did not
offer any data regarding the financial hardship, significant or
otherwise, the industry was experiencing. While the rule cited to
several articles on the impact of COVID-19 on the industry, the EPA did
not discuss any aspect of any of the cited articles that led to its
conclusion of ``significant financial hardship'' on the industry. Nor
did the EPA explain how reducing the frequency of a monitoring
requirement that had been in effect since 2016 would meaningfully
affect the industry's economic circumstances in any way or weigh those
considerations against the forgone emission reductions that would
result from reducing monitoring frequency.
Second, the EPA generally asserted that ``there are potential
efficiencies, and potential cost savings, with applying the same
monitoring frequencies for well sites and compressor stations.'' Again,
the EPA did not describe what the potential efficiencies are or the
extent of cost savings that would justify forgoing quarterly
monitoring, or weigh those efficiencies and cost savings against the
forgone emission reductions that would result from reducing the
monitoring frequency for compressor stations. Nor did we explain why
the Agency's 2016 BSER determination that quarterly monitoring was
achievable and cost-effective was incorrect in light of these asserted
efficiencies. On the contrary, based on the compliance records for the
2016 NSPS OOOOa, there is no indication that compressor stations
experienced hardship or difficulty in complying with the quarterly
monitoring requirement. Further, as discussed in section XII.A.1.b, our
analysis for NSPS OOOOb and EG OOOOc confirms that quarterly monitoring
remains both achievable and cost-effective for compressor stations, and
several State agencies also have rules that require quarterly
monitoring at compressor stations. For the reasons stated above, the
EPA concludes that it lacked justification and thus erred in revising
the VOC monitoring frequency for gathering and boosting compressor
stations from quarterly to semiannual. The EPA is therefore proposing
to repeal that amendment, thereby restoring the quarterly monitoring
requirement for gathering and boosting compressor stations, as
established in the 2016 NSPS OOOOa.
B. Technical and Implementation Amendments
In the following sections, the EPA describes a series of proposed
amendments to 2016 NSPS OOOOa for methane to align the 2016 methane
standards with the current VOC standards (which were modified by the
2020 Technical Rule). We describe the supporting rationales that were
provided in the 2020 Technical Rule for modifying the requirements
applicable to the VOC standards, and explain why the amendments would
also appropriately apply to the reinstated methane standards.
1. Well Completions
In the 2020 Technical Rule, the EPA made certain amendments to the
VOC standards for well completions in the 2016 NSPS OOOOa. For the same
reasons provided in the 2020 Technical Rule and reiterated below, the
EPA is proposing to apply the same amendments to the methane standards
for well completions in the 2016 NSPS OOOOa.
First, the EPA is proposing to amend the 2016 NSPS OOOOa methane
standards for well completions to allow
[[Page 63160]]
the use of a separator 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 well completion requirements, as
promulgated in 2016, had required that the owner or operator of a well
affected facility have a separator on site during the entire flowback
period. 81 FR 35901, June 3, 2016. In the 2020 Technical Rule, the EPA
amended this provision 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. See
40 CFR 60.5375a(a)(1)(iii). As explained in that rulemaking (85 FR
57403) and previously in the 2016 NSPS OOOOa final rule preamble,
``[w]e anticipate a subcategory 1 well to be producing or near other
producing wells. We therefore anticipate reduced emission completion
(REC) equipment (including separators) to be onsite or nearby, or that
any separator brought onsite or nearby can be put to use.'' 81 FR
35852, June 3, 2016. For the same reason, the EPA is proposing to make
the same amendment to the methane standards for well completions.
Additionally, the 2020 Technical Rule amended 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. As explained in the preamble
to the final 2020 Technical Rule, 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. 85 FR 57403, September 15, 2020. For the
same reason, the EPA is proposing the same clarification apply to the
methane standards for well completions.
The 2020 Technical Rule also amended the definition of flowback. In
2016, the EPA defined ``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 or in preparation
for cleanup and returning the well to production. 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.
81 FR 35934, June 3, 2016.
The 2020 Technical Rule amended this definition by adding a
clarifying statement that ``[s]creenouts, coil tubing cleanouts, and
plug drill-outs are not considered part of the flowback process.'' 40
CFR 60.5430a. In the proposal for the 2020 Technical Rule, 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, October 15, 2018. In
conjunction with this amendment, the 2020 Technical Rule added
definitions for screenouts, coil tubing cleanouts, and plug drill outs.
See 40 CFR 60.5430a. 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. For the
reason stated above, the EPA is proposing to apply the definitions of
flowback, screenouts, coil tubing cleanouts, and plug drill outs that
were finalized in the 2020 Technical Rule to the methane standards for
well completions in the 2016 NSPS OOOOa.
Finally, the 2020 Technical Rule amended specific recordkeeping and
reporting requirements for the VOC standards for well completions, and
the EPA is proposing to apply these amendments to the methane standards
for well completions in the 2016 NSPS OOOOa. For the reasons explained
in 83 FR 52082, the 2020 Technical Rule requires that for each well
site affected facility that routes flowback entirely through one or
more production separators, owners and operators must record and report
only the following data 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.
While the 2020 Technical Rule removed certain reporting
requirements (e.g., information about when a separator is hooked up or
disconnected during flowback) as unnecessary or redundant, 85 FR 57403,
the rule added a requirement that for periods where salable gas is
unable to be separated, owners and operators must 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.
As explained in the preamble to the proposal for the 2020 Technical
Rule, 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. Because these amendments to the recordkeeping
and reporting requirements associated with well completion are
independent of the specific pollutant being regulated, we are proposing
these same amendments to the methane standards for well completions in
the 2016 NSPS OOOOa.
2. Pneumatic Pumps
In the 2020 Technical Rule, the EPA made certain amendments to the
VOC standards for pneumatic pumps in the 2016 NSPS OOOOa. For the same
reasons provided in the 2020 Technical Rule, along with further
explanation provided below, the EPA is proposing to apply the same
amendments to the methane standards for pneumatic pumps in the 2016
NSPS OOOOa.
First, the EPA is proposing to amend the 2016 NSPS OOOOa methane
standards for pneumatic pumps to expand the technical infeasibility
provision to apply to pneumatic pumps at greenfield sites. Under the
2016 NSPS OOOOa, ``emissions from new, modified, and reconstructed
natural gas-driven diaphragm pumps located at well sites [must] be
reduced by 95 percent if either a control device or the ability to
route to a process is already available onsite, unless it is
technically infeasible at sites other than new developments (i.e.,
greenfield sites).'' 81 FR 35824 and 35844. For the 2016 NSPS OOOOa,
the EPA concluded that circumstances that could otherwise make control
of a pneumatic pump technically infeasible
[[Page 63161]]
at an existing location could be addressed in the design and
construction of a greenfield site. 81 FR 35849 and 35850 (June 3,
2016). Concerns raised in petitions for reconsideration on the 2016
NSPS OOOOa explained 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.\177\ These circumstances include, but are not limited to,
site designs requiring high-pressure flares to which routing a low-
pressure pump discharge is not feasible and use of small boilers or
process heaters that are insufficient to control pneumatic pump
emissions or that could result in safety trips and burner flame
instability. The EPA proposed to extend the technical infeasibility
exemption to greenfield sites in 2018 and sought comment on these
circumstances that could preclude control of a pneumatic pump at
greenfield sites. While the EPA received comments both in favor of and
opposing the application of the technical infeasibility exemption to
greenfield sites, the commenters did not identify a reasoned basis for
the EPA to decline to extend the exemption. See Response to Comments
(RTC) for 2020 Technical Rule at 5-1 to 5-4 at Docket ID No. EPA-HQ-
OAR-2017-0483. Moreover, the EPA specifically sought information
regarding the additional costs that would be incurred if owners and
operators of greenfield sites were required to select a control that
can accommodate pneumatic pump emissions in addition to the control's
primary purpose at a new construction site, but no such information was
provided.
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\177\ See proposal for 2020 Technical Rule at 83 FR 52061.
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The 2020 Technical Rule therefore expanded the technical
infeasibility provision to apply to pneumatic pumps at all well sites,
including new developments (greenfield sites), concluding that the
extension was appropriate because the EPA identified circumstances
where it may not be technically feasible to control pneumatic pumps at
a greenfield site. The 2020 Technical Rule removed the reference to
greenfield site in 40 CFR 60.5393a(b) and the associated definition of
greenfield site at 40 CFR 60.5430a.
In the final rule preamble for the 2016 NSPS OOOOa, the EPA stated
we did not intend to require the installation of a control device at a
well site for the sole purpose of controlling emissions from a
pneumatic pump, but rather only required control of pneumatic pumps to
the extent a control device or process would already be available on
site. It is not the EPA's intent to require a greenfield site to
install a control device specifically for controlling emissions from a
pneumatic pump. It is our understanding that sites are designed to
maximize operation and safety. This includes the placement of
equipment, such as control devices. Because vented gas from pneumatic
pumps is at low pressure, it may not be feasible to move collected gas
through a closed vent system to a control device, depending on site
design. Therefore, the EPA continues to conclude that, when determining
technical feasibility at any site, such a determination should consider
the routing of pneumatic pump emissions to the controls which are
needed for the other processes at the site (i.e., not the pneumatic
pump). 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. As explained in the
RTC for the 2020 Technical Rule, ``[t]he EPA believes that the
requirement to certify an engineering assessment to demonstrate
technical infeasibility provides protection against an owner or
operator purposely designing a new site just to avoid routing emissions
from a pneumatic pump to an onsite control device or to a process.''
\178\ For the reasons explained above, the EPA is proposing to align
the methane standards in the 2016 NSPS OOOOa for controlling pneumatic
pump emissions with the amendments made to the VOC standards in the
2020 Technical Rule to allow for a well-justified determination of
technical infeasibility at all well sites, including greenfield sites.
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\178\ See Docket ID No. EPA-HQ-OAR-2017-0483-2291. ``For
example, consider the example provided by one commenter where a new
site design requires only a high-pressure flare to control emergency
and maintenance blowdowns and it is not feasible for a low-pressure
pneumatic pump discharge to be routed to such a flare. The
infeasibility determination would need not only demonstrate that it
is not feasible for a low-pressure pneumatic pump discharge to be
directly routed to the flare, it would also need to demonstrate that
it is infeasible to design and install a low-pressure header to
allow routing this discharge to such a flare system.'' RTC at 5-4.
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Second, the 2020 Technical Rule amended the 2016 NSPS OOOOa to
specify that boilers and process heaters are not considered control
devices for the purposes of the pneumatic pump standards. It is the
EPA's understanding, based on information provided in reconsideration
petitions \179\ submitted regarding the 2016 NSPS OOOOa and comments
received on the proposal for the 2020 Technical Rule, that some boilers
and process heaters located at well sites are not inherently designed
for the control of emissions. While it is true that for some other
sources (not pneumatic pumps), boilers and process heaters may be
designed as control devices, that is generally not the operational
purpose of this equipment at a well site. Instead, it is the EPA's
understanding that boilers and process heaters operate seasonally,
episodically, or otherwise intermittently as process devices, thus
making the use of these devices as controls inefficient and non-
compliant with the continuous control requirements at 40 CFR
60.5415a.\180\ Further, as explained in the 2020 Technical Rule, the
fact that some boilers and process heaters located at well sites are
not inherently designed to control emissions means that ``routing
pneumatic pump emissions to these devices may result in frequent safety
trips and burner flame instability (e.g., high temperature limit
shutdowns and loss of flame signal).'' Id. The EPA determined 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[se] same concerns.'' 85 FR 57404 (September 15, 2020). Further, as
described above, the EPA did not intend to require the installation of
a control device for the sole purpose of controlling emissions from
pneumatic pumps. Based on the EPA's understanding that boilers and
process heaters located at well sites are designed and operated as
process equipment (meaning they are not inherently designed for the
control of emissions), the EPA also does not intend to require their
continuous operation solely to control emissions from pneumatic pumps
either. Therefore, the EPA is proposing to align the methane standards
for pneumatic pumps with the 2020 Technical Rule to specify that
boilers and process heaters are not considered control devices for the
purposes of controlling pneumatic pump emissions. The EPA solicits
comment on this alignment, including whether there are specific
examples where boilers and process heaters are
[[Page 63162]]
currently used as control devices at well sites.
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\179\ See Docket ID No. EPA-HQ-OAR-2017-0483-0016.
\180\ See Docket ID No. EPA-HQ-OAR-2017-0483-0016.
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Third, the EPA is proposing to align the certification requirements
for the determination that it is technically infeasible to route
emissions from a pneumatic pump to a control device or process. The
2016 NSPS OOOOa required certification of technical infeasibility by a
qualified third-party Professional Engineer (PE); however, the 2020
Technical Rule allows 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. The EPA continues to
believe that certification by an in-house engineer is appropriate for
this purpose. We are, therefore, proposing to align the methane
standards in the 2016 NSPS OOOOa with the 2020 Technical 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. We are soliciting comment on this proposed alignment.
3. Closed Vent Systems (CVS)
As in the 2020 Technical Rule, the EPA is proposing to allow
multiple options for demonstrating that there are no detectable methane
emissions from CVS. Additionally, the EPA is proposing 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.
The methane standards in the 2016 NSPS OOOOa require that CVS be
operated with no detectable emissions, as demonstrated through specific
monitoring requirements associated with the specific affected
facilities (i.e., pneumatic pumps, centrifugal compressors,
reciprocating compressors, and storage vessels). Relevant here, the
2016 NSPS OOOOa required this demonstration for both VOC and methane
emissions through annual inspections using EPA Method 21 for CVS
associated with pneumatic pumps, while requiring storage vessels to
conduct monthly audio, visual, olfactory (AVO) monitoring. The 2020
Technical Rule amended the VOC requirements for CVS for pneumatic pumps
to align the requirements for pneumatic pumps and storage vessels by
incorporating provisions allowing the option to demonstrate the
pneumatic pump CVS is operated with no detectable emissions by either
an annual inspection using EPA Method 21, monthly AVO monitoring, or
OGI monitoring at the frequencies specified for fugitive emissions
monitoring. The EPA is proposing to amend the methane standards to
allow pneumatic pump affected facilities to permit these same options
to demonstrate no detectable methane emissions from CVS either using
annual Method 21 monitoring, as currently required by the 2016 NSPS
OOOOa, or using either monthly AVO monitoring or OGI monitoring at the
fugitive monitoring frequency. The EPA considers these detection
options appropriate for CVS associated with pneumatic pumps because any
of the three would detect methane as well as VOC emissions. We
incorporated the option for monthly AVO monitoring in the 2020
Technical Rule because pneumatic pumps and controlled storage vessels
are commonly located at the same site and having separate monitoring
requirements for a potentially shared CVS is overly burdensome and
duplicative. 83 FR 52083 (October 15, 2018). We further incorporated
the option for OGI monitoring because OGI is already being used for
those sites that are subject to fugitive emissions monitoring and the
CVS can readily be monitored during the fugitive emissions survey at no
extra cost. 85 FR 57405. The EPA believes it is appropriate to maintain
these options because not all well sites with controlled pneumatic
pumps will be subject to fugitive emissions monitoring (e.g., pneumatic
pumps located at existing well sites that have not triggered the
fugitive monitoring requirements for new or modified well sites) and
requiring either OGI or EPA Method 21 survey of the CVS for the
pneumatic pump in the absence of fugitive emissions surveys would be
unreasonable. It is possible for a new pneumatic pump to be subject to
control at an existing well site that is not subject to the fugitive
emissions requirements. Requiring either EPA Method 21 or OGI for the
sole purpose of monitoring the CVS associated with the pneumatic pump
would be too costly,\181\ therefore we continue to believe monthly AVO
is an appropriate option for pneumatic pumps subject to the 2016 NSPS
OOOOa.
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\181\ Both OGI and EPA Method 21 have significant capital and
annual costs, including the cost of specialized equipment and
trained operators of that equipment. While the costs of these
programs are justified for well site fugitive emission monitoring
based on the assumption of a high component count from which
emissions would be controlled, the CVS is only one of those many
components. Thus, where well site fugitive monitoring is not
otherwise required, the cost-effectiveness of OGI or EPA Method 21
would be significantly higher for the CVS alone.
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Additionally, the 2020 Technical Rule amended the 2016 NSPS OOOOa
to allow certification of the design and operation of CVS by an in-
house engineer with expertise on the design and operation of the CVS in
lieu of a PE. This certification is necessary to ensure the design and
operation of the CVS will meet the requirement to route all vapors to
the control device or back to the process. As explained in the proposal
for the 2020 Technical Rule, 83 FR 52079, the EPA allows CVS
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. For the same reason, the EPA is proposing to amend
the CVS requirements associated with methane emissions in the
production and processing segments, and methane and VOC emissions in
the transmission and storage segment, to allow certification of the
design and operation of CVS by either a PE or an in-house engineer with
expertise on the design and operation of the CVS.
4. Fugitive Emissions at Well Sites and Compressor Stations
a. Well Sites
The EPA is proposing to exclude from fugitive emissions monitoring
a well site that is or later becomes a ``wellhead only well site,''
which the 2020 Technical Rule defines as ``a well site that contains
one or more wellheads and no major production and processing
equipment.'' The 2016 NSPS OOOOa excludes well sites that contain only
one or more wellheads from the fugitive emissions requirements because
fugitive emissions at such well sites are extremely low. 80 FR 56611.
As explained in that rulemaking, ``[s]ome well sites, especially in
areas with very dry gas or where centralized gathering facilities are
used, consist only of one or more wellheads, or `Christmas trees,' and
have no ancillary equipment such as storage vessels, closed vent
systems, control devices, compressors, separators and pneumatic
controllers. Because the magnitude of fugitive emissions depends on how
many of each type of component (e.g., valves, connectors, and pumps)
are present, fugitive emissions from these well sites are extremely
low.'' 80 FR 56611. The 2020 Technical Rule amended the 2016 NSPS OOOOa
to exclude from fugitive emissions monitoring a well site that is or
later becomes a ``wellhead only well site,'' which the 2020 Technical
Rule defines as ``a well site that contains one or more wellheads and
no major production and processing equipment.'' The 2020 Technical Rule
defined ``major production and processing equipment''
[[Page 63163]]
as including reciprocating or centrifugal compressors, glycol
dehydrators, heater/treaters, separators, and storage vessels
collecting crude oil, condensate, intermediate hydrocarbon liquids, or
produced water. We continue to believe that available information,
including various studies,\182\ supports an exemption for well sites
that do not have this major production and processing equipment. The
2020 Technical Rule allows certain small ancillary equipment, such as
chemical injection pumps, pneumatic controllers used to control well
emergency shutdown valves, and pumpjacks, that are associated with, or
attached to, the wellhead and ``Christmas tree'' to remain at a
``wellhead only well site'' without being subject to the fugitive
emissions monitoring requirements because they have very few fugitive
emissions components that would leak, and therefore have limited
potential for fugitive emissions. The emission reduction benefits of
continuing monitoring at that point would be relatively low, and thus
would not be cost-effective.
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\182\ See https://pubs.acs.org/doi/10.1021/acs.est.0c02927,
https://data.permianmap.org/pages/flaring, and https://www.edf.org/sites/default/files/documents/PermianMapMethodology_1.pdf.
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For the reason stated above, the EPA is proposing to amend the 2016
NSPS OOOOa to allow monitoring of methane fugitive emissions to stop
when a wellsite contains only wellhead(s) and no major production and
processing equipment, as provided in the 2020 Technical Rule.
b. Compressor Stations
As discussed above, the 2016 NSPS OOOOa required quarterly
monitoring of compressor stations for both VOC and methane emissions,
and it also permitted waiver from one quarterly monitoring event when
the average temperature is below 0 [deg]F for two consecutive months
because it is technically infeasible for the OGI camera (and EPA Method
21 instruments) to operate below this temperature. After the 2020
Policy Rule rescinded the methane standards, the 2020 Technical Rule
reduced the monitoring requirements for the VOC standards to require
only semiannual monitoring and, in doing so, removed the waiver. Upon
enactment of the CRA resolution, compressor stations again became
subject to quarterly monitoring pursuant to the reinstated 2016 NSPS
OOOOa methane standards, and the waiver as it applied to the methane
standards was also reinstated. Consistent with our proposal to align
the monitoring requirements for VOCs with the monitoring requirements
for methane, the EPA is also proposing to reinstate the waiver for the
VOC standards as specified in the 2016 NSPS OOOOa.
c. Well Sites and Compressor Stations on the Alaska North Slope
The EPA is proposing to amend the 2016 NSPS OOOOa to require that
new, reconstructed, and modified compressor stations located on the
Alaska North Slope that startup (initially, or after reconstruction or
modification) between September and March to conduct initial monitoring
of methane emissions within 6 months of startup, or by June 30,
whichever is later. The EPA made a similar amendment to the initial
monitoring of methane and VOC emissions at well sites located on the
Alaska North Slope in the March 12, 2018 amendments to the 2016 NSPS
OOOOa (``2018 NSPS OOOOa Rule'').\183\ As explained in that action,
such separate requirements were warranted due to the area's extreme
cold temperatures, which for approximately half of the year are below
the temperatures at which the monitoring instruments are designed to
operate. The 2020 Technical Rule made this amendment for VOC emissions
from gathering and boosting compressor stations located in the Alaska
North Slope for this same reason.
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\183\ 83 FR 10628 (March 12, 2018).
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The EPA is also proposing to amend the 2016 NSPS OOOOa to require
annual monitoring of methane and VOC emissions at all compressor
stations located on the Alaska North Slope, with subsequent annual
monitoring at least 9 months apart but no more than 13 months apart. In
the 2018 NSPS OOOOa Rule, the EPA similarly amended the monitoring
frequency for well sites located on the Alaska North Slope to annual
monitoring to accommodate the extreme cold temperature. 83 FR 10628
(March 12, 2018). For the same reason, in the 2020 Technical Rule, the
EPA amended the 2016 NSPS OOOOa to require annual VOC monitoring at
gathering and boosting compressor stations located on the Alaska North
Slope because extreme cold temperatures make it technically infeasible
to conduct OGI monitoring for over half of a year.\184\ Because the
same difficulties would arise with respect to monitoring for fugitive
methane emissions from gathering and boosting compressor stations or to
monitoring of methane and VOC emissions from compressor stations in the
transmission and storage segment, the EPA is proposing to amend the
2016 NSPS OOOOa to require that all compressor stations located on the
Alaska North Slope conduct annual monitoring of both methane and VOC
emissions.
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\184\ See Docket ID Nos. EPA-HQ-OAR-2010-0505-7682 and EPA-HQ-
OAR-2010-0505-12434. See also FLIR Systems, Inc. product
specifications for GF300/320 model OGI cameras at http://www.flir.com/ogi/display/?id=55671 and Thermo Fisher Scientific
product specification for TVA-2020 at https://assets.thermofisher.com/TFS-Assets/LSG/Specification-Sheets/EPM-TVA2020.pdf.
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Further, the EPA is proposing to extend the deadline for conducting
initial monitoring of both VOC and methane emissions from 60 days to 90
days for all well sites and compressor stations located on the Alaska
North Slope that startup or are modified between April and August. In
the 2020 Technical Rule, the EPA made this amendment for initial VOC
monitoring to allow the well site or gathering and boosting compressor
station to reach normal operating conditions. 85 FR 57406. For the same
reason, we are proposing to further amend the 2016 NSPS OOOOa to apply
this same 90-day initial monitoring requirement to initial monitoring
of fugitive methane and VOC emissions from all well sites and
compressor stations located on the Alaska North Slope that startup or
are modified between April and August.
d. Modification
The 2016 NSPS OOOOa, as originally promulgated, provided that
``[f]or purposes of the fugitive emissions standards at 40 CFR
60.5397a, [a] 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).'' 40 CFR 60.5430a. However, the original
2016 NSPS OOOOa defined ``modification'' only with respect to a well
site and was silent on what constitutes modification to a well site
that is a separate tank battery surface site. Specifically, 40 CFR
60.5365a(i), as promulgated in 2016, specified 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. See 40 CFR
60.5365a(i).
Because this provision was silent on when modification occurs at a
well site that is a separate tank battery surface site, the 2020
Technical Rule added language to clarify 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
[[Page 63164]]
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. Because
the 2020 Technical Rule amended only the VOC standards in the 2016 NSPS
OOOOa, and since this definition of modification equally applies to
fugitive methane emissions from a separate tank battery surface site,
the EPA is proposing to apply this definition of modification for
purposes of determining when modification occurs at a separate tank
battery surface site triggering the methane standards for fugitive
emissions at well sites.
e. Initial Monitoring for Well Sites and Compressor Stations
The 2016 NSPS OOOOa, as originally promulgated, had required
monitoring of methane and VOC fugitive emissions at well sites and
compressor stations to begin within 60 days of startup (of production
in the case of well sites) or modification. The 2020 Technical Rule
extended this time frame to 90 days for well sites and gathering and
boosting compressor stations in response to comments stating that well
sites and compressor stations do not achieve normal operating
conditions within the first 60 days of startup and suggesting that the
EPA allow 90 days to 180 days. The EPA agreed that additional time to
allow the well site or compressor station to reach normal operating
conditions is warranted, considering 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. 85 FR
57406. These same reasons apply regardless of pollutant or the location
of the compressor station; therefore, the EPA is proposing to further
amend the 2016 NSPS OOOOa to extend the deadline for conducting initial
monitoring from 60 to 90 days for monitoring both VOC and methane
fugitive emissions at all well sites and compressor stations (except
those on the Alaska North Slope which are separately regulated as
discussed in section X.B.4.c).
f. Repair Requirements
The 2020 Technical Rule made certain amendments to the 2016 NSPS
OOOOa repair requirements associated with monitoring of fugitive VOC
emissions at well sites and gathering and boosting compressor stations.
For the same reasons provided in the 2020 Technical Rule and reiterated
below, the EPA is proposing to similarly amend the 2016 NSPS OOOOa
repair requirements associated with monitoring of methane emissions at
well sites and gathering and boosting compressor stations and
monitoring of VOC and methane fugitive emissions at compressor stations
in the transmission and storage segment.
Specifically, the EPA is proposing to require a first attempt at
repair within 30 days of identifying fugitive emissions and final
repair, including the resurvey to verify repair, within 30 days of the
first attempt at repair. The 2016 NSPS OOOOa, as originally
promulgated, required repair within 30 days of identifying fugitive
emissions and a resurvey to verify that the repair was successful
within 30 days of the repair. Stakeholders raised questions regarding
whether emissions identified during the resurvey would result in
noncompliance with the repair requirement. In the 2020 Technical Rule,
the EPA clarified that repairs should be verified as successful prior
to the repair deadline and added 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 similarly
proposing to apply these amendments to the repair requirements made in
the 2020 Technical Rule to the repair requirements associated with
monitoring of methane emissions at well sites and gathering and
boosting compressor stations as well as monitoring of VOC and methane
fugitive emissions at compressor stations in the transmission and
storage segment and monitoring.
In addition, the EPA is proposing that delayed repairs 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.''
The proposed amendment would clarify that completion of delayed repairs
is required during scheduled shutdown for maintenance, and not just any
shutdown.
In 2018 NSPS OOOOa Rule the EPA amended the 2016 NSPS OOOOa to
specify 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.'' \185\ During the rulemaking for the 2020
Technical Rule, the EPA 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. Accordingly, in the 2020 Technical Rule the EPA
further amended this provision by adding the term ``for maintenance''
to clarify that repair must be completed during the ``next scheduled
compressor station shutdown for maintenance'' or other specified
scheduled events, or within 2 years, whichever is the earliest. For the
same reason, the EPA is proposing the same clarifying amendment to the
delay of repair requirements for fugitive methane emissions at well
sites and gathering and boosting compressor stations and fugitive VOC
and methane fugitive emissions at compressor stations in the
transmission and storage segment.
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\185\ 83 FR 10638, 40 CFR 60.5397a(h)(2).
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g. Definitions Related to Fugitive Emissions at Well Sites and
Compressor Stations
The 2020 Technical Rule made certain amendments to the definition
of a well site and the definition for startup of production as they
relate to fugitive VOC emissions requirements at well sites. For the
same reasons provided in the 2020 Technical Rule and reiterated below,
the EPA is proposing to similarly amend these definitions as they
relate to the fugitive methane emissions requirements at well sites.
[[Page 63165]]
The 2020 Technical Rule amended the definition of well site, for
purposes of VOC fugitive emissions monitoring, to exclude equipment
owned by third parties and oilfield solid waste and wastewater disposal
wells. 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 2020 Technical 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.'' This exclusion was added for several reasons,
including consideration that owners and operators may not have access
or authority to repair this third-party equipment and because the
custody meter ``is used effectively as the cash register for the well
site and provides a clear separation for the equipment associated with
production of the well site, and the equipment associated with putting
the gas into the gas gathering system.'' 83 FR 52077 (October 15,
2018).
The definition of a well site was also amended in the 2020
Technical Rule to exclude Underground Injection Control (UIC) Class I
oilfield disposal wells and UIC Class II oilfield wastewater disposal
wells. The EPA had proposed to exclude UIC Class II oilfield wastewater
disposal wells because of our understanding that they have negligible
fugitive VOC and methane emissions. 83 FR 52077. Comments received on
the 2020 Technical rulemaking effort further suggested, and the EPA
agreed, that we also should exclude UIC Class I oilfield disposal wells
because of their low VOC and methane emissions. Both types of disposal
wells are permitted through UIC programs under the Safe Drinking Water
Act for protection of underground sources of drinking water. For
consistency, the 2020 Technical Rule adopted the definitions for UIC
Class I oil field disposal wells and UIC Class II oilfield wastewater
disposal wells under the Safe Drinking Water Act definitions in
excluding them from the definition of a well site in the 2016 NSPS
OOOOa. Specifically, the 2020 Technical Rule defined a UIC Class I
oilfield disposal well as ``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 2020 Technical Rule defines a UIC Class II oilfield
wastewater disposal well as ``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.''
As amended, UIC Class I and UIC Class II disposal wells are not
considered well sites for the purposes of VOC fugitive emissions
requirements. Because the 2020 Technical Rule, as finalized, addressed
only VOC emissions in the production and processing segment, the EPA is
proposing the same exclusion and definition of ``well site'' for the
purposes of fugitive emissions monitoring of methane emissions at well
sites.
The EPA is also proposing to apply the definition for ``startup of
production'' for purposes of well site fugitive emissions requirements
for VOC to these requirements as they relate to methane. The 2016 NSPS
OOOOa initially contained a definition for ``startup of production'' as
it relates to the well completion standards that reduce emissions from
hydraulically fractured wells. For that purpose, the term was 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.'' 81 FR 25936
(June 3, 2016). The 2020 Technical Rule amended the definition of
``startup of production'' to separately define the term as it relates
to fugitive VOC emissions requirements at well sites. Specifically, ``.
. .[f]or the purposes of the fugitive monitoring requirements of 40 CFR
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'' 85 FR 57459 (September 15,
2020). This separate definition clarifies that fugitive emissions
monitoring applies to both conventional and unconventional
(hydraulically fractured) wells. For this same reason, the EPA is
proposing to apply this same definition of ``startup of production'' to
fugitive emissions monitoring of methane emissions at well sites.
h. Monitoring Plan
The 2016 NSPS OOOOa, as originally promulgated, required that each
fugitive emissions monitoring plan include a site map and a defined
observation path to ensure that the OGI operator visualizes all of the
components that must be monitored during each survey. The 2020
Technical Rule amended this requirement to allow the company to specify
procedures that would meet this same goal of ensuring every component
is monitored during each survey. While the site map and observation
path are one way to achieve this, other options can also ensure
monitoring, such as an inventory or narrative of the location of each
fugitive emissions component. The EPA stated in the 2020 Technical Rule
that ``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.'' 85 FR 57416
(September 15, 2020). Because the same monitoring device is used to
monitor both methane and VOC emissions, the same company-defined
procedures for ensuring each component is monitored are appropriate.
Therefore, the EPA is proposing to similarly amend the monitoring plan
requirements for methane and for compressor stations to allow company
procedures in lieu of a sitemap and an observation path.
i. Recordkeeping and Reporting
The 2020 Technical Rule amended the 2016 NSPS OOOOa to streamline
the recordkeeping and reporting requirements for the VOC fugitive
emissions standards. The amendments removed the requirement to report
or keep certain records that the EPA determined were redundant or
unnecessary; in some instances, the rule replaced those requirements or
added new requirements that could better demonstrate and ensure
compliance, in particular where the underlying requirement was also
amended (e.g., repair requirements). These amendments reflect
consideration of the public comments received on the proposal for that
rulemaking. The purpose and function of the recordkeeping and reporting
requirements are equally applicable to methane and VOCs, and therefore,
are not pollutant specific. For the same reasons the EPA streamlined
these requirements in the 2020 Technical Rule,\186\ the EPA is
proposing to apply these streamlined recordkeeping and reporting
requirements for methane
[[Page 63166]]
emissions from sources subject to NSPS OOOOa.
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\186\ See 85 FR 57415 (September 15, 2020).
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For each collection of fugitive emissions components located at a
well site or compressor station, the following amendments were made to
the recordkeeping and reporting requirements in the 2020 Technical
Rule:
Revised 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.
Removed the requirement to maintain records of a digital
photo of each monitoring survey performed, captured from the OGI
instrument used for monitoring when leaks are identified during the
survey because the records of the leaks provide proof of the survey
taking place.
Removed 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
once repair is completed and verified with a resurvey.
Required records of the date of first attempt at repair
and date of successful repair.
Revised reporting to specify the type of site (i.e., well
site or compressor station) and when the well site changes status to a
wellhead-only well site.
Removed requirement to report the name or ID of operator
performing the monitoring survey.
Removed requirement to report the number and type of
difficult-to-monitor and unsafe-to-monitor components that are
monitored during each monitoring survey.
Removed requirement to report the ambient temperature, sky
conditions, and maximum wind speed.
Removed requirement to report the date of successful
repair.
Removed requirement to report the type of instrument used
for resurvey.
5. AMEL
The 2020 Technical Rule made the following amendments to the
provisions associated with applications for use of an AMEL for VOC work
practice standards for well completions, reciprocating compressors, and
the collection of fugitive emissions components located at well sites
and gathering and boosting compressor stations. For the same reasons
provided in the 2020 Technical Rule and reiterated below, the EPA is
proposing to similarly amend the 2016 NSPS OOOOa provisions associated
with applications for use of an AMEL for methane work practice
standards at well sites and gathering and boosting compressor stations
and VOC and methane work practice standards at compressor stations in
the transmission and storage segment.
The 2020 Technical Rule amended the AMEL application requirements
to help streamline the process for evaluation and possible approval of
advanced measurement technologies. The amendments included allowing
submission of applications by, among others, owners and operators of
affected facilities, manufacturers or vendors of leak detection
technologies, or trade associations. The 2020 Technical Rule ``allows
any person to submit an application for an AMEL under this provision.''
85 FR 57422 (September 15, 2020). However, the 2020 Technical Rule,
like the 2016 NSPS OOOOa still requires that the application include
sufficient information to demonstrate that the AMEL achieves emission
reductions at least equivalent to the work practice standards in the
rule. To that end, the 2020 Technical 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.'' Id. At a minimum, the application
should include field data that encompass seasonal variations, which 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 AMEL
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.
Since the 2020 Technical Rule changes to the AMEL provisions in the
2016 NSPS OOOOa are procedural in the sense that they mostly speak to
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'' the EPA believes that it is
appropriate to retain those amendments. 85 FR 57422 (September 15,
2020). If finalized, the application must demonstrate equivalence as
explained above for both the reduction of methane and VOC emissions.
Because the 2020 Technical Rule amended only the VOC standards in the
2016 NSPS OOOOa, and since EPA believes that basis for promulgation of
this provision for AMEL applications equally applies to work practices
standards for methane emissions at facilities in the production and
processing segments and VOC and methane emissions at facilities in the
transmission and storage segment, the EPA is proposing to apply these
application requirements for all applicants seeking an AMEL for the
methane and VOC work practice standards in NSPS OOOOa.
6. Alternative Fugitive Emissions Standards Based on Equivalent State
Programs
The 2020 Technical Rule added a new section (at 40 CFR 60.5399a)
which served two purposes. First, the new section outlined procedures
for State, local, and Tribal authorities to seek the EPA's approval of
their VOC fugitive emissions standards at well sites and gathering and
boosting compressor stations as an alternative to the Federal
standards. Second, the new section approved specific voluntary
alternative standards for six States. For the same reasons provided in
the 2020 Technical Rule and reiterated below, the EPA is proposing to
similarly allow this new section to apply to fugitive emissions
standards for methane fugitive emissions at well sites and gathering
and boosting compressor stations, and VOC and methane fugitive
emissions at compressor stations in the transmission and storage
segment.
The 2020 Technical Rule added this new section in part to allow the
use of specific alternative fugitive emissions standards for VOC
emissions for six State fugitive emissions programs that the EPA had
concluded were at least equivalent to the fugitive emissions monitoring
and repair requirements at 40 CFR 60.5397a(e), (f), (g), and (h) as
amended in that rule.\187\ These approved alternative fugitive
emissions standards may be used for certain individual well sites or
gathering and boosting compressor stations that are subject to VOC
fugitive emissions monitoring and repair so long as the source complies
with specified Federal requirements applicable to each approved
alternative State program and included in 40 CFR 60.5399a(f) through
(n). For example, a well site that is subject to the requirements of
Pennsylvania General Permit 5A, section G, effective August 8, 2018,
could choose to comply with those
[[Page 63167]]
standards in lieu of the monitoring, repair, recordkeeping, and
reporting requirements in the NSPS for fugitive emissions at well
sites. However, in that example, the owner or operator 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 (i.e., under
Pennsylvania General Permit 5A, Section G in the example).
Additionally, the facility choosing to use the EPA-approved alternative
standard must submit, as an attachment to its annual report for NSPS
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 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 Federal requirements of the NSPS
at 40 CFR 60.5397a in its entirety.
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\187\ 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.
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In addition to providing the EPA-approved voluntary alternative
fugitive emissions standards for well sites and gathering and boosting
compressor stations located in California, Colorado, Ohio,
Pennsylvania, and Texas, and well sites in Utah, the amendments in the
2020 Technical Rule provide application requirements to request the EPA
approval of an alternative fugitive emissions standards as State,
local, and Tribal programs continue to develop. Applications for the
EPA approval of alternative fugitive emissions standards based on
State, local, or Tribal programs may be submitted by any interested
person, including individuals, corporations, partnerships,
associations, States, or municipalities. Similar to the application
process for AMEL for advanced measurement 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 the Federal NSPS. 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 State 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.
As part of the 2018 proposed rule (83 FR 52056, October 15, 2018)
that resulted in the 2020 Technical Rule, the EPA evaluated the
specific State programs for both methane and VOC emissions at well
sites, gathering and boosting compressor stations, and compressor
stations in the transmission and storage segment as discussed in detail
in a memorandum to that docket evaluating the equivalency of State
fugitive emissions programs.\188\ The EPA is now proposing that all
well sites and compressor stations located in and subject to the
specified State regulations in 40 CFR 60.5399a may utilize these
alternative fugitive emissions standards for both methane and VOC
fugitive emissions. In the 2020 Technical Rule the EPA concluded that
these monitoring, repair, recordkeeping, and reporting requirements
were equivalent to the same types of requirements in the 2016 NSPS
OOOOa for VOC at well sites and gathering and boosting compressor
stations. See 85 FR 57424. The monitoring instrument (i.e., OGI or EPA
Method 21) will detect, at the same time, both methane and VOC
emissions without speciating these emissions. Therefore, detection of
one of these pollutants is also detection of the other pollutant. For
the same reasons provided in the 2020 Technical Rule, and explained in
the associated State equivalency memos, the EPA proposes to find these
same State fugitive emissions standards (as specified in 40 CFR
60.5399a(f) through (n)) equivalent to the specified Federal methane
fugitive emissions standards for well sites and gathering and boosting
stations, and the methane and VOC fugitive emissions standards for
compressor stations in the transmission and storage segment. The EPA is
also proposing to allow State, local, and Tribal agencies to apply for
the EPA approval of their fugitives monitoring program as an
alternative to the Federal NSPS for methane. Put another way, the EPA
is proposing to include methane throughout 40 CFR 60.5399a.
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\188\ See Docket ID Nos. EPA-HQ-OAR-2017-0483-0041 and EPA-HQ-
OAR-2017-0483-2277.
---------------------------------------------------------------------------
The EPA recognizes that the determinations of equivalence included
in the 2020 Technical Rule were based on the fugitive emissions
monitoring requirements that existed at that time for the 2016 NSPS
OOOOa which, based on other changes in the 2020 Technical Rule,
included an exemption from monitoring for low production well sites and
required semiannual monitoring at gathering and boosting compressor
stations. As explained above, the EPA is proposing to repeal both of
those changes, and require semiannual monitoring at all well sites,
including those with low production, and quarterly monitoring at
gathering and boosting compressor stations. These proposed changes to
the 2016 NSPS OOOOa fugitive emissions requirements do not impact the
EPA's conclusion that the six previously approved alternative State
programs are equivalent to the Federal standards. Even so, the EPA is
proposing regulatory changes within the alternative State program
provisions in 2016 NSPS OOOOa to account for these proposed changes to
the Federal standards. See the redline version of regulatory text in
the docket at Docket ID No. EPA-HQ-OAR-2021-0317. These changes are
intended to ensure that the previously approved alternative State
programs continue to maintain equivalency with the Federal standards if
NSPS OOOOa is revised as proposed here. With these changes, the EPA
continues to find that the alternative State programs that were
previously approved are still equivalent with, if not better than, the
Federal requirements.
7. Onshore Natural Gas Processing Plants
a. Capital Expenditure
The 2020 Technical Rule made certain amendments to the 2016 NSPS
OOOOa definition of capital expenditure as it relates to modifications
for VOC LDAR requirements at onshore natural gas processing plants. For
the same reasons provided in the 2020 Technical Rule and reiterated
below, the EPA is proposing to similarly amend this definition as it
relates to the methane LDAR requirements at onshore natural gas
processing plants.
The 2020 Technical Rule amended the definition of ``capital
expenditure'' at 40 CFR 50.5430a by replacing the equation used to
determine the percent of replacement cost, ``Y.'' This amendment was
necessary because, as originally promulgated, the equation for
determining ``Y'' would result in an error, thus, making it difficult
to determine whether a capital expenditure had occurred using the NSPS
OOOOa equation. The 2020 Technical Rule replaced the equation with an
equation that utilizes the consumer price indices, ``CPI'' because it
more appropriately reflects inflation than the original equation.
Specifically, the equation for ``Y'' as amended in the
[[Page 63168]]
2020 Technical Rule, 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 2020 Technical Rule specifies that the ``annual average of
the CPI 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
clarified that the comparison of costs is between the original date of
construction of the process unit (the affected facility) and the date
of the project which adds equipment to the process unit. For these same
reasons, the EPA is proposing that the definition of ``capital
expenditure,'' as amended by the 2020 Technical Rule, also be used to
determine whether modification had occurred and thus triggers the
applicability of the methane LDAR requirements at onshore natural gas
processing plants in the 2016 NSPS OOOOa.
b. Initial Compliance Period
The 2020 Technical Rule amended the VOC standards for onshore
natural gas processing plants to specify that the initial compliance
deadline for the equipment leak standards is 180 days. The EPA is
proposing to apply this clarification to the initial compliance
deadline with the methane standards for equipment leaks at onshore
natural gas processing plants.
As explained in the 2020 Technical Rule, the EPA added a provision
requiring compliance ``as soon as practicable, but no later than 180
days after initial startup'' because that provision was in the NSPS for
equipment leaks of VOC at onshore natural gas processing plants when it
was first promulgated, specifically at 40 CFR 60.632(a) of part 60,
subpart KKK (NSPS KKK). 85 FR 57408. This provision at 40 CFR 60.632(a)
provides up to 180 days to come into compliance with NSPS KKK. In 2012,
the EPA revised the standards in NSPS KKK with the promulgation of NSPS
OOOO \189\ by lowering the leak definition for valves from 10,000 ppm
to 500 ppm and requiring the monitoring of connectors. 77 FR 49490,
49498. While the EPA did not mention that it was also amending the 180-
day compliance deadline in NSPS OOOO, this provision at 40 CFR
60.632(a) was not included in NSPS OOOO and, in turn, was not included
in NSPS OOOOa. During the rulemaking for NSPS OOOOa, the EPA declined a
request to include this provision at 40 CFR 60.632(a) in NSPS OOOOa,
explaining that such inclusion was not necessary because NSPS OOOOa
already includes by reference a similar provision (i.e., 40 CFR 60.482-
1a(a)) which requires each owner or operator to ``demonstrate
compliance . . . within 180 days of initial startup,'' 80 FR 56593,
56647-8. However, in reassessing the issue during the rulemaking for
the 2020 Technical Rule, the EPA noted that NSPS KKK includes both the
provision in 40 CFR 60.632(a) and 40 CFR 60.482-1(a), which contains a
provision that is the same as the one described above at 40 CFR 60.482-
1a(a), thus suggesting that 40 CFR 60.632(a) is not redundant or
unnecessary. In fact, the absence of this provision in NSPS OOOO/OOOOa
raised a question as to whether compliance is required within 30 days
for equipment that is required to be monitored monthly. To clarify this
confusion and remain consistent with NSPS KKK, the 2020 Technical Rule
amended NSPS OOOOa to reinstate this provision at 40 CFR 60.632(a). For
the same reasons explained above, the EPA is proposing to similarly
apply this provision to compliance with methane standards for the
equipment leaks at onshore natural gas processing plants.
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\189\ ``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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This provision clarifies that monitoring must 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 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).
8. Technical Corrections and Clarifications
The 2020 Technical Rule also revised the 2016 NSPS OOOOa for VOC
emissions to include certain additional technical corrections and
clarifications. In this action, the EPA is proposing to apply these
same technical corrections and clarifications to the methane standards
for production and processing segments and/or the methane and VOC
standards for the transmission and storage segment in the 2016 NSPS
OOOOa, as appropriate. Specifically, the EPA is proposing to:
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 (PRDs) 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, whether the monitoring is routine or
nonroutine.
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 OOOOa do not contain standards for
pneumatic pumps at gathering and boosting compressor stations. 81 FR
35850.
Revise 40 CFR 60.5411a(a)(1) to remove the reference to
paragraphs (a) and (c) of 40 CFR 60.5412a 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
[[Page 63169]]
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 OOOOa rulemaking, the EPA stated in a
response to comment that this phrase is being removed,\190\ but did not
do so in that rulemaking.
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\190\ 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 of 40 CFR part 60, subpart OOOOa, to
correctly indicate that the performance tests in 40 CFR 60.8 do not
apply to pneumatic pump affected facilities.
Revise Table 3 of 40 CFR part 60, subpart OOOOa, 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), and 60.5420a(b)
introductory text and (b)(13), and introductory text in 40 CFR 60.5411a
and 60.5416a, to remove language associated with the administrative
stay we issued under section 307(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'' (82 FR
25730, June 5, 2017). The administrative stay was vacated by the D.C.
Circuit on July 3, 2017.
XI. Summary of Proposed NSPS OOOOb and EG OOOOc
This section presents a summary of the specific NSPS standards and
EG presumptive standards the EPA is proposing for various types of
equipment and emission points. More details of the rationale for these
standards and requirements, including alternative compliance options
and exemptions to the standards, are provided in section XII of this
preamble and the TSD for this action in the public docket. As stated in
section I, the EPA intends to provide draft regulatory text for the
proposed NSPS OOOOb and EG OOOOc in a supplemental proposal.
A. Fugitive Emissions From Well Sites and Compressor Stations
Fugitive emissions are unintended emissions that can occur from a
range of equipment at any time. The magnitude of these emissions can
also vary widely. The EPA has historically targeted fugitive emissions
from the Crude Oil and Natural Gas source category through ground-based
component level monitoring using OGI, or alternatively, EPA Method 21.
The EPA is proposing the following monitoring requirements and
presumptive standards for the collection of fugitive emissions
components located at well sites and compressor stations. Additional
details for the proposed standards and proposed presumptive standards
are included in the following subsections. Information received through
the various solicitations in this section may be used to evaluate if a
change in the BSER is appropriate from the proposed requirements below,
specifically consideration of alternative measurement technologies as
the BSER. Any potential changes would be addressed through a
supplemental proposal.
Well sites with total site-level baseline methane
emissions less than 3 tpy: Demonstration, based on a site-specific
survey, that actual emissions are reflected in the baseline methane
emissions calculation,
Well sites with total site-level baseline methane
emissions of 3 tpy or greater: Quarterly OGI or EPA Method 21
monitoring,
(Co-proposal) Well sites with total site-level baseline
methane emissions of 3 tpy or greater and less than 8 tpy: Semiannual
OGI or EPA Method 21 monitoring,
(Co-proposal) Well sites with total site-level baseline
methane emissions of 8 tpy or greater: Quarterly OGI or EPA Method 21
monitoring,
Compressor stations: Quarterly OGI or EPA Method 21
monitoring,
Well sites and compressor stations located on the Alaska
North Slope: Annual monitoring, with separate initial monitoring
requirements, and
Alternative screening approach for all well sites and
compressor stations: Bimonthly screening surveys using advanced
measurement technology and annual OGI or EPA Method 21 monitoring at
each individual well site or compressor station.
1. Definition of Fugitive Emissions Component
A key factor in evaluating how to target fugitive emissions is
clearly identifying the emissions of concern and the sources of those
emissions. In the 2016 NSPS OOOOa, the EPA defined ``fugitive emissions
component'' as ``any component with the potential to emit methane and
VOCs'' and included several specific component types, ranging from
valves and connectors, to openings on controlled storage vessels that
were not regulated under NSPS OOOOa.
However, data shows that the universe of components with potential
for fugitive emissions is broader than the illustrative list included
in the 2016 NSPS OOOOa, and that the majority of the largest emissions
events occur from a subset of components that may not have been clearly
included in the definition. Therefore, the EPA is proposing a new
definition for ``fugitive emissions component'' to provide clarity that
these sources of large emission events are covered.
[[Page 63170]]
``Fugitive emissions component'' is proposed to be any component
that has the potential to emit fugitive emissions of methane and VOC at
a well site or compressor station, including valves, connectors, PRDs,
open-ended lines, flanges, all covers and closed vent systems, all
thief hatches or other openings on a controlled storage vessel,
compressors, instruments, meters, natural gas-driven pneumatic
controllers or natural gas-driven pumps. However, natural gas
discharged from natural gas-driven pneumatic controllers or natural
gas-driven pumps are not considered fugitive emissions if the device is
operating properly and in accordance with manufacturers specifications.
Control devices, including flares, with emissions resulting from the
device operating in a manner that is not in full compliance with any
Federal rule, State rule, or permit, are also considered fugitive
emissions components. This proposed definition includes the same
components that were included in the 2016 NSPS OOOOa and adds sources
of large emissions, such as malfunctioning controllers or control
devices.
The inclusion of specific component types in this proposed
definition would allow the use of OGI, EPA Method 21, or an alternative
screening technology to identify emissions that would either be
repaired (i.e., leaks) or have a root cause analysis with corrective
action (e.g., malfunctioning control device, unintentional gas carry
through, venting from covers and openings on a controlled storage
vessel, or malfunctioning natural gas-driven pneumatic controllers).
Further, we are proposing that where a CVS is used to route emissions
from an affected facility (i.e., centrifugal or reciprocating
compressor, pneumatic pump, or storage vessel), the owner or operator
would demonstrate there are no detectable emissions from the covers and
CVS through the OGI (or EPA Method 21) monitoring conducted during the
fugitive emissions survey. Where emissions are detected, corrective
actions to complete all necessary repairs as soon as practicable would
be required, and the emissions would be considered a potential
violation of the no detectable emissions standard. In the case of a
malfunction or operational upset of a control device or the equipment
itself, where emissions are not expected to occur if the equipment is
operating in compliance with the standards of the rule, this proposal
would require the owner or operator to conduct a root cause analysis to
determine why the emissions are present, take corrective action to
complete all necessary repairs as soon as practicable and prevent
reoccurrence of emissions, and report the malfunction or operational
upset as a potential violation of the underlying standards for the
source of the emissions. We are soliciting comment on whether to
include the option to continue utilizing monthly AVO surveys as
demonstrations of no detectable emissions from a CVS but are not
proposing that option specifically. Because the EPA is proposing both
NSPS and EG in this action, we anticipate that CVS associated with
controlled pneumatic pumps will be located at well sites subject to
fugitive emissions monitoring. Therefore, we do not believe the monthly
AVO option is necessary. However, we are soliciting comment on whether
there are circumstances where a CVS associated with a controlled
pneumatic pump is located at a well site not otherwise subject to
fugitive emissions monitoring and where OGI (or EPA Method 21) would be
an additional burden.
The EPA is soliciting comment on this proposed definition of
``fugitive emissions component,'' including any additional components
or characterization of components that should be included. Further, we
are soliciting comment on the use of the fugitive emissions survey to
identify malfunctions and other large emission sources where the
equipment is not operating in compliance with the underlying standards,
including the proposed requirement to perform a root cause analysis and
to take corrective action to mitigate and prevent future malfunctions.
2. Fugitive Emissions From Well Sites
The current NSPS for reducing fugitive VOC and methane emissions at
well sites requires semiannual monitoring, except that a low production
well site (one that produces at or below 15 barrels of oil equivalent
(boe) per day) is exempt from VOC monitoring. As explained in section
X.A.1, we are proposing to remove that exemption from NSPS OOOOa, as we
have concluded that exemption was not justified by the underlying
record and does not represent BSER. Further, based on our revised BSER
analysis, which is summarized in section XII.A.1.a, the EPA is
proposing updated standards for reducing fugitive VOC and methane
emissions from the collection of fugitive emissions components located
at new, modified, or reconstructed well sites (under the newly proposed
NSPS OOOOb). Also, for the reasons discussed in section XII.A.2, the
EPA is proposing to determine that the BSER analysis supports a
presumptive standard for reducing methane emissions from the collection
of fugitive emissions components located at existing well sites (under
the newly proposed EG OOOOc) that is the same as what we are proposing
for the NSPS (for NSPS OOOOb). Provided below is a summary of the
proposed updated NSPS and the proposed EG.
a. NSPS OOOOb
For new, modified, or reconstructed sources, we are proposing a
fugitive emissions monitoring and repair program that includes
monitoring for fugitive emissions with OGI in accordance with the
proposed 40 CFR part 60, appendix K (``appendix K''), which is included
in this action and outlines the proposed procedures that must be
followed to identify emissions using OGI.\191\ We are also proposing
that EPA Method 21 may be used as an alternative to OGI monitoring. We
are further proposing that monitoring must begin within 90 days of
startup of production (or startup of production after modification).
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\191\ ``Determination of Volatile Organic Compound and
Greenhouse Gas Leaks Using Optical Gas Imaging'' located at Docket
ID No. EPA-HQ-OAR-2021-0317.
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Unlike in NSPS OOOOa which, as amended by the 2020 Technical Rule,
set VOC monitoring frequency based on production level, the EPA is
proposing that the OGI monitoring frequency be based on the site-level
methane baseline emissions,\192\ as determined, in part, through
equipment/component count emission factors. The EPA is proposing the
calculation of the total site-wide methane emissions, including
fugitive emissions from components, emissions from natural gas-driven
pneumatic controllers, natural gas-driven pneumatic pumps, storage
vessels, as well as other regulated and non-regulated emission sources.
Specifically, we are proposing that owners or operators would calculate
the site-level baseline methane emissions using a combination of
population-based emission factors and storage vessel emissions.
Further, the EPA proposes this calculation would be repeated every time
equipment is added to or removed from the site. For each natural gas-
driven pneumatic pump, continuous bleed natural gas-driven pneumatic
[[Page 63171]]
controller, and intermittent bleed natural gas-driven pneumatic
controller located at the well site, the owner or operator would apply
the population emission factors for all components found in Table W-1A
of GHGRP subpart W. For each piece of major production and processing
equipment and each wellhead located at the well site, the owner or
operator would first apply the default average component counts for
major equipment found in Table W-1B and Table W-1C of GHGRP subpart W,
and then apply the component-type emission factors for the population
of valves, connectors, open-ended lines, and PRVs found in Table 2-8 of
the 1995 Emissions Protocol.\193\ Finally, the owner or operator would
use the calculated potential methane emissions after applying control
(if applicable) for each storage vessel tank battery located at the
well site. The sum of the emissions estimated for all equipment at the
site would be used as the baseline methane emissions for determining
the applicable monitoring frequency. The EPA proposes to use the
default population emission factors found in Table W-1A of GHGRP
subpart W and the default average component counts for major equipment
found in Tables W-1B and W-1C of GHGRP subpart W because they are well-
vetted emission and activity factors used by the Agency. The EPA is not
incorporating these emission factors directly into the proposed NSPS
OOOOb or EG OOOOc because they could be the subject of future GHGRP
subpart W revisions, and if revised, those revisions would be relevant
to this calculation. For the individual components (e.g., valves and
connectors), the EPA proposes to rely on the component-type emission
factors found in Table 2-8 of the 1995 Emissions Protocol for purposes
of quantifying emissions from major production and processing equipment
and each wellhead located at the well site because these data have been
relied upon in previous rulemakings for this sector, have been the
subject of extensive public comment, and the EPA has determined that
they are appropriate to use for purposes of this action.
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\192\ As shown in the TSD, the EPA analyzed the monitoring
frequency for both methane and VOC under both the single pollutant
approach and the multipollutant approach. Because the composition of
gas at a well site is predominantly methane (approximately 70
percent), a methane threshold represents the lowest threshold that
is cost effective to control both VOC and methane emissions.
\193\ EPA, Protocol for Equipment Leak Emission Estimates, EPA-
453/R-95-017, November 1995.
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The EPA requests comment on whether the proposed methodologies for
calculating site-level baseline methane emissions are appropriate for
these emission sources, and if not, what methodologies would be more
appropriate. Specifically, the EPA recognizes the proposed calculation
methodology assumes all equipment is operating as designed (e.g.,
controlled storage vessels with all vapors routed to a control that is
actually achieving 95 percent reduction or greater). Therefore, we are
soliciting comment on whether sites should use the uncontrolled PTE
calculation for their storage vessels in their site-level baseline
estimate to account for times when these vessels are not operating as
designed, which is a known cause of large emission events of concern.
Further, to that point, the EPA is soliciting comment on how to develop
a factor that could be applied to the site-level baseline calculation
that would account for large emission events, or any specific data that
would provide a factor for these events. As we state throughout this
preamble, large emission events are of specific concern and fugitive
emissions monitoring is an effective tool for detecting these
emissions, therefore, we acknowledge there is considerable interest
from various stakeholders that these emission events are accounted for
in our analyses. At this time, the EPA does not have enough information
to develop a factor or determine how to best apply that factor.
Information provided through this solicitation would allow us to
consider additional revisions to this calculation methodology through a
supplemental proposal.
The EPA is also soliciting comment on whether providing direct
major equipment population emission factors that can be combined with
site-specific gas compositions would provide a more transparent and
less burdensome means to develop the site-specific emissions estimates
than using a combination of major equipment counts, specific component
counts per major equipment, and component-level population emission
factors. Furthermore, the EPA requests comment on whether site-level
baseline methane emissions should be determined using a baseline
emissions survey instead of the proposed methodology, and if so, what
methodologies should be used to quantify emissions from the survey such
as measurement or emission factors based on leaking component emission
factors. The EPA also solicits comment on specific methodologies to
support commenters' positions. The EPA also requests comment on whether
there are additional production and processing equipment or emission
sources that should be included in the site-level baseline methane
emissions. For example, the EPA is aware that there could be emission
sources such as engines, dehydrator venting, compressor venting,
associated gas venting, and migration of gas outside of the wellbore at
a well site. If such equipment or emission sources should be included
in the site-level baseline, the EPA requests comment on methodologies
for quantifying emissions for purposes of the baseline.
Based on the analysis described in section XII.A.1, the potential
for fugitive emissions is impacted more by the number and type of
equipment at the site, and not by the volume of production. Therefore,
the EPA believes it is more appropriate to use site-specific emissions
estimates based on the number and type of equipment located at the
individual site to determine the monitoring frequency. Table 13
summarizes the proposed site-level baseline methane thresholds for the
proposed monitoring frequencies, which according to our analysis would
achieve the greatest cost-effective emission reductions.
As noted below, the EPA solicits comment on all aspects of the
proposed tiered approach to monitoring that is summarized in Table 13.
Although we are proposing no routine OGI monitoring where site-level
baseline methane emissions are below 3 tpy, the EPA is proposing to
require these sites to demonstrate the actual emissions are accounted
for in the calculation. This demonstration would include a survey, such
as OGI, EPA Method 21 (including provisions for the use of a soap
solution), or advanced measurement technologies. Given that this
demonstration is designed to show actual emissions are below 3 tpy, and
most survey techniques are not quantitative, the EPA anticipates that
sources finding emissions will make repairs on equipment/components
identified as leaking during the demonstration survey.
The EPA acknowledges that the 2016 NSPS OOOOa and this proposal
allow the use of EPA Method 21 as an alternative to OGI monitoring to
detect fugitive emissions from the collection of fugitive emissions
components under the proposed tiered approach to monitoring. However,
as discussed in section XI.A.5, EPA Method 21 is not proposed as an
alternative for follow-up OGI surveys under the proposed alternative
screening approach using advanced measurement technologies when
screening detects emissions. This is because EPA Method 21 is not able
to find all sources of leaks and is therefore not an appropriate method
for detection in these cases where large emissions events have been
identified. Given this limitation, the EPA is soliciting comment on
whether EPA Method 21 remains an appropriate
[[Page 63172]]
alternative to OGI for routine OGI surveys.
Table 13--Proposed Well Site Monitoring Frequencies Based on Site-Level
Baseline Methane Emissions
------------------------------------------------------------------------
Site-level baseline methane Proposed OGI Co-proposed OGI
emissions threshold monitoring frequency monitoring frequency
------------------------------------------------------------------------
>0 and <3 tpy............... No routine No routine
monitoring required. monitoring
required.
>=3 and <8 tpy.............. Quarterly........... Semiannual.
>=8 tpy..................... Quarterly........... Quarterly.
------------------------------------------------------------------------
Where quarterly monitoring is proposed, subsequent quarterly
monitoring would occur at least 60 days apart. Where semiannual
monitoring is co-proposed, subsequent semiannual monitoring would occur
at least 4 months apart and no more than 7 months apart. We are
proposing to retain the provision in the 2016 NSPS OOOOa that the
quarterly monitoring may be waived when temperatures are below 0 [deg]F
for two of three consecutive calendar months of a quarterly monitoring
period.
The EPA has previously required the use of OGI technology to detect
fugitive emissions of methane and VOC from the oil and gas sector
(i.e., well sites and compressor stations). However, the EPA had not
developed a protocol for its use even though the EPA has previously
mentioned the need for an OGI protocol during other rulemakings where
OGI has been proposed for leak detection.\194\ In this document, the
EPA is proposing a draft protocol for the use of OGI as appendix K to
40 CFR part 60. The EPA notes that while this protocol is being
proposed for use in the oil and gas sector, the applicability of the
protocol is broader. The protocol is applicable to surveys of process
equipment using OGI cameras in the entire oil and gas upstream and
downstream sectors from production to refining to distribution where a
subpart in those sectors references its use.
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\194\ The development of appendix K to 40 CFR part 60 was
previously mentioned in both the proposal for the National Uniform
Emission Standards for Storage Vessel and Transfer Operations,
Equipment Leaks, and Closed Vent Systems and Control Devices; and
Revisions to the National Uniform Emission Standards General
Provisions (77 FR 17897, March 26, 2012) and the Petroleum Refinery
Sector Risk and Technology Review and New Source Performance
Standards (79 FR 36880, June 30, 2014).
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As part of the development of appendix K, the EPA conducted an
extensive literature review on the technology development as well as
observations on current application of OGI technology. Approximately
150 references identify the technology, applications, and limitations
of OGI. The EPA also commissioned multiple laboratory studies and OGI
technology evaluations. Additionally, on November 9 and 10, 2020, the
EPA held a virtual stakeholder workshop to gather input on development
of a protocol for the use of OGI. The information obtained from these
efforts was used to develop the TSD for appendix K, which provides
technical analyses, experimental results, and other supplemental
information used to evaluate and develop standardized procedures for
the use of OGI technology in monitoring for fugitive emissions of VOCs,
HAP, and methane from industrial environments.\195\
---------------------------------------------------------------------------
\195\ Technical Support Document--Optical Gas Imaging Protocol
(40 CFR part 60, Appendix K), available in the docket for this
action.
---------------------------------------------------------------------------
Appendix K outlines the proposed procedures that instrument
operators must follow to identify leaks or fugitive emissions using a
hand-held, field portable infrared camera. Additionally, appendix K
contains proposed specifications relating to the required performance
of qualifying infrared cameras, required operator training and
verification, determination of an operating window for performing
surveys, and requirements for a monitoring plan and recordkeeping. The
EPA is requesting comment on all aspects of the draft OGI protocol
being proposed as appendix K to 40 CFR part 60.\196\
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\196\ See appendix K in Docket ID No. EPA-HQ-OAR-2021-0317.
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As mentioned in section X.B.4.f, we are proposing that, once
fugitive methane emissions are detected during the OGI survey, a first
attempt at repair must be made within 30 days of detecting the fugitive
emissions, with final repair, including resurvey to verify repair,
completed within 30 days after the first attempt. These proposed repair
requirements with respect to methane fugitive emissions are the same as
those made in the 2020 Technical Rule for VOC fugitive emissions (and
proposed in section X.B.4.f for methane in this action). Because large
emission events contribute disproportionately to emissions, the EPA is
soliciting comment on how to structure a requirement that would tier
repair deadlines based on the severity of the fugitive emissions
identified during the OGI (or EPA Method 21) surveys. In order for such
a structure to work, there would need to be a way to qualify which
fugitive emissions are smaller and which are larger, as the initial
monitoring with OGI will not provide this information. One approach
could be to define broad categories of leaks and make assumptions about
the magnitude of emissions for those broad categories. For example, an
open thief hatch would be considered a very large leak due to the
surface opening size, and it would need to be remedied on the tightest
timeframe, whereas a leaking connector would be considered a small leak
based on historical emissions factors and could be repaired on a more
lenient timeframe. The EPA is soliciting comments on how this approach
could be structured, particularly the types of leaks that would fall
into each broad category and the appropriate repair timeframes for each
of the categories. The EPA is also soliciting comment on other
approaches that could also be implemented for repairing fugitive
emissions in a tiered structure. Finally, we are proposing to retain
the requirement for owners and operators to develop a fugitive
emissions monitoring plan that covers all the applicable requirements
for the collection of fugitive emissions components located at a well
site and includes the elements specified in the proposed appendix K
when using OGI.
The affected facilities include well sites with major production
and processing equipment, and centralized tank batteries. As in the
2020 Technical Rule, the EPA is proposing to not include ``wellhead
only well sites,'' as affected facilities when the well site is a
wellhead only well site at the date it becomes subject to the rule.
Based on the proposed site-level baseline methane emissions calculation
methodology, wellhead only sites would only calculate emissions from
fugitive components (e.g., valves, connectors, flanges, and open-ended
lines) that are located on the wellhead. We believe
[[Page 63173]]
these sites would not exceed the 3 tpy threshold to require routine
monitoring. However, unlike the 2020 Technical Rule, the EPA is
proposing that when a well site later removes all major production and
processing equipment such that it becomes a wellhead only well site, it
must recalculate the emissions in order to determine if a different
frequency is then required. In this proposal, the definitions for
``wellhead only well site'' and ``well site'' would be the same as
those finalized in the 2020 Technical Rule. Specifically, ``wellhead
only well site'' means ``for purposes of the fugitive emissions
standards, a well site that contains one or more wellheads and no major
production and processing equipment.'' The term ``major production and
processing equipment'' refers to ``reciprocating or centrifugal
compressors, glycol dehydrators, heater/treaters, separators, and
storage vessels collecting crude oil, condensate, intermediate
hydrocarbon liquids, or produced water.'' The EPA is soliciting comment
on whether any other equipment not included in this definition should
be added in order to clearly specify what well sites are considered
wellhead only sites. Specifically, the EPA is soliciting comment on the
inclusion of natural gas-driven pneumatic controllers, natural gas-
driven pneumatic pumps, and pumpjack engines in the definition of
``major production and processing equipment.'' A ``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, a well site
includes a centralized production facility. Also, for purposes of the
fugitive emissions standards, 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.
In addition to retaining the above definitions, the EPA is also
proposing a new definition for ``centralized production facility'' for
purposes of fugitive emissions requirements for well sites, where a
``centralized tank battery'' is one or more permanent storage tanks and
all equipment at a single stationary source used to gather, for the
purpose of sale or processing to sell, crude oil, condensate, produced
water, or intermediate hydrocarbon liquid from one or more offsite
natural gas or oil production wells. This equipment includes, but is
not limited to, equipment used for storage, separation, treating,
dehydration, artificial lift, combustion, compression, pumping,
metering, monitoring, and flowline. Process vessels and process tanks
are not considered storage vessels or storage tanks. A centralized
production facility is located upstream of the natural gas processing
plant or the crude oil pipeline breakout station and is a part of
producing operations. Additional discussion on centralized production
facilities is included in section XI.L.
The EPA is not proposing any change to the current definition of
modification as it relates to fugitive emissions requirements at well
sites or centralized production facilities. Specifically, modification
occurs at a well site when: (1) A new well is drilled at an existing
well site; (2) a well at an existing well site is hydraulically
fractured; or (3) a well at an existing well site is hydraulically
refractured. Similarly, modification occurs at a centralized production
facility when (1) any of the actions above occur at an existing
centralized production facility; (2) a well sending production to an
existing centralized production facility is modified as defined above
for well sites; or (3) a well site subject to the fugitive emissions
standards for new sources removes all major production and processing
equipment such that it becomes a wellhead only well site and sends
production to an existing centralized production facility.
b. EG OOOOc
For existing well sites (for EG OOOOc), we are proposing a
presumptive standard that follows the same fugitive monitoring and
repair program as for new sources. For the reasons discussed in section
XII.A.2, the BSER analysis for existing sources supports proposing a
presumptive standard for reducing methane emissions from the collection
of fugitive emissions components located at existing well sites that is
the same as what the EPA is proposing for new, reconstructed, or
modified sources (for NSPS OOOOb). The EPA did not identify any factors
specific to existing sources that would alter the analysis performed
for new sources to make that analysis different for existing well
sites. The EPA determined that the OGI technology, methane emission
reductions, costs, and cost effectiveness discussed above for the
collection of fugitive emissions components at new well sites are also
applicable for the collection of fugitive emissions components at
existing well sites. Further, the fugitive emissions requirements do
not require the installation of controls on existing equipment or the
retrofit of equipment, which can generally be an additional factor for
consideration when determining the BSER for existing sources.
Therefore, the EPA found is appropriate to use the analysis developed
for the proposed NSPS OOOOb to also develop the BSER and proposed
presumptive standards for the EG OOOOc.
Based on the information available at this time, the EPA thinks the
large number of existing well sites, many of which are not complex
warrants soliciting comment on whether existing well sites (or a
subcategory thereof) could have different emission profiles due to
certain site characteristics or other factors that would suggest a
different presumptive standard is appropriate. Further, we remain
concerned about the burden of fugitive emissions monitoring
requirements on small businesses. Therefore, we are requesting comment
on regulatory alternatives for well sites that accomplish the stated
objectives of the CAA and which minimize any significant economic
impact of the proposed rule on small entities, including any
information or data that pertain to the emissions impacts and costs of
our proposal to remove the exemption from fugitive monitoring for well
sites with low emissions, or would support alternative fugitive
monitoring requirements for these sites. We are soliciting data that
assess the emissions from low production well sites, and information on
any factors that could make certain well sites less likely to emit VOC
and methane, including geologic features, equipment onsite, production
levels, and any other factors that could establish the basis for
appropriate regulatory alternatives for these sites. Further, the EPA
is aware there are a subset of existing well sites that are owned by
individual homeowners, farmers, or companies with very few employees
(well below the threshold defining a small business). For these owners,
the EPA is concerned our analysis underestimates the actual burden
imposed by these proposed standards. As an example, ownership may be
limited to 1 or 2 wells located on an individual's property, for which
the production is used for heating the home. The cost burden of
conducting fugitive emissions surveys in this type of scenario has not
fully be analyzed. Therefore, the EPA solicits comment and information
that would allow us to
[[Page 63174]]
further evaluate the burden on the smallest companies to further
propose appropriate standards at this subset (or other similar subsets)
of well sites through a supplemental proposal.
Finally, we are soliciting comment on all aspects of the proposed
fugitive emissions requirements for both new and existing well sites,
including whether we should use the tiering approach, whether the tiers
we have defined are appropriate, and the monitoring requirements for
each tier, including whether it would be cost-effective to monitor at
more frequent intervals than proposed. The EPA may include revisions to
this proposal for ground-based OGI monitoring at well sites if
information is received that would warrant consideration of a different
approach to establishing monitoring frequencies at well sites.
3. Fugitive Emissions from Compressor Stations
The current NSPS for reducing fugitive emissions from the
collection of fugitive emissions components located at a compressor
station is a fugitive emissions monitoring and repair program requiring
quarterly OGI monitoring.\197\ Based on our analysis, which is
summarized in section XII.A.1.b, the EPA is proposing quarterly OGI
monitoring requirement for both methane and VOC as it continues to
reflect the BSER for reducing both emissions from fugitive components
at new, modified, and reconstructed compressor stations. Likewise, the
EPA is also proposing quarterly monitoring as a presumptive GHG
standard (in the form of limitation on methane emissions) for the
collection of fugitive emissions components located at existing
compressor stations. The affected compressor stations include gathering
and boosting, transmission, and storage compressor stations.
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\197\ Note that for gathering and boosting compressor stations,
the EPA is proposing to rescind the 2020 Technical Rule amendment
that changed the monitoring frequency to semiannual for VOC
emissions. See section X.A.2 for more information.
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a. NSPS OOOOb
We are proposing that the quarterly monitoring using OGI be
conducted in accordance with the proposed appendix K described above in
section XI.A.2, which outlines procedures that must be followed to
identify leaks using OGI. We are proposing to retain the current
requirements that monitoring must begin within 90 days of startup of
the station (or startup after modification), with subsequent quarterly
monitoring occurring at least 60 days apart. Also, quarterly monitoring
may be waived when temperatures are below 0 [deg]F for two of three
consecutive calendar months of a quarterly monitoring period. We are
also not proposing any change to the following repair-related
requirements: Specifically, a first attempt at repair must be made
within 30 days of detecting the fugitive emissions, with final repair,
including resurvey to verify repair, completed within 30 days after the
first attempt. In addition, owners and operators must develop a
fugitive emissions monitoring plan that covers all the applicable
requirements for the collection of fugitive emissions components
located at a compressor station. In conjunction with the proposed
requirement that monitoring be conducted in accordance with the
proposed appendix K, we are proposing to require that the monitoring
plan also include elements specified in the proposed appendix K when
using OGI.
b. EG OOOOc
For existing sources, we are proposing a presumptive standard that
includes the same fugitive emissions monitoring and repair program as
for new sources. For the reasons discussed in section XII.A.2, the BSER
analysis for existing sources supports proposing a presumptive standard
for reducing methane emissions from the collection of fugitive
emissions components located at existing compressor stations that is
the same as what the EPA is proposing for new, modified, or
reconstructed sources (for NSPS OOOOb).
Similar to well sites, we are soliciting comment on all aspects of
the proposed quarterly monitoring for both new and existing compressor
stations, including whether more frequent monitoring would be
appropriate. We are also soliciting information on several additional
topics. First, the EPA is soliciting comment and data to assess whether
compressor stations should be subcategorized for the NSPS and/or the
EG, which the EPA could consider through a supplemental proposal. For
example, some industry stakeholders have asserted that station
throughput directly correlates to the operating pressures, equipment
counts, and condensate production, which would influence fugitive
emissions at the station. They suggested that subcategorization based
on design throughput capacity for the compressor station may be
appropriate. We are specifically seeking information related to
throughputs where fugitive emissions of methane are demonstrated to be
minimal below a certain capacity. While this specific example was
raised in the context of existing sources only, the EPA is also
soliciting comment on whether new, modified, or reconstructed
compressor stations could encounter the same issue and therefore
warrant similar subcategorization.
Next, for compressor stations, we are soliciting comment on delayed
repairs by existing sources when parts are not readily available and
must be special ordered. In comments submitted to the EPA as part of
the stakeholder outreach conducted prior to this proposal, industry
stakeholders stated that the EPA ``should acknowledge that existing
sources are older pieces of equipment so there is a higher likelihood
that replacement parts will not be readily available; therefore, a lack
of available parts should be an appropriate cause to delay a repair.''
\198\ Industry stakeholders further explained that operators will need
to special order replacement parts. Further, they stated in their
comments that operators should be afforded 30 days to schedule the
repair once they have received the replacement part. The EPA is
soliciting comment and data to better understand the breadth of this
issue with replacement parts for existing compressor stations.
Additionally, we are soliciting comment on whether 30 days following
receipt of the replacement part is appropriate for completing delayed
repairs at existing compressor stations, whether there should be any
limit on delays in repairs under these circumstances, and whether this
compliance flexibility should be limited or disallowed based on the
severity of the leak to be repaired.
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\198\ Document ID No. EPA-HQ-OAR-2021-0295-0033.
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We are also soliciting comment on the specific records that should
be maintained and/or reported to justify delayed repairs as a result of
part availability issues. Depending on the additional information
received, the EPA may consider proposing changes to the proposed EG for
compressor stations through a supplemental proposal.
Finally, as discussed in section XI.A.2, the EPA is soliciting
comment on whether the scheduling of repairs at compressor stations
should be tiered based on severity of the emissions found. Please refer
to section XI.A.3 for additional details on this solicitation for
comment.
4. Well Sites and Compressor Stations on the Alaska North Slope
For new, reconstructed, and modified well sites and compressor
stations
[[Page 63175]]
located on the Alaska North Slope, based on the rationale provided in
section X.B.4.c of this preamble, the EPA is proposing the same
monitoring requirements as those in NSPS OOOOa (under newly proposed
OOOOb). Also, the EPA is proposing to determine that the same technical
infeasibility issues with weather conditions exist for existing well
sites and compressor stations located on the Alaska North Slope.
Therefore, the EPA is proposing a presumptive standard for reducing
methane emissions from the collection of fugitive emissions components
located at existing well sites and compressor stations located on the
Alaska North Slope (under the newly proposed EG OOOOc) that is the same
as what we are proposing for NSPS OOOOb.
Specifically, the EPA is proposing to require annual monitoring of
methane and VOC emissions at all well sites and compressor stations
located on the Alaska North Slope, with subsequent annual monitoring at
least 9 months apart but no more than 13 months apart. The EPA is also
proposing to require that new, reconstructed, and modified well sites
and compressor stations located on the Alaska North Slope that startup
(initially, or after reconstruction or modification) between September
and March to conduct initial monitoring of methane and VOC fugitive
emissions within 6 months of startup, or by June 30, whichever is
later. Finally, the EPA is proposing to require that new,
reconstructed, and modified well sites and compressor stations located
on the Alaska North Slope that startup (initially, or after
reconstruction or modification) between April and August to conduct
initial monitoring of methane and VOC fugitive emissions within 90 days
of startup.
5. Alternative Screening Using Advanced Measurement Technologies
For new, modified, or reconstructed sources (i.e., collection of
fugitive emissions components located at well sites and compressor
stations), the EPA is proposing an alternative fugitive emissions
monitoring and repair program that includes bimonthly screening for
large emission events using advanced measurement technologies followed
with at least annual OGI in accordance with the proposed 40 CFR part
60, appendix K (``appendix K''), which is included in this action and
outlines the proposed procedures that must be followed to identify
emissions using OGI.\199\ Additionally, we are proposing this same
alternative screening using advanced measurement technologies as an
alternative presumptive standard for existing sources.
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\199\ ``Determination of Volatile Organic Compound and
Greenhouse Gas Leaks Using Optical Gas Imaging'' located at Docket
ID No. EPA-HQ-OAR-2021-0317.
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Specifically, the EPA is proposing to allow owners and operators
the option to comply with this alternative fugitive emissions standard
instead of the proposed ground based OGI surveys summarized in sections
XI.A.2 and XI.A.3. The EPA proposes to require owners and operators
choosing this alternative standard to do so for all affected well sites
and compressor stations within a company-defined area. This company-
defined area could be a county, sub-basin, or other appropriate
geographic area. Under this proposed alternative, the EPA proposes to
require a screening survey on a bimonthly basis using a methane
detection technology that has been demonstrated to achieve a minimum
detection threshold of 10 kg/hr. This screening survey would be used to
identify individual sites (i.e., well sites and compressor stations)
where a follow-up ground-based OGI survey of all fugitive emissions
components at the site is needed because fugitive emissions have been
detected. Given the proposed minimum detection threshold of 10 kg/hr,
which would constitute a significant emissions event, the EPA believes
this follow-up OGI survey should be completed in an expeditious
timeframe, therefore we are proposing to require this follow-up OGI
survey of all fugitive emissions components at the site within 14 days
of the screening survey. However, additional information is needed to
fully evaluate the appropriateness of this deadline. Therefore, the EPA
is soliciting comment on the proposed 14-day deadline for a follow-up
OGI survey and information that would allow further evaluation of other
potential deadlines to require.
Next, for sites with emissions identified during screening and
subject to this follow-up OGI survey, the EPA proposes that any
fugitive emissions identified must be repaired, including those
emissions identified during the screening survey. For purposes of this
proposal, the EPA is proposing the same repair deadlines as those for
the ground based OGI requirements discussed in sections XI.A.2 and
XI.A.3, which are a first attempt at repair within 30 days of the OGI
survey and final repair completed within 30 days of the first attempt.
As noted in section XI.A.1, some equipment types with large emissions
warrant a requirement for root cause analysis rather than simply
repairing the emission source. The EPA solicits comment on how that
root cause analysis with corrective action approach could be applied in
this proposed alternative screening approach. Further, because large
emission events, especially those identified during the screening
surveys, contribute disproportionately to emissions, the EPA is also
soliciting comment on how to structure a requirement that would tier
repair deadlines based on the severity of the fugitive emissions when
using this proposed alternative standard. See section XI.A.2 for
additional discussion of this solicitation on tiered repairs.
In addition to the bimonthly screening surveys proposed above, the
EPA recognizes that component-level fugitive emissions may still be
present at sites where the screening survey does not detect emissions.
Therefore, in conjunction with these bimonthly screenings performed
with the advanced measurement technology, the EPA is proposing to
require a full OGI (or EPA Method 21) survey at least annually at each
individual site utilizing the alternative screening standard. If the
owner or operator performs an OGI survey in response to emissions found
during the bimonthly screening survey, that OGI survey would count as
the annual OGI survey; a second survey would not be required to comply
with the annual OGI survey requirement and the clock would restart with
the next annual survey due within 12 calendar months. The overall
purpose of this annual OGI survey is to ensure that each individual
site is surveyed with OGI at least annually, even where large emissions
are not detected during the screening surveys using advanced
measurement technology. The EPA is not allowing EPA Method 21 for use
during the proposed follow-up OGI surveys when screening detects
emissions because EPA Method 21 is not appropriate for detecting the
sources of large emission events, such as malfunctioning control
devices.
Finally, the EPA is proposing to require that owners and operators
include information specific to the alternative standard within their
fugitive emissions monitoring plan. Since the 2016 NSPS OOOOa, owners
and operators have been required to develop and maintain a fugitive
emissions monitoring plan for all sites subject to the fugitive
emissions requirements. This monitoring plan includes information
regarding which sites are covered under the plan, which technology is
being used (e.g., OGI or EPA Method 21), and site or company-
[[Page 63176]]
specific procedures that are employed to ensure compliant surveys. The
EPA is proposing to add a requirement that the monitoring plan also
address sites that are utilizing the proposed alternative standard.
Specifically, the EPA is proposing a requirement to include the
following information when the alternative standard is applied:
Identification of the sites opting to comply with the
alternative screening approach;
General description of each site to be monitored,
including latitude and longitude coordinates of the asset in decimal
degrees to an accuracy and precision of five decimals of a degree using
the North American Datum of 1983;
Description of the measurement technology;
Verification that the technology meets the 10 kg/hr
methane detection threshold, including supporting data to demonstrate
the sensitivity of the measurement technology as applied;
Procedures for a daily verification check of the
measurement sensitivity under field conditions (e.g., controlled
releases);
Standard operating procedures consistent with EPA's
guidance \200\ and to include safety considerations, measurement
limitations, personnel qualification/responsibilities, equipment and
supplies, data and record management, and quality assurance/quality
control (i.e., initial and ongoing calibration procedures, data quality
indicators, and data quality objectives); and
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\200\ Guidance for Preparing Standard Operating Procedures
(SOPs), EPA/600/B-07/001, April 2007, https://www.epa.gov/sites/default/files/2015-06/documents/g6-final.pdf.
---------------------------------------------------------------------------
Procedures for conducting the screening.
In the event that an owner or operator uses multiple technologies
covered by one monitoring plan, the owner or operator would identify
which technology is to be used on which site within the monitoring
plan.
In addition to the proposed requirements within the monitoring
plan, the EPA is also proposing specific recordkeeping and reporting
requirements associated with the follow-up OGI surveys that are
consistent with the recordkeeping and reporting required for OGI
surveys in NSPS OOOOa as amended in the 2020 Technical Rule. See
section X.B.1.h and X.B.1.i. The EPA is soliciting comment on when
notifications would be required for sites where the alternative
standard is applied. Further, the EPA is soliciting comment on whether
submission of the monitoring plan, and/or Agency approval before
utilizing the alternative standard is necessary to ensure consistency
in screening survey procedures in the absence of finalized methods or
procedures.
While the EPA is proposing the above alternative screening
requirements, additional information is necessary to further refine the
specific alternative work practice as it relates to the available
technologies. Specific information is requested in the following
paragraphs, and, if received, would allow the EPA to better analyze the
BSER for fugitive emissions at well sites and compressor stations
through a supplemental proposal.
First, the EPA solicits comment on the use of 10 kg/hr as the
minimum detection threshold for the advanced measurement technologies
used in the alternative screening approach, including data that would
support consideration of another detection threshold. The EPA also
solicits comment on whether a matrix approach should be developed,
instead of prescribing one detection threshold and screening frequency,
and what that matrix should look like. In the matrix approach, the
frequency of the screening surveys and regular OGI (or EPA Method 21)
surveys would be based on the sensitivity of the technology, with the
most sensitive detection thresholds having the least frequent screening
and survey requirements and the least sensitive detection thresholds
having the most frequent screening and survey requirements. For
example, sites that are screened using a technology with a detection
threshold of 1 kg/hr may require less frequent screening and may
require an OGI survey less frequently than sites screened using a
technology with a detection threshold of 50 kg/hr. We are also
soliciting comment on the detection sensitivity of commercially
available methane detection technologies based on conditions expected
in the field, as well as factors that affect the detection sensitivity
and how the detection sensitivity would change with these factors.
Next, the EPA is soliciting comment on the standard operating
procedures being used for commercially available technologies,
including any manufacturer recommended data quality indicators and data
quality objectives in use to validate these measurements. Additionally,
for those commercially available technologies that quantify methane
emissions rather than just detect methane, we are soliciting comment on
the range of quantification based on conditions one would expect in the
field.
The EPA is seeking information that would allow us to further
evaluate the potential costs and assumed emission reductions achieved
through an alternative screening program. Therefore, the EPA is seeking
information on the cost of screening surveys using different types of
advanced measurement technologies, singularly or in combination, and
factors that affect that cost (e.g., is it influenced by the number of
sites and length of survey). Additionally, we are interested in
understanding whether there would be opportunities for cost-sharing
among operators and whether any aspect of regulation would be
beneficial or required to facilitate such cost-sharing opportunities.
We also solicit comment on whether these technologies and cost-sharing
opportunities would allow for cost-effective monitoring at all sites
owned or operated by the same company within a sub-basin or other
discrete geographic area. Further, we seek comment on the current and
expected availability of these advanced measurement technologies and
the supporting personnel and infrastructure required to deploy them,
how their cost and availability might be affected if demand for these
technologies were to increase, and how quickly the use of these
technologies could expand if they were integrated into this regulatory
program either as a required element of fugitive monitoring or as this
proposed alternative work practice.
The EPA recognizes that the approach outlined above may not be
suited to continuous monitoring technologies, such as network sensors
or open-path technology. While these systems typically have the ability
to meet the 10 kg/hr methane threshold discussed above \201\ the
emissions from these well sites can be intermittent or tied to process
events (e.g., pigging operations). We are concerned that the proposed
alternative screening approach would trigger an OGI survey for every
emission event, regardless of type, duration, or size, if a continuous
monitoring technology is installed. This would disincentivize the use
of continuous monitoring systems, which could be valuable tools in
finding large emission sources sooner. While we believe that a
framework for advanced measurement technologies that monitor sites
continuously should be developed, we do not currently have all of the
information that is necessary to develop
[[Page 63177]]
an equivalence demonstration for these monitors or to ensure the
technology works appropriately over time. Therefore, we are soliciting
comment on how an equivalence demonstration can be made for these
continuous monitoring technologies.
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\201\ Alden et al., Single-Blind Quantification of Natural Gas
Leaks from 1 km Distance Using Frequency Combs, Environmental
Science and Technology, 2019, 53, 2908-2917.
---------------------------------------------------------------------------
The framework for a continuous monitoring technology would need to
cover the following items at a minimum: The number of monitors needed
and the placement of the monitors; minimum response factor to methane;
minimum detection level; frequency of data readings; how to interpret
the monitor data to determine what emissions are a detection versus
baseline emissions; how to determine allowable emissions versus leaks;
the meteorological data criteria; measurement systems data quality
indicators; calibration requirements and frequency of calibration
checks; how downtime should be handled; and how to handle situations
where the source of emissions cannot be identified even when the
monitor registers a leak. We are soliciting comment on how to develop a
framework that is flexible for multiple technologies while still
ensuring that emissions are adequately detected and the monitors
respond appropriately over time. Additionally, we are soliciting
comment on whether these continuous monitors need to respond to other
compounds as well as methane; how close a meteorological station must
be to the monitored site; and whether OGI or EPA Method 21 surveys
should still be required, and if so, at what frequency.
At this time, the EPA does not have enough information to determine
how this proposed alternative standard using advanced measurement
technologies compares to the proposed BSER of OGI monitoring at well
sites at a frequency that is based on the site baseline methane
emissions as described in section XI.A.3.a, or to quarterly OGI
monitoring at compressor stations. Information provided through this
solicitation may be used to reevaluate BSER through a supplemental
proposal.
6. Use of Information From Communities and Others
As the EPA learned during the Methane Detection Technology
Workshop, industry, researchers, and NGOs have utilized advanced
methane detection systems to quickly identify large emission sources
and target ground based OGI surveys. State and local governments,
industry, researchers, and NGOs have been utilizing advanced
technologies to better understand the detection of, source of, and
factors that lead to large emission events. The EPA anticipates that
the use of these techniques by a variety of parties, including
communities located near oil and gas facilities or affected by oil and
gas pollution, will continue to grow as these technologies become more
widely available and decline in cost.
The EPA is seeking comment on how to take advantage of the
opportunities presented by the increasing use of these technologies to
help identify and remediate large emission events (commonly known as
``super-emitters''). Specifically, the EPA seeks comment on how to
evaluate, design, and implement a program whereby communities and
others could identify large emission events and, where there is
credible information of such a large emission event, provide that
information to owners and operators for subsequent investigation and
remediation of the event. The EPA understands that these large emission
events are often attributable to malfunctions or abnormal process
conditions that should not be occurring at a well-operating, well-
maintained, and well-controlled facility that has implemented the
various BSER measures identified in this proposal.
We generally envision a program for finding large emission events
that consists of a requirement that, if emissions are detected above a
defined threshold by a community, a Federal or State agency, or any
other third party, the owner or operator would be required to
investigate the event, do a root cause analysis, and take appropriate
action to mitigate the emissions, and maintain records and report on
such events.
We seek comment on all aspects of this concept, which would be
developed further as part of a supplemental proposal. Among other
things, the EPA is soliciting comment on an emissions threshold that
could be used to define these large emission events, and which types of
technologies would be suitable for identification of large emissions
events. For example, there are some satellite systems capable of
generally identifying emissions above 100 kg/hr with a spatial
resolution which could allow identification of emission events from an
individual site.\202\ Additionally there are other satellites systems
available which have wider spatial resolution that can identify large
methane emission events, and when combined with finer resolution
platforms, could allow identification of emission events from an
individual site. The EPA believes that any emissions visible by
satellites should qualify as large emission events. However, the EPA
solicits comment on whether the threshold for a large emission should
be lower than what is visible by satellite.
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\202\ D.J. Varon, J. McKeever, D. Jervis, J.D. Maasakkers, S.
Pandey, S. Houweling, I. Aben, T. Scarpelli, D.J. Jacob, Satellite
Discovery of anomalously Large Methane Point Sources from Oil/Gas
Production, available at https://doi.org/10.1029/2019GL083798,
October 25, 2019.
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Second, in order to make this approach viable, the EPA would need
to specify what actions an owner or operator must take when notified of
a large emission event, including deadlines for taking such actions.
These elements could include the specific steps the company would take
to investigate the notification and mitigate the event, such as
verifying the location of the emissions, conducting ground
investigations to identify the specific emission source, conducting a
root cause analysis, performing corrective action within a specific
timeframe to mitigate the emissions, and preventing ongoing and future
chronic or intermittent large emissions from that source. These steps
could be incorporated into a fugitive emissions monitoring plan
maintained by the owner or operator, and failure to take the actions
specified by the owner or operator in the plan could be considered
noncompliance. We seek comment on what specific follow-up actions or
other procedures would be appropriate to require once a large emission
event is identified, as well as appropriate deadlines for these
actions.
Third, the EPA would need to define guidelines for credible and
actionable data. The EPA is soliciting comment on what these guidelines
should entail and whether specific protocols (e.g., permissible
detection technologies, data analytics, operator training, data
reporting, public access, and data preservation) should govern the
collection of such data and whether such data should conform to any
type of certification. If specific certification or protocols are
necessary, the EPA is soliciting comment on how that certification
should be obtained.
Fourth, we are also soliciting comment on best practices for the
identification of the correct owner or operator of a facility
responsible for such large emissions, since such information is
necessary to halt such large-volume emission events, and how the
community or other third-party should notify the owner or operator, as
well as how the delegated authority should be made aware of such
notification.
Finally, we are soliciting comment on whether the EPA should
develop a model plan for responding to notifications that companies
could adopt instead of developing company- or site-specific plans,
including what
[[Page 63178]]
elements should be included in that model plan.
B. Storage Vessels
1. NSPS OOOOb
The current NSPS in subpart OOOOa for storage vessels is to reduce
VOC emissions by 95 percent, and the standard applies to a single
storage vessel with a potential for 6 or more tpy of VOC emissions.
Based on our analysis, which is summarized in section XII.B.1, the EPA
is proposing to retain the 95 percent reduction standard as it
continues to reflect the BSER for reducing VOC emissions from new
storage vessels. The EPA is also proposing to set GHG standards (in the
form of limitations on methane emissions) for storage vessels in this
action. Because the BSER for reducing VOC and methane emissions are the
same, the proposed GHG standard is to reduce methane emissions by 95
percent. The EPA continues to support the capture of gas vapors from
storage vessels rather than the combustion of what can be an energy-
rich saleable product. We incentivize this by recognizing the use of
vapor recovery as a part of the process, therefore the storage vessel
emissions would not contribute to the site's potential-to-emit.
Under the current NSPS for storage vessels, an affected facility is
a single storage vessel with potential VOC emissions of 6 tpy or
greater. The EPA is proposing to include a tank battery as a storage
vessel affected facility. The EPA proposes to define a tank battery as
a group of storage vessels that are physically adjacent and that
receive fluids from the same source (e.g., well, process unit,
compressor station, or set of wells, process units, or compressor
stations) or which are manifolded together for liquid or vapor
transfer.
To determine whether a single storage vessel is an affected
facility, the owner or operator would compare the 6 tpy VOC threshold
to the potential emissions from that individual storage vessel; to
determine whether a tank battery is an affected facility, the owner or
operator would compare the 6 tpy VOC threshold to the aggregate
potential emissions from the group of storage vessels. For new,
modified, or reconstructed sources, if the potential VOC emissions from
a storage vessel or tank battery exceeds the 6 tpy threshold, then it
is a storage vessel affected facility and controls would be required.
This is consistent with the EPA's initial determination in the 2012
NSPS OOOO that controlling VOC emissions as low as 6 tpy from storage
vessels is cost-effective. The proposed standard of 95 percent
reduction of methane and VOC emissions, which is the same as the
current VOC standard in the 2012 NSPS OOOO and 2016 NSPS OOOOa, can be
achieved by capturing and routing the emissions utilizing a cover and
closed vent system that routes captured emissions to a control device
that achieves an emission reduction of 95 percent, or that routes
captured emissions to a process.
Finally, we are proposing specific provisions to clarify what
circumstances constitute a modification of an existing storage vessel
affected facility (single storage vessel or tank battery), and thus
subject it to the proposed NSPS instead of the EG. The EPA is proposing
that a single storage vessel or tank battery is modified when physical
or operational changes are made to the single storage vessel or tank
battery that result in an increase in the potential methane or VOC
emissions. Physical or operational changes would be defined to include:
(1) The addition of a storage vessel to an existing tank battery; (2)
replacement of a storage vessel such that the cumulative storage
capacity of the existing tank battery increases; and/or (3) an existing
tank battery or single storage vessel that receives additional crude
oil, condensate, intermediate hydrocarbons, or produced water
throughput (from actions such as refracturing a well or adding a new
well that sends these liquids to the tank battery). The EPA is
proposing to require that the owner or operator recalculate the
potential VOC emissions when any of these actions occur on an existing
tank battery to determine if a modification has occurred. The existing
tank battery will only become subject to the proposed NSPS if it is
modified pursuant to this definition of modification and its potential
VOC emissions exceed the proposed 6 tpy VOC emissions threshold.
2. EG OOOOc
Based on our analysis, which is summarized in section XII.B.2, the
EPA is proposing EG for existing storage vessels which include a
presumptive GHG standard (in the form of limitation on methane
emissions). For existing sources under the EG, the EPA is proposing to
define a designated facility as an existing tank battery with potential
methane emissions of 20 tpy or greater. The proposed definition of a
tank battery in the EG is the same as the definition proposed for new
sources; however, since the designated pollutant in the context of the
EG is methane, determination of whether a tank battery is a designated
facility would be based on its potential methane emissions only. Our
analysis shows that it is cost effective to control an existing tank
battery with potential methane emissions 20 tpy or higher. Similar to
the proposed NSPS, we are proposing a presumptive standard that
includes a 95 percent reduction of the methane emissions from each
existing tank battery that qualifies as a designated facility. Such a
standard could be achieved by capturing and routing the emissions by
utilizing a cover and closed vent system that routes captured emissions
to a control device that achieves an emission reduction of 95 percent,
or routes emission back to a process.
C. Pneumatic Controllers
1. NSPS OOOOb
The current NSPS OOOOa regulates certain continuous bleed natural
gas driven pneumatic controllers, but includes different standards
based on whether the pneumatic controller is located at an onshore
natural gas processing plant. If the pneumatic controller is located at
an onshore natural gas processing plant, then the current NSPS requires
a zero bleed rate. If the pneumatic controller is located elsewhere,
then the current NSPS requires the pneumatic controller to operate at a
natural gas bleed rate no greater than 6 scfh. The current NSPS does
not regulate intermittent vent natural gas driven pneumatic controllers
at any location.
Based on our analysis, which is summarized in section XII.C.1, the
EPA is proposing pneumatic controller standards for NSPS OOOOb as
follows. First, in addition to each single natural gas-driven
continuous bleed pneumatic controller being an affected facility, the
EPA proposes to define each natural gas-driven intermittent vent
pneumatic controller as an affected facility. The EPA believes these
pneumatic controllers should be covered by NSPS OOOOb because natural
gas-driven intermittent devices represent a large majority of the
overall population of pneumatic controllers and are responsible for the
majority of emissions from these sources. We are proposing to define an
intermittent vent natural gas-driven pneumatic controller as a
pneumatic controller that is not designed to have a continuous bleed
rate but is instead designed to only release natural gas to the
atmosphere as part of the actuation cycle. This affected facility
definition would apply at all sites, including natural gas processing
plants.
Second, we are proposing a requirement that all controllers
[[Page 63179]]
(continuous bleed and intermittent vent) must have a VOC and methane
emission rate of zero. The proposed rule does not specify how this
emission rate of zero must be achieved, but a variety of viable options
are discussed in Section XII.C. including the use of pneumatic
controllers that are not driven by natural gas such as air-driven
pneumatic controllers and electric controllers, as well as natural gas
driven controllers that are designed so that there are no emissions,
such as self-contained pneumatic controllers. As noted above, the EPA
is proposing that the definition of an affected facility would be each
pneumatic controller that is driven by natural gas and that emits to
the atmosphere. As such, pneumatic controllers that are not driven by
natural gas would not be affected facilities, and thus would not be
subject to the pneumatic controller requirements of NSPS OOOOb.
Similarly, controllers that are driven by natural gas but that do not
emit to the atmosphere would also not be affected facilities. In order
to demonstrate that a particular pneumatic controller is not an
affected facility, owners and operators should maintain documentation
to show that such controllers are not natural gas driven such as
documentation of the design of the system, and to ensure that they are
operated in accordance with the design so that there are no emissions.
In both NSPS OOOO and OOOOa, there is an exemption from the
standards in cases where the use of a pneumatic controller affected
facility with a bleed rate greater than the applicable standard is
required based on functional needs, including but not limited to
response time, safety, and positive actuation. The EPA is not
maintaining this exemption in the proposed NSPS OOOOb, except for in
very limited circumstances explained in section XII.C. As discussed in
section XII.C., the reasons to allow for an exemption based on
functional need in NSPS OOOO and OOOOa were based on the inability of a
low-bleed controller to meet the functional requirements of an owner/
operator such that a high-bleed controller would be required in certain
instances. Since we are now proposing that pneumatic controllers have a
methane and VOC emission rate of zero, we do not believe that the
reasons related to the use of low bleed controllers are still
applicable. However, EPA is soliciting comment on whether owners/
operators believe that maintaining such an exemption based on
functional need is appropriate, and if so why.
The proposed rule includes an exemption from the zero-emission
requirement for pneumatic controllers in Alaska at locations where
power is not available. In these situations, the proposed standards
require the use of a low-bleed controller instead of high-bleed
controller. Further, in these situations (controllers in Alaska at
location without power) the proposed rule includes the exemption that
would allow the use of high-bleed controllers instead of low-bleed
based on functional needs. Lastly, in these situations owners/operators
must inspect intermittent vent controllers to ensure they are not
venting during idle periods.
2. EG OOOOc
In this action, the EPA is proposing to define designated
facilities (existing sources) analogous to the affected facility
definitions described above for pneumatic controllers under the NSPS.
For the reasons discussed in section XII.C.2, the BSER analysis for
existing sources supports proposing presumptive standards for reducing
methane emissions from existing pneumatic controllers that are the same
as those the EPA is proposing for new, modified, or reconstructed
sources (for NSPS OOOOb).
D. Well Liquids Unloading Operations
Well liquids unloading operations, which are currently unregulated
under the NSPS OOOOa, refer to unloading of liquids that have
accumulated over time in gas wells and are impeding or halting
production. The EPA is proposing standards in the NSPS OOOOb to reduce
methane and VOC emissions during liquids unloading operations.
1. NSPS OOOOb
We are proposing standards to reduce VOC and methane emissions from
each well that conducts a liquids unloading operation. Based on our
analysis, which is summarized in section XII.D.1, we are proposing a
standard under NSPS OOOOb that requires owners or operators to perform
liquids unloading with zero methane or VOC emissions. In the event that
it is technically infeasible or not safe to perform liquids unloading
with zero emissions, the EPA is proposing to require that an owner or
operator establish and follow BMPs to minimize methane and VOC
emissions during liquids unloading events to the extent possible.
The EPA is co-proposing two regulatory approach options to
implement the rule requirements.
For Option 1, the affected facility would be defined as every well
that undergoes liquids unloading. This would mean that wells that
utilize a non-emitting method for liquids unloading would be affected
facilities and subject to certain reporting and recordkeeping
requirements. These requirements would include records of the number of
unloadings that occur and the method used. A summary of this
information would also be required to be reported in the annual report.
The EPA also recognizes that under some circumstances venting could
occur when a selected liquids unloading method that is designed to not
vent to the atmosphere is not properly applied (e.g., a technology
malfunction or operator error). Under the proposed rule Option 1 owners
and operators in this situation would be required to record and report
these instances, as well as document and report the length of venting,
and what actions were taken to minimize venting to the maximum extent
possible.
For wells that utilize methods that vent to the atmosphere, the
proposed rule would require that owners or operators (1) Document why
it is infeasible to utilize a non-emitting method due to technical,
safety, or economic reasons; (2) develop BMPs that ensure that
emissions during liquids unloading are minimized including, at a
minimum, having a person on-site during the liquids unloading event to
expeditiously end the venting when the liquids have been removed; (3)
follow the BMPs during each liquids unloading event and maintain
records demonstrating they were followed; and (4) report the number of
liquids unloading events in an annual report, as well as the unloading
events when the BMP was not followed. While the proposed rule would not
dictate all of the specific practices that must be included, it would
specify minimum acceptance criteria required for the types and nature
of the practices. Examples of the types and nature of the required
practice elements are provided in XII.D.1.e.
For Option 2, the affected facility would be defined as every well
that undergoes liquids unloading using a method that is not designed to
totally eliminate venting. The significant difference in this option is
that wells that utilize non-venting methods would not be affected
facilities that are subject to the NSPS OOOOb. Therefore, they would
not have requirements other than to maintain records to document that
they used non-venting liquids unloading methods. The requirements for
wells that use methods that vent would be the same as described above
under Option 1. The EPA solicits comment on including information such
as where the well stream was directed during unloading and emissions
[[Page 63180]]
manifested and whether an estimate of the VOC and methane emissions
generated should be included in the annual report.
There are several techniques owners and operators can choose from
to unload liquids, including manual unloading, velocity tubing or
velocity strings, beam or rod pumps, electric submergence pumps,
intermittent unloading, gas lift (e.g., use of a plunger lift), foam
agents, wellhead compression, and routing the gas to a sales line or
back to a process. Although the unloading method employed by an owner
or operator can itself be a method that can be employed in such a way
that mitigates/eliminates venting of emissions from a liquids unloading
event, indicating a particular method to meet a particular well's
unloading needs is a production engineering decision. Based on
available information, liquids unloading operations are often conducted
in such a way that eliminates venting to the atmosphere and there are
many options that include techniques and procedures that an owner or
operator can choose from to achieve this standard (discussed in section
XII.D.e of this preamble).
However, the EPA recognizes that there may be reasons that a non-
venting method is infeasible for a particular well, and the proposed
rule would allow for the use of BMPs to reduce the emissions to the
maximum extent possible for such cases (discussed in section XII.D of
this preamble). BMPs include, but are not limited to, following
specific steps that create a differential pressure to minimize the need
to vent a well to unload liquids and reducing wellbore pressure as much
as possible prior to opening to atmosphere via storage tank, unloading
through the separator where feasible, and requiring an operator to
remain on-site throughout the unloading, and closure of all well head
vents to the atmosphere and return of the well to production as soon as
practicable. For example, where a plunger lift is used, the plunger
lift can be operated so that the plunger returns to the top and the
liquids and gas flow to the separator. Under this scenario, venting of
the gas can be minimized and the gas that flows through the separator
can be routed to sales. In situations where production engineers select
an unloading technique that vents emissions or has the potential to
vent emissions to the atmosphere, owners and operators already often
implement BMPs in order to increase gas sales and reduce emissions and
waste during these (often manual) liquids unloading activities.
2. EG OOOOc
The EPA has determined that each well liquids unloading event
represents a modification, which will make the well subject to new
source standards under the NSPS for purposes of the liquids unloading
standards.\203\ Therefore, after the effective date of NSPS OOOOb, the
first time a well undergoes liquids unloading it will become subject to
NSPS OOOOb. This will mean that there will never be a well that
undergoes liquids unloading that will be existing. Therefore, we are
not proposing presumptive standards under the subpart OOOOc EG.
---------------------------------------------------------------------------
\203\ To clarify further, when a well liquids unloading event
represents a modification, this does not make the whole well site a
new source. Rather, the modification will make the well subject to
NSPS for only the liquids unloading standards.
---------------------------------------------------------------------------
E. Reciprocating Compressors
1. NSPS OOOOb
The current NSPS in subpart OOOOa for reducing VOC and methane
emissions from reciprocating compressors is to replace the rod packing
on or before 26,000 hours of operation or 36 calendar months, or to
route emissions from the rod packing to a process through a closed vent
system under negative pressure. The affected facility is each
reciprocating compressor, with the exception of reciprocating
compressors located at well sites. Based on the analysis in section
XII.E.1, the proposed BSER for reducing GHGs and VOC from new
reciprocating compressors is replacement of the rod packing based on an
annual monitoring threshold. Under this proposal for the NSPS, we would
continue to retain, as an alternative, the option of routing rod
packing emissions to a process via a closed vent system under negative
pressure. In this proposed updated standard, the owner or operator of a
reciprocating compressor affected facility would be required to monitor
the rod packing emissions annually using a flow measurement. When the
measured leak rate exceeds 2 scfm (in pressurized mode), replacement of
the rod packing would be required.
As mentioned above, reciprocating compressors that are located at
well sites are not affected facilities under the 2016 NSPS OOOOa. The
EPA previously excluded them because we found the cost of control to be
unreasonable. 81 FR 35878 (June 3, 2016). Our current analysis, as
summarized in section XII.E.1, continues to support this exclusion for
a subset of well sites so this proposal for NSPS OOOOb includes that
same exclusion for well sites that are not centralized production
facilities. See section XI.L for additional details on centralized
production facilities. As described in that section, the EPA is
proposing to apply the proposed standards to reciprocating compressors
located at centralized production facilities.
2. EG OOOOc
Based on the analysis in section XII.E.2, the EPA is proposing EG
that include a presumptive GHG standard (in the form of limitation on
methane emissions) for existing reciprocating compressors that is the
same as the proposed NSPS, including applying these presumptive
standards to reciprocating compressors located at existing centralized
tank batteries.
F. Centrifugal Compressors
1. NSPS OOOOb
The current NSPS in subpart OOOOa for wet seal centrifugal
compressors is 95 percent reduction of GHGs and VOC emissions. The
affected facility is each wet seal centrifugal compressor, with the
exception of wet seal centrifugal compressors located at well sites.
Based on the analysis in section XII.F.1, the BSER for reducing GHGs
and VOC from new, reconstructed, or modified wet seal centrifugal
compressors is the same as the current standard, which is 95 percent
reduction of GHG and VOC emissions. The standard can be achieved by
capturing and routing the emissions, using a cover and closed vent
system, to a control device that achieves an emission reduction of 95
percent, or by routing captured emissions to a process.
As discussed above, wet seal centrifugal compressors that are
located at well sites are not affected facilities under the 2016 NSPS
OOOOa. The EPA previously excluded them because data available at the
time did not suggest there were a large number of wet seal centrifugal
compressors located at well sites. 81 FR 35878 (June 3, 2016). Our
analysis continues to support this exemption for wet seal centrifugal
compressors located at well sites that are not centralized production
facilities. See section XI.L for additional details on centralized
production facilities. As described in that section, the EPA is
proposing to apply the proposed standards to centrifugal compressors
located at centralized production facilities.
2. EG OOOOc
Based on the analysis in section XII.F.2, the EPA is proposing EG
that
[[Page 63181]]
include a presumptive GHG standard (in the form of limitation on
methane emissions) for existing wet seal centrifugal compressors that
is the same as the NSPS, including applying these presumptive standards
to wet seal centrifugal compressors at existing centralized tank
batteries.
G. Pneumatic Pumps
1. NSPS OOOOb
The current NSPS in subpart OOOOa regulates individual natural gas
driven diaphragm pneumatic pumps at well sites and at onshore natural
gas processing plants. The current NSPS for a natural gas driven
diaphragm pneumatic pump at well sites requires 95 percent control of
GHGs and VOCs if there is an existing control device or process on site
where emissions can be routed. There are two exceptions to the 95
percent control requirement: (1) The existing control or process
achieves less than 95 percent reduction; or (2) it is technically
infeasible to route to the existing control device or process. In
addition, the current NSPS in OOOOa specifies that boilers and process
heaters are not considered control devices and that routing emissions
from pneumatic pump discharges to boilers and process heaters is not
considered routing to a process. For more discussion on the use of
boilers and process heaters as control devices for pneumatic pump
emissions, see section X.B.2 of this preamble. The current NSPS for a
natural gas driven diaphragm pneumatic pump at an onshore natural gas
processing plant is a natural gas emission rate of zero, based on
natural gas as a surrogate for VOC and GHG, the two regulated
pollutants.
For NSPS OOOOb, we are proposing to expand the applicability of the
standard currently in NSPS OOOOa in two ways. The first is by including
all natural gas driven diaphragm pumps as affected facilities in the
transmission and storage segment in addition to the production and
natural gas processing segments. The second is that we are expanding
the affected facility definition to include natural gas driven piston
pumps in addition to diaphragm pumps. The proposed definition of an
affected facility would continue to exclude lean glycol circulation
pumps that rely on energy exchange with the rich glycol from the
contractor.
Based on our analysis, which is summarized in section XII.G.1, we
are proposing to retain the current standard for a natural gas driven
diaphragm pneumatic pump at well sites because the BSER for reducing
VOC and methane emissions from such pumps at a well site continues to
be routing to a combustion device or process, but only if the control
device or process is already available on site. As before, the current
analysis continues to show that it is not cost-effective to require the
owner or operator of a pneumatic pump to install a new control device
or process onsite to capture emissions solely for this purpose.
Moreover, even where a control device or process is available onsite
that would achieve at least 95 percent control, the EPA is aware that
it may not be technically feasible in some instances to route the
pneumatic pump to the control device or process. In this situation, the
proposed rule would exempt the owner and operator from this requirement
provided that they document the technical infeasibility and submit it
in an annual report. Another circumstance is that it may be feasible to
route the emissions to a control device, but the control cannot achieve
95 percent control. In this instance, the proposed rule would exempt
the owner or operator from the 95 percent requirement, provided that
the owner or operator maintain records demonstrating the percentage
reduction that the control device is designed to achieve. In this way,
the standard would achieve emission reductions with regard to pneumatic
pump affected facilities even if the only available control device
cannot achieve a 95 percent reduction. For more discussion of the
technical infeasibility aspects of the pneumatic pump requirements, see
section X.B.2 of this preamble. We are proposing to expand these
requirements to all diaphragm pumps at all sites in the production
segment, as well as at all transmission and storage sites. In addition,
we are proposing that these requirements would also include emissions
from piston pneumatic pumps at all sites in the production segment.
We are not proposing any change to the current standard of zero
natural gas emission for natural gas driven diaphragm pneumatic pumps
located at onshore natural gas processing plants, other than the
expansion of the affected facility definition to include piston pumps.
Our analysis discussed in section XII.G.1 demonstrates this standard is
the BSER.
2. EG OOOOc
The EPA is proposing EG that include presumptive methane standards
that are the same as described above for the NSPS OOOOb for existing
natural gas driven diaphragm pneumatic pumps located at well sites and
all other sites in the production segment (except processing plants)
and transmission and storage segment where an existing control device
exists. However, unlike the proposed methane standards in NSPS OOOOb
for natural gas driven piston pneumatic pumps at sites in the
production segment, the proposed presumptive standards under EG OOOOc
exclude piston pumps from the 95 percent control requirements. The
EPA's proposed emissions guidelines also include a presumptive methane
standard for pneumatic pumps located at onshore natural gas processing
plants that is the same as the proposed NSPS described above.
H. Equipment Leaks at Natural Gas Processing Plants
Based on our analysis, which is summarized in section XII.H.1, the
EPA is proposing to update the NSPS for reducing VOC and methane
emissions from equipment leaks at onshore natural gas processing
plants. Further, based on the same analysis in section XII.H.1 and the
EPA's understanding that it is appropriate to apply that same analysis
to existing sources, the EPA is also proposing EG that include these
same LDAR requirements as presumptive standards for reducing methane
leaks from existing equipment at onshore natural gas processing plants.
The EPA is proposing to expand the definition of an affected
facility (referred to as a ``equipment within a process unit'') and
establish a new standard for reducing equipment leaks of VOC and
methane emissions from new, modified, and reconstructed process units
at onshore natural gas processing plants. This proposed standard would
require (1) the use of OGI monitoring to detect equipment leaks from
pumps, valves, and connectors, and (2) retain the current requirements
in the 2016 NSPS OOOOa (which adopts by reference specific provisions
of 40 CFR part 60, subpart VVa (``NSPS VVa'')) for PRDs, open-ended
valves or lines, and closed vent systems and equipment designated with
no detectable emissions.
First, we are proposing to remove a threshold that excludes certain
equipment within a process unit from being subject to the equipment
leaks standards for onshore natural gas processing plants. While the
current definition of an affected facility includes all equipment,
except compressors, that is in contact with a process fluid containing
methane or VOCs (i.e., each pump, PRD, open-ended valve or line, valve,
and flange or other connector), the standards apply only to equipment
``in VOC service,''
[[Page 63182]]
which ``means the piece of equipment contains or contacts a process
fluid that is at least 10 percent VOC by weight.'' We are proposing to
remove this VOC concentration threshold from the LDAR requirements for
the following reasons. First, a VOC concentration threshold bears no
relationship to the LDAR for methane and is therefore not an
appropriate threshold for determining whether LDAR for methane applies.
Second, since there would be no threshold for requiring LDAR for
methane, any equipment not in VOC service would still be required to
conduct LDAR for methane even if not for VOC, thus rendering this VOC
concentration threshold irrelevant.
Second, for all pumps, valves, and connectors located within an
affected process unit at an onshore natural gas processing plant, we
are proposing to require the use of OGI to identify leaks from this
equipment on a bimonthly frequency (i.e., once every other month),
which according to our analysis is the BSER for identifying and
reducing leaks from this equipment. OGI monitoring would be conducted
in accordance with the proposed appendix K,\204\ which is included in
this action and outlines the proposed procedures that must be followed
to identify leaks using OGI. As an alternative to bimonthly monitoring
using OGI, we are proposing to allow affected facilities the option to
comply with the requirements of NSPS VVa, which are the current
requirements in the 2016 NSPS OOOOa.\205\ As explained in XII.A, our
analysis shows that the proposed standards, which use OGI, achieve
equivalent reduction of VOC and methane emissions as the current
standards, which are based on EPA Method 21, but at a lower cost. While
we no longer consider EPA Method 21 to be the BSER for reducing methane
and VOC emissions from equipment leaks at onshore natural gas
processing plants, we are retaining NSPS VVa as an alternative for
owners and operators who prefer using EPA Method 21.
---------------------------------------------------------------------------
\204\ ``Determination of Volatile Organic Compound and
Greenhouse Gas Leaks Using Optical Gas Imaging'' located at Docket
ID No. EPA-HQ-OAR-2021-0317.
\205\ It is important to note that the stay of the connector
monitoring requirements in 40 CFR 60.482-11a does not apply to
connectors located at onshore natural gas processing plants.
Therefore, where sources choose to comply with the requirements of
NSPS VVa in place of the proposed OGI requirements, the standards in
40 CFR 60.482-11a are applicable to all connectors in the process
unit.
---------------------------------------------------------------------------
Third, we are proposing to require a first attempt at repair for
all leaks identified with OGI within 5 days of detection, and final
repair completed within 15 days of detection. We are also proposing
definitions for ``first attempt at repair'' and ``repaired.'' The
proposed definitions would apply to the equipment leaks standards at
natural gas processing plants as well as to fugitive emissions
requirements at well sites and compressor stations. The proposed
definition of ``first attempt at repair'' is an action taken for the
purpose of stopping or reducing fugitive emissions or equipment leaks
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. The
proposed definition for ``repaired'' is fugitive emissions components
or equipment are adjusted, replaced, or otherwise altered, in order to
eliminate fugitive emissions or equipment leaks as defined in the
subpart and resurveyed to verify that emissions from the fugitive
emissions components or equipment are below the applicable leak
definition. Repairs can include replacement with low-emissions (``low-
e'') valves or valve packing, where commercially available, as well as
drill-and-tap with a low-e injectable. These low-e equipment meet the
specifications of API 622 or 624. Generally, a low-e valve or valve
packing product will include a manufacturer written warranty that it
will not emit fugitive emissions at a concentration greater than 100
ppm within the first five years. Further, we are proposing to
incorporate the delay of repair provisions that are in 40 CFR 60.482-9a
of NSPS VVa (and incorporated into NSPS OOOOa). These provisions would
allow the delay of repairs where it is technically infeasible to
complete repairs within 15 days without a process unit shutdown and
require repair completion before the end of the next process unit
shutdown.
Fourth, we are proposing to retain the current requirements in NSPS
OOOOa for open-ended valves or lines, closed vent systems and equipment
designated with no detectable emissions, and PRDs. For open-ended
valves or lines, we propose to retain the requirements in 40 CFR
60.482-6a of NSPS VVa. Specifically, we are proposing that each open-
ended valve or line in a new or existing process unit must be equipped
with a closure device (i.e., cap, blind flange, plug, or a second
valve) that seals the open end at all times except during operations
requiring process fluid flow through the open-ended valve or line. The
EPA is soliciting comment on requiring OGI monitoring (or EPA Method 21
monitoring for those opting for that alternative) on these open-ended
valves or lines equipped with closure devices to ensure no emissions
are going to the atmosphere. Specifically, the EPA is soliciting
information that would aid in determining what additional costs would
be incurred from either OGI or EPA Method 21 monitoring and repair of
leaking open-ended valves or lines, and information on leak rates and
concentrations of emissions, where monitoring has been performed.
While the EPA is proposing to retain the no detectable emission
requirement in NSPS OOOOa for closed vent systems and equipment
designated as having no detectable emissions (e.g., valves or PRDs),
the EPA is also soliciting comment on whether bimonthly OGI monitoring
according to the proposed appendix K is appropriate to demonstrate
compliance with this requirement. The current NSPS requires the closed
vent systems \206\ and the other equipment described above to operate
with no detectable emissions, as demonstrated by an instrument reading
of less than 500 ppm above background with EPA Method 21. On December
22, 2008, the EPA issued a final rule titled, ``Alternative Work
Practice to Detect Leaks from Equipment'' (AWP).\207\ In that final
rule, the EPA did not permit the use of OGI for this equipment,
stating, ``the AWP is not appropriate for monitoring closed vent
system, leakless equipment, or equipment designated as non-leaking.
While the AWP will identify leaks with larger mass emission rates,
tests conducted with both the AWP and the current work practice
indicate the AWP, at this time, does not identify very small leaks and
may not be able to identify if non-leaking/leakless equipment are truly
nonleaking because the detection sensitivity of the optical gas imaging
instrument is not sufficient.'' 73 FR 78204 (December 22, 2008). The
EPA is soliciting information that would support the use of OGI for
closed vent systems and equipment designated with no detectable
emissions at new and existing process units, including comment on
applying the proposed bimonthly OGI monitoring requirement on this
equipment in place
[[Page 63183]]
of the NSPS VVa annual EPA Method 21 monitoring.
---------------------------------------------------------------------------
\206\ For purposes of this standard, the EPA is referring to
closed vent systems used equipment within process units at onshore
natural gas processing plants. Closed vent systems associated with
controlled storage vessels, wet seal centrifugal compressors,
reciprocating compressors and pneumatic pumps are not included in
this discussion and would demonstrate compliance with the no
detectable emissions standard by EPA Method 21 (except for storage
vessels), monthly AVO, or OGI monitoring during the fugitive
emissions survey.
\207\ See 73 FR 78199 (December 22, 2008).
---------------------------------------------------------------------------
Finally, the EPA is proposing to retain the emission standards for
PRDs found in 40 CFR 60.482-4a of NSPS VVa. This provision requires
that PRDs be operated with no detectable emissions, except during
pressure releases at new and existing process units. As stated above,
the EPA is soliciting comment on the use of OGI to demonstrate that
PRDs are meeting this operational emission standard.
2. EG OOOOc
The EPA is proposing EG that include a presumptive methane standard
that is the same as described above for the NSPS OOOOb for equipment
leaks at existing onshore natural gas processing plants. Based on the
analysis in section XII.H.2, the BSER for reducing GHGs from equipment
leaks at new and existing onshore natural gas processing plants are the
same.
I. Well Completions
Based on our understanding that there are no advances in
technologies or practices, which is summarized in section XII.I, the
EPA is proposing to retain the REC and completion combustion
requirements for reducing methane and VOC emissions from well
completions of hydraulically fractured or refractured oil and natural
gas wells, as they continue to reflect the BSER. These proposed
standards are the same as those for natural gas and oil wells regulated
in the 2012 NSPS OOOO and 2016 NSPS OOOOa, as amended in the 2020
Technical Rule for VOC and proposed in section X.B.1 for methane.\208\
Because of the nature of well completions, any completion (or
recompletion) is considered a new or modified well affected facility,
therefore, the EPA does not believe there are existing well affected
facilities to which a EG OOOOc presumptive standard for well
completions would apply.
---------------------------------------------------------------------------
\208\ See Docket ID No. EPA-HQ-OAR-2021-0317 for proposed
redline regulatory text for 40 CFR 60.5375a as a reference for the
specific well completion standards proposed for NSPS OOOOb.
---------------------------------------------------------------------------
J. Oil Wells With Associated Gas
Associated gas originates at wellheads that also produce
hydrocarbon liquids and occurs either in a discrete gaseous phase at
the wellhead or is released from the liquid hydrocarbon phase by
separation. There are no current NSPS requirements for this emission
source. The EPA is proposing standards in the NSPS OOOOb to reduce
methane and VOC emissions resulting from the venting of associated gas
from oil wells.
1. NSPS OOOOb
We are proposing standards to reduce methane and VOC emissions from
each oil well that produces associated gas. Based on our analysis,
which is summarized in section XII.J, we are proposing a standard under
NSPS OOOOb that requires owners or operators of oil wells to route
associated gas to a sales line. In the event that access to a sales
line is not available, we are proposing that the gas can be used as an
onsite fuel source, used for another useful purpose that a purchased
fuel or raw material would serve, or routed to a flare or other control
device that achieves at least 95 percent reduction in methane and VOC
emissions. As discussed in section XII.J, the EPA is soliciting comment
on how ``access to a sales line'' should be defined. An affected
facility would be defined as any oil well that produces associated gas.
The proposed rule would require that when using a flare, the flare must
meet the requirements in 40 CFR 60.18 and that monitoring,
recordkeeping, and reporting be conducted to ensure that the flare is
constantly achieving the required 95 percent reduction. As discussed in
section XII.J, the EPA is soliciting comment on an alternative affected
facility definition that would exclude oil wells that route all
associated gas to a sales line. The EPA is also soliciting comment and
information that would support requirements using other strategies to
reduce venting and flaring of associated gas from oil wells. The EPA is
specifically requesting comment on whether the proposed requirements
will incentivize the sale or productive use of captured gas, and if
not, other methods that the EPA could use to incentivize or require the
sale or productive use instead of flaring.
2. EG OOOOc
The EPA is proposing presumptive standards for existing oil wells
in this action that are the same as discussed above for new sources.
K. Sweetening Units
Based on our understanding that no advances in technologies or
practices are available to reduce SO2 emissions from
sweetening units, as described in section XII.K, the EPA is proposing
to retain the standards as it continues to reflect the BSER. These
proposed standards are the same as those for sweetening units regulated
in the 2016 NSPS OOOOa, and as amended in the 2020 Technical Rule.\209\
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\209\ See Docket ID No. EPA-HQ-OAR-2021-0317 for proposed
redline regulatory text for 40 CFR 60.5375a as a reference for the
specific well completion standards proposed for NSPS OOOOb.
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L. Centralized Production Facilities
The EPA is also proposing a new definition for ``centralized
production facility,'' which is one or more permanent storage tanks and
all equipment at a single stationary source used to gather, for the
purpose of sale or processing to sell, crude oil, condensate, produced
water, or intermediate hydrocarbon liquid from one or more offsite
natural gas or oil production wells. This equipment includes, but is
not limited to, equipment used for storage, separation, treating,
dehydration, artificial lift, combustion, compression, pumping,
metering, monitoring, and flowline. Process vessels and process tanks
are not considered storage vessels or storage tanks. A centralized
production facility is located upstream of the natural gas processing
plant or the crude oil pipeline breakout station and is a part of
producing operations. The EPA is proposing this definition to (1)
specify how the fugitive emissions requirement apply to centralized
production facilities, (2) specify how exemptions related to 40 CFR
part 60, subpart K, Ka, or Kb (``NSPS Kb) may apply, and (3) specify
what standards would apply to reciprocating and centrifugal compressors
located at these facilities.
First, the EPA is proposing to specify how the fugitive emission
requirements apply to centralized production facilities. The 2016 NSPS
OOOOa, as originally promulgated, provided that ``[f]or purposes of the
fugitive emissions standards at 40 CFR 60.5397a, [a] 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).'' 40 CFR 60.5430a. The inclusion of centralized tank
batteries in the definition of well site was used to clarify the
boundary of a well site for purposes of the fugitive emissions
requirements. Further, in the RTC \210\ for the 2016 NSPS OOOOa we
stated, ``[o]ur intent is to limit the oil and gas production segment
up to the point of custody transfer to an oil and natural gas mainline
pipeline (including transmission pipelines) or a natural gas processing
plant. Therefore, the collection of fugitive emissions components
within this boundary are a part of the well site.'' The EPA continues
to define these facilities as a type of well site but is proposing a
separate definition to provide further
[[Page 63184]]
clarity, especially as it relates to when these facilities are
modified, and thus become subject to the fugitive emissions
requirements in NSPS OOOOb. The EPA has determined it is appropriate to
rename this site as a centralized production facility and to provide
the specific definition above to avoid confusion with the storage
vessel affected facility, of which applicability is determined for a
tank battery, and to better specify the facility name based on the
basic function the site performs (i.e., production operations).
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\210\ See Document ID No. EPA-HQ-OAR-2010-0505-7632 at page 4-
194.
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Second, the EPA has received questions related to whether NSPS Kb
would apply to the storage vessels at centralized production
facilities. There is an exemption in NSPS Kb for storage vessels in the
producing operations that are below a specific size. Specifically, 40
CFR 60.110(b)(4) exempts ``vessels with a design capacity less than or
equal to 1,589.874 m\3\ used for petroleum or condensate stored,
processed, or treated prior to custody transfer.'' This exemption is a
revision of an exemption originally promulgated in 40 CFR part 60,
subpart K (``NSPS K''). NSPS K ``does not apply to storage vessels for
the crude petroleum or condensate stored, processed, and/or treated at
a drilling and production facility prior to custody transfer.'' 40 CFR
60.110(b). In that final rule the EPA explained that, ``[t]he storage
of crude oil and condensate at producing fields is specifically
exempted from the standard.'' 39 FR 9312 (March 8, 1974). While
``producing fields'' were not explicitly defined, NSPS K defined the
terms ``custody transfer'' and ``drilling and production facility''.
For purposes of NSPS K, custody transfer means ``the transfer of
produced crude petroleum and/or condensate, after processing and/or
treating in the producing operations, from storage tanks or automatic
transfer facilities to pipelines or any other forms of
transportation.'' 40 CFR 60.111(g). Drilling and production facility
means ``all drilling and servicing equipment, wells, flow lines,
separators, equipment, gathering lines, and auxiliary
nontransportation-related equipment used in the production of crude
petroleum but does not include natural gasoline plants.'' 40 CFR
60.111(h). The definition of ``custody transfer'' was later also
incorporated into 40 CFR part 60, subpart Ka (``NSPS Ka''), NSPS Kb,
and 40 CFR part 63, subpart HH (National Emission Standards for
Hazardous Air Pollutants from Oil and Natural Gas Production
Facilities).
Instead of a categorical exemption for storage vessels located at
drilling and production facilities, NSPS Ka, and subsequently NSPS Kb,
adopted threshold-based exemptions that are based on the capacity of an
individual storage vessel used to store petroleum (crude oil) or
condensate prior to custody transfer. In NSPS Ka, the EPA stated
``[t]his exemption applies to storage between the time that the
petroleum liquid is removed from the ground and the time that custody
of the petroleum liquid is transferred from the well or producing
operations to the transportation operations'' 45 FR 23377 (April 4,
1980). In NSPS Kb, the EPA further stated that ``[t]he promulgated
standards for petroleum liquid storage vessels specifically exempted
vessels with a capacity less than 420,000 gallons and storing petroleum
(crude oil) and condensate prior to custody transfer (production
vessels). The emission controls that are applicable to the storage
vessels included in the standards being proposed are not applicable to
production vessels.'' 49 FR 29701.
The EPA finds it inappropriate to use the controls required by NSPS
K, Ka, and Kb on storage vessels located in the production segment,
especially where flash emissions are prevalent. Specifically, the NSPS
K, Ka, and Kb control requirements include provisions allowing the use
of floating roofs to reduce emissions from storage tanks. Floating
roofs are not designed to store liquid (or gases) under pressure.
Pressurized liquid sent to a storage vessel from a well or separator or
other process that operates above atmospheric pressure may contain
dissolved gases. These gases will be released or ``flash'' from the
liquid as the fluid comes to equilibrium with atmospheric pressure
within the storage vessel. The flash gas will either be released from
gaps in the seal system or from ``rim vents'' on the floating roof. The
rim vent may be an open tube or may be fitted with a low-pressure
relief valve, but it is specifically designed to allow any gas
entrained or dissolved in the storage liquid to be released above the
floating roof. That is, floating roofs are not designed to prevent the
release of flash gas, they are only designed to limit the
volatilization of a liquid that occurs when the storage liquid is
directly exposed with unsaturated air. Since a significant portion of
emissions from storage vessels at well sites or centralized production
facilities are from flash gas, floating roofs are much less effective
at reducing storage vessel emissions than venting these emissions
through a CVS to a control or recovery device.
Further, it is the EPA's understanding that these centralized
production facilities carry out the same operations that would be
conducted at the individual well sites. Therefore, the EPA is proposing
a definition of ``centralized production facility'' that clearly
specifies these facilities are located within the producing operations.
Therefore, if all other conditions are met (i.e., vessels with a design
capacity less than or equal to 1,589.874 m\3\ used for petroleum or
condensate stored, processed, or treated prior to custody transfer),
storage vessels at these centralized facilities would meet the
exemption criteria for NSPS Kb.
Alternatively, the EPA is soliciting comment on whether it would be
more appropriate to specify within the proposed NSPS OOOOb and EG OOOOc
that storage vessels at well sites and centralized production
facilities are subject to the requirements in NSPS OOOOb and EG OOOOc
instead of NSPS K, Ka, or Kb. This alternative approach would eliminate
the need for sources to determine if the storage vessel meets the
exemption criteria specified in those subparts and instead focus on
appropriate controls for the storage vessels based on the location and
type of emissions likely present (e.g., flash emissions).
Finally, the EPA is now proposing to define centralized production
facilities separately from well sites because the number and size of
equipment, particularly reciprocating and centrifugal compressors, is
larger than standalone well sites which would not be included in the
proposed definition of ``centralized production facilities'' above. In
the 2016 NSPS OOOOa, the EPA exempted reciprocating and centrifugal
compressors located at well sites from the applicable compressor
standards.
Reciprocating compressors that are located at well sites are not
affected facilities under the 2016 NSPS OOOOa. The EPA previously
excluded them because we found the cost of control to be unreasonable.
81 FR 35878. However, as mentioned above, the EPA believes the
definition of ``well site'' in NSPS OOOOa may cause confusion regarding
whether reciprocating compressors located at centralized production
facilities are also exempt from the standards. In our current analysis,
described in section XII.E, we find it is appropriate to apply the same
emission factors to reciprocating compressors located at centralized
production facilities as those used for reciprocating compressors at
gathering and boosting compressor stations. Given the results of that
analysis, the EPA is proposing to apply the proposed NSPS OOOOb and
presumptive standards in EG OOOOc to
[[Page 63185]]
reciprocating compressors located at centralized production facilities.
The new definition above is intended to apply the results of the EPA's
analysis. We believe that this new definition is necessary in the
context of reciprocating compressors to distinguish between these
compressors at centralized production facilities where the EPA has
determined that the standard should apply, and these compressors at
standalone well sites where the EPA has determined that the standard
should not apply. See section XII.E for more details of those proposed
standards.
Similarly, wet seal centrifugal compressors that are located at
well sites are not affected facilities under the 2016 NSPS OOOOa. The
EPA previously excluded them because data available at the time did not
suggest there were a large number of wet seal centrifugal compressors
located at well sites. 81 FR 35878. In our current analysis, described
in section XII.F, we find it is appropriate to apply the same emission
factors to wet seal centrifugal compressors located at centralized
production facilities as those used for these same compressors at
gathering and boosting compressor stations. Given the results of that
analysis, the EPA is proposing to apply the proposed NSPS OOOOb and
presumptive standards in EG OOOOc to wet seal centrifugal compressors
located at centralized production facilities. See section XII.F for
more details of those proposed standards.
M. Recordkeeping and Reporting
The EPA is proposing to require electronic reporting of performance
test reports, annual reports, and semiannual reports through the
Compliance and Emissions Data Reporting Interface (CEDRI). (CEDRI can
be accessed through the EPA's Central Data Exchange (CDX) at https://cdx.epa.gov/.) A description of the electronic data submission process
is provided in the memorandum Electronic Reporting Requirements for New
Source Performance Standards (NSPS) and National Emission Standards for
Hazardous Air Pollutants (NESHAP) Rules, available in the docket for
this action. Performance test results collected using test methods that
are supported by the EPA's Electronic Reporting Tool (ERT) as listed on
the ERT website \211\ at the time of the test would be required to be
submitted in the format generated through the use of the ERT or an
electronic file consistent with the xml schema on the ERT website, and
other performance test results would be submitted in portable document
format (PDF) using the attachment module of the ERT. For semiannual and
annual reports, the owner or operator would be required to use the
appropriate spreadsheet template to submit information to CEDRI.
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\211\ https://www.epa.gov/electronic-reporting-air-emissions/electronic-reporting-tool-ert.
---------------------------------------------------------------------------
The EPA is also proposing to allow owners and operators the ability
to seek extensions for submitting electronic reports for circumstances
beyond the control of the facility, i.e., for a possible outage in CDX
or CEDRI or for a force majeure event, in the time just prior to a
report's due date. The EPA is providing these potential extensions to
protect owners and operators from noncompliance in cases where they
cannot successfully submit a report by the reporting deadline for
reasons outside of their control. The decision to accept the claim of
needing additional time to report is within the discretion of the
Administrator.
Electronic reporting is required in the amended 2016 NSPS OOOOa,
and the EPA believes that the electronic submittal of these reports in
the proposed NSPS OOOOb will increase the usefulness of the data
contained in those reports, is in keeping with current trends in data
availability, will further assist in the protection of public health
and the environment, and will ultimately result in less burden on the
regulated community. Electronic reporting can also eliminate paper-
based, manual processes, thereby saving time and resources, simplifying
data entry, eliminating redundancies, minimizing data reporting errors,
and providing data quickly and accurately to the affected facilities,
air agencies, the EPA, and the public. Moreover, electronic reporting
is consistent with the EPA's plan \212\ to implement E.O. 13563 and is
in keeping with the EPA's agency-wide policy \213\ developed in
response to the White House's Digital Government Strategy.\214\
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\212\ EPA's Final Plan for Periodic Retrospective Reviews,
August 2011. Available at: https://www.regulations.gov/document?D=EPA-HQ-OA-2011-0156-0154.
\213\ E-Reporting Policy Statement for EPA Regulations,
September 2013. Available at: https://www.epa.gov/sites/production/files/2016-03/documents/epa-ereporting-policy-statement-2013-09-30.pdf.
\214\ Digital Government: Building a 21st Century Platform to
Better Serve the American People, May 2012. Available at: https://obamawhitehouse.archives.gov/sites/default/files/omb/egov/digital-government/digital-government.html.
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In addition to the annual and semiannual reporting requirement, the
EPA is soliciting comment on what elements, if any, are appropriate for
more frequent reporting, and what mechanism would be appropriate for
the collection and public dissemination of this information. For
example, it may be appropriate to make information related to large
emission events public in a timelier manner than the annual reporting
period. Therefore, the EPA is soliciting comment on the appropriate
mechanism to use for this type of report, including how the data would
be reported, who would manage that reporting system, the frequency at
which the data should be reported, the potential benefits of more
frequent reporting for reducing emissions, the associated burden with
this type of reporting and ways to mitigate that burden, and other
considerations that should be taken into account.
N. Prevention of Significant Deterioration and Title V Permitting
The pollutant we are proposing to regulate is GHGs, not methane as
a separately regulated pollutant. As explained in section XV of this
preamble, we are proposing to add provisions to NSPS OOOOb and EG
OOOOc, analogous to what was included in the 2016 NSPS OOOOa and other
rules regulating GHGs from electric utility generating units, to make
clear in the regulatory text that the pollutant regulated by this rule
is GHGs. The proposed addition of these and other provisions is
intended to address some of the potential implications on the CAA
Prevention of Significant Deterioration (PSD) preconstruction permit
program and the CAA title V operating permit program.
XII. Rationale for Proposed NSPS OOOOb and EG OOOOc
The following sections provide the EPA's BSER analyses and the
resulting proposed NSPS to reduce methane and VOC emissions and the
resulting proposed EG, which include presumptive standards, to reduce
methane emissions from across the Crude Oil and Natural Gas source
category. Our general process for evaluating BSER for the emission
sources discussed below included: (1) Identification of available
control measures; (2) evaluation of these measures to determine
emission reductions achieved, associated costs, non-air environmental
impacts, energy impacts and any limitations to their application; and
(3) selection of the control techniques that represent
[[Page 63186]]
BSER.\215\ As discussed in the 2016 NSPS OOOOa, the available control
technologies will reduce both methane and VOC emissions at the same
time. The revised BSER analysis we have undertaken for the sources
addressed in the proposed NSPS OOOOb continues to support this
conclusion. CAA Section 111 also requires the consideration of cost in
determining BSER. Section IX describes how the EPA evaluates the cost
of control for purposes of this rulemaking. Sections XII.A through
XII.I provide the BSER analysis and the resulting proposed NSPS and EG
for the individual emission sources contemplated in this action. Please
note that there are minor differences in some values presented in
various documents supporting this action. This is because some
calculations have been performed independently (e.g., NSPS OOOOb and EG
OOOOc TSD calculations for NSPS OOOOb and EG OOOOc focused on unit-
level cost-effectiveness and RIA calculations focused on national
impacts) and include slightly different rounding of intermediate
values.
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\215\ In the context of developing the draft emissions
guidelines contained herein, this general process also follows, and
is intended to satisfy, certain requirements of EPA's implementing
regulations for CAA section 111(d), namely the specific listed
component of a draft EG contained in 40 CFR 60.22a(b)(2), and some
elements of paragraph (b)(3).
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For this proposed EG the EPA is proposing to translate the degree
of emission limitation achievable through application of the BSER
(i.e., level of stringency) into presumptive standards.\216\ As
discussed in each of the EG-specific subsections below, the EPA's
evaluation of BSER in the context of existing sources utilized much of
the same information as our BSER analysis for the NSPS. This is because
within the oil and natural gas industry many of the control measures
that are available to reduce emissions of methane from existing sources
are the same as those control measures available to reduce VOC and
methane emissions from new, modified, and reconstructed sources. By
extension, many of the methane emission reductions achieved by the
available control options, as well as the associated costs, non-air
environmental impacts, energy impacts, and limitations to their
application, are very similar if not the same for new and existing
sources. Any relevant differences between new and existing sources in
the context of available control measures or any other factors are
discussed in the EG-specific subsections below.
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\216\ This is intended to satisfy certain elements of the
requirements of EPA's implementing regulations found at 40 CFR
60.22a(b)(3) and (5) with the exception of compliance times which
the EPA discusses separately in section XVI.
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Where the EPA identified relevant distinctions between new and
existing sources in the context of evaluating BSER, it was typically
regarding the cost of control options. While many factors can cause
differences in the cost of control between new and existing sources,
the EPA would like to highlight two general concepts to illustrate how
the oil and natural gas industry is unique. These concepts are the
``size'' of the affected facility and the type of standards. First,
affected facilities defined in any given NSPS can range from entire
process units to individual pieces of equipment. For affected
facilities comprised of an entire process unit, or very large processes
or equipment, there can be significant differences between the cost of
construction or modification for a new source as compared to the cost
of a retrofit required for implementation of a control at an existing
source. In the case of a new sources, there can be cost savings
associated with the up-front planning for the installation of controls
which cannot be achieved at existing sources that must instead retrofit
already existing processes or equipment. This is particularly true of
controls involving equipment changes or add-on control devices. In
contrast, most affected facilities for which the EPA is proposing
standards in NSPS OOOOb are more narrowly defined. For example, a
pneumatic controller affected facility is generally defined as a single
natural gas-driven pneumatic controller, which is a discrete and
relatively small piece of equipment in a larger process. Another
example is the reciprocating compressor affected facility which is
defined as a single reciprocating compressor. As such, the EPA did not
identify the same type of cost savings associated with the up-front
planning of controls in the oil and gas sector as we might in the
context of larger affected facilities. We believe this is one factor
that led to costs being very similar for new and existing sources.
Second, with regard to the type of standards, many of the standards
proposed for NSPS OOOOb, and the presumptive standards proposed for EG
OOOOc, are non-numerical standards, such as work practice standards,
that require limited or no significant physical modifications. The EPA
found that costs for these non-numerical standards would typically not
differ between new and existing sources because the work practice could
be implemented in both contexts without the need to first install or
retrofit any equipment. Put another way, a work practice tends to
operate in the same manner regardless of whether the site is new or
existing, and existing sites typically do not need to take any
preliminary steps in order to implement the work practice. For these
reasons, many of the proposed presumptive standards for EG OOOOc
discussed in the following sections mirror the proposed standards
identified based on the BSER analyses for NSPS OOOOb.
A. Proposed Standards for Fugitive Emissions From Well Sites and
Compressor Stations
1. NSPS OOOOb
There are many potential sources of fugitive emissions throughout
the Crude Oil and Natural Gas Production source category. Fugitive
emissions occur when connection points are not fitted properly or when
seals and gaskets start to deteriorate. Changes in pressure and
mechanical stresses can also cause components or equipment to emit
fugitive emissions. Poor maintenance or operating practices, such as
improperly reseated pressure relief valves (PRVs) or worn gaskets and
springs on thief hatches on controlled storage vessels are also
potential causes of fugitive emissions. Additional sources of fugitive
emissions include agitator seals, connectors, pump diaphragms, flanges,
instruments, meters, open-ended lines, PRDs such as PRVs, pump seals,
valves or controlled liquid storage tanks.
In the 2021 GHGI, the methane emissions for 2019 from fugitive
emissions in the Crude Oil and Natural Gas source category were 96,000
metric tons methane for petroleum systems and 351,500 metric tons for
natural gas systems. These levels represent 6 percent of the total
methane emissions estimated from all petroleum systems sources (i.e.,
exploration through refining) and 5 percent of all methane emissions
from natural gas systems (i.e., exploration through distribution). In
addition, fugitive emissions may be represented in other categories of
the GHGI production segment; for example, a portion of fugitive
emissions (as defined in this action) is also expected to be related to
fugitive emissions from tank thief hatches, and thief hatches on
controlled storage vessels, and those emissions are included in the
emissions estimates for storage vessels in the GHGI.
In the 2016 NSPS OOOOa, the EPA promulgated standards to control
GHGs (in the form of limitations on methane emissions) and VOC
emissions from fugitive emissions components located at well sites and
compressor stations. These standards required a fugitive
[[Page 63187]]
emissions monitoring and repair program, where well sites and
compressor stations had to be monitored semiannually and quarterly,
respectively.
a. Fugitive Emissions From Well Sites
Oil and natural gas production practices and equipment vary from
well site to well site. A well site can serve one well or multiple
wells. Some production sites may include only a single wellhead that is
extracting oil or natural gas from the ground, while other sites may
include multiple wellheads with a number of operations such as
production, extraction, recovery, lifting, stabilization, separation
and/or treating of petroleum and/or natural gas (including condensate).
In addition, the 2016 NSPS OOOOa definition of well site also includes
centralized tank batteries for purposes of the fugitive emissions
requirements because, like storage vessels at well sites, centralized
tank batteries collect crude oil, condensate, intermediate hydrocarbon
liquids, or produced water from wells; therefore, ``excluding tank
batteries not located at the well site could incentivize some owners or
operators to place new tank batteries further away from well sites to
make use of such an exemption.'' \217\ The equipment to perform these
production operations (including piping and associated components,
compressors, generators, separators, storage vessels, and other
equipment) has components that may be sources of fugitive emissions.
Therefore, the number of components with the potential for fugitive
emissions can vary depending on the number of wells and the number of
major production and processing equipment at the site. Another factor
that impacts the operations at a well site, and the resulting fugitive
emissions potential, is the nature of the oil and natural gas being
extracted. This can range from well sites that only extract and handle
``dry'' natural gas to those that extract and handle heavy oil.
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\217\ See Document ID No. EPA-HQ-OAR-2010-0505-7632 at page 4-
221.
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In both the 2016 NSPS OOOOa and subsequent amendments in the 2020
Technical Rule, the EPA relied on a model plant approach to estimate
emissions from well sites. Model plants were developed to provide a
representation of well sites across the spectrum. Separate production-
based model plants using component counts to determine baseline
emissions were developed. The basic approach used was to assign a
number of specific equipment types for each well site model plant and
then to estimate the number of components based on assigned numbers of
components per equipment type. Primarily, the well site model plants
utilized information from the DrillingInfo HPDI[supreg] database,\218\
the 1996 EPA/GRI Study,\219\ EPA's GHG Inventory, and GHGRP subpart W.
Fugitive model plants were originally developed for the 2015 NSPS OOOOa
proposed rule (80 FR 56614, September 18, 2015) and evolved over time
in response to new information and public comments. More information on
the history of the model plant development can be found in the 2015
NSPS Proposal TSD,\220\ the 2016 NSPS Final TSD,\221\ the 2018 NSPS
Proposal TSD,\222\ and the 2020 NSPS Final TSD.\223\
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\218\ Drilling Information, Inc. 2014. DI Desktop. 2014
Production Information Database.
\219\ Gas Research Institute (GRI)/U.S. EPA. Research and
Development, Methane Emissions from the Natural Gas Industry, Volume
8: Equipment Leaks. June 1996 (EPA-600/R-96-080h).
\220\ EPA-HQ-OAR-2010-0505-5021.
\221\ EPA-HQ-OAR-2010-0505-7631.
\222\ EPA-HQ-OAR-2017-0483-0040.
\223\ EPA-HQ-OAR-2017-0483-2290.
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In this proposal, the EPA is shifting away from using model plants
for well sites for the BSER analysis and is instead using an individual
site-level emission-calculation approach in order to better
characterize and take into account the differences at individual well
sites that can lead to a vast range in the magnitude of fugitive
emissions, which a model plant cannot do. Provided below is a more
detailed explanation of the issues concerning the previous model plant
approach, followed by a description of the site-specific baseline
emission calculation approach, which is similar to the State of
Colorado's LDAR program.
In the 2020 Technical Rule, the EPA created separate model plants
to represent fugitive emissions from low production well sites (those
producing 15 boe or less per day) and non-low production well sites, as
it was generally assumed that low producing sites would have fewer
major production and processing equipment and thus lower fugitive
emissions. This prior estimate of baseline emissions was calculated
using model plant site designs with assumed populations of major
production and processing equipment and fixed fugitive emissions
component counts. While the estimated baseline emissions from the two
model plants differ due to the difference in the assumed populations of
major production and processing equipment and fixed fugitive emissions
component counts, the estimated baseline emissions were intended to
represent the baseline emissions for all well sites represented by each
model plant. Since that rulemaking, further analysis of existing and
new information indicates that there is significant variation in the
well characteristics, type of oil and gas products and production
levels, gas composition, operations, and types and quantity of
equipment at well sites across the U.S. The TSD for this action further
describes existing data and new information received since the 2020
Technical Rule that have been evaluated by the EPA to arrive at the
conclusion that there is no one-size-fits-all approach to predicting
emissions from well sites and that the emissions vary greatly, in ways
that bear little correlation to production levels alone. For example,
site-level methane emissions data from comprehensive studies sampled
across several different regions at numerous well sites, shows a wide
range of methane emissions (i.e., ranging from as low as 0 to as high
as 1,200 tpy for marginal or low production wells). Additionally,
recently obtained ICR data indicate that actual component counts at
well sites with equipment could be higher than those estimated by model
plants for low and non-low production, e.g., EPA's non-low model plant
could be underestimating number of wells, tanks and separators; and
similar observations were made for low production based on this data.
Contrary to previous general assumptions, information reviewed also
shows that it is not necessarily the case that fugitive emissions from
sites with lower production have lower emissions than sites with higher
production. In fact, it is quite possible that the inverse can be true
(i.e., lower producing sites could have higher emissions and inversely,
higher producing sites could have lower emissions.) More information
can be found in the NSPS OOOOb and EG TSD for this proposal.
Therefore, the EPA has concluded that the previous model plant
approach, which was based on two production levels (equal/above or
below 15 boe per day) and the estimated equipment types and numbers
associated with each of the two production levels, may not be
reflective of the actual baseline fugitive emissions from well sites.
Further, the potential for fugitive emissions at any given site is
impacted more by the number and type of equipment at the site and
maintenance practices, which can vary widely among well sites with low
production.\224\ Given these
[[Page 63188]]
limitations in utilizing model plants to analyze fugitive emission
reduction programs at well sites with widely varying configurations,
operations, and production levels, we find it appropriate to shift away
from using model plants and instead rely on the potential fugitive
emissions at the individual site in our BSER analysis and resulting
proposed standards. Therefore, this new analysis, which is described
below, is conducted on this basis.
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\224\ See https://pubs.acs.org/doi/10.1021/acs.est.0c02927,
https://data.permianmap.org/pages/flaring, and https://www.edf.org/sites/default/files/documents/PermianMapMethodology_1.pdf.
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This site-specific baseline emissions calculation approach is
similar to the State of Colorado's LDAR program. The concept is that
each site calculates its baseline methane emissions for all the
equipment at the site, the number and type of equipment at the well
site, the number of fugitive emissions components associated with each
piece of equipment, and the site-specific gas composition. The fugitive
monitoring frequency would be based on the baseline site-specific
methane emissions level calculated based on this information. This
calculation is described in detail in section XI.A.2. We believe that
this approach will more accurately depict the emissions profile at each
individual well site. As a result, the EPA is conducting the BSER
analysis based on site-level baseline methane emissions, where the
analysis is performed in increments of 1 tpy of site-level baseline
methane emissions as discussed more below.
During the rulemaking for the 2016 NSPS OOOOa, the EPA analyzed two
options for reducing fugitive methane and VOC emissions at well sites:
A fugitive emissions monitoring program based on individual component
monitoring using EPA Method 21 for detection combined with repairs and
a fugitive emissions monitoring program based on the use of OGI
detection combined with repairs. Finding that both methods achieve
comparable emission reduction but OGI was more cost effective, the EPA
ultimately identified semiannual monitoring of well sites using OGI as
the BSER. 81 FR 35856 (June 3, 2016). While there are several new
fugitive emissions technologies under development, the EPA needs
additional information to fully characterize the cost, availability,
and capabilities of these technologies, and they are therefore not
being evaluated as potential BSER at this time. However, we are
proposing the use of these technologies as an alternative screening
method as described in section XI.A.5. For this analysis for both the
NSPS and the EG, we re-evaluated the use of OGI as BSER. In the
discussion below, we evaluate OGI control options based on varying the
frequency of conducting the survey and fugitive emissions repair
threshold (i.e., the visible identification of methane or VOC when an
OGI instrument is used). For this analysis, we considered biennial,
annual, semiannual, quarterly, and monthly survey frequency for well
sites.
The regulatory concept for the proposed NSPS OOOOb is that the
required frequency of fugitive monitoring would be based on total site
baseline methane emissions. At well sites, the composition of gas is
predominantly methane (approximately 70 percent on average). Therefore,
as shown in our analysis, compared to VOC, methane better reflects the
baseline emission level where it is cost effective to regulate both
methane and VOC fugitive emissions at well sites. For this reason, we
chose to use methane as the threshold for our determination.
For the BSER analyses, we selected for evaluation total site-wide
methane emissions increments of 1 tpy of site-level baseline methane
emissions ranging from 1 tpy to 50 tpy. The EPA acknowledges that the
site-level baseline methane emissions calculated may not account for
the presence of large emission events when they occur. However, the EPA
has found it inappropriate to apply a factor that assumes every site is
experiencing a large emission event annually based on information
suggesting that only a small percentage of sites experience these
events at any given time.\225\
---------------------------------------------------------------------------
\225\ Brandt, A.R., Heath, G.A., Cooley, D. (2016). Methane
Leaks from Natural Gas Systems Follow Extreme Distributions.
Environ. Sci. Technol. 50, 12512, https://pubs.acs.org/doi/abs/10.1021/acs.est.6b04303; Zavala-Araiza, D., Alvarez, R., Lyon, D, et
al. (2016). Super-emitters in natural gas infrastructure are caused
by abnormal process conditions. Nat Commun 8, 14012 (2017). https://www.nature.com/articles/ncomms14012; Zavala-Araiza, D., Lyon, D.,
Alvarez, R. et al. (2015). PNAS 112, 15597. https://www.pnas.org/content/112/51/15597.
---------------------------------------------------------------------------
In 2015, we evaluated the potential emission reductions from the
implementation of an OGI monitoring program where we assigned an
emission reduction of 40, 60, and 80 percent to annual, semiannual, and
quarterly monitoring survey frequencies, respectively. The EPA re-
evaluated the control efficiencies under different monitoring
frequencies for the 2020 Technical Rule based on comments received on
the 2018 proposal and concluded that the assigned control efficiencies
described above can be expected from the corresponding monitoring
frequencies using OGI.\226\ No other information reviewed since that
time indicates that the assigned reduction frequencies are different
than previously established and the reduction efficiencies are
consistent with what current information indicates. In addition, we
also evaluated biennial survey frequency for well sites assuming an
achievable reduction frequency of 30 percent, and monthly monitoring
where information evaluated indicated monthly OGI monitoring has the
potential of reducing emissions up towards 90 percent.
---------------------------------------------------------------------------
\226\ See 85 FR 57412 and section 2.4.1.1 of the 2020 TSD.
---------------------------------------------------------------------------
It is worth noting that these calculations are based on the
expected reductions from ``typical'' component equipment leaks that
occur with well-maintained sites. The EPA is aware of situations where
equipment malfunctions related to equipment components can cause large
emission events that are described in detail in section XII.A.5. In
these cases, we expect the emission reductions associated with the
different monitoring frequencies evaluated would be significantly
higher than assumed above and is the reason we solicit comment on the
proposed alternative screening program using advanced measurement
technologies to identify and quantify large emission sources. Given the
intermittent and stochastic nature of large emission events, it is
difficult to apply emission factors that predict the probability of a
site experiencing these events within any timeframe. As stated above,
the EPA finds it inappropriate to apply a factor that assumes every
site is experiencing a large emission event annually given the
available data. However, we recognize that identifying and stopping
these large emission events is a central purpose of the monitoring
requirements proposed in this document, and that quantifying the
pollution reduction benefits associated with addressing these large
emission events is important to fully capture the benefits and cost-
effectiveness of our proposed fugitive emissions monitoring
requirements. We also acknowledge there is substantial ongoing research
on large emission events that may further inform the EPA's
calculations, including the potential to develop factors that take into
account a distribution of emissions across well sites and the
associated emissions reductions achieved when large emission events are
included in the calculation.
We evaluated the costs of a monitoring and repair program under
various monitoring frequencies. For
[[Page 63189]]
well sites, the capital costs associated with the fugitives monitoring
program were estimated to be $1,030 per well site. These capital costs
include the cost of developing the fugitive emissions monitoring plan
and purchasing or developing a recordkeeping data management system
specific to fugitive emissions monitoring and repair. Consistent with
the analyses used for the 2016 NSPS OOOOa and 2020 Technical Rule, the
EPA assumes that each company will develop a monitoring plan and
recordkeeping system that covers a company-defined area, which is
assumed to include 22 well sites. This assumption is used because there
are several elements of the fugitive monitoring program that are not
site-specific. The total company-defined area (22 well site) capital
costs are divided evenly to arrive at the $1,030 capital cost per well
site estimate.
When evaluating the annual costs of the fugitive emissions
monitoring and repair requirements (i.e., monitoring, repair, repair
verification, data management licensing fees, recordkeeping, and
reporting), the EPA considers costs at the individual site level.
Estimates for these costs were updated extensively as part of the 2020
Technical Rule, and the EPA has made further updates for this proposal
based on more recent information. With these updates, the estimated
annual costs of the fugitive emissions program at well sites are
estimated to range from $2,490 for biennial monitoring to $8,140 for
monthly monitoring.\227\ These total annual costs include annualization
of the up-front cost at 7 percent interest rate over 8 years. We note
these costs are representative of the average annual costs expected at
well sites, where larger sites may have larger costs associated with
longer surveys or potentially more repairs, while smaller sites may
experience the opposite with shorter surveys or potentially less
repairs. Therefore, we believe the costs developed for well sites are
representative of OGI fugitives monitoring program costs and reflect
the best information available at this time.
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\227\ As a comparison, the annualized costs for fugitive
emissions monitoring and repair at well sites were estimated to
range from $1,900 to $3,500 for annual to quarterly monitoring,
respectively, in the 2020 Technical Rule. See 2020 TSD, attachment 5
at Document ID No. EPA-HQ-OAR-2017-0483-2290.
---------------------------------------------------------------------------
The EPA requests comment on its range of cost estimates for an OGI
fugitives monitoring program. The EPA believes that there will be
sufficient supply of OGI equipment and available OGI camera operators
for industry to conduct all required monitoring, upon the effective
date of the NSPS OOOOb and the subsequent implementation of the EG
OOOOc. However, the EPA requests additional information on this
capacity and whether there is a likelihood of shortages in the early
years of the program that might raise costs. The EPA is also requesting
comment on the proposed appendix K and whether the proposed training,
certification, and audit provisions are appropriate and do not place
undue burden on the ability of industry to satisfy the regulatory
requirements.
At well sites, there are savings associated with the gas not being
released. The value of the natural gas saved is assumed to be $3.13 per
Mcf of recovered gas. Annual costs were also calculated considering
these savings.
As discussed in section XI.C, natural gas-driven intermittent
pneumatic controllers are designed to vent during actuation only, but
these devices are known to malfunction and operate incorrectly, which
causes them to release natural gas to the atmosphere when idle. The EPA
is proposing a zero VOC and methane emissions standard for natural gas-
driven intermittent pneumatic controllers. However, for sites in Alaska
located in the production segment (well sites, gathering and boosting
stations, and centralized tank batteries) and in the transmission and
storage segment that do not have electricity, the EPA is proposing a
standard wherein intermittent natural gas-driven pneumatic controllers
only vent during actuation and not when idle. See section XII.C on
pneumatic controllers for a full explanation of this standard. While
these intermittent controllers are their own separate affected
facility, we are proposing that they be monitored in conjunction with
the fugitive emissions components located at the same well site to
verify proper actuation and that venting does not occur during idle
times.
We created a matrix that includes, for each site-wide methane
emission level, the capital (up front) cost, annual costs (with and
without the consideration of savings), emission reductions for methane
and VOC, and cost effectiveness (dollar per tons of emission
reduction). Cost effectiveness was calculated using two approaches; the
single pollutant approach where all the costs are assigned to the
reduction of one pollutant; and the multipollutant approach, where half
the costs are assigned to the methane reduction and half to the VOC
reduction, see discussion in preamble section IX. This was repeated for
each site-wide methane emissions level for each monitoring frequency.
There were several trends shown in this matrix. As noted above, the
annual cost for each individual monitoring frequency is applied to all
site-wide emission levels when evaluating that frequency. Therefore, as
the emissions (and potential emission reductions) increased, the
fugitive emissions monitoring became more cost-effective. For example,
for semiannual monitoring, the cost effectiveness ranged from $5,300
per ton of methane reduced (for a 1 tpy site-wide methane site) to $100
per ton (for a 50 tpy site-wide methane site). Also, because the
emission reduction increase was greater than the cost increase with
increasing monitoring frequency, the fugitive emissions monitoring
became more cost-effective with increasing monitoring frequency. For
example, for a 10 tpy site-wide methane site, the methane cost
effectiveness for annual monitoring was $750 per ton, $530 per ton for
semiannual monitoring, and $525 per ton for quarterly monitoring. This
trend did not extend to monthly monitoring, as the cost of monthly
monitoring increases significantly (almost double) compared to
quarterly monitoring, while the emission reduction only increased by 10
percent. The complete matrix is available in the NSPS OOOOb and EG TSD
for this rulemaking.
The matrix shows that, on a multipollutant basis, both semiannual
and quarterly monitoring at well sites with baseline emissions as low
as 2 tpy is cost-effective, and that at 3 tpy, both semiannual and
quarterly monitoring are cost-effective based on the methane emissions
alone. Cost-effectiveness, however, is not the only relevant factor in
setting the BSER, particularly for a source as numerous and diverse as
well sites. We estimate that there will be approximately 21,000 new
wells each year (and 410,000 existing wells) to which the proposed
fugitive emissions requirements will apply.\228\ Various studies
demonstrate that the vast majority of emissions come from a relatively
small subset of wells.\229 230\
[[Page 63190]]
The EPA would like to ensure that resources and effort are focused on
those wells that emit the most methane and VOC. Moreover, given the
diversity of ownership, while our cost assumption that distributes the
costs of recordkeeping evenly across 22 sites within a company-defined
area is a reasonable estimate for the population as a whole, it may
underestimate the costs and therefore overestimate the cost-
effectiveness for owners with fewer than 22 well sites (and conversely,
underestimate cost-effectiveness for owners with more than 22 well
sites). In order to best focus resources and effort on the well sites
with the greatest emissions and more accurately capture costs,
particularly for owners with fewer well sites, the EPA requests comment
on the number of wells that likely emit at each baseline emissions
level, and the baseline emissions level of wells generally owned by
owners with few wells. The EPA anticipates that it may refine its BSER
determination for well sites through its supplemental proposal based on
the information gathered from commenters.
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\228\ Estimated well counts are based on non-wellhead only
sites. Based on information provided by API, we assume that 27% of
sites are wellhead only; see Memoranda for Meetings with the
American Petroleum Institute (API), September 23, 2021, located at
Docket ID No. EPA-HQ- OAR-2021-0317. Absent additional information,
we also assume that 27% of wells are wellhead only. The estimated
new well count reflects the arithmetic average of well counts over
the analysis horizon in the RIA, 2023-2035. The estimated existing
well count reflects the total in 2026, which is the first year that
we estimate impacts for the emissions guidelines.
\229\ Brandt, A., Heath, G., Cooley, D. (2016) Methane leaks
from natural gas systems follow extreme distributions. Environ. Sci.
Technol., DOI: 10.1021/acs.est.6b04303.
\230\ Zavala-Araiza, D., Alvarez, R., Lyon, D, et al. (2016).
Super-emitters in natural gas infrastructure are caused by abnormal
process conditions. Nat Commun 8, 14012 (2017). https://www.nature.com/articles/ncomms14012.
---------------------------------------------------------------------------
Taking these factors into account, and as explained in more detail
below, the EPA proposes to conclude that (1) BSER for well sites with a
baseline site-wide emissions level of less than 3 tpy is no regular
monitoring, but that to help ensure that these sites actually emit at
less than 3 tpy, a one-time survey (following each calculation of site-
level baseline methane emissions) would be required to ensure that any
abnormalities are addressed; (2) BSER for well sites with a baseline
site-wide emissions level of 3 tpy or greater is quarterly monitoring.
Because of the uncertainties discussed above, and as explained in more
detail below, the EPA further co-proposes to conclude that BSER for
well sites with a baseline site-wide emissions level of 3 tpy or
greater and less than 8 tpy is semiannual monitoring. Our co-proposal
is the same as our main proposal with regard to well sites whose
baseline site-wide emissions are less than 3 tpy (no regular
monitoring, but a one-time survey) and whose emissions are 8 tpy or
greater (quarterly monitoring). The EPA estimates that a majority of
fugitive emissions (approximately 86%) can be attributed to wells with
site-wide baseline emissions of 3 tpy or greater, where 54% can be
attributed to wells with site-wide baseline emissions of 8 tpy or
greater.\231\
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\231\ Percentages were estimated for the baseline scenario in
the RIA for the 2030 analysis year by combining the bin percentages
presented in RIA Table 2-4 with the projected well site activity
data documented in the RIA.
---------------------------------------------------------------------------
Proposed BSER for Well Sites with Baseline Emissions Less Than 3
tpy. As noted, in both our main proposal and our co-proposal, we
propose to conclude that BSER for well sites with baseline emissions of
less than 3 tpy is no regular monitoring, but a one-time survey to help
ensure that these sites actually emit at less than 3 tpy.
Based on the matrix described above, the EPA determined that where
total site baseline methane emissions are 2 tpy, semiannual and
quarterly monitoring costs approximately $2,700/ton methane reduced,
while biennial and annual monitoring costs approximately $4,000/ton
methane reduced. The costs for VOC reductions range from $10,000 to
$15,000/ton VOC reduced for quarterly to biennial monitoring,
respectively. These costs are outside the range of what we are
proposing to consider cost effective on a single-pollutant basis for
both methane and VOC. See Section IX.B. However, when considered on a
multipollutant basis, the costs of semiannual and quarterly monitoring
are approximately $1,350 per ton methane reduced, and approximately
$5,000 per ton of VOC, which we do consider cost-effective. Thus, for
sites with total baseline methane emissions of 2 tpy, we conclude that
regular monitoring at semiannual or quarterly frequencies would be
cost-effective.\232\
---------------------------------------------------------------------------
\232\ The NSPS OOOOb and EG OOOOc TSD also provide costs for
monitoring at 1 tpy, which is not considered cost-effective at any
frequency evaluated.
---------------------------------------------------------------------------
We do not propose to conclude that routine monitoring with OGI is
the BSER for sites with baseline emissions of less than 3 tpy, however,
for several reasons. While the estimates for semiannual and quarterly
monitoring are within what we consider to be cost effective for well
sites with baseline emissions of 2 tpy, in light of the large cohort of
relatively lower-emitting sites, we are concerned that our cost
effectiveness estimates may not accurately capture the costs, and
therefore cost-effectiveness, of routine monitoring with OGI for
businesses that own relatively few well sites. Throughout the
development of the 2016 NSPS OOOOa, and in subsequent analyses and
rulemaking actions, industry stakeholders have consistently stated that
the fugitive monitoring requirements are particularly burdensome for
smaller entities that own fewer well sites. The EPA believes that many
of these smaller entities are likely to own well sites with baseline
emissions of less than 3 tpy, a category that tends to include smaller
and less complex facilities with few or no major pieces of production
and processing equipment.\233\ And as noted, the EPA would like to
ensure that resources and effort are focused on well sites with
significant emissions. Given the possibility that our cost-
effectiveness analysis has overestimated the average number of sites,
and therefore underestimated the cost-effectiveness, for this cohort of
well sites, the EPA is proposing no regular monitoring at sites with
baseline site-wide emissions of less than 3 tpy.
---------------------------------------------------------------------------
\233\ Anna M. Robertson, Rachel Edie, Robert A. Field, David
Lyon, Renee McVay, Mark Omara, Daniel Zavala-Araiza, and Shane M.
Murphy. ``New Mexico Permian Basin Measured Well Pad Methane
Emissions Are a Factor of 5-9 Times Higher Than U.S. EPA
Estimates.''
Environmental Science & Technology 2020 54 (21), 13926-13934.
DOI: 10.1021/acs.est.0c02927.
---------------------------------------------------------------------------
While the EPA is proposing to conclude that BSER for well sites
with total site-level baseline methane emissions less than 3 tpy is no
regular monitoring, we believe it is essential to ensure that well
sites in this monitoring tier are operating in a well-controlled
manner, and are not experiencing leaks or malfunctions that would cause
their emissions to exceed 3 tpy. Therefore, the EPA is proposing a
requirement for owners and operators to conduct a survey, and perform
repairs as needed, to demonstrate that the well site is free of leaks
or malfunctions and is therefore operating in a manner consistent with
the baseline methane emissions calculation.\234\ This survey could
employ any method available that would demonstrate the actual emissions
are consistent with the baseline calculation, including, but not
limited to, the use of OGI, EPA Method 21 (which includes provisions
for a soap bubble test), or alternative methane detection technologies
like those discussed in the proposed screening alternative in section
XI.A.5.
---------------------------------------------------------------------------
\234\ We anticipate that during the survey to confirm their
baseline methane emissions and thus exemption status, sources would
also repair the leaks found, consistent with our understanding of
the standard industry practice.
---------------------------------------------------------------------------
The EPA seeks comment on all aspects of this proposed BSER
determination, including information, data, and analysis that would
shed further light on the factors and concerns just expressed and that
would support the establishment of ongoing monitoring requirements at
the cohort of sites with baseline methane emissions below 3 tpy. Among
other things, the EPA seeks
[[Page 63191]]
comment on the ownership profile of well sites with site-wide baseline
emissions less than 3 tpy, the extent to which well sites in this
cohort are owned by firms that own relatively few wells, and the
relative economic costs associated with requiring regular OGI
monitoring at these wells. The EPA also seeks information that would
improve our understanding of the overall number of wells that would
fall in this cohort of sites, and the contribution these wells make to
overall fugitive emissions. And the EPA seeks comment on our estimates
of the costs and emission reduction associated with OGI monitoring at
this cohort of sites, or other data and analysis that would provide
support for regular OGI monitoring at these sites. In addition, the EPA
notes that the advanced measurement technologies that form the basis of
our proposed alternative screening option in section XI.A.5 could be
particularly well-suited for rapidly and cost-effectively detecting
recurrences of large emitting events at sites with baseline emissions
below 3 tpy. Accordingly, the EPA seeks comment that could inform
whether to require the use of these technologies for ongoing monitoring
at this cohort of sites, including information on the capabilities of
these emerging technologies, methodologies for their use, and the costs
and emission reductions associated with using these advanced
measurement technologies as part of a mandatory monitoring regime. If
appropriate, and based on input received during the comment period, the
EPA may consider further addressing monitoring requirements for sites
with baseline emissions below 3 tpy as part of a supplemental proposal.
Additionally, the EPA is soliciting comment on different criteria,
such as the number of well sites owned by a specific owner, that could
better account for factors that may affect the costs of fugitive
emissions monitoring. As noted, while the EPA has presented costs on an
individual site-level, we have also distributed the costs of
recordkeeping evenly across an assumed 22 sites within a company-
defined area. While this may be appropriate for companies with larger
ownership, it is likely underestimating the cost (and overestimating
the cost-effectiveness) on owners with fewer sites. Information
provided on small businesses, including ownership thresholds, could be
used to further determine differences in OGI monitoring requirements at
well sites through a supplemental proposal.
Further, the EPA is soliciting comment on whether the presence of
specific major production and processing equipment types at a well site
warrants a separate monitoring frequency consideration even where the
calculated total site-level baseline methane emissions are below 3 tpy.
As mentioned throughout this preamble, the EPA is concerned about the
presence of large emission events, which various studies have shown are
most often attributed to specific equipment. This equipment includes
separators paired with onsite storage vessels, combustion devices, and
intermittent pneumatic controllers.235 236 237 Therefore,
the EPA is soliciting comment on whether well sites with these specific
types of equipment present must conduct at least semiannual monitoring,
regardless of the total site-level baseline methane emissions
calculated, including those sites calculated below 3 tpy.
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\235\ Id.
\236\ Tyner, David R., Johnson, Matthew R., ``Where the Methane
Is--Insights from Novel Airborne LiDAR Measurements Combined with
Ground Survey Data.'' Environmental Science & Technology 2021 55
(14), 9773-9783. DOI: 10.1021/acs.est.1c01572.
\237\ Rutherford, J.S., Sherwin, E.D., Ravikumar, A.P. et al.
Closing the methane gap in US oil and natural gas production
emissions inventories. Nat Commun 12, 4715 (2021). https://doi.org/10.1038/s41467-021-25017-4.
---------------------------------------------------------------------------
Finally, the EPA believes there is a subset of well sites (i.e.,
wellhead only well sites) that will never have baseline methane
fugitive emissions of 3 tpy or greater. Therefore, the proposed rule
would not define these sites as affected facilities, thus removing the
need for these sites to determine baseline emissions. As defined in the
2020 Technical Rule, a ``wellhead only well site'' is ``a well site
that contains one or more wellheads and no major production and
processing equipment.'' The term ``major production and processing
equipment'' is defined as including reciprocating or centrifugal
compressors, glycol dehydrators, heater/treaters, separators, and
storage vessels collecting crude oil, condensate, intermediate
hydrocarbon liquids, or produced water. As described earlier in this
section, sites will calculate their baseline methane emissions using a
combination of population-based emission factors and storage vessel
emissions. The population-based emission factors include emissions from
wellheads, reciprocating and centrifugal compressors, glycol
dehydrators, heater/treaters, separators, natural gas-driven pneumatic
pumps, and natural gas-driven pneumatic controllers (both continuous
and intermittent). By definition, a wellhead only well site would not
have emissions associated with the major production and processing
equipment, which includes storage vessels. Further, this proposed rule
would not allow the use of natural gas-driven pneumatic controllers at
any location (except on the Alaska North Slope), including wellhead
only well sites. Therefore, the only emissions would be calculated
based on the fugitive emissions components associated with the
wellhead, which we believe would never be above 3 tpy.
Proposed BSER for Sites with Baseline Emissions of 3 tpy or
Greater. The EPA next evaluated what frequency of OGI monitoring is
BSER for well sites where the total site-level baseline methane
emissions are 3 tpy or greater. Table 14 summarizes the cost-
effectiveness information for each monitoring frequency evaluated at
this threshold.
Table 14--Summary of Emission Reductions and Cost-Effectiveness for Site-Level Baseline Methane Emissions of 3 TPY
--------------------------------------------------------------------------------------------------------------------------------------------------------
Single-pollutant Multipollutant
Methane VOC emission ---------------------------------------------------------------
Monitoring frequency Annual cost emission reduction (tpy/ Methane cost- VOC cost- Methane cost- VOC cost-
($/yr/site) reduction site) effectiveness effectiveness effectiveness effectiveness
(tpy/site) ($/ton) ($/ton) ($/ton) ($/ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
3 tpy site-level baseline methaneemissions
--------------------------------------------------------------------------------------------------------------------------------------------------------
Biennial................................ $2,500 0.90 0.25 $2,800 $10,000 $1,400 $5,000
Annual.................................. 3,000 1.20 0.33 2,500 9,000 1,250 4,500
Semiannual.............................. 3,200 1.80 0.50 1,800 6,400 900 3,200
Quarterly............................... 4,200 2.40 0.67 1,800 6,300 900 3,200
Monthly................................. 8,100 2.70 0.75 3,000 11,000 1,500 5,400
--------------------------------------------------------------------------------------------------------------------------------------------------------
[[Page 63192]]
Based on the information summarized in Table 14, the average costs
per ton reduced appear to be reasonable for either semiannual or
quarterly monitoring when site-level baseline methane emissions are 3
tpy or greater under the single pollutant approach for methane
(biennial, annual, or monthly are outside of what the EPA considers
reasonable for VOCs in the single pollutant approach), or reasonable at
any frequency under the multipollutant approach.
In addition to considering the average costs per ton reduced for
these sites, the EPA also evaluated the incremental cost associated
with progressing to greater monitoring frequencies. To conduct this
analysis, the EPA first considered semiannual monitoring for these
sites as a baseline for comparison. Since 2016, owners and operators
have been conducting semiannual monitoring pursuant to NSPS OOOOa,
State requirements, or voluntarily, thus demonstrating the
reasonableness of that frequency. Additionally, the cost is comparable
to the costs found reasonable in the 2016 NSPS OOOOa \238\ for both the
single pollutant approach for methane or multipollutant approach for
both methane and VOC. To determine if quarterly monitoring is
reasonable for sites with total baseline methane emissions of 3 tpy, we
evaluated the incremental costs of going from semiannual to quarterly
monitoring. The incremental costs of semiannual to quarterly monitoring
for an emissions baseline of 3 tpy methane is $1,700/ton methane and
$6,000/ton VOC using the single pollutant approach (and $800/ton
methane and $3,000/ton VOC using the multipollutant cost effectiveness
approach). These incremental costs are within the range we find
reasonable in this proposal under the single pollutant approach for
methane and under the multipollutant approach.
---------------------------------------------------------------------------
\238\ The 2020 Technical Rule amended only the VOC standards in
the 2016 NSPS OOOOa and, as discussed in section X.A, incorrectly
identified $738/ton as the highest value that the EPA found cost
effective for methane reduction in the 2016 NSPS OOOOa.
---------------------------------------------------------------------------
We next evaluated monthly monitoring for this cohort. As shown in
Table 14, monthly monitoring appears reasonable under the
multipollutant approach. Therefore, we evaluated the incremental costs
of going from quarterly monitoring to monthly monitoring to determine
if monthly monitoring is appropriate. Table 15 summarizes these
incremental costs. As shown in Table 15, the incremental cost of going
from quarterly to monthly monitoring when baseline emissions are 3 tpy
is $13,000/ton methane and $47,000/ton VOC under the single pollutant
approach ($6,500/ton methane and $23,500/ton VOC under the
multipollutant approach). In both approaches, these costs are outside
the range of what we are proposing to consider cost effective. See
Section IX.B.
Based on the analysis described above, we propose to find that
quarterly monitoring at well sites with total site-level baseline
methane emissions of 3 tpy or greater is the BSER. We note that
California requires quarterly inspections for all well sites under its
LDAR requirements in Code of Regulations, Title 17, Division 3, Chapter
1, Subchapter 10 Climate Change, Article 4, Article Subarticle 13:
Greenhouse Gas Emission Standards for Crude Oil and Natural Gas
Facilities, which supports a conclusion that quarterly monitoring at
these sites is feasible and cost-effective.\239\
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\239\ https://ww2.arb.ca.gov/sites/default/files/classic/regact/2016/oilandgas2016/ogfro.pdf.
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Accordingly, the EPA's primary proposal is to conclude that BSER
for well sites with total site-level baseline emissions of less than 3
tpy is no regular monitoring (but a one-time survey) and that BSER for
well sites with total site-level baseline emissions of 3 tpy or greater
is quarterly monitoring and repair.
While the EPA is proposing quarterly OGI monitoring for well sites
with total site-level baseline methane emissions of 3 tpy or greater,
we are concerned this cost-effectiveness analysis may not fully account
for the numerosity and diversity of sites and their potential emission
profiles. We further note that some States with established fugitive
emissions monitoring programs have provided for more graduated
frequencies that recognize this diversity among sites. For example,
Colorado's Regulation 7 Control of Ozone via Ozone Precursors and
Control of Hydrocarbons via Oil and Gas Emissions \240\ requires a
tiered inspection frequency regime that provides for semiannual
monitoring at site-wide baseline emissions thresholds that far exceed
the EPA's proposed 3 tpy threshold. Under the Colorado regulations, a
semiannual inspection frequency is required for well production
facilities with uncontrolled actual VOC emissions between 2 and 12 tpy
(corresponding to approximately 7 to 43 tpy methane). Quarterly
inspections are required for well sites without storage tanks and with
uncontrolled actual VOC emissions between 12 and 20 tpy (corresponding
to approximately 43 to 72 tpy methane), and for well sites with storage
tanks and with uncontrolled actual VOC emissions between 12 and 50 tpy
(corresponding to approximately 43 to 180 tpy methane). Colorado
Regulation 7 also requires monthly inspections for well production
facilities without storage tanks with uncontrolled actual VOC emissions
above 20 tpy (and above 50 tpy for facilities with storage tanks). The
proposed thresholds for quarterly monitoring in this action are more
stringent than the Colorado regulations when compared using the gas
composition ratio of 0.28 VOC to methane that is used in our BSER
analysis. Specifically, the VOC emissions associated with a site-level
baseline methane emission rate of 3 tpy are 0.83 tpy VOC, less than
half the VOC threshold that requires semiannual monitoring and 14.5
times lower than the VOC threshold requiring quarterly monitoring in
Colorado.
---------------------------------------------------------------------------
\240\ https://cdphe.colorado.gov/aqcc-regulations.
---------------------------------------------------------------------------
Although Colorado's regulations are most directly comparable to the
EPA's proposed approach, other States also provide for more graduated
monitoring frequencies. For example, Ohio's General Permits 12.1 and
12.2 initially require quarterly monitoring for well sites, followed by
a reduced monitoring frequency of semiannual or annual monitoring
depending on the fraction of equipment found to be leaking.\241\
---------------------------------------------------------------------------
\241\ https://epa.ohio.gov/dapc/genpermit/oil-and-gas-well-site-production.
---------------------------------------------------------------------------
When considering these State programs, particularly the comparison
of our proposal to Colorado's thresholds; the fact that our cost-
effectiveness calculation may not account for the diversity of
emissions and sites; and the concerns we have raised regarding the
cost-effectiveness for businesses with fewer well sites than are
assumed in our cost-effectiveness analysis (many of whom we anticipate
are small businesses), the EPA believes it is also appropriate to co-
propose semiannual monitoring for well sites in a middle cohort--those
with total site-level baseline emissions of 3 tpy or greater and less
than 8 tpy. We seek comment on the number and ownership profile of
wells that would fall into this category to better understand whether
semiannual monitoring is an appropriate monitoring frequency for sites
in this range.
To inform this analysis, we evaluated methane emissions in 1 tpy
increments starting at 3 tpy. Tables 15a and 15b summarize the total
costs and incremental costs of semiannual to quarterly for baseline
methane
[[Page 63193]]
emissions of 3 tpy or greater and less than 8 tpy.
Table 15a--Summary of Total Cost-Effectiveness for Fugitive Monitoring at Well Sites
----------------------------------------------------------------------------------------------------------------
Single pollutant cost- Multipollutant cost-
effectiveness effectiveness
Site-level baseline methane Annual cost ($/---------------------------------------------------------------
emissions (tpy) yr/site) Methane ($/ Methane ($/
ton) VOC ($/ton) ton) VOC ($/ton)
----------------------------------------------------------------------------------------------------------------
Semiannual Monitoring
----------------------------------------------------------------------------------------------------------------
3............................... $3,200 $1,800 $6,400 $890 $3,200
4............................... 3,200 1,300 4,800 670 2,400
5............................... 3,200 1,100 3,800 530 1,900
6............................... 3,200 890 3,200 440 1,600
7............................... 3,200 760 2,700 380 1,400
8............................... 3,200 670 2,400 330 1,200
----------------------------------------------------------------------------------------------------------------
Quarterly Monitoring
----------------------------------------------------------------------------------------------------------------
3............................... 4,200 1,800 6,300 880 3,200
4............................... 4,200 1,300 4,700 660 2,400
5............................... 4,200 1,000 3,800 530 1,900
6............................... 4,200 880 3,200 440 1,600
7............................... 4,200 750 2,700 380 1,400
8............................... 4,200 660 2,400 330 1,200
----------------------------------------------------------------------------------------------------------------
Table 15B--Summary of Incremental Cost-Effectiveness for Fugitive Monitoring at Well Sites
----------------------------------------------------------------------------------------------------------------
Incremental Incremental cost-effectiveness
Incremental methane Incremental -------------------------------
Site-level baseline methane annual cost ($/ emission VOC emission
emissions (tpy) yr/site) reduction (tpy/ reduction (tpy/ Methane ($/ VOC ($/ton)
site) site) ton)
----------------------------------------------------------------------------------------------------------------
Incremental for semiannual to quarterly
----------------------------------------------------------------------------------------------------------------
3............................... $1,000 0.60 0.17 $1,700 $6,000
4............................... 1,000 0.80 0.22 1,250 4,500
5............................... 1,000 1.00 0.27 1,000 3,600
6............................... 1,000 1.20 0.33 840 3,000
7............................... 1,000 1.40 0.39 720 2,600
8............................... 1,000 1.60 0.45 630 2,250
----------------------------------------------------------------------------------------------------------------
While there is no obvious cutoff point, the EPA anticipates that
well sites with calculated baseline emissions of 8 tpy or greater will
generally consist of complex sites comprising multiple wellheads and/or
one or more of the major pieces of production or processing equipment
that are known to have a propensity for causing large emissions events.
The EPA also believes it is possible that at 8 tpy and greater, well
sites are both more likely to be owned by companies with a larger
number of sites and that the owners of these wells are likely to be
larger companies. Lastly, the EPA estimates that a large share of
fugitive emissions (approximately 54%) can be attributed to wells with
site-wide baseline emissions of 8 tpy or greater.\242\ For these
reasons, the EPA believes that an 8 tpy threshold for quarterly
monitoring would appropriately focus resources on the wells with the
largest emissions profiles, and that concerns about on the costs for
small owners or operators are most attenuated for this cohort of
relatively large and high-emitting sites. As noted above, we seek
comment on whether it is sensible to have a middle cohort with a
semiannual monitoring requirement and, if so, what the bounds of that
cohort should be. In making this determination, the EPA is particularly
interested in comments regarding the number and ownership profiles of
well sites that may fall into this middle cohort.
---------------------------------------------------------------------------
\242\ Percentage estimated using the analysis underpinning the
baseline scenario in the RIA for the 2030 analysis year.
---------------------------------------------------------------------------
As required by section 111, the EPA's proposed BSER analysis for
fugitive emissions from all well sites has considered nonair quality
health and environmental impacts. No secondary gaseous pollutant
emissions or wastewater are generated during the monitoring and repair
of fugitive emissions components. There are some emissions that would
be generated by contractors conducting the OGI camera monitoring
associated with driving to and from the site for the fugitive emissions
survey. Using AP-42 mobile emission factors and assuming a distance of
70 miles to the well site, the emissions generated from semiannual
monitoring at a well site (140 miles to and from the well site twice a
year) is estimated to be 0.35 lb/yr of hydrocarbons, 6.0 lb/yr of CO
and 0.40 lb/yr of NOx. No other secondary impacts are
expected. We do not believe these secondary emissions are so
significant as to affect the proposed determinations described above.
In summary, based on the analysis described above, the EPA is
proposing OGI monitoring based on tiered total site-wide baseline
methane emission levels to represent thresholds that would determine
the monitoring frequency. For well sites with total site-level methane
emissions less than 3 tpy,
[[Page 63194]]
the EPA is proposing to require a one-time survey to demonstrate that
the well site is free of leaks or other abnormal conditions that are
not accounted for in the baseline calculation. For well sites with
total site-level methane emissions of 3 tpy or greater, the EPA is
proposing quarterly monitoring at all sites. Lastly, the EPA is co-
proposing semiannual monitoring for well sites with total site-level
methane emissions of 3 tpy or greater and less than 8 tpy, and
quarterly monitoring for all sites with baseline emissions of 8 tpy or
greater. As noted earlier, site-level baseline emission levels would be
calculated by owners and operators for each site based on prescribed
population emission factors for components and equipment at the site,
combined with an assessment of potential methane emission from storage
vessels (after applying controls).
b. Fugitive Emissions From Compressor Stations
The EPA continues to utilize the model plant approach in estimating
baseline fugitive emissions from compressor stations. Unlike well
sites, we believe that compressor station designs are less variable and
that model plants are an effective construct to analyze fugitive
emission control programs. The EPA has evaluated feedback received from
several industry stakeholders related to development of compressor
station model plants over multiple years since the original 2015 NSPS
OOOOa proposal were model plants for compressor stations (including
those at gathering and boosting stations, transmission stations, and
storage facilities) were first introduced. Consistent with this early
approach for estimating emissions from compressor stations, the EPA
still believes the model plant approach is the best way to assess
fugitive emissions from compressor stations, in the absence of
information indicating otherwise. Baseline model plant emissions for
compressor stations can reasonably be calculated using equipment
counts, fugitive emissions component counts, and emissions factors from
the 1995 Emissions Protocol. The EPA has evaluated each specific model
plant for gathering and boosting, transmission, and storage, based on
information that has become available, and model plants were updated
where information indicated an update was appropriate. For example,
information from actual compressor stations in operation provided by
GPA Midstream for several of their member companies representing
numerous sites across the country, was used to refine the gathering and
boosting model plant in 2020. Refinements have also been made to the
transmission and storage model plants based on information received
from companies in these segments. The size and equipment located at
compressor stations do not vary as widely as at well sites, and
therefore emissions are expected to be less variable as well.
Furthermore, stakeholders have not indicated that a model plant
approach is not reasonable. For these reasons, the EPA retains a model
plant approach for compressor stations which are representative in
estimating fugitive emissions.
There are three types of compressor stations in the Crude Oil and
Natural Gas source category: (1) Gathering and boosting stations, (2)
transmission stations, and (3) storage stations. The equipment
associated with these compressor stations vary depending on the volume
of natural gas that is transported and whether any treatment of the gas
occurs, such as the removal of water or hydrocarbons. The model plants
developed for these sites include all equipment (including piping and
associated components, compressors, generators, separators, storage
vessels, and other equipment) and associated components (e.g., valves
and connectors) that may be sources of fugitive emissions associated
with these operations. One model plant was developed for each of the
three types of compressor stations described above, which are discussed
in detail in the 2020 NSPS OOOOa TSD and in the NSPS OOOOb and EG TSD
supporting this action. For gathering and boosting stations, the
fugitive baseline emissions were estimated to be 16.6 tpy of methane
and 4.6 tpy of VOC. For transmission stations, the fugitive baseline
emissions were estimated to be 40.4 tpy of methane and 1.1 tpy of VOC.
For storage stations, the fugitive baseline emissions were estimated to
be 142.2 tpy of methane and 3.9 tpy of VOC.
As with well sites, in the original BSER analysis for the 2016 NSPS
OOOOa rulemaking, two options for reducing fugitive methane and VOC
emissions at compressor stations were identified, which were (1) a
fugitive emissions monitoring program based on individual component
monitoring using EPA Method 21 for detection combined with repairs and
(2) a fugitive emissions monitoring program based on the use of OGI
detection combined with repairs. Finding that both methods achieve
comparable emission reduction but OGI was more cost effective, the EPA
ultimately identified quarterly monitoring of compressor stations using
OGI as the BSER. 81 FR 35862. While there are several new fugitive
emissions technologies under development, the EPA needs additional
information and better understanding of these technologies, and they
are therefore not being evaluated as potential BSER at this time. For
this analysis for both the NSPS and the EG, we re-evaluated OGI as
BSER. In the discussion below, we evaluate OGI control options based on
varying the frequency of conducting the survey and fugitive emissions
repair threshold (i.e., the visible identification of methane or VOC
when an OGI instrument is used). For this analysis, we considered
annual, semiannual, quarterly, and monthly survey frequency for
compressor stations.
In 2015, we evaluated the potential emission reductions from the
implementation of an OGI monitoring program where an emission reduction
of 40, 60 and 80 percent for annual, semiannual, and quarterly
monitoring survey frequencies, respectively, were determined
appropriate. No other information reviewed since 2015 indicates that
the assigned reduction frequencies are different than previously
established and the reduction efficiencies are consistent with what
current information indicates. In addition, we also evaluated monthly
monitoring for compressor stations where information evaluated
indicated monthly OGI monitoring has the potential of reducing
emissions up towards 90 percent.
We evaluated the costs of monitoring and repair under various
monitoring frequencies described above, including the cost of OGI
monitoring via the camera survey, repair costs, resurvey costs,
monitoring plan development and the cost of a recordkeeping system. For
compressor stations, the capital cost associated with the fugitives
monitoring program were estimated to be $3,090 for each gathering and
boosting compressor station, which includes development of a fugitive
emissions monitoring plan for a company-defined area (assumed to
include 7 gathering and boosting compressor stations) and database
management development or licensing for recordkeeping. These capital
costs are divided evenly amongst the 7 gathering and boosting
compressor stations in the company-defined area for purposes of the
model plant analysis, consistent with the 2016 NSPS OOOOa and 2020
Technical Rule analyses. The capital cost associated with the fugitives
monitoring program for transmission and storage compressor stations was
estimated at $23,880, which is for a single transmission and storage
compressor station. The annual costs
[[Page 63195]]
include the capital recovery cost (calculated at a 7 percent interest
rate for 10 years), survey and repair costs, database management fees,
and recordkeeping and reporting costs. The annual costs estimated for
compressor stations range from $6,350 for annual monitoring to $33,220
for monthly monitoring at gathering and boosting compressor stations.
For transmission compressor stations, the annual costs estimated range
from $12,900 for annual monitoring to $39,770 for monthly monitoring.
For storage compressor stations, the annual costs estimated range from
$17,000 for annual monitoring to $43,860 for monthly monitoring.
As discussed above, the EPA is proposing that natural gas-driven
intermittent vent controllers at production and natural gas
transmission sites in Alaska without electricity would be subject to a
standard that prohibits emissions when the controller is idle.
Intermittent pneumatic controllers are designed to vent during
actuation only, but these devices are known to malfunction and operate
incorrectly which causes them to release natural gas to the atmosphere
when idle. For sites in Alaska that do not have electricity located in
the production segment (well sites, gathering and boosting stations,
and centralized tank batteries) and in the transmission and storage
segment, the EPA is proposing to define intermittent natural gas-driven
pneumatic controllers as an affected facility and proposing to apply a
standard that these controllers only vent during actuation and not when
idle. See section XII.C on pneumatic controllers for a full explanation
of this standard. We have determined that it would be efficient and
reasonable to verify proper actuation and that venting does not occur
during idle times by proposing that these devices are monitored along
with fugitive emissions components at a site to ensure these devices
are meeting the standard. We believe the cost of monitoring of
intermittent pneumatic controllers will be absorbed by the cost of the
fugitive emissions program, and that little to no additional cost would
be associated with monitoring these devices on the fugitive emissions
components monitoring schedule. If compressor stations have
electricity, they would be required to have non-emitting controllers,
and no additional costs are expected to be incurred relayed to repair
and/or replacement of malfunctioning intermittent vent controllers.
At gathering and boosting compressor stations there are savings
associated with the gas not being released. The value of the natural
gas saved is assumed to be $3.13 per Mcf of recovered gas. Transmission
and storage compressor stations do not own the natural gas; therefore,
revenues from reducing the amount of natural gas emitted/lost was not
applied for this segment.
The EPA evaluated the cost-effectiveness of monitoring for each
sub-type of compressor station, starting with evaluating whether
quarterly monitoring remains the BSER. The 2016 NSPS OOOOa requires a
fugitive emissions monitoring and repair program, where compressor
stations have to be monitored quarterly. Compressor stations have
successfully met this standard. Further, several State agencies have
rules that require quarterly monitoring at compressor stations. For
example, Colorado's Regulation 7 Control of Ozone via Ozone Precursors
and Control of Hydrocarbons via Oil and Gas Emissions \243\ requires a
semiannual inspection frequency for compressor stations with
uncontrolled actual VOC emissions between 2 and 12 tpy, a quarterly
inspection frequency for compressor stations with uncontrolled actual
VOC emissions between 12 and 50 tpy, and monthly inspections for
compressor stations with uncontrolled actual VOC emissions above 50
tpy. California requires quarterly inspections under their LDAR
requirements \244\ and similarly, Ohio's General Permit 18.1 also
requires quarterly monitoring for compressor stations.\245\ These
examples of State rules, where quarterly monitoring appears to be the
lowest monitoring frequency required with one exception where the VOC
baseline emissions were extraordinarily high, is a demonstration of the
reasonableness of monitoring fugitive emissions components on a
quarterly basis for compressor stations.
---------------------------------------------------------------------------
\243\ https://cdphe.colorado.gov/aqcc-regulations.
\244\ https://ww2.arb.ca.gov/sites/default/files/classic/regact/2016/oilandgas2016/ogfro.pdf.
\245\ https://www.epa.state.oh.us/dapc/genpermit/ngcs/GP_181.
---------------------------------------------------------------------------
Given the apparent reasonableness of quarterly monitoring as
discussed above, the EPA evaluated whether it was reasonable to require
monthly monitoring for compressor stations. Table 16 summarizes the
cost, emission reductions, and cost-effectiveness of quarterly and
monthly OGI monitoring at compressor stations for the single pollutant
approach, while Table 17 summarizes the multi-pollutant approach.
Table 16--Summary of the Single Pollutant Cost of Control for Compressor Station Fugitive Emissions Monitoring
--------------------------------------------------------------------------------------------------------------------------------------------------------
Emission reductions Methane cost VOC cost of
Capital cost Annual cost ($/ Annual cost w/ -------------------------------- of control w/o control w/o
Model plant ($) yr) savings ($/yr) Methane (tons/ savings ($/ savings ($/
yr) VOC (tons/yr) ton) ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Quarterly Monitoring
--------------------------------------------------------------------------------------------------------------------------------------------------------
Gathering & Boosting.................... $3,100 $13,400 $11,000 13.3 3.7 $1,000 $3,600
Transmission............................ 23,900 19,900 19,900 32.3 0.9 600 22,300
Storage................................. 23,900 24,000 24,000 114.0 3.2 200 7,600
---------------------------------------------------------------------------------------------------------------
Compressor Program Weighted Average. .............. .............. .............. .............. .............. 900 4,400
---------------------------------------------------------------------------------------------------------------
Monthly Monitoring
--------------------------------------------------------------------------------------------------------------------------------------------------------
Gathering & Boosting.................... 3,100 33,200 30,500 15.0 4.2 2,200 8,000
Transmission............................ 23,900 39,800 39,800 36.4 1.0 1,100 39,500
Storage................................. 23,900 43,900 43,900 128.2 3.5 340 12,400
---------------------------------------------------------------------------------------------------------------
Compressor Program Weighted Average. .............. .............. .............. .............. .............. 1,800 9,300
--------------------------------------------------------------------------------------------------------------------------------------------------------
[[Page 63196]]
Table 17--Summary of the Multi-Pollutant Cost of Control for Compressor Station Fugitive Emissions Monitoring
--------------------------------------------------------------------------------------------------------------------------------------------------------
Emission reductions Methane cost VOC Cost of
Capital cost Annual cost ($/ Annual cost w/ -------------------------------- of control w/o control w/o
Model plant ($) yr) savings ($/yr) Methane (tons/ savings ($/ savings ($/
yr) VOC (tons/yr) ton) ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Quarterly Monitoring
--------------------------------------------------------------------------------------------------------------------------------------------------------
Gathering & Boosting.................... $3,100 $13,400 $11,000 13.3 3.7 $500 $1,800
Transmission............................ 23,900 19,900 19,900 32.3 0.9 300 11,100
Storage................................. 23,900 24,000 24,000 114.0 3.2 100 3,800
---------------------------------------------------------------------------------------------------------------
Compressor Program Weighted Average. .............. .............. .............. .............. .............. 430 2,200
---------------------------------------------------------------------------------------------------------------
Monthly Monitoring
--------------------------------------------------------------------------------------------------------------------------------------------------------
Gathering & Boosting.................... 3,100 33,200 30,500 15.0 4.2 1,100 4,000
Transmission............................ 23,900 39,800 39,800 36.4 1.0 550 19,800
Storage................................. 23,900 43,900 43,900 128.2 3.5 200 6,200
---------------------------------------------------------------------------------------------------------------
Compressor Program Weighted Average. .............. .............. .............. .............. .............. 900 4,600
--------------------------------------------------------------------------------------------------------------------------------------------------------
Based on the single pollutant approach, both quarterly and monthly
frequencies are reasonable for methane emissions, while only quarterly
is reasonable for VOC emissions. Like described for well sites, owners
and operators of compressor stations have been monitoring quarterly
since 2016 pursuant to NSPS OOOOa, State requirements, or voluntarily,
which suggests these costs are reasonable. These costs for quarterly
monitoring are also comparable to those found reasonable in both the
2016 NSPS OOOOa and the 2020 Technical Rule. Further, both frequencies
are reasonable under the multipollutant approach when considering the
total cost-effectiveness compared to a baseline of no OGI monitoring.
The EPA then looked at the incremental costs of going from
quarterly to monthly monitoring. Quarterly monitoring achieves an
emission reduction ranging from 13.3 tpy at gathering and boosting
compressor stations to 114 tpy at storage compressor stations. Monthly
monitoring achieves additional reductions ranging from 1.7 tpy at
gathering and boosting compressor stations to 14.2 tpy at storage
compressor stations. However, these additional reductions are achieved
at $9,400/ton methane (and nearly $50,000/ton VOC). The EPA finds that
achieving these additional emissions reductions is not reasonable for
the cost, given the only small fraction of additional reductions
realized at monthly monitoring. Based on the cost analysis summarized
above, we find that the cost effectiveness of quarterly monitoring for
compressor stations is reasonable.
Finally, no secondary gaseous pollutant emissions or wastewater are
generated during the monitoring and repair of fugitive emissions
components. There are some emissions that would be generated by the OGI
camera monitoring contractors with respect to driving to and from the
site for the fugitive emissions survey. Using AP-42 mobile emission
factors and assuming a distance of 70 miles to the compressor station,
the emissions generated from quarterly monitoring at a compressor
station (140 miles to and from the compressor station four times a
year) is estimated to be 0.70 lb/yr of hydrocarbons, 12.0 lb/yr of CO
and 0.80 lb/yr of NOX. No other secondary impacts are
expected.
In light of the above, we find that the BSER for reducing methane
and VOC emissions from all compressor stations, including gathering and
boosting stations, transmission stations, and storage stations is
quarterly monitoring for this proposal. Therefore, for NSPS OOOOb, we
are proposing to require quarterly monitoring for all compressor
stations.
2. EG OOOOc
The EPA also evaluated BSER for the control of fugitive emissions
at existing well sites and compressor stations. The findings were that
the controls evaluated for new sources for NSPS OOOOb are appropriate
for consideration under the EG OOOOc. Further, the EPA finds that the
OGI monitoring, methane emission reductions, costs, and cost
effectiveness results discussed above for new sources are also
applicable for existing sources.
Therefore, for the EG OOOOc, the EPA is proposing presumptive
standards to require quarterly monitoring for well sites with site-
level baseline methane emissions greater than and equal to 3 tpy.
Further, we are co-proposing semiannual monitoring for well sites with
site-level baseline methane emissions greater than and equal to 3 tpy
and less than 8 tpy, and quarterly monitoring for well sites with site-
level baseline methane emissions greater than and equal to 8 tpy. We
find the costs reasonable for existing well sites with total site-level
baseline methane emissions greater than or equal to 3 tpy to conduct
quarterly OGI monitoring at an incremental cost of $1,700/ton methane
reduced. We are aware that there is a large percentage of existing well
sites that are likely owned and operated by small businesses. We
continue to be concerned about the burden of frequent OGI monitoring on
these small businesses and are requesting comment consistent with our
solicitation for new sources.
The EPA also finds, and is proposing, that the BSER for reducing
methane emissions from all existing compressor stations, including
gathering and boosting stations, transmission stations, and storage
stations is quarterly monitoring. For compressor stations, we find that
both quarterly (at $430/ton methane reduced) and monthly monitoring (at
$900/ton methane reduced) are reasonable when looking at total cost-
effectiveness against a baseline of no monitoring, however, at an
incremental cost of $9,400/ton methane reduced, monthly monitoring is
not reasonable. Therefore, for the EG OOOOc, we are proposing a
presumptive standard of quarterly monitoring for all compressor
stations.
[[Page 63197]]
3. Alternative Screening Using Advanced Measurement Technology
As discussed throughout this preamble, the EPA recognizes the
existence large emission events. In certain instances, these situations
could be caused by severely and continuously leaking components that
would be identified and corrected via the routine OGI-based periodic
monitoring program, but only on a quarterly or semiannual basis.
Moreover, some large emission events are intermittent and stochastic in
nature and may not be identified via these OGI surveys. Since the 2016
NSPS OOOOa, significant strides have occurred in developing and
deploying methane detection technologies that can detect fugitive
emissions (especially large emission events) in a potentially faster
and more cost-effective manner than traditional techniques such as OGI
and EPA Method 21. The EPA has continued following the development of
these technologies and their applications through various public
programs, such as the DOE ARPA-E programs, which have focused on the
development of cost-effective tools to locate and measure methane
emissions. Additionally, the EPA has continued discussions with
stakeholders, including academic researchers and private industry, as
they develop and evaluate novel tools for the detection and
quantification of methane emissions in the oil and gas sector. As noted
in section VII.B, the EPA also held a two-day workshop in August 2021
to hear perspectives on these new technologies. Some of the promising
technologies now emerging include, but are not limited to, fixed-base
and open path sensor networks, unmanned aircraft systems (UAS) equipped
with methane detection equipment, the use of high-end instruments for
mobile measurements on the ground and in the air, and satellite
observations with advanced optical techniques.
As the EPA learned during the Methane Detection Technology
Workshop, industry has utilized these advanced measurement technologies
to supplement existing fugitive emissions programs and to quickly
identify unexpected emissions events (e.g., emissions from controlled
storage vessels) in order to make repairs as quickly as possible.\246\
While most of these advanced measurement technologies are not sensitive
enough to pin-point the exact same emission sources as the current
fugitive emission detection programs, many can more quickly detect the
largest emissions sources (e.g., malfunctions and undersized or non-
performing major equipment), and they can also find emissions that may
be missed by fugitive emission surveys (e.g., component-level leaks on
valves, connectors, and meters). Moreover, the EPA understands the
stochastic nature, distribution, and frequency of these large emission
events across sites and over time is uncertain, and that these events
occur sporadically at an individual site in ways that may take longer
to detect or might not be detected through a periodic fugitive
emissions survey using traditional technologies. Integrating advanced
emission detection technologies into this rule--whether deployed by
owner-operators themselves or by third parties--could be a valuable way
to reduce fugitive emissions more cost-effectively and rapidly detect
and remedy ``super-emitting'' events that make an outsize contribution
to overall emissions from this source category.
---------------------------------------------------------------------------
\246\ See summary report of the EPA's Methane Detection Workshop
located at Docket ID No. EPA-HQ-OAR-2021-0317.
---------------------------------------------------------------------------
There are many other advantages to these advanced measurement
technologies over technologies currently used for fugitive emissions
detection (i.e., OGI and EPA Method 21 technologies). For instance,
these advanced measurement technologies may be less susceptible to
operator error or judgment than traditional methods of leak detection,
thus making surveys more consistent and reliable. Many of these
technologies can survey broader areas than can be effectively surveyed
with field personnel, drastically reducing the driving time from site
to site, which could have potential cost and safety benefits and allow
for more frequent monitoring, which could allow for the identification
and mitigation of large volume methane emissions sooner than OGI or EPA
Method 21 surveys.
As described in section XI.A.5, the EPA is proposing an alternative
work practice for detecting fugitive emissions that incorporates these
advanced measurement technologies. There were a number of presentations
during the Methane Detection Technology Workshop that discussed the
detection capabilities of various methane measurement technologies
which could be used for a screening approach. Given the diverse array
of advanced technologies that are now in use, and the rapid pace at
which these technologies are being refined and new technologies are
being developed, the EPA believes that it is appropriate to articulate
a foundational set of performance criteria and documentation
requirements for this alternative work practice that can be applied to
multiple existing and forthcoming technologies. Based on the
information available to the Agency, including the information
presented in the Methane Detection Technology Workshop, the EPA
believes setting a minimum detection threshold of 10 kg/hr methane
might be appropriate for use in determining what technologies and in
what deployment platforms (e.g., fixed, ground and aerial) are
appropriate for a potential screening alternative within the proposed
NSPS OOOOb and EG OOOOc. Therefore, the specific alternative work
practice that the EPA is proposing includes a provision that would
allow the use of any technology with a minimum detection threshold of
10 kg/hr.
Although we have focused this discussion on advanced measurement
technologies, the EPA is also soliciting comment on whether there are
ways to utilize existing technologies to screen for large emission
events. For example, could gauges or meters be utilized to identify
potential large losses between the wellhead and the custody meter
assembly.
Further, the EPA is seeking comment on very simple AVO checks that
could be performed in conjunction with the periodic OGI monitoring
surveys to help identify potential large emission events. For example,
two often-cited causes of super-emitter sources are unlit flares and
separator dump valves that are stuck open allowing unintentional gas
carry-through to emit from storage vessels. The additional time and
cost required to perform visual inspections to see if the flare pilot
light is working, or to see if a dump valve is stuck open, would be
minimal. Yet the benefits of simple AVO inspections could be
significant. The EPA is soliciting comment on this concept, as well as
comments on the common items that could be included on a checklist for
such low-burden AVO inspections in conjunction with fugitive
monitoring.
B. Proposed Standards for Storage Vessels
1. NSPS OOOOb
a. Background
In the 2012 NSPS OOOO, the EPA established VOC standards for
storage vessels. Based on our review of these standards, we are
proposing to retain the current standard of 95 percent reduction.
However, the EPA is proposing to redefine the affected facility to
include a tank battery. Specifically, the EPA is proposing to define a
storage vessel affected facility as a single storage vessel or a group
of storage vessels that are physically adjacent and that receive fluids
from the
[[Page 63198]]
same source (e.g., well, process unit, or set of wells or process
units) or manifolded together for the transfer of liquid or vapors. In
this definition, we consider tanks to be physically adjacent when they
are near or next to each other and may or may not be connected or piped
together. In addition, the EPA is proposing methane standards for new,
reconstructed, and modified storage vessels under the proposed NSPS
OOOOb. Both the proposed revised VOC standards and the proposed methane
standards would be the same (i.e., 95 percent reduction of emissions
from storage vessel affected facilities as defined above in this
proposal). These reductions can be achieved by utilizing a cover and
closed vent system to capture and route the emissions to a control
device that achieves an emission reduction of 95 percent, or by routing
the captured emissions to a process.
Both methane and VOC emissions from storage vessels are a result of
working, breathing and flashing losses. Working losses occur when
vapors are displaced due to the emptying and filling of storage
vessels. Breathing losses are the release of gas associated with daily
temperature fluctuations when the liquid level remains unchanged.
Flashing losses occur when a liquid with dissolved gases is transferred
from a vessel with higher pressure (e.g., separator) to a vessel with
lower pressure (e.g., storage vessel), thus allowing dissolved gases
and a portion of the liquid to vaporize or flash. In the Crude Oil and
Natural Gas source category, flashing losses occur when crude oils or
condensates flow into a storage vessel from a separator operated at a
higher pressure. Typically, the higher the operating pressure of the
upstream separator, the greater the flash emissions from the storage
vessel. Temperature of the liquid may also influence the amount of
flash emissions. Lighter crude oils and condensate generally flash more
hydrocarbons than heavier crude oils.
b. Definition of Affected Facility
The current standards apply to single storage vessels with
potential VOC emissions of 6 tpy or greater, although the EPA has long
observed that these storage vessels are typically located as part of a
tank battery. 76 FR 52738, 52763 (Aug. 23, 2011). Further, the 6 tpy
applicability threshold was established by directly correlating VOC
emissions to throughput, was based on the use of a single combustion
control device, regardless of the number of storage vessels routing
emissions to that control device, and control of 6 tpy VOC was cost
effective using that single control device. Id. at 52763-64. Over the
years, there have been questions and issues raised regarding how to
calculate the potential VOC emissions from individual storage vessels
that are part of a tank battery. The EPA attempted to address this
issue through various amendments to NSPS OOOO and NSPS OOOOa,\247\ most
recently in the 2020 Technical Rule. In the 2020 Technical Rule, the
EPA continued to recognize that tank batteries are more prevalent than
individual storage vessels. While the 2020 Technical Rule included
amendments to the calculation methodology for determining potential VOC
emissions from storage vessels that are part of a tank battery, the EPA
has now determined that it is more appropriate to evaluate the control
of methane and VOC emissions from tank batteries \248\ as a whole
instead of each individual storage vessel within a tank battery.\249\
In this review the EPA evaluated regulatory options based on the use of
a single control device to reduce both methane and VOC emissions from a
tank battery, which is consistent with the 2012 NSPS OOOO, 2016 NSPS
OOOOa, and subsequent amendments to each of those rules. The EPA
believes that this approach will simplify applicability criteria for
owners and operators of storage vessels, and more accurately aligns
with the EPA's original intent of how storage vessel affected facility
status should be determined.
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\247\ See 79 FR 79018 and 80 FR 48262.
\248\ For purposes of this analysis and the resulting proposed
standards, the term ``tank battery'' refers to a single storage
vessel or a group of storage vessels that are physically adjacent
and that receive fluids from the same source (e.g., well, process
unit, or set of wells or process units) or which are manifolded
together for liquid or vapor transfer.
\249\ This approach would no longer allow facilities to apply
certain criteria and average the total potential VOC emissions of
the tank battery across the number of storage vessels in the battery
to determine a per-vessel potential for VOC emissions.
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c. Modification
Section 60.14(a) of the general provisions to part 60 defines
modification as follows: ``Except as provided in paragraphs (e) and (f)
of this section, any physical or operational change to an existing
facility which results in an increase in the emission rate to the
atmosphere of any pollutant to which a standard applies shall be
considered a modification. . . .'' We also note that 40 CFR 60.14(f)
states that ``Applicable provisions set forth under an applicable
subpart of this part shall supersede any conflicting provisions of this
section.'' The EPA understands the difficulty assessing emissions from
storage vessels and seeks to provide clarity on actions that are
considered modification of a tank battery by explicitly listing these
in the proposed NSPS OOOOb. We evaluated circumstances that would lead
to an increase in the VOC and methane emissions from a tank battery and
therefore constitute a modification of an existing tank battery. A
modification of an existing tank battery would then require the tank
battery owner or operator to assess the potential emissions relative to
the proposed NSPS instead of the EG.
The EPA is proposing that a single storage vessel or tank battery
is modified when any of the following physical or operational changes
are made: (1) The addition of a storage vessel to an existing tank
battery; (2) replacement of a storage vessel such that the cumulative
storage capacity of the existing tank battery increases; and/or (3) an
existing single storage vessel or tank battery that receives additional
crude oil, condensate, intermediate hydrocarbons, or produced water
throughput (from actions such as refracturing a well or adding a new
well that sends these liquids to the tank battery). For both items 1
and 2, even if the type and quantity of fluid processed remains the
same, the increased storage capacity will lead to higher breathing
losses and thereby increase the VOC emissions from the tank battery
relative to the VOC emissions prior to the vessel addition or
replacement. Therefore, we conclude that these actions are a
modification of the tank battery. However, we are soliciting comment to
help us better understand the effect of the proposed definition number
1 and 2 on the number of new storage vessels or tank batteries that
would be subject to the NSPS. Under the current definition of a storage
vessel affected facility in NSPS OOOOa, which is each single storage
vessel that meets the 6 tpy applicability threshold, a new storage
vessel that is installed in an existing tank battery is an affected
facility (assuming the 6 tpy applicability threshold is met for the
single storage vessel) whether the new storage vessel is a replacement
or an addition to the tank battery. However, under the proposed
definition number 1 and 2 above, the NSPS OOOOb is triggered only if
the new storage vessel is an addition to the tank battery or is of
bigger capacity than the storage vessel it is replacing in a tank
battery. We therefore solicit comment on how often a storage vessel in
a tank battery is replaced with one that is of bigger capacity, or
whether the need to increase a tank battery's capacity is
[[Page 63199]]
generally accomplished by adding storage vessels as opposed to
replacing an existing one with a bigger one. We further solicit comment
on whether, under our proposed definition of a tank battery (i.e., a
single storage vessel or a group of storage vessels that are physically
adjacent and that receive fluids from the same source (e.g., well,
process unit, or set of wells or process units)), the replacement of a
storage vessel in a tank battery should also require the assessment of
the potential VOC and methane emissions from the tank battery.
Item 3 will increase the volumetric throughput of the tank battery
relative to the throughput prior to storage of the additional fluid.
This will increase the working losses and potentially increase the
flashing losses from the tank battery, depending on the properties of
the new fluid stream. In any event, adding a new fluid stream to an
existing tank battery increases the VOC emissions from that tank
battery relative to just prior to the addition of a new fluid stream
and is therefore considered a modification of the tank battery.
The EPA is proposing to require that the owner or operator
recalculate the potential VOC emissions when any of these actions occur
on an existing single storage vessel or tank battery to determine if
the modification may require control of VOC emissions. The existing
single storage vessel or tank battery will only become subject to the
proposed NSPS if it is modified pursuant to this proposed definition of
modification and its potential VOC emissions exceed the proposed 6 tpy
VOC emissions threshold for the tank battery.
d. Technology Review
The available control techniques for reducing methane and VOC
emissions from storage vessels include routing the emissions from the
storage vessels to a combustion control device or a VRU, which would
route the emission to a process (including a gas sales line). These are
the same control systems that were evaluated under the 2012 NSPS OOOO.
While floating roofs can also be used to reduce emissions from many
storage vessel applications, including at natural gas processing plants
and compressor stations, floating roofs are not effective at reducing
emissions from storage vessels that have flashing losses (e.g., storage
vessels at well sites or centralized production facilities). Besides
the control options described above, we did not find other available
control options through our review, including review of the RACT/BACT/
LAER Clearinghouse.
In the development of the 2012 NSPS OOOO, we found that using
either a VRU or a combustion control device could achieve a 95 percent
or higher VOC emission reduction efficiency. Available information
since then continues to support that such devices can achieve a 95
percent control efficiency for both methane and VOC emissions. We are
not proposing to require higher control efficiency because, in order to
achieve a minimum of 95 percent control efficiencies on a continuous
basis, operators will need to design and operate the control to achieve
greater than 95 percent. Thus, while the control device may commonly
operate at greater than 95 percent control efficiencies, there may be
process fluctuations in heat loads, inlet backpressure, and other
variables that may affect performance that may lower the control
efficiencies achieved. For example, there are field conditions, such as
high winds that may influence combustion efficiencies.\250\ We also
note that, while the EPA established operating and monitoring
requirements to ensure flares achieve a 98 percent control efficiency
at petroleum refineries in 40 CFR part 63, subpart CC, these
requirements include sophisticated monitoring and operational controls
and tend to lead to additional fuel use and greater secondary impacts
than combustion systems targeting to achieve a minimum of 95 percent
control efficiency. Considering these factors, we conclude that,
consistent with CAA section 111(a) definition of a ``standard of
performance,'' 95 percent control efficiency as the minimum allowable
control efficiency at any time continues to reflect ``the degree of
emission limitation achievable'' through the application of the BSER
for tank batteries (a combustor or a VRU). We solicit comment on the
issues described above for requiring higher than 95 percent
reduction.\251\
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\250\ EPA. April 2012. Parameters for Properly Designed and
Operated Flares. Prepared for U.S. Environmental Protection Agency,
Office of Air Quality Planning and Standards, Research Triangle
Park, NC.
\251\ Further, in section XIII.E (solicitation of comment on
control device efficiency), the EPA solicits comment on the level of
reduction that can be reliably achieved using a flare and what
measures need to be in place to assure such reduction.
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During pre-proposal outreach, some small businesses raised a
concern that the NSPS OOOOa requirement for a continuous pilot light
for a storage vessel control device generated more emissions than it
prevented for storage vessels with low emissions. Specifically, small
business representatives raised concerns that there are situations
where propane or other fossil fuel must be used to maintain continuous
pilot lights for flares used as control devices on storage vessels that
do not produce enough emissions. The EPA is interested in whether the
benefits of reducing emissions with these control devices are negated
by the need to burn additional fossil fuels and whether there are
additional factors that lead to variability in emissions from storage
vessels that could be used to more narrowly target these requirements
to limit the unnecessary operation of flares. We are soliciting comment
from all stakeholders on this issue.
e. Control Options and BSER Analysis
For this proposal, the EPA evaluated regulatory options based on
different potential emissions thresholds for VOC and methane. We
assumed the potential tank battery emissions were reduced by 95 percent
using either a VRU or a combustion control device. Since VRUs recover
saleable products, we also estimated the value of the recovered product
when VRUs were used. The EPA encourages the use of VRUs to capture and
sell the emissions from the storage vessels by classifying VRUs as part
of the process, therefore emission recovered would not be included in
the potential emissions at a site.
For new, modified, or reconstructed sources, we evaluated the cost
of control using a single combustion device (or VRU) on a single
storage vessel as well as a tank battery made up of multiple storage
vessels. To do this, we evaluated the use of a single control device
achieving 95 percent reduction of VOC and methane emissions at the
following potential emission thresholds: 6 tpy VOC from a single
storage vessel; 3 and 6 tpy VOC from a tank battery; and 1.3 tpy, 5.3
tpy, 20 tpy, and 50 tpy methane from a tank battery. Based on our cost
analysis we propose to retain the 6 tpy applicability threshold.
The estimated all-in capital costs for a single combustion control
device are approximately $80,000. The estimated annualized costs
include the capital recovery cost (calculated at a 7 percent interest
rate for 15 years) and labor costs for operations and maintenance and
are estimated at approximately $31,500/yr. The estimated capital costs
for a VRU sized for a source with potential VOC emissions of 6 tpy are
approximately $32,000 and the estimated annualized costs are estimated
at approximately $24,000/yr not considering any potential recovery
credits from sales. More information on this cost analysis
[[Page 63200]]
is available in the NSPS OOOOb and EG TSD for this proposal.
Based on our analysis, the cost effectiveness of controlling VOC
and methane emissions from a tank battery with the potential for VOC
emissions of 6 tpy, under the single pollutant approach where all the
costs are assigned to the reduction of VOC, is $5,540 per ton of VOC
eliminated assuming the use a single combustion control device. As
explained above, storage vessels are commonly located adjacent to one
another as part of tank battery, which allows the vapors from the
storage vessels within the tank battery to be collected and routed to a
single control device, when one is used. The single pollutant cost
effectiveness for a VRU to control a tank battery with potential VOC
emissions of 6 tpy is approximately $4,000 per ton of VOC eliminated.
As shown in section IX, costs ranging from $4,000 to $5,540 per ton of
VOC reduced are within the range that the EPA considers to be cost
effective for reducing VOC emissions. Because it is cost effective to
reduce the VOC emissions from a tank battery with potential VOC
emissions of 6 tpy or greater, one of the two targeted pollutants in
this action, it is cost effective to reduce both VOC and methane
emissions from a single storage vessel or a tank battery at that level.
Based on our estimate, a tank battery with potential 6 tpy VOC
emissions has potential 1.3 tpy of methane emissions. Because storage
vessels contain crude oil, condensate, intermediate hydrocarbons, or
produced water, which are approximately 80 percent VOC, the methane
emissions from storage vessels are generally less than the VOC
emissions.
We also evaluated the cost effectiveness at a lower VOC threshold
of 3 tpy. As shown in the NSPS OOOOb and EG TSD, the single pollutant
cost effectiveness for controlling a tank battery with potential
emissions of 3 tpy ranges from $7,500 to $11,000. As shown in section
IX, costs ranging from $7,500 to $11,000 per ton of VOC reduced is not
within the range that the EPA considers to be cost effective for
reducing VOC emissions. Using the multipollutant approach, the VOC cost
effectiveness is between $3,800 and $5,500, which is considered
reasonable, but the methane cost effectiveness is between $17,000 and
$25,000 for any of the methane thresholds assessed in conjunction with
3 tpy VOC limit, which is considered unreasonable. Therefore, the 3 tpy
VOC control option was not considered reasonable at this time using
either the single pollutant or multipollutant approach.
Our analysis also shows that, under the single pollutant approach
where all the costs are assigned to the reduction of methane and zero
to VOC, it is cost effective to control a single storage vessel or a
tank battery with potential methane emissions of 20 tpy (at costs
ranging from $1,250 to $1,660 per ton methane). Based on our estimate,
a tank battery with potential methane emissions of 20 tpy would have
the potential VOC emissions of 91 tpy, 95 percent of which would be
reduced at zero cost. Under the multipollutant cost-effectiveness
approach, where half of the cost is allocated to methane reduction and
the other half to VOC reduction, it is cost effective to control a tank
battery with potential methane emissions of 10 tpy and corresponding
potential VOC emissions of 46 tpy, at an average cost of $1,500 per ton
methane reduced and $330 per ton VOC reduced. In light of the above, 6
tpy of VOC is the lowest threshold that is cost effective to control
both VOC and methane emissions. Therefore, the EPA is proposing to
define the affected facility for purposes of regulating both VOC and
methane emissions as a tank battery with potential VOC emissions of 6
tpy or greater.
2. EG OOOOc
The EPA is proposing presumptive standards for reducing methane
emissions from existing storage vessels. For purposes of the EG, we are
proposing to define a designated facility as a single storage vessel or
tank battery with the potential for methane emissions of 20 tpy or
greater. For purposes of the EG, we are proposing the same definition
of a storage vessel affected facility, which is a single storage vessel
or a group of storage vessels that are physically adjacent and that
receive fluids from the same source (e.g., well, process unit, or set
of wells or process units).
The available controls for reducing methane emissions from existing
tank batteries are the same as those for reducing methane and VOC
emissions from new, modified and reconstructed tank batteries. In
assessing the control costs for existing sources, we applied a 30
percent retrofit factor to the capital and installation costs to
account for added costs of manifolding existing storage vessels and
installing the control system on an existing tank battery. When
applying controls to new sources, there is limited additional costs in
designing the fixed roof with fittings to manifold the vapors and
installing the closed vent piping or ducts during the tank installation
process. For existing sources, installing fittings on an existing tank
may require special lifts to access the roof and cut new ports in the
roof. This may also require the tank to be taken out of service to
conduct these installations, which requires additional time and labor.
Additionally, when installing controls as part of the design for a new
source, the facility layout can be designed to accommodate the control
systems near the tank battery and the control device can be installed
with the same crew installing the storage vessels, minimizing
additional installation costs. For existing sources, there may be other
equipment near the tanks that may require the control equipment to be
further from the tank battery, which increases materials and
installation costs. Also, control equipment costs will include the full
costs of crew mobilization. Therefore, it is more expensive to install
controls at an existing tank battery than to install controls as part
of a new tank battery. We considered the same regulatory options based
on potential methane emissions thresholds of 1.3 tpy, 5.3 tpy, 20 tpy,
and 50 tpy per tank battery.
The estimated capital costs for a single combustion control device
for emissions in this range are approximately $103,000. The estimated
annual costs include the capital recovery cost (calculated at a 7
percent interest rate for 15 years) and labor costs for operations and
maintenance and are estimated at approximately $34,000. The costs for
VRU are more variable than combustion control systems and dependent on
the potential emissions for which the VRU is designed to recover. The
estimated capital costs for a VRU sized for a source with potential
methane emissions of 20 tpy device are approximately $106,000 and the
estimated annualized costs are approximately $49,000/yr not considering
any potential recovery credits. With a VRU, the recovered VOC and
methane are recovered as salable products. Considering the value of
recovered product, the annualized cost for VRU sized to recover
potential methane emissions of 20 tpy is estimated to be $26,000/yr.
More information on this cost analysis is available in the NSPS OOOOb
and EG TSD for this proposal.
The resulting cost effectiveness, for the application of a single
combustion control device or VRU to achieve a 95 percent emission
reduction ranges from $19,000 to $27,400 per ton of methane eliminated
at a threshold of 1.3 tpy methane. This cost is not considered
reasonable. Next, we evaluated the cost effectiveness at a methane
threshold of 5.3 tpy, which ranged from $10,000 to $13,700 per ton of
methane reduced,
[[Page 63201]]
which is also not considered reasonable. At a threshold of 20 tpy
methane, the cost effectiveness ranges from $1,400 to $1,800 per ton
methane reduced. At a threshold of 50 tpy methane, the cost
effectiveness ranges from $340 to $720 per ton methane reduced. When we
considered the application of these options at a national level, the
overall cost effectiveness of the 20 tpy potential methane emissions
threshold was $400 per ton methane reduced without considering product
recovery credits and has a net cost savings considering product
recovery credits. Additionally, the incremental cost effectiveness of
the 20 tpy option relative to the 50 tpy potential methane emissions
threshold was approximately $900 per ton additional methane reduced
when considering product recovery credits.
Based on the cost analysis summarized above, we find that the cost
effectiveness for achieving 95 percent emission reduction of methane
from a tank battery with potential methane emissions of 20 tpy is
reasonable for methane. A cost-effective value of $1,800/ton of methane
reduction is comparable to the estimated methane cost-effectiveness
values for the controls identified as BSER for the 2016 NSPS OOOOa and
which we consider to be representative of reasonable control cost for
reducing methane emissions from the Crude Oil and Natural Gas source
category, as explained in section IX.B. We further note that both
California and Colorado require 95 percent reduction of methane
(California) and hydrocarbon (Colorado) emissions from storage vessels.
For California, existing separator and tank systems with an annual
emission rate greater than 10 tpy methane must control emissions using
a vapor collection system that reduces emissions by at least 95
percent.\252\ For Colorado, storage vessels that emit greater than or
equal to 2 tpy of actual uncontrolled VOC emissions must reduce VOC
emissions by 95 percent.\253\ These requirements, which are comparable
to the proposed presumptive standards, are further indication that the
cost of implementing the proposal is reasonable and not excessive.
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\252\ See sections 95668 and 95671 of California Code of
Regulations, Title 17, Division 3, Chapter 1, Subchapter 10 Climate
Change, Article 4.
\253\ See section I.D.3.a of Colorado Department of Public
Health and Environment, ``Control of Ozone via Ozone Precursors and
Control of Hydrocarbons via Oil and Gas Emissions (Emissions of
Volatile Organic Compounds and Nitrogen Oxides), Regulation Number
7'' (5 CCR 1001-9), July 2021.
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3. Legally and Practicably Enforceable Limits
In addition to the BSER analysis described above, the EPA is
clarifying the term ``legally and practicably enforceable limits'' as
it related to storage vessel affected facilities in the proposed NSPS
OOOOb and EG OOOOc. In the 2016 NSPS OOOOa, the EPA stated that ``any
owner or operator claiming technical infeasibility, nonapplicability,
or exemption from the regulation has the burden to demonstrate the
claim is reasonable based on the relevant information. In any
subsequent review of a technical infeasibility or nonapplicability
determination, or a claimed exemption, the EPA will independently
assess the basis for the claim to ensure flaring is limited and
emissions are minimized, in compliance with the rule.'' See 81 FR
35824, 35844 (June 3, 2016).
In the context of storage vessels under both the 2012 NSPS OOOO and
2016 NSPS OOOOa, the EPA has learned that numerous owners and operators
claim that their storage vessels are not affected facilities under 40
CFR 60.5365(e) and 40 CFR 60.5365a(e). This claim is made based on a
determination that the potential for VOC emissions is less than 6 tpy
when taking 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.\254\
However, when the EPA has reviewed the limits considered by these
facilities as legally and practicably enforceable, we have become aware
that the limits do not require a reduction in emissions; they are often
self-imposed or of such a general nature as to be unenforceable or
otherwise lack measures to assure the required emission reduction. For
example, a permit contains an emission limit of 2 tpy for a single
storage vessel, but does not contain any performance testing
requirements, continuous or other monitoring requirements,
recordkeeping and reporting, or other requirements that would ensure
that emissions are maintained below the emissions limit in the permit.
In National Mining Ass'n v. EPA, 59 F.3d 1351 (D.C. Cir. 1995), the
court explained what constitutes ``effective'' control in assessing a
source's potential to emit. According to the court, while ``effective''
controls need not be Federally enforceable, ``EPA is clearly not
obliged to take into account controls that are only chimeras and do not
really restrain an operator from emitting pollution.'' Id. at 1362. The
court also emphasized that these non-Federally enforceable controls
must stem from state or local government regulations, and not
``operational restrictions that an owner might voluntarily adopt.'' Id.
at 1362. Further, as a general ``default rule,'' the burden of proof
falls ``upon the party seeking relief.'' Schaffer ex rel. Schaffer v.
Weast, 546 U.S. 49, 57-58, 126 S.Ct. 528, 163 L.Ed.2d 387 (2005).
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\254\ 40 CFR 60.5365(e) and 40 CFR 60.5365a(e)(1) and (2) allow
owners and operators to take into account these requirements when
calculating the potential VOC emissions.
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In light of the above, the EPA is proposing to include a definition
for a ``legally and practicably enforceable limit'' as it relates to
limits used by owners and operators to determine the potential for VOC
emissions from storage vessels that would otherwise be affected
facilities under these rules. The intent of this proposed definition is
to provide clarity to owners and operators claiming the storage vessel
is not an affected facility in the Oil and Gas NSPS due to legally and
practicably enforceable limits that limit their potential VOC emissions
below 6 tpy. This definition is being proposed for NSPS OOOOb and the
proposed presumptive standard included in EG OOOOc. This proposed
definition of ``legally and practicably enforceable limit'' is
consistent with the EPA's historic position on what is considered
``legally and practicably enforceable,'' as tailored to storage vessels
in the oil and gas sector that would otherwise be affected facilities
under these rules. The proposed definition is as follows:
``For purposes of determining whether a single storage vessel or
tank battery is an affected facility, a legally and practicably
enforceable limit must include all of the following elements:
i. A quantitative production limit and quantitative operational
limit(s) for the equipment, or quantitative operational limits for the
equipment;
ii. an averaging time period for the production limit in (i) (if a
production-based limit is used) that is equal to or less than 30 days;
iii. established parametric limits for the production and/or
operational limit(s) in (i), and where a control device is used to
achieve an operational limit, an initial compliance demonstration
(i.e., performance test) for the control device that establishes the
parametric limits;
iv. ongoing monitoring of the parametric limits in (iii) that
demonstrates continuous compliance with the production and/or
operational limit(s) in (i);
v. recordkeeping by the owner or operator that demonstrates
continuous
[[Page 63202]]
compliance with the limit(s) in (i-iv); and
vi. periodic reporting that demonstrates continuous compliance.''
In this proposed definition, the EPA is not addressing the various
ways in which a State or other authority's permit may be issued since
the format of permit issuances varies by jurisdiction. The proposed
definition of ``legally and practicably enforceable'' does not specify
limits, monitoring requirements, or recordkeeping. Instead, the owner
or operator should work with the permitting authority to establish
specific limits, monitoring requirements and recordkeeping that will
ensure any permitted emission limit is achieved. Only those limits that
include the elements described above will be considered ``legally and
practicably enforceable'' for purposes of determining the potential for
VOC emissions from a single storage vessel or tank battery, and thus
applicability (or non-applicability) of each single storage vessel or
tank battery as an affected facility under the rule.
This proposed definition will provide clarity to owners and
operators in what limits are necessary to ensure they have
appropriately determined their single storage vessels or tank batteries
are affected facilities under the proposed NSPS OOOOb or designated
facilities under the proposed EG OOOOc. Further, as stated in the 2016
NSPS OOOOa, well-designed rules ensure fairness among industry
competitors and are essential to the success of future enforcement
efforts. 81 FR 35844 (June 3, 2016). The EPA is soliciting comment on
this proposed definition from all stakeholders.
C. Proposed Standards for Pneumatic Controllers
1. NSPS OOOOb
a. Background
In the 2012 NSPS OOOO, the EPA established VOC standards for
natural gas-driven pneumatic controllers. Specifically, subpart OOOO
established a natural gas bleed rate limit of 6 scfh for individual,
continuous bleed, natural gas-driven controllers located in the
production segment. Continuous bleed, natural gas-driven controllers
with a bleed rate of 6 scfh or less are commonly called ``low bleed''
controllers. However, that rule also allowed for the use of ``high
bleed'' controllers (those with a bleed rate over 6 scfh) where
required by functional needs such as response time, safety, and
positive actuation. At natural gas processing plants, subpart OOOO
implemented a VOC standard that required a bleed rate of zero (``zero
bleed'' or ``no bleed''). The rule also included allowances for the use
of continuous bleed natural gas-driven controllers at natural gas
processing plants where required by functional needs.
In the 2016 NSPS OOOOa, the EPA extended the 6 scfh natural gas
bleed rate standard to the natural gas transmission and storage segment
and established GHG standards for all segments. Effectively, the 2016
NSPS OOOOa required low bleed controllers to reduce methane and VOC
emissions from the production and transmission and storage segments and
required a bleed rate of zero for pneumatic controllers at natural gas
processing plants. Like the 2012 NSPS OOOO, the 2016 NSPS OOOOa
included allowances for the use of continuous high bleed controllers in
the production and transmission and storage segments and continuous
natural gas-driven pneumatic controllers at natural gas processing
plants where required by functional needs.
Emissions from natural gas-driven intermittent vent pneumatic
controllers were not addressed in either the 2012 NSPS OOOO or the 2016
NSPS OOOOa. This was because, when operated and maintained properly,
methane and VOC emissions from intermittent controllers are
substantially lower (by an order of magnitude) than emissions from
other types of natural gas-driven controllers. However, the EPA is now
aware that these intermittent controllers often malfunction and vent
during idle periods. Emissions factors considering this fact are around
four times higher than the factors for low-bleed controllers. Further,
as presented in subsection c of this section, methane emissions from
intermittent controllers make up a significant portion of the overall
methane emissions from all natural gas and petroleum system sources in
the GHGI. As such, the EPA is now proposing to reduce emissions from
intermittent controllers via NSPS OOOOb.
b. Affected Facility Definitions and Zero Emissions Standard
As a result of the review of these requirements in the 2016 NSPS
OOOOa, the previous BSER determinations, and the consideration of new
information, including State regulations that have been enacted since
2016, the EPA is proposing GHG (methane) and VOC standards for natural
gas-driven pneumatic controllers in all segments of the industry
included in the Crude Oil and Natural Gas source category (i.e.,
production, processing, transmission and storage).
First, in terms of the definition of an affected facility, the EPA
is proposing to revise the types of pneumatic controllers that are
affected facilities to include both continuous bleed controllers and
intermittent vent controllers. For continuous bleed controllers, an
affected facility is each single continuous bleed natural gas-driven
pneumatic controller that vents to the atmosphere. For intermittent
vent controllers, an affected facility is each single natural gas-
driven pneumatic controller that is not designed to have a continuous
bleed rate but is designed to only release natural gas to the
atmosphere as part of the actuation cycle. These affected facility
definitions apply for pneumatic controllers in both the production and
transmission and storage segments, as well as for those at natural gas
processing plants.
Next, in terms of standards, we are proposing a requirement that
all controllers (continuous bleed and intermittent vent) in the
production and natural gas transmission and storage segments must have
a methane and VOC emission rate of zero. Controllers that emit zero
methane and VOC to the atmosphere can include, but are not limited to,
air-driven pneumatic controllers (also referred to as instrument air-
driven or compressed air-driven controllers), mechanical controllers,
electronic controllers, and self-contained natural gas-driven pneumatic
controllers. While these ``zero-emissions controllers'' would not
technically be affected facilities because they are not driven by
natural gas (air-driven, mechanical, and electronic) or because they do
not vent to the atmosphere, owners and operators should maintain
documentation if they would like to be able to demonstrate to permit
writers or enforcement officials that there are no methane or VOC
emissions from the controllers and that these controllers are not
affected facilities and are not subject to the rule. The proposed
standard would apply to both continuous bleed and intermittent vent
controllers at these sites.
For all natural gas processing plants, we are proposing to
essentially retain the 2016 NSPS OOOOa standard that requires that
controllers must have a methane and VOC emission rate of zero (i.e.,
zero-emissions controllers must be used). However, we are proposing to
slightly change the wording of the standard from subparts OOOO and
OOOOa, which require a ``bleed rate of zero.'' Many natural gas
processing plants use pneumatic controllers that are powered by
compressed air, which
[[Page 63203]]
can technically have a compressed air bleed rate greater than zero. Put
another way, some controllers that are powered with compressed air can
allow some of that compressed air to leave the controller and thus be
released into the atmosphere (they can ``bleed'' compressed air).
However, since the compressed air does not contain any natural gas,
methane, or VOC, we are clarifying the standard by proposing to require
that pneumatic controllers at natural gas processing plants have a
methane and VOC emission rate of zero.
In both NSPS OOOO and OOOOa, there is an exemption from the
standards in cases where the use of a pneumatic controller affected
facility with a bleed rate greater than the applicable standard is
required based on functional needs, including but not limited to
response time, safety, and positive actuation. The EPA is not
maintaining this exemption in the proposed NSPS OOOOb, except for in
very limited circumstances explained below. As discussed below, the
reasons to allow for an exemption based on functional need in NSPS OOOO
and OOOOa were based on the inability of a low-bleed controller to meet
the functional requirements of an owner/operator such that a high-bleed
controller would be required in certain instances. Since we are now
proposing that pneumatic controllers have a methane and VOC emission
rate of zero, we do not believe that the reasons related to the use of
low bleed controllers are still applicable.
The proposed rule also does include an exemption from the zero-
emission requirement for pneumatic controllers in Alaska at locations
where electricity power is not available. In these situations, the
proposed standards would require the use of a low-bleed controller
instead of high-bleed controller. The proposed rule also includes the
exemption for pneumatic controllers in Alaska at sites without power
that would allow the use of high-bleed controllers instead of low-bleed
based on functional needs. In addition, inspections of intermittent
vent controllers to ensure they are not venting during idle periods
described above would also be required at sites in Alaska without
power.
c. Description
Pneumatic controllers are devices used to regulate a variety of
physical parameters, or process variables, using air or gas pressure to
control the operation of mechanical devices, such as valves. The
valves, in turn, control process conditions such as levels,
temperatures and pressures. When a pneumatic controller identifies the
need to alter a process condition, it will open or close a control
valve. In many situations across all segments of the Oil and Natural
Gas Industry, pneumatic controllers make use of the available high-
pressure natural gas to operate or control the valve. In these
``natural gas-driven'' pneumatic controllers, natural gas may be
released with every valve movement (intermittent) and/or continuously
from the valve control. Pneumatic controllers can be categorized based
on the emissions pattern of the controller. Some controllers are
designed to have the supply-gas provide the required pressure to power
the end-device, and the excess amount of gas is emitted. The emissions
of this excess gas are referred to as ``bleed,'' and this bleed occurs
continuously. Controllers that operate in this manner are referred to
as ``continuous bleed'' pneumatic controllers. These controllers can be
further categorized based on the rate of bleed they are designed to
have. Those that have a bleed rate of less than or equal to 6 scfh are
referred to as ``low bleed,'' and those with a bleed rate of greater
than 6 scfh are referred to as ``high bleed.'' Another type of
controller is designed to release gas only when the process parameter
needs to be adjusted by opening or closing the valve, and there is no
vent or bleed of gas to the atmosphere when the valve is stationary.
These types of controllers are referred to as ``intermittent vent''
pneumatic controllers. A third type of natural gas-driven controller
releases gas to a downstream pipeline instead of the atmosphere. These
``self-contained'' types of controllers can be used in applications
with very low pressure.
As discussed above, emissions from natural gas-powered pneumatic
controllers occur as a function of their design. Self-contained
controllers do not emit natural gas to the atmosphere. Continuous bleed
controllers using natural gas as the power source emit a portion of
that gas at a constant rate. Intermittent vent controllers using
natural gas as the power source are designed to emit natural gas only
when the controller sends a signal to open or close the valve, which is
called actuation. From continuous bleed and intermittent vent
controllers, another source of emissions is from improper operation or
equipment malfunctions. In some instances, a low bleed controller may
emit natural gas at a higher level than it is designed to do (i.e.,
over 6 scfh) or an intermittent vent controller could emit continuously
or near continuously rather than only during actuation.
Not all pneumatic controllers are driven by natural gas. At sites
with power, electrically powered pneumatic devices or pneumatic
controllers using compressed air can be used. As these devices are not
driven by pressurized natural gas, they do not emit any natural gas to
the atmosphere, and consequently, they do not emit VOC or methane to
the atmosphere. In addition, some controllers operate mechanically
without a power source or operate electronically rather than
pneumatically. At sites without electricity provided through the grid
or on-site electricity generation, mechanical controllers and
electronic controllers using solar power can be used.
The emissions from natural gas-powered pneumatic controllers
represent a significant portion of the total emissions from the Oil and
Natural Gas Industry. In the 2021 GHGI, the estimated methane emissions
for 2019 from pneumatic controllers were 700,000 metric tons of methane
for petroleum systems and 1.4 million metric tons for natural gas
systems. These levels represent 45 percent of the total methane
emissions estimated from all petroleum systems (i.e., exploration
through refining) sources and 22 percent of all methane emissions from
natural gas systems (i.e., exploration through distribution). The vast
majority of these emissions are from natural gas-driven intermittent
vent controllers, which the EPA is proposing to define as an affected
facility for the first time in NSPS OOOOb. Of the combined methane
emissions from pneumatic controllers in the petroleum systems and
natural gas systems production segments, emissions from intermittent
vent controllers make up 88 percent of the total. Continuous high bleed
and low bleed controllers make up 8 and 4 percent, respectively.
d. Control Options
In identifying control options for this NSPS OOOOb proposal, we re-
examined the options previously evaluated in the rulemakings to
promulgate the 2012 NSPS OOOO and the 2016 NSPS OOOOa, and also
examined State rules with requirements for pneumatic controllers that
achieve emission reductions beyond those achieved by NSPS OOOOa. For
NSPS subparts OOOO and OOOOa, we identified options for reducing
emissions from continuous bleed natural gas-driven pneumatic
controllers. These options included using low bleed controllers in
place of
[[Page 63204]]
high bleed controllers, enhanced maintenance (i.e., periodic inspection
and repair), and using zero-emissions controllers. For the production
and transmission and storage segments, only the option to require low
bleed controllers was fully analyzed in these previous analyses. Based
on the EPA's determination at that time that electricity was ``likely
unavailable'' at production and transmission and storage sites, the EPA
did not fully consider instrument air or electronic controllers. The
EPA also did not evaluate enhanced maintenance, as it was concluded
that the highly variable nature of determining the proper methods of
maintaining a controller could incur significant costs. The EPA did not
evaluate options to reduce emissions from intermittent vent controllers
in either the 2012 or 2016 NSPS.
Three U.S. States (California, Colorado, and New Mexico) and two
Canadian provinces (Alberta and British Columbia) have rules or
proposed rules that achieve emission reductions beyond those achieved
by NSPS OOOOa. Starting on January 1, 2019, and subject to certain
exceptions, a California rule requires that all new and existing
continuous bleed devices must not vent natural gas to the atmosphere.
The rule allows low bleed devices installed prior to January 1, 2016,
to continue to operate, provided that annual testing is performed to
verify that the low bleed rate is maintained. A Colorado rule adopted
in February 2021, requires that all new controllers are no-bleed
controllers (which includes self-contained natural gas-driven
controllers), and over a period of two years, a sizeable portion of
existing controllers must be retrofit to have a natural gas bleed rate
of zero. New Mexico has proposed a rule that would require an emission
rate of zero from all controllers located at sites with access to
electrical power. The Canadian provinces of Alberta (effective 2022)
and British Columbia (effective 2021) also regulate emissions from
pneumatic controllers. In British Columbia, pneumatic devices that emit
natural gas must not be used at new sources and at existing gas
processing plants and large compressor stations, and in Alberta, owners
and operators must prevent or control (by 95 percent) vent gas from new
pneumatic controllers. While the terminology differs across these
regulations, the EPA believes that all these requirements (with the
exception of the 95 percent reduction requirement in Alberta) are very
similar to if not the same as the zero methane and VOC emission
requirement being proposed by the EPA for NSPS OOOOb.
From EPA's review of our past BSER analysis as well as reviewing
these other rules, several options were identified for the BSER
analysis for NSPS OOOOb to reduce methane and/or VOC emissions from
natural gas-driven pneumatic controllers. These include the following:
(1) Use of low bleed natural gas-driven pneumatic controllers in the
place of high bleed natural gas-driven pneumatic controllers; (2)
require zero emissions from intermittent vent controllers except during
actuation, and (3) prohibit the emissions of methane and VOC from all
pneumatic controllers (i.e., establish a zero methane and VOC emission
standard for both continuous bleed and intermittent bleed controllers).
e. 2021 BSER Analysis
Production and Transmission and Storage Segments
For production and transmission and storage sites, the EPA
evaluated two options. The first was an option to require the use of
low bleed natural gas-driven pneumatic controllers in the place of high
bleed natural gas-driven pneumatic controllers, along with a
requirement that natural gas-driven intermittent vent pneumatic
controllers only discharge natural gas during actuation. We also
evaluated an option of establishing a zero methane and VOC emissions
standard, which we propose to determine represents the BSER for
production and natural gas transmission and storage sites.
The first option evaluated was the use of low bleed natural gas-
driven pneumatic controllers in the place of high bleed natural gas-
driven pneumatic controllers. In the analysis of this option, we
examined the emissions reduction potential, the cost of implementation,
and the cost effectiveness in terms of cost per ton of emissions
eliminated.
The emission reduction potential of using a low bleed controller in
place of a high bleed controller depends on the actual bleed rate of
each device, which varies from device to device. Using average emission
factors for each device type, the difference in emissions can be
estimated on a per-controller basis. We estimated this difference
between a low bleed and a high bleed device to be an 84 percent
reduction for controllers in the production segment and a 92 percent
reduction in emissions in the transmission and storage segment,
equating to a difference of 2.1 tpy methane and 0.6 tpy VOC per
controller in the production segment and 2.9 tpy methane and 0.08 tpy
VOC per controller in the transmission and storage segment. The cost of
a new low bleed natural gas-driven pneumatic controller is
approximately $255 higher than the cost of a new high bleed device. On
an annualized basis, assuming a 15-year equipment lifetime and a 7
percent interest rate, the cost is $28 per year per low bleed
controller. Under the single pollutant approach where all the costs are
assigned to the reduction of one pollutant, the estimated cost
effectiveness is $13 per ton of methane avoided and $48 per ton of VOC
avoided per controller in the production segment. Using the
multipollutant approach where half the cost of control is assigned to
the methane reduction and half to the VOC reduction, the estimated cost
effectiveness is $7 per ton of methane avoided and $24 per ton of VOC
avoided. When considering the cost of saving the natural gas that would
otherwise be emitted for the production segment, the cost effectiveness
shows an overall savings under both the single pollutant and
multipollutant approaches. For the natural gas transmission and storage
segment, the cost effectiveness is $10 per ton methane avoided and $355
per ton VOC avoided per controller using the single pollutant method,
and $5 per ton of methane and $178 per ton of VOC avoided per
controller using the multipollutant method. Transmission and storage
facilities do not own the natural gas; therefore, revenues from
reducing the amount of natural gas emitted/lost was not applied for
this segment. These values are well within the range of what the EPA
considers to be reasonable for methane and VOC using both the single
pollutant and multipollutant approaches.
We also evaluated a requirement that natural gas-driven
intermittent vent pneumatic controllers only discharge natural gas
during actuations. This emissions reduction option would be required in
conjunction with a requirement to use low bleed controllers in place of
high bleed controllers. The average emission factor determined by an
industry study for natural gas-driven intermittent vent controllers,
including both properly and improperly operating controllers, is 9.2
scfh natural gas.\255\ Comparing this to the emission factor for a
properly operating intermittent vent controller of 0.3 scfh natural gas
illustrates the significant potential for reductions from a program
that
[[Page 63205]]
identifies intermittent vent controllers that are improperly operating
and repairing, replacing, or altering their operating conditions so
they may function properly. To ensure these devices are emitting
natural gas only during actuations in accordance with their design,
there would be no equipment expenditure or associated capital costs;
however, emissions monitoring or inspections, combined with repair as
needed, would be necessary to ensure this proper operation is achieved.
We considered requiring independent inspections specifically for
intermittent vent controllers but concluded that it would be more
efficient to couple inspections of these controllers with the
inspections of equipment for leaks under the fugitive monitoring
program (see section XII.A of this preamble).
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\255\ API Field Measurement Study: ``Pneumatic Controllers EPA
Stakeholder Workshop on Oil and Gas.'' November 7, 2019--Pittsburgh
PA. Paul Tupper.
---------------------------------------------------------------------------
The second option we evaluated was a zero methane and VOC emissions
standard. While applicability of both the 2012 NSPS OOOO and the 2016
NSPS OOOOa are based on an individual pneumatic controller (as is the
proposed definition of affected facility under NSPS OOOOb), zero-
emissions controller options are more appropriately evaluated as
``site-wide'' controls. While individual natural gas-driven pneumatic
controllers can be switched to other types of natural-gas driven
pneumatic controllers (e.g., high bleed to low bleed types or low bleed
to self-contained), the implementation of some zero-emissions
controllers options would require equipment that would presumably be
used for all the controllers at the site. For example, in order to
utilize instrument air driven controllers, a compressor and related
equipment would need to be installed. For the vast majority of
situations, the EPA does not believe that an owner and operator would
install a compressor just for a single controller, but rather would
instead install a site-wide system to provide compressed air to all the
controllers at the site. Therefore, to adequately account for the costs
of the system, including the controllers and the common equipment, we
evaluated these zero-emissions controller options using ``model''
plants.
These model plants include assumptions regarding the number of each
type of pneumatic controller at a site. Emissions were estimated for
each of the model plants using a calculation based on of the number of
controllers at the plant and emission factors for each controller.
Three sizes of model plants (i.e., small, medium, and large) were
developed and used for both the production and transmission and storage
segments. Each model plant contained one high bleed natural gas-driven
controller and increasing numbers of low bleed and intermittent natural
gas-driven controllers. For the production segment, the controller-
specific emission factors used are from a recent study conducted by the
American Petroleum Institute,\256\ and are 2.6 scfh, 16.4 scfh, and 9.2
scfh total natural gas emissions for low bleed, high bleed, and
intermittent bleed controllers, respectively. This API study did not
cover the transmission and storage segment; therefore, the emission
factors from GHGRP subpart W were used, which are 1.37 scfh, 18.2 scfh,
and 2.35 scfh for low bleed, high bleed, and intermittent bleed
controllers, respectively. It was assumed that the portion of natural
gas that is methane is 82.9 percent in the production segment and 92.8
percent in the transmission and storage segment. Further, it was
assumed that VOCs were present in natural gas at a certain level
compared to methane. The specific ratios assumed were 0.278 pounds VOC
per pound methane in the production segment and 0.0277 pounds VOC per
pound methane in the transmission and storage segment. This information
results in estimated emissions for a single natural gas-driven
pneumatic controller in the production segment of 0.39, 2.48, and 1.39
tpy methane and 0.1, 0.7, and 0.4 tpy VOC per low bleed, high bleed,
and intermittent vent controller, respectively. The emissions for a
single natural gas-driven pneumatic controller in the transmission and
storage segment are 0.23, 3.08, and 0.40 tpy methane and 0.006, 0.08,
and 0.01 tpy VOC per low bleed, high bleed, and intermittent vent
controller, respectively.
---------------------------------------------------------------------------
\256\ API Field Measurement Study: ``Pneumatic Controllers EPA
Stakeholder Workshop on Oil and Gas.'' November 7, 2019--Pittsburgh
PA. Paul Tupper.
---------------------------------------------------------------------------
Based on the factors described above and the number of each type of
controller in each model plant, baseline emissions for the model plants
were calculated. For the production model plants, the baseline
emissions were calculated to be 5.7 tpy methane and 1.6 tpy VOC for the
small model plant (assumes fewer controllers on site than medium
plant), 11.2 tpy methane and 3.1 tpy VOC for the medium model plant
(assumes more controllers on site than small plant), and 24.9 tpy
methane and 6.9 tpy VOC for the large model plant (assumes more
controllers on site than the medium plant). For the transmission and
storage model plants, the baseline emissions were calculated to be 4.1
tpy methane and 0.1 tpy VOC for the small model plant, 5.7 tpy methane
and 0.2 tpy VOC for the medium model plant, and 10.0 tpy methane and
0.3 tpy VOC for the large model plant. For detailed information on the
configuration of these model plants and the calculation of the baseline
emissions, see the NSPS OOOOb and EG TSD for this rulemaking, which is
available in the docket.
Instrument air controllers and electronic controllers were the two
zero emission options evaluated. Both these options require electricity
to operate. Instrument air systems use compressed air as the signaling
medium for pneumatic controllers and pneumatic actuators, whereas
electronic controllers send an electric signal to an electric actuator
(rather than sending a pneumatic signal to a pneumatic actuator). As
instrument air systems are usually installed at facilities where there
is a high concentration of pneumatic control valves, electrical power
from the grid, and the presence of an operator that can ensure the
system is properly functioning, we evaluated the use of instrument air
for the large model plant with more controllers and the use of
electronic controllers, which can be powered by solar panels, at the
small and medium-sized model plant with less controllers. The emission
reduction potential of using these zero-emissions controllers rather
than natural-gas-driven pneumatic controllers is 100 percent since
these systems eliminate all natural gas emissions (they do not emit any
VOC or methane). Based on the information available to the EPA during
development of this proposal, these two zero-emissions options were the
only two analyzed. The EPA solicits comment on the other potential
zero-emission options for these sites (mechanical-only controllers,
self-contained natural gas-driven controllers, and natural gas-driven
controllers where the emissions are captured and routed to a process).
For the small and medium-sized model plants, the zero-emissions
option evaluated was the use of electronic controllers. The respective
emissions reduction for small and medium-sized plants would be 5.7 and
11.2 tpy methane and 1.6 and 3.1 tpy VOC in the production segment and
4.1 and 5.7 tpy methane and 0.11 and 0.16 tpy VOC in the transmission
and storage segment. The cost of a new electronic controller system
using electricity from the grid or other on-site power generation is
estimated to be $26,000 and $46,000, for small and medium-sized plants
respectively. The cost of a new solar-powered electronic controller
system is
[[Page 63206]]
estimated to be $28,000 and $52,000, for small and medium-sized plants
respectively. The estimated annualized capital costs, assuming a 15-
year equipment lifetime and a 7 percent interest rate, are $2,800 and
$5,040, respectively for a system powered with electricity from the
grid or other power source for small and medium-sized plants, and
$3,090 and $5,630, respectively, for a solar-powered system for small
and medium-sized plants.
For the production segment, considering the slightly more expensive
solar-powered system, under the single pollutant approach, the
estimated cost effectiveness is $550 per ton of methane avoided and
$1,970 per ton of VOC avoided for a small plant and $500 per ton of
methane avoided and $1,810 per ton of VOC avoided for a medium-sized
plant. Using the multipollutant approach where half the cost of control
is assigned to the methane reduction and half to the VOC reduction, the
estimated cost effectiveness is $275 per ton of methane avoided and
$980 per ton of VOC avoided for a small plant and $250 per ton of
methane avoided and $900 per ton of VOC avoided for a medium-sized
plant in the production segment. When considering the cost of saving
the natural gas that would otherwise be emitted for the production
segment, the cost effectiveness is $370 per ton of methane avoided and
$1,320 per ton of VOC avoided for a small plant and $320 per ton of
methane avoided and $1,150 per ton of VOC avoided for a medium-sized
plant. Using the multipollutant approach, the estimated cost
effectiveness is $185 per ton of methane avoided and $660 per ton of
VOC avoided for a small plant and $160 per ton of methane avoided and
$580 per ton of VOC avoided for a medium-sized plant in the production
segment. These values are well within the range of what the EPA
considers to be reasonable for methane and VOC using both the single
pollutant and multipollutant approaches.
For the natural gas transmission and storage segment, considering
the slightly more expensive solar-powered system, the estimated cost
effectiveness is $750 per ton of methane avoided and $27,200 per ton of
VOC avoided for a small plant and $990 per ton of methane avoided and
$35,700 per ton of VOC avoided for a medium-sized plant. Using the
multipollutant approach, the estimated cost effectiveness is $380 per
ton of methane avoided and $13,600 per ton of VOC avoided for a small
plant and $490 per ton of methane avoided and $17,800 per ton of VOC
avoided for a medium-sized plant. Transmission and storage facilities
do not own the natural gas; therefore, revenues from reducing the
amount of natural gas emitted/lost was not applied for this segment.
While the cost effectiveness values for VOC are higher than the range
of what the EPA considers to be reasonable for VOC, the cost
effectiveness for methane is within the range of what the EPA considers
to be reasonable for methane using the single pollutant approach.
For the large model plants, the zero-emissions option evaluated was
the use of instrument air systems. For the production segment, the
emissions avoided would be 24.9 tpy methane and 6.9 tpy VOC, and in the
transmission and storage segment 10.0 tpy methane and 0.3 tpy VOC. The
cost of a new instrument air system is estimated to be $96,000 and the
estimated annualized capital costs, assuming a 15-year equipment
lifetime and a 7 percent interest rate, are $10,500. For the production
segment, under the single pollutant approach, the estimated cost
effectiveness is $420 per ton of methane avoided and $1,520 per ton of
VOC avoided. Using the multipollutant approach, the estimated cost
effectiveness is $210 per ton of methane avoided and $760 per ton of
VOC avoided. When considering the cost of saving the natural gas that
would otherwise be emitted for the production segment, the cost
effectiveness is $240 per ton of methane avoided and $860 per ton of
VOC avoided. Using the multipollutant approach, the estimated cost
effectiveness is $120 per ton of methane avoided and $430 per ton of
VOC avoided in the production segment. These values are well within the
range of what the EPA considers to be reasonable for methane and VOC
using both the single pollutant and multipollutant approaches.
For the natural gas transmission and storage segment, the estimated
cost effectiveness is $1,050 per ton of methane avoided and $38,000 per
ton of VOC avoided. Using the multipollutant approach, the estimated
cost effectiveness is $530 per ton of methane avoided and $19,000 per
ton of VOC avoided. Transmission and storage facilities do not own the
natural gas; therefore, revenues from reducing the amount of natural
gas emitted/lost was not applied for this segment. While the cost
effectiveness values for VOC are higher than the range of what the EPA
considers to be reasonable for VOC, the cost effectiveness for methane
is within the range of what the EPA considers to be reasonable for
methane using the single pollutant approach.
Note that the annual costs for these zero-emissions controllers are
based on the annualized capital costs only. While we assume the
maintenance costs for electric controllers is less than the costs for
natural gas-driven controllers, there are costs associated with the use
of electricity that are not incurred for natural gas-driven
controllers. We solicit comments on whether such operational costs
should be included in these estimates, as well as information regarding
these costs.
The capital costs of solar-powered controllers include the cost of
the batteries, which represents around 7 percent of the total cost of a
solar-powered system. As noted above, the capital cost was annualized
assuming a 15-year lifetime, however batteries for a solar system may
have a shorter life. We are soliciting comment on the life of these
batteries and, if this life is shorter than 15 years, how the costs of
these batteries should be included as a maintenance cost for solar
powered systems.
The EPA finds that the cost effectiveness for both the low bleed
and zero-emissions options are reasonable for sites in the production
and natural gas transmission and storage segments. The incremental cost
effectiveness in going from the low bleed option to the zero-emissions
option is estimated to be $390 and $340 per ton of additional methane
eliminated for small and medium-sized plants ($1,400 and $1,200 per ton
of VOC), respectively, in the production segment and $640 and $870 per
ton of additional methane eliminated for small and medium-sized plants
($23,000 and $31,500 per ton of VOC), respectively, in the transmission
and storage segment. The incremental cost effectiveness in going from
the low bleed option to the non-emissions option is estimated to be
$260 and $940 per ton of additional methane and VOC avoided,
respectively, for large plants in the production segment and to be $940
and $34,000 per ton of additional methane and VOC avoided,
respectively, for large plants in the transmission and storage segment.
These incremental costs of control do not consider savings for the
production segment. The EPA believes the incremental costs of control
are reasonable for methane and VOC in the production segment, and for
methane in the transmission and storage segment.
As discussed above, several States and Canadian provinces require
the use of controllers that do not emit methane or VOC throughout the
Oil and Natural Gas Industry, which further demonstrates the
reasonableness of this option and that there are no technical barriers
inhibiting the use of electronic controllers or instrument air systems
at sites in the production and transmission
[[Page 63207]]
and storage segments. In 2015, the EPA concluded that, ``[a]t sites
without available electrical service sufficient to power an instrument
air compressor, only gas driven pneumatic devices are technically
feasible in all situations.'' (80 FR 56623, September 18, 2015).
However, since that time, at least two States and two Canadian
provinces have adopted regulations that require zero emitting
controllers at all new sites. The EPA evaluated these rules, and
considers these rules, along with the basic understanding that sources
in these areas are able to comply with the rules, evidence that the
feasibility issues that led to the EPA's previous decision not to
require zero emission controllers in 2015 have been overcome. Further,
the EPA recognizes that industry commenters on the proposed Colorado
rule raised some of the same technical feasibility issues that have
been presented to the EPA in the past, including battery storage
capacity issues, weather-related issues, and mechanical issues related
to vibration.\257\ However, despite these issues being raised, Colorado
finalized the requirement that new controllers have a natural gas bleed
rate of zero at all sites, even though without power. The EPA has
considered new information since 2016 and has now concluded that use of
zero-emission controllers is technically feasible subject to a
particular proposed exception discussed below. The EPA specifically
requests comments on this conclusion. The EPA further solicits comment
on market availability of zero-emission options.
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\257\ Pneumatic Controller Task Force Report to the Air Quality
Control Commission. Pneumatic Controller Field Study and
Recommendations. Colorado Department of Public Health and
Environment. Air Pollution Control Division. June 1, 2020.
---------------------------------------------------------------------------
Secondary impacts from the use of electronic controllers and
instrument air systems are indirect, variable, and dependent on the
electrical supply used to power the compressor or controllers. These
impacts are expected to be minimal. For example, it is estimated that
the electricity needed to operate a compressor is only around 0.4 kW/
hour/controller when the compressor is operating. No other secondary
impacts are expected. The EPA solicits comment on whether owners and
operators would use diesel generators to generate power to run zero-
emissions controllers. The EPA recognizes that diesel generators would
generate formaldehyde emissions and there could be associated secondary
impacts. The EPA does not intend for diesel generators to be used.
In light of the above, we find that the BSER for reducing methane
and VOC emissions from natural gas-driven pneumatic controllers at
production and transmission and storage sites is the use of zero-
emissions controllers. Therefore, for NSPS OOOOb, we are proposing to
require zero emissions of methane and VOC to the atmosphere for all
pneumatic controllers at production and transmission and storage sites.
Both NSPS OOOO and NSPS OOOOa allow the use of high-bleed pneumatic
controllers at production sites and natural gas-driven continuous bleed
controllers at natural gas processing plants if it is determined that
the use of such a pneumatic controller affected facility with a bleed
rate greater than the applicable standard is required ``based on
functional needs, including but not limited to response time, safety
and positive actuation.'' See 40 CFR 60.5390(a) and 60.5390a(a). This
exemption was based on comments received on the 2011 proposed NSPS OOOO
rule. There, ``[t]he commenters suggest exemptions that address
situations such as those where the natural gas includes impurities that
could increase the likelihood of fouling a low-bleed pneumatic
controller, such as paraffin or salts; where weather conditions could
degrade pneumatic controller performance; during emergency conditions;
where flow is not sufficient for low-bleed pneumatic controllers; where
electricity is not available; and where engineering judgment recommends
their use to maintain safety, reliability or efficiency.'' (77 FR
49520, August 16, 2012). These reasons to allow for an exemption based
on functional need were based on the inability of a low-bleed
controller to meet the functional requirements of an owner/operator
such that a high-bleed controller would be required in certain
instances. Since we are now proposing that nearly all pneumatic
controllers have a methane and VOC emission rate of zero, subject to
exemption explained below, we do not believe that the reasons cited
above are still applicable. Therefore, the proposed rule does not
include an exemption based on functional need. The EPA is requesting
comment regarding the possibility of situations where functional
requirements/needs dictate that a natural gas-driven controller that
emits any amount of VOC and/or methane be used. For example, are there
situations where a zero-emission controller cannot be used due to
functional needs such that an owner/operator must use a low-bleed
controller or an intermittent controller instead? Comments requesting
such an exemption should include details of the specific functional
need and why all zero-emission controller options are not suitable.
For many sites, the EPA believes that the most feasible zero-
emission option will be solar-powered controllers. The EPA recognizes
that solar-powered controllers are dependent on sunshine, and in areas
at higher latitudes that undergo prolonged periods without sunshine,
this option could be problematic to implement due to the technical
limitations of solar panels coupled with the practical realities
related to the hours of sunshine received. Therefore, the proposed rule
includes an exemption from the zero-emission requirement for pneumatic
controllers at sites in Alaska that do not have access to power (i.e.,
electricity from the grid or produced using natural gas on-site). Sites
with power have clearly demonstrated that zero emissions from
controllers is achievable, and therefore the EPA is not proposing to
exempt pneumatic controllers at sites in Alaska that have power. The
proposed exemption would only apply to pneumatic controllers at sites
located in Alaska that do not have access to power. In those
situations, affected facilities would not be required to comply with
the zero-emission standard, but instead must use low-bleed pneumatic
controllers (unless a high bleed device is needed for functional
reasons) and must monitor any intermittent controllers in conjunction
with the fugitives monitoring program to ensure they are not venting
when idle. The EPA is soliciting comment on this proposed exemption.
Specifically, the EPA is interested in comments regarding the technical
feasibility of solar panels to power pneumatic controllers in Alaska.
The EPA is also interested in comments regarding whether there are
other locations outside of Alaska where such an exemption may be
warranted. In submitting responses to this request, commenters should
be mindful that two Canadian Provinces, which are north of any U.S.
State other than Alaska, require zero-emitting controllers at all new
sites.
Natural Gas Processing Plants
Natural gas processing plants typically have higher numbers of
pneumatic controllers than production and transmission and storage
sites. Model plants were also used for this analysis, specifically the
model plants used are the same as those used for the 2011 and 2015 BSER
analyses, and include small, medium, and large sites.
[[Page 63208]]
The number of controllers is 15, 63, and 175 for small, medium, and
large model plants, respectively. All controllers at these sites are
assumed to be continuous, but the number of low bleed and high bleed
devices is not specified for the model plants. It was assumed that each
controller emitted 1 tpy methane, as derived from Volume 12 of a 1996
GRI report.\258\ In addition, it was assumed that the portion of
natural gas that is methane is 82.8 percent in the natural gas
processing segment, and the specific VOC to methane ratio assumed was
0.278 pounds VOC per pound methane. For detailed information on the
configuration of these model plants, see the NSPS OOOOb and EG TSD,
which is available in the docket.
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\258\ Radian International LLC. Methane Emissions from the
Natural Gas Industry, Vol. 12: Pneumatic Devices. Prepared for the
Gas Research Institute and Environmental Protection Agency. EPA-600/
R-96-080k. June 1996.
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For natural gas processing plants, the only option evaluated was
the requirement to use zero-emission controllers. For our analysis, we
examined the use of instrument air, which is the most commonly used
controller technology at natural gas processing plants. For this
analysis, we used cost data from the 2011 NSPS OOOO TSD updated to 2019
dollars. The updated capital costs for an instrument air system at a
natural gas processing plant ranges from $20,000 to $162,000, depending
on the system size. The annualized costs were based on a 7 percent
interest rate and a 10-year equipment life. This equated to an
annualized cost of approximately $13,000 to $96,000 per system. The
emissions reduction associated with the installation of an instrument
air system over natural gas-driven pneumatic controllers ranged from
approximately 15 to 175 tpy methane and 4.2 to 49 tpy VOC per system.
The cost effectiveness is estimated to range from approximately $550 to
$900 per ton methane eliminated $2,000 to $3,100 per ton VOC
eliminated. When considering the costs of saving the natural gas that
would otherwise be emitted, the cost effectiveness improves, with a
cost effectiveness of $370 to $700 per ton of methane eliminated and
$1,300 to $2,500 per ton of VOC eliminated. These cost effectiveness
values are presented on a single pollutant basis, and the cost of
control on a multipollutant basis is 50 percent of these values. These
values are well within the range of what the EPA considers to be
reasonable for methane and VOC using both the single pollutant and
multipollutant approaches.
The 2012 NSPS OOOO and 2016 NSPS OOOOa require a zero-bleed
emission rate for pneumatic controllers at natural gas processing
plants. Natural gas processing plants have successfully met this
standard for many years now. Further, several State agencies have rules
that include this zero-bleed requirement for controllers at natural gas
processing plants. This is further demonstration of the reasonableness
of a zero methane and VOC emission standard for pneumatic controllers
at natural gas processing plants.
We find the cost effectiveness of eliminating methane and VOC
emissions using both the single pollutant and multipollutant approaches
to be reasonable.
Secondary impacts from the use of instrument air systems are
indirect, variable, and dependent on the electrical supply used to
power the compressor. These impacts are expected to be minimal, and no
other secondary impacts are expected.
In light of the above, we find that the BSER for reducing methane
and VOC emissions from natural gas-driven pneumatic controllers at
natural gas processing plants is the use of zero-emissions controllers.
Therefore, for NSPS OOOOb, we are proposing to require a natural gas
emission rate of zero for all pneumatic controllers at natural gas
processing plants. However, we recognize that there may be technical
limitations in some situations where zero-emissions controllers may not
be feasible, and therefore, we are proposing an allowance for the use
of natural gas-driven pneumatic controllers with an emission rate of
methane and VOC greater than zero where needed due to functional
requirements in this BSER determination. Justification of this
functional need must be provided in an annual report and maintained in
records.
f. Use of Combustion Devices and VRUs
Another option that could potentially be used to reduce emissions
from pneumatic controllers is to collect the emissions from natural gas
driven continuous bleed controllers and intermittent vent controllers
and route the emissions through a closed vent system to a control
device or process. This option is allowed in some State rules. While
the EPA did not evaluate the cost effectiveness of this option due to a
lack of available information regarding control system costs and
feasibility across sites, we think this option could be cost effective
for owners and operations in certain situations, particularly if the
site already has a control device to which the emissions from
controllers could be routed. As this option could be used to achieve
significant methane and VOC emission reductions (95 percent or
greater), we are soliciting comment on whether this is a control
technique used in the industry to reduce emissions from natural gas-
driven pneumatic controllers. We are also interested in information
related to the performance testing, monitoring, and compliance
requirements associated with these control devices. Finally, we are
interested in ideas as to how this option could potentially fit with
the proposed requirements for pneumatic controllers. For example, if an
owner or operator determines that a natural gas-driven pneumatic
controller is required for functional need reasons, the EPA could
require that emissions be collected and routed to a control device that
achieves 95, or 98, percent control.
2. EG OOOOc
The EPA evaluated BSER for the control of methane from existing
pneumatic controllers (designated facilities) in all segments in the
Crude Oil and Natural Gas source category covered by the proposed NSPS
OOOOb and translated the degree of emission limitation achievable
through application of the BSER into a proposed presumptive standard
for these facilities that essentially mirrors the proposed NSPS OOOOb.
First, based on the same criteria and reasoning as explained above,
the EPA is proposing to define the designated facilities in the context
of existing pneumatic controllers as those that commenced construction
on or before November 15, 2021. Based on information available to the
EPA, we did not identify any factors specific to existing sources that
would indicate that the EPA should change these definitions as applied
to existing sources. As such, for purposes of the emission guidelines,
the definition of a designated facility in terms of pneumatic
controllers is each individual natural gas driven pneumatic controller
(continuous bleed or intermittent vent) that vents to the atmosphere.
Next, the EPA finds that the control options evaluated for new
sources for NSPS OOOOb are appropriate for consideration in the context
of existing sources under the EG OOOOc. The EPA finds no reason to
evaluate different, or additional, control measures in the context of
existing sources because the EPA is unaware of any control measures, or
systems of emission
[[Page 63209]]
reduction, for pneumatic controllers that could be used for existing
sources but not for new sources.
Next, the methane emission reductions expected to be achieved via
application of the control measures identified above for new sources
are also expected to be achieved by application of the same control
measures to existing sources. The EPA finds no reason to believe that
these calculations would differ for existing sources as compared to new
sources because the EPA believes that the baseline emissions of an
uncontrolled source are the same, or very similar, and the efficiency
of the control measures are the same, or very similar, compared to the
analysis above. This is also true with respect to the costs, non-air
environmental impacts, energy impacts, and technical limitations
discussed above for the control options identified.
For the most part, the information presented above regarding the
costs related to new sources and the NSPS are also applicable for
existing sources. The instance where the EPA estimated a difference in
the costs between a new and existing source was for the retrofit of an
existing production site to use instrument air at sites equipped with
electrical power. While the equipment needed is the same as for new
sites, it may be more difficult to design and install a retrofitted
system. Therefore, the EPA estimates the costs for design and
installation to be twice that of the costs for new systems (from
approximately $32,000 for new systems to approximately $64,000 for
existing systems), resulting in the capital cost of the system being
approximately $127,000 with an annualized cost of approximately
$14,000.
As noted above, the EPA's analysis for this proposal only examined
the cost of instrument air for the large model plant. The total
elimination of methane emissions (25 tons per year methane for
production sites and 10 tons per year methane for transmission and
storage sites) would be the same for existing sources as presented
above for new sources. Considering the cost difference, the cost
effectiveness for production sites is $560 per ton of methane
eliminated without considering savings, and $365 per ton when
considering savings. For the transmission and storage segment, the cost
effectiveness is $1,400 per ton of methane eliminated. These values are
within the range of what the EPA considers to be reasonable for
methane. Since none of the other factors are different for existing
sources when compared to the information discussed above for new
sources, the EPA concludes that BSER for existing sources and the
proposed presumptive standard for EG OOOOc to be the requirement to use
zero-emission controllers. This proposed EG includes the exemption from
the zero-emission standard for pneumatic controllers in Alaska as
explained above in the context of the proposed NSPS OOOOb.
b. Possible Phase-In Approach for Existing Sources
The EPA recognizes there could be different compliance time
approaches that could be implemented for existing pneumatic
controllers. The EPA's proposal for compliance times State plans must
include to meet the requirements of the EG can be found in Section
XIV.E. As explained there, the EPA is proposing that State plans must
generally include a 2-year timeline for compliance in the proposed EG,
but is also soliciting comment on the possibility of the EG requiring
different compliance timelines for different emission points.
Specifically, in the context of pneumatic controllers, the EPA is
further soliciting comment on including a phase-in approach in the EG.
The EPA recognizes that a phase-in approach may only be appropriate for
existing sources as new facilities could presumably plan for zero-
emission controllers during construction. A phase-in period could span
a number of years (e.g., 2 years), to allow owners and operators to
prioritize conversion of natural gas-driven controllers at existing
sites based on specific factors (e.g., focus first on sites with onsite
power, sites with highest production, sites with the highest number of
controllers). A phase-in approach could also result in the conversion
of a certain percentage of sites within a given area (e.g., State or
basin). For example, the State of Colorado requires a minimum of 40
percent of sites to be converted after 2 years, with 15 percent in year
1 and 25 percent in year 2. The EPA also recognizes potential
challenges with a phase-in approach, such as difficulties with
enforcement and calculation of the percentage converted due to the
frequency at which sites may change ownership. The EPA solicits comment
on all aspects of the EG requiring State plans to include a phase-in
approach, and whether the agency should consider this type of approach
rather than a single compliance time. The EPA also solicits comment on
cost and feasibility factors that would enter into adopting and
designing a phase-in timeline.
c. Natural Gas Processing Plants
The information presented above regarding the emissions, emission
reduction options and their effectiveness, costs, and other factors
related to new natural gas processing plants and the NSPS are also
applicable for existing sources. Therefore, the EPA concludes that BSER
for existing sources and the EG OOOOc for natural gas processing plants
is the requirement to use zero-emission controllers.
D. Proposed Standards for Well Liquids Unloading Operations
1. NSPS OOOOb
a. Background
In the 2015 NSPS OOOOa proposal (80 FR 56614-56615, September 18,
2015), the EPA stated that based on available information and input
received from stakeholders on the 2014 Oil and Natural Gas Sector
Liquids Unloading Processes review document,\259\ sufficient
information was not available to propose a standard for liquids
unloading.
---------------------------------------------------------------------------
\259\ U.S. Environmental Protection Agency. Oil and Natural Gas
Sector Liquids Unloading Processes. Report for Oil and Natural Gas
Sector. Liquids Unloading Processes Review Panel. April 2014.
---------------------------------------------------------------------------
At that time, the EPA requested comment on technologies and
techniques that could be applied to new gas wells to reduce emissions
from liquids unloading events in the future. In the 2016 NSPS OOOOa
final rule (81 FR 35846, June 3, 2016), the EPA stated that, although
the EPA received valuable information from the public comment process,
the information was not sufficient to finalize a national standard
representing BSER for liquids unloading at that time.
For this proposal, the EPA conducted a review of available
information, including new information that became available after the
2016 NSPS OOOOa rulemaking. As a result of this review, the EPA is
proposing a zero VOC and methane emission standard under NSPS OOOOb for
liquid unloading, which can be achieved using non-venting liquids
unloading methods. In the event that it is technically infeasible or
not safe to perform liquids unloading with zero emissions, the EPA is
proposing to require that an owner or operator establish and follow
BMPs to minimize methane and VOC emissions during liquids unloading
events to the extent possible. These proposed requirements apply to
each well liquids unloading event.
An overall description of liquids unloading, the definition of a
modification, the definition of affected facility, our BSER analysis,
and the proposed format of the standard are presented below.
[[Page 63210]]
b. Description
In new gas wells, there is generally sufficient reservoir pressure/
gas velocity to facilitate the flow of water and hydrocarbon liquids
through the well head and to the separator to the surface along with
produced gas. In mature gas wells, the accumulation of liquids in the
wellbore can occur when the bottom well pressure/gas velocity
approaches the average reservoir pressure (i.e., volumetric average
fluid pressure within the reservoir across the areal extent of the
reservoir boundaries).\260\ This accumulation of liquids can impede and
sometimes halt gas production. When the accumulation of liquids results
in the slowing or cessation of gas production (i.e., liquids loading),
removal of fluids (i.e., liquids unloading) is required in order to
maintain production. These gas wells therefore often need to remove or
``unload'' the accumulated liquids so that gas production is not
inhibited.
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\260\ Gordon Smith Review. Oil & Natural Gas Sector Liquids
Unloading Processes. Submitted: June 16, 2014. Pg. 4.
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The 2019 U.S. GHGI estimates almost 175,800 metric tpy of methane
emissions from liquids unloading events for natural gas systems.
Specifically, this includes almost 175,800 metric tpy from natural gas
production, 98,900 metric tpy of which is from liquids unloading events
that use a plunger lift, and 76,900 metric tpy from liquids unloading
events that do not use a plunger lift. The overall total represents 3
percent of the total methane emissions estimated from natural gas
systems.
In addition to the GHGI information, we also examined the
information submitted under GHGRP subpart W. Specifically, we examined
the GHGRP subpart W liquids unloading emissions data reported for
Reporting Years 2015 to 2019. The liquids unloading emissions reported
under GHGRP subpart W include emissions from venting wells, including
those wells that vent during events that use a plunger lift and wells
that vent during events that do not use a plunger lift. The information
reported shows that methane emissions from liquids unloading for a well
range from 0 to over 1,000 metric tons (1,100 tons) per year. While the
single well with liquids unloading emissions of 1,100 tpy appears to be
an outlier, there were over 65 subbasins with reported average liquids
unloading emissions of 50 tpy or greater per well when disaggregating
data by year and calculation method. There were over 1,000 wells
reporting in these subbasins. In addition, there were almost 300 sub-
basins with reported average liquids unloading methane emissions of 10
tpy or greater per well. There were almost 8,000 wells reporting in
these subbasins.
Another source of information reviewed related to emissions
information from liquids unloading was a study published in 2015 by
Allen, et al. (University of Texas (UT) Study).\261\ \262\ The UT Study
collected monitoring data across regions of the U.S. Among other
findings in this report, for wells that vent more than 100 times per
year, the average methane emissions per well per year were 27 metric
tpy, with 95 percent confidence bounds of 10 to 50 Mg/yr (based on the
confidence bounds in the emissions per event). The monitoring data
shows that methane emissions from liquids unloading for a well range
from 1 to 19,500 Mscf per year, or 0.02 to 406 tpy.\263\ As indicated
by the UT study \264\ emissions information, a small fraction of wells
account for a large fraction of liquids unloading emissions.
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\261\ D.T. Allen, D.W. Sullivan, D. Zavala-Araiza, A.P. Pacsi,
M. Harrison, K. Keen, M.P. Fraser, A. Daniel Hill, B.K. Lamb, R.F.
Sawyer, J.H. Seinfeld, Methane emissions from process equipment at
natural gas production sites in the United States: Liquid
unloadings. Environ. Sci. Technol. 49, 641-648 (2015). doi:10.1021/
es504016r Medline. (UT Study).
\262\ D.T. Allen, D.W. Sullivan, D. Zavala-Araiza, A.P. Pacsi,
M. Harrison, K. Keen, M.P. Fraser, A. Daniel Hill, B.K. Lamb, R.F.
Sawyer, J.H. Seinfeld. Methane Emissions from Process Equipment at
Natural Gas Production Sites in the United States: Liquid
Unloadings--Supporting Information; (UT Study--SI). Table S5-1, pg.
21.
\263\ UT Study--SI. Tables S3-1 to S3-3, pgs. 11-14.
\264\ UT Study. pg. 642.
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c. Modification
As noted in section XII.D.1.b, new wells typically do not require
liquids unloading until the point that the accumulation of liquids
impedes or even stops gas production. At that point, the well must be
unloaded of liquids to improve the gas flow. One method to accomplish
this involves the intentional manual venting of the well to the
atmosphere to improve gas flow. This is done using various techniques.
One common manual unloading technique diverts the well's flow,
bypassing the production separator to a lower pressure source, such as
an atmospheric pressure tank. Under this scenario, venting to the
atmospheric tank occurs because the separator operates at a higher
pressure than the atmospheric tank and the well will temporarily flow
to the atmospheric tank (which has a lower pressure than the
pressurized separator). Natural gas is released through the tank vent
to the atmosphere until liquids are unloaded and the flow diverted back
to the separator. As discussed later in this section, the EPA has
received feedback that there are technical difficulties with flaring
vented emissions as a result of the intermittent and surging flow
characteristic of venting for liquids unloading, and the changing
velocities during an unloading event.
Since each unloading event constitutes a physical or operational
change to the well that has the potential to increase emissions, the
EPA is proposing to determine each event of liquids unloading
constitutes a modification that makes a well an affected facility
subject to the NSPS. See 40 CFR 60.14(a) (``any physical or operational
change to an existing facility which results in an increase in the
emission rate to the atmosphere of any pollutant to which a standard
applies shall be considered a modification within the meaning of
section 111 of the Act''). The EPA solicits comment on this
determination.
d. Definition of Affected Facility
Given that we have proposed to determine that every liquids
unloading event is a modification, the next step is to define the
affected facility. The EPA recognizes that methods are commonly
employed that significantly reduce, or even eliminate, emissions from
liquids unloading. Therefore, the EPA is co-proposing two options on
how a modified well due to a liquids unloading event would be covered
under the rule.
Under the first option, the affected facility subject to the
requirements of NSPS OOOOb would be defined as every well that
undergoes liquids unloading after the effective date of the final rule.
Under this scenario, a well that undergoes liquids unloading is an
affected facility regardless of whether the liquids unloading approach
used results in venting to the atmosphere. This option posits that
techniques employed to unload liquids that do not increase emissions
are not to be considered in whether the unloading event is an affected
facility or not, since the liquids unloading event in their absence
could result in an emissions increase. This is somewhat analogous to a
physical change to an existing storage vessel that resulted in the
ability to increase throughput, and thus emissions. This physical
change could result in an increase in emissions even if emissions were
captured and routed back to a process such that the level of pollutant
actually emitted to the atmosphere did not change. Under this scenario,
the EPA could request and obtain compliance and enforcement information
on non-venting liquids
[[Page 63211]]
unloading event methods commonly employed (simple records and reporting
requirements), as well as venting liquids unloading events.
Under the second option, the affected facility would be defined as
every well that undergoes liquids unloading using a method that is not
designed to totally eliminate venting (i.e., that results in emissions
to the atmosphere). Under this scenario, if an owner or operator
employs a method to unload liquids that does not vent to the
atmosphere, the liquids unloading event would not constitute an
increase in emissions and therefore, the well would not be an affected
facility. As such, the first liquids unloading event that vents to the
atmosphere after the effective date of the final rule, would be an
affected facility subject to the requirements of NSPS OOOOb. This
option could create an enforcement information and compliance gap.
Specifically, the EPA would not be able to obtain compliance assurance
information on liquids unloading events and emissions/methods and there
could be a decreased incentive for owners or operators to ensure that
no unexpected emission episodes occur when a method designed to be non-
venting is used.
The EPA solicits comments on the two affected facility definition
options being co-proposed. Specifically, we request comment on whether
there are implementation and/or compliance assurance concerns that
arise with applying either of the co-proposed options. In addition, we
request comment on if there are any appropriate exemptions for
operations that may be unlikely to result in emissions, such as
wellheads that are not operating under positive pressure.
e. 2021 BSER Analysis
The choice of what liquids unloading technique to employ is based
on an operator well-by-well and reservoir-by-reservoir engineering
analysis. Because liquids unloading operations entail a number of
complex science and engineering considerations that can vary across
well sites, there is no single technological solution or technique that
is optimal for liquids unloading at all wells. Rather, a large number
of differing technologies, techniques and practices (i.e., ``methods'')
have been developed to address the unique characteristics of individual
wells so as to manage liquids and maintain production. These methods
include, but are not limited to, manual unloading, velocity tubing or
velocity strings, beam or rod pumps, electric submergence pumps,
intermittent unloading, gas lift (e.g., use of a plunger lift), foam
agents, wellhead compression, and routing the gas to a sales line or
back to a process.
Selecting a particular method to meet a particular well's unloading
needs must be based on a production engineering decision that is
designed to remove the barriers to production. The situation is further
complicated as the best method for a particular well can change over
time. At the onset of liquids loading, techniques that rely on the
reservoir energy are typically used. Eventually a well's reservoir
energy is not sufficient to remove the liquids from the well and it is
necessary to add energy to the well to continue production.
In the 2016 NSPS OOOOa final rule preamble, the EPA acknowledged
that operators must select the technique to perform liquids unloading
operations based on the conditions of the well each time production is
impaired. During the development of the 2016 NSPS OOOOa rule, the EPA
considered subcategorization based on the potential for well site
liquids unloading emissions but determined that the differences in
liquids unloading events (with respect to both frequency and emissions
level) are due to specific conditions of a given well at the time the
operator determines that well production is impaired such that
unloading must be done. Since owners and operators must select the
technique to perform an unloading operation based on those conditions,
and because well conditions change over time, each iteration of
unloading may require repeating a single technique or attempting a
different technique that may not have been appropriate under prior
conditions. As noted above, we recognized that the choice of method to
unload liquids from a well needs to be a production engineering
decision based on the characteristics of the well at the time of the
unloading, and owners and operators need the flexibility to select a
method that is effective and can be safely employed. No information has
become available since 2016 that leads the EPA to reach a different
conclusion regarding subcategorization of wells for the purpose of
developing standards to address liquids unloading emissions. Further,
the EPA acknowledges the need for owners and operators to have the
flexibility to select the most appropriate method(s) and recognize that
any standard must not impede this flexibility.
Many methods used for liquids unloading do not result in any
venting to the atmosphere, provided that the method is properly
executed. High-level summaries of a few of these methods are provided
below.\265\
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\265\ ``Oil and Natural Gas Sector Liquids Unloading
Processes''. Report for Oil and Natural Gas Sector Liquids Unloading
Processes Review Panel. Prepared by U.S. EPA OAQPS. April 2014.
\265\ 80 FR 56593, September 18, 2015.
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A commonly used method employed in the field is the use of a
plunger lift system. While plunger lift systems often are used in a way
to minimize emissions, under certain conditions they can be operated to
unload liquids in a manner that eliminates the need to vent to the
atmosphere. Plunger lifts use the well's own energy (gas/pressure) to
drive a piston or plunger that travels the length of the tubing in
order to push accumulated liquids in the tubing to the surface.
Specific criteria regarding well pressure and liquid to gas ratio can
affect applicability. Candidate wells for plunger lift systems
generally do not have adequate downhole pressure for the well to flow
freely into a gas gathering system. Optimized plunger lift systems
(e.g., with smart well automation) can decrease the amount of gas
vented by up to and greater than 90 percent, and in some instances can
reduce the need for venting due to overloading. Plunger lift costs
range from $1,900 to $20,000.\266\ Adding smart automation can cost
anywhere between an estimated $4,700 to $18,000 depending on the
complexity of the well. Natural Gas STAR estimates that the annual cost
savings from avoided emissions from the use of an automated system
ranges anywhere between $2,400 and $10,241 per year.\267\
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\266\ U.S. Environmental Protection Agency. Installing Plunger
Lift Systems in Gas Wells. Office of Air and Radiation: Natural Gas
Star Program. Washington, DC. 2006.
\267\ U.S. Environmental Protection Agency. (U.S. EPA) 2011.
Options for Removing Accumulated Fluid and Improving Flow in Gas
Wells. Office of Air and Radiation: Natural Gas Star Program.
Washington, DC. 2011. pg. 1.
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Other artificial lifts (e.g., rod pumps, beam lift pumps, pumpjacks
and downhole separator pumps) are typically used when there is
inadequate pressure to use a plunger lift, and the only means of
liquids unloading to keep gas flowing is downhole pump technology.
Artificial lifts can be operated in a manner that produces no
emissions. The use of an artificial lift requires access to a power
source. The capital and installation costs (including location
preparation, well clean out, artificial lift equipment and pumping
unit) is estimated to be $41,000 to $62,000/well, with the average cost
of a pumping unit being between $17,000 to $27,000. \268\
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\268\ U.S. EPA, 2011. pg. 9.
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[[Page 63212]]
Velocity tubing is smaller diameter production tubing that reduces
the cross-sectional area of flow, increasing the flow velocity and
achieving liquids removal without blowing emissions to the atmosphere.
Generally, a gas flow velocity of 1,000 feet per minute (fpm) is
necessary to remove wellbore liquids. Velocity tubing strings are
appropriate for low volume natural gas wells upon initial completion or
near the end of their productive lives with relatively small liquids
production and higher reservoir pressure. Candidate wells include
marginal gas wells producing less than 60 Mcfd. Similarly, coil tubing
can also be used in wells with lower velocity gas production (i.e.,
seamed coiled tubing may provide better lift due to elimination of
turbulence in the flow stream). The proper use of velocity tubing is
considered to be a ``no emissions'' solution. It is also low
maintenance and effective for low volumes lifted. Velocity lifting can
be deployed in combination with foaming agents (discussed below). The
capital and installation costs are estimated to range anywhere from
$7,000 to $64,000 per well.\269\ Installation requires a well workover
rig to remove existing production tubing and placement of the smaller
diameter tubing string in the well.
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\269\ U.S. EPA, 2011. pg. 8.
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The use of foaming agents (soap, surfactants) as a method to unload
liquids is implemented by the injection of foaming agents in the
casing/tubing annulus by a chemical pump on a timer basis. The gas
bubbling of the soap-water solution creates gas-water foam which is
more easily lifted to the surface for water removal. This, like the use
of artificial lifts, requires power to run the surface injection pump.
Additionally, foaming agents work best if the fluid in the well is at
least 50 percent water and are not effective for natural gas liquids or
liquid hydrocarbons. This method requires that the soap supply be
monitored. If the well is still unable to unload fluid, smaller tubing
may be needed to help lift the fluids. Foaming agents and velocity
tubing are reported as possibly being more effective when used in
combination. No equipment is required in shallow wells. In deep wells,
a surfactant injection system requires the installation of surface
equipment and regular monitoring. Foaming agents are reported as being
low cost ``no emissions'' solution. The capital and startup costs to
install soap launchers and velocity tubing is estimated to range
between $7,500 and $67,880, with the monthly cost of the foaming agent
is approximately $500 per well or approximately $6,000 per year.\270\
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\270\ U.S. EPA. 2011. Pg. 8.
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These are just a few examples of demonstrated methods that are
being used in the industry to unload accumulated liquids that impair
production, that can be implemented without venting and, thus, without
emissions. As stressed earlier, the selection of a specific method must
be made based on well-specific characteristics and conditions.
Since GHGRP subpart W only requires reporting of liquids unloading
events that resulted in venting of methane, no information is submitted
regarding those wells that utilize a non-venting method. The EPA is
also not aware of information that specifies the total number of wells
that need to undergo liquids unloading. A 2012 report sponsored by the
API and American Natural Gas Alliance (ANGA) \271\ provided more
definitive insight into the number of wells that use non-venting
liquids unloading methods. This report indicated that an estimated 21.1
percent of plunger equipped wells vent, and 9.3 percent of non-plunger
equipped wells vent. The EPA interprets this to mean that almost 80
percent of plunger-equipped wells, and over 90 percent of non-plunger-
equipped wells perform liquids unloading and utilize non-venting
methods.
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\271\ Shires, T. URS Corporation and Lev-On, M. the LEVON Group.
Characterizing Pivotal Sources of Methane Emissions from Natural Gas
Production. Summary and Analysis of API and ANGA Survey Responses.
Prepared for the American Petroleum Institute and the American
Natural Gas Alliance. September 21, 2012.
---------------------------------------------------------------------------
As noted above, there is a tremendous range in the emissions from
liquids unloading reported for individual wells. Further, as discussed
above, the costs for the non-venting methods range considerably. Also,
as discussed above, we have determined that the myriad of possible
reservoir conditions and unloading methods do not lend to any
reasonable subcategorization of the industry for which representative
wells could be designed. Therefore, it is not possible to develop a
``model'' well, or even a series of model wells, that can be used to
conduct the type of analysis frequently performed for BSER
determinations that calculates a cost per ton of emissions reduced (or
in this case eliminated).
Based on the highest costs included in the cost examples provided
above, the cost effectiveness of a non-venting method would be
considered reasonable for wells with annual methane emissions from
liquids unloading of 16 tpy or greater, or VOC emissions of 3 tpy or
greater. This upper range is based on the cost of the combination of
velocity tubing and soap launchers. The upper range of the capital cost
cited above was $67,800. Annualizing this capital cost at a 7 percent
interest rate over 10 years, and adding in the $6,000 per year foaming
agent cost, results in a total annual cost of $15,600. Given the total
elimination of emissions, the cost effectiveness for a well with 16 tpy
methane emissions would be $980 per ton of methane reduced, which is a
level that the EPA considers reasonable for methane. Similarly, for
VOC, the cost effectiveness for a well with 3 tpy VOC emissions would
be $5,200 per ton of VOC reduced. This is also a level that the EPA
considers reasonable. Given the range of costs, it could be reasonable
even for some wells with annual liquids unloading methane emissions as
low as 2.5 tpy ($400 per ton of methane reduced (velocity tubing)), or
VOC emissions as low as 0.2 tpy ($5,000 per ton of VOC reduced
(velocity tubing)). Based on the GHGRP subpart W data for the years
2015 through 2019, around 50 percent of the wells that performed
liquids unloading and reported emissions reported emissions higher than
these levels.
While owners and operators must select a liquids unloading method
that is applicable for the well-specific conditions, they have the
choice of many methods that can be used to eliminate venting/emissions
from liquids unloading events. While we do not have information to
calculate the specific percentage of total wells undergoing liquids
unloading that use non-venting methods, available information suggests
that a majority of wells that undergo liquids unloading do not vent.
The EPA solicits information on the number (or percent) of liquids
unloading events that vent to the atmosphere versus do not vent to the
atmosphere under normal conditions and whether there are technical
obstacles (other than costs) that would not allow liquids unloading to
be performed without venting.
CAA section 111(a) requires that the standard reflect the BSER that
the EPA determines ``has been adequately demonstrated.'' An
``adequately demonstrated system'' is one that ``has been shown to be
reasonably reliable, reasonably efficient, and which can reasonably be
expected to serve the interests of pollution control without becoming
exorbitantly costly in an economic or environmental way.'' Essex Chem.,
486 F.2d at 433. For the reasons explained above and further elaborated
below, the EPA considers non-venting methods such as those described
above
[[Page 63213]]
to have been adequately demonstrated as the BSER for liquids unloading
events. The complete elimination of emissions from liquids unloading
with these non-venting methods have been adequately demonstrated in
practice. The EPA notes that as part of decisions regarding liquids
unloading, one goal of owners and operators is to eliminate venting to
prevent the loss of product (natural gas) that could be routed to the
sales line. States currently encourage the use of methods to eliminate
emissions unless venting of emissions is necessary for safety reasons
or when it is technically infeasible to not vent to unload liquids from
the wellbore. For example, Pennsylvania has a general plan approval
and/or general operating permit application (BAQ-GPA/GP-5A) that
specifies that an owner or operator that conducts wellbore liquids
unloading operations shall use best management practices including, but
not limited to, plunger lift systems, soaping, swabbing, unless venting
is necessary for safety to mitigate emissions during liquids unloading
activities (Best Available Technology (BAT) Compliance Requirements
under Section L of the General Permit).
As discussed previously, a majority of wells already conduct
liquids unloading operations without venting to the atmosphere. Also,
as discussed previously, there are multiple non-venting liquids
unloading methods that an owner and operator can select based on a
well's specific characteristics and conditions. Our evaluation of costs
shows that there are non-venting liquids unloading methods that could
be employed to unload liquids that are reasonable given a wide range of
emission levels. Finally, there are no negative secondary environmental
impacts that would result from the implementation of methods that would
eliminate venting of methane and VOC emissions to the atmosphere. In
light of the above, the EPA considers non-venting liquids unloading
methods to have been adequately demonstrated to represent BSER for
reducing methane and VOC emissions during liquids unloading events.
An ``adequately demonstrated'' system needs not be one that can
achieve the standard ``at all times and under all circumstances.''
Essex Chem., 486 F.2d at 433. That said, as discussed below, the EPA
recognizes that there may be reasons that a non-venting method is
infeasible for a particular well, and the proposed rule would allow for
the use of BMPs to reduce the emissions to the maximum extent possible.
The EPA recognizes that there may be safety and technical reasons
why venting to the atmosphere is necessary to unload liquids. In
addition, it is possible that a well production engineer has already
explored non-venting options and determined that there was no feasible
option due to its specific characteristics and conditions. For
scenarios where a liquids unloading method employed requires venting to
the atmosphere, the EPA evaluated requiring BMPs that would minimize
venting to the maximum extent possible. There are several States that
require the development and implementation of BMPs that minimize
emissions from liquids unloading events that vent. For example,
Colorado requires specified BMPs to eliminate or minimize vented
emissions from liquids unloading. The rule requires that all attempts
be made to unload liquids without venting unless venting is required
for safety reasons. If venting is required, the rule requires that
owners and operators be on site and that they ensure that any venting
is limited to the maximum extent practicable. Specific BMPs evaluated
are based on State rules that require BMPs to minimize emissions during
liquids unloading events are to require operators to monitor manual
liquids unloading events onsite and to follow procedures that minimize
the need to vent emissions during an event. This includes following
specific steps that create a differential pressure to minimize the need
to vent a well to unload liquids and reducing wellbore pressure as much
as possible prior to opening to atmosphere via storage tank, unloading
through the separator where feasible, and requiring closure of all well
head vents to the atmosphere and return of the well to production as
soon as practicable. For example, where a plunger lift is used, the
plunger lift can be operated so that the plunger returns to the top and
the liquids and gas flow to the separator. Under this scenario, venting
of the gas can be minimized and the gas that flows through the
separator can be routed to sales. In situations where production
engineers select an unloading technique that results or has the
potential to vent emissions to the atmosphere, owners and operators
already often implement BMPs in order to increase gas sales and reduce
emissions and waste during these (often manual) liquids unloading
activities. We performed a cost and impacts evaluation of the use of
BMPs to reduce emissions from liquids unloading. This evaluation is
provided in the NSPS OOOOb and EG TSD for this rulemaking.
Another potential method for reducing emissions from liquids
unloading is to capture the vented gas from an unloading event and
route it to a control device. At the time the Crude Oil and Natural Gas
Sector Liquids Unloading Processes draft review document was submitted
to reviewers, the EPA noted that, although the EPA was not aware of any
specific instances where combustion devices/flares were used to control
emissions vented from unloading events, the EPA requested information
on the technical feasibility of flaring as an emissions control option
for liquids unloading events. Feedback received from reviewers
indicated that there are technical reasons that flaring during liquids
unloading is not a feasible option.\272\ Reviewers emphasized that, in
order to flare gas during liquids unloading, the liquids would need to
be separated from the well stream, and the intermittent and surging
flow characteristics of venting for liquids unloading, changing
velocities during an unloading, and flare ignition considerations for a
sporadically used flare (i.e., would require either a continuous pilot
or electronic igniter) would make use of a flare technically and
financially infeasible.273 274 The reviewers indicated that
separating the liquids from the well stream would require the well
stream to flow through a separator with sufficient backpressure to
separate the gas and liquids. One reviewer noted that after separating
the liquids from the well stream the gas would then be piped to flare
system, where the backpressure needed to operate the separator would
affect the performance of a plunger lift system (if used). Based on
feedback received on the technical and cost feasibility of using a
flare to control vented emissions from liquids unloading events
indicating that a flare cannot be used in all situations, we did not
consider this option any further in this proposal. However, the EPA is
soliciting comments about the use of control devices to reduce
emissions from liquids unloading events. Specifically, we request
information on the types of wells and unloading events for which
routing to control is feasible
[[Page 63214]]
and effective, the level of emission reduction achieved, and the
testing and monitoring requirements that apply.
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\272\ U.S. Environmental Protection Agency. Oil and Natural Gas
Sector Liquids Unloading Processes. Report for Crude Oil and Natural
Gas Sector. Liquids Unloading Processes Review Panel. April 2014.
\273\ Gordon Smith Review. Oil and Natural Gas Sector Liquids
Unloading Processes. Review Submitted: June 16, 2014. Pg. 31.
\274\ Jim Bolander, P.E., Senior Vice President, Southwestern
Energy (SWN). Review Submitted: April 2014. Pg. 8.
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A similar potential method is to capture the vented gas from an
unloading event and route it to the sales line or back to a process.
This could potentially represent another method that results in zero
emissions. While this is not a mitigation option that has been
specifically mentioned for emissions from liquids unloading, it is a
common option for other emission sources in the oil and natural gas
production segment. The EPA is soliciting comments about the option to
collect and route emissions back to the sales line or to a process.
Specifically, we request information on the types of wells and
unloading events for which this option is feasible (if any). If this
option is feasible, we also request information on the specifics of the
equipment and processes needed to accomplish this, as well as the
costs.
In conclusion, the EPA evaluated several options and identified the
use of non-venting methods as the BSER for reducing methane and VOC
emissions during liquids unloading events. However, the EPA recognizes
there could be situations where it is infeasible to utilize a non-
venting method. Therefore, the EPA proposes to allow for the
development and implementation of BMPs to reduce emissions to the
extent possible during liquids unloading where it is infeasible to
utilize a non-venting method.
f. Format of the Standard
As discussed under section XII.D.1.d of this preamble, the EPA is
co-proposing two regulatory approaches to implement the BSER
determination.
For Option 1, the affected facility would be defined as every well
that undergoes liquids unloading. This would mean that wells that
utilize a non-venting method for liquids unloading would be affected
facilities and subject to certain reporting and recordkeeping
requirements. These requirements would include records of the number of
unloadings that occur and the method used. A summary of this
information would also be required to be reported in the annual report.
The EPA also recognizes that under some circumstances venting could
occur when a selected liquids unloading method that is designed to not
vent to the atmosphere is not properly applied (e.g., a technology
malfunction or operator error). Under the proposed rule Option 1 owners
and operators in this situation would be required to record and report
these instances, as well as document and report the length of venting
and what actions were taken to minimize venting to the maximum extent
possible.
For wells that utilize methods that vent to the atmosphere, the
proposed rule would require that they: (1) Document why it is
infeasible to utilize a non-venting method due to technical, safety, or
economic reasons; (2) develop BMPs that ensure that emissions during
liquids unloading are minimized; (3) follow the BMPs during each
liquids unloading event and maintain records demonstrating they were
followed; (4) report the number of liquids unloading events in an
annual report, as well as the unloading events when the BMP was not
followed. While the proposed rule would not dictate the specific
practices that must be included, it would specify minimum acceptance
criteria required for the types and nature of the practices. Examples
of the types and nature of the required practice elements for BMP are
provided in section XII.D.1.e, such as those contained in Colorado's
rule. The EPA is specifically requesting comment on the minimum
elements that should be required in BMPs and the specificity that the
proposed rule should include regarding these elements.
An advantage of this regulatory option is that it would provide
information to the EPA on the number of liquids unloading events that
occur and the types of unloading methods used. Having this important
information would enhance the EPA, the industry, and the public's
knowledge of emissions from liquids unloading. Option 1 would also
provide incentive for owners and operators to ensure that non-venting
methods are applied as they are designed such that unexpected emissions
do not occur as the result of technology malfunctions or operator
error. However, it would result in some recordkeeping and reporting
burden for wells that already use or plan to use non-venting methods
that would not be incurred under Option 2.
For Option 2, the affected facility would be defined as every well
that undergoes liquids unloading using a method that is not designed to
eliminate venting. The significant difference in this option is that
wells that utilize non-venting methods would not be affected facilities
that are subject to the NSPS OOOOb. Therefore, they would not have
requirements other than to maintain records to demonstrate that they
used non-venting liquids unloading methods. The requirements for wells
that use methods that vent would be the same as described above under
Option 1.
The EPA believes that this option would provide additional
incentive for owners and operators to seek ways to overcome potential
infeasibility issues to ensure that their wells are not affected
facilities and subject to reporting and recordkeeping requirements.
This would ultimately result in lower emissions. However, this would
not provide the EPA information to have a more comprehensive
understanding of emissions and emission reduction methods from liquids
unloading. It would also not provide incentive for owners and operators
to ensure that no unexpected emission episodes occur when a method
designed to be non-venting is used.
2. EG OOOOc
As described above, the EPA is proposing that each unloading event
represents a modification, which will make the well subject to new
source standards under NSPS. Therefore, existing wells that undergo
liquids unloading would become subject to NSPS OOOOb. This will mean
that there will never be a well that undergoes liquids unloading that
will be ``existing'' for purposes of CAA section 111(d). Therefore,
there is no need for emissions guidelines or an associated presumptive
standard under EG OOOOc for liquids unloading operations.
E. Proposed Standards for Reciprocating Compressors
1. NSPS OOOOb
a. Background
The 2012 NSPS OOOO and the 2016 NSPS OOOOa applied to each
individual new or reconstructed reciprocating compressor, except for
those compressors located at a well site, or those located at an
adjacent well site and servicing more than one well site. The 2016 NSPS
OOOOa required the reduction of methane and VOC emissions from new,
reconstructed, or modified reciprocating compressors by replacing rod
packing systems within 26,000 hours or 36 months of operation,
regardless of the condition of the rod packing. As an alternative, the
2016 NSPS OOOOa allowed owners or operators to collect the emissions
from the rod packing using a rod packing emissions collection system
that operates under negative pressure and route the rod packing
emissions to a process through a closed vent system.
In determining BSER for reciprocating compressors in 2016, the EPA
determined that the previous determination for NSPS OOOO conducted in
2011/2012 still represented BSER in 2016. In the 2012 determination the
EPA first concluded that the piston rod packing wear
[[Page 63215]]
produces fugitive emissions that cannot be captured and conveyed to a
control device, and that an operational standard pursuant to section
111(h) of the CAA was appropriate. The EPA conducted analyses of the
costs and emission reductions of the replacement of rod packing every 3
years or 26,000 hours of operation and determined that the costs per
ton of emissions reduced were reasonable for the industry, with the
exception of compressors at well sites. Based on the 2011 BSER
analysis, requiring replacement of rod packing every 3 years or 26,000
hours of operation for well site reciprocating compressors was not
considered cost effective (almost $57,000 per ton of VOC reduced).\275\
No other more stringent control options were evaluated at that time.
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\275\ 2011 NSPS OOOO TSD. pg. 6-17.
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For this review of the NSPS, the EPA focused on these control
options which were previously assessed for the 2012 NSPS OOOO and the
2016 NSPS OOOOa. In addition, we evaluated an option that would require
annual monitoring to determine if the rod packing needed to be
replaced. This option is in contrast to the option where replacement is
required on a fixed (e.g., 3 year) schedule. For this review, BSER was
evaluated for reciprocating compressors at gathering and boosting
stations in the production segment (considered to be representative of
emissions from reciprocating compressors at centralized production
facilities), at natural gas processing plants, and at sites in the
transmission and storage segment. In 2012 and in 2016, the EPA
determined that the cost effectiveness of replacement of the rod
packing based on the fixed 3-year (or 26,000 hours) schedule was
unreasonable for reciprocating compressors located at the well site
(discussed below). No new information has become available to change
this determination. Therefore, we did not include reciprocating
compressors located at well sites in our evaluation of regulatory
options.
However, as discussed in section XI.L (Centralized Production
Facilities) of this preamble, the EPA believes the definition of ``well
site'' in NSPS OOOOa may cause confusion regarding whether
reciprocating compressors located at centralized production facilities
are also exempt from the standards. The EPA is proposing a new
definition for a ``centralized production facility''. The EPA is
proposing to define centralized production facilities separately from
well sites because the number and size of equipment, particularly
reciprocating and centrifugal compressors, is larger than standalone
well sites which would not be included in the proposed definition of
``centralized production facilities''. This proposal is necessary in
the context of reciprocating compressors to distinguish between these
compressors at centralized production facilities where the EPA has
determined that the standard should apply, and compressors at
standalone well sites where the EPA has determined that the standard
should not apply. In our current analysis, described below, we consider
the reciprocating compressor gathering and boosting segment emission
factor as being representative of reciprocating compressor emissions
located at centralized production facilities. As such, the EPA is
proposing that reciprocating compressors located at centralized
production facilities would be subject to the standards in NSPS OOOOb
and the EG in subpart OOOOc, but reciprocating compressors at well
sites (standalone well sites) would not.
As a result of the EPA's review of NSPS OOOOa, we are proposing
that BSER is to replace the rod packing when, based on annual flow rate
measurements, there are indications that the rod packing is beginning
to wear to the point where there is an increased rate of natural gas
escaping around the packing to unacceptable levels. We are proposing
that if annual flow rate monitoring indicates a flow rate for any
individual cylinder as exceeding 2 scfm, an owner or operator would be
required to replace the rod packing.
b. Description
In a reciprocating compressor, natural gas enters the suction
manifold, and then flows into a compression cylinder where it is
compressed by a piston driven in a reciprocating motion by the
crankshaft powered by an internal combustion engine. Emissions occur
when natural gas leaks around the piston rod when pressurized natural
gas is in the cylinder. The compressor rod packing system consists of a
series of flexible rings that create a seal around the piston rod to
prevent gas from escaping between the rod and the inboard cylinder
head. However, over time, during operation of the compressor, the rings
become worn and the packaging system needs to be replaced to prevent
excessive leaking from the compression cylinder.
As discussed previously, emissions from a reciprocating compressor
occur when, over time, during operation of the compressor, the rings
that form a seal around the piston rod that prevents gas from escaping
become worn. This results in increasing emissions from the compression
cylinder. Based on the 2021 GHGI,\276\ the methane emissions from
reciprocating compressors in 2019 represented 14 percent of the total
methane emissions from natural gas systems in the Crude Oil and Natural
Gas Industry sector. For segments where the GHGI included a breakdown
of methane emissions for reciprocating compressors, the reported
emissions were 309,500 metric tons for the gathering and boosting
segment, 46,700 metric tons for the processing segment, 406,500 metric
tons for the transmission segment, and 103,200 metric tons for the
storage segment.
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\276\ U.S. Environmental Protection Agency. Inventory of U.S.
Greenhouse Gas Emissions and Sinks (1990-2019). Published in 2021.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2019.
---------------------------------------------------------------------------
c. Affected Facility
For purposes of the NSPS, the reciprocating compressor affected
facility is a single reciprocating compressor. A reciprocating
compressor located at a well site, or an adjacent well site and
servicing more than one well site, is not an affected facility under
the proposed rule for the NSPS OOOOb. As discussed above, the EPA is
proposing that the affected facility includes reciprocating compressors
located at centralized production facilities and the affected facility
exception for ``a well site, or an adjacent well site servicing more
than one well site'' applies to standalone well sites and not
centralized production facilities.
d. 2021 BSER Analysis
The methodology used for estimating emissions from reciprocating
compressor rod packing is consistent with the methodology developed for
the 2012 NSPS OOOO BSER analysis and then also used to support the 2016
NSPS OOOOa BSER. This approach uses volumetric methane emission factors
referenced in the EPA/GRI study \277\ as the basis, multiplied by the
density of methane. These factors were per cylinder, so they were
multiplied by the average number of cylinders per reciprocating
compressor at each oil and gas industry segment, the pressurized factor
(percentage of hours per year the compressor was pressurized), and
8,760 hours (number of hours in a year). Once the methane emissions
were calculated, VOC emissions were calculated by multiplying the
methane by ratios developed based on representative gas composition.
The specific ratios that were used for this analysis were 0.278
[[Page 63216]]
pounds VOC per pound of methane for the production and processing
segments, and 0.0277 pounds VOC per pound of methane for the
transmission and storage segment. The resulting baseline emissions from
reciprocating compressors were 12.3 tpy methane (3.4 tpy VOC) from
gathering and boosting stations, 23.3 tpy methane (6.5 tpy VOC) from
natural gas processing plants, 27.1 tpy methane (0.75 tpy VOC) from
transmission stations, and 28.2 tpy methane (0.78 tpy VOC) from storage
facilities.
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\277\ EPA/GRI. (1996). Methane Emissions from the Natural Gas
Industry: Volume 8--Equipment Leaks.
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Reducing emissions that result from the leaking of natural gas past
the piston rod packing can be accomplished through several approaches
including: (1) Specifying a frequency for the replacement of the
compressor rod packing, (2) monitoring the emissions from the
compressor and replacing the rod packing when the results exceed a
specified threshold, (3) specifying a frequency for the replacement of
the piston rod, (4) requiring the use of specific rod packing
materials, and/or (5) capturing the leaking gas and routing it either
to a process or a control device.
There was either insufficient information to establish BSER or it
was determined that the option cannot be applied in all situations for
approach options (3) through (5). These are discussed briefly below.
Like the packing rings, piston rods on reciprocating compressors
also deteriorate. Piston rods, however, wear more slowly than packing
rings, having a life of about 10 years.\278\ Rods wear ``out-of-round''
or taper when poorly aligned, which affects the fit of packing rings
against the shaft (and therefore the tightness of the seal) and the
rate of ring wear. An out-of-round shaft not only seals poorly,
allowing more leakage, but also causes uneven wear on the seals,
thereby shortening the life of the piston rod and the packing seal.
Replacing or upgrading the rod can reduce reciprocating compressor rod
packing emissions. Also, upgrading piston rods by coating them with
tungsten carbide or chrome reduces wear over the life of the rod. We
assume that operators will choose, at their discretion, when to
replace/realign or retrofit the rod as part of regular maintenance
procedures and replace the rod when appropriate when the compressor is
out of service for other maintenance such as rod packing replacement.
Although replacing/realigning or retrofitting the rod has been
identified as a potential methane and VOC emission reduction option for
reciprocating compressors, there is insufficient information on its
emission reduction potential and use throughout the industry.
Therefore, we did not evaluate this option any further as BSER for this
proposal.
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\278\ U.S. Environmental Protection Agency. Lessons Learned from
Natural Gas STAR Partners. Reducing Methane Emissions from
Compressor Rod Packing Systems. Natural Gas STAR Program. 2006.
---------------------------------------------------------------------------
Although specific analyses have not been conducted, there may be
potential for reducing methane and VOC emissions by updating rod
packing components made from newer materials, which can help improve
the life and performance of the rod packing system. One option is to
replace the bronze metallic rod packing rings with longer lasting
carbon-impregnated Teflon rings. Compressor rods can also be coated
with chrome or tungsten carbide to reduce wear and extend the life of
the piston rod. Although changing the rod packing material has been
identified as a potential methane and VOC emission reduction option for
reciprocating compressors, there is insufficient information on its
emission reduction potential and use throughout the industry.
Therefore, we did not evaluate this option any further as BSER for this
proposal.
The 2016 NSPS OOOOa includes the alternative to route the emissions
from reciprocating compressors to a process. One estimate obtained by
the EPA states that a gas recovery system can result in the elimination
of over 99 percent of methane emissions that would otherwise occur from
the venting of the emissions from the compressor rod packing. The
emissions that would have been vented are combusted in the compressor
engine to generate power. It was estimated that, if a facility is able
to route rod packing vents to a VRU system, it is possible to recover
approximately 95-100 percent of emissions. As a comparison, the EPA
estimated that the 3-year/26,000-hour changeout results in between 55
and 80 percent emission reduction. Therefore, an option to achieve
additional emission reductions could be to require routing the
reciprocating compressor emissions to a process/through a closed vent
system under negative pressure. Although this was a control option
considered in the 2016 NSPS OOOOa (and included as an alternative), the
EPA did not require routing to a process for all compressors because at
that time there was insufficient information to require this as a
control for all reciprocating compressors. The EPA received feedback
that this option cannot be applied in every installation, and has not
received any new information that indicates this has changed. Thus,
this option was not considered further as a requirement but for this
proposal, as with the 2016 NSPS OOOOa, it is considered to be an
acceptable alternative to mitigate methane and VOC emissions where it
is technically feasible to apply.
Similarly, another option evaluated as having the potential to
achieve methane and VOC emission reductions was to require the
collection of emissions in a closed vent system and routing them to a
flare or other control device. If the gas is routed to a flare,
approximately 95 percent of the methane and VOC would be reduced. The
EPA has expressed historically and maintains that combustion is not
believed to be a technically feasible control option for reciprocating
compressors because, as detailed in the 2011 NSPS OOOO TSD, routing of
emissions to a control device can cause positive back pressure on the
packing, which can cause safety issues due to gas backing up in the
distance piece area and engine crankcase in some designs. The EPA has
not identified any new information to indicate that this has changed.
Therefore, this option was not considered further as BSER for this
proposal.
The remaining two control option approaches that were evaluated
further for this proposal include: (1) Specifying a frequency for the
replacement of the compressor rod packing (equivalent to the frequency
used in the 2016 NSPS OOOOa BSER control level), and (2) monitoring the
emissions from the compressor and replacing the rod packing when the
results exceed a specified threshold. Both of these approaches would
reduce the escape of natural gas from the piston rod. No wastes would
be created (other than the worn packing that is being replaced) and no
wastewater would be generated.
As noted previously, periodically replacing the packing rings
ensures the correct fit is maintained between packing rings and the
rod, thereby limiting emissions occurring around the flexible rings
that fit around the shaft by recreating a seal against leakage that may
have been lost due to wear. The potential emission reductions for
reciprocating compressors at gathering and boosting stations,
processing plants, and transmission and storage facilities were
calculated by comparing the average rod packing emissions with the
average emissions from newly installed and worn-in rod packing. As
noted above, because the EPA concluded that the cost effectiveness of
this option was extremely unreasonable for reciprocating compressors at
well sites in previous BSER analyses (see the 2011 NSPS OOOO TSD,
section 2.2; 80 FR 56620, September 18, 2015), and since no new
information was identified that
[[Page 63217]]
would change this outcome as it relates to stand alone well sites,
reductions and costs were not re-evaluated in this analysis for
reciprocating compressors at production well sites.
The emissions after the replacement of the rod packing were
calculated using the methodology used under previous NSPS actions (see
NSPS OOOOb and EG TSD, section 7.1). The resulting emission reductions
used for the analysis represented the emission reductions expected in
the year the rod packing is replaced. It is expected that there would
be an increase in the emissions (and decrease in the emission
reductions) from a compressor where the rod packing was replaced the
second and third years before the next replacement. As noted above,
this assumed reduction was between 55 and 80 percent depending on the
location of the compressor.
The costs of replacing rod packing were obtained from a Natural Gas
STAR Lessons Learned document \279\ and the dollars were converted to
2019 dollars. The estimated cost to replace the packing rings in 2019
dollars was estimated to be $1,920 per cylinder. It was assumed that
rod packing replacement would occur during planned shutdowns and
maintenance, and therefore no additional travel costs would be incurred
for implementing a rod packing replacement program. Since the assumed
number of cylinders differs for reciprocating compressors at different
segments, this means the capital costs also vary. These estimated
capital costs are $6,350 at gathering and boosting and transmission
stations, $4,800 at processing plants, and $8,650 at storage stations.
---------------------------------------------------------------------------
\279\ EPA (2006). Lessons Learned: Reducing Methane Emissions
from Compressor Rod Packing Systems. Natural Gas STAR. Environmental
Protection Agency.
---------------------------------------------------------------------------
The 26,000-hour replacement frequency used for the cost impacts in
the 2011 NSPS OOOO TSD and 2016 NSPS OOOOa TSD was determined using a
weighted average of the annual percentage of time that reciprocating
compressors are pressurized. The weighted average percentage was
calculated to be 98.9 percent. This percentage was multiplied by the
total number of hours in 3 years to obtain a value of 26,000 hours.
This calculates to an average of 3.8 years for gathering and boosting
compressors, 3.3 years for processing compressors, 3.8 years for
transmission compressors, and 4.4 years for storage compressors. The
calculated years were assumed to be the equipment life of the
compressor rod packing and were used to calculate the capital recovery
factor for each of the segments. Assuming an interest rate of 7
percent, the capital recovery factors were calculated to be 0.3093,
0.3498, 0.3093, and 0.2695 for the gathering and boosting part of
production, processing, transmission, and storage segments,
respectively.
The capital costs were calculated using the average rod packing
cost noted above and the average number of cylinders per compressor
(which differs depending on sector segment). The annual capital costs
were calculated using the capital costs and the capital recovery
factors. The estimated annual costs ranged from $1,700 at processing
plants to just over $2,300 at storage facilities. Note that these
estimated costs represent the costs, and associated emission
reductions, that would occur in the year when the rod packing was
changed. There would be no costs for the other two years in the three-
year cycle. The costs presented for gathering and boosting segment
reciprocating compressors represent the estimated costs assumed for
reciprocating compressors located at centralized production facilities.
There are monetary savings associated with the amount of natural
gas saved with reciprocating compressor rod packing replacement.
Monetary savings associated with the amount of gas saved with
reciprocating compressor rod packing replacement were estimated using a
natural gas price of $3.13 per Mcf. Estimated savings were only applied
for gathering and boosting stations and processing plants, as it is
assumed the owners of the compressor station do not own the natural gas
that is compressed at the station.
Using the single pollutant approach, where all the costs are
assigned to the reduction of one pollutant, the cost effectiveness of
replacement of the reciprocating rod packing within 26,000 hours or 36
months of operation, regardless of the condition of the rod packing, is
approximately $290 per ton of methane reduced for gathering and
boosting ($100 per ton if gas savings are considered), $90 per ton of
methane reduced for the processing segment (net savings if gas savings
are considered), $90 per ton of methane reduced for the transmission
segment, and $110 per ton of methane reduced for the storage segment.
Using the multipollutant approach, where half the cost of control is
assigned to the methane reduction and half to the VOC reduction, the
cost effectiveness of replacement of the reciprocating rod packing
within 26,000 hours or 36 months of operation, regardless of the
condition of the rod packing, is approximately $140 per ton of methane
reduced for gathering and boosting ($50 per ton if gas savings are
considered), $45 per ton of methane reduced for the processing segment
(net savings if gas savings are considered), $45 per ton of methane
reduced for the transmission segment, and $50 per ton of methane
reduced for the storage segment.
Using the single pollutant approach, where all the costs are
assigned to the reduction of one pollutant, the VOC cost effectiveness
of replacement of the reciprocating rod packing within 26,000 hours or
36 months of operation, regardless of the condition of the rod packing,
is approximately $1,030 per ton of VOC reduced for gathering and
boosting ($380 per ton if gas savings are considered), $330 per ton of
VOC reduced for the processing segment (net savings if gas savings are
considered), $3,260 per ton of VOC reduced for the transmission
segment, and $3,860 per ton of VOC reduced for the storage segment.
Using the multipollutant approach, where half the cost of control is
assigned to the methane reduction and half to the VOC reduction, the
cost effectiveness of replacement of the reciprocating rod packing
within 26,000 hours or 36 months of operation, regardless of the
condition of the rod packing, is approximately $520 per ton of VOC
reduced for gathering and boosting ($190 per ton if gas savings are
considered), $160 per ton of VOC reduced for the processing segment
(net savings if gas savings are considered), $1,630 per ton of VOC
reduced for the transmission segment, and $1,930 per ton of VOC reduced
for the storage segment.
As an alternative to replacing the rod packing on a fixed schedule,
another option is to replace the rod packing when, based on
measurements, there are indications that the rod packing is beginning
to wear to the point where there is an increased rate of natural gas
escaping around the packing to unacceptable levels. This is an approach
required by the California Greenhouse Gas Emission Regulation and in
Canada. The California Greenhous Gas Emission Regulation requires that
the rod packing/seal be tested during periodic inspections and, if the
rod packing/seal leak concentration exceeds the specified threshold of
2 scfm/cylinder, repairs must be made within 30 days.\280\ Similarly,
certain Canadian jurisdictions require periodic monitoring measurements
of rod packing vent
[[Page 63218]]
volumes (typically annually) for existing reciprocating compressors.
Where specified vent volumes are exceeded, the rules require corrective
action be taken to reduce the flow rate to below or equal to a
specified limit, as demonstrated by a remeasurement. Vent volume
thresholds specified that would result in the need for corrective
action vary from 0.49 to 0.81 scfm/cylinder.\281\
---------------------------------------------------------------------------
\280\ State of California Air Resources Board (CARB).
``Regulation for Greenhouse Gas Emission Standards for Crude Oil and
Natural Gas Facilities.'' Oil and Gas Final Regulation Order
(ca.gov).
\281\ Canadian Federal standards: http://gazette.gc.ca/rp-pr/p2/2018/2018-04-26-x1/pdf/g2-152x1.pdf; Discussion Draft Regulation
26.11.41 (maryland.gov); MAP-Technical-Report-December-19-2019-
FINAL.pdf (nm.gov).
---------------------------------------------------------------------------
This approach is similar to an approach identified in the Natural
Gas STAR Program referred to as ``Economic Packing and Piston Rod
Replacement.'' \282\ Under this approach, facilities use specific
financial objectives and monitoring data to determine emission levels
at which it is cost effective to replace rings and rods. Benefits of
calculating and utilizing this ``economic replacement threshold''
include methane and VOC emission reductions and natural gas cost
savings. Using this approach, one Natural Gas STAR partner reportedly
achieved savings of over $233,000 annually at 2006 gas prices. An
economic replacement threshold approach can also result in operational
benefits, including a longer life for existing equipment, improvements
in operating efficiencies, and long-term savings. The EPA is not
proposing to establish a financial objective or economic replacement
threshold in this proposal, but the costs and emission reductions of
replacing rod packing based on monitoring from this program were
considered in the analysis discussed below.
---------------------------------------------------------------------------
\282\ U.S. Environmental Protection Agency. Lessons Learned from
Natural Gas STAR Partners. Reducing Methane Emissions from
Compressor Rod Packing Systems. Natural Gas STAR Program. 2006.
---------------------------------------------------------------------------
The elements of such a program include establishing a frequency of
monitoring, identifying a threshold where action is required to reduce
emissions, and specifying the action for reducing emissions. The option
defined by the EPA and evaluated below is for annual monitoring and
requiring the replacement of the rod packing if the measured flow rate
for any individual cylinder exceeds 2 scfm. This threshold is
consistent with California's regulation. However, this option differs
from the California regulation in that it would require a complete
replacement of the rod packing if this threshold is exceeded, where
California allows repair sufficient to reduce the flow rate back below
2 scfm. The 2 scfm flow rate threshold was established based on
manufacturer guidelines indicating that a flow rate of 2 scfm or
greater was considered indicative of rod packing failure.\283\
---------------------------------------------------------------------------
\283\ State of California. Air Resources Board Public Hearing to
Consider the Proposed Regulation for Greenhouse Gas Emission
Standards for Crude Oil and Natural Gas Facilities. Staff Report:
Initial Statement of Reasons. pgs. 96-97.
---------------------------------------------------------------------------
We estimated the emission reductions from requiring annual flow
rate monitoring and repair/replacement of packing when the measured
flow rate exceeds 2 scfm total gas during pressurized operation. Based
on California's background regulatory documentation, information
provided to the State indicated that the average leak rate for those
compressors emitting more than 2 scfm was about 3 scfm during
pressurized operation, and less than 2 scfm during pressurized idle and
unpressurized states. Therefore, we assumed that the leak rate for
compressors emitting more than 2 scfm was about 3 scfm during
pressurized operation. As indicated above for the fixed schedule rod
packing replacement option, based on the 2011 NSPS OOOO TSD and 2016
NSPS OOOOa TSD, the average emissions from a newly installed rod
packing are assumed to be 11.5 scfh per cylinder.\284\ Using a ratio of
0.829 methane: Total natural gas ratio, 3 scfm total gas is
approximately 2.49 scfm (149.2 scfh) methane. This compressor emission
rate, which was used for all industry segments, was converted to an
annual mass emission rate by applying segment-specific pressurized
factors, then converted to a mass basis.
---------------------------------------------------------------------------
\284\ 2011 TSD, pg. 6-13.
---------------------------------------------------------------------------
The estimated percent reduction in methane emissions that would be
achievable from reducing 149.2 scfh methane/cylinder to 11.5 scfh
methane/cylinder (average emissions from a newly installed rod packing/
cylinder) is 92 percent. We applied this percent reduction in methane
emissions and estimated reciprocating compressor methane and VOC
emission reductions that would be achieved from repairing/replacing rod
packing based on the annual flow rate monitoring option. The
calculations assume that all cylinders are emitting at 3 scfm, and that
the rod packings for all compressor cylinders are replaced. This
represents the emission reductions expected for the year in which the
rod packings are replaced. Emissions would be expected to increase (and
emission reductions decrease) in subsequent years until the next time
the annual measurements require that the rod packing be replaced.
The capital and annual costs of replacing the rod packings are the
same as presented above for the fixed interval rod packing replacement
option. In addition, this option would include the costs associated
with the annual flow measurements. The estimated costs of this
monitoring are based on the costs for annual flow rate monitoring under
GHGRP subpart W for similar flow rate annual measurement requirements
($597). The capital costs associated with replacing compressor rod
packing would only occur in the year when packing is required to be
replaced. The monitoring costs would be incurred every year.
Additionally, the cost estimates assume that the packing of all
compressor cylinders would need to be replaced (which is unlikely to be
the case in many instances) and are therefore conservative estimates.
Support information for the California rule cites data indicating that
approximately 14 percent of compressors measurements indicated a leak
rate of over 2 scfm per cylinder. Based on an average of 3.45
cylinders/compressor, California assumed that the packing for 2
cylinders/compressor would need to be replaced to come into compliance
with the 2 scfm standard (57.9 percent).\285\
---------------------------------------------------------------------------
\285\ Based on Appendix B. Economic Analysis. State of
California. Air Resources Board. Proposed Regulation for Greenhouse
Gas Emission Standards for Crude Oil and Natural Gas Facilities. pg.
B-28. Notice Package for Oil and Gas Reg (ca.gov); State of
California. Air Resources Public Hearing to Consider the Proposed
Regulation for Greenhouse Gas Emission Standards for Crude Oil and
Natural Gas Facilities. Staff Report: Initial Statement of Reasons.
Date of Release: May 31, 2016. pg. 99.
---------------------------------------------------------------------------
Using the single pollutant approach, where all the costs are
assigned to the reduction of one pollutant, the cost effectiveness of
the annual monitoring option is approximately $230 per ton of methane
reduced for gathering and boosting ($40 per ton if gas savings are
considered), $110 per ton of methane reduced for the processing segment
(net savings if gas savings are considered), $100 per ton of methane
reduced for the transmission segment, and $110 per ton of methane
reduced for the storage segment. Using the multipollutant approach,
where half the cost of control is assigned to the methane reduction and
half to the VOC reduction, the cost effectiveness of replacement of the
reciprocating rod packing based on the annual monitoring approach is
approximately $110 per ton of methane reduced for gathering and
boosting ($20 per ton if gas savings are considered), $50 per ton of
methane reduced for the processing segment (net savings if gas savings
are considered), $50 per ton of methane reduced for the transmission
[[Page 63219]]
segment, and $60 per ton of methane reduced for the storage segment.
Using the single pollutant approach, where all the costs are
assigned to the reduction of one pollutant, the VOC cost effectiveness
of the annual monitoring option is approximately $810 per ton of VOC
reduced for gathering and boosting ($160 per ton if gas savings are
considered), $380 per ton of VOC reduced for the processing segment
(net savings if gas savings are considered), $3,700 per ton of VOC
reduced for the transmission segment, and $4,100 per ton of VOC reduced
for the storage segment. Using the multipollutant approach, where half
the cost of control is assigned to the methane reduction and half to
the VOC reduction, the cost effectiveness of replacement of the
reciprocating rod packing based on the annual monitoring approach is
approximately $410 per ton of VOC reduced for gathering and boosting
($80 per ton if gas savings are considered), $190 per ton of VOC
reduced for the processing segment (net savings if gas savings are
considered), $1,850 per ton of VOC reduced for the transmission
segment, and $2,040 per ton of VOC reduced for the storage segment.
We also assessed the incremental cost effectiveness of the annual
monitoring option compared to the fixed 3-year/26,000 replacement
schedule. Using the single pollutant approach, where all the costs are
assigned to the reduction of one pollutant, the incremental cost
effectiveness (without natural gas savings) from the fixed replacement
option to the annual monitoring option for methane is approximately
$130 per ton for gathering and boosting stations, $210 per ton for
processing plants, $180 per ton for transmission stations, and $140 per
ton for storage facilities. For VOC, the incremental cost effectiveness
is approximately $480 per ton for gathering and boosting stations, $750
per ton for processing plants, $6,600 per ton for transmission
stations, and $5,150 per ton for storage facilities.
The cost effectiveness of both options (fixed schedule and annual
monitoring) are reasonable for methane and VOC using either the single
pollutant or multipollutant approach. The incremental cost
effectiveness in going from the fixed schedule option to the annual
monitoring option is reasonable for all scenarios, with the exception
of VOC for transmission stations. Therefore, based on the consideration
of the costs in relation to the emission reductions, the EPA finds that
the annual monitoring option is the most reasonable option.
Further, as discussed above, California requires reciprocating
compressor annual rod packing flow rate monitoring and repair and or
replacement of the packing where flow rate monitoring indicates a
measurement that exceeds 2 scfm. This further supports the
reasonableness of a monitoring program.
Neither the fixed schedule rod packing replacement option nor the
rod packing replacement based on annual monitoring option would result
in secondary emissions impacts as both options would reduce the escape
of natural gas from the piston rod. No wastes would be created (other
than the worn packing that is being replaced) and no wastewater would
be generated. An advantage related to the replacement of rod packing
for reciprocating compressors based on annual rod packing monitoring is
that it would only require replacement of the rod packing where
monitoring of the rod packing indicates wear and increasing flow rate/
emissions to unacceptable levels. This optimizes the output of capital
expenditures to focus on emissions control where an increased emissions
potential is identified.
In light of the above we determined that annual rod pack flow rate
monitoring and replacement of the packing where flow rate monitoring
indicates a measurement that exceeds 2 scfm represents BSER for NSPS
OOOOb for this proposal for all segments including reciprocating
compressors located at centralized productions facilities (with the
exception of compressors at stand-alone well sites). As in the 2016
NSPS OOOOa, the EPA is proposing to allow the collection and routing of
emissions to a process as an alternative standard because that option
would achieve emission reductions equivalent to, or greater than, the
proposed standard for NSPS OOOOb.
The affected facility based on EPA's review would continue to be
each reciprocating compressor not located at a well site, or an
adjacent well site and servicing more than one well site. As discussed
above, the EPA is proposing a new definition for a ``centralized
production facility''. The EPA is proposing to define centralized
production facilities separately from well sites because the number and
size of equipment, particularly reciprocating and centrifugal
compressors, is larger than standalone well sites which would not be
included in the proposed definition of ``centralized production
facilities''. Thus, the EPA is proposing that reciprocating compressors
located at centralized production facilities would be subject to the
standards in NSPS in OOOOb, but reciprocating compressors at well sites
(standalone well sites) would not.
2. EG OOOOc
The EPA evaluated BSER for the control of methane from existing
reciprocating compressors (designated facilities) in all segments in
the Crude Oil and Natural Gas source category covered by the proposed
NSPS OOOOb and translated the degree of emission limitation achievable
through application of the BSER into a proposed presumptive standard
for these facilities that essentially mirrors the proposed NSPS OOOOb.
First, based on the same criteria and reasoning as explained above,
the EPA is proposing to define the designated facility in the context
of existing reciprocating compressors as those that commenced
construction on or before November 15, 2021. Based on information
available to the EPA, we did not identify any factors specific to
existing sources that would indicate that the EPA should alter this
definition as applied to existing sources. Next, the EPA finds that the
control measures evaluated for new sources for NSPS OOOOb are
appropriate for consideration for existing sources under the EG OOOOc.
The EPA finds no reason to evaluate different, or additional, control
measures in the context of existing sources because the EPA is unaware
of any control measures, or systems of emission reduction, for
reciprocating compressors that could be used for existing sources but
not for new sources. Next, the methane emission reductions expected to
be achieved via application of the control measures identified above to
new sources are also expected to be achieved by application of the same
control measures to existing sources. The EPA finds no reason to
believe that these calculations would differ for existing sources as
compared to new sources because the EPA believes that the baseline
emissions of an uncontrolled source are the same, or very similar, and
the efficiency of the control measures are the same, or very similar,
compared to the analysis above. This is also true with respect to the
costs, non-air environmental impacts, energy impacts, and technical
limitations discussed above for the control options identified.
The EPA has not identified any costs associated with applying these
controls at existing sources, such as retrofit costs, that would apply
any differently than, or in addition to, those costs assessed above
regarding application of the identified controls to new sources. The
cost effectiveness values for the
[[Page 63220]]
proposed presumptive standard of replacement of the rod packing based
on an annual monitoring threshold is approximately $230 per ton of
methane reduced ($40 per ton if gas savings are considered) for the
gathering and boosting segment (including reciprocating compressors
located at centralized tank facilities), $110 per ton of methane
reduced for the processing segment (net savings if gas savings are
considered), $100 per ton of methane reduced for the transmission
segment, and $110 per ton of methane reduced for the storage segment.
In summary, the EPA did not identify any factors specific to
existing sources, as opposed to new sources, that would alter the
analysis above for the proposed NSPS OOOOb as applied to the designated
pollutant (methane) and the designated facilities (reciprocating
compressors). As a result, the proposed presumptive standard for
existing reciprocating compressors is as follows.
For reciprocating compressors in the gathering and boosting segment
(including reciprocating compressors located at centralized tank
facilities), processing, and transmission and storage segments, the
presumptive standard is replacement of the rod packing based on an
annual monitoring threshold. Specifically, the presumptive standard
would require an owner or operator of a reciprocating compressor
designated facility to monitor the rod packing flow rate annually. When
the measured leak rate exceeds 2 scfm (in pressurized mode), the
standard would require replacement of the rod packing. As an
alternative, the presumptive standard would be routing rod packing
emissions to a process via a closed vent system under negative
pressure.
F. Proposed Standards for Centrifugal Compressors
1. NSPS OOOOb
a. Background
The 2012 NSPS OOOO and the 2016 NSPS OOOOa applied to each wet seal
compressor not located at a well site, or an adjacent well site and
servicing more than one well site. The 2016 NSPS OOOOa required methane
and VOC emissions be reduced from each centrifugal compressor wet seal
fluid degassing system by 95.0 percent. Compliance with this
requirement allowed routing of emission from the wet seal fluid
degassing system to a control device or to a process. Dry seal
compressors were not subject to requirements under the 2016 NSPS OOOOa.
In determining BSER for wet seal compressors in 2016, the EPA
determined that the previous determination for NSPS OOOO conducted in
2011/2012 still represented BSER for the control of VOC in 2016. In
addition, the EPA determined that analogous control of methane
represented BSER. In the 2012 determinations, the EPA conducted
analyses of the cost and emission reductions of (1) requiring the
conversion of a wet seal system to a dry seal system, and (2) routing
to a control device or process. The 2011 NSPS OOOO rule (76 FR 52738,
52755, August 23, 2011) proposed an equipment standard that would have
required the use of dry seals to limit the VOC emissions from new
centrifugal compressors. At that time, the EPA solicited comments on
the emission reduction potential, cost, and any technical limitations
for the option of routing the gas back to a low-pressure fuel stream to
be combusted as fuel gas. In addition, in 2011 (76 FR 52738), the EPA
solicited comments on whether there are situations or applications
where a wet seal is the only option, because a dry seal system is
infeasible or otherwise inappropriate. The EPA received information
indicating that the integration of a centrifugal compressor into an
operation may require a certain compressor size or design that is not
available in a dry seal model, and in the case of capture of emissions
with routing to a process, there may not be down-stream equipment
capable of handling a low-pressure fuel source. In the final 2012 NSPS
OOOO rule, the EPA made the determination that the replacement of wet
seals with dry seals and routing to a process was not technically
feasible or practical for some centrifugal compressors, and also that
the costs per ton of emissions reduced were reasonable for routing
emissions to a control device or process. No other more stringent
control options were evaluated at that time. During the development of
the 2016 NSPS OOOOa rule, the EPA reviewed available information on
control options for wet seal compressors and did not identify any new
information to indicate that this has changed.
For this review, the EPA also focused on these control options.
BSER was evaluated for wet-seal centrifugal compressors at gathering
and boosting stations (considered to be representative of emissions
from centrifugal compressors at centralized production facilities) in
the production segment, at natural gas processing plants, and at sites
in the transmission and storage segment. During the development of the
2012 NSPS OOOO and 2016 NSPS OOOOa rulemakings, our data indicated that
there were no centrifugal compressors located at well sites. Since the
2012 NSPS OOOO and 2016 NSPS OOOOa rulemakings, we have not received
information that would change our understanding that there are no
centrifugal compressors in use at well sites.
However, as discussed in section XI.L (Centralized Production
Facilities) of this preamble, the EPA believes the definition of ``well
site'' in NSPS OOOOa may cause confusion regarding whether centrifugal
compressors located at centralized production facilities are also
exempt from the standards. The EPA is proposing a new definition for a
``centralized production facility''. The EPA is proposing to define
centralized production facilities separately from well sites because
the number and size of equipment, particularly reciprocating and
centrifugal compressors, is larger than standalone well sites which
would not be included in the proposed definition of ``centralized
production facilities''. This proposal is necessary in the context of
centrifugal compressors to distinguish between these compressors at
centralized production facilities where the EPA has determined that the
standard should apply, and compressors at standalone well sites where
the EPA has determined that the standard should not apply. In our
current analysis, described below, we consider the centrifugal
compressor gathering and boosting segment emission factor as being
representative of centrifugal compressor emissions located at
centralized production facilities. As such, the EPA is proposing that
centrifugal compressors located at centralized production facilities
would be subject to the standards in NSPS OOOOb and the EG in subpart
OOOOc, but centrifugal compressors at well sites (standalone well
sites) would not.
In addition to the requirement to reduce methane and VOC emissions
from each centrifugal compressor wet seal fluid degassing system by
95.0 percent, the 2016 NSPS OOOOa requires compressor components to be
monitored as fugitive emissions components and leaks found are to be
repaired under the fugitive emissions monitoring requirements of 40 CFR
60.5397a. The monitoring frequency depends on source (i.e., well sites,
compressor stations) and sector segment. These fugitive emissions
components were not considered part of the centrifugal compressor
affected facility.
Based on the EPA's review of NSPS OOOOa, we are proposing that BSER
continues to be that methane and VOC
[[Page 63221]]
emissions be reduced from each centrifugal compressor wet seal fluid
degassing system by 95.0 percent.
b. Description
Centrifugal compressors use a rotating disk or impeller to increase
the velocity of the natural gas where it is directed to a divergent
duct section that converts the velocity energy to pressure energy.
These compressors are primarily used for continuous, stationary
transport of natural gas in the processing and transmission systems.
Some centrifugal compressors use wet (meaning oil) seals around the
rotating shaft to prevent natural gas from escaping where the
compressor shaft exits the compressor casing. The wet seals use oil
which is circulated at high pressure to form a barrier against
compressed natural gas leakage. The circulated oil entrains and adsorbs
some compressed natural gas that may be released to the atmosphere
during the seal oil recirculation process. Off gassing of entrained
natural gas from wet seal centrifugal compressors is not suitable for
sale and is either released to the atmosphere, flared, or routed back
to a process.
Some centrifugal compressors utilize dry seal systems. Dry seal
systems minimize leakage by using the opposing force created by
hydrodynamic grooves and springs. The hydrodynamic grooves are etched
into the surface of the rotating ring affixed to the compressor shaft.
When the compressor is not rotating, the stationary ring in the seal
housing is pressed against the rotating ring by springs. When the
compressor shaft rotates at high speed, compressed natural gas has only
one pathway to leak down the shaft, and that is between the rotating
and stationary rings. This natural gas is pumped between the grooves in
the rotating and stationary rings. The opposing force of high-pressure
natural gas pumped between the rings and springs trying to push the
rings together creates a very thin gap between the rings through which
little natural gas can leak. While the compressor is operating, the
rings are not in contact with each other and, therefore, do not wear or
need lubrication. O-rings seal the stationary rings in the seal case.
Historically, the EPA has considered dry seal centrifugal compressors
to be inherently low-emitting and has never required control of
emissions from dry seal compressors. The EPA has received
feedback,\286\ however, that there are some wet seal compressor system
designs that are also low emitting when compared to dry seal
compressors and is soliciting comment on lower emitting wet seal
compressor system designs and dry seal compressor emissions in this
proposed action.
---------------------------------------------------------------------------
\286\ Conference Call. Prepared by Tora Consulting. December 19,
2018.
---------------------------------------------------------------------------
The 2021 U.S. GHGI estimates over 166,700 metric tpy of methane
emissions in 2019 from compressors from natural gas systems. For the
natural gas processing and transmission segments, wet seal compressor
methane emissions are estimated to be about 78,700 metric tons and dry
seal compressor methane estimated emissions are estimated to be about
88,000 metric tons.\287\ The wet seal and dry seal compressor methane
emission estimates reflect the increasing prevalence of the use of dry
seals over wet seals and emissions control requirements that require
the control of emissions from wet seal compressors. The methane
emissions from centrifugal compressors represent 3 percent of the total
methane emissions from natural gas systems in the Oil and Natural Gas
Industry sector.
---------------------------------------------------------------------------
\287\ U.S. Environmental Protection Agency. Inventory of U.S.
Greenhouse Gas Emissions and Sinks (1990-2019). Published in 2021.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2019.
---------------------------------------------------------------------------
c. Affected Facility
For purposes of the NSPS, the centrifugal compressor affected
facility is a single centrifugal compressor using wet seals. A
centrifugal compressor located at a well site, or an adjacent well site
and servicing more than one well site, is not an affected facility
under the proposed rule for NSPS OOOOb. As discussed above, the EPA is
proposing that the affected facility includes centrifugal compressors
located at centralized production facilities and the affected facility
exception for ``a well site, or an adjacent well site servicing more
than one well site'' applies to standalone well sites and not
centralized production facilities.
d. 2021 BSER Analysis
The methodology we used for estimating emissions from compressors
is consistent with the methodology developed for the 2012 NSPS OOOO
BSER analysis, which was also used to support the 2016 NSPS OOOOa
BSER.\288\ The wet-seal centrifugal compressor methane uncontrolled
emission factors are based on the volumetric emission factors used for
the GHGI, which were converted to a mass emission rate using a density
of 41.63 pounds of methane per thousand cubic feet. The VOC emissions
were calculated using the ratio of 0.278 pounds VOC per pound of
methane for the production and processing segments, and 0.0277 pounds
VOC per pound of methane for the transmission and storage segment. The
resulting baseline uncontrolled emissions per centrifugal compressor
are 157 tpy methane (43.5 tpy VOC) from wet-seal compressors at
gathering and boosting sites, 211 tpy methane (58.7 tpy VOC) from wet-
seal compressors at natural gas processing plants, 157 tpy methane (4.3
tpy VOC) from wet-seal compressors at transmission compressor stations,
and 117 (3.24 tpy VOC) from wet-seal compressors at storage facilities.
Since the emission factors for dry seal compressors are approximately
lower than wet seal compressors,\289\ the EPA considered requiring dry
seals as a replacement to wet seals as a control option in 2011. The
EPA proposed dry seals as a replacement to wet seals to control VOC
emissions at that time. Based on comments received on the proposal that
dry seal compressors were not feasible in all instances based on costs
and technical reasons, the EPA did not finalize the proposal that dry
seal compressors represented BSER. Instead, the EPA separately
evaluated the control options for wet seal compressors (77 FR 49499-
49500, 49523, August 16, 2012). In the 2015 NSPS OOOOa proposed rule,
the EPA maintained that available information since the 2012 NSPS OOOO
rule continued to show that dry seal compressors cannot be use in all
circumstances. The EPA has not identified any new information since
that time that indicates that dry seal compressors as a replacement for
wet seal compressors is technically feasible in all circumstances.
Thus, we did not evaluate the replacement of a wet seal system with a
dry seal system as BSER for controlling emissions from wet seal systems
for the NSPS OOOOb proposal.
---------------------------------------------------------------------------
\288\ 2011 NSPS OOOO TSD, section 6.2.2; 2016 NSPS OOOOa TSD,
section 7.2.2.
\289\ 2011 NSPS OOOO TSD, Table 6-2, pg. 6-4; 2016 NSPS OOOOa
TSD, Table 7-2, pg. 104.
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In addition to soliciting comment and information on lower-emitting
wet seal compressor designs (that emit less than dry seal compressors),
the EPA is soliciting information on dry seal compressor emissions.
Feedback received (noted above) on lower emitting wet seal compressor
designs included concern that lower emitting wet seal systems were
being replaced by higher emitting (but still low emitting) dry seal
systems because they were not subject to the NSPS. Given that the trend
has been that wet seal compressor systems are increasingly being
replaced by dry seal compressor systems, the EPA solicits comments on
dry seal compressor emissions and whether/and
[[Page 63222]]
to what degree operational or malfunctioning conditions (e.g., low seal
gas pressure, contamination of the seal gas, lack of supply of
separation gas, mechanical failure) have the potential to impact
methane and VOC emissions. The EPA also solicits comment on whether
owners and operators implement standard operating procedures to
identify and correct operational or malfunction conditions that have
the potential to increase emissions from dry seal systems. Finally, the
EPA solicits comments on whether we should consider evaluating BSER and
developing NSPS standards for dry seal compressors.
The control options to reduce emissions from centrifugal
compressors evaluated include control techniques that reduce emissions
from leaking of natural gas from wet seal compressors by capturing
leaking gas and route it either to (1) a control device (combustion
device), or (2) to the process. We evaluated the costs and impacts of
both of these options.
Combustion devices are commonly used in the Crude Oil and Natural
Gas Industry to combust methane and VOC emission streams. Combustors
are used to control VOC and methane emissions in many industrial
settings, since the combustor can normally handle fluctuations in
concentration, flow rate, heating value and inert species content.\290\
A combustion device generally achieves 95 percent reduction of methane
and VOC when operated according to the manufacturer instructions. For
this analysis, we assumed that the entrained natural gas from the seal
oil that is removed in the degassing process would be directed to a
combustion device that achieves a 95 percent reduction of methane and
VOC emissions. This option was determined to be BSER under the 2011
NSPS OOOO (77 FR 49490, August 16, 2012) and 2016 NSPS OOOOa rules. The
combustion of the recovered gas creates secondary emissions of
hydrocarbons (NOX, CO2, and CO emissions).
Routing the captured gas from the centrifugal compressor wet seal
degassing system to a combustion device has associated capital and
operating costs.
---------------------------------------------------------------------------
\290\ U.S. Environmental Protection Agency. AP 42, Fifth
Edition, Volume I, Chapter 13.5 Industrial Flares. Office of Air
Quality Planning & Standards. 1991.
---------------------------------------------------------------------------
The capital and annual costs for the installation of a combustion
device (an enclosed flare for the analysis) were calculated using the
methodology in the EPA Control Cost Manual.\291\ The capital costs of a
flare and the equipment (closed vent system) necessary to route
emissions to the flare are based on costs from the 2011 NSPS OOOO TSD
and 2016 NSPS OOOOa TSD. These costs were updated to 2019 dollars. The
updated capital costs of $80,930 were annualized at 7 percent based on
an equipment life of 10 years. The total annualized capital costs were
estimated to be $11,520. The annual operating costs are also based on
the 2011 NSPS OOOO TSD and 2016 NSPS OOOOa TSD. These costs were
updated to 2019 dollars. The 2019 annual operating costs were estimated
to be $117,160. The combined annualized capital and operating costs per
compressor per year is an estimated $128,680. There is no cost savings
estimated for this option because the recovered natural gas is
combusted. The costs presented for gathering and boosting segment
centrifugal compressors represent the estimated costs assumed for
centrifugal compressors located at centralized production facilities.
---------------------------------------------------------------------------
\291\ U.S. Environmental Protection Agency. OAQPS Control Cost
Manual: Sixth Edition (EPA 452/B-02-001). Research Triangle Park,
NC.
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Using the single pollutant approach, where all the costs are
assigned to the reduction of one pollutant, the cost effectiveness of
routing emissions from a wet seal system to a new flare for methane
emissions is $870 per ton of methane reduced for the transmission
segment and gathering and boosting, $640 per ton of methane reduced for
the processing segment, and $1,160 per ton of methane reduced for the
storage segment. Using the multipollutant approach, where half the cost
of control is assigned to the methane reduction and half to the VOC
reduction, the cost effectiveness of routing emissions from a wet seal
system to a new flare for methane emissions is $430 per ton of methane
reduced for the transmission segment and gathering and boosting, $320
per ton of methane reduced for the processing segment, and $580 per ton
of methane reduced for the storage segment.
Using the single-pollutant approach, where all the costs are
assigned to the reduction of one pollutant, the cost effectiveness of
routing emissions from a wet seal system to a new flare for VOC
emissions is $3,100 per ton of VOC reduced for gathering and boosting,
$2,300 per ton of VOC reduced for the processing segment, $31,200 per
ton of VOC reduced for the transmission segment, and $41,800 per ton of
VOC reduced for the storage segment. Using the multipollutant approach,
where half the cost of control is assigned to the methane reduction and
half to the VOC reduction, the cost effectiveness of routing emissions
from a wet seal system to a new flare for VOC emissions is $1,600 per
ton of VOC reduced for gathering and boosting, $1,200 per ton of VOC
reduced for the processing segment, $15,600 per ton of VOC reduced for
the transmission segment, and $20,900 per ton of VOC reduced for the
storage segment.
In addition to an owner or operator having the option to capture
emissions and routing to a new combustion control device, a less costly
option that may be available could be for owners and operators to
capture and route emissions to a combustion control device installed
for another source (e.g., a control device that is already on site to
control emissions from another emissions source). The costs, which are
provided in the NSPS OOOOb and EG TSD for this rulemaking, would be for
the ductwork to capture the emissions and route them to the control
device. The analysis assumes that the combustion control device on site
achieves a 95 percent reduction in emissions of methane and VOC.
Another option for reducing methane and VOC emissions from the
compressor wet seal fluid degassing system is to route the captured
emissions back to the compressor suction or fuel system, or other
beneficial use (referred to collectively as routing to a process).
Routing to a process would entail routing emissions via a closed vent
system to any enclosed portion of a process unit (e.g., compressor or
fuel gas system) where the emissions are predominantly recycled,
consumed in the same manner as a material that fulfills the same
function in the process, transformed by chemical reaction into
materials that are not regulated materials, incorporated into a
product, or recovered. Emissions that are routed to a process are
assumed to result in the same or greater emission reductions as would
have been achieved had the emissions been routed through a closed vent
system to a combustion device.\292\ For purposes of this analysis, we
assumed that routing methane and VOC emissions from a wet seal fluid
degassing system to a process reduces VOC emissions greater than or
equal to a combustion device (i.e., greater than or equal to 95
percent). There are no secondary impacts with the option to control
emissions from centrifugal wet seals by capturing gas and routing to
the process.
---------------------------------------------------------------------------
\292\ U.S. Environmental Protection Agency. Control Techniques
Guidelines for the Oil and Natural Gas Industry. Office of Air
Quality Planning and Standards, Sector Policies and Programs
Division. October 2016. EPA-453/B-16-001. (2016 CTG). pgs. 5-19 to
5-20.
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[[Page 63223]]
The capital cost of a system to route the seal oil degassing system
to a process is estimated to be $26,210 ($2,019),\293\ The estimated
costs include an intermediate pressure degassing drum, new piping, gas
demister/filter, and a pressure regulator for the fuel line. The annual
costs were estimated to be $2,880 (without savings) assuming a 15-year
equipment life at 7 percent interest. Because the natural gas is not
lost or combusted, the value of the natural gas represents a savings to
owners and operators in the production (gathering and boosting) and
processing segments. Savings were estimated using a natural gas price
of $3.13 per Mcf, which resulted in annual savings of $27,000 per year
at gathering and boosting stations and $36,400 per year at processing
plants. The annual cost savings are much greater than the annual costs,
which results in an overall savings when they are considered.
---------------------------------------------------------------------------
\293\ 2011 NSPS OOOO TSD, pg. 114; 2016 CTG, pg. 5-20.
---------------------------------------------------------------------------
Using the single pollutant approach, where all the costs are
assigned to the reduction of one pollutant, the cost effectiveness
(without natural gas savings) of routing emissions from a wet seal
system to a process for methane emissions is approximately $19 per ton
of methane reduced for the transmission segment and gathering and
boosting, $14 per ton of methane reduced for the processing segment,
and $26 per ton of methane reduced for the storage segment. Using the
multipollutant approach, where half the cost of control is assigned to
the methane reduction and half to the VOC reduction, the cost
effectiveness (without natural gas savings) of routing emissions from a
wet seal system to a process for methane emissions is approximately $10
per ton of methane reduced for the transmission segment and gathering
and boosting, $7 per ton of methane reduced for the processing segment,
and $13 per ton of methane reduced for the storage segment. As noted
above, there is an overall net savings if the value of the natural gas
recovered is considered.
Using the single pollutant approach, where all the costs are
assigned to the reduction of one pollutant, the cost effectiveness
(without natural gas savings) of routing emissions from a wet seal
system to a process for VOC emissions is approximately $70 per ton of
VOC reduced for gathering and boosting, $50 per ton of VOC reduced for
the processing segment, $700 per ton of VOC reduced for the
transmission segment, and $940 per ton of VOC reduced for the storage
segment. Using the multipollutant approach, where half the cost of
control is assigned to the methane reduction and half to the VOC
reduction, the cost effectiveness (without natural gas savings) of
routing emissions from a wet seal system to a process for VOC emissions
is approximately $35 per ton of VOC reduced for gathering and boosting,
$26 per ton of VOC reduced for the processing segment, $350 per ton of
VOC reduced for the transmission segment, and $470 per ton of VOC
reduced for the storage segment. As noted above, there is an overall
net savings if the value of the natural gas recovered is considered.
The cost effectiveness of both options (routing emissions to a
combustion device or to a process) are reasonable for methane for all
of the evaluated segments, using both the single pollutant and
multipollutant approaches. The cost effectiveness of routing emissions
to a process are also reasonable for VOC for all of the evaluated
segments, using both the single pollutant and multipollutant
approaches. For routing emissions to a combustion device, the cost
effectiveness is reasonable for the gathering and boosting and
processing segments using the single pollutant and multipollutant
approaches. Based on the consideration of the costs in relation to the
emission reductions of both methane and VOC, the EPA finds that
requiring emissions to be reduced from each centrifugal compressor
using a wet seal by at least 95 percent (which can be achieved by
either option) continues to be reasonable in the gathering and boosting
(considered to be representative of emissions/costs from centrifugal
compressors at centralized production facilities). processing,
transmission and storage segments.
The 2012 NSPS OOOO and the 2016 NSPS OOOOa require emissions be
reduced from each centrifugal compressor wet seal fluid degassing
system by at least 95.0 percent by routing emissions to a control
device or to a process. States have generally adopted/incorporated this
NSPS level of control (or a level of control that is substantially
similar) in their State regulations for the control of emissions from
centrifugal compressor sources using wet seals. Owners and operators
have successfully met this standard for almost a decade. These facts
further demonstrate the reasonableness of this level of control. In the
discussion above, we reviewed two options to reduce emissions from wet
seal compressors that are both current regulatory options under the
2016 NSPS OOOOa: (1) Capturing leaking gas and route to a combustion
device (flare), or (2) capturing leaking gas and route to the process.
Under the 2016 NSPS OOOOa, the level of control determined based on
BSER was that methane and VOC emissions be reduced from each
centrifugal compressor wet seal fluid degassing system by 95 percent or
greater. The EPA has not identified any other control options or any
other Federal, State, or local requirements that would achieve a
greater reduction in methane and VOC emissions from centrifugal
compressor wet seal systems. Although capturing leaking gas and routing
to the process has the advantage of both reducing emissions by at least
95 percent or greater and capturing the natural gas (resulting in a
natural gas savings), the EPA has received feedback in the development
of the 2012 NSPS OOOO rule that this option may not be a viable option
in situations where there may not be down-stream equipment capable of
handling a low-pressure fuel source. During the development of the 2016
NSPS OOOOa rule, the EPA reaffirmed that information since the
development of the 2012 NSPS OOOO rule continues to show that capturing
leaking gas and routing to the process cannot be used in all
circumstances. No new information has been identified since the
development of the 2016 NSPS OOOOa rule to indicate that capturing
leaking gas and routing to the process can be achieved in all
circumstances (80 FR 56619, September 18, 2015). Thus, by establishing
a 95 percent methane and VOC emissions control level as BSER, an owner
or operator has the option of routing emissions to a process where it
is a viable option, or to a combustion device where routing to a
process is not a viable option. If an owner or operator chooses to
route to a process to meet the 95 percent level of control, there are
no secondary impacts. If an owner or operator chooses to route to a
combustion device to meet the 95 percent level of control, the
combustion of the recovered gas creates secondary emissions of
hydrocarbons (NOX, CO2, and CO emissions).
The costs, emission reductions, and cost effectiveness values were
presented above for collecting the wet seal compressor emissions and
routing them to both a combustion device and to a process to achieve at
least a 95 percent control. The EPA considers the cost effectiveness of
both of these control options reasonable across all segments evaluated
(i.e., the gathering and boosting portion of production, processing,
transmission, storage) for the reduction of methane emissions under the
single pollutant approach and multipollutant approach. As discussed
[[Page 63224]]
above, in our current analysis, we consider the centrifugal compressor
gathering and boosting segment emission factor as being representative
of centrifugal compressor emissions located at centralized production
facilities. Thus, the cost analysis performed for the gathering and
boosting segment represents the estimated costs of evaluated options
for centrifugal compressors with wet seals located at centralized
storage facilities.
In light of the above, we determined that reducing methane and VOC
emissions from each centrifugal compressor wet seal fluid degassing
system by 95 percent or greater continues to represent BSER for NSPS
OOOOb for this proposal. The affected facility based on EPA's review
would continue be each wet seal compressor not located at a well site,
or an adjacent well site and servicing more than one well site. As
discussed above, the EPA is proposing a new definition for a
``centralized production facility''. The EPA is proposing to define
centralized production facilities separately from well sites because
the number and size of equipment, particularly reciprocating and
centrifugal compressors, is larger than standalone well sites which
would not be included in the proposed definition of ``centralized
production facilities''. Thus, the EPA is proposing that centrifugal
compressors located at centralized production facilities would be
subject to the standards in the NSPS in OOOOb, but centrifugal
compressors at well sites (standalone well sites) would not.
2. EG OOOOc
The EPA evaluated BSER for the control of methane from existing
centrifugal compressors using wet seals (not located at a well site, or
an adjacent well site and servicing more than one well site)
(designated facilities) in all segments in the Crude Oil and Natural
Gas source category covered by the proposed NSPS OOOOb and translated
the degree of emission limitation achievable through application of the
BSER into a proposed presumptive standard for these facilities that
essentially mirrors the proposed NSPS OOOOb.
First, based on the same criteria and reasoning as explained above,
the EPA is proposing to define the designated facility in the context
of existing centrifugal compressors using wet seals (not located at a
well site, or an adjacent well site and servicing more than one well
site) as those that commenced construction on or before November 15,
2021. Based on information available to the EPA, we did not identify
any factors specific to existing sources that would indicate that the
EPA should alter this definition as applied to existing sources. Next,
the EPA finds that the control measures evaluated for new sources for
NSPS OOOOb are appropriate for consideration for existing sources under
the EG OOOOc. The EPA finds no reason to evaluate different, or
additional, control measures in the context of existing sources because
the EPA is unaware of any control measures, or systems of emission
reduction, for centrifugal compressors that could be used for existing
sources but not for new sources. Next, the methane emission reductions
expected to be achieved via application of the control measures
identified above to new sources are also expected to be achieved by
application of the same control measures to existing sources. The EPA
finds no reason to believe that these calculations would differ for
existing sources as compared to new sources because the EPA believes
that the baseline emissions of an uncontrolled source are the same, or
very similar, and the efficiency of the control measures are the same,
or very similar, compared to the analysis above. This is also true with
respect to the costs, non-air environmental impacts, energy impacts,
and technical limitations discussed above for the control options
identified.
The EPA has not identified any costs associated with applying these
controls at existing sources, such as retrofit costs, that would apply
any differently than, or in addition to, those costs assessed above
regarding application of the identified controls to new sources. The
cost effectiveness values for the proposed presumptive standard of
reducing methane emissions from each centrifugal compressor wet seal
fluid degassing system by 95 percent or greater are based on the cost
effectiveness of routing emissions from a wet seal system to a flare or
to a process. The cost effectiveness of routing emissions from a wet
seal system to a new flare for methane emissions is $870 per ton of
methane reduced for the transmission segment and gathering and
boosting, $640 per ton of methane reduced for the processing segment,
and $1,160 per ton of methane reduced for the storage segment. The cost
effectiveness (without natural gas savings) of routing emissions from a
wet seal system to a process for methane emissions is approximately $19
per ton of methane reduced for the transmission segment and gathering
and boosting, $14 per ton of methane reduced for the processing
segment, and $26 per ton of methane reduced for the storage segment.
In summary, the EPA did not identify any factors specific to
existing sources, as opposed to new sources, that would alter the
analysis above for the proposed NSPS OOOOb as applied to the designated
pollutant (methane) and the designated facilities (centrifugal
compressors using wet seals). As a result, the proposed presumptive
standard for existing centrifugal compressors using wet seals is as
follows.
For centrifugal compressors using wet seals in the gathering and
boosting segment (including centrifugal compressors using wet seals
located at centralized tank facilities), processing, and transmission
and storage segments, the presumptive standard is to reduce methane
emissions by at least 95 percent. An owner or operator can meet this
presumptive standard by routing methane emissions to a control device
or process that reduces emissions by at least 95 percent. As discussed
previously, the EPA is proposing a new definition for a ``centralized
production facility''. The EPA is proposing to define centralized
production facilities separately from well sites because the number and
size of equipment, particularly reciprocating and centrifugal
compressors, is larger than standalone well sites which would not be
included in the proposed definition of ``centralized production
facilities''. Thus, the EPA is proposing that centrifugal compressors
located at centralized production facilities would be subject to the
standards in the EG in OOOOc, but centrifugal compressors at well sites
(standalone well sites) would not.
G. Proposed Standards for Pneumatic Pumps
1. NSPS OOOOb
a. Background
In the 2016 NSPS OOOOa, the EPA established GHG (in the form of
limitations on methane emissions) and VOC standards for natural gas-
driven diaphragm pneumatic pumps located at well sites. This standard
required that natural gas emissions be reduced by 95.0 percent by
routing to an existing control device if: (1) A control device was
onsite, (2) the control device could achieve a 95.0 percent reduction,
and (3) it was technically feasible to route the emissions to the
control device. The standard did not require the installation of a
control device solely for the purpose of complying with the 95.0
percent reduction for the emissions from pneumatic pumps. It also
allowed
[[Page 63225]]
the option of routing emissions to a process. At natural gas processing
plants, the EPA established a standard that required a natural gas
emission rate of zero (i.e., that prohibited methane and VOC emissions
from pneumatic pumps).
As a result of the review of these requirements and the previous
BSER determination, the EPA is proposing methane and VOC standards in
NSPS OOOOb for natural gas-driven pneumatic pumps located in all
segments of the source category. Specifically, the EPA is proposing
that each natural gas driven pneumatic pump is an affected facility.
The EPA is proposing that methane and VOC emissions from natural gas-
driven diaphragm and piston pumps at well sites and all other sites in
the production segment be reduced by 95.0 percent or routed to a
process, provided that there is an existing control device onsite or it
is technically feasible to route the emissions to a process. For
natural gas driven pneumatic pumps at natural gas transmission stations
and natural gas storage facilities, the same requirement applies, but
only to diaphragm pumps. The EPA is proposing to retain the technical
infeasibility provisions of NSPS OOOOa for purposes of NSPS OOOOb. If
there is a control device onsite,\294\ the owner or operator is not
required to route emissions to that control device if it is not
technically feasible to do so, even for new construction sites which
the EPA had previously referred to as ``greenfield'' sites. The EPA is
also proposing to retain in NSPS OOOOb the exception to the 95.0
percent reduction requirement if there is a control device onsite that
it is technically feasible to route to that cannot achieve that level
of reduction but can achieve a lower level of reductions. In those
situations, the emissions from the pump are still to be routed to the
control device and controlled at the level that the device can achieve.
The EPA is also proposing a prohibition on methane and VOC emissions
from pneumatic pumps (diaphragm and piston pumps) at natural gas
processing plants. While zero emissions pneumatic pumps would not
technically be affected facilities because they are not driven by
natural gas, owners and operators should maintain documentation if they
would like to be able to demonstrate to permit writers or enforcement
officials that there are no methane or VOC emissions from the pumps and
that these pumps are not affected facilities subject to the rule.
---------------------------------------------------------------------------
\294\ For the same reasons discussed in section X.B.2, the EPA
is proposing that boilers and process heaters are not control
devises for purposes of controlling emissions from pneumatic pumps.
---------------------------------------------------------------------------
This BSER for reducing methane and VOC from pneumatic pumps are the
same as those for the 2016 NSPS OOOOa, except that (1) the EPA
determined that the NSPS OOOOa levels of control also represent BSER
for diaphragm pumps at all sites in the production segment (including
gathering and boosting stations), and for all transmission and storage
sites, and (2) the EPA determined that the NSPS OOOOa levels of control
also represent BSER for piston pumps (in addition to diaphragm pumps)
in the production segment and at natural gas processing plants.
As discussed below, a primary reason that the EPA is unable to
conclude that requiring a natural gas emission rate of zero for
production and transmission and storage facilities is BSER at this time
is because proven technologies that eliminate natural gas emissions
rely on electricity to function. In contrast to pneumatic controllers,
our review of information that has become available since the
promulgation of the 2016 NSPS OOOOa standards, including State-level
regulations for pneumatic pumps, does not demonstrate that zero
emission technology for pneumatic pumps would be feasible at sites that
lack access to onsite power. The EPA is specifically soliciting
comments on the possibility of subcategorizing production and natural
gas transmission and storage sites into those sites that have access to
onsite power and those that do not, and then determining BSER
separately for each subcategory. Further, the EPA is soliciting comment
on how, if at all, the proposed NSPS OOOOb standards for pneumatic
controllers might factor into how the EPA ought to evaluate the
possibility of requiring a natural gas emission rate of zero for
pneumatic pumps in the production and transmission and storage
segments. For example, if a site installs a solar-powered system to
operate their controllers, then could that same system provide power to
the pumps such that all pumps at the site could have zero emissions of
natural gas?
b. Description
A pneumatic pump is a positive displacement reciprocating unit
generally used by the Oil and Natural Gas Industry for one of four
purposes: (1) Hot oil circulation for heat tracing/freeze protection,
(2) chemical injection, (3) moving bulk liquids, and (4) glycol
circulation in dehydrators. There are two basic types of pneumatic
pumps used in the Oil and Natural Gas Industry, diaphragm pumps and
piston pumps. Pumps used for heat tracing/freeze protection circulate
hot glycol or other heat-transfer fluids in tubing covered with
insulation to prevent freezing in pipelines, vessels and tanks. These
heat tracing/freeze protection pumps are usually diaphragm pumps.
Chemical injection pumps are designed to inject precise amounts of
chemical into a process stream to regulate operations of a plant and
protect the equipment. Typical chemicals injected in an oil or gas
field are biocides, demulsifiers, clarifiers, corrosion inhibitors,
scale inhibitors, hydrate inhibitors, paraffin dewaxers, surfactants,
oxygen scavengers, and H2S scavengers. These chemicals are
normally injected at the wellhead and into gathering lines or at
production separation facilities. Since the injection rates are
typically small, the pumps are also small. They are often attached to
barrels containing the chemical being injected. These chemical
injection pumps are primarily piston pumps, although they can be small
diaphragm pumps. Examples of the use of pneumatic pumps to transfer
bulk liquids at oil and natural gas production sites include pumping
motor oil or pumping out sumps. Pumps used for these purposes ae
typically diaphragm pumps.
Glycol dehydrator pumps recover energy from the high-pressure rich
glycol/gas mixture leaving the absorber and use that energy to pump the
low-pressure lean glycol back into the absorber. Glycol dehydrator
pumps are controlled under the oil and gas NESHAPs (40 CFR part 63,
subparts HH and HHH), are not included as affected facilities for the
2016 NSPS OOOOa and were not included in the review for proposed NSPS
OOOOb.
Both diaphragm and piston pumps are positive displacement
reciprocating pumps, meaning they use contracting and expanding
cavities to move fluids. These pumps work by allowing a fluid (e.g.,
the heat transfer fluid, demulsifier, corrosion inhibitor, etc) to flow
into an enclosed cavity from a low-pressure source, trapping the fluid,
and then forcing it out into a high-pressure receiver by decreasing the
volume of the cavity. The piston and diaphragm pumps have two major
components, a driver side and a motive side, which operate in the same
manner but with different reciprocating mechanisms. Pressurized gas
provides energy to the driver side of the pump, which operates a piston
or flexible diaphragm to draw fluid into the pump. The motive side of
the pump delivers the energy to the fluid being moved in order to
discharge
[[Page 63226]]
the fluid from the pump. The natural gas leaving the exhaust port of
the pump is either directly discharged into the atmosphere or is
recovered and used as a fuel gas or stripping gas.
Diaphragm pumps work by flexing the diaphragm out of the
displacement chamber, and piston pumps typically include plunger pumps
with a large piston on the gas end and a smaller piston on the liquid
end to enable a high discharge pressure with a varied but much lower
pneumatic supply gas pressure.
As noted above, energy is supplied to the driver side of the pump
to operate the piston or diaphragm. Commonly, this energy is provided
by pressurized gas. This gas can be compressed air, or ``instrument
air,'' provided by an electrically powered air compressor. In many
situations across all segments of this industry, electricity is not
available, and this energy is provided by pressurized natural gas
(i.e., ``natural gas-driven pneumatic pumps''). This energy can also be
directly provided by electricity.
Natural gas-driven pneumatic pumps emit methane and VOC as part of
their normal operation. These emissions occur when the gas used in the
pump stroke is exhausted to enable liquid filling of the liquid cavity
of the pump. Emissions are a function of the amount of fluid pumped,
the pressure of the pneumatic supply gas, the number of pressure ratios
between the pneumatic supply gas pressure and the fluid discharge
pressure, and the mechanical inefficiency of the pump.
The 2021 U.S. GHGI estimates almost 215,000 metric tpy of methane
emissions from pneumatic pumps in the oil and natural gas production
segment in 2019. Specifically, this includes almost 113,000 metric tpy
from natural gas production, 75,000 from petroleum production, and
26,000 from gathering and boosting compressor stations. These emissions
make up 5 percent of all methane emissions in the GHGI for the combined
gas and oil production segment, and 2 percent of all methane emissions
for gathering and boosting. The overall total, which represents 3
percent of the total methane emissions from this industry, does not
include emissions from the processing, transmission, and storage
segments which the EPA is now proposing to regulate under NSPS OOOOb.
c. 2021 BSER Analysis
BSER was evaluated for all segments of the industry. The 2015 NSPS
OOOOa proposal included methane and VOC standards for pneumatic pumps
in the production and transmission and storage segments. However, the
EPA did not finalize regulations for pneumatic pumps at gathering and
boosting stations in the final 2016 NSPS OOOOa due to lack of data on
the prevalence of the use of pneumatic pumps at gathering and boosting
stations. Since that time, GHGRP subpart W has required that emissions
from natural gas-driven pneumatic pumps be reported from gathering and
boosting stations. As reported above, the 2021 GHGI estimates over
26,000 metric tpy of methane emissions from these pumps in the
gathering and boosting segment in 2019. Similarly, the EPA did not
include pneumatic pumps in the transmission and storage segment in the
final 2016 NSPS OOOOa because we did not have a reliable source of
information indicating the prevalence of pneumatic pumps or their
emission rates in the transmission and storage segment. While the GHGI
does not include emissions from pneumatic pumps in the transmission and
storage segment, and the GHGRP does not require the reporting of
emissions from these pumps in this segment, State rules (notably the
California rule and the proposed New Mexico rule) do include
requirements for natural gas driven pneumatic pumps at transmission and
storage facilities. The EPA is soliciting comment on whether natural
gas driven pneumatic pumps are used in the natural gas transmission and
storage segment and to what extent.
In 2015, the EPA identified several options for reducing methane
and VOC emissions from natural gas-driven pumps in the production and
natural gas transmission and storage segments: Replace natural gas-
driven pumps with instrument air pumps, replace natural gas-driven
pumps with solar-powered direct current pumps (solar pumps), replace
natural gas-driven pumps with electric pumps, route natural gas-driven
pump emissions to a control device, and route natural gas-driven pump
emissions to a process. The only option identified in 2015 and analyzed
at natural gas processing plants was the use of instrument air. The EPA
re-evaluated that information as well as new information including
updated GHGI and GHGRP information, as well as information from more
recent State regulations. No additional options were identified at this
time. Therefore, for this analysis for the NSPS, the EPA re-evaluated
these options as BSER. In the discussion below, the options to require
technology that would eliminate methane and VOC emissions by requiring
the use of a non-natural gas driven pumps are discussed, followed by a
discussion of routing natural gas driven pumps to a control device.
With the exception of the evaluation of instrument air systems, the
BSER analysis for pneumatic pumps was conducted on an individual pump
basis. Due to the differences in the level of emissions, we conducted
the BSER analysis separately for natural gas-driven diaphragm pneumatic
pumps and natural gas-driven piston pneumatic pumps for the production
and transmission and storage segments. The emission factor for
diaphragm pneumatic pumps is 3.46 tpy of methane, while it is only 0.38
tpy of methane for piston pumps. The corresponding VOC emission factors
are 0.96 tpy for the production segment and 0.096 tpy for the
transmission and storage segment for diaphragm pumps, and 0.11 and 0.01
tpy for piston pumps, for production and transmission and storage
segment, respectively.
For instrument air systems, the BSER analysis was conducted using
model plants that included combinations of diaphragm and piston pumps.
For example, the smallest model plant included two diaphragm pumps and
two piston pumps. Therefore, the cost effectiveness calculated for
these instrument air systems represents the cost to eliminate emissions
from both types of pumps. Since instrument air was the only option
evaluated for natural gas processing plants, the BSER determination was
made for all pumps at the plants (as opposed to separate determinations
for diaphragm and piston pumps).
Zero Emissions Options
For this analysis, we first evaluated the options that would
eliminate methane and VOC emissions from pneumatic pumps, specifically
instrument/compressed air systems, electric pumps, and solar-powered
pumps.
Instrument air systems require a compressor, power source,
dehydrator, and volume tank. No alterations are needed to the pump
itself to convert from using natural gas to instrument air. However,
they can only be utilized in locations with sufficient electrical
power. Instrument air systems are more economical and, therefore, more
common at facilities with a high concentration of pneumatic devices and
where an operator can ensure the system is properly functioning.
Electric pumps provide the same functionality as gas-driven pumps and
are only restricted by the availability of a source of electricity.
Solar-powered pumps are a type of electric pump, except that the
power is
[[Page 63227]]
provided by solar-charged direct current (DC). Solar-powered pumps can
be used at remote sites where a source of electricity is not available,
and they have been shown to be able to handle a range of throughputs up
to 100 gallons per day with maximum injection pressure around 3,000
pounds per square inch gauge (psig).
Production and Transmission and Storage Segments. For the
production and transmission and storage segments, we evaluated the
costs and impacts of these ``zero-emissions'' options (See Chapter 9 of
the NSPS OOOOb and EG TSD for this rulemaking). We found that the cost-
effectiveness of these options, for both diaphragm and piston pumps,
were generally within the ranges that the EPA considers reasonable.
However, for instrument air systems and electric pumps, our analysis
assumes that electricity is available onsite. As noted above, in 2015,
the EPA determined that a zero-emission standard for pumps in the
production and transmission and storage segments was infeasible because
(1) electricity is not available at all sites and (2) solar pumps are
not technically feasible in all situations for which piston pumps and
diaphragm pumps are needed. 80 FR 56625-56626. While we specifically
requested comment on this determination in 2015, nothing was submitted
at that time that caused a reversal in this decision. At this time, we
are unclear as to whether these limitations have been overcome and
whether zero-emission pneumatic pumps are technically feasible for all
pneumatic pumps throughout the production and transmission and storage
segments. Therefore, at this time, we are unable to conclude that this
zero-emission option represents BSER in this proposal, but we are
soliciting comment on this issue to better understand whether a zero-
emission option is now technically feasible.
As explained in Section XII.C.1.e, the EPA believes that similar
previously identified technical limitations have been overcome in the
context of pneumatic controllers. Further, a few States do prohibit
emissions from pneumatic pumps throughout the Crude Oil and Natural Gas
Industry. California prohibits the venting of natural gas to the
atmosphere from pneumatic pumps through the use of compressed air or
electricity, or by collecting all potentially vented natural gas with
the use of a vapor collection system that undergoes periodic leak
detection and repair. While California requires this, the fact that
other States (e.g., Colorado, Wyoming) do not require zero emissions
from pneumatic pumps at all locations leads us to be uncertain as to
whether it is technically feasible at this time. Canadian Provinces
also regulate emissions from natural gas-driven pneumatic pumps. In
British Columbia, pneumatic pumps installed after January 1, 2021, must
not emit natural gas, and in Alberta, vent gas from pneumatic pumps
installed after January 2, 2022, must be prevented. In addition, New
Mexico has proposed a regulation that requires zero-emitting pumps, but
only at production and transmission and storage sites that have access
to electricity.
The EPA is soliciting comment on the basis for our proposed
determination: That because electricity is not available at all sites
and that there are applications at these sites where solar-powered
pumps may not be feasible the Agency is uncertain as to whether the
zero-emission options represent BSER. Also, as noted above, we are
soliciting comment on an approach where the EPA would propose to
subcategorize pneumatic pumps located in the production and
transmission and storage sites based on availability of electricity and
develop separate standards for each subcategory.
Natural gas processing plants. Natural gas processing plants are
known to have a source of electrical power. Therefore, instrument air
and electric pumps are technically feasible options at these
facilities.
As the next step in the BSER determination, we evaluated capital
and annual costs of compressed air systems for the natural gas
processing plants. While electric pumps are an option at natural gas
processing plants, we assumed that natural gas processing plants will
elect to always use instrument air and an impacts analysis for electric
pumps was not conducted.
The capital costs for an instrument air system were estimated to
range from $4,500 to $39,500. The annual costs include the capital
recovery cost (calculated at a 7 percent interest rate for 10 years),
labor costs for operations and maintenance, and electricity costs.
These are estimated to range from $11,300 to $81,350. Because gas
emissions are avoided as compared to the use of natural gas-driven
pumps, the use of an instrument air system will have natural gas
savings realized from the gas not released. The EPA estimates that each
diaphragm pump replaced will save 201 Mcf per year of natural gas from
being emitted and each piston pump will save of 22 Mcf per year in the
processing segment. The estimated value of the natural gas saved, based
on $3.13 per Mcf, would range from $1,400 to $35,000 per year per
plant. The annual costs, including these savings, ranges from $9,900 to
$46,500. More information on this cost analysis is available in the
NSPS OOOOb and EG TSD for this proposal.
The resulting cost effectiveness, under the single pollutant
approach where all the costs are assigned to the reduction of one
pollutant, for the application of instrument air to achieve a 100
percent emission reduction at natural gas processing plants ranges from
$420 to $1,470 per ton of methane eliminated. For VOC, these cost
effectiveness values ranged from $1,520 to $5,290 per ton of VOC
eliminated. Considering savings, these cost effectiveness values range
from $240 to $1,300 per ton of methane eliminated and $870 to $4,600
per ton of VOC eliminated. Under the multipollutant approach where half
the cost of control is assigned to the methane reduction and half to
the VOC reduction, the cost effectiveness ranges from $210 to $730 per
ton of methane eliminated and $760 to $2,640 per ton of VOC eliminated.
Considering savings, the cost effectiveness values range from $120 to
$650 per ton of methane eliminated and from $440 to $2,320 per ton of
VOC eliminated. These values are well within the range of what the EPA
considers to be reasonable for methane and VOC using both the single
pollutant and multipollutant approaches. As discussed above, the
evaluation for instrument air systems is based on a combination of
diaphragm and piston pumps. Therefore, this determination of
reasonableness applies to both types of pumps at natural gas processing
plants.
The 2016 NSPS OOOOa requires a natural gas emission rate of zero
for pneumatic pumps at natural gas processing plants. Natural gas
processing plants have successfully met this standard. Further, as
discussed above several State agencies have rules that include this
zero-emission requirement. This is a demonstration of the
reasonableness of a natural gas emission rate of zero for pneumatic
pumps at natural gas processing plants.
Secondary impacts from the use of instrument air systems are
indirect, variable, and dependent on the electrical supply used to
power the compressor. These impacts are expected to be minimal, and no
other secondary impacts are expected.
In light of the above, we find that the BSER for reducing methane
and VOC emissions from natural gas-driven piston and diaphragm pumps at
gas processing plants is a natural gas emission rate of zero. This
option results in a 100 percent reduction of emissions for both methane
and VOC. Therefore, for NSPS OOOOb, we are
[[Page 63228]]
proposing to require a natural gas emission rate of zero for all
pneumatic pumps at natural gas processing plants.
Routing to a Control Device or VRU Options
Above we stated our determination that the EPA is unable to
conclude that this zero-emission option represents BSER in this
proposal for pumps in the production and transmission and storage
segments. Therefore, we evaluated the use of control devices to reduce
methane and VOC emissions. This BSER analysis was conducted on an
individual pump basis and diaphragm and piston pumps were evaluated
separately.
Combustors (e.g., enclosed combustion devices, thermal oxidizers
and flares that use a high-temperature oxidation process) can be used
to control emissions from natural gas-driven pumps. Combustors are used
to control VOCs in many industrial settings, since the combustor can
normally handle fluctuations in concentration, flow rate, heating
value, and inert species content. The types of combustors installed in
the Crude Oil and Natural Gas Industry can achieve at least a 95
percent control efficiency on a continuous basis. It is noted that
combustion devices can be designed to meet 98 percent control
efficiencies, and can control, on average, emissions by 98 percent or
more in practice when properly operated. However, combustion devices
that are designed to meet a 98 percent control efficiency may not
continuously meet this efficiency in practice in the oil and gas
industry due to factors such as variability of field conditions.
A related option for controlling emissions from pneumatic pumps is
to route vapors from the pump to a process, such as back to the inlet
line of a separator, to a sales gas line, or to some other line
carrying hydrocarbon fluids for beneficial use, such as use as a fuel.
Use of a VRU has the potential to reduce the VOC and methane emissions
from natural gas-driven pneumatic pumps by 100 percent if all vapor is
recovered. However, the effectiveness of the gas capture system and
downtime for maintenance would reduce capture efficiency and therefore,
we estimate that routing emissions from a natural gas-driven pump to a
VRU and to a process can reduce the gas emitted by approximately 95
percent, while at the same time, capturing the gas for beneficial use.
Based on a 95 percent reduction, the reduction in emissions in the
production segment would be 3.29 tpy of methane and 0.91 tpy of VOC per
diaphragm pump, and 0.36 tpy methane and 0.10 tpy VOC per piston pump.
In the transmission and storage segment, the reduction in emissions
would be 3.29 tpy of methane and 0.09 tpy of VOC per diaphragm pump,
and 0.36 tpy of methane and 0.01 ton per year of VOC per piston pump.
Installation of a new combustion device or VRU. Costs for the
installation of a new combustion device and a new VRU were evaluated.
Installing a new combustion device has associated capital costs and
operating costs. Based on the analysis conducted for the 2012 NSPS for
a combustion device to control emissions from storage vessels, the
capital cost for installing a new combustion device was $32,300 in 2008
dollars. We updated this to $38,500 to reflect 2019 dollars. Based on
the life expectancy for a combustion device at 10 years, we estimate
the annualized capital cost of installing a new combustion device to be
$5,500 in 2019 dollars, using a 7 percent discount rate. The 2016 NSPS
OOOOa TSD indicates the annual operating costs associated with a new
combustion device were $17,000 in 2012 dollars, which we updated to
$19,100 in 2019 dollars. Therefore, the total annual costs for a new
combustion device are $24,600. Because the gas captured is combusted
there are no gas savings associated with the use of a combustion
device.
Installing a new VRU would also have both capital costs and
maintenance costs. We based the costs of a VRU on the analysis
conducted for the 2012 NSPS for control of emissions from storage
vessels, which is representative of the costs that would be incurred
for a VRU used to reduce emissions from natural gas-driven pneumatic
pumps. The capital cost and installation costs for a new VRU are
estimated to be $116,900 (in 2019 dollars) and the annual operation and
maintenance costs estimated to be $11,200 (in 2019 dollars). The total
annualized cost of a new VRU is estimated to be $27,800, including the
operation and maintenance cost and the annualized capital costs based
on a 7 percent discount rate and 10-year equipment life.
Because there is potential for beneficial use of gas recovered
through the VRU, the savings that would be realized for 95 percent of
the gas that would have emitted and lost were estimated. The gas saved
would equate to 191 Mcf per year from a diaphragm pump and 21 Mcf per
year from a piston pump. This results in estimated annual savings of
$600 per diaphragm pump and $65 per piston pump in the production
segment. The resulting annual costs, considering these savings, are
$27,200 per diaphragm pump and $27,700 per piston pump in the
production segment. Transmission and storage facilities do not own the
natural gas; therefore, savings from reducing the amount of natural gas
emitted/lost was not applied for this segment. More information on
these cost analyses is available in the NSPS OOOOb and EG TSD for this
proposal.
The resulting cost effectiveness estimates for application of a new
control device to reduce emissions from natural gas-driven pumps in the
production segment by 95 percent, or the use of a VRU to route
emissions back to a process, are discussed below under both the single
pollutant approach, where all the costs are assigned to the reduction
of one pollutant, and the multipollutant approach, where half the cost
of control is assigned to the methane reduction and half to the VOC
reduction. The results are presented separately for diaphragm and
piston pumps. These values assume that the control device or VRU is
installed solely for the purpose of controlling the emissions from a
single natural gas-driven pneumatic pump, and only the emission
reductions from a single pump are considered.
For diaphragm pumps in the production segment using the single
pollutant approach, the cost effectiveness is estimated to be $7,500
per ton of methane reduced using a new combustion device, and $8,500
using a new VRU ($8,300 with savings). For VOC, these cost
effectiveness values are $26,900 per ton of VOC reduced using a new
combustion device, and $30,400 using a new VRU ($29,800 with savings).
These values are outside of the range considered reasonable by the EPA
for both methane and VOC.
For diaphragm pumps in the production segment using the
multipollutant approach, the cost effectiveness is estimated to be
$3,750 per ton of methane reduced using a new combustion device, and
$4,250 using a new VRU ($4,150 with savings). For VOC, these cost
effectiveness values are $13,450 per ton of VOC reduced using a new
combustion device, and $15,200 using a new VRU ($14,900 with savings).
These values are outside of the range considered reasonable by the EPA
for both methane and VOC.
For piston pumps in the production segment using the single
pollutant approach, the cost effectiveness is estimated to be $68,100
per ton of methane reduced using a combustion device, and $77,000 using
a VRU ($76,800 with savings). For VOC, these cost effectiveness values
are $244,800
[[Page 63229]]
per ton of VOC reduced using a combustion device, and $277,000 using a
VRU ($276,400 with savings). These values are outside of the range
considered reasonable by the EPA for both methane and VOC.
For piston pumps in the production segment using the multipollutant
approach, the cost effectiveness is estimated to be $34,000 per ton of
methane reduced using a combustion device, and $38,500 using a VRU
($38,400 with savings). For VOC, these cost effectiveness values are
$122,400 per ton of VOC reduced using a combustion device, and $138,500
using a VRU ($138,200 with savings). These values are outside of the
range considered reasonable by the EPA for both methane and VOC.
For diaphragm pumps in the transmission and storage segment using
the single pollutant approach, the cost effectiveness is estimated to
be $7,400 per ton of methane reduced using a new combustion device, and
$8,500 using a new VRU. For VOC, these cost effectiveness values are
$270,000 per ton of VOC reduced using a new combustion device, and
$305,000 using a new VRU. These values are outside of the range
considered reasonable by the EPA for both methane and VOC.
For diaphragm pumps in the transmission and storage segment using
the multipollutant approach, the cost effectiveness is estimated to be
$3,700 per ton of methane reduced using a new combustion device, and
$4,200 using a new VRU. For VOC, these cost effectiveness values are
$135,000 per ton of VOC reduced using a new combustion device, and
$152,600 using a new VRU. These values are outside of the range
considered reasonable by the EPA for both methane and VOC.
For piston pumps in the transmission and storage segment using the
single pollutant approach, the cost effectiveness is estimated to be
$68,000 per ton of methane reduced using a combustion device, and
$77,000 using a VRU. For VOC, these cost effectiveness values are $2.5
million per ton of VOC reduced using a combustion device, and $2.8
million using a VRU. These values are outside of the range considered
reasonable by the EPA for both methane and VOC.
For piston pumps in the transmission and storage segment using the
multipollutant approach, the cost effectiveness is estimated to be
$34,000 per ton of methane reduced using a combustion device, and
$38,500 using a VRU. For VOC, these cost effectiveness values are $1.2
million per ton of VOC reduced using a combustion device, and $1.4
million using a VRU. These values are outside of the range considered
reasonable by the EPA for both methane and VOC.
For diaphragm pumps, we do not consider the costs to be reasonable
to install a new control device, or a new VRU to route the emissions to
a process, for the production and transmission and storage segments for
methane or VOC emission reduction using either the single pollutant or
multipollutant approach. Similarly, for piston pumps, we do not
consider the costs to be reasonable under any scenario. Therefore, we
are unable to conclude that requiring the installation of a new control
device, or the installation of a new VRU to route emissions to a
process, to achieve 95 percent reduction of methane and VOC emissions
from natural gas-driven pumps for the production or transmission
segments represents BSER in this proposal.
Routing to an existing combustion device or VRU. In addition to
evaluating the installation of a new control device or new VRU
installed solely for the purpose of reducing the emissions from a
single natural gas-driven pneumatic pump, we evaluated the option of
routing the emissions from natural gas-driven pneumatic pumps to an
existing control device to achieve a 95 percent reduction in methane
and VOC emissions or routing the emissions to an existing VRU and to a
process. The emission reduction for this option would be the same as
discussed above for a new control device achieving 95 percent control,
that is 3.29 tpy of methane and 0.91 tpy of VOC per diaphragm pump, and
0.36 tpy methane and 0.10 tpy VOC per piston pump in the production
segment and 3.29 tpy of methane and 0.09 tpy of VOC per diaphragm pump,
and 0.36 tpy of methane and 0.01 ton per year of VOC per piston pump in
the transmission and storage segment. The resulting cost effectiveness
estimates for use of an existing control device to reduce emissions
from natural gas-driven pumps in the production segment by 95 percent,
or the use of an existing VRU to route emissions to a process, are
discussed below under both the single pollutant approach, where all the
costs are assigned to the reduction of one pollutant, and the
multipollutant approach, where half the cost of control is assigned to
the methane reduction and half to the VOC reduction. The results are
presented separately for diaphragm and piston pumps.
We estimated the costs for routing emissions to an existing control
device or VRU based on the average of the cost presented in the 2015
proposed NSPS OOOOa and the costs presented by two commenters to the
proposal,\295\ as documented in the 2016 NSPS OOOOa TSD. This yielded a
capital cost estimate of $6,100 in 2019 dollars, for an annualized cost
of $900 in 2019 dollars, using the 7 percent discount rate and 10-year
equipment life. In the 2016 NSPS OOOOa TSD the EPA assumed there were
no incremental operating costs for routing to an existing control
device or VRU, so the total annual costs consist only of the $900
capital recovery cost. This assumption is maintained for this analysis.
The same savings discussed above for the gas that is recovered by a VRU
would be realized when routing to an existing VRU and to a process.
These savings are $600 per year per diaphragm pump and $65 per year per
piston pump in the production segment. The resulting annual costs for
routing to an existing VRU and to process, considering these savings,
are $270 per diaphragm pump and $800 per piston pump in the production
segment. As noted above, transmission and storage facilities do not own
the natural gas; therefore, savings from reducing the amount of natural
gas emitted/lost was not applied for this segment.
---------------------------------------------------------------------------
\295\ EPA-HQ-OAR-2010-0505-6884-A1 and EPA-HQ-OAR-2010-0505-
6881.
---------------------------------------------------------------------------
For diaphragm pumps in the production segment using the single
pollutant approach, the cost effectiveness is estimated to be $260 per
ton of methane reduced using an existing combustion device, and $260
per ton of methane using an existing VRU ($80 with savings). For VOC,
these cost effectiveness values are $950 per ton of VOC reduced using
an existing combustion device, and $950 using an existing VRU ($300
with savings). For diaphragm pumps in the production segment using the
multipollutant approach, the cost effectiveness is estimated to be $130
per ton of methane reduced using an existing combustion device, and
$130 using an existing VRU ($40 with savings). For VOC, these cost
effectiveness values are $475 per ton of VOC reduced using an existing
combustion device, and $475 using an existing VRU ($150 with savings).
These values are well within the range of what the EPA considers to be
reasonable for methane and VOC using both the single pollutant and
multipollutant approaches.
For diaphragm pumps in the transmission and storage segment using
the single pollutant approach, the cost effectiveness is estimated to
be $260 per ton of methane reduced using an existing combustion device,
and $260 using an existing VRU. For VOC, these
[[Page 63230]]
cost effectiveness values are $9,500 per ton of VOC reduced using an
existing combustion device, and $9,500 using an existing VRU. For
diaphragm pumps in the transmission and storage segment using the
multipollutant approach, the cost effectiveness is estimated to be $130
per ton of methane reduced using an existing combustion device, and
$130 using an existing VRU. For VOC, these cost effectiveness values
are $4,800 per ton of VOC reduced using an existing combustion device,
and $4,800 using an existing VRU. These values are within the range of
what the EPA considers to be reasonable.
The 2016 NSPS OOOOa requires that emissions from natural gas driven
pneumatic pumps at well sites achieve a 95 percent reduction in methane
and VOC emissions by routing them to a control device if an existing
control device is on site. Owners and operators at well sites have
successfully met this standard. Further, several State agencies (e.g.,
California, proposed in New Mexico) have rules that include this
requirement, and have extended the requirement to sites throughout the
production segment as well as the transmission and storage segment.
These factors considered together demonstrate the reasonableness of a
requirement that emissions from natural gas driven pneumatic pumps at
sites without access to electricity achieve a 95 percent reduction in
methane and VOC emissions by routing them to a control device, provided
that an existing control device is on site.
There are secondary impacts from the use of a combustion device to
control emissions routed from natural gas-driven diaphragm pumps. The
combustion of the recovered natural gas creates secondary emissions of
hydrocarbons, NOX, CO2, and CO. The EPA considers
the magnitude of these emissions to be reasonable given the significant
reduction in methane and VOC emissions that the control would achieve.
Details of these impacts are provided in the NSPS OOOOb and EG TSD for
this rulemaking. There are no other wastes created or wastewater
generated. The secondary impacts from use of a VRU are indirect,
variable, and dependent on the electrical supply used to power the VRU.
No other secondary impacts are expected.
In light of the above, we find that the BSER for reducing methane
and VOC emissions from natural gas-driven diaphragm pumps in the
production and transmission and storage segments is to route the
emissions to an existing control device that achieves 95 percent
control of methane and VOC, or to route the emissions to an existing
VRU and to a process. We are, therefore, proposing to include this
requirement in NSPS OOOOb.
For piston pumps in the production segment using the single
pollutant approach, the cost effectiveness is estimated to be $2,400
per ton of methane reduced using a combustion device, and $2,400 using
a VRU ($2,200 with savings). For VOC, these cost effectiveness values
are $8,700 per ton of VOC reduced using a combustion device, and $8,700
using a VRU ($8,000 with savings).
For piston pumps in the production segment using the multipollutant
approach, the cost effectiveness is estimated to be $1,200 per ton of
methane reduced using a combustion device, and $1,200 using a VRU
($1,100 with savings). For VOC, these cost effectiveness values are
$4,350 per ton of VOC reduced using a combustion device, and $4,350
using a VRU ($4,000 with savings).
For piston pumps in the production segment, we do not consider the
costs to route emissions from a natural gas-driven pneumatic pump to an
existing control device to achieve 95 percent reduction, or to route to
an existing VRU and to a process, to be reasonable for methane or VOC
using the single pollutant approach. However, the methane and VOC cost
effectiveness using the multipollutant method is within the range that
the EPA considers reasonable.
There are secondary impacts from the use of a combustion device to
control emissions routed from natural gas-driven piston pumps. These
impacts are the same as discussed above for diaphragm pumps.
In light of the above, we find that the BSER for reducing methane
and VOC emissions from natural gas-driven piston pumps in the
production and transmission and storage segments is to route the
emissions to an existing control device that achieves 95 percent
control of methane and VOC, or to route the emissions to an existing
VRU and to a process. We are, therefore, proposing to include this
requirement for piston pumps in NSPS OOOOb.
The EPA notes that State rules for concerning natural gas-driven
piston pumps emissions control requirements differ. For example,
California specifically includes both diaphragm and piston pumps in the
definition of pneumatic pumps, while Colorado specifically excludes
piston pumps from control requirements. At this time, the EPA is unable
to fully understand the basis for the piston pump State control
requirement differences based on the background information for these
State rules.
We are specifically seeking comment on the emissions factors used
to estimate the baseline emissions from pneumatic pumps, which are from
a 1996 EPA/GRI study.\296\ The EPA is interested in more recent
information regarding emissions from pneumatic pumps.
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\296\ Gas Research Institute (GRI)/U.S. Environmental Protection
Agency. 1996d. Research and Development, Methane Emissions from the
Natural Gas Industry, Volume 13: Chemical Injection Pumps. June 1996
(EPA-600/R-96-080m).
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For piston pumps in the transmission and storage segment using the
single pollutant approach, the cost effectiveness is estimated to be
$2,400 per ton of methane reduced using a combustion device, and $2,400
using a VRU. For VOC, these cost effectiveness values are $87,000 per
ton of VOC reduced using a combustion device, and $87,000 using a VRU.
For piston pumps in the transmission and storage segment using the
multipollutant approach, the cost effectiveness is estimated to be
$1,200 per ton of methane reduced using a combustion device, and $1,200
using a VRU. For VOC, these cost effectiveness values are $43,500 per
ton of VOC reduced using a combustion device, and $43,500 using a VRU.
For piston pumps in the transmission and storage segment, we do not
consider the costs to be reasonable to route emissions from a natural
gas-driven pneumatic pump to an existing control device, or to route to
an existing VRU and to a process, for either methane or VOC under the
single pollutant approach. Further, we do not find that the cost
effectiveness for both methane and VOC to be reasonable under the
multipollutant approach. Therefore, we are unable to conclude that
requiring the routing of emissions from natural gas-driven piston pumps
in the transmission and storage segment to an existing control device
to achieve 95 percent reduction of methane and VOC emissions, or the
routing of emissions to a VRU and to a process, represents BSER for
NSPS OOOOb in this proposal.
2. EG OOOOc
The EPA evaluated BSER for the control of methane from existing
pneumatic pumps (designated facilities) in all segments in the Crude
Oil and Natural Gas source category covered by the proposed NSPS OOOOb
and translated the degree of emission limitation achievable through
application of the BSER into a proposed presumptive standard for these
facilities
[[Page 63231]]
that mirrors the proposed NSPS OOOOb, with the exception of the BSER
conclusion regarding piston pumps in the production segment.
First, based on the same criteria and reasoning explained above the
EPA is proposing to define the designated facility in the context of
existing pneumatic pumps as those that commenced construction on or
before November 15, 2021. Based on information available to the EPA, we
did not identify any factors specific to existing sources that would
indicate that the EPA should alter this definition as applied to
existing sources.
The EPA finds that the controls evaluated for new sources for NSPS
OOOOb are appropriate for consideration for existing sources under the
EG OOOOc. The EPA finds no reason to evaluate different, or additional,
control measures in the context of existing sources because the EPA is
unaware of any control measures, or systems of emission reduction, for
pneumatic pumps that could be used for existing sources but not for new
sources. Next, the methane emission reductions expected to be achieved
via application of the control measures identified above to new sources
are also expected to be achieved by application of the same control
measures to existing sources. The EPA finds no reason to believe that
these calculations would differ for existing sources as compared to new
sources because the EPA believes that the baseline emissions of an
uncontrolled source are the same, or very similar, and the efficiency
of the control measures are the same, or very similar, compared to the
analysis above. This is also true with respect to the costs, non-air
environmental impacts, energy impacts, and technical limitations
discussed above for the control options identified.
The EPA has not identified any costs associated with applying these
controls at existing sources, such as retrofit costs, that would apply
any differently than, or in addition to, those costs assessed above
regarding application of the identified controls to new sources. The
cost effectiveness values for the option of zero emissions from
pneumatic pumps in the natural gas processing sector range from $420 to
$1,470 per ton of methane eliminated ($240 to $1,300 per ton
considering savings). These cost effectiveness values are in the range
considered reasonable by the EPA. However, as explained above in the
context of new sources, at this time we are unclear as to whether the
technical limitations associated with this option have been overcome
and whether zero-emission pneumatic pumps are technically feasible.
Therefore, at this time, we are unable to conclude that this zero-
emission option represents BSER in this proposal for the EG, but we are
soliciting comment on this issue to better understand whether a zero-
emission option is technically feasible.
For diaphragm pumps in the production segment the cost
effectiveness is estimated to be $260 per ton of methane reduced using
an existing (on site) combustion device or VRU, and $260 per ton of
methane using an existing (on site) VRU ($80 with savings). For
diaphragm pumps in the transmission and storage segment the cost
effectiveness of is estimated to be $260 per ton of methane reduced
using an existing (on site) combustion device, and $260 using an
existing (on site) VRU. This cost effectiveness is considered
reasonable by the EPA.
For piston pumps in the production segment the cost effectiveness
is estimated to be $2,400 per ton of methane reduced using an existing
(on site) combustion device or VRU, and $2,400 per ton of methane using
an existing (on site) VRU ($2,200 with savings). For piston pumps in
the transmission and storage segment the cost effectiveness is
estimated to be $2,400 per ton of methane reduced using an existing (on
site) combustion device, and $2,400 using an existing (on site) VRU.
This cost effectiveness is outside of the range considered reasonable
by the EPA. In summary, the EPA did not identify any factors specific
to existing sources, as opposed to new sources, that would alter the
analysis above for the proposed NSPS OOOOb as applied to the designated
pollutant (methane) and the designated facilities (pneumatic pumps).
However, the BSER conclusion regarding piston pumps in the production
and transmission and storage segments for the EG differs from the
conclusion for new sources under the NSPS. As a result, the proposed
presumptive standards for existing pneumatic pumps are as follows.
For diaphragm pneumatic pumps in the production and transmission
and storage segments, the presumptive standard is routing emissions to
an existing (already on site) control device or existing (already on
site) VRU and to a process to achieve 95 percent reduction in methane.
For pneumatic pumps (diaphragm and piston) in the natural gas
processing sector, the presumptive standard is a natural gas emission
rate of zero.
As for new sources, the EPA is specifically soliciting comment on
whether the production and transmission storage segments should be
subcategorized based on the availability of electricity and BSER
determined separately for each subcategory in the EG.
H. Proposed Standards for Equipment Leaks at Natural Gas Processing
Plants
1. NSPS OOOOb
a. Background
In the 2012 NSPS OOOO, the EPA established VOC standards for
equipment leaks at onshore natural gas processing plants. These
standards were based on the Standards of Performance for Equipment
Leaks of VOC in the Synthetic Organic Chemicals Manufacturing Industry
(NSPS VVa), which is an EPA Method 21 LDAR program generally requiring
monthly monitoring of pumps with a leak definition of 2,000 ppm,
quarterly monitoring of valves with a leak definition of 500 ppm, and
annual monitoring of connectors with a leak definition of 500 ppm.\297\
In the 2016 NSPS OOOOa, the EPA added GHG (methane) to the title of the
standards for equipment leaks at onshore natural gas plants but
continued to rely on the requirements in NSPS VVa, which limited
monitoring and repair (if found leaking) to those equipment components
``in VOC service.'' Based on our review of the current standards, we
are proposing to revise the equipment leak standards for onshore
natural gas plants to more readily apply to equipment components that
have the potential to emit methane even though they are not ``in VOC
service.''
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\297\ 40 CFR part 60, subpart VVa, includes ``skip period''
provisions that may alter the cited monitoring frequencies.
---------------------------------------------------------------------------
b. Technology and LDAR Program Review
The EPA acknowledges that advancements are being made in leak
detection, including remote sensing, sensor networks, and OGI. The EPA
already provides use of OGI as an alternative work practice at 40 CFR
60.18(g); however, the alternative work practice requires annual EPA
Method 21 monitoring as part of the OGI monitoring protocol. Parallel
with this proposal, the EPA is proposing appendix K to part 60 to
provide a standard method for OGI leak monitoring. This allows us to
consider a wider range of LDAR programs when evaluating the BSER for
equipment leaks at onshore natural gas processing plants. To evaluate
different LDAR programs, we used a Monte Carlo simulation that
simulated initiation of leaks for pumps, valves, and connectors at
monthly intervals based on
[[Page 63232]]
component specific leak frequencies and EPA Method 21 leak size
distributions based on historical EPA Method 21 leak data. We randomly
assigned a mass emission rate based on the EPA Method 21 leak size
assuming a lognormal distribution for the mass emission rate around the
EPA Method 21 screening value correlation equation estimates. The
simulation runs for five years for each LDAR program to build up leaks
that might not be repaired under a given program, and compares the
emissions estimated in the fifth year of the simulation for different
LDAR programs. The model also records the number of repairs made in the
fifth year of the simulation to assess the annual repair costs
associated with the LDAR program. More information on the LDAR program
Monte Carlo simulation and associated cost analyses is available in the
NSPS OOOOb and EG TSD for this proposal.
Based on our model simulation of NSPS OOOOa requirements (Method 21
based LDAR program following the requirements in NSPS VVa), the EPA
projects that the program achieves a 91.5 percent emission reduction
for the components monitored. This is comparable to the projected
control efficiencies of this LDAR program applied to similar industrial
processes.\298\ However, when considering the components not monitored
at the onshore natural gas processing plant because they are not ``in
VOC service'', the overall hydrocarbon control efficiency of the
current NSPS OOOOa requirements drops to 73.2 percent. Thus,
significant emission reductions can be achieved by extending the
current provisions to include all components that have the potential to
emit methane.
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\298\ EPA, October 2007. ``Leak Detection and Repair--A Best
Practices Guide.'' Office of Enforcement and Compliance Assurance.
EPA-305-D-07-001. See ``Table 4.1--Control effectiveness for an LDAR
program at a chemical process unit and a refinery.''
---------------------------------------------------------------------------
Based on our model simulation of an OGI-based LDAR program, we
found that bimonthly OGI monitoring of all equipment components (with
potential VOC or methane emissions) using devices capable of
identifying mass leaks at 30 g/hr and at 15 g/hr would achieve emission
reductions of 88.5 percent and 92.2 percent, respectively. Based on the
requirements in appendix K that the instrument be able to detect a
methane leak of 17 g/hr, these results suggest that bimonthly OGI
monitoring following appendix K will achieve comparable emission
reductions as the current NSPS OOOOa requirements for the equipment
components subject to the monitoring requirements.
c. Control Options and 2021 BSER Analysis
The EPA then evaluated various LDAR programs for their control
efficiency, cost and cost effectiveness for a small and a large model
natural gas processing plant. These ``small'' and ``large'' model
plants were based on the number of components at each facility in
various monitoring summaries for onshore natural gas processing
plants.\299\ We considered the (option 1) current NSPS OOOOa standards
expanded to components that also have the potential to emit methane
regardless of the VOC content of the stream, (option 2) bimonthly OGI
following appendix K for all components (VOC or methane), and (options
3 and 4) a hybrid approach following the current alternative work
practice (regular OGI with annual EPA Method 21). For option 3 we
evaluated requiring quarterly OGI with an annual EPA Method 21 survey
at 10,000 ppm. For option 4 we evaluated requiring bimonthly OGI with
an annual EPA Method 21 survey at 10,000 ppm. These control options and
their associated costs are summarized in Tables 18 and 19 for the small
and large model plants, respectively.
---------------------------------------------------------------------------
\299\ See Section 10.4 of Chapter 10 ``Equipment Leaks from
Natural Gas Processing Plants'' in the TSD located at Docket ID No.
EPA-HQ-OAR-2021-0317.
Table 18--Summary of Control Options and Costs for Small Model Plants
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Emissions reduction (tpy)
Control option -------------------------------- Capital cost Annual cost ($/ CE \a\ ($/ton CE \a\ ($/ton Incremental ($/ Incremental ($/
VOC Methane ($) yr) VOC) methane) ton VOC) ton methane)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Methane and VOC Service
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1............................................................... 12.34 56.95 $17,700 $114,100 $9,200 $2,000 .............. ..............
2............................................................... 12.61 58.19 1,500 62,800 5,000 1,100 -189,100 -41,300
3............................................................... 12.64 58.33 19,200 84,500 6,700 1,400 696,200 151,100
4............................................................... 12.76 58.92 19,200 95,500 7,500 1,600 87,000 18,800
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Cost effectiveness (CE) compared to no monitoring.
Table 19--Summary of Control Options and Costs for Large Model Plants
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Emissions reduction (tpy)
Control option -------------------------------- Capital cost Annual cost ($/ CE \a\ ($/ton CE \a\ ($/ton Incremental ($/ Incremental ($/
VOC Methane ($) yr) VOC) methane) ton VOC) ton methane)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Methane and VOC Service
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1............................................................... 25.59 118.27 $36,200 $229,000 $9,000 $1,900 .............. ..............
2............................................................... 26.11 120.81 3,000 123,500 4,700 1,000 -200,000 -43,100
3............................................................... 26.17 121.10 39,200 170,500 6,500 1,400 760,000 165,200
4............................................................... 26.44 122.31 39,200 191,300 7,200 1,600 79,500 17,100
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\a\ Cost effectiveness (CE) compared to no monitoring.
We further assumed that all facilities outsource their equipment
leak surveys. The first year ``capital'' costs of implementing an EPA
Method 21 program (identifying components required to be monitored and
developing a data system to track the proper frequency to monitor each
component) are summarized in Tables 18 and 19. Additionally, these
tables summarize the annualized costs of conducting a complete EPA
Method 21
[[Page 63233]]
monitoring survey of all equipment (those in VOC service or contacting
methane), which includes the annual costs of conducting required
surveys and making the necessary repairs as well as annualized first
year ``capital'' costs. The first-year startup costs for OGI surveys
are small, estimated to be $750 for small plants and $1,500 for large
plants. Because OGI surveys can be conducted much more quickly, the
annualized cost of conducting bimonthly OGI surveys is approximately
half the annualized cost of EPA Method 21 surveys through NSPS VVa.
Both EPA Method 21 and OGI LDAR programs reduce loss of product.
Therefore, the costs of the LDAR programs are offset to some degree to
the emissions reduced. When evaluating LDAR programs that consider all
components (both VOC and methane), the annual value of the product not
lost due to reduced emissions is approximately $14,000/yr.
Based on our analysis, the resulting cost effectiveness is
reasonable for all of the options when assigning all costs to the
reduction of methane. When assigning all costs to VOC reduction,
however, only the bimonthly OGI option is considered reasonable at
$5,000/ton VOC reduced for small plants and $4,700/ton VOC reduced at
large plants. The EPA next considered the incremental cost-
effectiveness between the four options to determine which option
represents the BSER for equipment leaks at onshore natural gas
processing plants. All four options achieve similar emission
reductions, as discussed in the previous section. Bimonthly OGI (option
2) reduces an additional 2 tpy of methane at a cost savings. Adding
annual EPA Method 21 to bimonthly OGI monitoring (option 4) reduces an
additional 1.5 tpy methane for large model gas plant but at significant
cost well above any costs the EPA would consider appropriate, at
approximately $45,000/ton methane reduced (comparing option 4 with
option 2). Therefore, the EPA does not consider it reasonable to
require the additional of annual EPA Method 21.
Based on the discussion above, we consider a bimonthly OGI LDAR
program following appendix K that includes all equipment components
that have the potential to emit VOC or methane to be BSER for new
sources. Therefore, we are proposing this LDAR requirement for new
sources under NSPS OOOOb. Because an EPA Method 21 monitoring program
based on the requirements of NSPS VVa when applied to all equipment
components that have the potential to emit VOC or methane is projected
to achieve similar emission reductions, we are proposing that this EPA
Method 21-based LDAR program may be used as an alternative to bimonthly
OGI surveys.
In the development of the 2012 NSPS OOOO, we found that NSPS VVa
provisions for PRDs, open-ended valves or lines, and closed vent
systems and equipment designated with no detectable emissions were
BSER. Available information since then continues to support this
conclusion. Therefore, we are proposing to retain the current
requirements in the 2016 NSPS OOOOa (which adopts by reference specific
provisions NSPS VVa) for PRDs, open-ended valves or lines, and closed
vent systems and equipment designated with no detectable emissions,
except expanding the applicability to sources that have the potential
to emit methane. The EPA is soliciting information that would support
the use of the proposed bimonthly OGI monitoring requirement for these
equipment components in place of the NSPS VVa annual EPA Method 21
monitoring.
The EPA requests comments on ways to streamline approval of
alternative LDAR programs using remote sensing techniques, sensor
networks, or other alternatives for equipment leaks at onshore natural
gas processing plants. Based on our Monte Carlo equipment leak model
that assumes well-implemented LDAR programs with no delayed repair,
both an EPA Method 21 based program following NSPS VVa and a bimonthly
OGI monitoring program following appendix K are projected to achieve a
91-percent emission reduction effectiveness. We request comment on
whether providing such an emission reduction target and equipment leak
modeling tool to simulate LDAR under similar ``ideal'' program
implementation conditions may facilitate future equivalency
determinations.
2. EG OOOOc
The application of an LDAR program at an existing source is the
same as at a new source because there is no need to retrofit equipment
at the site to achieve compliance with the work practice standard. The
cost effectiveness for implementing a bimonthly OGI LDAR program for
all equipment components that have the potential to emit methane is
approximately $850/ton methane reduced. As explained above, the cost
effectiveness of this OGI monitoring option is within the range of
costs we believe to be reasonable for methane reductions. Therefore, we
consider a bimonthly OGI LDAR program following appendix K that
includes all equipment components that have the potential to emit
methane to be BSER for existing sources.
I. Proposed Standards for Well Completions
1. NSPS OOOOb
a. Background
Pursuant to CAA section 111(b)(1)(B), the EPA reviewed the current
standards in NSPS OOOOa for well completions and proposes to determine
that they continue to reflect the BSER for reducing methane and VOC
emissions during oil and natural gas well completions following
hydraulic fracturing and refracturing. Accordingly, we are not
proposing revisions to these standards. Provided below are a
description of the affected facilities, the current standards, and a
summary of our review.
Natural gas and oil wells all must be ``completed'' after initial
drilling in preparation for production. Well completion activities not
only will vary across formations but can vary between wells in the same
formation. Over time, completion and recompletion activities may change
due to the evolution of well characteristics and technology
advancement. Well completion activities include multiple steps after
the well bore hole has reached the target depth. Developmental wells
are drilled within known boundaries of a proven oil or gas field and
are located near existing well sites where well parameters are already
recorded and necessary surface equipment is in place. When drilling
occurs in areas of new or unknown potential, well parameters such as
gas composition, flow rate, and temperature from the formation need to
be ascertained before surface facilities required for production can be
adequately sized and brought on site. In this instance, exploratory
(also referred to as ``wildcat'') wells and field boundary delineation
wells typically either vent or combust the flowback gas.
One completion step for improving oil and gas production is to
fracture the reservoir rock with very high-pressure fluid, typically a
water emulsion with a proppant (generally sand) that ``props open'' the
fractures after fluid pressure is reduced. Natural gas emissions are a
result of the backflow of the fracture fluids and reservoir gas at high
pressure and velocity necessary to clean and lift excess proppant to
the surface. Natural gas from the completion backflow escapes to the
atmosphere during the reclamation of water, sand, and hydrocarbon
liquids during the collection of the multi-phase mixture directed to a
surface impoundment. As the fracture fluids are depleted, the
[[Page 63234]]
backflow eventually contains a higher volume of natural gas from the
formation. Due to the specific additional equipment and resources
involved and the nature of the backflow of the fracture fluids,
completions involving hydraulic fracturing have higher costs and vent
substantially more natural gas than completions not involving hydraulic
fracturing.
During its lifetime, wells may need supplementary maintenance,
referred to as recompletions (these are also referred to as workovers).
Recompletions are remedial operations required to maintain production
or minimize the decline in production. Examples of the variety of
recompletion activities include completion of a new producing zone, re-
fracture of a previously fractured zone, removal of paraffin buildup,
replacing rod breaks or tubing tears in the wellbore, and addressing a
malfunctioning downhole pump. During a recompletion, portable equipment
is conveyed back to the well site temporarily and some recompletions
require the use of a service rig. As with well completions,
recompletions are highly specialized activities, requiring special
equipment, and are usually performed by well service contractors
specializing in well maintenance. Any flowback event during a
recompletion, such as after a hydraulic fracture, will result in
emissions to the atmosphere unless the flowback gas is captured.
When hydraulic re-fracturing (recompletions) is performed, the
emissions are essentially the same as new well completions involving
hydraulic fracture, except that surface gas collection equipment will
already be present at the wellhead after the initial fracture. The
flowback velocity during re-fracturing will typically be too high for
the normal wellhead equipment (separator, dehydrator, lease meter),
while the production separator is not typically designed for separating
sand.
Flowback emissions are a result of free gas being produced by the
well during well cleanup event, when the well also happens to be
producing liquids (mostly water) and sand. The high rate flowback, with
intermittent slugs of water and sand along with free gas, is directed
to an impoundment or vessels until the well is fully cleaned up, where
the free gas vents to the atmosphere while the water and sand remain in
the impoundment or vessels. Therefore, nearly all of the flowback
emissions originate from the recompletion process but are vented as the
flowback enters the impoundment or vessels. Minimal amounts of
emissions are caused by the fluid (mostly water) held in the
impoundment or vessels since very little gas is dissolved in the fluid
when it enters the impoundment or vessels.
The 2021 GHGI estimates approximately 34,000 metric tpy of methane
emissions from hydraulically fractured completion/workover natural gas
well events and approximately 12,000 metric tpy of methane emissions
from hydraulically fractured completion/workover oil well events in
2019.
b. Affected Facility
Each affected facility is a single well that conducts a well
completion operation following hydraulic fracturing or refracturing.
c. Current NSPS Requirements
The current NSPS for natural gas and oil well completions and
recompletions are the same. For well completions of hydraulically
fractured (or refractured) wells, the EPA identified two subcategories
of hydraulically fractured wells for which well completions are
conducted: (1) Non-wildcat and non-delineation wells (subcategory 1
wells); and (2) wildcat and delineation wells and low-pressure wells
(subcategory 2 wells). A wildcat well, also referred to as an
exploratory well, is a well drilled outside known fields or is the
first well drilled in an oil or gas field where no other oil and gas
production exists. A delineation well is a well drilled to determine
the boundary of a field or producing reservoir.
In the 2016 NSPS OOOOa rule, the EPA finalized operational
standards for non-wildcat and non-delineation wells (subcategory 1
wells) that required a combination of REC and combustion. Because RECs
are not feasible for every well at all times during completion or
recompletion activities due to variability of produced gas pressure
and/or inert gas concentrations, the rule allows for wellhead owners
and operators to continue to reduce emissions when RECs are not
feasible due to well characteristics (e.g., wellhead pressure or inert
gas concentrations) by using a completion combustion device. For
wildcat and delineation wells and low-pressure wells (subcategory 2
wells), the EPA finalized an operational standard that required either
(1) routing all flowback directly to a completion combustion device
with a continuous pilot flame (which can include a pit flare) or, at
the option of the operator, (2) routing the flowback to a well
completion vessel and sending the flowback to a separator as soon as a
separator will function and then directing the separated gas to a
completion combustion device with a continuous pilot flame. For option
2, any gas in the flowback prior to the point when the separator will
function was not subject to control. For both options (1) and (2),
combustion is not required 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. Under the 2016 NSPS OOOOa rule, oil wells with a gas-to-oil
ratio less than 300 scf of gas per stock tank barrel of oil produced
are affected facilities but have no requirements other than to maintain
records of the low GOR certification and a claim signed by the
certifying official. As discussed in section X.B.1 of this preamble, in
the 2020 Technical Rule, the EPA made certain amendments (e.g., related
to the use of a separator, amended definition of flowback, amended
recordkeeping and reporting requirements) to the VOC standards for well
completions in the 2016 NSPS OOOOa, and is proposing to apply the same
amendments to the methane standards for well completions in the 2016
NSPS OOOOa.
d. 2021 BSER Analysis
The two techniques considered under the previous BSER analyses that
have been proven to reduce emissions from production segment well
completions and recompletions include REC and completion combustion.
REC is an approach that not only reduces emissions but delivers natural
gas product to the sales meter that would typically be vented. The
second technique, completion combustion, destroys the organic
compounds. No other emissions control techniques were identified as
being required under other rules (Federal, State, or local rules) that
would exceed the level of control required under the 2016 NSPS OOOOa
rule. Therefore, no other technology control requirements were
evaluated in this review.
Reduced emission completions, also referred to as ``green'' or
``flareless'' completions, use specially designed equipment at the well
site to capture and treat gas so it can be directed to the sales line.
This process prevents some natural gas from venting and results in
additional economic benefit from the sale of captured gas and, if
present, gas condensate. However, as the EPA has previously
acknowledged, there are some limitations that may exist for performing
RECs based on technical barriers. These limitations continue to exist.
Three main limitations for performing a REC include the proximity of
pipelines to the well, the pressure of the produced gas, and the inert
gas
[[Page 63235]]
concentration. These limitations are discussed below.
For exploratory wells (in particular), no nearby sales line may
exist. The lack of a nearby sales line incurs higher capital outlay
risk for exploration and production companies and/or pipeline companies
constructing lines in exploratory fields. The EPA is soliciting comment
on how ``access to a sales line'' and a ``sales line'' should be
defined.
During the completion/recompletion process, the pressure of
flowback fluids may not be sufficient to overcome the gathering line
backpressure. In this case, combustion of flowback gas is one option,
either for the duration of the flowback or until a point during
flowback when the pressure increases to flow to the sales line. Another
potential compressor application is to boost pressure of the flowback
gas after it exits the separator. This technique is experimental
because of the difficulty operating a compressor where there is a
widely fluctuating flowback rate.
Lastly, if the concentration of inert gas, such as nitrogen or
CO2, in the flowback gas exceeds sales line concentration
limits, venting to the atmosphere or to a combustion device of the
flowback may be necessary for the duration of flowback or until the gas
energy content increases to allow flow to the sales line. Further,
since the energy content of the flowback gas may not be high enough to
sustain a flame due to the presence of the inert gases, combustion of
the flowback stream would require a continuous ignition source with its
own separate fuel supply.
Where a REC can be conducted, the achievable emission reductions
vary according to reservoir characteristics and other parameters
including length of completion, number of fractured zones, pressure,
gas composition, and fracturing technology/technique. Based on several
experiences presented at Natural Gas STAR technology transfer
workshops, this analysis assumes 90 percent of flowback gas can be
recovered during a REC.\300\ Gas that cannot be recovered during a REC
can be directed to a completion combustion device in order to achieve
an estimated 95 percent reduction in overall emissions.
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\300\ Memorandum to Bruce Moore, U.S. EPA from ICF Consulting.
Percent of Emissions Recovered by Reduced Emission Completions. May
2011.
---------------------------------------------------------------------------
Completion combustion devices commonly found on drilling sites are
generally crude and portable, often installed horizontally due to the
liquids that accompany the flowback gas. These flares can be as simple
as a pipe with a basic ignition mechanism and discharge over a pit near
the wellhead. However, the flow directed to a completion combustion
device may or may not be combustible depending on the inert gas
composition of flowback gas, which would require a continuous ignition
source. Sometimes referred to as pit flares, these types of combustion
devices do not employ an actual control device and are not capable of
being tested or monitored for efficiency. They do provide a means of
minimizing vented gas and is preferable to venting.
The efficiency of completion combustion devices, or exploration and
production flares, can be expected to achieve 90 percent, on average,
over the duration of the completion or recompletion.\301\ If the energy
content of natural gas is low, then the combustion mechanism can be
extinguished by the flowback gas. Therefore, it is more reliable to
install an igniter fueled by a consistent and continuous ignition
source. Because of the exposed flame, open pit flaring can present a
fire hazard or other undesirable impacts in some situations (e.g., dry,
windy conditions and proximity to residences). As a result, owners and
operators may not be able to combust unrecoverable gas safely in every
case.
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\301\ 77 FR 48889-48890, March 22, 2013 (Approval and
Promulgation of Federal Implementation Plan for Oil and Natural Gas
Well Production Facilities; Fort Berthold Indian Reservation
(Mandan, Hidatsa, and Arikara Nation), North Dakota; Rule).
---------------------------------------------------------------------------
Noise and heat are the two adverse impacts of completion combustion
device operations. In addition, combustion and partial combustion of
many pollutants also create secondary pollutants including
NOX, CO, sulfur oxides (SOX), CO2, and
smoke/particulates. The degree of combustion depends on the rate and
extent of fuel mixing with air and the temperature maintained by the
flame. Most hydrocarbons with carbon-to-hydrogen ratios greater than
0.33 are likely to smoke. The high methane content of the gas stream
routed to the completion combustion device, it suggests that there
should not be smoke except in specific circumstances (e.g., energized
fractures). The stream to be combusted may also contain liquids and
solids that will also affect the potential for smoke.
The previous BSER analyses cost effectiveness per ton of methane
and VOC emissions reduced per completion event evaluated for REC,
completion combustion, and REC and completion combustion were updated
to 2019 dollars. The results of this updated analysis are provided
below, and details are provided in the NSPS OOOOb and EG TSD for this
rulemaking.
The updated capital cost for performing a REC for a well completion
or recompletion lasting 3 days is estimated to be $15,174 (2019
dollars). Monetary savings associated with additional gas captured to
the sales line is estimated based on a natural gas price of $3.13 per
Mcf. It was assumed that all gas captured would be included as sales
gas. The updated capital and cost for wells including completion
combustion devices resulted in an estimated average completion
combustion device cost of approximately of $4,198 per well completion
(2019 dollars). For both REC and completion combustion devices, the
capital costs are one-time events, and annual costs were conservatively
assumed to be equal to the capital costs. The EPA also evaluated the
costs that would be associated with using a combination of a REC and
completion combustion device. The annual costs would be a combined
estimated capital and annual cost of $19,371 (2019 dollars). As a
result of updating capital/annual costs to reflect 2019 dollars and
decreasing the control efficiency assumed for completion combustion
from 95 percent to 90 percent, the cost effectiveness estimates are
slightly higher, but substantially similar to previous cost
effectiveness BSER analysis control option estimates for natural gas
well and oil well completions and recompletions.
For gas wells, under the single pollutant approach where all the
costs are assigned to the reduction of methane emissions and zero to
reduction of VOC, the cost effectiveness estimates were approximately
$1,180 per ton of methane reduced for REC ($990 with natural gas
savings), $330 for completion combustion, and $1,420 for a combination
of REC and completion combustion ($1,250 with natural gas savings). If
all costs were assigned to VOC reduction and zero to methane reduction,
the cost effectiveness estimates were approximately $4,230 per ton of
VOC removed for REC ($3,570 with natural gas savings), $1,170 for
completion combustion, and $5,110 for a combination of REC and
completion combustion ($4,490 with natural gas savings). Under the
multipollutant approach where half the cost of control is assigned to
the methane reduction and half to the VOC reduction, these estimates
are approximately $590 per ton of methane reduced for REC ($500 with
natural gas savings), $160 for completion combustion, and $710 for a
combination of REC and completion combustion ($630 with natural gas
savings). For VOC, the cost effectiveness
[[Page 63236]]
estimates were approximately $2,100 per ton of VOC removed for REC
($1,790 with natural gas savings), $590 for completion combustion, and
$2,600 for a combination of REC and completion combustion ($2,250 with
natural gas savings).
For oil wells, under the single pollutant approach where all the
costs are assigned to the reduction of methane emissions and zero to
reduction of VOC emissions, the cost effectiveness values were
approximately $1,620 per ton of methane reduced for REC ($1,440 with
natural gas savings), $450 for completion combustion, and $1,960 for a
combination of REC and completion combustion ($1,790 with natural gas
savings). Where all costs were assigned to reducing VOC emissions and
zero to reducing methane emissions, the cost effectiveness estimates
were approximately $5,840 per ton of VOC removed for REC ($5,190 with
natural gas savings), $1,620 for completion combustion, and $7,070 for
a combination of REC and completion combustion ($6,450 with natural gas
savings). Under the multipollutant approach where half the cost of
control is assigned to the methane reduction and half to the VOC
reduction, these estimates are approximately $810 per ton of methane
reduced for REC ($720 with natural gas savings), $230 for completion
combustion, and approximately $980 for a combination of REC and
completion combustion ($900 with natural gas savings). For VOC, the
cost effectiveness estimates were approximately $2,920 per ton of VOC
removed for REC ($2,600 with natural gas savings), $810 for completion
combustion, and $3,530 for a combination of REC and completion
combustion ($3,220 with natural gas savings).
As noted above, the current NSPS OOOOa requirements consist of a
combination of REC and completion combustion for hydraulically
fractured natural gas and oil well completions. These techniques have
been employed by the oil and gas industry since 2012 for natural gas
well completions and 2016 for oil well completions. The EPA concludes
that the cost effectiveness of REC, completion combustion, or a
combination, for natural gas and oil wells are within the range that
the EPA considers to be reasonable when considering both methane and
VOC cost effectiveness. Since there are multiple scenarios where the
cost effectiveness of the control measures is reasonable for natural
gas and oil wells (including the cost effectiveness of VOC for REC and
combined REC and completion combustion), we conclude that the overall
cost effectiveness is reasonable.
There are secondary impacts from the use of a completion combustion
device, as the combustion of the gas creates secondary emissions of
hydrocarbons, NOX, CO2, and CO. The EPA considers
the magnitude of these emissions to be reasonable given the significant
reduction in methane and VOC emissions that the control would achieve.
Details of these impacts are provided in the NSPS OOOOb and EG TSD for
this rulemaking. There are no other wastes created or wastewater
generated from either REC or completion combustion.
In light of the above, we determined that the current standards,
which consist of a combination of REC and combustion, continue to
represent the BSER for reducing methane and VOC emissions from well
completions of hydraulically fractured or refractured oil and natural
gas wells. We therefore propose to retain these standards in the
proposed NSPS OOOOb.
As discussed in section XII.I.1.c, in the 2020 Technical Rule, the
EPA made certain amendments to the VOC standards for well completions
in the 2016 NSPS OOOOa. For the same reasons provided in the 2020
Technical Rule and discussed in section X.B.1 of this preamble for
including these amendments for methane in NSPS OOOOa, the EPA is
proposing to include these methane and VOC amendments for well
completions in the NSPS OOOOb rule.
2. EG OOOOc
A well completion operation following hydraulic fracturing or
refracturing is a ``modification,'' as defined in CAA section 111(a),
as each such well completion operation involves a physical change to a
well that results in an increase in emissions; accordingly, each such
operation would trigger the applicability of the NSPS. Therefore, there
are no ``existing'' well completion operations of hydraulically
fractured or refractured oil or natural gas wells. In light of the
above, there are no proposed presumptive standards for such operations
in this action.
J. Proposed Standards for Oil Wells With Associated Gas
1. NSPS OOOOb
a. Background
Wells in some formations and shale basins are drilled primarily for
oil production. Although the wells are drilled for oil, the wells may
produce an associated, pressurized natural gas stream. The natural gas
is either naturally occurring in a discrete gaseous phase within the
liquid hydrocarbon or is released from the liquid hydrocarbons by
separation. In many areas, a natural gas gathering infrastructure may
be at capacity or unavailable. In such cases, if there is not another
beneficial use of the gas at the site (e.g., as fuel) the collected
natural gas is either flared or vented directly to the atmosphere.
Emissions from associated gas venting and flaring are not regulated
by either the 2012 NSPS OOOO or the NSPS OOOOa. The EPA did not
evaluate BSER for associated gas production in either rulemaking. For
this rulemaking, the EPA is proposing that methane and VOC emissions
resulting from associated gas production be reduced by at least 95
percent.
b. Definition of Affected Facility
The EPA is proposing the definition of an oil well associated gas
affected facility as an oil well that produces associated gas.
c. Description
In 2019, according to the EIA, the number of onshore gas producing
oil wells in the U.S.\302\ was 334,342 and the volume of vented and
flared natural gas in 2019 was 523,066 million cubic feet.\303\
According to the 2021 GHGI, in 2019 venting of associated gas emitted
42,051 metric tons of CH4 and 1,291 metric tons of
CO2 and flaring of associated gas emitted 81,797 metric tons
of CH4 and 25,355,892 metric tons of CO2.
---------------------------------------------------------------------------
\302\ https://www.eia.gov/dnav/ng/ng_prod_oilwells_s1_a.htm. The
number of onshore gas producing oil wells was derived from the
``U.S. Natural Gas Number of Oil Wells'' subtracting ``Federal
Offshore--Gulf of Mexico'' wells [336,732--2,390 = 334,342 wells].
\303\ https://www.eia.gov/dnav/ng/ng_prod_sum_a_EPG0_VGV_mmcf_a.htm. The volume of vented and flared
natural gas was derived from ``U.S. Natural Gas Vented and Flared''
subtracting ``Alaska--State Offshore'' and ``California--State
Offshore'' and ``Federal Offshore--Gulf of Mexico'' and
``Louisiana--State Offshore'' and ``Texas--State Offshore''
[538,479-825-0-14,461-45-82 = 523,066].
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For the 2019 reporting year in GHGRP subpart W, there were a total
of 2,500 wells that reported emissions from the venting of associated
gas emissions. The total emissions from these wells were just over
33,900 metric tons of methane (848,000 metric tons CO2e).
Over 90 percent of these methane emissions were reported in three
basins--Gulf Coast, Williston, and Permian. Examining this information
by State shows that almost half of the venting wells and over 64
percent of the methane emissions from the venting of associated gas
occurs in Texas. Texas and North Dakota account for almost 90
[[Page 63237]]
percent of the reported methane emissions from vented associated gas
oil wells. The average methane emissions from the venting of associated
gas in 2019 was 13.6 metric tpy per venting well. The average per State
ranges from 0.03 tpy per venting well in California to over 340 tpy per
venting well in North Dakota.
The 2019 GHGRP subpart W data also show that there were over 38,000
wells reporting that they flared associated gas, with over 21 million
metric tons of CO2 emissions and over 68,000 metric tons of
methane emissions. As with the venting emissions, the majority of the
wells flaring associated gas (over 93 percent) were in the Gulf Coast,
Williston, and Permian basins. Approximately 96 percent of the
CO2 and methane emissions were reported in these three
basins. The majority of the wells flaring associated gas (over 72
percent) and emissions (over 87 percent) were from wells in Texas and
North Dakota.
d. Control Options
For new and existing sources (oil wells), options to mitigate
emissions from associated gas in order of environmental and resource
conservation benefit include:
Capturing the associated gas from the separator and
routing into a gas gathering flow line or collection system;
Beneficially using the associated gas (e.g., onsite use,
natural gas liquid processing, electrical power generation, gas to
liquid);
Reinjecting for enhanced oil recovery; and
Flaring with legally and practicably enforceable limits.
Typically, State oil and gas regulatory agencies (or, on certain
public and Tribal lands, the BLM) regulate venting and flaring of
associated gas from oil wells to ensure oil and natural gas resources
are conserved and utilized in a manner consistent with their respective
statutes. State oil and gas regulatory agencies typically encourage,
and in some cases require, capture (conservation) over flaring, then
flaring over venting. In addition, these State regulators have adopted
a variety of approaches for regulating venting and flaring of
associated gas from oil wells. Some require technical and economic
feasibility analyses for continuing flaring beyond a certain time
(e.g., one year). Some require gas capture plans to track and
incrementally increase the percentage of gas captured (rather than
flared) over prescribed timelines and some of these include provisions
to curtail production in the event of not meeting gas capture goals.
Many State oil and gas regulations recognize that there are times when
gas capture may not be feasible, such as when there is no gas gathering
pipeline to tie into, the gas gathering pipeline may be at capacity, or
a compressor station or gas processing plant downstream may be off-
line, thus closing in the gas gathering pipeline. Venting is allowed by
some State and regulatory agencies in certain circumstances such as
emergency or upset conditions, during production evaluation, and well
purging or productivity tests. In cases where venting is allowed, these
rules typically require reporting of the volume of gas flared and
vented (and sometimes a gas analysis), while some States combine
flaring and venting information together in publicly accessible well
data.
Where flares are allowed, these State oil and gas regulations
typically do not include monitoring, recordkeeping and reporting on the
performance of the flare and would not be recognized as providing
legally and practicably enforceable limits for CAA purposes. Some State
environmental regulators address associated gas with a regulation
stipulating flaring over venting that includes monitoring,
recordkeeping and reporting provisions, while others regulate flaring
over venting without monitoring requirements.
The EPA is interested in information on, and the feasibility, of
options to utilize associated gas in some useful manner in situations
where a sales line is not available. In addition to use as fuel, such
options could include conversion technologies where methane is
converted into hydrogen or other added value chemicals. The EPA is
interested in information on these, as well as other, technologies.
e. 2021 BSER Analysis
In performing the BSER analysis for emissions from associated gas
oil wells, we recognize there are similarities between the control
options available for associated gas and those available for emissions
from oil well completions. We are soliciting comment on these
similarities. For both flowback emissions during oil well completions
and associated gas production, if the infrastructure exists to allow
the routing of the gas to a sales line (e.g., ``into a gas flow line or
collection system''), owners and operators will almost always choose
that option given the economic benefits of being able to sell the gas.
For example, in the 2019 GHGRP subpart W data, applicable facilities
reported over 1.2 trillion scf of associated gas was routed to sales
lines. This represents only a subset of the total volume of associated
gas sent to a sales line, as GHGRP subpart W does not require reporting
of this volume in subbasins where the company is not also reporting
venting or flaring associated gas.
The environmental benefit of routing all associated gas to a sales
line is significant, as there are no methane and VOC emissions. The EPA
assumes that in situations where gas sales line infrastructure is
available, there is minimal cost to owners and operators to route the
associated gas to the sales line. While situations at well sites can
differ, which would impact this cost, the EPA believes that in every
situation the value of the natural gas captured and sold would outweigh
these minimal costs of routing the gas to the sales line, thus
resulting in overall savings. Given the prevalence of this practice,
the environmental benefit, and the economic benefits to owners and
operators, the EPA concludes that BSER is routing associated gas from
oil wells to a sales line. The EPA seeks comment on this proposed BSER
determination, including comment on how to define whether an oil well
producing associated gas has access to a sales line for purposes of
this BSER and what factors (such as proximity to an existing sales
line) should bear on that determination.
NSPS OOOOa also includes other compliance options that achieve a
100 percent reduction in emissions from recovered flowback gas. These
are ``re-inject the recovered gas into the well or another well, use
the recovered gas as an onsite fuel source, or use the recovered gas
for another useful purpose that a purchased fuel or raw material would
serve.'' 40 CFR 60 60.5375a(a)(1)(ii). The EPA believes that, for
associated gas from oil wells, the options of using the gas as an
onsite fuel source or for another useful purpose are also viable
alternatives to routing to a sales line. However, a significant
difference exists between the short-term and relatively small volume of
gas recovered during the limited duration of completion flowback versus
the consistent flow of recovered gas from ongoing production from the
well. Because of this difference, the EPA does not have information
that supports re-injecting the associated gas into the well or another
well as a viable emissions control alternative. Therefore, the EPA is
specifically requesting comment on whether NSPS OOOOb should include
re-injecting associated gas as an alternative to routing the gas to a
sales line.
The format of the well completion provisions in NSPS OOOOa
recognize that routing the recovered gas to a gas flow line or
collection system, re-
[[Page 63238]]
injecting the recovered gas, or using the recovered gas fuel or for
another purpose may not be technically feasible. In these situations,
owners and operators are required to route the flowback emissions to a
completion combustion device.
Similarly, the EPA recognizes that there are associated gas oil
wells where there is no access to a gas sales line. Therefore, as an
aspect of BSER in these situations, the EPA evaluated the flaring of
the associated gas as an option to control emissions for situations
where access to a sales line is not available.
As discussed previously, the average annual methane emissions from
the venting of associated gas reported in GHGRP subpart W for 2019 is
13.6 metric tpy (14.9 tpy) per venting well. Using a representative gas
composition for the production segment, the estimated VOC emissions
would be 4.15 tpy per well. We conducted the BSER analysis using this
emissions level as a representative well.
The installation and proper operation of a flare can achieve 95
percent and greater reduction in methane and VOC emissions. To be
conservative, a 95 percent emission reduction was used for the BSER
analysis. Therefore, the resulting emission reductions are 14.2 tpy
methane and 3.9 tpy VOC.
The capital cost of a flare is estimated to be $5,719. This was
based on a 2011 Natural Gas Star Pro Fact Sheet and updated to 2019
dollars. The resulting capital recovery, assuming a 7 percent interest
rate and 15-year equipment life, was $628. The Natural Gas Star Pro
report estimated the cost of the natural gas needed for the pilot was
$1,800 per year. For this cost analysis, we assumed that this cost was
not warranted since the associated gas could be used to fuel the pilot.
We are soliciting comments on this cost estimate.
The EPA stresses that 95 percent or greater emission reduction is
achievable if the flare is properly operated and maintained. In order
to ensure that this occurs, the EPA proposes to apply the requirements
in Sec. 60.18 of the part 60 General Provisions to oil wells flaring
associated gas. In order to account for the cost of the compliance with
these requirements, we assumed that the associated cost would be 25
percent of the total annual costs, or an additional $160. This results
in a total estimated annual cost of $785. We are soliciting comment on
the estimated costs associated with compliance with the Sec. 60.18
monitoring, reporting, and recordkeeping costs for flares used to
control emissions of vented associated gas emissions, and whether those
requirements would ensure the flare is achieving the proposed emission
reduction of 95 percent or greater.
Based on these annual costs and the emission reductions cited
above, the cost effectiveness, using the single pollutant method, is
$55 per ton of methane reduction and $200 per ton of VOC reduction.
Using the multipollutant approach, the cost effectiveness is $30 per
ton of methane and $100 per ton of VOC. These cost effectiveness values
are well within the range considered reasonable by the EPA.
As discussed above, while flares significantly reduce the methane
and VOC emissions, there are CO, CO2, and NOX
emissions resulting from the combustion of the associated gas. We
estimate that for the representative well, the annual emissions
resulting from the flaring of the associated gas would be 50 tpy
CO2, 0.1 tpy CO, and 0.03 tpy NOX. While these
secondary impacts are not negligible, the EPA notes that emissions from
flaring represents over an 80 percent reduction in CO2e
emissions as compared to venting.
Based on our analysis, we find that the BSER for reducing methane
and VOC emissions from associated gas venting at well sites is routing
of the associated gas from oil wells to a sales line. In the event that
access to a sales line is not available, we are proposing that the gas
can be used as an onsite fuel source, used for another useful purpose
that a purchased fuel or raw material would serve, or routed to a flare
or other control device that achieves at least a 95 percent reduction
in emissions of methane and VOC.
We are requesting comment on the affected facility definition and
the overall format of the proposed requirements. The EPA is proposing
that an associated gas oil well affected facility be each oil well that
produces associated gas. The EPA is soliciting comments on how to
define ``associated gas'' or an ``oil well that produces associated
gas.'' The proposed NSPS OOOOb would require that all associated gas be
routed to a sales line. In the event that access to a sales line is not
available, the proposed NSPS OOOOb would require that the gas can be
used as an onsite fuel source, used for another useful purpose that a
purchased fuel or raw material would serve, or routed to a flare or
other control device that achieves at least a 95 percent reduction in
emissions of methane and VOC.
Under this proposal, every oil well that produces associated gas
would be an affected facility and therefore, subject to the rule. For
those wells where the associated gas is routed to a sales line, the
only requirement would be to certify that this is occurring. Wells that
use the associated gas as a fuel or for another purpose would be
required to document how it is used. If the associated gas is routed to
a flare, all of the proposed monitoring, recordkeeping, and reporting
requirements would apply.
As an alternative, the EPA is soliciting comments on defining the
affected facility as each oil well that produces associated gas and
does not route the gas to a sales line. This would significantly reduce
the number of affected facilities, although the burden for owners and
operators that route the gas to a sales line would be similar. While
they would not be required under NSPS OOOOb to maintain documentation
that the gas is routed to a sales line, they would still need to
maintain documentation to prove that the well was not an affected
facility. Under this alternative, the proposed rule would require that
the gas be used as an onsite fuel source, used for another useful
purpose that a purchased fuel or raw material would serve, or routed to
a flare or other control device that achieves at least a 95 percent
reduction in emissions of methane and VOC. The EPA's concern with this
alternative is that while we believe that most owners and operators
would route the gas to a sales line if there is access, it would not
specifically require routing the gas to a sales line. We expect that
the cost of a flare, along with the associated monitoring, reporting,
and recordkeeping costs, will provide additional incentive for owners
and operators to connect to an available sales line. We are requesting
comment on how, under this alternative approach, to incentivize owners
and operators even more to capture or beneficially use associated gas.
The EPA is specifically requesting comment on whether the proposed
requirements will incentivize the sale or productive use of captured
gas, and if not, other methods that the EPA could use to incentivize or
require the sale or productive use instead of flaring.
2. EG OOOOc
The EPA evaluated BSER for the control of methane from existing
associated gas oil wells that do not route the gas to a sales line or
to a process for another beneficial use (designated facilities) and
translated the degree of emission limitation achievable through
application of the BSER into a proposed presumptive standard for these
facilities that essentially mirrors the proposed NSPS OOOOb.
First, based on the same criteria and reasoning as explained above,
the EPA is proposing to define the designated
[[Page 63239]]
facilities in the context of those that commenced construction on or
before November 15, 2021. Based on information available to the EPA, we
did not identify any factors specific to existing sources that would
indicate that the EPA should change these definitions as applied to
existing sources. As such, for purposes of the emission guidelines, the
definition of a designated facility in terms of associated gas oil
wells as existing oil wells with associated gas that do not route the
gas to a sales line or to a process for another beneficial use.
Next, the EPA finds that the control options evaluated for new
sources for NSPS OOOOb are appropriate for consideration in the context
of existing sources under the EG OOOOc. The EPA finds no reason to
evaluate different, or additional, control measures in the context of
existing sources because the EPA is unaware of any control measures, or
systems of emission reduction, for the venting of associated gas that
could be used for existing sources but not for new sources.
Next, the methane emission reductions expected to be achieved via
application of the control measures identified above for new sources
are also expected to be achieved by application of the same control
measures to existing sources. The EPA finds no reason to believe that
these calculations would differ for existing sources as compared to new
sources because the EPA believes that the baseline emissions of an
uncontrolled source are the same, or very similar, and the efficiency
of the control measures are the same, or very similar, compared to the
analysis above. This is also true with respect to the costs, non-air
environmental impacts, energy impacts, and technical limitations
discussed above for the control options identified.
The information presented above regarding the costs related to new
sources and the NSPS are also applicable for existing sources. The EPA
considers these cost effectiveness values to be reasonable. Since none
of the other factors are different for existing sources when compared
to the information from discussed above for new sources, the EPA
concludes that BSER for existing sources and the proposed presumptive
standard for EG OOOOc to be the requirement to route associated gas to
a flare or other control device that achieves at least 95 percent
control.
Related to control option of flaring with legally and practicably
enforceable limits at existing oil wells specifically, enhancing
monitoring and performance requirements for flares at existing oil
wells may be an important emissions reduction measure. For those
operators who have already installed monitoring capability on their
existing flares, the additional investment may be minimal to cover
reporting of performance. For those existing oil wells where operators
do not have flare monitoring installed, the EPA solicits comment both
on the flare performance monitoring technology available and the cost
of procuring, installing, operating and maintaining such technology.
This could include, but is not limited to, digital pilot light
monitors, combustion temperature, gas flow meters, gas chromatography
(GC) units, and passive remote monitoring of combustion efficiencies at
the flare tip. Similar technologies have been used for flares
controlling landfill gas, including automated notifications of flare
failure. Additional discussion of control devices, including flares, is
included in section XIII.D of this preamble.
K. Proposed Standards for Sweetening Units
Sulfur dioxide (SO2) standards for onshore sweetening
units were first promulgated in 1985 and codified in 40 CFR part 60,
subpart LLL (NSPS LLL). In 2012, the EPA reviewed the NSPS for the oil
and natural gas sector, and the resulting 2012 NSPS OOOO rule
incorporated provisions of NSPS LLL with minor revisions to adapt the
NSPS LLL language to NSPS OOOO (77 FR 49489). The incorporated
provisions required sweetening unit affected facilities to reduce
SO2 emissions via sulfur recovery. The EPA also increased
the SO2 emission reduction standard from the subpart LLL
requirement for units with a sulfur production rate of at least 5 long
tons per day (LT/D) from 99.8 percent to 99.9 percent. This change was
based on the reanalysis of the original data used in the NSPS LLL BSER
analysis.
In 2016, the EPA finalized the NSPS OOOOa rule--which established
standards for both methane and VOCs for certain equipment, process and
activities across the oil and natural gas sector. The final 2016 NSPS
OOOOa rule reaffirmed and included the SO2 emission
reduction requirements as specified in the 2012 NSPS OOOO rule (81 FR
35824).
The EPA then amended the 2016 NSPS OOOOa rule in 2020 to correct an
affected facility definition applicability error in the rule as it
pertains to sweetening units. The 2016 NSPS OOOOa rule erroneously
limited the applicability of the SO2 standards to sweetening
units located at onshore natural gas processing plants. This limitation
was not included in NSPS LLL, and no reason was identified as to ``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'' (85 FR 57398).
Therefore, the 2020 NSPS OOOOa final rule amendments corrected the
affected facility description applicability error to correctly define
affected facilities as any onshore sweetening unit that processes
natural gas produced from either onshore or offshore wells at 40 CFR
60.5365a(g).
A sweetening unit refers to a process device that removes
H2S and/or CO2 from the sour natural gas stream
(40 CFR 60.5430a)--i.e., sweetening units convert H2S in
acid gases (i.e., H2S and CO2) that are separated
from natural gas by a sweetening process, like amine gas treatment,
into elemental sulfur in the Claus process. These units can operate
anywhere within the production and processing segments of the oil and
natural gas source category, including as stand-alone processing
facilities that do not extract or fractionate natural gas liquids from
field gas (85 FR 57408, September 15, 2020).
An estimated 6,900 tons of SO2 emissions were reported
under the National Emissions Inventory (NEI) for Year 2017 \304\ for
Source Classification Code 31000201 (Industrial Processes Oil and Gas
Production, Natural Gas Production, Gas Sweetening: Amine Process) and
SCC 31000208 (Industrial Processes, Oil and Gas Production, Natural Gas
Production, Sulfur Recovery Units).
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\304\ 2017 National Emissions Inventory (NEI) Data [verbar] US
EPA.
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Pursuant to CAA section 111(b)(1)(B), the EPA reviewed the current
standards in NSPS OOOOa (including the 2020 revisions) for sweetening
units and proposes to determine that they continue to reflect the BSER
for reducing SO2 emissions. The EPA has not identified any
greater emissions control level than what is currently required under
NSPS OOOOa for sweetening unit affected facilities. Therefore, the EPA
is proposing to retain/include the current NSPS OOOOa requirements for
sweetening units for the control of SO2 emissions from
sweetening unit affected facilities in NSPS OOOOb. The proposed NSPS
OOOOb maintains the requirement that each sweetening unit that
processes natural gas produced from either onshore or offshore wells is
an affected facility; as well as each sweetening unit
[[Page 63240]]
that processes natural gas followed by a sulfur recovery unit. Units
with a sulfur production rate of at least 5 long tons per day must
reduce SO2 emissions by 99.9 percent. Compliance with the
standard is determined based on initial performance tests and daily
reduction efficiency measurements. For affected facilities that have a
design capacity less than 2 LT/D of H2S in the acid gas
(expressed as sulfur), recordkeeping and reporting requirements are
required; however, emissions control requirements are not required.
Facilities that produce acid gas that is entirely re-injected into oil/
gas-bearing strata or that is otherwise not released to the atmosphere
are also not subject to emissions control requirements.
XIII. Solicitations for Comment on Additional Emission Sources and
Definitions
The EPA is considering including additional sources as affected
facilities under the proposed NSPS OOOOb and the proposed EG OOOOc.
Specifically, the EPA is evaluating the potential for establishing
standards applicable to abandoned and unplugged wells, pipeline pigging
and related blowdown activities, and tank truck loading operations.
While the EPA has assessed these sources based on currently available
information, we have determined that we need additional information to
evaluate BSER and propose NSPS and EG for these emissions sources. As
described below, the EPA is soliciting information to assist in this
effort.
The EPA is also assessing whether proposed standards that would
require 95 percent reduction based on a combustion control device as
the BSER (e.g., standards for storage vessels, centrifugal compressors,
pneumatic pumps, and associated gas that cannot be routed to a sales
line or consumed for a useful purpose) could be further strengthened,
including the potential for additional monitoring and associated
recordkeeping and reporting requirements, to ensure proper design and
operation of combustion control devices.
While we are not proposing NSPS nor EG for these emissions sources
(i.e., abandoned wells, pigging operations, or tank truck loading) or
updates to ensure proper design and operation of combustion control
devices in this action, the EPA is soliciting comment and information
that would better inform the EPA as we continue to evaluate options for
these sources. Should the EPA receive information through the public
comment process that would help the Agency evaluate BSER for these
emission sources, the EPA could consider NSPS and EG for these sources
through a supplemental proposal. In this section we summarize the
available information that we have evaluated regarding emissions,
control options, and where specific States may have existing
requirements, and we solicit specific comments. In the case of
combustion control devices, we solicit comment on the current standard
of 95 percent reduction and what additional monitoring, recordkeeping,
and reporting may be appropriate to ensure compliance. We also
generally solicit comment and information on the following topics
associated with these emission sources.
The EPA solicits comment on the control options discussed below and
how these controls may be broadly applied across different basins or
geographic areas. The EPA solicits comment on what equipment is onsite
during these emission events. The EPA solicits comment on the technical
feasibility of control options and any instances where it is not
technically feasible to minimize emissions from these sources
including, but not limited to, any retrofit concerns for existing
sources. The EPA solicits comment on any practices owners and operators
already implement as part of voluntary efforts or State requirements to
minimize emissions from these sources. The EPA solicits comment on
methods/approaches for estimating baseline emissions from these
sources, estimating cost of control, and efficiency of control options.
Finally, the EPA solicits comment on the cost of maintaining records
and submitting reports for these emissions sources, including the types
of records that are appropriate to maintain and report.
A. Abandoned Wells
The EPA is soliciting comment for potential NSPS and EG to address
issues with emissions from abandoned, or non-producing oil and natural
gas wells that are not plugged or are plugged ineffectively. Should the
EPA receive information through the public comment process that would
help the Agency evaluate BSER, the EPA may propose NSPS and EG through
a supplemental proposal.
The EPA broadly characterizes abandoned wells as oil or natural gas
wells that have been taken out of production, which may include a wide
range of non-producing wells. This includes wells that State
governments classify as idle, inactive, dormant, or shut-in, but not
plugged. The classification varies from State to State, and State
governments may allow these wells to be dormant, without plugging, for
varying time periods that may last several years. It also includes
wells with no production for many years--sometimes more than a decade--
and no responsible operator. These wells are commonly referred to as
orphaned, deserted, or long-term idle. Finally, this includes wells
that have been abandoned for long periods, known as legacy wells. State
governments have varied definitions of temporarily idled, orphaned, or
non-producing wells.
It is the EPA's understanding that since non-producing oil and
natural gas wells generally are not staffed and are seldom monitored,
many have fallen into disrepair. The EPA recognizes that some States
and NGOs also have elevated concerns about the potential number of low-
production wells that could be abandoned in the near future as they
reach the end of their productive lives. The 2021 GHGI estimates that
in 2019 the U.S. population of abandoned wells (including orphaned
wells and other non-producing wells) is around 3.4 million (about 2.7
million abandoned oil wells and 0.6 million abandoned natural gas
wells).\305\ These non-producing wells often have methane,
CO2, and VOC emissions. The most recent studies of emissions
from abandoned wells focus on methane emissions, which are larger than
the CO2 or VOC emissions from such wells.\306\ The GHGI
estimates that abandoned oil wells emitted 209 kt of methane and 4 kt
of CO2 in 2019. While emissions of both pollutants from
abandoned oil wells decreased by 10 percent from 1990, the total
population of these wells increased 28 percent. The GHGI estimates that
abandoned gas wells emitted 55 kt of methane and 2 kt of CO2
in 2019. While emissions of both pollutants increased from abandoned
gas wells by 38 percent from 1990, the total population of such wells
increased 84 percent.
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\305\ The GHGI separates non-producing oil and gas wells into
those that are unplugged and plugged. The abandoned wells identified
in the GHGI include those that have been taken out of production
temporarily, but can return to production, as well as orphan wells.
\306\ See TSD at Docket ID No. EPA-HQ-OAR-2021-0317.
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The large populations of abandoned unplugged wells are likely due
to various circumstances. For instance, some operators declare
bankruptcy before wells are plugged, and for many, bonding requirements
represent only a fraction of the actual costs to plug the well and
restore the well site. Wells are also abandoned or idled when changing
oil or natural gas prices make them unprofitable to continue
production.
[[Page 63241]]
The EPA recognizes that many oil and natural gas producing States
require the plugging of non-producing oil and natural gas wells, and
subsequent restoration of the well site. However, the large number of
abandoned, unplugged wells nationwide suggests that Federal standards
may be warranted. Many oil and gas producing States specify the time in
which wells may remain in idle status without State approval. At the
end of that time, States generally require tests of well integrity
before giving approval for additional time in this idle status.
In its 2018 survey of idled and abandoned wells, the IOGCC
documented State definitions and requirements for idled wells, as well
as the management plans for those wells.\307\ There is variation in how
States define these idle wells, ranging from no definitions to specific
definitions for documented and undocumented orphaned and abandoned
wells. Further, there is great variability in the allowance for the
length of time a well may remain in idle status with or without
approval, with some States limiting that time to a few months while
other States allow idled status indefinitely. While some States require
strict management plans of idled wells, others do not. Finally, some
States provide funds for plugging, remediating, and reclaiming orphan
wells, and others do not. These funds are supported by civil penalties,
settlements, forfeited bonds, and State appropriations. The IOGCC's
survey found that 28 States and Canadian provinces have wells approved
to remain in idle status, with most having between 100 and 10,000
approved idle wells. Most States and provinces maintain inventories of
documented orphan wells and prioritize orphan wells for plugging
according to risk. States and provinces reported from zero to 13,266
documented orphan wells, with about half reporting fewer than 100
orphan wells.
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\307\ See IOGCC Report located at Docket ID No. EPA-HQ-OAR-2021-
0317.
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The IOGCC's 2018 survey also collected estimates from some States
on the number of undocumented orphan wells, including those for which
no permits or other records exist. Most of these wells were drilled
before there was any regulatory oversight. Ten States reported no
undocumented orphan wells. Nine other States did not provide an
estimate. Eleven States provided an estimate ranging from fewer than 10
to 100,000 or more undocumented orphan wells. Most of the States
surveyed by the IOGCC had established funds dedicated to plugging
orphan wells. Money for these funds comes primarily from taxes, fees,
or other assessments on the oil and gas industry.
The EPA has identified the following potential strategies to reduce
air emissions from these sources. The first strategy is to employ
practices and procedures to ensure proper well closure. Under this
strategy, the EPA could focus on well closure requirements aimed at
preventing future abandonment of unplugged wells and halt the growth of
this unplugged population. Given that all wells eventually reach their
end of life, this strategy could be applied to both new and existing
wells. Under the NSPS, for example, the EPA could require owners or
operators to submit a closure plan describing when and how the well
would be closed and to demonstrate whether the owner or operator has
the financial capacity to continue to demonstrate compliance with the
rules until the well is closed and to carry out any required closure
procedures per the rule. This demonstration could require some
financial assurance or bonding if the Agency determines the financial
capacity of the owner or operator to continue to assure compliance with
the rule is in doubt. The EPA also could require reporting any transfer
of well ownership, along with a copy of the well closure requirements,
to the EPA and/or the applicable State when transferring ownership. The
Agency might also consider a requirement to temporarily close the well
to the atmosphere with a swedge and valve or packer or other approved
method once a well is temporarily abandoned or shut in. As one example,
this is a requirement under Colorado law for all wells that are
designated as shut in or temporarily abandoned.\308\
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\308\ Code of Colorado Regulations, Oil and Gas Conservation
Commission, 2 CCR 404-1, paragraph b, ``Temporary Abandonment,'' p.
80.
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The primary purpose of detailing financial capacity as part of a
compliance plan, and to potentially require some financial assurance
bonding, is to ensure that State governments have adequate resources to
plug oil and gas wells when the owner or operator is unwilling or
unable to do so. The IOGCC notes that States typically have
requirements for both single-well or blanket financial assurance. In
the IOGCC's 2018 survey, 35 States reported information on the types of
financial assurance accepted in their jurisdictions, with most
accepting more than one type. The IOGCC noted that the amounts and
criteria for bonding vary considerably among the States. Single-well
bond amounts range from $1,500 to $500,000 per well; blanket bonds
(covering multiple wells) vary from $7,500 to $30,000,000, the IOGCC
said. In some States, bond amounts are based on well depth; in others,
bond amounts are based on case-by-case evaluations; and in several,
bond amounts may be increased if determined necessary.
That study identified the following types of financial assurance,
including cash deposit of a payment given as a guarantee that an
obligation will be met, certificate of deposit of a financial
instrument certifying that the face amount is on deposit with the
issuing bank to be redeemed for cash by the State if required,
financial statements of a report of basic accounting data that depicts
a firm's financial history and activities, letter of credit,
irrevocable letter of credit where payment is guaranteed if stipulated
conditions are met, security interest giving the right to take property
or a portion of property offered as security, and surety or performance
bonds as a contract by which one party agrees to make payment on the
default or debt of another party. Other forms of financial assurance
include certificates of insurance, consolidated financial funds, escrow
accounts, and liens. The amounts and criteria for financial assurance
vary considerably among the States and provinces.
Another strategy under consideration is to require fugitive
emissions monitoring at a specified frequency for the duration of time
the well is idled and unplugged. The EPA's understanding, however, is
that most idled and non-producing well sites would be classified as
wellhead only sites, which the EPA is proposing to exclude from
fugitive emissions monitoring for both new and existing well sites (see
section XI.A).
The EPA is aware that other Federal agencies have information on,
and experience with, abandoned wells, such as the U.S. Forest Service,
National Park Service, U.S. Fish and Wildlife Service, and the BLM. On
Federal and Tribal mineral estate, the BLM coordinates with the surface
management agency when remediating abandoned wells to mitigate the
potential risks those wells may pose. The EPA may be informed by the
methods employed by the BLM to monitor and remediate abandoned wells on
Federal lands, as well as by draft legislative initiatives that may
expand the scope of the BLM's efforts. The EPA understands that one
such initiative, the ``Revive Economic Growth and Reclaim Orphaned
Wells (REGROW) Act,'' could amend the Energy Policy Act of 2005 to
[[Page 63242]]
require the BLM to establish a new program to plug, remediate, and
reclaim orphaned oil and gas wells and surrounding land, and to provide
funds to State and Tribal governments for this purpose.\309\
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\309\ S. 1076, ``To amend the Energy Policy Act of 2005 to
require the Secretary of the Interior to establish a program to
plug, remediate, and reclaim orphaned oil and gas wells and
surrounding land, to provide funds to State and Tribal governments
to plug, remediate, and reclaim orphaned oil and gas wells and
surrounding land, and for other purposes,'' 117th Congress, 1st
Session, as introduced on April 12, 2021, available at https://www.congress.gov/117/bills/s1076/BILLS-117s1076is.xml.
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The EPA is soliciting additional information that would support a
determination of the BSER to address emissions from abandoned, idled,
and non-producing wells. The specific information of interest includes
updates to the number of abandoned, orphaned, or temporarily idled
wells in the U.S., which could be State-specific or basin-specific;
fugitive emission estimates for the wells; and costs of mitigation
measures, including effective closure requirements and proper plugging
practices, financial assurance mechanisms, and requiring fugitive
emissions monitoring while in idled and unplugged status. The EPA is
also soliciting information on mechanisms to disincentivize operator
delay in permanently abandoning wells and/or transfer of late-life
assets to companies that may not be well-positioned to fund proper
closure. The EPA also solicits information at the State level, on the
length of time that wells remain temporarily idled before they must be
inspected by State governments. Further, we are seeking information
about what would be included in well closure requirements, including
what closure requirements are appropriate and any recordkeeping and
reporting associated with those requirements, as well as whether it is
appropriate to close the well to the atmosphere once it is designated
as shut in or temporarily abandoned. The EPA also solicits information
on whether compliance assurance for well closure requirements will
necessitate certain forms of financial assurance on the part of well
owners and operators. The EPA solicits comment on effective plugging,
such as criteria or guidelines are necessary for sufficient plugging
and post-plugging follow up monitoring necessary over a certain time
period. Finally, the EPA solicits comments on the cost of monitoring
idled or abandoned wells or monitoring techniques that might lower the
costs of such monitoring.
B. Pigging Operations and Related Blowdown Activities
The EPA is soliciting comment for potential NSPS and EG under
consideration that include addressing emissions from pipeline pigging
and related blowdown activities. Should the EPA receive information
through the public comment process that would help the Agency evaluate
BSER, the EPA may propose NSPS and EG through a supplemental proposal.
Raw natural gas is transported from production wells to natural gas
processing plants through networks of gathering pipelines. After
natural gas processing, pipeline networks in the transmission and
storage segment transport the gas to downstream customers. Raw natural
gas is frequently saturated with hydrocarbons and may contain other
components such as water, carbon dioxide, and hydrogen sulfide,
especially upstream of the natural gas processing plant. Liquid
condensates can accumulate in low elevation segments of the gathering
pipelines, impeding the flow of natural gas. To maintain gas flow and
operational integrity of the gathering pipelines, operators
mechanically push these condensates out of the low elevations and down
the pipeline by an operation called ``pigging,'' which involves first
inserting a device called a pig \310\ into a pig launcher upstream of
the pipeline segment where condensates have accumulated. The natural
gas flowing through the pipeline then pushes the pig through the
pipeline, allowing the pig to sweep along the accumulated condensates.
The pig is removed from the pipeline segment when it is caught in a pig
receiver. Pigging operations are also conducted using ``smart'' pigs
that are equipped with sensors to collect data about the pipeline's
structural characteristics and integrity for safety and maintenance
purposes.
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\310\ Pigs are typically spherical, barrel- or bullet-shaped
objects slightly smaller than the diameter of the pipeline.
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Before a pig can be inserted or removed through the hatch of a pig
launcher or a pig receiver, the pipeline gas in the launcher or
receiver barrel must be removed. It is common practice to vent the gas
directly to the atmosphere where gas capture or control are not used.
This gas is under the same pressure as the pipeline and contains
methane, ethane, and VOCs including HAP such as benzene, toluene,
ethylbenzene, and xylene. Emissions can also result from the
volatilization of collected condensate liquid when the pig barrel is
depressurized.
Pig launchers and receivers can be installed within larger
facilities, such as at a compressor station or natural gas processing
plant, or can be ``stand-alone'' sites, where the only equipment at a
particular location is related to pigging operations. Additionally,
sections of pipeline or equipment that are separate from the pig
launcher or receiver may need to be evacuated of gas for reasons other
than pigging, such as routine maintenance or inspection activities.
Emissions from blowdowns can be calculated by accounting for the volume
of the section of pipeline or equipment being evacuated, composition of
that gas being vented, pressure of the gas vented, frequency of the
blowdown activity, and inclusion of emissions from any volatile liquids
present in the pipeline section or equipment being vented.
The EPA is aware of some State and local governments have
regulations in place that address blowdown activities, including
pigging. These include limits on the amount of emissions from pigging
operations, required use of add-on controls, and implementation of best
management practices.\311\ Estimating emissions from pigging operations
is fairly straightforward if all variables (e.g., volume, pressure, and
composition of gas) are known. However, the wide range of variables,
which are applied in different combinations and are dependent on the
frequency of blowdown events, can make it challenging to estimate total
nationwide emissions from pigging and related blowdown activities. For
example, in 2019, six of the eight operators reporting to GHGRP subpart
W in the Uinta Basin reported a collective 7,299 blowdown events due to
pigging that met the threshold for reporting under GHGRP subpart W, but
the attribution of emissions from each individual pigging event is
undetermined at this time.\312\ Data reported in 2019 under GHGRP
subpart W include 472,995 total individual blowdown events from 1,212
facilities for a combined 307,630 metric tons of methane emitted,
including 79,746 events at pig launchers or receivers for a combined
total of 19,066 metric tons of methane, however, these data only
include emissions from blowdown equipment with a unique physical volume
greater than 50 cubic feet and occurring at a facility with total
emissions greater than 25,000 metric
[[Page 63243]]
tons CO2 Eq.\313\ The EPA is also aware of a single operator
in the Marcellus Shale region that operates around 400 pig launchers
and receivers which collectively emit approximately 1,335 metric tons
of methane annually, but the total annual emissions from each launcher
or receiver varies widely, due to variations in the inputs used to
calculate emissions from an individual pigging event.\314\ The EPA is
seeking comment on the availability of nationwide data sets or
methodologies to better identify the total inventory of pig launchers
and receivers, and, if no such data set or proxy exists, comment on the
most defensible method of calculating total emissions from pigging and
related blowdown activities.
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\311\ See TSD located at Docket ID No. EPA-HQ-OAR-2021-0317.
\312\ EPA (2020) Greenhouse Gas Reporting Program. U.S.
Environmental Protection Agency. Data reported as of September 26,
2020.
\313\ Id.
\314\ See Appendix A to the TSD located at Docket ID No. EPA-HQ-
OAR-2021-0317.
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The EPA has identified the following potential control options that
can reduce emissions from pipeline pig launchers and receivers: (1)
Reducing the frequency that the pig launcher or receiver must be
evacuated of gas; (2) eliminating or reducing the volume of gas vented
during blowdowns; (3) using add-on controls that are applied to
blowdown emissions; or (4) a combination of these strategies. The EPA
has identified the following systems as potential control strategies to
evaluate further.
First, pig ball valves are a design alternative to conventional pig
launcher and receiver systems that have a smaller sized barrel (or
chamber) that launches and receives the pig, thus resulting in reduced
emissions from pigging operations. A conventional pig launcher or
receiver system can be retrofitted by replacing the conventional
launcher and receiver barrels with special ball valves used to insert
and remove the pig directly from the main pipeline. By replacing the
large volume barrel with the much smaller volume ball valve, the volume
of gas vented during each pigging operation can be reduced by as much
as 80 to 95 percent, with a corresponding reduction in emissions and
other risks associated with pipeline pigging operations. The net cost
of a pig ball valve compared to a traditional launcher/receiver should
consider not only the cost of the valve and its installation, but also
the savings realized from the prevention of large quantities of vented
gas and personnel time spent blowing down a larger launcher/receiver.
These costs and savings will vary according to site-specific
dimensions, gas composition, and pigging frequency. The EPA understands
that not every dimension of pipeline and pig launcher or receiver can
use a pig ball valve and seeks further comment on specific
circumstances where such equipment is appropriate, potential challenges
to using a pig ball valve or retrofitting a launcher or receiver to
accommodate a pig ball valve, and specific costs of installing or
retrofitting a launcher or receiver compared to a conventional full-
barrel launcher or receiver.
Second, multi-pig launcher systems are a design alternative to
conventional launcher/receiver systems and reduce pigging emissions by
reducing the frequency that launchers and receivers must be opened to
the atmosphere and vented prior to pig insertion and removal. The
launcher barrel is designed to hold multiple spherical pigs, which are
each held in place by gates or pins prior to release. Emission
reductions are approximately proportional to the reduction in frequency
of opening the launcher and receiver hatch. For example, if a pig
launcher holds six pigs, which are loaded all at once, the frequency of
venting of the pig barrel is reduced to one-sixth of what it would have
been if each pig were loaded individually. The EPA understands that
multi-pig launchers and receivers are most appropriate for large
diameter pipelines where the footprint of the launcher or receiver site
is large enough to accommodate such a system. The EPA seeks comment on
specific circumstances where such equipment is appropriate, and
requests information on emission reductions and specific costs and
savings of installing or retrofitting and operating a multi-pig
launcher or receiver compared to a conventional single-pig launcher or
receiver.
Next, there are several liquids management technologies that focus
on reducing emissions from the liquid condensate that is collected
during pigging operations. The first technology relates to the design
of condensate drains on receiver barrels. Drains can be installed in
the bottom of receiver barrels and pig ball valves to ensure that all
condensate is drained from the system prior to depressurization. These
drains generally route the condensate back into the main pipelines, to
onsite storage tanks, or to onsite processes via enclosed piping and
can be retrofitted to existing systems. Recovering condensate prevents
emissions that would occur when the liquids volatilize during
depressurization of the pig receiver. The EPA seeks comment on
different configurations of condensate drains, how the recovered
condensate is routed and managed, limitations on using this technology,
and data showing the amount of condensate recovered and associated
emissions prevented.
The second liquids management technology is a pig ramp on a
receiver barrel. A pig ramp \315\ is a simple device that can be
installed inside a receiver barrel to allow liquids trapped in front of
the pig to be captured and to allow liquids clinging to the pig itself
to drain before the pig is pulled from the chamber. Pig ramps are
typically used in conjunction with condensate drains. The pig ramp
promotes the flow of liquid through the barrel and into the drain line
by elevating the pig on a rack-like apparatus within the receiver
barrel, thereby preventing the pig from creating blockages in the
receiver. By promoting the flow of liquid to a location within the
receiver or pipeline where the liquids can be captured and drained
prior to depressurization, pig ramps reduce the amount of condensed
VOCs that would otherwise volatilize during depressurization and
removal of the pig from the receiver, thereby reducing emissions. The
EPA seeks comment on the successful installation and use of pig ramps
as well as information on cost, emission reductions, and concerns or
challenges that may make the use of pig ramps inappropriate.
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\315\ https://www.mplx.com/content/documents/mplx/markwest/Launcher%20Receiver%20Design%20Detail.pdf.
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The third liquids management technology involves enhanced liquids
containment. If recovered condensate cannot be routed back to the
pipeline or to controlled storage vessels, covering containers that
collect liquids remaining in a receiver barrel after depressurization
with a fitted impermeable material will reduce emissions from
evaporation. However, whether or not this strategy will ultimately
reduce emissions depends on how the recovered condensate is actually
managed. The EPA seeks comment on how recovered condensate can be
managed to ensure that emissions from the volatilization of the liquids
is minimized, thereby achieving emissions reductions.
Lastly, the EPA has identified several additional control options
that can be employed to reduce emissions. First, an owner or operator
could install ``jumper lines'' that allow routing high pressure systems
to lower pressure systems. The depressurization emissions from high
pressure launchers and receivers can be reduced by routing the high-
pressure gases to a lower pressure system before venting the remaining
gases to the atmosphere or to control equipment.
[[Page 63244]]
Routing to a lower pressure system is achieved with a depressurization
line (or jumper line) exiting the top of the barrel, or exiting the top
of the pig ball valve, and connecting to nearby low-pressure lines on
site. Compressor stations and gas plants have low pressure lines on the
site that typically can receive these depressurized gases and recycle
them through the process. Similarly, launchers and receivers along high
pressure pipelines are occasionally located near low pressure pipelines
that can receive depressurized gases exiting the barrel or pig ball
valve. The EPA seeks comment on the universe of sites where jumper
lines are feasible to install, as well as information on cost, emission
reductions, and comment on implementation successes and challenges.
Second, owners and operators can route low-pressure systems into a
fuel gas system or VRU. Gases that remain in high pressure barrels
after venting to low pressure systems, and gases in low pressure
barrels, can be recovered during depressurization by discharging the
gases to very low-pressure systems at the site (e.g., 10-15 psig). Two
examples of very low-pressure systems at compressor stations are a fuel
gas system and a condensate tank VRU. Applying such an approach can
reduce the gas pressure in the barrels to the pressure of the very low-
pressure system, with a corresponding reduction in depressurization
emissions. The feasibility of this option is contingent upon the
presence of such equipment already onsite. The EPA seeks comment on the
universe of sites where routing gas to low-pressure systems is
feasible, as well as information on cost, emission reductions, and
comment on implementation successes and challenges.
Third, owners and operators can utilize barrel pump-down systems.
In barrel pump-down systems, small fixed or portable compressors are
used to pump vapors in the receiver or a launcher barrel back into the
main pipeline prior to venting and opening the barrel hatch. In barrel
pump-down systems, the inlet of a gas compressor is connected to the
receiver or launcher depressurization line, and the compressor
discharge is connected into the main pipeline. Vapors exiting the
depressurization line are pulled into the compression system and
recovered back into the pipeline at system pressure. These control
systems can recover greater than 99 percent of the depressurization
vapors from pig launchers and receivers. The EPA seeks comment on the
universe of sites where barrel pump-down systems are feasible, as well
as information on cost, emission reductions, and comment on
implementation successes and challenges.
Finally, owners and operators could route depressurization gases to
combustion devices to control emissions from pigging operations.
Depressurization gases from barrels and pig ball valves can be routed
through the depressurization line to onsite combustion devices. Well-
designed and operated combustion devices can achieve vapor destruction
efficiencies as high as 95 to 98 percent. Combustion devices can be
used in conjunction with engineering solutions discussed above that
first reduce accumulation of or recover as much natural gas and
condensate as possible, before destroying the remaining vapors in the
combustion device. An example would be to route high pressure systems
to low pressure lines and drain barrel condensate, then route the
remaining vapors to a combustion device. The EPA understands that
large, high-capacity combustion devices are typically available at
compressor stations and processing plants and can be used to control
pigging gases while meeting the other flaring needs of the facility.
There are also numerous low-capacity combustion devices available for
serving remote launcher/receiver sites. The EPA seeks comment on the
universe of sites where routing depressurization gases from pigging
operations to a combustion device is feasible, as well as information
on cost, emission reductions, and comment on implementation successes
and challenges.
In addition to those methods already identified above for reducing
emissions from pigging and related blowdown activities, the EPA is
seeking comment on other existing technologies and work practices to
reduce the need for blowdown events or reduce emissions from blowdown
events when they occur. The EPA is specifically interested in the costs
of such technologies or work practices and any variables impacting
cost, the control efficiency of the technology or work practice and
variables affecting efficiency, and any technological or logistical
limitations to implementing the technology or work practice.
While blowdown emissions due to pigging are the primary area where
the EPA seeks comment, the EPA is aware that planned blowdowns occur
for many reasons, typically related to maintenance or inspection
activities. Planned blowdowns may occur at facilities such as a gas
processing plant, compressor station, well pad, or stand-alone pig
launcher and receiver station, but may also occur at locations other
than these facilities, including along pipelines. Under GHGRP subpart
W, blowdown vent stack equipment or event types are grouped into the
following seven categories: Facility piping (i.e., piping within the
facility boundary), pipeline venting (i.e., physical volumes associated
with pipelines vented within the facility boundary), compressors,
scrubbers/strainers, pig launchers and receivers, emergency shutdowns
(this category includes emergency shutdown blowdown emissions
regardless of equipment type), and all other equipment with a physical
volume greater than or equal to 50 cubic feet.\316\ The EPA seeks
comment on any substantive differences between pigging blowdowns and
other types of planned blowdowns. Further, the EPA is soliciting
comment on how to define an affected facility that includes these
blowdown activities, and specific limitations (e.g., technical or
logistical) to including non-pigging-related types of blowdowns as part
of affected facilities. In particular, the EPA is considering whether
the pipeline itself could be defined as an affected facility for
purposes of regulating blowdowns. In this scenario, the owner or
operator of the pipeline would be responsible for complying with any
requirements in place for blowdown activities that occur anywhere along
the pipeline. The EPA is soliciting comment on any potential concerns
this type of approach would raise for owners and operators,
particularly where pipelines cross State boundaries or at the location
where pipeline ownership may change from the upstream owner to a
different downstream owner.
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\316\ 40 CFR 98.233(i)(2).
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C. Tank Truck Loading
The EPA is considering including emission standards and EG for tank
truck loading operations; however, additional information is needed to
evaluate BSER and propose NSPS or EG for this emissions source. The EPA
is therefore soliciting comment on adding tank truck loading operations
as an affected facility in both the NSPS and EG. Depending on the
information received through the public comment process, the EPA may
propose NSPS and EG for this source through a supplemental proposal. In
this section we summarize the available information we have reviewed
for this emissions source and potential control options.
Tank truck loading operations result in emissions when organic
vapors in empty tank trucks are displaced to the
[[Page 63245]]
atmosphere as crude oil, condensate, intermediate hydrocarbon liquids,
or produced water from storage vessels is loaded into the tank
trucks.\317\ Tank truck loading emissions are the primary source of
evaporative emissions from tank trucks. It is the EPA's understanding
that these vapors are a composite of vapors formed in the empty tank
truck by evaporation of residual materials from previous loads, vapors
transferred to the tank truck in vapor balance systems as materials are
being unloaded, and vapors generated in the tank truck as new material
is being loaded. Further, the quantity of evaporative losses from
loading operations is, therefore, a function of the parameters such as
the physical and chemical characteristics of the crude oil, condensate,
intermediate hydrocarbon liquids, or produced water; the method of
unloading the crude oil, condensate, intermediate hydrocarbon liquids,
or produced water from the storage vessel into the tank truck; and the
operations to transport the empty tank truck off-site. The composition
of evaporative losses includes VOC, methane, and some HAP.
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\317\ Section 5.2.2.1.1 of the AP-42 Section 5.2: Transportation
and Marketing of Petroleum Liquids https://www.epa.gov/sites/default/files/2020-09/documents/5.2_transportation_and_marketing_of_petroleum_liquids.pdf.
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According to the 2017 NEI, VOC emissions from tank truck loading
operations were approximately 72,448 tpy, of which over 70,990 tpy were
emitted in the crude oil and natural gas production segment, with the
balance of approximately 1,457 tpy emitted from the natural gas
processing segment. According to the Oklahoma loading losses guidance,
\318\ a loading loss vapor VOC content of 85 percent by weight (i.e.,
15 percent by weight methane and ethane) may be assumed at wellhead
facilities. Condensate and crude oil being loaded at a facility other
than a wellhead facility may assume a vapor VOC content of 100 percent.
Applying these compositions to the emissions in the 2017 NEI results in
approximately 12,528 tpy methane at well sites and 1,457 tpy methane
from other segments.
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\318\ See https://www.deq.ok.gov/wp-content/uploads/deqmainresources/LoadingLossesGuidance_08-2019.pdf.
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According to EIA, the contiguous continental states area comprising
of 48 States have a six year daily average condensate production (API
gravity greater than or equal to 50) \319\ of 911,000 bbls/day.\320\
Emissions per barrel of liquids loaded into tank trucks may be
estimated at 0.43lb VOC/bbl. It is the EPA's understanding that most
sites use tank trucks with a capacity of approximately 130 bbl. The EPA
solicits comment on whether API gravity greater than or equal to 50 is
the appropriate gravity of condensate to use.
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\319\ See https://glossary.oilfield.slb.com/en/terms/c/condensate.
\320\ See http://www.eia.gov/dnav/pet/pet_crd_api_adc_mbblpd_m.htm and TSD located at Docket ID No. EPA-
OAR-HQ-2021-0317.
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The EPA understands that there are three options generally in use
for controlling emissions during the tank truck loading process. The
first control option is vapor balancing which is used to route the
vapors displaced during material loading from the tank truck back to
the storage vessel. Vapor balancing requires a vapor capture line to
connect the tank truck to the storage vessel or manifold system of a
tank battery. Because vapor balancing is a closed system, the only
anticipated emissions from this control option would be fugitive in
nature. However, emissions may occur from the tank truck if it is not
properly maintained to DOT specifications, or when the tank truck is
cleaned or reloaded without control off-site. Vapor balancing does not
have any secondary air impacts or energy requirements. We estimate the
capital cost associated with a vapor balancing loading arm (equipment
associated with a capture line to connect the tank truck to the storage
vessel) at about $5000 per arm based on limited available information.
The second control option is use of a closed vent system operating
with a reduction efficiency of 95 to 99 percent. A vapor capture system
is used and routed to a vapor recovery device (VRD) or VRU which uses
refrigeration, absorption, adsorption, and/or compression. The
recovered liquid product is piped back to storage. Alternatively, the
vapors may be collected via a vapor capture system and routed to an on-
site thermal oxidizer or flare. It is possible to route emissions from
this closed vent system to an existing control device located on-site
for another purpose. The EPA recognizes that this option may have
secondary impacts dependent on the type of control chosen (e.g., VRU,
VRD, or combustion device).
Finally, the third option is to directly pipe liquids downstream.
By directly piping liquids downstream, no emissions from tank truck
loading are released to the atmosphere. We are not aware of any
secondary impacts or energy costs associated with this option. However,
the EPA is also unsure if this option is technically feasible for every
site. It is our understanding that this option requires access to
pipelines that can transport the crude oil and/or condensate to
downstream locations, and availability of pipelines or capacity to move
these liquids in existing pipelines may present an issue with requiring
this option for all sites.
In addition to these three control options, the EPA has also
identified work practices related to the method of loading which are
important and play a role in minimizing air emissions. Practices such
as submerged fill and bottom loading help reduce emissions when the
fill pipe opening is below the liquid surface level which reduces
liquid turbulence and results in much lower vapor generation than
encountered during splash (top) loading. We estimate the capital costs
of submerged fill loading arms are approximately $1,500 per arm based
on limited available data at this time.
The EPA is soliciting comment on the three control options and work
practices presented in this section to control or reduce emissions
resulting from the tank truck loading process. We solicit comment on
other control options or other work practice standards similar to those
used in other sectors such as petroleum refineries and how appropriate
those options may be for the Crude Oil and Natural Gas source category.
We solicit comment on how widely used the control measure and work
practices are, any feasibility challenges, and estimates of baseline
emissions and cost information associated with these control options
and work practices. The EPA is aware of several State regulations that
have established standards for this emissions source.\321\ Finally, the
EPA solicits comment on any practices owners and operators already
implement as part of voluntary efforts or State requirements to
minimize emissions from these sources.
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\321\ See TSD located at Docket ID No. EPA-OAR-HQ-2021-0317.
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D. Control Device Efficiency and Operation
As discussed above in sections XI.B, F, and G and XII.B, F, and G,
the EPA is proposing to retain the 95 percent reduction performance
standard for storage vessels, wet seal centrifugal compressors, and
pneumatic pumps based on our analysis showing that a combustion control
device remains the BSER for these affected facilities and can reliably
achieve this performance standard. This 95 percent reduction is
generally achieved by capturing the emissions in a closed vent system
that routes those emission to either a control device or back to the
process. Under the 2016 NSPS OOOOa, as amended by the 2020 Technical
Rule with further
[[Page 63246]]
amendments proposed in this action, closed vent systems must be
designed and operated with no detectable emissions, which is defined as
either no emissions detected greater than 500 ppm above background with
EPA Method 21, no emissions detected with OGI, or no audible, visual,
or olfactory emissions detected. Thus, for a closed vent system, the
assumed control efficiency is 100 percent. Therefore, any control
device used must be designed and operated to achieve at least 95
percent reduction of emissions to comply with the standard. Examples of
control devices include flares, thermal oxidizers, catalytic oxidizers,
enclosed combustion devices, carbon adsorption systems, condensers, and
VRUs. However, there are various data sources available that suggest
combustion control devices, which we have again identified as the BSER
for these affected facilities, can achieve a continuous destruction
efficiency of 98 percent.\322\
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\322\ Oil and Natural Gas Sector: Standards of Performance for
Crude Oil and Natural Gas Production, Transmission, and
Distribution. Background Supplemental Technical Support Document for
the Final New Source Performance Standards; EPA-HQ-OAR-2010-0505-
7631, pp. 19-20.
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Therefore, the EPA is soliciting comment on potentially proposing a
change in the standards for wet seal centrifugal compressors, storage
vessels, and pneumatic pumps that would require 98 percent reduction of
methane and VOC emissions from these affected facilities. It is the
EPA's understanding that combustion control devices, such as flares and
enclosed combustion devices, may achieve at least 98 percent control of
all organic compounds. Further, as noted in AP-42 Chapter 13.5,
properly operated flares achieve at least 98 percent destruction
efficiency in the flare plume in normal operating conditions.\323\
However, the EPA has received some data \324\ relevant to the use of
these controls at oil and gas facilities that indicates air-assisted
and steam-assisted flares have been found operating outside of the
conditions necessary to achieve at least 98 percent control efficiency
on a continuous basis. Therefore, the EPA is soliciting comment and
information that would help us better understand the cost, feasibility,
and emission reduction benefits associated with establishing a 98
percent control efficiency requirement for flares in the Crude Oil and
Natural Gas source category, including information on the level of
performance being achieved in practice by flares in the field, what
conditions or factors contribute to malfunctions or poor performance at
these flares, and what measures the EPA could or should require in
order to ensure that flares perform at a 98 percent level of control.
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\323\ https://www.epa.gov/sites/default/files/2020-10/documents/13.5_industrial_flares.pdf.
\324\ ``Intermittency of Large Methane Emitters in the Permian
Basin'' Daniel H. Cusworth, et al. Environmental Science &
Technology Letters 2021 8 (7), 567-573 DOI: 10.1021/
acs.estlett.1c00173; and Irakulis-Loitxate, I., Guanter, L., Liu,
Y.N., Varon, D.J., Maasakkers, J.D., Zhang, Y., Lyon, D., . . . &
Jacob, D. J. (2021). Satellite-based characterization of methane
point sources in the Permian Basin (No. EGU21-15877). Copernicus
Meetings.
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The EPA also requests comment on whether additional measures to
ensure proper performance of flares would be appropriate to ensure that
flares meet the current 95 percent control requirement. For example,
the EPA is soliciting comment on the specific requirements that could
be used to demonstrate continuous compliance when using a combustion
control device. In its July 8, 2021, report, the Office of Inspector
General (OIG) \325\ observed that State permitting authorities had
difficulty verifying continuous compliance with combustion efficiency
requirements for flares and enclosed combustors. The OIG recommended
that the EPA explore additional means to verify continuous compliance
in NSPS OOOO and NSPS OOOOa that would provide additional tools for
State agencies to properly permit and enforce combustion efficiency. In
considering this recommendation, the EPA has determined that additional
information is necessary to support the development of cost-effective
continuous compliance requirements.
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\325\ EPA Office of Inspector General Report ``EPA Should
Conduct More Oversight of Synthetic-Minor-Source Permitting to
Assure Permits Adhere to EPA Guidance,'' Report No. 21-P-0175 July
8, 2021.
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The current standards in NSPS OOOO and NSPS OOOOa require owners
and operators to perform an initial demonstration of compliance for all
control devices used to meet the standards in the rule. Further, NSPS
OOOO and NSPS OOOOa require monthly EPA Method 22 observations to
demonstrate continuous compliance with visible emission requirements,
in addition to monitoring for the presence of a pilot light. When an
enclosed combustion device is used, owners and operators may
demonstrate initial compliance through field testing or through
manufacturer testing. The EPA maintains a list of devices for which
manufacturers have demonstrated compliance with the testing
requirements, including achieving a destruction efficiency of at least
95 percent. The devices that have demonstrated compliance through
manufacturer testing have achieved greater than 98 percent destruction
efficiency; however, this is demonstrated in a testing environment
only, and while the testing is designed to challenge the units, the
units may not necessarily demonstrate the same destruction efficiency
in field applications. The EPA is seeking comment on alternative means
to demonstrate continuous compliance with the required control
efficiency (whether maintained at 95 percent or increased to 98
percent).
The Petroleum Refinery Sector Standards, 40 CFR part 63, subpart
CC, were amended in 2015 (80 FR 75178) to include a series of
additional monitoring requirements that ensure flares achieve the
required 98 percent control of organic compounds. Previously these
flares had been subject to the flare requirements at 40 CFR 60.18 in
the part 60 General Provisions. More recently, the updated flare
requirements in NESHAP subpart CC have been applied to other source
categories in the petrochemical industry, such as ethylene production
facilities (40 CFR part 63, subpart YY), to ensure that flares in that
source category also achieve the required 98 percent control of organic
compounds. These monitoring requirements include continuous monitoring
of waste gas flow, composition and/or net heating value of the vent
gases being combusted in the flare, assist gas flow, and supplemental
gas flow. The data from these monitored parameters are used to ensure
the net heat value in the combustion zone is sufficient to achieve good
combustion. The monitoring also includes prescriptive requirements for
monitoring pilot flames, visible emissions, and maximum permitted
velocity. Lastly, where fairly uniform, consistent waste gas
compositions are sent to a flare, owners or operators can simplify the
monitoring by taking grab samples in lieu of continuously monitoring
waste gas composition, and in some instances, engineering calculations
can be used to determine flow measurements.
While effective, the EPA seeks comment on how appropriate any such
monitoring requirements and systems would be for the oil and gas
production, gathering and boosting, gas processing, or transmission and
storage segments subject to the proposed NSPS OOOOb and EG OOOOc. The
EPA seeks comment on how to distinguish among flare units where such
monitoring is practical, and alternatives where such systems are not
practical because they
[[Page 63247]]
lack continuous, on-site personnel or do not have the supporting
infrastructure.
Additionally, the EPA seeks comment on several facets of ongoing
compliance, including: (1) Owner or operator experience in determining
the proper location of a thermocouple for monitoring the presence of a
pilot flame, and how to avoid pilot flame failure; (2) how OGI may be
used to identify poor combustion efficiency (e.g., to effectively
utilize OGI to qualitatively screen enclosed combustion devices) for
additional quantitative testing. As noted in Section XI.A.1 of this
preamble, we are proposing that emissions resulting from control
devices operating in a manner that is not in full compliance with any
Federal rule, State rule, or permit, are also considered fugitive
emissions. However, there may be other ways to use OGI beyond seeing
these fugitive emissions to determine whether control devices are
operating properly. For instance, the EPA is interested in how OGI has
been used to evaluate heat signature of gases exiting the top of the
stack and/or the presence of any unburned hydrocarbon trailing or
advective plumes.
With respect to enclosed combustors, the EPA is seeking information
on the development of comprehensive specifications for creating an
operating envelope under which a make/model can achieve 98 percent
reduction (i.e., parameters that should be identified on enclosed
combustion device specification sheets), such as maximum heat load,
minimum heat load, minimum inlet pressure of waste gas stream,
temperature of combustion zone (and proper location for temperature
monitor), air intake rate, operation and maintenance necessary for
optimal combustion. The EPA also seeks information on real-time
monitoring of enclosed combustion device inlet waste gas stream
pressure aimed at achieving higher combustion efficiency.
The EPA is also soliciting comment on the current use of non-
combustion control devices, the practicality of requiring 98 percent
reduction through the use of non-combustion control devices, and the
monitoring requirements necessary to demonstrate initial and continuous
compliance with such control efficiency. NSPS OOOO and NSPS OOOOa
require parametric monitoring for condensers, carbon adsorption
systems, and similar control devices, to demonstrate continuous
compliance. However, the EPA is seeking comment on whether those
monitoring requirements are sufficient to assure continuous compliance
should the EPA propose a requirement of 98 percent reduction. In
addition to monitoring requirements, the EPA is seeking information on
what additional records should be maintained and/or reported for
demonstrating continuous compliance when non-combustion control devices
are used. The EPA is particularly concerned that increasing the level
of control from 95 to 98 percent would disincentivize use or
potentially force replacement of non-combustion control devices
entirely, including those that capture product for reuse in vapor
recovery systems. For example, Texas requires additional monitoring and
other significant engineering upgrades for a VRU operator to meet a
higher control efficiency than 95 percent.\326\ Adding to this concern
is the potential increase in overall costs of the rule and potential
increase in emissions where facilities replace non-combustion control
devices with combustion control devices.
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\326\ See Vapor Recovery Unit Capture/Control Guidance located
at https://www.tceq.texas.gov/assets/public/permitting/air/NewSourceReview/oilgas/vapor-rec-unit.pdf.
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Finally, the EPA is seeking comment on new technologies that would
address control efficiency from flares specifically and provide real-
time or near real-time measurement of control efficiency. One example
would be OGI continuous flame imaging systems that capture flame size
and temperature to ensure these parameters are within acceptable
ranges. New optical technology is in the early phases of development
and deployment. The EPA acknowledges that it may be challenging to
analyze costs and reductions without comprehensive data specific to a
particular technology, but in the interest of a forward-looking
standard, we seek information on potential methods to assure continuous
compliance for these control devices.
E. Definition of Hydraulic Fracturing
During pre-proposal outreach, a number of small businesses stated
that the NSPS has unintentionally been applied to conventional and
vertical wells that engage in hydraulic fracturing. The small business
stakeholders contended that these wells have a very different profile
from unconventional or horizontal wells in terms of footprint, water
usage, chemical usage, equipment used, and flowback period. They
recommended that the EPA explicitly exempt these wells from the
proposal. We maintain that the original intent of the NSPS was to
regulate hydraulically fractured wells, in both conventional and
unconventional reservoirs,\327\ and both vertical and horizontal
wells.\328\
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\327\ See Docket ID Item Nos. EPA-HQ-OAR-2010-0505-0445, Chapter
4, p. 4-2 and EPA-HQ-OAR-2010-0505-4546, p. 30.
\328\ See Docket ID Item No. EPA-HQ-OAR-2010-0505-4546, p. 61.
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NSPS OOOOa defines hydraulic fracturing as ``the process of
directing pressurized fluids containing any combination of water,
proppant, and any added chemicals to penetrate tight formations, such
as shale or coal formations, that subsequently require high rate,
extended flowback to expel fracture fluids and solids during
completions.'' The NSPS does not offer numeric thresholds that define
``tight formations'' or ``high rate, extended flowback''. When
developing the original NSPS OOOO, EPA's analysis assumed hydraulic
fracturing is performed in tight sand, shale, and coalbed methane
formations which have an in situ permeability (flow rate capability) to
gas of less than 0.1 millidarcy.\329\ The EPA also assumed the flowback
lasted between 3 and 10 days for the average gas well,\330\ and 3 days
for the average oil well.\331\ However, in response to a public comment
on the 2015 NSPS OOOOa proposal claiming the definition of hydraulic
fracturing was too broad, the EPA clarified it intended to ``include
operations that would increase the flow of hydrocarbons to the
wellhead''.\332\ Similarly, in response to a public comment seeking an
exemption for wells that have a flowback period of less than 24 hours,
the EPA acknowledged that there is a range of flowback periods, finding
that the requested exemption was not warranted.\333\
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\329\ See Docket ID Item No. EPA-HQ-OAR-2010-0505-0445, Chapter
4, p. 4-2.
\330\ See Docket ID Item No. EPA-HQ-OAR-2010-0505-0445, Chapter
4, p. 4-1.
\331\ See Docket ID Item No. EPA-HQ-OAR-2010-0505-5021, p.20.
\332\ See Docket ID Item No. EPA-HQ-OAR-2010-0505-7632, Chapter
3, p. 3-113.
\333\ See Docket ID Item No. EPA-HQ-OAR-2010-0505-7632, Chapter
3, p. 3-64.
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We are soliciting comment on if numeric thresholds for ``tight
formations'' or ``high rate, extended flowback'' are appropriate to
include in the definition of hydraulic fracturing, and if so, what
those numeric thresholds should be. Alternatively, we solicit comment
on if it is appropriate to align the NSPS definition with the U.S.
Geologic Survey (USGS) definition of hydraulic fracturing (``the
process of injecting water, sand, and/or chemicals into a well to break
up underground bedrock to free up oil or gas
[[Page 63248]]
reserves''),\334\ which may more accurately capture the EPA's original
intent.
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\334\ USGS. Hydraulic Fracturing. https://www.usgs.gov/mission-areas/water-resources/science/hydraulic-fracturing?qt-science_center_objects=0#qt-science_center_objects. Accessed
September 1, 2021.
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XIV. State, Tribal, and Federal Plan Development for Existing Sources
Over the last forty years, under CAA section 111(d), the agency has
regulated four pollutants from five source categories (i.e., sulfuric
acid plants (acid mist), phosphate fertilizer plants (fluorides),
primary aluminum plants (fluorides), kraft pulp plants (total reduced
sulfur), and municipal solid waste landfills (landfill gases)).\335\ In
addition, the agency has regulated additional pollutants under CAA
section 111(d) in conjunction with CAA section 129.\336\ The Agency has
not previously addressed emissions of GHGs (in the form of limitations
of methane) from the Crude Oil and Natural Gas source category under
CAA section 111(d). However, the EPA has ample experience with this
source category from implementing the NSPS for so long, and has
examined existing sources in a variety of context including the 2013
Federal Implementation Plan (FIP) for oil and natural gas well
production facilities on the Fort Berthold Indian Reservation (78 FR
17836 (Mar. 22, 2013)), the 2016 Oil and Natural Gas Control Techniques
Guidelines (81 FR 74798 (Oct. 27, 2016)), and the 2020 proposed FIP for
managing emissions from oil and natural gas sources on Indian country
lands within the Uintah and Ouray Indian Reservation (85 FR 3492 (Jan.
21, 2020)). The draft EG contained in this proposal draw from, among
other sources of information and analysis, all of these experiences
combined with information on State laws that regulate existing sources.
In this action, the EPA is proposing EG for Sates to follow in
developing their plans to reduce emissions of GHGs (in the form of
limitations on methane) from designated facilities within the Crude Oil
and Natural Gas source category.
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\335\ See ``Phosphate Fertilizer Plants; Final Guideline
Document Availability,'' 42 FR 12022 (March 1, 1977); ``Standards of
Performance for New Stationary Sources; Emission Guideline for
Sulfuric Acid Mist,'' 42 FR 55796 (October 18, 1977); ``Kraft Pulp
Mills, Notice of Availability of Final Guideline Document,'' 44 FR
29828 (May 22, 1979); ``Primary Aluminum Plants; Availability of
Final Guideline Document,'' 45 FR 26294 (April 17, 1980); ``EG and
Compliance Times for Municipal Solid Waste Landfills,'' 81 FR 59276
(August 29, 2016). In addition, EPA regulated mercury from coal-
fired electric power plants in a 2005 rule that was vacated by the
D.C. Circuit, ``Standards of Performance for New and Existing
Stationary Sources: Electric Utility Steam Generating Units; Final
Rule,'' 70 FR 28606 (May 18, 2005) (Clean Air Mercury Rule), vacated
by New Jersey v. EPA, 517 F.3d 574 (D.C. Cir. 2008). EPA also
regulated GHG from fossil fuel-fired electric power plants in a 2015
rule that EPA subsequently repealed and replaced with a 2019 rule
that, in turn, was vacated by the D.C. Circuit. ``Carbon Pollution
EG for Existing Stationary Sources: Electric Utility Generating
Units; Final Rule,'' 80 FR 64662 (Oct. 23, 2015) (Clean Power Plan),
repealed and replaced by ``Repeal of the Clean Power Plan; EG for
Greenhouse Gas Emissions From Existing Electric Utility Generating
Units; Revisions to EG Implementing Regulations,'' 84 FR 32520 (July
8, 2019) (Affordable Clean Energy Rule), vacated by Am. Lung Assoc.
\336\ See, e.g., ``Standards of Performance for New Stationary
Sources and EG for Existing Sources: Sewage Sludge Incineration
Units, Final Rule,'' 76 FR 15372 (March 21, 2011).
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A. Overview
While section IV of this preamble provides a general overview of
the State planning process triggered by the EPA's finalization of EG
under CAA section 111(d), this section explains the EG process and
proposed State plan requirements in more detail, and also solicits
comment on various issues related to this EG. The EG process is
governed by CAA section 111(d) as well as the final EG and the EPA's
implementing regulations at 40 CFR part 60, subpart Ba.\337\ After the
EPA establishes the BSER in the final EG, as described in preamble
sections XI and XII, each State that includes a designated facility
must develop, adopt, and submit to the EPA its State plan under CAA
section 111(d). The EPA then must determine whether to approve or
disapprove the plan. If a State does not submit a plan, or if the EPA
does not approve a State's plan, then the EPA must establish a Federal
plan for the State.
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\337\ As previously noted, the D.C. Circuit has vacated certain
timing provisions within subpart Ba. Am. Lung Assoc. v. EPA.
However, the court did not vacate the applicability provision, and
therefore Subpart Ba applies to any EG that EPA finalizes from this
proposal.
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Each of these steps, and more, is discussed in detail in this
section which is organized into six parts. First, we discuss the
components of the EG. Second, we discuss establishing standards of
performance in State plans in response to a finalized EG. Third, we
discuss the components of an approvable State plan submission. Fourth,
we discuss the timing for State plan submissions and compliance times.
Fifth, we discuss the EPA's action on State plans and promulgation of a
Federal plan, if needed. Sixth, we discuss the CAA section 111(d)
process as it relates to Tribes. While this section describes the
requirements of the implementing regulations under 40 CFR part 60,
subpart Ba, proposes requirements for States in the context of this EG,
and solicits comments in the context of this EG, nothing in this
proposal is intended to reopen the implementing regulations themselves
for comment.
B. Components of EG
As previously described, CAA sections 111(d)(1) and 111(a)(1)
collectively establish and define certain roles and responsibilities
for the EPA and the States. The EPA addresses its responsibilities by
drafting and publishing EG in accordance with 40 CFR 60.22a, which
``[contain] information pertinent to control of the designated
pollutant from designated facilities.'' Mirroring language included in
CAA section 111(d)(1), the EPA's implementing regulations define a
designated pollutant as ``any air pollutant, the emissions of which are
subject to a standard of performance for new stationary sources, but
for which air quality criteria have not been issued and that is not
included on a list published under section 108(a) or section
112(b)(1)(A) of the Act.'' 40 CFR 60.21a(a). The EPA's implementing
regulations also define a designated facility as ``any existing
facility (see Sec. 60.2) which emits a designated pollutant and which
would be subject to a standard of performance for that pollutant if the
existing facility were an affected facility (see Sec. 60.2).'' Id. at
Sec. 60.21a(b). The designated pollutant for purposes of the draft EG
included in this proposal is GHGs, but the presumptive standards in the
EG are expressed in terms of limitations on methane. A description of
each of the designated facilities included in the draft EG can be found
above in preamble sections XI and XII.
More specifically, 40 CFR 60.22a(b) lists six components to be
included in EG to provide information for development of the State
plans triggered by the promulgation of the EG. First, EG must include
information regarding the ``endangerment of public health or welfare
caused, or contributed to, by the designated pollutant.'' 40 CFR
60.22a(b)(1). Information on the harmful public health and welfare
impacts of methane emissions from the oil and natural gas industry are
included above in section III of this document. Second, the EG must
include a ``description of systems of emission reduction which, in the
judgment of the Administrator, have been adequately demonstrated.'' 40
CFR 60.22a(b)(2). The EPA has included such a description above in
sections XI and XII of this preamble, and the NSPS OOOOb and EG TSD
located at Docket ID No. EPA-HQ-OAR-2021-0317.
[[Page 63249]]
Third, the EG must include information regarding ``the degree of
emission limitation'' achievable through application of each system,
along with information ``on the costs, non-air quality health
environmental effects, and energy requirements of applying each system
to designated facilities.'' 40 CFR 60.22a(b)(3). The EPA has included
such a description in sections XI and XII of this preamble, and the
NSPS OOOOb and EG TSD located at Docket ID No. EPA-HQ-OAR-2021-0317.
Fourth, the EG must include information regarding the amount of time
that the EPA believes would be normally necessary for designated
facilities to design, install, and startup the control systems
identified in component number three. See 40 CFR 60.22a(b)(4). The EPA
explains how it proposes to address this component below in section
XIV.E. Fifth, and likely most helpful to States when developing their
plans in response to the final EG, the EG must include information
regarding the ``degree of emission limitation achievable through the
application of the best system of emission reduction'' that has been
adequately demonstrated, taking into account the same factors as
described in component three (cost, non-air quality health and
environmental impact and energy requirements), ``and the time within
which compliance with standards of performance can be achieved.'' 40
CFR 60.22a(b)(5). The EPA has included such information in sections XI
and XII of this preamble and the NSPS OOOOb and EG TSD located at
Docket ID No. EPA-HQ-OAR-2021-0317 as well as in section XIV.E of this
preamble. In identifying the degree of achievable emission limitation,
the EPA may subcategorize, that is to ``specify different degrees of
emission limitation or compliance times or both for different sizes,
types, and classes of designated facilities when costs of control,
physical limitations, geographical location, or similar factors make
subcategorization appropriate.'' Id. The EPA can choose to exercise
that discretion to subcategorize within the draft EG for certain
emission points. Sixth, and last, the EG is to include any other
information not contemplated by the five other components that the EPA
``determines may contribute to the formulation of State plans.'' This
section includes such information and guidance specifically designed to
assist States in developing their plans under CAA 111(d) for these
draft EG.
C. Establishing Standards of Performance in State Plans
While the EPA has the authority and responsibility to determine the
BSER and the degree of limitation achievable through application of the
BSER, CAA section 111(d)(1) provides that States shall submit to the
EPA plans that establish standards of performance for designated
facilities (i.e., existing sources) and provide for implementation and
enforcement of such standards. In light of the statutory text, and as
reflected in the technical completeness criteria in the EPA's
implementing regulations (explained below), State plans implementing
the EG should include requirements and detailed information related to
two key aspects of implementation: establishing standards of
performance for designated facilities and providing measures that
implement and enforce such standards.
Establish Standards of Performance for Designated Facilities. As an
initial matter, a State must identify existing facilities within its
borders that meet the applicability requirements in the final EG and
are thereby considered a ``designated facility'' under the EG.\338\
Then, States are required to establish standards of performance for the
identified designated facilities. There is a fundamental requirement
under CAA section 111(d) that a State's standards of performance
reflect the degree of emission limitation achievable through the
application of the BSER, which derives from the definition of
``standard of performance'' in CAA section 111(a)(1). The statute
further requires the EPA to permit States, in applying a standard of
performance, to consider a source's remaining useful life and other
factors. Accordingly, based on both the mandatory and discretionary
aspects of CAA section 111(d), a certain level of process is required
of State plans: namely, the standards of performance must reflect the
degree of emission limitation achievable through application of the
BSER, and if the State chooses, the consideration of remaining useful
life and other factors in applying a standard of performance to a
designated facility.
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\338\ In accordance with 40 CFR 60.23a(b), states without any
designated facilities are directed to submit to the Administrator a
letter of negative declaration certifying that there are no
designated facilities, as defined by EPA's emissions guidelines,
located within the state. No plan is required for states that do not
have any designated facilities.
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For this EG the EPA is proposing to translate the degree of
emission limitation achievable through application of the BSER (i.e.,
level of stringency) into presumptive standards of performance that
States may use in the development of State plans for specific emission
points. The EPA believes that the presumptive standards of performance
included in the EG will provide States with the level of stringency
that the EPA would require to approve a State plan. Put another way,
the EPA is choosing to format this EG such that if a State chooses to
adopt the presumptive standards as the standards of performance in
their State plan, then the EPA believes that such plan could be
approved as meeting the requirements of CAA section 111(d) and the
finalized EG, assuming the plan meets all other applicable
requirements. In this way, the presumptive standards included in the EG
serve a similar purpose as a model rule because they are intended to
assist States in developing their plan submissions by providing the
States with a starting point for their standards that are based on
general industry parameters and assumptions. The EPA believes that
providing these presumptive standards of performance will create a
streamlined approach for States in developing plans and for the EPA in
evaluating State plans. Of course, the EPA cannot pre-determine the
outcome of a future rulemaking process, and inclusion of these
presumptive standards in this EG does not impact the rulemaking process
associated with the EPA's review of, and action on, a State plan
submission. In its review of State plans, the EPA will consider the
information in the final EG (including what EPA publishes in the final
EG as the presumptive standards), as well as information submitted by
the State and the public. The EPA will evaluate the approvability of
all plans through individual notice-and-comment rulemaking processes.
As described in sections XI and XII, the EPA is proposing to
translate the degree of emission limitation achievable through
application of the BSER into presumptive standards for the following
designated facilities as shown in Table 20.
[[Page 63250]]
Table 20--Summary of Proposed EG Subpart OOOOc Presumptive Numerical
Standards
------------------------------------------------------------------------
Proposed presumptive mass-based
Designated facility standards in the draft emissions
guidelines for GHGs
------------------------------------------------------------------------
Storage Vessels: Tank Battery with 95 percent control.
PTE of 20 tpy or More of Methane.
Pneumatic Controllers: Natural Gas VOC and methane emission rate of
Driven that Vent to the zero.
Atmosphere.
Wet Seal Centrifugal Compressors.. 95 percent control.
Pneumatic Pumps: Natural Gas Zero natural gas emissions from
Processing Plants. diaphragm and piston pneumatic
pumps.
Pneumatic Pumps: Locations Other 95 percent control of diaphragm
Than Natural Gas Processing pneumatic pumps if there is an
Plants. existing control or process on
site. 95 percent control not
required if (1) routed to an
existing control that achieves less
than 95 percent or (2) it is
technically infeasible to route to
the existing control device or
process.
Associated Gas from Oil Wells..... Route associated gas to a sales
line. In the event that access to a
sales line is not available, the
gas can be used as an onsite fuel
source, used for another useful
purpose that a purchased fuel or
raw material would serve, or routed
to a flare or other control device
that achieves at least 95 percent
control.
------------------------------------------------------------------------
For these designated facilities, State plans would generally be
expected to establish standards of performance that reflect these
numerical presumptive standards, if included in the final EG. Further,
for these designated facilities, the EPA is proposing to require that
the standards of performance be expressed in the same form as the
numerical presumptive standards set forth in Table 20. For example, for
storage vessels that are part of a tank battery with a PTE of 20 tpy or
more of methane, the EPA is proposing a numerical presumptive standard
of 95-percent control. Accordingly, if finalized as proposed, States
would be required to submit a plan that includes numerical standards of
performance for these designated facilities expressed in the same form
as the presumptive standard of 95 percent control. As described in this
proposal and the associated supporting materials in the docket, the EPA
has extensively and rigorously performed technical analyses in order to
determine the appropriate proposed BSER for each set of designated
facilities. The form of the numerical expression of the degrees of
emission limitation achievable through application of the BSERs, and
the associated presumptive standards, are a result of these technical
analyses. The EPA believes that requiring States to maintain the same
form of numerical standard in their plans will preserve the integrity
of the BSERs and avoid analytic issues that are likely to arise if EPA
is required to determine whether a different form of numerical standard
submitted by a State has the same level of stringency as the final EG.
Accordingly, having a uniform form of standard of performance will help
streamline the States' development of their plans, as well as the EPA's
review of those plans, since there will be fewer variables to evaluate
in the development and review of each standard of performance. The EPA
solicits comment on its proposal to require State plans to include
numerical standards of performance for these designated facilities that
are in the same form as the numerical presumptive standards, and
whether EPA should additionally allow States to include a different
form of numerical standards for these facilities so long as States
demonstrate the equivalency of such standards to the level of
stringency required under the final EG.
For the following designated facilities, the EPA is proposing to
translate the degree of emission limitation achievable through
application of the BSER into the presumptive standards shown in Table
21.
Table 21--Summary of Proposed EG Subpart OOOOc Presumptive Non-Numerical
Standards
------------------------------------------------------------------------
Proposed presumptive non-numerical
Designated facility standards in the draft emissions
guidelines for GHGs
------------------------------------------------------------------------
Fugitive Emissions: Well Sites-->0 Perform fugitive emissions survey
to <3 tpy methane. and repair to demonstrate actual
site emissions are reflected in
calculation.
Fugitive Emissions: Well Sites-- Quarterly OGI monitoring following
>=3 tpy methane. appendix K. (Optional quarterly EPA
Method 21 monitoring with 500 ppm
defined as a leak).
First attempt at repair within 30
days of finding fugitive emissions.
Final repair within 30 days of
first attempt.
(Co-proposal) Fugitive Emissions: Semiannual OGI monitoring following
Well Sites-->=3 to <8 tpy methane. appendix K. (Optional semiannual
EPA Method 21 monitoring with 500
ppm defined as a leak).
First attempt at repair within 30
days of finding fugitive emissions.
Final repair within 30 days of
first attempt.
(Co-proposal) Fugitive Emissions: Quarterly OGI monitoring following
Well Sites-->=8 tpy methane. appendix K. (Optional quarterly EPA
Method 21 monitoring with 500 ppm
defined as a leak).
First attempt at repair within 30
days of finding fugitive emissions.
Final repair within 30 days of
first attempt.
Fugitive Emissions: Compressor Quarterly OGI monitoring following
Stations. appendix K. (Optional quarterly EPA
Method 21 monitoring with 500 ppm
defined as a leak).
First attempt at repair within 30
days of finding fugitive emissions.
Final repair within 30 days of
first attempt.
Fugitive Emissions: Well Sites and Annual OGI monitoring following
Compressor Stations on Alaska appendix K. (Optional annual EPA
North Slope. Method 21 monitoring with 500 ppm
defined as a leak).
First attempt at repair within 30
days of finding fugitive emissions.
Final repair within 30 days of
first attempt.
Fugitive Emissions: Well Sites and (Optional) Alternative bimonthly
Compressor Stations.. screening with advanced measurement
technology and annual OGI
monitoring following appendix K.
Pneumatic Controllers: Alaska (at Natural gas bleed rate no greater
sites where onsite power is not than 6 scfh.
available--continuous bleed
natural gas driven).
Pneumatic Controllers: Alaska (at Monitor and repair through fugitives
sites where onsite power is not program.
available--intermittent natural
gas driven).
Reciprocating Compressors......... Replace the reciprocating compressor
rod packing based on annual
monitoring (when measured leak rate
exceeds 2 scfm) or route emissions
to a process.
Equipment Leaks at Gas Plants..... Bimonthly OGI LDAR program (NSPS VVa
as optional alternative).
------------------------------------------------------------------------
[[Page 63251]]
The EPA's implementing regulations at 40 CFR 60.24a(b) require that
standards of performance shall either be based on allowable rate or
limit of emissions, except when the EPA identifies cases in an EG where
it would not be feasible to prescribe or enforce a rate or limit. Put
another way, 40 CFR 60.24a(b) permits the EPA to identify cases where
it is not feasible for States to prescribe or enforce a numerical
standard, and in those cases the EPA can include non-numerical
emissions limitations such as design, equipment, work practice, or
operational standards, or a combination thereof, in the EG. See also
definition of ``standard of performance'' in 40 CFR 60.21a(f). This
authority in the context of the EG is akin to the EPA's authority under
CAA section 111(h) to prescribe non-numerical standards where the
Administrator determines it is not feasible to prescribe or enforce a
numerical standard of performance. Where the EPA finalizes EG that
authorize design, equipment, work practice, or operational standard, or
a combination thereof, the State ``plan shall, to the degree possible,
set forth the emission reductions achievable by implementation of such
standards, and may permit compliance by the use of equipment determined
by the State to be equivalent to that prescribed'' by the State plan.
See 40 CFR 60.24a(b).
For the designated facilities listed in Table 21 the EPA has
determined that it is not feasible to prescribe or enforce a numerical
standard. As such, for these designated facilities, the EPA is
proposing presumptive standards that are comprised of design,
equipment, work practice, and/or operational standards. For these
designated facilities, States are generally expected to establish the
same non-numerical presumptive standards in Table 21. If States do not
incorporate the presumptive standards included in the final EG into
their State plan, but instead wish to utilize a different design,
equipment, work practice, and/or operational standard for any of the
designated facilities listed in Table 21, then the EPA is proposing to
require that the State include in its plan a demonstration of how that
standard will achieve a reduction in methane emissions at least
equivalent to the reduction in methane emissions achieved by
application of the presumptive standards included in the final EG. Such
a demonstration should take into account, among other factors, the
timelines for compliance. The EPA believes that this requirement is
consistent with the AMEL provision in CAA section 111(h)(3), which
requires a demonstration that any alternative ``will achieve a
reduction in emissions . . . at least equivalent to the reduction in
emissions'' achieved by EPA's standard, and the technical completeness
criteria found at 40 CFR 60.27a(g)(3)(iv), which requires that State
plans must include a ``demonstration that the State plan submittal is
projected to achieve emissions performance under the applicable EG.''
To the extent that a State determines the presumptive standards in
the final EG are not reasonable for a particular designated facility
due to remaining useful life and other factors, the statute requires
that the EPA's regulations under CAA section 111(d) permit States to
consider such factors in applying a standard of performance. As such,
the EPA's implementing regulations at 40 CFR 60.24a(e) allow States to
consider remaining useful life and other factors to apply a less
stringent standard of performance to a designated facility or class of
facilities if one or more demonstrations are made. These demonstrations
include unreasonable cost of control resulting from plant age,
location, or basic process design; physical impossibility of installing
necessary control equipment; or other factors specific to the facility
(or class of facilities) that make application of a less stringent
standard or final compliance time significantly more reasonable. The
implementing regulations also clarify that, absent such a
demonstration, the State's standards of performance must be ``no less
stringent than the corresponding'' EG. See 40 CFR 60.24a(c).
The EPA intends to provide further clarification on the general
process and requirements for accounting for remaining useful life and
other factors, including on the reasonableness aspect of the required
demonstration, via a rulemaking to amend the implementing regulations
in the near future. However, the EPA also recognizes that the oil and
natural gas industry is unique such that the general approach to
considering remaining useful life and other factors in the implementing
regulations may not be an ideal fit. For example, the sheer number and
variety of designated facilities in the oil and natural gas industry
could make a source-specific (or even a class-specific) evaluation of
remaining useful life and other factors extremely difficult and
burdensome for States that want to undertake a demonstration. In
addition, the presumptive standards for these designated facilities
generally entail fewer major capital expenses compared with other
industries for which EPA has previously issued EG under CAA section
111(d), and many of the proposed presumptive standards generally take
the form of design, equipment, work practice, or operational standards
rather than numerical emission limitations. Further, in proposing the
presumptive standards for existing sources, the EPA has deliberately
included certain flexibilities (e.g., in cases of technical
infeasibility) such that the EPA believes the presumptive standards
should be achievable and cost-effective for a wide variety of
facilities across the source category. Given these facts, the EPA
believes that it would likely be difficult for States to demonstrate
that the presumptive standards are not reasonable for the vast majority
of designated facilities. The EPA is soliciting comment on these
observations, and any other facts and circumstances that are unique to
the oil and natural gas industry that could impact the remaining-
useful-life-and-other-factors demonstration. The EPA is also soliciting
comment as to whether the Agency should include specific provisions
regarding the consideration of remaining useful life and other factors
in this EG that would supplement or supersede the general provisions in
the implementing regulations.
To the extent a State chooses to submit a plan that includes
standards of performance that are more stringent than the requirements
of the final EG, States have the authority to do so under CAA section
116, and the EPA has the authority to approve such plans and render
them Federally enforceable if all applicable requirements are met.
Union Electric Co. v. EPA, 427 U.S. 246, (1976). See also 40 CFR
60.24a(f). The EPA acknowledges that in the Affordable Clean Energy
(ACE) rule, it previously took the position that Union Electric does
not control the question of whether CAA section 111(d) State plans may
be more stringent than Federal requirements. The ACE rule took this
position on the basis that Union Electric on its face applies only to
CAA section 110, and that it is potentially salient that CAA section
111(d) is predicated on specific technologies whereas CAA section 110
gives States broad latitude in the measures used for attaining the
National Ambient Air Quality Standards (NAAQS). 84 FR 32559-61 (July 8,
2019). The EPA no longer takes this position. Upon further evaluation,
the EPA believes that because of the structural similarities between
CAA sections 110 and 111(d), CAA section 116 as interpreted by Union
Electric
[[Page 63252]]
requires the EPA to approve CAA section 111(d) State plans that are
more stringent than required by the EG if the plan is otherwise is
compliance with all applicable requirements. See FCC v. Fox Television
Stations, Inc., 556 U.S. 502 (2009). The D.C. Circuit in Union Electric
rejected a construction of CAA sections 110 and 116 that measures more
stringent than those required to attain the NAAQS cannot be approved
into a federally enforceable State Implementation Plan (SIP) but must
be adopted and enforced only as a matter of State law. Id. at 263-64.
While the BSER and the NAAQS are distinct from one another in that the
former is technology-based and the latter is based on ambient air
quality, both CAA sections 111(d) and 110 are structurally similar in
that States must adopt and submit to the EPA plans which include
requirements to meet the objectives of each respective section.
Requiring States to enact and enforce two sets of standards, one that
is a federally approved CAA section 111(d) plan and one that is a
stricter State plan, runs directly afoul of the court's holding that
there is no basis for interpreting CAA section 116 in such manner.
Therefore, the EPA interprets CAA sections 111(d) and 116 as allowing
States to include, and the EPA to approve, more stringent standards of
performance in State plans. The EPA notes that its authority is
constrained to approving measures which comport with applicable
statutory and regulatory requirements. For example, CAA section 111(d)
only contemplates that State plans include requirements for designated
facilities, therefore the EPA believes it does not have the authority
to approve and render federally enforceable measures on other entities.
The EPA is also aware that in the context of regulating the oil and
natural gas industry many States have existing programs they may want
to leverage for purposes of satisfying their CAA section 111(d) State
plan obligations. The EPA anticipates providing information on ways in
which State plans can accommodate existing State programs to the extent
such programs are at least as stringent as the requirement of the final
EG. Consistent with the proposed presumptive standards, the EPA
proposes that a State plan which relies on an existing State program
must still establish standards of performance that are in the same form
as the presumptive standards. The EPA solicits comment on whether
States relying on existing programs should be authorized to include a
different form of standard in their plans so long as they demonstrate
the equivalency of such standards to the level of stringency required
under the final EG, and how such equivalency demonstrations can be made
in a rigorous and consistent way. The EPA proposes to require that, in
situations where a State wishes to rely on State programs (statutes
and/or regulations) that pre-date finalization of the EG proposed in
this document to satisfy the requirements of CAA section 111(d), the
State plan should identify which aspects of the existing State programs
are being submitted for approval as federally enforceable requirements
under the plan, and include a detailed explanation and analysis of how
the relied upon existing State programs are at least as stringent as
the requirements of the final EG. The EPA notes that the completeness
criteria in 40 CFR 60.27a(g) requires a copy of the actual State law/
regulation or document submitted for approval and incorporation into
the State plan. Put another way, where a State is relying on an
existing State program for its plan, a copy of the pre-existing State
statute or regulation underpinning the program would be required by
this criterion, and would be a critical component of the EPA's
evaluation of the approvability of the plan. The EPA also solicits
comment on various ways in which existing State programs can be adopted
into State plans. Particularly, the EPA is interested in how existing
State programs that regulate both designated facilities and sources not
considered as designated facilities under this EG could be tailored for
a State plan to meet the requirements of CAA section 111(d).
Providing Measures that Implement and Enforce Such Standards. As
part of establishing standards of performance, State plans must also
include compliance schedules for those standards. See 40 CFR 60.24a(a).
Section XIV.E, explains how the EPA is proposing to approach compliance
schedules. The EPA's implementing regulations require that, except
where the State chooses to account for remaining useful life and other
factors, State plans shall require final compliance as expeditiously as
practicable, but no later than the compliance times specified in the
EG. See 40 CFR 60.24a(c). Where a State applies a less stringent
standard of performance because of remaining useful life and other
factors, the compliance schedule must appropriately comport with that
standard.\339\
---------------------------------------------------------------------------
\339\ 40 CFR 60.24a(d) additionally required state plans to
include increments of progress for any compliance schedule that
extended more than 24 months after the state plan submittal date.
While the substantive requirement for increments of progress was not
challenged and remains effective, the timing aspect of this
provision was vacated by the D.C. Circuit. Am. Lung Assoc., 985 F.3d
at 991. The EPA intends to address the timing aspect of this
provision in the near future.
---------------------------------------------------------------------------
In addition to establishing standards of performance and compliance
schedules, State plans must also include, adequately document, and
demonstrate the methods employed to implement and enforce the standards
of performance such that the EPA can review and identify measures that
assure transparent and verifiable implementation. As part of ensuring
that regulatory obligations appropriately meet statutory requirements
such as enforceability, the EPA has historically and consistently
required that obligations placed on sources be quantifiable, non-
duplicative, permanent, verifiable, and enforceable. See 40 CFR
60.27a(g)(3)(vi). In accordance with the EPA's implementing
regulations, standards of performance required for designated
facilities as part of a State plan to implement the EG proposed here
must be non-duplicative, permanent, verifiable, and enforceable. The
EPA acknowledges that it may not be feasible to quantify certain non-
numerical standards of performance included in the EG. As such, the EPA
is proposing that standards of performance for this EG be quantifiable
to the extent feasible. A State plan implementing the EG should include
information adequate to support a determination by the EPA that the
plan meets these requirements. Additionally, States must include
appropriate monitoring, reporting, and recordkeeping requirements to
ensure that State plans adequately provide for the implementation and
enforcement of standards of performance. For designated facilities
where the EPA's presumptive standards include associated monitoring,
reporting, and/or recordkeeping requirements, the EPA has determined
that such requirements are necessary to ensure compliance. Thus, for
those designated facilities, the EPA is proposing to require that the
standards of performance established by States maintain the same
monitoring, reporting, and recordkeeping requirements, or equivalent
requirements. For example, the EG's presumptive standards for fugitives
monitoring at well sites includes requirements for owners and operators
to maintain records and submit reports that demonstrate compliance with
the monitoring and repair provisions. As such, the EPA is proposing
that the portion of the State plan which
[[Page 63253]]
establishes standards of performance for that designated facility also
includes requirements for owners and operators to maintain records and
submit reports that demonstrate compliance with the monitoring and
repair provisions. Where a State plan adopts standards of performance
that differ from the presumptive standards, the plan may accordingly
include different monitoring, reporting, and recordkeeping requirements
than those in the presumptive standards, but such requirements must be
appropriate for the implementation and enforcement of the standards.
For components of a State plan that differ from any presumptively
approvable aspects of the final EG, the EPA will review the
approvability of such components through notice and comment rulemaking.
Emissions Inventories. The implementing regulations at 40 CFR
60.25a contain generally applicable requirements for emission
inventories, source surveillance, and reports. State plans must include
provisions to meet these requirements as well. Section 60.25a further
specifies that such data shall be summarized in the plan, and emission
rates of designated pollutants from designated facilities shall be
correlated with applicable standards of performance. Typically, the EPA
would expect that State plans would present this information on a
source-specific or unit-specific level. However, the EPA recognizes
that due to the very large number of existing oil and natural gas
sources,\340\ and the frequent change of configuration and/or
ownership, that it may not be practical to require States to compile
this information in the same way that is typically expected for other
industries under other EG. Therefore, the EPA is soliciting comment on
whether to supersede the requirements of 40 CFR 60.25a(a) for purposes
of this EG. The EPA may supersede any requirement in its implementing
regulations for CAA section 111(d) if done so explicitly in the EG. See
40 CFR 60.20a(a)(1). Specially, for the reasons explained previously,
the EPA believes that in this context it could be difficult for the
State plans to include ``an inventory of all designated facilities,
including emission data for the designated pollutants and information
related to emissions as specified in appendix D to this part'' as
required by the first sentence in 40 CFR 60.25a(a). The EPA understands
that States may not have such an inventory of all designated facilities
already available and that creating such an inventory could be resource
intensive. Likewise, the EPA understands that States may not have site-
specific emissions data for each designated facility, and that creating
such an inventory could also be very resource intensive. The EPA does
not believe that such detailed information is necessary for States to
develop standards of performance, and that standards of performance
could be developed with a different type of emissions inventory data.
Therefore, in order to avoid the potential burden that could be imposed
by applying 40 CFR 60.25a(a) as written to this EG, the EPA is
soliciting comment on whether the Agency should supersede the
requirements of 40 CFR 60.25a(a) for purposes of this EG, and replace
that requirement with a different emissions inventory requirement that
seeks to represent the same general type of information but allows
States to utilize existing inventories and emissions data. An example
of an inventory that could be leveraged, and on which the EPA
specifically solicits comment, is the GHGRP. The EPA envisions a
superseding requirement that would not impose such a resource intensive
burden on States by allowing use of an inventory of GHG emissions data
and operational data for designated facilities during the most recent
calendar year for which data is available at the time of State plan
development and/or submission. The emissions inventory data submitted
for this purpose could be derived from the GHGRP, and/or other
available existing inventory information available to the State. The
EPA recognizes that in this situation the facility definitions used for
purposes of compiling the emissions inventory data might not be fully
aligned with the designated facilities in the EG, and that it is
possible that there could be designated facilities under this EG that
are not required to report under the emissions inventory program being
relied upon. Further, the EPA recognizes that the GHGRP may include a
reporting threshold and/or utilize emission factors in a different
manner than the EG. The EPA solicits comment on whether it is
appropriate to utilize or supersede 40 CFR 60.25a(a) for purposes of
this EG. Specifically, the EPA solicits comment on the practicality of
States compiling an inventory for all designated facilities and on what
reasonable alternatives may be more practical.
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\340\ In the U.S. the EPA has identified over 15,000 oil and gas
owners and operators, around 1 million producing onshore oil and gas
wells, about 5,000 gathering and boosting facilities, over 650
natural gas processing facilities, and about 1,400 transmission
compression facilities.
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Meaningful Engagement. The fundamental purpose of CAA section 111
is to reduce emissions from certain stationary sources that cause, or
significantly contribute to, air pollution which may reasonably be
anticipated to endanger public health or welfare. Therefore, a key
consideration in the State's development of a State plan pursuant to an
EG promulgated under CAA section 111(d) is the potential impact of the
proposed plan requirements on public health and welfare. A robust and
meaningful public participation process during State plan development
is critical to ensuring that these impacts are fully considered. The
EPA is proposing and soliciting comment on requiring States to perform
outreach and meaningful engagement with overburdened and underserved
communities during the development process of their State plan pursuant
EG OOOOc.
States often rely primarily on public hearings as the foundation of
their public engagement in their State plan development process because
a public hearing is explicitly required pursuant to the applicable
regulations. The existing provisions in subpart Ba (40 CFR 60.23a(c)-
(f)) detail the public participation requirements associated with the
development of a CAA section 111(d) State plan. Per these implementing
regulations, States must provide certain notice of and conduct one or
more public hearings on their State plan before such plan is adopted
and submitted to the EPA for review and action. However, robust and
meaningful public involvement in the development of a State plan should
go beyond the minimum requirement to hold a public hearing. Meaningful
engagement should include ensuring that States share information with
and solicit input from stakeholders at critical junctures during plan
development, which helps ensure that a plan is adequately addressing
the potential impacts to public health and welfare that are the core
concern of CAA section 111.
This early engagement is especially important for those
stakeholders and communities directly impacted by the GHG emissions
from designated facilities within the Crude Oil and Natural Gas source
category being addressed in a State plan developed pursuant the EG
OOOOc. As reflected in section VI and VII of the preamble, engagement
with stakeholders and in particular adjacent communities was key during
the development of the proposed NSPS and EG and will be key in the
development of corresponding State plans that achieve the intended
emission reductions and provide benefits to these communities. In
[[Page 63254]]
recognizing that minority and low-income populations often bear an
unequal burden of environmental harms and risks, the EPA continues to
consider ways to protect them from adverse public health and
environmental effects of air pollution emitted from sources within the
Oil and Natural Gas Industry that are addressed in this proposed
rulemaking. For these reasons, the EPA is proposing to include an
additional requirement associated with the adoption and submittal of
State plans pursuant to EG OOOOc (in addition to the current
requirements of Subpart Ba) by requiring States to meaningfully engage
with members of the public, including overburdened and underserved
communities, during the plan development process and prior to adoption
and submission of the plan to the EPA.
The EPA's authority for proposing to include an additional
requirement for meaningful engagement is provided by the authority of
both CAA sections 111(d) and 301(a)(1). Under CAA section 111(d), one
of the EPA's obligations is to promulgate a process ``similar'' to that
of CAA section 110 under which States submit plans that implement
emission reductions consistent with the BSER. CAA section 110(a)(1)
requires States to adopt and submit State implementation plans (SIPs)
after ``reasonable notice and public hearings.'' The Act does not
define what constitutes ``reasonable notice'' under CAA section 110,
and therefore the EPA may reasonably interpret this requirement in
promulgating a process under which States submit section 111(d) plans.
The EPA proposes to give the ``reasonable notice'' requirement
additional and separate meaning from the ``public hearing''
requirement. Therefore, in addition to the generally applicable public
participation requirements in 40 CFR 60.23a(c)-(f) (which presently
only require public notification of a public hearing), the EPA proposes
to promulgate these additional meaningful engagement requirements
within the EG OOOOc to ensure that the public has reasonable notice of
relevant information and the opportunity to participate in the State
plan development throughout the process. Given the public health and
welfare objectives of CAA section 111(d) in regulating specific
existing sources, the EPA believes it is reasonable to require
meaningful engagement as part of the public participation process in
order to further these objectives. Additionally, CAA section 301(a)(1)
provides that the EPA is authorized to prescribe such regulations ``as
are necessary to carry out [its] functions under [the CAA].'' The
proposed meaningful engagement requirements would effectuate the EPA's
function under CAA section 111(d) in prescribing a process under which
States submit plans to implement the statutory directives of this
section.
The proposed meaningful engagement requirements for State plan
development would ensure that the process is inclusive, effective, and
accessible to all. For this reason, the process must not be
disproportionate or favor certain stakeholders. During the development
of the State plan pursuant to EG OOOOc, the EPA expects States to
identify any underserved or overburdened communities potentially
impacted by the State plan. If any communities are identified, States
should engage with these communities and develop public participation
strategies to overcome linguistic, cultural, institutional, geographic,
and other barriers to meaningful participation and ensure meaningful
community representation in the process, recognizing diverse
constituencies within any particular community. Community participation
should occur as early as possible if it is to be meaningful. Meaningful
engagement includes targeted outreach to underserved and overburdened
communities, sharing information, and soliciting input on State plan
development and on any accompanying assessments. The EPA uses the term
``underserved'' to mean populations sharing a particular
characteristic, as well as geographic communities, that have been
systemically denied a full opportunity to participate in aspects of
economic, social, and civic life, and the term ``overburdened'' in
referring to minority, low-income, Tribal, and indigenous populations
or communities in the U.S. that potentially experience disproportionate
environmental harms and risks as a result of greater vulnerability to
environmental hazards . This increased vulnerability may be
attributable to an accumulation of both negative and lack of positive
environmental, health, economic, or social conditions within these
populations or communities. This engagement will help ensure that State
plans achieve meaningful emission reductions, that overburdened
communities partake in the benefits and gains of the State plan, and
that these communities are protected from being adversely impacted by
the State plan. The EPA recognizes that emissions from designated
sources could cross State borders, and therefore may affect underserved
and overburdened communities in neighboring States. The EPA is
soliciting comment on how meaningful engagement should apply to
communities outside of the State that is developing a State plan, for
example if a State should coordinate with the neighboring State for
outreach or directly contact the affected community.
In sections VI and VII of this preamble the EPA addresses
environmental justice considerations, implications, and stakeholder
outreach the agency is taking to help ensure vulnerable communities are
not disproportionately impacted by this rule. The considerations,
analyses, and outreach presented in these preamble sections could help
States in designing, planning, and developing their own outreach and
engagement plans associated with the development and implementation of
their State plans to reduce emissions of GHGs from designated
facilities within the Crude Oil and Natural Gas source category.
To ensure that robust and meaningful public engagement process
occurs as the States develop their CAA 111(d) plans, the EPA is also
proposing to include a requirement within EG OOOOc for States to
demonstrate in their plan submittal how they provided meaningful and
timely engagement with all pertinent stakeholders, including, as
necessary, industries and small businesses, as well as low-income
communities, communities of color, and indigenous populations living
near the designated facilities and who may be otherwise potentially
affected by the State's plan. The State would be required to describe,
in their plan submittal, the engagement they had with their
stakeholders, including their overburdened and underserved communities.
Additionally, the EPA would evaluate the States' demonstrations
regarding meaningful public engagement as part of its completeness
evaluation of a State plan submittal. If a State plan submission does
not meet the required elements for public participation, including
requirements for meaningful engagement, this may be ground for the EPA
to find the submission incomplete or to disapprove the plan.
The EPA further notes that the implementing regulations allow a
State to request the approval of different State procedures for public
participation pursuant 40 CFR 60.23a(h). The EPA proposes to require
that such alternate State procedures do not supersede the meaningful
engagement requirements being proposed within EG OOOOc, so that a State
would still be required to comply with the meaningful
[[Page 63255]]
participation requirements even if they apply for a different procedure
than the other public notice and hearing requirements under 40 CFR
60.23a. As provided in 40 CFR 60.23a(h), the EPA is proposing that
States may also apply for, and the EPA may approve, alternate
meaningful engagement procedures if, in the judgement of the
Administrator, the procedures, although different from the requirements
of within EG OOOOc, in fact provide for adequate notice to and
meaningful participation of the public.
D. Components of State Plan Submission
Under CAA section 111(d)(2), the EPA has an obligation to determine
whether each State plan is ``satisfactory.'' Therefore, in addition to
identifying the components that the EG must include, the EPA's
implementing regulations for CAA section 111(d) identify additional
components that a State plan must include. Many of these requirements
are found in 40 CFR 60.23a, 60.24a, 60.25a, and 60.26a. These
provisions include requirements for components such as the following:
Procedures a State must go through for adopting a plan before
submitting it to the EPA; the stringency of standards of performance
and compliance timelines; emission inventories, reporting, and
recordkeeping; and, the legal authority a State must show in adopting a
plan. These requirements are also generally contained in a list of
required State plan elements, referred to as the State plan
completeness criteria, found at 40 CFR 60.27a(g)(2)-(3). If the EPA
determines that a submitted plan does not meet these criteria then the
State is treated as not submitting a plan and the EPA has a duty to
promulgate a Federal plan for that State. See CAA section 111(d)(2)(A)
and 40 CFR 60.27a(g)(1). If the EPA determines a plan submission is
complete, such determination does not reflect a judgment on the
eventual approvability of the submitted portions of the plan, which
instead must be made through notice-and-comment rulemaking. The
completeness criteria do not apply to States without any designated
facilities because these States are directed to submit to the
Administrator a letter of negative declaration certifying that there
are no designated facilities, as defined by the EPA's emissions
guidelines, located within the State. See 40 CFR 60.23a(b). No plan is
required for States that do not have any designated facilities.
Designated facilities located in States that mistakenly submit a letter
of negative declaration would be subject to a Federal plan until a
State plan regulating those facilities becomes approved by the EPA.
The EPA established nine administrative and six technical criteria
for complete State plans under CAA section 111(d). See 40 CFR
60.27a(g)(2)-(3). If a State plan does not include even one of these
criteria, then the State plan may be deemed incomplete by the EPA.
States that are familiar with the SIP submittal process under CAA
section 110 will be familiar with the completeness criteria found in 40
CFR part 51, appendix V. While the completeness criteria for State plan
submittals found at 40 CFR 60.27a(g)(2)-(3) is somewhat similar to the
SIP submittal criteria in appendix V, it is not exactly the same. As
such, even States that are familiar with the SIP submittal process
under CAA section 110 are strongly encouraged to review the
completeness criteria in 40 CFR 60.27a(g)(2)-(3) as well as the other
State plan requirements found in 40 CFR 60.23a, 60.24a, 60.25a, and
60.26a early in their planning process.
In short, the administrative completeness criteria require that the
State's plan include a formal submittal letter and a copy of the actual
State regulations themselves, as well as evidence that the State has
legal authority to adopt and implement the plan, actually adopted the
plan, followed State procedural laws when adopting the plan, gave
public notice of the changes to State law, held public hearing(s) if
applicable, and responded to State-level comments. For a detailed
description regarding the public hearing requirement, see 40 CFR
60.23a. For a detailed description of what the State plan must include
in terms of evidence that the State has legal authority to adopt and
implement the plan, see 40 CFR 60.26a. States are strongly encouraged
to review the State plan requirements included in 40 CFR 60.23a and
60.26a in conjunction with the administrative completeness criteria in
40 CFR 60.27a.
The technical criteria require that the State's plan identify the
designated facilities, the standards of performance, the geographic
scope of the plan, monitoring, recordkeeping and reporting requirements
(both for facilities to ensure compliance and for the State to ensure
performance of the plan as a whole), and compliance schedules. The
technical criteria further require that the State demonstrate that the
plan is projected to achieve emission performance under the EG and that
each emission standard is quantifiable, non-duplicative, permanent,
verifiable, and enforceable. As previously described, it may not be
feasible to quantify certain non-numerical standards of performance.
The EPA is proposing to require States demonstrate that each standard
of performance is quantifiable, as feasible. For a detailed description
of the State plan requirements regarding standards of performance, see
section XIV.C and 40 CFR 60.24a.
In addition to these technical criteria, 40 CFR 60.25a(a) requires
that State plans include certain emissions data for the designated
facilities. As explained previously, the EPA is soliciting comment on
superseding that requirement for this EG. Further, Sec. 60.25a
provides a detailed description of what the State plan is required to
include in terms of certain compliance monitoring and reporting. States
are strongly encouraged to review the State plan requirements included
in 40 CFR 60.24a and 60.25a in conjunction with the technical
completeness criteria in 40 CFR 60.27a.
E. Timing of State Plan Submissions and Compliance Times
The EPA acknowledges that the D.C. Circuit has vacated certain
timing provisions within 40 CFR part 60, subpart Ba. Am. Lung Assoc. v.
EPA, 985 F.3d at 991 (DC Cir. 2021). These provisions include timing
requirements for when State plans are due upon publication of a final
EG, for EPA's action on a State plan submission, and for EPA's
promulgation of a Federal plan. The Agency plans to undertake
rulemaking to address the provisions vacated under the court's decision
in the near future. At this time, the EPA is soliciting comment on any
facts and circumstances that are unique to the oil and natural gas
industry that the EPA should consider when proposing a timeline for
plan submission applicable to a final EG for this source category. We
recognize that the public needs to have an opportunity to review and
comment on the new timelines that will address these regulatory gaps,
including in particular the timeline for State plan submission, and the
Agency is committed to publishing this proposed timeline for comment
when available.
In accordance with 40 CFR 60.22a(b)(5), the EPA's EG is to provide
information for the development of State plans that includes, among
other things, ``the time within which compliance with standards of
performance can be achieved.'' The EPA is proposing those compliance
times for comment. See 40 CFR 60.25a(c). Each State plan must include
compliance schedules that, subject to certain exception, require
compliance as expeditiously as practicable but no later
[[Page 63256]]
than the compliance times included in the relevant EG. Id. at 60.24a(a)
and (c). States are free to include compliance times in their plans
that are earlier than those included in the final EG. Id. at 40 CFR
60.24a(f)(2). If a State chooses to include a compliance schedule in
their plan that extends for a certain period beyond the date required
for submittal of the plan, then ``the plan must include legally
enforceable increments of progress to achieve compliance for each
designated facility.'' \341\ Id. at 40 CFR 60.24a(d). To the extent a
State accounts for remaining useful life and other factors in applying
a less stringent standard of performance (than required by the EPA in
the final EG), the State must also include a compliance deadline that
it can demonstrate appropriately correlates with that standard.
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\341\ As previously noted, the timing aspect of this provision
was vacated by the D.C. Circuit. Am. Lung Assoc. v. EPA, 985 F.3d
914 at 991. The EPA intends to address the timing aspect of this
provision in the near future.
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The EPA is proposing to require that State plans impose a
compliance timeline on designated facilities to require final
compliance with the standards of performance as expeditiously as
practicable, but no later than two years following the State plan
submittal deadline. As explained above, the EPA anticipates proposing a
State plan submission deadline in a separate document. The EPA believes
that two years is an appropriate amount of time for designated
facilities to ensure compliance based on the EPA's general
understanding of the industry and the proposed presumptive standards.
However, the EPA recognizes that there are many existing sources in the
oil and natural gas industry that would be subject to a State plan if
the presumptive standards are finalized in a similar manner as proposed
in this document, and that there may be a wide range of configurations
that may be present at any given facility. Further, the EPA recognizes
that it may be appropriate to require different compliance times for
different designated facilities. For example, it may be appropriate to
require one compliance schedule for reciprocating compressors and a
different compliance schedule for storage vessels. There may not be a
one-size-fits-all approach to compliance times that is appropriate for
all designated facilities.
Accordingly, the EPA is soliciting comment on whether a two-year
compliance schedule is appropriate for all designated facilities, or
whether the EG should require a shorter or longer compliance schedule.
The EPA is further soliciting comment on whether it would be
appropriate to establish different compliance schedules for different
designated facilities, and if so, what are the appropriate timelines
for each designated facility. The EPA is soliciting comment on this
matter to collect information that might inform different compliance
timeline(s) that Agency may propose for comment in the future via a
supplemental proposal.
F. EPA Action on State Plans and Promulgation of Federal Plans
While CAA section 111(d)(1) authorizes States to develop State
plans that establish standards of performance and provides States with
certain discretion in determining the appropriate standards, CAA
section 111(d)(2) provides the EPA a specific oversight role with
respect to such State plans. This latter provision authorizes the EPA
to prescribe a Federal plan for a State ``in cases where the State
fails to submit a satisfactory plan.'' The States must therefore submit
their plans to the EPA, and the EPA must evaluate each State plan to
determine whether each plan is ``satisfactory.'' The EPA's implementing
regulations for CAA section 111(d) accordingly provide procedural
requirements for the EPA to make such a determination. See 40 CFR
60.27a.
Upon receipt of a State plan, the EPA is first required to
determine whether the State plan submittal is complete in accordance
with the completeness criteria explained above. See 40 CFR
60.27a(g)(1). The EPA would then have a set period of time to act on
any State plan that is deemed complete.\342\ If the EPA determines that
the State plan submission is incomplete, then the State will be treated
as not having made the submission, and the EPA would be required to
promulgate a Federal plan for the designated facilities in that State.
Likewise, if a State does not make any submission then the EPA is
required to promulgate a Federal plan. If the EPA does not make an
affirmative determination regarding completeness of the State plan
submission within a certain amount of time from receiving the State
plan, then the submission is deemed complete by operation of law. Id.
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\342\ As explained above, the D.C. Circuit vacated the timing
provisions regarding EPA's action on a state plan submission, and
EPA's promulgation of a Federal plan. Am. Lung Assoc. v. EPA, 985
F.3d at 991. The Agency plans to undertake rulemaking to address the
provisions vacated under the court's decision in the near future.
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If a State has submitted a complete plan, then the EPA is required
to evaluate that plan submission for approvability in accordance with
the CAA, EPA's implementing regulations, and the applicable EG. The EPA
may approve or disapprove the State plan submission in whole or in
part. See 40 CFR 60.27a(b). If the EPA approves the State plan
submission, then that State plan becomes Federally enforceable. If the
EPA disapproves the required State plan submission, in whole or in
part, then the EPA is required to promulgate a Federal plan for the
designated facilities in that State via a notice-and-comment
rulemaking, and with an opportunity for public hearing. See 40 CFR
60.27a(c) and (f). In either scenario that would give rise to the EPA's
duty to promulgate a Federal plan (a finding that a State did not
submit a complete plan or a disapproval of a State plan), the EPA would
not be required to promulgate the Federal plan if the State corrects
the deficiency giving rise to the EPA's duty and the EPA approves the
State's plan before promulgating the Federal plan. Requirements
regarding the content of a Federal plan are included in 40 CFR
60.27a(e).
G. Tribes and the Planning Process Under CAA Section 111(d)
Under the Tribal Authority Rule (TAR) adopted by the EPA, Tribes
may seek authority to implement a plan under CAA section 111(d) in a
manner similar to a State. See 40 CFR part 49, subpart A. Tribes may,
but are not required to, seek approval for treatment in a manner
similar to a State for purposes of developing a Tribal Implementation
Plan (TIP) implementing the EG. If a Tribe obtains approval and submits
a TIP, the EPA will generally use similar criteria and follow similar
procedures as those described above for State plans when evaluating the
TIP submission, and will approve the TIP if appropriate. The EPA is
committed to working with eligible Tribes to help them seek
authorization and develop plans if they choose. Tribes that choose to
develop plans will generally have the same flexibilities available to
States in this process. If a Tribe does not seek and obtain the
authority from the EPA to establish a TIP, the EPA has the authority to
establish a Federal CAA section 111(d) plan for areas of Indian country
where designated facilities are located. A Federal plan would apply to
all designated facilities located in the areas of Indian country
covered by the Federal plan unless and until the EPA approves an
applicable TIP applicable to those facilities.
[[Page 63257]]
XV. Prevention of Significant Deterioration and Title V Permitting
In this section, the EPA is addressing how regulation of GHGs under
CAA section 111 could have implications for other EPA rules and for
permits written under the CAA PSD preconstruction permit program and
the CAA title V operating permit program. The EPA is proposing to
include provisions in the regulations that explicitly address some of
these potential implications, consistent with our experience in prior
rules regulating GHGs. The EPA included and explained the basis for
similar provisions when promulgating 2016 NSPS OOOOa, as well as the
2015 subpart TTTT NSPS for electric utility generating units. See 81 FR
35823, 35871 (June 3, 2016); 80 FR 64509, 64628 (October 23, 2015). The
discussion in these prior rule preambles equally applies to the oil and
gas sources subject to NSPS OOOOb and EG OOOOc.
In summary, in light of the U.S. Supreme Court's decision in
Utility Air Regulatory Group v. Environmental Protection Agency, 573
U.S. 302 (2014) (UARG), the EPA may not treat GHGs as an air pollutant
for purposes of determining whether a source is a major source (or
modification thereof) for the purpose of PSD applicability. Certain
portions of the EPA's PSD regulations (specifically, the definition of
``subject to regulation'') effectively ensure that most sources will
not trigger PSD solely by virtue of their GHG emissions. E.g., 40 CFR
51.166(b)(48)(iv), 52.21(b)(49)(iv).\343\ However, the EPA's PSD
regulations (specifically, the definition of ``regulated NSR
pollutant'') provide additional bases for PSD applicability for
pollutants that are regulated under CAA section 111. To address this
latter component of PSD applicability, the EPA is proposing to add
provisions within the subpart OOOOb NSPS and subpart OOOOc EG to help
clarify that the promulgation of GHG standards under section 111 will
not result in additional sources becoming subject to PSD based solely
on GHG emissions, which would be contrary to the holding in UARG. These
provisions will be similar to those in the 2016 NSPS OOOOa and other
section 111 rules that regulate GHGs. See, e.g., 40 CFR 60.5360a(b)(1)-
(2), 60.5515(b)(1)-(2).
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\343\ In 2016, the EPA proposed additional revisions to the PSD
and title V regulations that would address these and other concerns.
81 FR 58110 (October 3, 2016).
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The EPA understands there are also concerns that if methane were to
be subject to regulation as a separate air pollutant from GHGs, sources
that emit methane above the PSD thresholds or modifications that
increase methane emissions could be subject to the PSD program. To
address this concern and for purposes of clarity, the EPA is proposing
to adopt regulatory text within subpart OOOOb NSPS and subpart OOOOc EG
to clarify that the air pollutant that is subject to regulation is
GHGs, even though the standard is expressed in the form of a limitation
on emission of methane. This language will be substantially similar to
language found in, for example, the 2016 NSPS OOOOa and other rules.
See, e.g., 40 CFR 60.5360a(a), 60.5515(a).
For sources that are subject to the PSD program based on non-GHG
emissions, the CAA continues to require that PSD permits satisfy the
best available control technology (BACT) requirement for GHGs. Based on
the language in the PSD regulations, the EPA and States may continue to
limit the application of BACT to GHG emissions in those circumstances
where a new source emits GHGs in the amount of at least 75,000 tpy on a
CO2 Eq. basis or an existing major source increases
emissions of GHGs by more than 75,000 tpy on a CO2 Eq.
basis. See 40 CFR 51.166(b)(48)(iv), 52.21(b)(49)(iv). The proposed
revisions to the regulatory text within subparts OOOOb NSPS and OOOOc
EG will ensure that this BACT applicability level remains operable to
sources of GHGs regulated under CAA section 111, as have similar
revisions in prior rules. See, e.g., 40 CFR 60.5360a(b)(1)-(2),
60.5515(b)(1)-(2). This proposed rule will not require any additional
revisions to SIPs.
Regarding title V, the UARG decision similarly held that the EPA
may not treat GHGs as an air pollutant for purposes of determining
whether a source is a major source for the purpose of title V
applicability. Promulgation of CAA section 111 requirements for GHGs
will not result in the EPA imposing a requirement that stationary
sources obtain a title V permit solely because such sources emit or
have the potential to emit GHGs above the applicable major source
thresholds.\344\
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\344\ Additional regulatory text, based on that in prior rules,
will further ensure that title V regulations are not applied to GHGs
solely because they are regulated under CAA section 111. See, e.g.,
40 CFR 60.5360a(b)(3)-(4), 60.5515(b)(3)-(4). The EPA understands
that concerns regarding the regulation of methane as a separate air
pollutant (described with respect to PSD) also apply to title V. The
EPA's proposed regulatory text--clarifying that the pollutant
subject to regulation is GHGs--will similarly address these concerns
with respect to title V. See, e.g., 40 CFR 60.5360a(a), 60.5515(a).
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To be clear, however, unless exempted by the Administrator through
regulation under CAA section 502(a), any source, including a ``non-
major source,'' subject to a standard or regulation under section 111
is required to apply for, and operate pursuant to, a title V permit
that ensures compliance with all applicable CAA requirements for the
source, including any GHG-related applicable requirements. This aspect
of the title V program is not affected by UARG.\345\ The EPA proposes
to include an exemption from the obligation to obtain a title V permit
for sources subject to NSPS OOOOb and EG OOOOc, unless such sources
would otherwise be required to obtain a permit under 40 CFR 70.3(a) or
40 CFR 71.3(a), as the EPA did in NSPS OOOO and OOOOa.\346\ See 40 CFR
60.5370, 60.5370a. However, sources that are subject to the CAA section
111 standards promulgated in this rule and that are otherwise required
to obtain a title V permit under 40 CFR 70.3(a) or 40 CFR 71.3(a) will
be required to apply for, and operate pursuant to, a title V permit
that ensures compliance with all applicable CAA requirements, including
any GHG-related applicable requirements.
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\345\ See Memorandum from Janet G. McCabe, Acting Assistant
Administrator, Office of Air and Radiation, and Cynthia Giles,
Assistant Administrator, Office of Enforcement and Compliance
Assurance, to Regional Administrators, Regions 1-10, Next Steps and
Preliminary Views on the Application of Clean Air Act Permitting
Programs to Greenhouse Gases Following the Supreme Court's Decision
in Utility Regulatory Group v. Environmental Protection Agency (July
24, 2014) at 5.
\346\ The EPA provided the rationale for exempting this source
category from the title V permitting requirements during the
rulemaking for the 2012 NSPS OOOO. See 76 FR 52737, 52751 (August
23, 2011). That rationale continues to apply to this source
category.
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XVI. Impacts of This Proposed Rule
A. What are the air impacts?
The EPA projected that, from 2023 to 2035, relative to the
baseline, the proposed NSPS OOOOb and EG OOOOc will reduce about 41
million short tons of methane emissions reductions (920 million tons
CO2 Eq.), 12 million short tons of VOC emissions reductions,
and 480 thousand short tons of HAP emission reductions from facilities
that are potentially affected by this proposal. The EPA projected
regulatory impacts beginning in 2023 as that year represents the first
full year of implementation of the proposed NSPS OOOOb. The EPA assumes
that emissions impacts of the proposed EG OOOOc will begin in 2026. The
EPA projected impacts through 2035 to illustrate the accumulating
effects of this rule over a longer period. The EPA
[[Page 63258]]
did not estimate impacts after 2035 for reasons including limited
information, as explained in the RIA.
B. What are the energy impacts?
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 in XVI.D. There will likely
be minimal change in emissions control energy requirements resulting
from this rule. Additionally, this proposed 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.
C. What are the compliance costs?
The PV of the regulatory compliance cost associated with the
proposed NSPS OOOOb and EG OOOOc over the 2023 to 2035 period was
estimated to be $13 billion (in 2019 dollars) using a 3-percent
discount rate and $10 billion using a 7-percent discount rate. The EAV
of these cost reductions is estimated to be $1.2 billion per year using
a 3-percent discount rate and $1.2 billion per year using a 7-percent
discount rate.
These estimates do not, however, include the producer revenues
associated with the projected increase in the recovery of saleable
natural gas. Estimates of the value of the recovered product have been
included in previous regulatory analyses as offsetting compliance
costs. Using the 2021 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 proposed action, the EPA
estimated a PV of regulatory compliance costs of the proposed rule over
the 2023 to 2035 period of $7.2 billion using a 3-percent discount rate
and $6.3 billion using a 7-percent discount rate. The corresponding
estimates of the EAV of compliance costs after accounting for the
recovery of saleable natural gas were $680 million per year using a 3-
percent discount rate and $760 million using a 7-percent discount rate.
D. What are the economic and employment impacts?
The EPA conducted an economic impact and distributional analysis
for this proposal, as detailed in section 4 of the RIA for this
proposal. To provide a partial measure of the economic consequences of
the proposed NSPS OOOOb and EG OOOOc, the EPA developed a pair of
single-market, static partial-equilibrium analyses of national crude
oil and natural gas markets. We implemented the pair of single-market
analyses instead of a coupled market or general equilibrium approach to
provide broad insights into potential national-level market impacts
while providing maximum analytical transparency. We estimated the price
and quantity impacts of the proposed NSPS OOOOb and EG OOOOc on crude
oil and natural gas markets for a subset of years within the time
horizon analyzed in the RIA. The models are parameterized using
production and price data from the U.S. Energy Information
Administration and supply and demand elasticity estimates from the
economics literature.
The RIA projects that regulatory costs are at their highest in
2026, the first year the requirements of both the proposed NSPS OOOOb
and EG OOOOc are assumed to be in effect and will represent the year
with the largest market impacts based upon the partial equilibrium
modeling. We estimated that the proposed rule could result in a maximum
decrease in annual natural gas production of about 249 million Mcf in
2026 (or about 0.8 percent of natural gas production) with a maximum
price increase of $0.05 per Mcf (or about 1.8 percent). We estimated
the maximum annual reduction in crude oil production would be about
12.2 million barrels (or about 0.3 percent of crude oil production)
with a maximum price increase of about $0.06 per barrel (or less than
0.1 percent).
Before 2026, the modeled market impacts are much smaller than the
2026 impacts as only the incremental requirements under the proposed
NSPS OOOOb are assumed to be in effect. As regulatory costs are
projected to decline after 2026, the modelled market impacts for years
after 2026 are smaller than the peaks estimated for 2026. Please see
section 4.1 of the RIA for more detail on the formulation and
implementation of the model as well as a discussion of several
important caveats and limitations associated with the approach.
As discussed in the RIA for this proposal, employment impacts of
environmental regulations are generally composed of a mix of potential
declines and gains in different areas of the economy over time.
Regulatory employment impacts can vary across occupations, regions, and
industries; by labor and product demand and supply elasticities; and in
response to other labor market conditions. Isolating such impacts is a
challenge, as they are difficult to disentangle from employment impacts
caused by a wide variety of ongoing, concurrent economic changes.
The oil and natural gas industry directly employs approximately
140,000 people in oil and natural gas extraction, a figure which varies
with market prices and technological change, and employs a large number
of workers in related sectors that provide materials and services.\347\
As indicated above, the proposed NSPS OOOOb and EG OOOOc are projected
to cause small changes in oil and natural gas production and prices. As
a result, demand for labor employed in oil and natural gas-related
activities and associated industries might experience adjustments as
there may be increases in compliance-related labor requirements as well
as changes in employment due to quantity effects in directly regulated
sectors and sectors that consume oil and natural gas products.
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\347\ Employment figure drawn from the Bureau of Labor
Statistics Current Employment Statistics for NAICS code 211.
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E. What are the benefits of the proposed standards?
To satisfy the requirement of E.O. 12866 and to inform the public,
the EPA estimated the climate and health benefits due to the emissions
reductions projected under the proposed NSPS OOOOb and EG OOOOc. The
EPA expects climate and health benefits due to the emissions reductions
projected under the proposed NSPS OOOOb and EG OOOOc. The EPA estimated
the global social benefits of CH4 emission reductions
expected from this proposed rule using the SC-CH4 estimates
presented in the ``Technical Support Document: Social Cost of Carbon,
Methane, and Nitrous Oxide Interim Estimates under E.O. 13990 (IWG
2021)'' published in February 2021 by the Interagency Working Group on
the Social Cost of Greenhouse Gases (IWG). The SC-CH4 is the
monetary value of the net harm to society associated with a marginal
increase in emissions in a given year, or the benefit of avoiding that
increase. In principle, SC-CH4 includes the value of all
climate change impacts, including (but not limited to) changes in net
agricultural productivity, human health effects, property damage from
increased flood risk and natural disasters, disruption of energy
systems, risk of conflict, environmental migration, and the value of
ecosystem services. The SC-CH4 therefore, reflects the
societal value of reducing emissions of the gas in question by one
metric ton and is the theoretically appropriate value to use in
conducting benefit-cost
[[Page 63259]]
analyses of policies that affect CH4 emissions.
The interim SC-GHG estimates were developed over many years, using
a transparent process, peer-reviewed methodologies, the best science
available at the time of that process, and with input from the public.
As a member of the IWG involved in the development of the February 2021
Technical Support Document (TSD): Social Cost of Carbon, Methane, and
Nitrous Oxide Interim Estimates under Executive Order 13990 (IWG 2021),
the EPA agrees that the interim SC-GHG estimates represent the most
appropriate estimate of the SC-GHG until revised estimates have been
developed reflecting the latest, peer-reviewed science.
The EPA estimated the PV of the climate benefits over the 2023 to
2035 period to be $55 billion at a 3-percent discount rate. The EAV of
these benefits is estimated to be $5.2 billion per year at a 3-percent
discount rate. These values represent only a partial accounting of
climate impacts from methane emissions and do not account for health
effects of ozone exposure from the increase in methane emissions.
Under the proposed NSPS OOOOb and EG OOOOc, the EPA expects that
VOC emission reductions will improve air quality and are likely to
improve health and welfare associated with exposure to ozone,
PM2.5, and HAP. Calculating ozone impacts from VOC emissions
changes requires information about the spatial patterns in those
emissions changes. In addition, the ozone health effects from the
proposed rule will depend on the relative proximity of expected VOC and
ozone changes to population. In this analysis, we have not
characterized VOC emissions changes at a finer spatial resolution than
the national total. In light of these uncertainties, we present an
illustrative screening analysis in Appendix B of the RIA based on
modeled oil and natural gas VOC contributions to ozone concentrations
as they occurred in 2017 and do not include the results of this
analysis in the estimate of benefits and net benefits projected from
this proposal.
XVII. Statutory and Executive Order Reviews
Additional information about these statutes and EOs 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 proposed action is an economically significant regulatory
action that was submitted to the 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 analysis, ``Regulatory Impact Analysis for the
Proposed Standards of Performance for New, Reconstructed, and Modified
Sources and Emissions Guidelines for Existing Sources: Oil and Natural
Gas Sector Climate Review'', is available in the docket and describes
in detail the EPA's assumptions and characterizes the various sources
of uncertainties affecting the estimates.
B. Paperwork Reduction Act (PRA)
The information collection activities in the proposed amendments
for 40 CFR part 60, subparts OOOO and OOOOa, have been submitted for
approval to the Office of Management and Budget (OMB) under the PRA.
The information collection activities in the proposed rules for 40 CFR
part 60, subparts OOOOb and OOOOc, will be submitted for approval to
OMB under the PRA as part of a supplemental proposed rule.\348\ The
Information Collection Request (ICR) document that the EPA prepared has
been assigned EPA ICR number 2523.04. You can find a copy of the ICR in
the docket for this rule, and it is briefly summarized here.
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\348\ While not quantified in this proposal, the EPA anticipates
the estimated ICR burden of proposed NSPS OOOOb and EG OOOOc to be
at least as burdensome as NSPS OOOOa. The EPA anticipates some
sources may have similar ICR burden to NSPS OOOOa. Examples of these
include fugitive emissions from compressor stations, pneumatic
controllers at gas processing, centrifugal compressors, pneumatic
pumps, well completions, and sweetening units. The EPA anticipates
other sources could have dissimilar burden to NSPS OOOOa because the
standards are different or are brand new to this proposal. Examples
of these include fugitive emissions from well sites, storage
vessels, pneumatic controllers, reciprocating compressors, liquids
unloading, and equipment leaks at gas plants.
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The final rule for this action will include updates to the CFR to
reflect the disapproval of the 2020 Policy Rule that was effectuated by
the joint resolution enacted pursuant to the CRA on June 30, 2021. The
EPA is not soliciting comment on these updates. In addition, this rule
proposes amendments to the 2016 NSPS OOOOa to address (1) certain
resulting inconsistencies between the VOC and methane standards
resulting from the CRA, and (2) rescind certain determinations made in
the 2020 Technical Rule, with respect to fugitive emissions monitoring
at low production well sites and gathering and boosting stations as
they were not supported by the record for that rule, or by our
subsequent information and analysis. The EPA is also proposing further
amendments to its 2016 NSPS OOOOa to address technical and
implementation issues.
This ICR reflects the EPA's proposed amendments to the 2016 NSPS
OOOOa. The information collected will be used by the EPA and delegated
State and local agencies to determine the compliance status of affected
facilities subject to the rule.
The respondents are owners or operators of onshore oil and natural
gas affected facilities (40 CFR 60.5365a). For the purposes of this
ICR, it is assumed that oil and natural gas affected facilities located
in the U.S. are owned and operated by the oil and natural gas industry,
and that none of the affected facilities in the U.S. are owned or
operated by State, local, Tribal or the Federal government. All
affected facilities are assumed to be privately owned for-profit
businesses.
The EPA estimates an average of 3,268 respondents will be affected
by NSPS OOOOa over the three-year period (2021-2023). The average
annual burden for the recordkeeping and reporting requirements for
these owners and operators is 283,030 person-hours, with an average
annual cost of $93,779,839 over the three-year period (2021-2023).
Respondents/affected entities: Oil and natural gas operators and
owners.
Respondent's obligation to respond: Mandatory.
Estimated number of respondents: 3,268.
Frequency of response: Varies depending on affected facility.\349\
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\349\ The specific frequency for each information collection
activity within this request is shown in Tables 1a through 1d of the
Supporting Statement in the public docket.
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Total estimated burden: 283,030 hours (per year). Burden is defined
at 5 CFR 1320.3(b).
Total estimated cost: $93,779,839 (2019$), which includes no
capital or O&M 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. Submit your
comments on the Agency's need for this information, the accuracy of the
[[Page 63260]]
provided burden estimates and any suggested methods for minimizing
respondent burden to the EPA using the docket identified at the
beginning of this rule. You may also send your ICR-related comments to
OMB's Office of Information and Regulatory Affairs via email to
[email protected], Attention: Desk Officer for the EPA. Since
OMB is required to make a decision concerning the ICR between 30 and 60
days after receipt, OMB must receive comments no later than December
15, 2021. The EPA will respond to any ICR-related comments in the final
rule.
C. Regulatory Flexibility Act (RFA)
The RFA generally requires an agency to prepare a regulatory
flexibility analysis of any rule subject to notice and comment
rulemaking requirements under the Administrative Procedure Act or any
other statute unless the agency certifies that the rule will not have a
significant economic impact on a substantial number of small entities.
Small entities include small businesses, small organizations, and small
governmental jurisdictions.
For purposes of assessing the impacts of this rule on small
entities, a small entity is defined as: (1) A small business in the oil
or natural gas industry whose parent company has revenues or numbers of
employees below the SBA Size Standards for the relevant NAICS code; (2)
a small governmental jurisdiction that is a government of a city,
county, town, school district, or special district with a population of
less than 50,000; and (3) a small organization that is any not-for-
profit enterprise which is independently owned and operated and is not
dominant in its field.
Pursuant to section 603 of the RFA, the EPA prepared an initial
regulatory flexibility analysis (IRFA) that examines the impact of the
proposed rule on small entities along with regulatory alternatives that
could minimize that impact. The complete IRFA is available for review
in the docket and is summarized here.
The IRFA describes the reason why the proposed rule is being
considered and describes the objectives and legal basis of the proposed
rule, as well as discusses related rules affecting the oil and natural
gas sector. The IRFA describes the EPA's examination of small entity
effects prior to proposing a regulatory option and provides information
about steps taken to minimize significant impacts on small entities
while achieving the objectives of the rule.
The EPA also summarized the potential regulatory cost impacts of
the proposed rule and alternatives in Section 2 of the RIA. The
analysis in the IRFA drew upon some of the same analyses and
assumptions as the analyses presented in the RIA. The IRFA analysis is
presented in its entirely in Section 4.3 of the RIA.
We estimated cost-to-sales ratios (CSR) for each small entity to
summarize the impacts of the proposed rule on small entities. In the
processing segment, we find that average compliance costs are expected
to be negative, and no entity has a cost-to-sales ratio greater than
either 1 percent or 3 percent. In the production segment, when expected
revenues from natural gas product recovery are included, 101 small
entities (7.2 percent) have cost-to-sales ratios greater than 1
percent, but none have cost-to-sales ratios greater than 3 percent.
When expected revenues from natural gas product recovery are excluded,
the number of small entities with cost-to-sales ratios greater than 1
percent increases to 331 (23 percent); about half of those small
entities (11 percent) also have cost-to-sales ratios greater than 3
percent.
The analysis above is subject to a number of caveats and
limitations. These are discussed in detail in the IRFA, as well as in
Section 4.3 of the RIA. As required by section 609(b) of the RFA, the
EPA also convened a Small Business Advocacy Review (SBAR) Panel to
obtain advice and recommendations from small entity representatives
that potentially would be subject to the rule's requirements. The SBAR
Panel evaluated the assembled materials and small-entity comments on
issues related to elements of an IRFA. A copy of the full SBAR Panel
Report is available in the rulemaking docket.
D. Unfunded Mandates Reform Act (UMRA)
The proposed NSPS and EG do not contain an unfunded mandate of $100
million or more as described in UMRA, 2 U.S.C. 1531-1538, and do not
significantly or uniquely affect small governments. The proposed NSPS
does not contain a Federal mandate that may result in expenditures of
$100 million or more for State, local, and Tribal governments, in the
aggregate or the private sector in any one year. For projected cost
estimates, see ``Regulatory Impact Analysis for the Proposed Standards
of Performance for New, Reconstructed, and Modified Sources and
Emissions Guidelines for Existing Sources: Oil and Natural Gas Sector
Climate Review'', which is available in the docket. The EG is proposed
under CAA section 111(d) and does not impose any direct compliance
requirements on designated facilities, apart from the requirement for
States to develop State plans. As explained in section XIV.G., the EG
also does not impose specific requirements on Tribal governments that
have designated facilities located in their area of Indian country. The
burden for States to develop State plans following promulgation of the
rule is estimated to be below $100 million in any one year. Thus, the
EG is not subject to the requirements of section 203 or section 205 of
the UMRA.
The NSPS and EG are also not subject to the requirements of section
203 of UMRA because, as described in 2 U.S.C. 1531-38, they contain no
regulatory requirements that might significantly or uniquely affect
small governments. The NSPS and EG action imposes no enforceable duty
on any State, local, or Tribal governments or the private sector.
Specifically, for the EG the State governments to which rule
requirements apply are not considered small governments. In light of
the interest among governmental entities, the EPA conducted pre-
proposal outreach with national organizations representing States and
Tribal governmental entities while formulating the proposed rule as
discussed in section VII. The EPA considered the stakeholders'
experiences and lessons learned to help inform how to better structure
this proposal and consider ongoing challenges that will require
continued collaboration with stakeholders. With this proposal, the EPA
seeks further input from States and Tribes. For public input to be
considered during the formal rulemaking, please submit comments on this
proposed action to the formal regulatory docket at EPA Docket ID No.
EPA-HQ-OAR-2021-0317 so that the EPA may consider those comments during
the development of the final rule.
E. Executive Order 13132: Federalism
Under Executive Order 13132, the EPA may not issue an action that
has federalism implications, that imposes substantial direct compliance
costs, and that is not required by statute, unless the Federal
Government provides the funds necessary to pay the direct compliance
costs incurred by State and local governments, or the EPA consults with
State and local officials early in the process of developing the
proposed action.
The proposed NSPS OOOOb does not have federalism implications. It
will not have substantial direct effects on the
[[Page 63261]]
States, on the relationship between the Federal Government and the
States, or on the distribution of power and responsibilities among the
various levels of government.
The proposed EG OOOOc may have federalism implications because
development of State plans may entail many hours of staff time to
develop and coordinate programs for compliance with the proposed rule,
as well as time to work with State legislatures as appropriate, and
develop a plan submittal. The Agency understands that the EG may impose
a burden on States and is committed to providing aid and guidance to
States through the plan development process. In the spirit of E.O.
13132 and consistent with the EPA policy to promote communications
between the EPA and State and local governments, the EPA specifically
solicits comment on this proposed rule from State and local officials
including information on costs associated with developing and
submitting State plans in accordance with EG OOOOc.
F. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments
This action has Tribal implications. However, it will neither
impose substantial direct compliance costs on Federally recognized
Tribal governments, nor preempt Tribal law, and does not have
substantial direct effects 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 E.O. 13175. 65 FR 67249 (November 9, 2000). The majority
of the designated facilities impacted by proposed NSPS and EG on Tribal
lands are owned by private entities, and Tribes will not be directly
impacted by the compliance costs associated with this rulemaking. There
would only be Tribal implications associated with this rulemaking in
the case where a unit is owned by a Tribal government or in the case of
the NSPS, a Tribal government is given delegated authority to enforce
the rulemaking. Tribes are not required to develop plans to implement
the EG under CAA section 111(d) for designated existing sources. The
EPA notes that this proposal does not directly impose specific
requirements on designated facilities, including those located in
Indian country, but before developing any standards for sources on
Tribal land, the EPA would consult with leaders from affected Tribes.
Consistent with previous actions affecting the Crude Oil and
Natural Gas source category, there is significant Tribal interest
because of the growth of the oil and natural gas production in Indian
country. Consistent with the EPA Policy on Consultation and
Coordination with Indian Tribes, the EPA will engage in consultation
with Tribal officials during the development of this action.
G. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks
This action is subject to E.O. 13045 (62 FR 19885, April 23, 1997)
because it is an economically significant regulatory action as defined
by E.O. 12866, and the EPA believes that the environmental health or
safety risk addressed by this action has a disproportionate effect on
children. Accordingly, the agency has evaluated the environmental
health and welfare effects of climate change on children. GHGs,
including methane, contribute to climate change and are emitted in
significant quantities by the oil and gas industry. The EPA believes
that the GHG emission reductions resulting from implementation of these
proposed standards and guidelines, if finalize will further improve
children's health. The assessment literature cited in the EPA's 2009
Endangerment Findings concluded that certain populations and life
stages, including children, the elderly, and the poor, are most
vulnerable to climate-related health effects. The assessment literature
since 2009 strengthens these conclusions by providing more detailed
findings regarding these groups' vulnerabilities and the projected
impacts they may experience. These assessments describe how children's
unique physiological and developmental factors contribute to making
them particularly vulnerable to climate change. Impacts to children are
expected from heat waves, air pollution, infectious and waterborne
illnesses, and mental health effects resulting from extreme weather
events. In addition, children are among those especially susceptible to
most allergic diseases, as well as health effects associated with heat
waves, storms, and floods. Additional health concerns may arise in low
income households, especially those with children, if climate change
reduces food availability and increases prices, leading to food
insecurity within households. More detailed information on the impacts
of climate change to human health and welfare is provided in section
III of this preamble.
H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
This action, which is a significant regulatory action under
Executive Order 12866, has a significant adverse effect on the supply,
distribution or use of energy. To estimate the potential impacts of the
proposed NSPS OOOOb and EG OOOOc on crude oil and natural gas
production, the EPA developed a pair of single-market, static partial-
equilibrium analyses of national crude oil and natural gas markets.
These analyses are presented in the RIA for this action, which is in
the public docket. We treat crude oil markets and natural gas markets
separately in these models. The EPA estimated that the proposed rule
could result in a maximum decrease in annual natural gas production of
about 249 million Mcf in 2026 (or about 0.8 percent of natural gas
production). We estimated the maximum annual reduction in crude oil
production would be about 12.2 million barrels (or about 0.3 percent of
crude oil production). Before 2026, the modeled market impacts are much
smaller than the 2026 impacts as only the incremental requirements
under the proposed NSPS OOOOb are assumed to be in effect. As
regulatory costs are projected to decline after 2026, the modelled
market impacts for years after 2026 are smaller than the peaks
estimated for 2026. As regulatory costs are projected to decline after
2026, the modelled market impacts for years after 2026 are smaller than
the peaks estimated for 2026. The energy impacts the EPA estimates from
these rules may be under- or over-estimates of the true energy impacts
associated with this action. For more information on the estimated
energy effects, please refer to the RIA for this rulemaking.
I. National Technology Transfer and Advancement Act (NTTAA)
This proposed action for NSPS OOOOb and EG OOOOc involves technical
standards.\350\ Therefore, the EPA conducted searches for the Standards
of Performance for New, Reconstructed, and Modified Sources and
Emissions Guidelines for Existing Sources: Oil and Natural Gas Sector
Climate Review through the Enhanced National Standards Systems Network
(NSSN) Database managed by the American National Standards Institute
[[Page 63262]]
(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 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 voluntary consensus standards (VCS)
for this rule. Two VCS were identified as an acceptable alternative to
EPA test methods for the purpose of this proposed rule. First, ANSI/
ASME PTC 19-10-1981, Flue and Exhaust Gas Analyses (Part 10) (manual
portions only and not the instrumental portion) was identified to be
used in lieu of EPA Methods 3B, 6, 6A, 6B, 15A and 16A. This standard
includes manual and instructional methods of analysis for carbon
dioxide, carbon monoxide, hydrogen sulfide, nitrogen oxides, oxygen,
and sulfur dioxide. 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 proposed rule in lieu of 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 September 10, 2021, memo titled, ``Voluntary Consensus Standard
Results for New, Reconstructed, and Modified Sources and Emissions
Guidelines for Existing Sources: Oil and Natural Gas Sector Climate
Review'' in the public docket. The EPA plans to propose the regulatory
language for NSPS OOOOb and EG OOOOc through a supplemental action. At
that time, the EPA will include any appropriate incorporation by
reference in accordance with requirements of 1 CFR 51.5 as discussed
below. The EPA anticipates that the following ten standards would be
incorporated by reference.
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\350\ The EPA is not proposing changes to previously conducted
searches for 40 CFR part 60, subparts OOOO and OOOOa. Therefore,
this section only describes proposed NSPS OOOOb and EG OOOOc
standards and searches.
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ASTM D86-96, Distillation of Petroleum Products (Approved
April 10, 1996) covers the distillation of natural gasolines, motor
gasolines, aviation gasolines, aviation turbine fuels, special boiling
point spirits, naphthas, white spirit, kerosines, gas oils, distillate
fuel oils, and similar petroleum products, utilizing either manual or
automated equipment.
ASTM D1945-03 (Reapproved 2010), Standard Test Method for
Analysis of Natural Gas by Gas Chromatography covers the determination
of the chemical composition of natural gases and similar gaseous
mixtures within a certain range of composition. This test method may be
abbreviated for the analysis of lean natural gases containing
negligible amounts of hexanes and higher hydrocarbons, or for the
determination of one or more components.
ASTM D3588-98 (Reapproved 2003), Standard Practice for
Calculating Heat Value, Compressibility Factor, and Relative Density of
Gaseous Fuel covers procedures for calculating heating value, relative
density, and compressibility factor at base conditions for natural gas
mixtures from compositional analysis. It applies to all common types of
utility gaseous fuels.
ASTM D4891-89 (Reapproved 2006), Standard Test Method for
Heating Value of Gases in Natural Gas Range by Stoichiometric
Combustion covers the determination of the heating value of natural
gases and similar gaseous mixtures within a certain range of
composition.
ASTM D6522-00 (Reapproved December 2005), Standard Test
Method for Determination of Nitrogen Oxides, Carbon Monoxide, and
Oxygen Concentrations in Emissions from Natural Gas-Fired Reciprocating
Engines, Combustion Turbines, Boilers, and Process Heaters Using
Portable Analyzers covers the determination of nitrogen oxides, carbon
monoxide, and oxygen concentrations in controlled and uncontrolled
emissions from natural gas-fired reciprocating engines, combustion
turbines, boilers, and process heaters.
ASTM E168-92, General Techniques of Infrared Quantitative
Analysis covers the techniques most often used in infrared quantitative
analysis. Practices associated with the collection and analysis of data
on a computer are included as well as practices that do not use a
computer.
ASTM E169-93, General Techniques of Ultraviolet
Quantitative Analysis (Approved May 15, 1993) provide general
information on the techniques most often used in ultraviolet and
visible quantitative analysis. The purpose is to render unnecessary the
repetition of these descriptions of techniques in individual methods
for quantitative analysis.
ASTM E260-96, General Gas Chromatography Procedures
(Approved April 10, 1996) is a general guide to the application of gas
chromatography with packed columns for the separation and analysis of
vaporizable or gaseous organic and inorganic mixtures and as a
reference for the writing and reporting of gas chromatography methods.
ASME/ANSI PTC 19.10-1981, Flue and Exhaust Gas Analyses
[Part 10, Instruments and Apparatus] (Issued August 31, 1981) covers
measuring the oxygen or carbon dioxide content of the exhaust gas.
EPA-600/R-12/531, EPA Traceability Protocol for Assay and
Certification of Gaseous Calibration Standards (Issued May 2012) is
mandatory for certifying the calibration gases being used for the
calibration and audit of ambient air quality analyzers and continuous
emission monitors that are required by numerous parts of the CFR.
The EPA determined that the ASTM and ASME/ANSI standards,
notwithstanding the age of the standards, are reasonably available
because it they are available for purchase from the following
addresses: American Society for Testing and Materials (ASTM), 100 Barr
Harbor Drive, Post Office Box C700, West Conshohocken, PA 19428-2959;
or ProQuest, 300 North Zeeb Road, Ann Arbor, MI 48106 and the American
Society of Mechanical Engineers (ASME), Three Park Avenue, New York, NY
10016-5990. The EPA determined that the EPA standard is reasonably
available because it is publicly available through the EPA's website:
http://nepis.epa.gov/Adobe/PDF/P100EKJR.pdf.
J. 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). The
documentation for this decision is contained in the RIA prepared under
E.O. 12866 for this proposal. In Section 4 of the RIA, the EPA presents
a qualitative discussion of the climate impacts of GHGs and
environmental justice. The section also presents a set of limited
quantitative environmental justice analyses focused on the current
distribution of VOC and HAP emissions from oil and natural gas sector.
These analyses evaluated baseline scenarios
[[Page 63263]]
and enabled us to characterize risks due to oil and natural gas VOC and
HAP emissions prior to implementation of the proposed rule. These
analyses potentially suggest that VOC and HAP emissions from the oil
and natural gas sector may disproportionately impact vulnerable
populations or overburdened communities under baseline scenarios;
however, various uncertainties and data gaps remain, and should be
taken into consideration when interpreting these results. Additionally,
we lack key information that would be needed to characterize post-
control risks under the proposed NSPS OOOOb and EG OOOOc or the
regulatory alternatives analyzed in the RIA, preventing the EPA from
analyzing spatially differentiated outcomes. While a definitive
assessment of the impacts of this proposed rule on minority
populations, low-income populations, and/or indigenous peoples was not
performed, the EPA believes that this action will achieve substantial
methane, VOC, and HAP emission reductions and will further improve
environmental justice community health and welfare. The EPA believes
that any potential environmental justice populations that may
experience disproportionate impacts in the baseline may realize
disproportionate improvements in air quality resulting from emission
reductions.
In addition, the EPA provided the public, including those
communities disproportionately impacted by the burdens of pollution,
opportunities for meaningful engagement with the EPA on this action. A
summary of outreach activities conducted by the Agency and what we
heard from communities is provided in section VI of this preamble.
List of Subjects in 40 CFR Part 60
Environmental protection, Administrative practice and procedure,
Air pollution control, Reporting and recordkeeping requirements.
Michael S. Regan,
Administrator.
[FR Doc. 2021-24202 Filed 11-5-21; 4:15 pm]
BILLING CODE 6560-50-P