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

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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \198\ Document ID No. EPA-HQ-OAR-2021-0295-0033.
---------------------------------------------------------------------------

    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

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.
---------------------------------------------------------------------------

    \199\ ``Determination of Volatile Organic Compound and
Greenhouse Gas Leaks Using Optical Gas Imaging'' located at Docket
ID No. EPA-HQ-OAR-2021-0317.
---------------------------------------------------------------------------

    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-

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
---------------------------------------------------------------------------

    \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

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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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

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

(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

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

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,''

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

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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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

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).
---------------------------------------------------------------------------

    \210\ See Document ID No. EPA-HQ-OAR-2010-0505-7632 at page 4-
194.
---------------------------------------------------------------------------

    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

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.
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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

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.
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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

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.
---------------------------------------------------------------------------

    \217\ See Document ID No. EPA-HQ-OAR-2010-0505-7632 at page 4-
221.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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

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\
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    \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.
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    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.
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    \226\ See 85 FR 57412 and section <IP_ADDRESS> of the 2020 TSD.
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    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

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.
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    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