are proposing for flares that are not continuously monitored as
described in section III.N.1 of this preamble. We recognize that
because these releases are not through engineered nozzles that can be
designed to promote mixing and combustion efficiency, the combustion
efficiency of these releases can be highly variable. Reporters may use
a lower combustion efficiency but may not use higher combustion
efficiency than 92 percent for natural gas released directly in an
explosion or fire. We request comment on these proposed provisions. We
request comment and supporting data on the proposed maximum combustion
efficiency of 92 percent for the portion of the total volume of natural
gas released via explosion or fire.
    The proposed requirement to calculate and report GHG emissions from
other large release events would be limited to events that release at
least 250 mtCO2e per event or have a CH4 emission
rate of 100 kg/hr or greater at any point in time. The 250
mtCO2e per event threshold is equivalent to approximately
500,000 standard cubic feet (scf) of pipeline quality natural gas. For
events that span two reporting years, we are proposing that these
thresholds apply to the event, not a portion of the event within a
given reporting year. We selected these proposed thresholds to capture
reporting for large emission events, such as well blowouts, well
releases, and large pressure relief venting.
    In order to establish the mass CO2e per event reporting
threshold, we assessed other emission sources that could qualify as
large. Specifically, we considered completions of hydraulically
fractured wells that are not controlled (i.e., not performed using
reduced emission completions (RECs)) to be large emissions events. RECs
are completions where gas flowback emissions from the gas outlet of the
separator that are otherwise vented are captured, cleaned, and routed
to the flow line or collection system, re-injected into the well or
another well, used as an on-site fuel source, or used for other useful
purpose that a purchased fuel or raw material would serve, with de
minimis direct venting to the atmosphere. Based on analysis of GHGRP
data for wells that are not RECs and that vent, the U.S. GHG Inventory
developed an average emission factor of about 360 mtCO2e per
event for these completions.\27\ Because this is an average emission
factor, some uncontrolled hydraulically fractured completions will be
below this average and some above. From this assessment, we considered
250 mtCO2e to be a reasonable emissions threshold for a
``large'' event.
---------------------------------------------------------------------------

    \27\ U.S. EPA. Inventory of U.S. Greenhouse Gas Emissions and
Sinks 1990-2014. EPA 430-R-16-002. April 2016. Available at https://www.epa.gov/ghgemissions/inventory-us-greenhouse-gas-emissions-and-sinks-1990-2014 and in the docket for this rulemaking, Docket Id.
No. EPA-HQ-OAR-2023-0234.
---------------------------------------------------------------------------

    While 250 mtCO2e is much lower than the emissions from
the Aliso Canyon or Ohio well blowout releases, we determined that a
250 mtCO2e threshold would be needed to capture most well
blowouts. There are limited data to quantify an ``average'' well
blowout, but the 2021 U.S. GHG Inventory uses an oil well blowout
emission factor of 2.5 MMscf per event. As this is an average, many
well blowouts may be less than this average value. The 250
mtCO2e threshold is approximately equivalent to 500,000 scf
of natural gas, which aligns with the lower range of well blowouts
expected based on the average emission factor of 2.5 MMscf per event.
This value also aligns with the definitions of ``major release'' in New
Mexico Administrative Code (NMAC) section <IP_ADDRESS>, which requires
reporting under NMAC section <IP_ADDRESS>.
    We also tentatively find that the proposed 250 mtCO2e
threshold (approximately equivalent to 500,000 scf natural gas release)
is a reasonable threshold for requiring individual assessments of
releases. In subpart Y (Petroleum Refineries), we established event-
specific emission calculation requirements for startup, shutdown, or
malfunction releases to a flare exceeding 500,000 scf per day (40 CFR
98.253(b)(1)(iii)). While the subpart Y threshold is per day rather
than per event, it is also specific to flared emissions. For flared
emissions to exceed a 250 mtCO2e threshold, approximately 4
MMscf of natural gas would have to be released to the flare, which is
well above the subpart Y ``per day'' threshold for flares. Thus, we
propose that the 250 mtCO2e per event threshold is an
appropriate size threshold for requiring event-specific emission
calculations to be performed. More information regarding our review and
characterization of types of other large release events is included in
the subpart W TSD, available in the docket for this rulemaking, Docket
Id. No. EPA-HQ-OAR-2023-0234. Emissions from smaller or routine release
events would still be reported, as applicable, under the source-
specific calculation and reporting requirements in subpart W.
    We are also proposing a 100 kg/hr CH4 emission threshold
to align with the super-emitter response program proposed in the NSPS
OOOOb. These emissions are generally intermittent, with widely varying
durations. Releases from maintenance activities, for example, may occur
for only a few hours, but these large, short events can

significantly contribute to a facility's emissions. The proposed
emission rate threshold for a super-emitter emissions event under NSPS
OOOOb provides a means to get information for these large, shorter
duration releases. Therefore, we are proposing that the 100 kg/hr
CH4 emission threshold be applied as an instantaneous
emissions rate threshold, such that any emissions from any other large
release event that emits CH4 at a rate of 100 kg/hr or more
at any point in time must be reported.
    With a combination of both a cumulative mass emissions per event
threshold and the instantaneous 100 kg/hr CH4 emission rate
threshold, the EPA is requesting comment whether a larger cumulative
mass emissions per event threshold is reasonable. Specifically, we
understand that the Pipeline and Hazardous Materials Safety
Administration (PHMSA) includes, in the definition of ``incident'' at
49 CFR 191.3, an ``unintentional estimated loss of three million cubic
feet or more.'' As many subpart W facilities are required to keep
records of these incidents, we request comment on the use of a 1,500
mtCO2e per event threshold, which would be approximately
equivalent to a 3 million cubic feet release of natural gas. We request
comment on whether the CO2e mass threshold is appropriate
for considering emissions from events such as fires, or if the
threshold should be expressed as a loss of 3 million cubic feet or more
of natural gas, whether directly emitted or partially burned via a
fire. We also request comment on whether these thresholds should be
assessed per event within the calendar year, rather than just per
event. We propose that the thresholds for other large release events
would be evaluated on a per event basis because then all events are
considered consistently regardless of when they occur. For example,
consider a 400 mtCO2e event that spans two calendar years,
with 200 mtCO2e released in each calendar year. As proposed,
the reporter would be required to report the other large release event
in each of the corresponding reporting years. If, however, the
thresholds were instead evaluated on a per event within a calendar year
basis, this emissions event would not qualify as an other large release
event in either reporting year. There may be cases where limiting the
thresholds to events to within a calendar year could reduce the number
of events reported without significantly missing emissions and
potentially limiting the number of report resubmissions. For example,
if the 400 mtCO2e event that spanned 2 calendar years
resulted in 40 mtCO2e of emission in reporting year 1 and
360 mtCO2e of emissions in reporting year 2, then if the
thresholds were evaluated on a per event per calendar year basis, only
the emissions in reporting year 2 would be required to be reported.
Under the thresholds as proposed, the 40 mtCO2e of emission
in reporting year 1 would be required to be reported. Depending on when
the other large release event was identified and start date determined,
this may require resubmission of a previously submitted subpart W
report. We request comment on whether the other large release event
thresholds should be limited to releases within a single calendar year.
    We are proposing a definition of ``other large release events'' in
40 CFR 98.238 to clarify the types of releases that must be
characterized for this new emissions source and specify that other
large release events include, but are not limited to, maintenance
events, well blowouts, well releases, releases from equipment rupture,
fire, or explosions. Currently, there are no calculation methodologies
or reporting requirements for these types of large releases in subpart
W. The proposed definition would also include large pressure relief
valve releases from process equipment other than onshore production and
onshore petroleum and natural gas gathering and boosting storage tanks
that are not included in the blowdown definition. The proposed
definition of other large release events excludes pressure relief valve
releases from hydrocarbon liquids storage tanks because the calculation
methodology for storage tanks is expected to account for these releases
via either the proposed requirements to account for collection
efficiency when emissions are observed from the thief hatch or the
additional term in the emissions equation for when there is a stuck
dump valve. While subpart W currently includes emission factors for
pressure relief devices, these equipment leak emission factors only
account for leaks past a pressure relief valve that is in the closed
position, not releases from the complete opening of these valves. The
proposed definition specifies that pressure relief valve releases from
onshore production and onshore petroleum and natural gas gathering and
boosting storage tanks would not be considered other large release
events because the calculation methodology for these storage tanks
currently assumes all flash gas will be emitted. As noted in section
III.K of this preamble, pressure relief emission releases from onshore
production and onshore petroleum and natural gas gathering and boosting
storage tanks generally occur from the thief hatch and these releases
must be accounted for when calculating the fraction of flash gas that
is recovered or sent to a flare, if applicable. A more detailed
discussion of certain other emissions events we have identified and
expect to be subject to the ``other large release events'' proposed
amendments is included in the subpart W TSD available in the docket for
this rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
    As part of the proposed definition of ``other large release
events'' in 40 CFR 98.238, we are also proposing that other large
release events include releases from equipment for which the existing
calculation methodologies in subpart W would significantly
underestimate the episodic nature of these emissions. For example,
subpart W contains population emission factors and leaker emission
factors for estimating equipment leak emissions for storage wellheads.
Thus, it is possible to argue that subpart W includes calculation
methodologies for the equipment responsible for the Aliso Canyon
release. However, the calculation methodologies in subpart W do not
accurately estimate emissions from such an uncharacteristically large
release event because such events are infrequent such that they may not
exist when measurement studies are conducted. Additionally, if we
proposed to instead revise the emission factors under the existing
methodologies to account for such an event, the resulting calculation
would likely yield erroneously high emissions from normal operations
for most reporting facilities. Thus, we determined that it is more
accurate for facility-specific reporting to account for these large
releases on a per event basis. Therefore, if a single leak or event has
emissions that exceed the emissions estimated by an applicable
methodology included in subpart W by 250 mtCO2e or more on a
per event basis, or 100 kg/hr of CH4 or more as an
instantaneous rate at any time during an event, we are proposing that
such releases would be included in the definition of ``other large
release events'' and that reporters would be required to calculate and
report the GHG emissions from these events using the proposed
requirements for other large release events. We are proposing in 40 CFR
98.233(y)(1)(ii) that this provision does not require the direct
measurement of every release, such as measurement of every leak
identified during an equipment leak monitoring survey. However, we are
proposing to require that if the owner or operator has credible
information that demonstrates

that the release meets or exceeds or may reasonably be anticipated to
meet or exceed (or to have met or have exceeded) the emissions
calculated by the source-specific methodology by 250 mtCO2e
or more, or 100 kg/hr of CH4 or more, then the release must
be quantified and, if the thresholds are confirmed to be exceeded,
reported as an other large release event. We consider credible
information would include, but is not limited to, data from monitoring
or measurement data completed by the facility, information from
notifications as a potential super-emitter emissions event under the
super-emitter provisions of NSPS OOOOb at proposed 40 CFR 60.5371b or
data of similar quality as that provided through the provisions of NSPS
OOOOb at proposed 40 CFR 60.5371b that is received by the facility. We
anticipate that we would take into consideration what is included in
the final NSPS OOOOb regarding such notifications in the types of
information that would be considered credible for these provisions in
subpart W, if finalized. The owner or operator would be required to
consider all credible information they have regarding the release in
complying with this requirement.
    Further, we are proposing to define the terms ``well release'' and
``well blowout'' in 40 CFR 98.238 to assist reporting facilities with
differentiating between these types of release events that could
potentially occur at wells. We find that a well blowout is generally
distinguished by a complete loss of well control for a long duration of
time and a well release is characterized as a short period of
uncontrolled release (not the controlled pre-separation stage of well
flowback in a hydraulically fractured completion) followed by a period
of controlled release in which control techniques were successfully
implemented.
    Finally, we are proposing a series of reporting requirements in 40
CFR 98.236(y) related to the type, location, duration, calculations,
and emissions of each ``other large release event.'' Specifically, we
are proposing that reporters provide the location, a description of the
release (from a specified list that includes an ``other (specify)''
option for releases that are not described well with the list
provided), a description of the technology or method used to identify
the release, volume of gas released, volume fractions of CO2
and CH4 in the gas released, and CO2 and
CH4 emissions for each ``other large release event.'' We are
also proposing that reporters would provide the start date and time of
the release, duration of the release, and the method used to determine
the start date and time (options would include a pressure monitor, a
temperature monitor, other monitored process parameter, most recent
monitoring or measurement survey showing no large release, or the
default assumption that the release started 182 days prior to the
documented end of the release (this would be the required assumption if
they do not have monitored data associated with the release). We are
also proposing that reporters provide a general description of the
event and indicate whether the ``other large release event'' was also
identified as a potential super-emitter emissions event under the
super-emitter provisions of NSPS OOOOb at 40 CFR 60.5371b or an
applicable approved state plan or applicable Federal plan in 40 CFR
part 62.
    We are proposing that reporters that received super-emitter
emissions event notifications would be required to report information
on each release notification received, including latitude and longitude
of the release, whether the release was received under the super-
emitter provisions of NSPS OOOOb at 40 CFR 60.5371b or an applicable
approved state plan or applicable Federal plan in 40 CFR part 62 or
another notifier. If the notification is from another notifier, the
reporter would provide the name of the notifier, the remote sensing
method used, the date and time of the measurement, the measured
emission rate, and uncertainty bounds on the emission rate, if provided
by the notifier. We are also proposing that, for each notification
received, facilities would report the type of event resulting in the
emissions (e.g., normal operations, a planned maintenance event,
leaking equipment, malfunctioning equipment or device, or undetermined
cause) and an indication of whether the emissions identified from the
event are included as an other large release event or as another source
required to be reported under subpart W. If the emissions identified
via the notification are not included in emissions reported under
subpart W, we are proposing that the reporter provide a reason (e.g.,
the location of the emissions as provided in the notification do not
belong to the facility; the emissions could not be verified or
corroborated during site inspection or facility data records;
information was determined to not be credible and basis for the
determination). This information would support EPA verification and
ensure accuracy of the emissions reported under other large release
events.
    As part of the GHGRP verification process, the EPA reviews data
provided in submitted reports to identify potential errors in the
reported data based on the different values reported and the
calculation methodology. The EPA requests comment on the need to
establish additional requirements for third-party notifiers and the
verification of third-party notifications. Generally, verification of
GHGRP reports is conducted while a facility is entering data into the
e-GGRT system and after the report is officially submitted. The EPA
requests comment on the need for EPA verification support or an advance
verification process during the reporting year for assessments of
third-party notifications. Currently, facilities with questions about
reporting requirements submit inquiries via the e-GGRT Help Desk to get
questions answered regarding monitoring or reporting requirements. We
request comment on whether this existing process is adequate for
supporting questions regarding individual third-party notifications
received by a reporter and request suggestions on how the EPA
verification process could better support the other large release event
calculation and reporting requirements.
    The supplemental proposal for NSPS OOOOb and EG OOOOc, as described
in section II of this preamble, included a matrix for alternative
screening approaches for fugitive emissions from well sites and
compressor stations that would allow the use of advanced measurement
technologies to detect emissions under the proposed NSPS OOOOb and EG
OOOOc. As part of that proposal, the EPA also requested comment on how
to evaluate and design a requirement for owners and operators to
investigate and remediate large emission events, which could include
the use of alternative screening techniques and advanced measurement
technologies, all of which, if finalized, could potentially be used to
identify ``other large release events'' under subpart W. While some
methods that could be used to identify and estimate the magnitude of
these ``other large release events,'' such as monitors installed on
mobile vehicles or aircraft or CH4 satellite imagery, would
not be specifically included as measurement methods listed in 40 CFR
98.234 of subpart W, these methods may be used to quantify the
emissions release for ``other large release events'' under the
``engineering estimates'' and ``best available data'' provisions of the
proposed calculation methodology. To improve the EPA's understanding of
the

technologies and methods used to identify reported ``other large
release events,'' including the impact of periodic screenings with
advanced measurement technologies on the identification of large
release events, we are proposing reporting provisions that would
require reporters to indicate whether each ``other large release
event'' was identified as part of compliance with NSPS OOOOb or the
applicable state plan or applicable Federal plan in 40 CFR part 62.

C. New and Additional Emission Sources

    Sources of emissions that are required to be reported to subpart W
are listed in 40 CFR 98.232 for each industry segment, with the
methodology and reporting requirements for each source provided in 40
CFR 98.233 and 98.236, respectively. The EPA finalized this list of
emission sources for each of the eight original industry segments as
part of the 2010 Final Rule and identified emission sources for the
Onshore Petroleum and Natural Gas Gathering and Boosting and Onshore
Natural Gas Transmission Pipeline industry segments when those segments
were added to subpart W in 2015 (80 FR 64262, October 22, 2015). Per
the TSD for the 2010 Final Rule (hereafter referred to as the ``2010
subpart W TSD''),\28\ there were several factors that impacted the
EPA's decision on whether an emissions source should be included for
reporting. These factors included how significant the contribution of
the source was to the U.S. GHG Inventory, the type of emission expected
from the source (vented versus fugitive), the best practice monitoring
methods available to measure emissions from the source, accessibility
of the emission source, geographical dispersion of the emission source,
and the applicability of population versus leaker factors.
---------------------------------------------------------------------------

    \28\ Greenhouse Gas Emissions Reporting from the Petroleum and
Natural Gas Systems Industry: Background Technical Support. November
2010. Docket Id. No. EPA-HQ-OAR-2009-0923-3610; also available in
the docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
---------------------------------------------------------------------------

    The EPA has evaluated the sources covered under subpart W in
comparison with present-day inventories of the oil and gas industry,
such as the 2022 U.S. GHG Inventory \29\ and the American Petroleum
Institute (API) 2021 Compendium of Greenhouse Gas Emissions
Methodologies for the Natural Gas and Oil Industry (2021 API
Compendium).\30\ The EPA also reviewed stakeholder feedback, including
public comments from the 2022 Proposed Rule, on missing sources of
emissions from subpart W. As a result, the EPA is proposing to add
several emission sources identified in this review that are anticipated
to have a meaningful impact on reported emissions, are commonplace in
the oil and gas industry, and/or have existing emission calculation
methodologies and reporting provisions in the current subpart W
regulatory text. For some of these emission sources, discussed in
additional detail in section III.C.1 of this preamble, reporting is
currently required for some, but not all, industry segments in which
they exist. Other proposed emission sources, discussed in additional
detail in sections III.C.2 through 5 of this preamble, are not
currently required to be reported for any industry segments in which
they exist. The proposed addition of sources to subpart W would be
expected to enhance the overall quality of the data collected under the
GHGRP and improve the accuracy of total emissions reported from
facilities, consistent with Congress' direction in the IRA and section
II.A of this preamble.
---------------------------------------------------------------------------

    \29\ Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-
2020. U.S. EPA. April 2022. Available at https://www.epa.gov/ghgemissions/inventory-us-greenhouse-gas-emissions-and-sinks-1990-2020 and in the docket for this rulemaking, Docket Id. No. EPA-HQ-
OAR-2023-0234.
    \30\ Compendium of Greenhouse Gas Emissions Methodologies For
The Natural Gas And Oil Industry. Produced by URS Corporation for
American Petroleum Institute. November 2021. Available at https://www.api.org/-/media/files/policy/esg/ghg/2021-api-ghg-compendium-110921.pdf. Available in the docket for this rulemaking, Docket Id.
No. EPA-HQ-OAR-2023-0234.
---------------------------------------------------------------------------

    The following sections detail the proposed additions of emission
sources to subpart W.
1. Current Subpart W Emission Sources Proposed for Additional Industry
Segments
    Upon review of the U.S. GHG Inventory and the 2021 API Compendium,
as well as other publications,\31\ the EPA determined that several of
the emission sources included in at least one industry segment in
subpart W are not currently required to be reported by facilities in
all the industry segments in which those sources exist. As such,
consistent with section II.A of this preamble, we are proposing to add
requirements to report CO2, CH4, and nitrous
oxide (N2O) emissions (as applicable for the source type)
from the following sources under 40 CFR 98.232 and 98.236(a): \32\
---------------------------------------------------------------------------

    \31\ For example, American Petroleum Institute (API). Liquefied
Natural Gas (LNG) Operations Consistent Methodology for Estimating
Greenhouse Gas Emissions. Prepared for API by The LEVON Group, LLC.
Version 1.0, May 2015. Available in the docket for this rulemaking,
Docket Id. No. EPA-HQ-OAR-2023-0234.
    \32\ It should be noted that the EPA did not identify any
subpart W emission sources missing from the Onshore Petroleum and
Natural Gas Gathering and Boosting industry segment.

 Onshore petroleum and natural gas production: Blowdown vent
stacks
 Onshore natural gas processing: Natural gas pneumatic device
venting, Hydrocarbon liquids and produced water storage tank emissions
 Onshore natural gas transmission compression: Dehydrator vents
 Underground natural gas storage: Dehydrator vents, Blowdown
vent stacks, Condensate storage tanks
 LNG storage: Blowdown vent stacks, Acid gas removal unit vents
 LNG import and export equipment: Acid gas removal unit vents
 Natural gas distribution: Natural gas pneumatic device
venting, Blowdown vent stacks
 Onshore natural gas transmission pipeline: Equipment leaks at
transmission company interconnect metering-regulating stations,
Equipment leaks at farm tap and/or direct sale metering-regulating
stations, Transmission pipeline equipment leaks

    We are also proposing several revisions that would facilitate
implementation of the proposal to require reporting of these emission
sources from additional industry segments. We are proposing to revise
the name of the current emission source type ``onshore production and
onshore petroleum and natural gas gathering and boosting storage
tanks'' to ``hydrocarbon liquids and produced water storage tanks'' and
revise ``storage tank vented emissions'' to ``hydrocarbon liquids and
produced water storage tank emissions'' throughout subpart W. The
proposed removal of the reference to ``onshore production and onshore
petroleum and natural gas gathering and boosting'' would reflect a more
appropriate name corresponding to the proposed addition of the
reporting of these storage tank emissions for the Onshore Natural Gas
Processing industry segment; the addition of ``produced water'' to the
name is discussed in detail in section III.C.3 of this preamble.
Additionally, we are proposing to revise the emission source type name
in 40 CFR 98.233(k) and 98.236(k) from ``transmission storage tanks''
to ``condensate storage tanks,'' which would reflect a more appropriate
name corresponding to the proposed addition of the reporting of these
storage tank emissions for the

Underground Natural Gas Storage industry segment.\33\
---------------------------------------------------------------------------

    \33\ Revisions are also proposed to 40 CFR 98.232(e)(3) to
reference the source as ``condensate storage tanks.''
---------------------------------------------------------------------------

    We are also proposing revisions to the calculation methodologies
and/or emissions reporting structure for each of these emission source/
industry segment combinations that would be needed in 40 CFR 98.233 and
98.236, respectively. For industry segments for which we are proposing
to additionally require reporting of emissions from AGR vents,
dehydrator vents, hydrocarbon liquids and produced water storage tank
emissions, and condensate storage tank emissions, we are proposing that
reporters would use the same calculation methods and report the same
information as reporters in the industry segments in which those source
types are already reported. For these sources, the EPA is not aware of
differences in the operation of the emission sources between industry
segments that would necessitate separate calculation methodologies. The
remainder of this section describes additional proposed amendments to
40 CFR 98.233.
    For the proposed addition of natural gas pneumatic device venting
as an emission source for the Onshore Natural Gas Processing industry
segment, we are proposing that those facilities would use the proposed
calculation methodologies as described in section III.E of this
preamble. For any reporters to the Onshore Natural Gas Processing
industry segment that would use proposed Calculation Methodology 3, the
emission factors we are proposing are the same as the proposed revised
emission factors for the Onshore Natural Gas Transmission Compression
and Underground Natural Gas Storage industry segments. As noted in the
subpart W TSD (available in the docket), the data available to develop
emission factors for the Onshore Natural Gas Processing industry
segment are limited, and because operations defined as being part of
these three industry segments are similar and can occur at the same
facilities, the EPA has historically applied the same population and
leaker emission factors to these three segments (e.g., equipment
leaks). See section III.E of this preamble for additional details about
the proposed calculation methodologies.
    As noted earlier in this section, we are proposing to add blowdown
vent stack reporting to the Onshore Petroleum and Natural Gas
Production, Underground Natural Gas Storage, LNG Storage, and Natural
Gas Distribution industry segments. Subpart W currently requires
reporting of blowdowns either using flow meter measurements (existing
40 CFR 98.233(i)(3)) or using unique physical volume calculations by
equipment or event types (existing 40 CFR 98.233(i)(2)). There are two
lists of equipment or event types. One applies to the Onshore Natural
Gas Processing, Onshore Natural Gas Transmission Compression, LNG
Import and Export Equipment, and Onshore Petroleum and Natural Gas
Gathering and Boosting segments (proposed 40 CFR 98.233(i)(2)(iv)(A),
as discussed in section III.J.2 of this preamble). The other list of
equipment or event types (in proposed 40 CFR 98.233(i)(2)(iv)(B), as
discussed in section III.J.2 of this preamble) was developed for the
Onshore Natural Gas Transmission Pipeline industry segment when that
segment was added to subpart W in 2015 (80 FR 64275, October 22, 2015).
To allow reporters in the new industry segments to calculate emissions
by equipment or event types, the EPA is proposing to specify the
appropriate list of equipment or event types. We are proposing that
facilities in the Onshore Petroleum and Natural Gas Production,
Underground Natural Gas Storage, and LNG Storage industry segments
following the methodology in 40 CFR 98.233(i)(2) would be required to
categorize blowdown vent stack emission events into the seven
categories provided in proposed 40 CFR 98.233(i)(2)(iv)(A), as the
types of blowdown vent stack emission events for these segments are
similar to those for the segments currently required to categorize
under this provision.
    We are proposing that facilities in the Natural Gas Distribution
industry segment would be required to categorize blowdowns into the
eight categories listed in proposed 40 CFR 98.233(i)(2)(iv)(B), as the
types of blowdowns that occur in the Natural Gas Distribution industry
segment are expected to be pipeline blowdowns similar to those in the
Onshore Natural Gas Transmission Pipeline industry segment. We note
that during the early stages of our review of potential new sources, we
considered whether to add emissions from mishaps (dig-ins) in the
Natural Gas Distribution industry segment as a new emission source.
However, mishaps (dig-ins) are already included on the list of
equipment and event types in proposed 40 CFR 98.233(i)(2)(iv)(B),
specifically emergency shutdowns including pipeline incidents as
defined in 49 CFR 191.3. Therefore, a proposed amendment is not
necessary to include those events.
    We are proposing one other amendment related to the calculation of
emissions from blowdown vent stacks. The EPA previously determined that
for reporters in the Onshore Petroleum and Natural Gas Gathering and
Boosting industry segment using the methodology provided in existing 40
CFR 98.233(i)(2) and equation W-14A, it is reasonable to allow
engineering estimates based on best available information when
determining temperature and pressure for emergency blowdowns, due to
the geographically dispersed nature of the facilities in this industry
segment. As discussed in section III.J.3 of this preamble, we are
proposing to also allow engineering estimates based on best available
information when determining temperature and pressure for emergency
blowdowns for the Onshore Natural Gas Transmission Pipeline industry
segment, as facilities in this industry segment are also geographically
dispersed. Due to the fact that facilities in the Onshore Petroleum and
Natural Gas Production and Natural Gas Distribution industry segments
are similarly geographically dispersed, we are proposing that reporters
in those industry segments using the methodology provided in 40 CFR
98.233(i)(2) and equation W-14A would also be allowed to use
engineering estimates based on best available information available
when determining temperature and pressure for emergency blowdowns.
    For the Onshore Natural Gas Transmission Pipeline industry segment,
as noted earlier in this section, we are proposing to add reporting of
emissions from equipment leaks from transmission pipelines,
transmission company interconnect metering-regulating stations, and
farm tap and/or direct sale stations. The EPA proposes to add these
sources to the calculation methodologies provided in 40 CFR 98.233(r),
with associated proposed updates to the variable definitions in
equation W-32A to include components in the Onshore Natural Gas
Transmission Pipeline industry segment. We are also proposing to add
default CH4 population emission factors for the components specified in
this paragraph at facilities in the Onshore Natural Gas Transmission
Pipeline industry segment in proposed Table W-5 of subpart W. The EPA
derived these proposed emission factors from the 1996 Gas Research
Institute (GRI)/EPA study Methane Emissions from the Natural Gas
Industry (hereafter referred to as ``the 1996 GRI/EPA study''),
specifically

Volumes 9 and 10.\34\ The precise derivation of the proposed emission
factors is discussed in more detail in the subpart W TSD, available in
the docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234. We
are proposing that emissions from these components would be reported
using population emission factors, as we are not aware of any currently
available information or data that could be used to develop leaker
emission factors from transmission pipelines, transmission company
interconnect metering-regulating stations, or farm tap and/or direct
sale stations. We are seeking comments on whether there are study data
available which could be used to develop default leaker factors whereby
subpart W could include the use of equipment leak surveys, default
component-specific leaker emission factors, and the calculation method
in 40 CFR 98.233(q) an as option for transmission pipeline facilities
to quantify emissions from transmission company interconnect metering-
regulating stations, or farm tap and/or direct sale stations.
Similarly, we are seeking comment on whether an option to survey
components at transmission company interconnect metering-regulating
stations, or farm tap and/or direct sale stations using the existing
methods in subpart W in 40 CFR 98.234 (e.g., EPA Method 21, optical gas
imaging (OGI)) and directly measuring and reporting emissions
consistent with proposed 40 CFR 98.233(q)(3) should be provided; or
whether a methodology in which a multi-year leak survey cycle and the
application of either default emission factors or measurements used
with the methods provided in 40 CFR 98.233(q) should be provided
analogous to the methodology provided for above grade transmission-
distribution transfer stations should be provided. We are specifically
interested in comments on which approach would be preferred and the
supporting rationale.
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    \34\ Methane Emissions from the Natural Gas Industry, Volume 9:
Underground Pipelines, Final Report (GRI-94/0257.26 and EPA-600/R-
96-080i) and Volume 10: Metering and Pressure Regulating Stations in
Natural Gas Transmission and Distribution, Final Report (GRI-94/
0257.27 and EPA-600/R-96-080j). Gas Research Institute and U.S.
Environmental Protection Agency. June 1996. Available in the docket
for this rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
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    Separately, concerning the quantification of emissions from
transmission pipelines, we are seeking comments on alternative methods
for surveying for equipment leaks as well as quantifying and reporting
emissions from these emission sources. We are specifically interested
in what survey techniques would be appropriate and why, including
supporting information on specific instruments and their detection
capabilities and whether certain methods would be more suitable for the
survey of pipeline leaks than others. We are also seeking comment on
what quantification techniques would be best suited for measuring
emissions from pipeline leaks and whether these techniques require
digging down to the pipeline in order to quantify emissions and also
verify pipeline characteristics. As an example, the EPA performed a
review of recent study data (Weller et al. 2020) that used an
alternative technology, namely AMLD, for the purposes of performing
surveys to identify leaks and as a method to quantify emissions from
pipeline leaks. For the reasons discussed in section III.Q.2 of this
preamble and discussed in more detail in the subpart W TSD, available
in the docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234,
we are not proposing amendments based on that study or use of that
technology. Instead, we are seeking comment on the scope and frequency
of leak detection surveys and measurements for transmission pipelines.
We are considering whether we should require annual surveys of the
entire pipeline system or whether a reduced frequency of survey (i.e.,
partial surveys over a multi-year survey cycle in which the entire
system is surveyed during the survey cycle and approximately equal
portions of the system are surveyed each year of the multi-year survey
cycle) is more appropriate and why. Finally, we are seeking comment on
whether facilities should be permitted to develop facility-specific
pipeline emission factors based on direct measurements and if so, what
the appropriate number of measurements should be for determining a
representative emission factor for each pipeline material including
supporting rationale.
2. Nitrogen Removal Units
    The EPA is proposing to revise existing 40 CFR 98.232, 98.233(d),
and 98.236(d) to add calculation and reporting requirements for
CH4 emissions from nitrogen removal units used in the
Onshore Petroleum and Natural Gas Production, Onshore Natural Gas
Processing, Onshore Petroleum Natural Gas Gathering and Boosting, LNG
Storage, and LNG Import and Export Equipment industry segments.
Nitrogen removal units remove nitrogen from the raw natural gas stream
to meet pipeline requirements and for compressing natural gas into
LNG.35 36 The nitrogen removal unit typically follows in
series after other process units that remove acid gas (e.g., CO2,
hydrogen sulfide), water, and heavy hydrocarbons. It is estimated that
11 percent of current daily production and 16 percent of known gas
reserves in the U.S. contain some nitrogen.\37\ Methane emissions from
nitrogen removal units occur from the vent and as fugitives. A nitrogen
removal unit separates the nitrogen gas from the CH4
resulting in an outlet CH4 stream that contains approximately 2 to 5
percent nitrogen\38\ and an outlet nitrogen stream that can contain 1
to 5 percent CH4 (EPA 2005).\39\ Optimization of the
nitrogen removal unit can reduce CH4 in the outlet nitrogen
stream to 2 percent (EPA 2005) and even to 1 percent CH4 by
volume.\40\ The EPA GasSTAR program already accounts for CH4
emissions from nitrogen removal unit vents and fugitives.
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    \35\ Kuo, J.C., K.H. Wang, C. Chen. Pros and cons of different
Nitrogen Removal Unit (NRU) technology. 7 (2012) 52-59. Journal of
Natural Gas Science and Engineering. July 2012. Available in the
docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
    \36\ Park, J., D. Cho. Decision methodology for nitrogen removal
process in the LNG plant using analytic hierarchy process. Journal
of Industrial and Engineering Chemistry. 37 (2016) 75-83. 2016.
Available in the docket for this rulemaking, Docket Id. No. EPA-HQ-
OAR-2023-0234.
    \37\ Kuo 2012.
    \38\ Weidert, D.J., and R.B. Hopewell. Holding the Key.
Hydrocarbon Engineering. August 2016. Available in the docket for
this rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
    \39\ EPA 2005. Optimizing Nitrogen Rejection Units, Lessons
Learned from Natural Gas STAR. Gas Processors Association, Devon
Energy, Enogex, Dynegy Midstream Services, and EPA's Natural Gas
STAR Program. Presented at Processors Technology Transfer Workshop.
April 22, 2005. Available in the docket for this rulemaking, Docket
Id. No. EPA-HQ-OAR-2023-0234.
    \40\ Nitrogen Rejection Unit Optimization, PRO Fact Sheet No.
905. U.S. Environmental Protection Agency, Partner Reported
Opportunities (PROs) for Reducing Methane Emissions. 2011. Available
in the docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2023-
0234.
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    Based upon a 2002 field study conducted at four natural gas
processing plants,\41\ the EPA estimates that emissions from nitrogen
removal unit vents that would be reported to the GHGRP would be
approximately 2,400 mt CH4 per year. For more information on
the estimation of potential CH4 emissions from nitrogen
removal unit venting see the subpart W TSD, available in the docket for
this

rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
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    \41\ Identification and Evaluation of Opportunities to Reduce
Methane Losses at Four Gas Processing Plants. Prepared for Gas
Technology Institute under U.S. EPA Grant No. 827754-01-0.
Clearstone Engineering. June 20, 2002. Available in the docket for
this rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
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    The EPA is proposing to define ``nitrogen removal unit'' in 40 CFR
98.238 as a process unit that separates nitrogen from natural gas using
various separation processes (e.g., cryogenic units, membrane units)
and ``nitrogen removal unit vent emissions'' as the nitrogen gas
separated from the natural gas and released with CH4 and
other gases to the atmosphere, flare, or other combustion unit. The EPA
is proposing to amend 40 CFR 98.232(c)(17), 98.232(d)(5),
98.232(g)(10), 98.232(h)(9), and 98.232(j)(3) to add nitrogen removal
unit vents to the list of source types for which the industry segments
previously specified would be required to report emissions.
Corresponding additions are proposed at 40 CFR 98.236(a) to add
nitrogen removal units to the list of equipment and activities that
would be reported for each of these industry segments.
    The EPA is proposing CH4 emission calculation
methodologies for nitrogen removal units that are identical to the
existing calculation methodologies in 40 CFR 98.233(d) for AGRs (which
currently apply to calculating emissions of CO2). These
methods include use of vent meters, engineering calculations based upon
flowrate of gas streams, or calculation using simulation software.
Further, the EPA is proposing to add relevant reporting elements for
CH4 emissions from nitrogen removal units to 40 CFR
98.236(d) for each of the proposed allowable calculation methodologies.
As a part of this proposed rulemaking, the EPA is also proposing to
require the reporting of CH4 emissions from AGR vents. Refer
to section III.F.1 of this preamble for more detailed discussion of the
calculation methodologies, including additional revisions proposed as
part of this rulemaking and which we propose would also apply to
nitrogen removal units.
    The EPA is proposing that nitrogen removal unit vents routed to a
flare would follow the same calculation requirements as other flared
emission source types in proposed 40 CFR 98.233(n) and that flared
nitrogen removal unit emissions (CO2, CH4, and
N2O) would be reported under proposed 40 CFR 98.236(n)
separately from vented nitrogen removal unit emissions
(CH4). The flared nitrogen removal unit emissions would be
included with ``other'' flared source types for purposes of the
proposed disaggregation provisions in proposed 40 CFR 98.233(n)(10) and
proposed 40 CFR 98.236(n)(19). See section III.N of this preamble for
more information on the proposed flaring calculation and reporting
provisions.
    The EPA is seeking comment on the proposal to require reporting of
CH4 emissions from nitrogen removal unit venting, including
the estimated magnitude of emissions, which industry segments, if any,
should be required to report nitrogen removal unit vent emissions, and
whether the existing calculation methods for AGR vents are appropriate
and if there are other methods the EPA should consider.
3. Produced Water Tanks
    The EPA is proposing to add CH4 emissions from produced
water tanks to subpart W. The EPA is proposing to define ``produced
water'' consistent with the definition in the effluent guidelines for
the oil and gas extraction point source category (40 CFR 435.11(bb)),
which is the water (brine) brought up from the hydrocarbon-bearing
strata during the extraction of oil and gas, and can include formation
water, injection water, and any chemicals added downhole or during the
oil/water separation process. Produced water is the largest wastewater
source by volume generated during oil and gas extraction.\42\ The ratio
of produced water to recovered hydrocarbon is extremely variable across
the U.S., ranging from less than 1:1 to more than 100:1.\43\ In the
2022 U.S. GHG Inventory emissions estimate for 2020, the EPA estimated
approximately 140,300 mt CH4 emissions from produced water
tanks associated with natural gas wells and 88,600 mt CH4
emissions from produced water tanks associated with oil wells.
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    \42\ Summary of Input on Oil and Gas Extraction Wastewater
Management Practices Under the Clean Water Act. Final Report. EPA-
821-S19-001. U.S. Environmental Protection Agency, Engineering and
Analysis Division, Office of Water. Washington, DC May 2020.
    \43\ Ibid.
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    The EPA is proposing amendments to 40 CFR 98.233(j) to require
reporters with atmospheric pressure storage tanks receiving produced
water to calculate CH4 emissions using any of the three
calculation methodologies specified in 40 CFR 98.233(j)(1) through
(3).\44\ For facilities with produced water storage tanks electing to
model their CH4 emissions consistent with 40 CFR
98.233(j)(1), the EPA is proposing to allow facilities to select any
software option that meets the requirements currently stated in 40 CFR
98.233(j)(1) (i.e., to select a modeling software that uses the Peng-
Robinson equation of state, models flashing emissions from produced
water, and speciates CH4 emissions that result when the
produced water from the separator or non-separator equipment enters an
atmospheric pressure storage tank), but we request comment on whether
the Peng-Robinson equation of state should be used for produced water
tanks and whether there are other parameters that should be considered
requirements for modeling emissions from produced water tanks. We
expect that modeling flashing emissions from produced water tanks would
calculate accurate estimates of CH4 emissions, as it is
widely accepted that these models provide accurate estimates of
flashing emissions from hydrocarbon liquids atmospheric storage tanks.
Therefore, we expect process simulation software options such as Bryan
Research & Engineering (BRE)'s ProMax[supreg] \45\ (ProMax) would be
appropriate for modeling produced water CH4 emissions. For
example, BRE has produced a white paper regarding ProMax's accuracy in
predicting produced water emissions.\46\ However, per the 2021 API
Compendium, the EPA is aware that API 4697 E&P Tanks v3.0 program \47\
is not appropriate for determining emissions from produced water tanks,
as the program's methodology is based on properties specific to crude
oil. Given that API's E&P Tanks software cannot model produced water
tanks, we are proposing to specifically state in 40 CFR 98.233(j)(1)
that API's E&P Tanks should only be used for modeling atmospheric
storage tanks receiving hydrocarbon liquids.
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    \44\ As part of the proposed amendment to require reporters to
calculate and report emissions from produced water tanks, we are
also proposing conforming edits throughout subpart W to refer to
hydrocarbon liquids and produced water instead of just hydrocarbon
liquids.
    \45\ BRE Promax[supreg] software available from BRE website
(https://www.bre.com/).
    \46\ Are Produced Water Emission Factors Accurate? Bryan
Research & Engineering, Inc. Available in the docket for this
rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
    \47\ E&P Tanks v3.0 software and the user guide (Publication
4697) formerly available from the API website.
---------------------------------------------------------------------------

    There are several documents that address produced water emissions;
however, the emission factors used in all of these documents all
ultimately trace back to the 1996 GRI/EPA study.\48\

Therefore, the EPA is proposing to add CH4 emission factors
to 40 CFR 98.233(j)(3) that were developed as part of the 1996 GRI/EPA
study,\49\ which is consistent with the factors used by the U.S. GHG
Inventory.\50\ The emission estimates from the 1996 GRI/EPA study were
estimated using an ASPEN PLUS process simulation assuming the natural
gas industry produces 497 million barrels of salt water annually,
including approximately 100 million barrels from coal bed
CH4 wells; 70 percent of the water from gas wells is
reinjected with the remaining 30 percent stored in atmospheric tanks;
and hydrocarbon composition is 100 percent CH4.\51\ The 1996
GRI/EPA study estimated produced water emissions for salt contents of
2, 10, and 20 percent, and pressures of 50, 250, and 1,000 pounds per
square inch. The 2021 API Compendium (Table 6-26) provides the 1996
GRI/EPA emission factors converted from units of million pounds per
year to units of metric tons per thousand barrels (based upon the
assumption of 497 million barrels of produced water annual production).
In addition, average emission factors were calculated for each
pressure.
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    \48\ Studies referencing the 1996 GRI/EPA study produced water
emission factors include: (1) 2021 API Compendium; (2) Oil & Gas
Production Protocol, Annex II to the General Reporting Protocol,
Version 1.0. The Climate Registry. February 2010; (3) 2011 Oil and
Gas Emission Inventory Enhancement Project for CenSARA States.
Produced by ENVIRON International Corporation and Eastern Research
Group, Inc. (ERG) for Central States Air Resources Agencies
(CenSARA). December 2012; and (4) Instructions for Using the 2017
EPA Nonpoint Oil and Gas Emissions Estimation Tool, Production
Module. Produced by Eastern Research Group, Inc. (ERG) for U.S.
Environmental Protection Agency. October 2019.
    \49\ Methane Emissions from the Natural Gas Industry, Volume 6:
Vented and Combustion Source Summary, Final Report. GRI-94/0257.23
and EPA-600/R-96-080f. Gas Research Institute and U.S. Environmental
Protection Agency. June 1996. Available in the docket for this
rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
    \50\ U.S. EPA. Inventory of U.S. Greenhouse Gas Emissions and
Sinks 1990-2019: Updates for Produced Water Emissions. April 2021.
Available in the docket for this rulemaking, Docket Id. No. EPA-HQ-
OAR-2023-0234.
    \51\ Atlas of Gas Related Produced Water for 1990. 95/0016.
Produced by Energy Environmental Research Center, University of
North Dakota, and ENSR Consulting and Engineering for Gas Research
Institute. May 1995. Available in the docket for this rulemaking,
Docket Id. No. EPA-HQ-OAR-2023-0234.
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    We also propose to add reporting requirements for produced water
tanks. The provisions in 40 CFR 98.236(j)(1) are proposed to be revised
to refer to both hydrocarbon liquid and produced water atmospheric
storage tanks. Additionally, we are proposing to add reporting
requirements to 40 CFR 98.236(j)(2) for total annual produced water
volumes for each pressure range, estimates of the fraction of produced
water throughput that is controlled by flares and/or vapor recovery,
counts of controlled and uncontrolled produced water tanks, and annual
CH4 emissions vented directly to atmosphere from produced
water tanks. Flared produced water tank emissions would be reported
under 40 CFR 98.236(n), as proposed in section III.N.2 of this
preamble. Industry segments required to report emissions from produced
water tanks would include Onshore Petroleum and Natural Gas Production,
Onshore Petroleum and Natural Gas Gathering and Boosting, and Onshore
Natural Gas Processing. The EPA is also proposing to revise the
emission source type name in 40 CFR 98.233(j) and 40 CFR 98.236(j) from
``onshore production and onshore petroleum and natural gas gathering
and boosting storage tanks'' to ``hydrocarbon liquids and produced
water storage tanks'' to reflect the proposed addition of produced
water tanks. The EPA is also proposing to revise the source type
provided in 40 CFR 98.232(c)(10) and 40 CFR 98.232(j)(6) to
``Hydrocarbon liquid and produced water storage tank emissions'' which
reflects the addition of produced water tanks.
4. Mud Degassing
    The EPA is proposing to add a new emission source type to subpart W
for emissions from drilling mud degassing. The proposed amendments for
this new source type would add calculation and reporting requirements
for CH4 emissions from mud degassing associated with well
drilling for onshore petroleum and natural gas production facilities in
40 CFR 98.232(c), 98.233(dd), and 98.236(dd). In this proposal, the EPA
is not proposing to require the reporting of CO2 emissions
from this source. Based on available research, it appears that
CH4 is the primary GHG emitted from this source, while
emissions of CO2 are expected to be very small. However, as
noted later in this section, the EPA is seeking comment on requiring
reporting of CO2 emissions from mud degassing, including
comment on the expected magnitude of CO2 emissions from mud
degassing and appropriate calculation methods for CO2
emissions from mud degassing.
    The term ``drilling mud,'' also referred to as ``drilling fluid,''
refers to a class of viscous fluids used during the drilling of oil and
gas wells. Throughout the drilling process, drilling mud is pumped
continuously through the drill string and out the bit to cool and
lubricate the drill bit, carry cuttings away from the drill bit, and to
maintain the desired pressure within the well. The three types of
drilling mud used in the oil and gas industry are water-based, oil-
based, and synthetic-based muds. The density of the mud can be
controlled to counteract formation pressure, and drilling mud adds
stability to the bore hole. During drilling, gas is freed from rock
drilled out of the wellbore and becomes entrained in the drilling mud
that is being pumped continuously through the drill string.
    As drilling mud circulates through the wellbore, natural gas and
heavier hydrocarbons can become entrained in the mud. Mud degassing
refers to the practice of extracting the entrained gas from drilling
mud once it is outside the wellbore. Gas entrained in the drilling mud
is separated from the mud in a mud separator and then vented directly
to the atmosphere or flared. The entrained gas contains CH4
and can contain other pollutants such as volatile organic compounds
(VOC) and possibly CO2, depending on the gas characteristics
of the hydrocarbon-bearing zones through which the borehole is drilled,
including the target zone. Although the majority of natural gas will be
released when the mud passes through the mud separator, small
quantities of natural gas will remain entrained in the drilling mud and
in the rock cuttings after the mud passes through the traps. These
small quantities will eventually be released to the atmosphere as the
drilling mud and associated cuttings are stored, processed and
disposed.
    Based on our review of the available information regarding mud
degassing emissions, we note that mud degassing has been included only
in a limited number of U.S. state-level, regional and national
inventories of the onshore oil and gas production segments, mostly due
to a lack of sufficient data to characterize the emissions. In a 1977
EPA publication titled, Atmospheric Emissions from Offshore Oil and Gas
Development and Production,\52\ the EPA estimated two total hydrocarbon
(THC) emission factors in units of emissions per drilling day, one for
water-based mud degassing and the other for oil-based mud degassing,
based on engineering calculations. The 1977 EPA publication does not
include emission factors for synthetic-based mud. Several entities,
such as the state of New York and the Central States Air Resources
Agency (CenSARA), have incorporated estimates for mud degassing in
their inventory estimates. A CenSARA study conducted in 2011 developed
default emission factors derived from the 1977 EPA report.\53\ The
CenSARA study

added a THC emission factor for synthetic drilling muds and also
provided emission factors in mt CH4 per drilling day. The
THC emission factors are 881.84 pounds per drilling day for water-based
muds and 198.41 pounds per drilling day for oil-based and synthetic
drilling muds. The CH4-specific emission factors are 0.2605
mt CH4 per drilling day for water-based muds and 0.0586 mt
per drilling day for oil-based and synthetic drilling muds; they are
based on an assumption of 83.85 percent CH4 in the gas
stream vented from mud degassing. The CenSARA methodology does allow
for adjustment of the CH4 default emission factors to local
conditions by multiplying the nationwide emission factor to the ratio
of the local CH4 mole percent of vented gas to the mole
percent of CH4 from the vented gas used to derive the
CenSARA emission factor (83.85).
---------------------------------------------------------------------------

    \52\ Atmospheric Emissions from Offshore Oil and Gas Development
and Production. Produced by Energy Resources Co. for Environmental
Protection Agency. Available in the docket for this rulemaking,
Docket Id. No. EPA-HQ-OAR-2023-0234.
    \53\ 2011 Oil and Gas Emission Inventory Enhancement Project for
CenSARA States. Produced by ENVIRON International Corporation for
Central States Air Resources Agencies. November 2011. Available at
https://www.deq.ok.gov/wp-content/uploads/air-division/EI_OG_Final_Report_CenSara_122712.pdf and in the docket for this
rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
---------------------------------------------------------------------------

    For its emissions inventory, the state of New York based its
emission factor for mud degassing on the CenSARA study, while also
concluding that communication with experts indicated that there were
not any more recent estimates available.\54\ Furthermore, New York only
adopted the CenSARA CH4 emission factor of 0.2605 mt
CH4 per drilling day for water-based muds. This factor
serves as the single emission factor for New York. Unlike CenSARA, New
York's calculation methods do not provide the ability for users to make
a local adjustment to the emission factor. Both CenSARA and New York
define the number of drilling days as the completion date minus the
spud date.
---------------------------------------------------------------------------

    \54\ New York State Oil and Gas Sector: Methane Emissions
Inventory. Produced by Abt Associates for New York State Energy
Research and Development Authority. November 2022. Available at
https://www.nyserda.ny.gov/-/media/Project/Nyserda/Files/Publications/Energy-Analysis/22-38-New-York-State-Oil-and-Gas-Sector-Methane-Report-acc.pdf and in the docket for this rulemaking,
Docket Id. No. EPA-HQ-OAR-2023-0234.
---------------------------------------------------------------------------

    The U.S. GHG Inventory does not currently include mud degassing
emissions. In 2020, the EPA released a memorandum discussing the
potential inclusion of CH4 emissions estimates for mud
degassing as an update under consideration for the U.S. GHG Inventory,
based on the THC emission factors presented in the 1977 EPA
publication.\55\ Specifically, the memorandum provided emission factors
of 0.32 mt CH4 per drilling day for water-based drilling
muds and 0.07 mt CH4 per drilling day for oil-based drilling
muds in the discussion. The CH4 emission factor presented for
consideration for updating the U.S. GHG Inventory assumed a default
CH4 fraction (by weight) of 61.2 percent for associated gas.
The EPA has not to date incorporated the use of these emission factors,
and mud degassing is not included in the current U.S. GHG Inventory.
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    \55\ U.S. EPA. Inventory of U.S. Greenhouse Gas Emissions and
Sinks 1990-2019: Update under Consideration for Mud Degassing
Emissions. September 2020. Available at https://www.epa.gov/sites/default/files/2020-09/documents/ghgi-webinar2020-degassing.pdf and
in the docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2023-
0234.
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    Separately, API published updated CH4 and whole gas
emission factors based on the emission factors from the 1977 EPA
publication in their 2021 API Compendium.\56\ API's updated
CH4 emission factors are based on a gas content of 65.13
weight percent CH4, derived from sample data provided in the
1977 EPA publication. While including the same THC and CH4
emission factors as CenSARA, API specifies that these are for offshore
drilling only. The API Compendium presents lower emission factors for
onshore drilling. In the 2021 API Compendium, API stated that it
adjusted the 1977 EPA values for borehole size and porosity to better
reflect those used in onshore drilling. API's onshore production
CH4 emission factors are 0.0458 mt per drilling day for
water-based mud and 0.0103 mt per drilling day for oil-based and
synthetic muds. Similar to CenSARA, the API methodology allows for the
nationwide emission factors to be adjusted to local conditions by
applying a ratio of the mole percent in vented gas from degassing at
local operations to the nationwide mole percent of 83.85.
---------------------------------------------------------------------------

    \56\ Compendium of Greenhouse Gas Emissions Methodologies For
The Natural Gas And Oil Industry. Produced by URS Corporation for
American Petroleum Institute. November 2021. Available at https://www.api.org/-/media/files/policy/esg/ghg/2021-api-ghg-compendium-110921.pdf and in the docket for this rulemaking, Docket Id. No.
EPA-HQ-OAR-2023-0234.
---------------------------------------------------------------------------

    Although most efforts have focused on the development of emission
factors for mud degassing, the 2021 API Compendium also encourages
operators to use site-specific CH4 (and CO2 if
present) measurements to estimate emissions if possible. Generally,
measured data would involve use of mud-logger services with hydrocarbon
gas sensors. In some cases, operators may use gas chromatography, but
gas chromatography alone does not allow calculation of gas
concentration in the mud. Gas emissions would be determined by using
the volumetric flowrate of the mud, the amount of time of mud flow and
the concentration of CH4 and CO2 in the mud.
    After careful consideration of the available literature and well
drilling and mud degassing practices, the EPA is proposing two options
in a new paragraph (40 CFR 98.233(dd)) to measure CH4
emissions from drilling mud degassing: use of measurements taken
through mudlogging and gas detection at representative wells and use of
emission factors and activity counts.
    Calculation Method 1 would require the reporter to calculate
CH4 emissions from mud degassing for a representative well.
To qualify as a representative well, the well would be required to be
drilled in the same sub-basin and at the same targeted total depth from
the surface as the wells it is representative of. Calculation Method 1
would be required to be used when the reporter has taken mudlogging
measurements, including gas trap-derived gas concentration and mud
pumping rate, for at least one well in the sub-basin at the approximate
total depth. A CH4 emissions rate from mud degassing would
be calculated for the representative well and the CH4
emission rate for the well would be applied to the total time drilling
mud is circulated through the wellbore during drilling for each of the
other wells drilled in the same sub-basin and targeting the same
approximate total depth from surface in the reporting year.
    The operator would be required to identify and calculate natural
gas emissions for a new representative well at least once every 2 years
for each sub-basin and targeted depth within the facility to ensure
that the emissions from representative wells are representative of the
operating and drilling practices within each applicable sub-basin in
the facility. In the Onshore Petroleum and Natural Gas Production
industry segment, facilities are defined at the basin-level. In the
first year of reporting, however, the operator may use measurements
from the prior reporting year if measurements from the current
reporting year are not available.
    Proposed Calculation Method 1 uses a three-step approach to
calculate emissions from mud degassing for each well in a particular
sub-basin and at the same approximate total targeted depth. In the
first step, reporters would calculate CH4 emissions for the
representative well using proposed equation W-41. For this step, the
reporter would need to know the average efflux mud rate from the mud
pump in gallons per minute (gpm),

``MRr''; the total amount of time in minutes that drilling
mud is circulated in the representative well, ``Tr''; the
percentage of the fluid flow that is gas, ``Xn''; and the
measured mole concentration of CH4, ``GHGCH4.''
If a representative well cannot be identified because mudlogging was
not used for any well within the same sub-basin and at the same
targeted approximate total depth, the reporter may choose a
representative well within the facility that is drilled into the same
formation and at the same approximate total depth.
    In the second step, reporters would calculate the CH4
emissions rate for the representative well using proposed equation W-
42. The emissions rate would be derived by dividing the representative
well's total annual CH4 emissions, ``Es,CH4,r,''
by the total time that drilling mud is circulated in the representative
well, ``Tr.'' In the third step, reporters would apply the
CH4 emissions rate calculated in the second step to other
wells in the sub-basin that are at the same approximate total depth to
derive the total volume of CH4 emissions for each well at
that depth. In this step, the reporter would calculate total
CH4 emissions for each well, ``p,'' in the same sub-basin
and at the same approximate total depth as the representative well
using proposed equation W-43, where the total time drilling mud is
circulated in the well would be multiplied by the representative well's
emissions rate, ``ERs,CH4,p,'' determined using equation W-
42 in step 2.
    If mudlogging measurements were not taken, the EPA is proposing
that reporters would use Calculation Method 2 and determine emissions
from mud degassing using proposed equation W-44, which incorporates the
nationwide emission factors provided by the CenSARA study.
Specifically, the EPA is proposing an emission factor of 0.2605 mt
CH4 per drilling day per well for water-based mud and a
factor of 0.0586 mt CH4 per drilling day per well for oil-
based and synthetic drilling muds. As noted by New York state, there
are limited data and few studies on mud degassing emissions. The EPA is
proposing these emission factors as an alternative calculation method
because our assessment of the available literature is that these
proposed emission factors are generally appropriate if measurements are
not available. In addition, the emission factors proposed are
consistent with those of several organizations that calculate and
publish emissions from mud degassing in their inventories. As noted
previously in this section, these factors are based on a CH4
mole percent of 83.85 in the gas stream vented from mud degassing. The
EPA is not proposing to allow adjustment of the emission factors for
local conditions under proposed Calculation Method 2 because the use of
emission factors under this proposed calculation method would only be
allowed if the operator did not have site-specific measurements (i.e.,
would not have the measurement that would be the basis of such an
adjustment).
    Although the EPA is proposing to use the nationwide emission
factors provided by the CenSARA study, the EPA is proposing to define
the number of drilling days differently than the study. Rather than
considering the first drilling day to be the day the well is spudded,
we are proposing that the total number of drilling days is the sum of
all days from the first day that the borehole penetrates the first
hydrocarbon-bearing zone through the completion of all drilling
activity. The EPA believes that penetration of the first hydrocarbon-
bearing zone more accurately reflects the point in time where
CH4 will start becoming entrained in drilling mud. The EPA
is also defining the last drilling day as the day drilling mud ceases
to be circulated in the well. Reporters would calculate emissions for
each well by multiplying the emission factor by the number of drilling
days per well per year.
    The EPA is seeking comment on these calculation methodologies,
including whether there are calculation methodologies other than the
proposed methods that the EPA should consider for calculating
CH4 emissions from mud degassing. The EPA is also seeking
comment on CO2 emissions from mud degassing, including the
magnitude of CO2 emissions from this source type, whether
emissions of CO2 should be reported, and suggested
calculation methods for CO2 emissions. The EPA is also
seeking comment on whether to consider mud weight balance in the
derivation of emission factors, and if so, how to incorporate such
considerations. Underbalanced, balanced, and overbalanced all lead to
varying hydrostatic weights of the mud and could affect the flow of
hydrocarbons into the well bore, possibly impacting emissions
calculations. However, we are not aware of any studies to date that
have considered mud weight balance.
    In addition to the calculation requirements, the EPA is proposing
corresponding reporting requirements for emissions by well in 40 CFR
98.236(dd). Specifically, for all wells with mud degassing emissions
that use Calculation Method 1, the reporter would report the well ID
number for each well for which mud degassing emissions are calculated,
the approximate total depth of the well in feet below surface, and the
total time in minutes that drilling mud is circulated in the well.
Reporters would also report whether the drilling mud used was water-
based, oil-based, or synthetic. Additionally, for a well that is not a
representative well, reporters would report the well ID number of the
representative well that was used to derive the CH4
emissions rate used to calculate emissions from the non-representative
well.
    For reporters using Calculation Method 1, the EPA is also proposing
to require additional data on representative wells, including the
average mud flow rate in gpm, the concentration of natural gas in the
drilling mud, the measured mole fraction of CH4 in the
drilling mud, and the CH4 emissions rate. For reporters
using Calculation Method 2, the EPA is proposing that reporters would
report the well ID number for each well for which mud degassing
emissions are calculated, the total number of drilling days at each
well, and whether the drilling mud used was water-based, oil-based, or
synthetic. Annual CH4 emissions in mt CH4 would
be reported for each well whether emissions were calculated using
Calculation Method 1 or Calculation Method 2.
    To clearly define the emission source type and parameters to use in
the emissions calculations, the EPA is proposing to define three new
terms in 40 CFR 98.238. The EPA is proposing to define ``drilling mud''
as a mixture of clays and additives with water, oil, or synthetic
materials continuously pumped through the drill string and out the bit
while drilling to cool and lubricate the drill bit and to move cuttings
through the wellbore to the surface. The EPA is proposing to define
``drilling mud degassing'' as the practice of safely removing pockets
of free gas entrained in the drilling mud once it is outside of the
wellbore. ``Mud rate'' is proposed to mean the pumping rate of the mud
by the mud pumps, usually measured in gpm. The mud rate would be an
input to proposed equation W-41.
    Finally, we note that in proposing these new requirements, we
considered adding mud degassing emissions to two existing source
categories in the Onshore Petroleum and Natural Gas Production industry
segment, well completions and workovers with hydraulic fracturing and
well completions and workover without hydraulic fracturing, rather than
proposing calculation and reporting

requirements for mud degassing as a new emissions source. Upstream oil
and gas development is undertaken in two stages, exploration and
production. The exploration stage consists of well drilling followed by
well completion, including casing of the well and hydraulically
fracturing the well (in the case of hydraulically fractured
completion). However, for purposes of this proposal, the EPA has
determined that well drilling activities are a distinct activity
separate from well completion. For example, a common practice in the
oil and gas industry is to drill a well but leave the borehole
uncompleted (referred to in the oil and gas industry as ``drilled but
uncompleted''). These boreholes are left uncompleted for a period of
time until economic conditions improve, completion crews are available,
or for other reasons. Even without completion, the drilling activity
still has the potential to produce emissions. Therefore, the EPA is
proposing drilling mud degassing as a new emissions source type source
for onshore petroleum and natural gas production facilities.
5. Crankcase Venting
    The EPA is proposing to add calculation and reporting requirements
for CH4 emissions from a new emission source type, crankcase
ventilation from RICE or GT used in the Onshore Petroleum and Natural
Gas Production, Onshore Natural Gas Processing, Onshore Natural Gas
Transmission Compression, Underground Natural Gas Storage, LNG Storage,
LNG Import and Export Equipment, Natural Gas Distribution, and Onshore
Petroleum and Natural Gas Gathering and Boosting industry segments.
Crankcase ventilation is the process of venting or removing blow-by
from the void spaces of an internal combustion engine outside of the
combustion cylinders to prevent excessive pressure build-up within the
engine.\57\ This proposed source does not include ingestive systems
that vent blow-by into the engine where it is returned to the
combustion process.\58\
---------------------------------------------------------------------------

    \57\ Cox, J. ``Managing Engine Blow-by with Crankcase
Ventilation Systems.'' The Solberg Blog, June 17, 2022. Available at
 https://www.solbergmfg.com/en/resources/blog/crankcase-ventilation-system-for-engine-in-the-pow and in the docket for this rulemaking,
Docket Id. No. EPA-HQ-OAR-2023-0234.
    \58\ See, e.g., Caterpillar. Application & Installation Guide:
Crankcase Ventilation Systems. LEBW4958-04. 2015. Available in the
docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
---------------------------------------------------------------------------

    The EPA first proposed including ``crankcase vents'' in subpart W
in the January 2016 proposal to add leaker emission factors (81 FR
4987, January 29, 2016). At that time in 2016, the EPA proposed to add
new monitoring methods for detecting leaks from oil and gas equipment
in the petroleum and natural gas systems source category consistent
with the leak detection methods in the then proposed NSPS OOOOa (80 FR
56593, September 18, 2015). Specifically, in 2016, the EPA proposed
aligning subpart W equipment components with the 2015 proposed NSPS
OOOOa definition of ``fugitive emissions component,'' which was ``any
component that has the potential to emit fugitive emissions of
[CH4] or VOC at a well site or compressor station site,
including but not limited to valves, connectors, pressure relief
devices, open-ended lines, access doors, flanges, closed vent systems,
thief hatches or other openings on storage vessels, agitator seals,
distance pieces, crankcase vents, blowdown vents, pump seals or
diaphragms, compressors, separators, pressure vessels, dehydrators,
heaters, instruments, and meters'' (80 FR 56593, September 18, 2015).
The proposed NSPS OOOOa definition of ``fugitive emissions component''
also indicated that it did not include devices that ``vent as part of
normal operations.'' Commenters on the proposed NSPS OOOOa indicated
that some of the examples listed within the proposed definition of
``fugitive emissions component'' did include devices that vent as part
of normal operations, including crankcase vents.\59\ As a result of
these comments, the final definition for ``fugitive emissions
component'' in the NSPS OOOOa (81 FR 35824, June 3, 2016) did not
include the reference to ``crankcase vents'' or other types of devices
that vent as part of normal operations, consistent with the EPA's
stated intent in the 2015 NSPS OOOOa proposal not to include those
devices in the definition. The 2016 promulgated amendments to subpart W
for fugitive emissions aligned with the definition of ``fugitive
emissions component'' in the final NSPS OOOOa.
---------------------------------------------------------------------------

    \59\ U.S. EPA. EPA's Responses to Public Comments on the EPA's
Oil and Natural Gas Sector: Emission Standards for New,
Reconstructed, and Modified Sources. Chapter 4--Fugitives
Monitoring. May 2016. Available as EPA-HQ-OAR-2010-0505-7632 and in
the docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
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    We have estimated sector-wide emissions from crankcase ventilation
using data from a 2015 study published by Johnson et al., Methane
Emissions from Leak and Loss Audits of Natural Gas Compressor Stations
and Storage Facilities.\60\ In this study, the audit of three natural
gas compressor stations and two natural gas storage facilities yielded
an average ratio of crankcase-to-exhaust emissions of 14.4 percent. The
study authors compared total emissions rate (crankcase plus exhaust)
against literature values of a four-cylinder lean burning engine in
EPA's Compilation of Air Pollutant Emission Factors (AP-42).\61\ The
literature value overpredicted the combined emissions by 11.4 percent,
which slightly exceeded the calculated uncertainty for exhaust
emissions of 7.2 percent. This comparison indicates the measured value
offers a reasonable estimate of CH4 loss from natural gas
compressor stations and storage facilities. Based on this study, the
EPA conservatively estimates that the total CH4 emissions
from crankcase ventilation that could be reported to the GHGRP would be
approximately 800,000 mt per year, assuming crankcase emissions are
14.4 percent of combustion emissions from all proposed industry
segments. For more information on the estimation of potential
CH4 emissions from crankcase venting, see the subpart W TSD,
available in the docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-
2023-0234.
---------------------------------------------------------------------------

    \60\ Johnson, D.R., et al. 2015. ``Methane Emissions from Leak
and Loss Audits of Natural Gas Compressor Stations and Storage
Facilities.'' Environ. Sci. Technol. 2015, 49, 13, 8132-8138. July
4, 2015. Available at https://doi.org/10.1021/es506163m and in the
docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
    \61\ U.S. EPA. AP-42 Compilation of Air Pollutant Emission
Factors, 5th ed. Volume I, Chapter 3: Stationary Internal Combustion
Sources: Section 3.1 Stationary Gas Turbines and Section 3.2 Natural
Gas-fired Reciprocating Engines. Available at https://www.epa.gov/air-emissions-factors-and-quantification/ap-42-fifth-edition-volume-i-chapter-3-stationary-0 and in the docket for this rulemaking,
Docket Id. No. EPA-HQ-OAR-2023-0234.
---------------------------------------------------------------------------

    The API provided an emission factor for CH4 from
crankcase ventilation in their 2021 API Compendium.\62\ API's emission
factor was developed from results from Phase II of a comprehensive
measurement program conducted to determine cost-effective directed
inspection and maintenance control opportunities for reducing natural
gas losses due to fugitive equipment leaks and avoidable process
inefficiencies. Phase II of the program was conducted at five gas
processing plants, seven gathering compressor stations, and twelve well
sites during 2004 and 2005.\63\
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    \62\ Compendium of Greenhouse Gas Emissions Methodologies For
The Natural Gas And Oil Industry. Produced by URS Corporation for
American Petroleum Institute. November 2021. Available at https://www.api.org/-/media/files/policy/esg/ghg/2021-api-ghg-compendium-110921.pdf and in the docket for this rulemaking, Docket Id. No.
EPA-HQ-OAR-2023-0234.
    \63\ Cost-Effective Directed Inspection and Maintenance Control
Opportunities at Five Gas Processing Plants and Upstream Gathering
Compressor Stations and Well Sites. EPA Phase II Aggregate Site
Report prepared for U.S. EPA Natural Gas STAR Program by Natural Gas
Machinery Laboratory, Clearstone Engineering Ltd., and Innovative
Environmental Solutions, Inc. March 2006. Available at https://www.epa.gov/sites/default/files/2016-08/documents/clearstone_ii_03_2006.pdf and in the docket for this rulemaking,
Docket Id. No. EPA-HQ-OAR-2023-0234.

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

    Based on the information provided in this section, the EPA is
proposing to add 40 CFR 98.233(ee) to provide a component-level average
emission factor approach for estimating emissions for crankcase
ventilation based on the number of crankcase vents on RICE or GT in the
facility. The proposed CH4 emission factor for crankcase
ventilation is 2.28 standard cubic feet per hour per source, as
provided in the 2021 API Compendium. The 2021 API Compendium emission
factor was selected as representative because it was developed from
results of the most comprehensive field study of crankcase ventilation
in the oil and natural sector available to date. Site-specific
information required for the emission calculation would include the
number of crankcase vents on RICE or GT, the operating time of each
engine or GT, and the concentration of CH4 in the gas stream
entering the engines or GT. If site-specific CH4
concentration is unknown, the proposed provision includes an option to
determine the CH4 concentration in the gas stream using
either engineering estimates based on best available data or the
provisions of 40 CFR 98.233(u)(2). The EPA is seeking comment on
whether this calculation method is appropriate and whether there are
other methodologies that we should consider providing, including
details on how those additional methods would be applied to this
source. For reporting, the EPA is proposing to add 40 CFR 98.236(ee) to
require reporters to provide emissions, the number of crankcase vents
at the facility, and engine or GT operating hours.

D. Reporting for the Onshore Petroleum and Natural Gas Production and
Onshore Petroleum and Natural Gas Gathering and Boosting Industry
Segments

    Within the Onshore Petroleum and Natural Gas Production and Onshore
Petroleum and Natural Gas Gathering and Boosting industry segments, GHG
emissions and activity data are currently generally reported at the
basin, county/sub-basin, or unit level, depending upon the specific
emission source. Examples of emission sources that report at the sub-
basin or county level include liquids unloading, completions and
workovers with hydraulic fracturing, and storage tanks. Sources that
report at the facility (basin) level include natural gas pneumatic
devices, blowdown vent stacks, and equipment leaks. The current
aggregation of data reported within the Onshore Petroleum and Natural
Gas Production and Onshore Petroleum and Natural Gas Gathering and
Boosting segments can present challenges in the process of emissions
verification, with corresponding potential impacts on data quality, and
it also limits data transparency.
    In order to address these concerns and improve data quality
consistent with section II.C of this preamble, the EPA is proposing to
disaggregate reporting requirements within the Onshore Petroleum and
Natural Gas Production and Onshore Petroleum and Natural Gas Gathering
and Boosting industry segments. As a first step, the EPA is proposing
to revise the reporting requirements to be more explicitly consistent
with the current reporting form structure for the well identification
(ID) numbers at the facility, with two proposed changes and one
addition. Currently, for certain emission sources directly related to
wells (liquids unloading, completions and workovers with hydraulic
fracturing, completions and workovers without hydraulic fracturing well
testing, and associated natural gas), subpart W requires reporters to
provide a list of well ID numbers in each sub-basin that contributed to
the emissions (e.g., a list of well IDs that had completions or
workovers with hydraulic fracturing). Under existing 40 CFR
98.236(aa)(1)(ii)(D) through (H), reporters are also asked to provide
the counts of wells that were producing, acquired, divested, completed,
and/or permanently taken out of production for each sub-basin, along
with a list of well ID number for the wells in each of those
categories. For the subpart W reporting form, these requirements were
implemented through addition of a single table, in which reporters
provide a list of all well ID numbers, the sub-basin, the operating
status per 40 CFR 98.236(aa)(1)(ii)(D) through (H), and any well-
specific information required for the emission source types directly
related to wells. The EPA is proposing to revise 40 CFR
98.236(aa)(1)(ii) and add requirements to 40 CFR 98.236(aa)(1)(iii)
that reflect this reporting form structure, with two notable changes.
First, the EPA is proposing to no longer require reporting of the sub-
basin ID for each well. Instead, reporters would report the sub-basin
ID by well-pad and then report the well-pad ID on which the well is
located. The well-pad ID is a new proposed data element and is
described in the following paragraph. Second, the EPA is proposing to
revise the requirements to provide a list of well IDs for the five
emission source types directly related to wells (currently required in
40 CFR 98.236(f)(1)(ii), (f)(2)(i), (g)(1), (h)(1)(i), (h)(2)(i),
(h)(3)(i), (h)(4)(i), (l)(1)(ii), (l)(2)(ii), (l)(3)(ii), (l)(4)(ii),
(m)(1), (m)(7)(i), and (m)(8)(i)) to instead specify that reporters
should report emissions and activity data for each of those emission
source types by well within the source-specific reporting requirements,
as described later in this section.
    Second, the EPA is proposing to add the following data elements:
well-pad ID (for Onshore Petroleum and Natural Gas Production segment)
and gathering and boosting site ID (for Onshore Petroleum and Natural
Gas Gathering and Boosting). These proposed data elements are hereafter
collectively referred to as ``site-level IDs.'' The EPA is proposing to
add to 40 CFR 98.236(aa)(1)(iv) (for Onshore Petroleum and Natural Gas
Production) and 40 CFR 98.236(aa)(10)(v) (for Onshore Petroleum and
Natural Gas Gathering and Boosting) requirements for reporting of
information related to each well-pad ID and gathering and boosting site
ID, respectively. The proposed reporting elements for each well-pad ID
include a unique name or ID for each well-pad, the sub-basin ID, and
the location (i.e., representative latitude and longitude coordinates).
    For the Onshore Petroleum and Natural Gas Gathering and Boosting
industry segments, the EPA is proposing at 40 CFR 98.236(aa)(10)(v) to
require reporters to provide a unique name or ID, the site type, and
the location for each gathering and boosting site. For the ``site
type'' for each gathering and boosting site, the EPA is proposing that
reporters would select between ``gathering compressor station,''
``centralized oil production site,'' ``gathering pipeline site,'' or
``other fence-line site.'' The EPA is proposing a definition of
``gathering compressor station'' in 40 CFR 98.238 to be used for the
purposes of this reporting requirement and to differentiate gathering
compressor stations from other types of compressor stations in subpart
W (e.g., transmission compressor stations). The Onshore Petroleum and
Natural Gas Gathering and Boosting industry segment also includes
centralized oil production sites that collect oil from multiple well-
pads but that do not have compressors (i.e.,

are not ``compressor stations''). The EPA is also proposing to add a
definition of a ``centralized oil production site'' in 40 CFR 98.238 to
be used for the purposes of this reporting requirement. For gathering
pipelines, the EPA is proposing a definition of ``gathering pipeline
site'' to specify that it is all the gathering pipelines at the
facility within a single state. In addition, the EPA has received
information from stakeholders noting that there are facility
configurations that would not clearly fit within the proposed
definition for ``gathering compressor station'' or ``centralized oil
production site,'' including, but not limited to, booster stations,
dehydration facilities, and treating facilities.\64\ The EPA is
proposing to provide the ``other fence-line site'' site type to cover
these types of sites. For gathering pipelines, the EPA is proposing
within the definition of ``gathering and boosting site'' that a
gathering pipeline site is all the gathering pipelines at the facility
within a single state. For the ``location'' reported for each gathering
and boosting site, the EPA is proposing that reporters would provide
the representative latitude and longitude coordinates where the site
type is a gathering compressor station, centralized oil production site
or other fence-line facility, and the state where the site type is a
gathering pipeline.
---------------------------------------------------------------------------

    \64\ Letter from Angie Burckhalter, The Petroleum Alliance of
Oklahoma, to Administrator Michael S. Regan, U.S. EPA, Re: Docket
Id. No. EPA-HQ-OAR-2019-0424; Revisions and Confidentiality
Determinations for Data Elements Under the Greenhouse Gas Reporting
Rule. October 6, 2022. Available in the docket for this rulemaking,
Docket Id. No. EPA-HQ-OAR-2023-0234.
---------------------------------------------------------------------------

    For the emission source types in the Onshore Petroleum and Natural
Gas Production industry segment directly related to wells that
currently report by sub-basin (i.e., well venting for liquids
unloading, completions and workovers with hydraulic fracturing,
completions and workovers without hydraulic fracturing, and associated
gas venting or flaring) or by calculation method and use of a flare
(i.e., well testing), we are proposing to require reporting of
emissions and activity data for each individual well instead of in the
current aggregations (e.g., by sub-basin). Where the current emission
source-level provisions of 40 CFR 98.236 for the Onshore Petroleum and
Natural Gas Production industry segment and the Onshore Petroleum and
Natural Gas Gathering and Boosting industry segment require reporting
at either the facility or the sub-basin level (other than the emission
source types directly related to wells), we are proposing to no longer
require reporting at the sub-basin level and instead require reporters
to provide emissions and activity data by well-pad ID or gathering and
boosting site ID for each facility. For emission source types that
report at the unit level (e.g., AGRs, dehydrators, and flares), we are
proposing to maintain reporting at that level but are proposing to also
require the reporter to identify the well-pad ID or gathering and
boosting site ID. This proposed requirement would take the place of the
reporting of the county or sub-basin ID, if applicable. The EPA is
seeking comment as to whether the lower levels of aggregation of
activity data to the site level within the Onshore Petroleum and
Natural Gas Production and Onshore Petroleum and Natural Gas Gathering
and Boosting segments would cause data elements that are currently not
entitled to confidential treatment (i.e., data elements that are not
considered ``emissions data'' as described in section V of this
preamble) to become entitled to confidential treatment. See section V
of this preamble for further information about the proposed
confidentiality determinations and reporting determinations for inputs
to emissions equations.
    In addition, the EPA is proposing revisions to the language of
existing reporting requirements and proposing to require specific
throughput data elements related to wells permanently shut-in and
plugged during the reporting year. First, the EPA is proposing to
revise the phrase ``permanently taken out of production (i.e., plugged
and abandoned)'' in proposed 40 CFR 98.236(aa)(1)(ii)(D) and (H) to
read ``permanently shut-in and plugged'' for consistency with the
language used in CAA section 136. This proposed amendment is for
consistency in language rather than any expected difference in the
wells to be reported or the interpretation of the terms. Second, the
EPA is proposing to require reporting of the quantities of natural gas,
crude oil and condensate produced that is sent to sale during the
reporting year for each well that is permanently shut-in and plugged in
40 CFR 98.236(aa)(1)(iii)(C) through (E) for the Onshore Petroleum and
Natural Gas Production industry segment and 40 CFR 98.236(aa)(2)(iv)
through (vi) for the Offshore Petroleum and Natural Gas Production
industry segment. Third, for each Onshore Petroleum and Natural Gas
Production well-pad with a well that was permanently shut-in and
plugged the EPA is proposing to require reporting of the total
quantities of natural gas, crude oil and condensate produced that is
sent to sale in the reporting year for the wells on that well-pad.
These proposed data elements, if finalized, are anticipated to be
useful in the future evaluation of the plugged well provisions of CAA
section 136(f)(7).

E. Natural Gas Pneumatic Device Venting and Natural Gas Driven
Pneumatic Pump Venting

    Subpart W currently requires calculation of GHG emissions from
natural gas pneumatic device venting (existing 40 CFR 98.233(a)) and
natural gas driven pneumatic pump venting (existing 40 CFR 98.233(c))
using default population emission factors multiplied by the number of
devices and the average time those devices are ``in-service'' (i.e.,
supplied with natural gas). In our 2022 Proposed Rule, we proposed to
update the population emission factors for pneumatic devices based on
recent study data. Consistent with section II.B of this preamble, we
are proposing calculation methods based on measurements and leak
screening for each source type as described in this section. Under the
proposed calculation methods for pneumatic devices, the existing
default population emission factors for intermittent bleed natural gas
pneumatic devices would no longer be applicable and the default
population emission factors for continuous bleed natural gas pneumatic
devices would only be applicable for the leak screening method
(proposed Calculation Method 3).
1. Direct Measurement Methods for Natural Gas Pneumatic Devices and
Natural Gas Pneumatic Pumps
    Consistent with section II.B of this preamble, we are proposing to
provide a calculation method based on direct measurement of natural gas
supplied to pneumatic devices in proposed 40 CFR 98.233(a)(1) and
supplied to pneumatic pumps in proposed 40 CFR 98.233(c)(1). We are
proposing that, if a flow monitoring device is installed on the natural
gas supply line dedicated to one or a combination of pneumatic devices,
or the natural gas supply line dedicated to one or more pneumatic
pumps, that are vented directly to the atmosphere, then the measured
flow must be used to calculate the emissions from the pneumatic devices
or pneumatic pumps, as applicable, downstream of that flow monitor. We
are also proposing to require this calculation method when the flow is
continuously measured in a supply line that serves both pneumatic
devices and natural gas driven pneumatic pumps that are all vented
directly to the atmosphere. The

flow monitor would be required to meet the requirements specified in
existing 40 CFR 98.234(b). We are proposing to denote this natural gas
supply measurement as Calculation Method 1 for pneumatic devices and
pneumatic pumps. We are also proposing to add reporting requirements
for each measurement location to report the type of flow monitor, the
number of each type of pneumatic device being monitored at that
location, and an indication of whether any natural gas driven pneumatic
pumps are also monitored at that location, and the CH4 and
CO2 emissions calculated for that monitoring location in
proposed 40 CFR 98.236(b)(3). Comparable reporting requirements for
natural gas driven pneumatic pumps are specified in proposed 40 CFR
98.236(c)(3).
    For natural gas pneumatic devices that do not have or do not elect
to install a flow meter dedicated to measuring the flow of natural gas
supplied to one or a combination of pneumatic devices that are vented
directly to the atmosphere, we are proposing in 40 CFR 98.233(a)(2) to
allow reporters to measure the natural gas emissions from each
pneumatic device vented directly to the atmosphere at the well-pad,
gathering and boosting site, or facility, as applicable, using one of
the measurement methods in existing 40 CFR 98.234(b) through (d). We
are proposing to refer to the vent measurement method as Calculation
Method 2 for pneumatic devices. For natural gas driven pneumatic pumps
that do not have or do not elect to install a flow meter dedicated to
measuring the flow of natural gas supplied to one or a combination of
pneumatic pumps vented directly to the atmosphere, we are proposing to
require that the reporter either measure the natural gas emissions from
each such pneumatic pump at the facility as specified in proposed 40
CFR 98.233(c)(2) or calculate emissions from each such pneumatic pump
at the facility using the default emissions factor as specified in
proposed 40 CFR 98.233(c)(3). The proposed measurement option is
referred to as Calculation Method 2 for pumps and is similar to the
proposed Calculation Method 2 for pneumatic devices. The proposed
pneumatic pump method based on a default emission factor is the same as
the methodology in 40 CFR 98.233(c) of the existing rule and is
referred to as Calculation Method 3 in the proposed rule.
    If Calculation Method 2 is elected for pneumatic devices, we are
proposing that all pneumatic devices that are vented directly to the
atmosphere present at the facility (except those for which natural gas
supply is measured according to Calculation Method 1) would have to be
measured at regular intervals and that for a well-pad, gathering and
boosting site, or facility, as applicable, selected to be measured that
year, all pneumatic devices that vent to the atmosphere must be
measured according to Calculation Method 2 (except those for which
natural gas supply is measured according to Calculation Method 1). For
facilities in the Onshore Petroleum and Natural Gas Production and in
the Onshore Petroleum and Natural Gas Gathering and Boosting industry
segments, a complete cycle of measurements would be required to be
completed in no more than 5 years, and we are proposing that the number
of pneumatic devices measured each year be approximately equal. We
selected a 5-year interval for Onshore Petroleum and Natural Gas
Production and Onshore Petroleum and Natural Gas Gathering and Boosting
facilities because of the high number of devices at these facilities
and the time needed to measure all natural gas pneumatic devices.
Additionally, we are proposing that when measurements are conducted at
a particular well-pad or gathering and boosting site, all pneumatic
devices at that well-pad or gathering and boosting site must be
measured in the same year. This would help enhance the
representativeness of the measurement data.
    For facilities in the Onshore Natural Gas Processing, Onshore
Natural Gas Transmission Compression, Underground Natural Gas Storage,
and Natural Gas Distribution industry segments, we are proposing the
measurement interval to be dependent on the number of devices at the
facility. For facilities with 25 or fewer natural gas pneumatic
devices, we are proposing measurement of all devices annually. For
facilities with 26 to 50 devices, we are proposing measurement of all
devices in a two-year period. The proposed interval period increases
with every 25 devices, until reaching a maximum cycle time of 5 years
for facilities with 101 or more natural gas pneumatic devices that are
vented directly to the atmosphere. The 25-device increment was selected
because we estimated that this would be the typical number of devices
that could be measured following the proposed methods in an 8-hour
period.
    Under Calculation Method 2, we are proposing that each pneumatic
device vent measurement, except for isolation valve actuators, would be
conducted for a minimum of 15 minutes; measurements for pneumatic
isolation valve actuators would be conducted for a minimum of 5
minutes. We are proposing a reduced monitoring duration for isolation
valve actuators specifically because these devices actuate very
infrequently, and the monitoring is targeted to confirm the valve
actuators are not malfunctioning (i.e., emitting when not actuating)
rather than to develop an average emission rate considering some
limited number of actuations. We are proposing that, if there is a
measurable flow during the measurement period, the average flow rate
measured during the measurement period would be used as the average
flow rate for that device and multiplied by the total hours the device
is in service (i.e., supplied with natural gas) to calculate annual
emissions (by pneumatic device type). For continuous bleed devices, if
there is no measurable flow rate (i.e., flow rate is below the method
detection limit), we are proposing to require reporters to confirm the
device is in service when measured and that the device type is
correctly characterized. Once confirmed, we are proposing that the
device must be retested (if designated as a high bleed device) or the
manufacturer's steady state bleed rate must be used (if designated as a
low bleed device) to estimate the device's emissions. For intermittent
bleed devices, the lack of any emissions during a 5-minute or 15-minute
period, as applicable, would indicate that the device did not actuate
and that the device is seating correctly when not actuating. As such,
we are proposing that engineering calculations would be made to
estimate emissions per activation and that company records or
engineering estimates would be used to assess the number of actuations
per year to calculate the emissions from that device for the reporting
year.
    Under Calculation Method 2, if vent measurements are made over
several years, we are proposing that all measurements made within a
multi-year measurement would be used to calculate a facility-specific
emission factor by device type (continuous high bleed, continuous low
bleed, and intermittent bleed). The emissions measurements for the
pneumatic device vents measured during the reporting year would be used
directly for those devices. We are proposing that reporters would use
the facility-specific emission factor developed from the cycle of
measurements times the number of devices (by type) at the facility that
were not measured during the reporting year to calculate the emissions
from the

pneumatic devices that were not measured during the reporting year.
    Reporters using proposed Calculation Method 2 would report for each
well-pad, gathering and boosting site, or facility, as applicable, the
total number of natural gas pneumatic devices by type, the number of
years in the measurement cycle, the number of devices by measured in
the reporting year, the value of the emissions factor for the reporting
year as calculated using equation W-1A and the devices upon which the
emission factor is based, the average time the devices were in service
(i.e., supplied with natural gas) during the calendar year, and the GHG
emissions for each type of natural gas pneumatic device.
    We are proposing calculation and reporting requirements for
Calculation Method 2 for pneumatic pumps in proposed 40 CFR
98.233(c)(2) and proposed 40 CFR 98.236(c)(4), respectively, that are
similar to the proposed Calculation Method 2 requirements for pneumatic
devices, with differences described as follows. First, only facilities
in the Onshore Petroleum and Natural Gas Production and in the Onshore
Petroleum and Natural Gas Gathering and Boosting industry segments are
currently required to report emissions from pneumatic pumps and based
on the analysis performed as described in section III.C.1 of this
preamble and documented in the subpart W TSD, we are not proposing to
add this source type for any other industry segment. Therefore,
proposed Calculation Method 2 for pneumatic pumps only includes the
provisions for a 5-year cycle and does not include the measurement
cycles for other industry segments. The 5-year cycle is being proposed
for natural gas driven pneumatic pumps for the same reason that it is
being proposed for pneumatic devices (i.e., a few facilities have a
high number of pumps, and the time needed to measure all of the pumps
in a single year would be excessive). To minimize the burden while
still collecting sufficient data to calculate sufficiently accurate
emissions, we are proposing an approach similar to the current approach
that Natural Gas Distribution facilities may use to conduct equipment
leak surveys. Second, the proposal specifies that reporters would
measure for a minimum of 5 minutes while liquid is continuously being
pumped. Five minutes is currently specified for other emission
measurements in the rule (e.g., leak rates from transmission storage
tank vents in existing 40 CFR 98.233(k)(2), which are condensate
storage tank vents in this proposal). Typically, emissions from pumps
are expected to be greater than leak rates from transmission storage
tank leaks. Thus, it is expected that a sufficient volume of sample
would be collected in 5 minutes of pump operation to be measurable with
sufficient accuracy. Third, we are proposing that the emissions would
be calculated as the product of the measured natural gas flow rate and
the number of hours the pneumatic pump was pumping. Under proposed
Calculation Method 2 for pneumatic pumps, proposed reporting data
elements in 40 CFR 98.236(c)(4) per well-pad or gathering and boosting
site would include the number of years in the measurement cycle; an
indication of whether emissions were measured or calculated; the
primary measurement method (when emissions were measured); the value of
the calculated emissions factor, the total number of pumps measured and
used in calculating the emission factor, the number of pumps that
vented to atmosphere, and the estimated average number of hours per
year that the vented pumps were pumping liquid (when the emissions were
calculated); the total measured CO2 and CH4
emissions; and the total calculated CO2 and CH4
emissions.
    We request comment on whether the option of up to a 5-year cycle is
appropriate for all facilities in the onshore production and gathering
and boosting industry segments. If a shorter time frame would be
appropriate, we request comment on how long the maximum cycle should be
and why that length of time would be adequate. We also request comment
on the proposed sampling period of 5 minutes. If a longer test period
would be needed or a shorter time period would be sufficient to collect
representative emissions data, we request comment on what time period
would be appropriate and the reasons why that test time would be
appropriate. Finally, we request comment on suggestions for other
approaches to emissions measurement that might be more effective and
better achieve the goal of obtaining accurate vented emissions data
from natural gas driven pneumatic pumps.
2. Intermittent Bleed Pneumatic Device Surveys
    As part of our review to characterize pneumatic device emissions,
we found a significant difference in the emissions from intermittent
bleed pneumatic devices that appeared to be functioning as intended
(short, small releases during device actuation) and those that appeared
to be malfunctioning (continuously emitting or exhibiting large or
prolonged releases upon actuation). For natural gas intermittent bleed
pneumatic devices, it is possible to identify malfunctioning devices
through routine monitoring using OGI or other technologies. As noted in
the introduction to section II of this preamble, the EPA recently
proposed NSPS OOOOb and EG OOOOc for oil and natural gas sources. Under
the proposed standards in NSPS OOOOb and the proposed presumptive
standards in EG OOOOc (which would inform the state plans or, if
necessary, the Federal plan in 40 CFR part 62), nearly all covered
pneumatic devices (continuous bleed and intermittent vent) would be
required to have a CH4 (and, for NSPS OOOOb only, VOC)
emission rate of zero. The only proposed exception would be for
pneumatic devices in Alaska at locations where on-site power is not
available, in which case owners and operators would be required to use
low bleed pneumatic devices in place of high bleed pneumatic devices
(unless a high bleed device is needed for a functional need such as
safety), and to verify that any intermittent bleed pneumatic devices
operate such that they do not vent when idle by monitoring these
devices during the fugitive emissions survey.
    We envision relatively few intermittent bleed pneumatic devices
that vent GHG to the atmosphere under the proposed zero-emission
standard and presumptive standard for these pneumatic devices,
compliance with which would require the use of technology to achieve
the zero-emission standard. As noted in the previous paragraph, we
proposed in NSPS OOOOb and EG OOOOc to require periodic monitoring of
those few intermittent bleed pneumatic devices in Alaska. In addition,
as noted in section II of this preamble, the proposed amendments that
would apply to sources subject to the NSPS OOOOb and approved state
plans or applicable Federal plan in 40 CFR part 62 would not become
effective for individual reporters unless and until their emission
sources become subject to and are required to comply with either the
final NSPS OOOOb or an approved state plan or applicable Federal plan
in 40 CFR part 62. Prior to that time, a reporter may elect to conduct
inspections or surveys of their intermittent bleed pneumatic devices.
Therefore, the EPA is proposing amendments to subpart W to provide an
alternative methodology to calculate emissions from intermittent bleed
pneumatic devices based on the results of inspections or surveys,
consistent with section II.B of this

preamble. Specifically, we are proposing to provide in 40 CFR
98.233(a)(3) an alternative calculation methodology for facilities that
monitor for malfunctioning intermittent bleed pneumatic devices
analogous to a ``leaker factor'' approach used for equipment leaks. We
included this ``leaker factor'' approach in the 2022 Proposed Rule;
however, we are proposing revisions to the ``leaker factors'' terms
included in the calculation approach using peer reviewed study data. We
are proposing to refer to this monitoring/leaker factor approach as
Calculation Method 3 for pneumatic devices.
    If Calculation Method 3 is elected, we are proposing that all
intermittent bleed pneumatic devices that vent to the atmosphere at the
well-pad, gathering and boosting site, or facility, as applicable,
would be required to be monitored according to the leak detection
methods in 40 CFR 98.234(a)(1) through (3), but with a monitoring
duration of at least 2 minutes or until a malfunction is identified.
Based on our review of the measurement studies that identified
malfunctioning intermittent bleed devices, we found that most
malfunctioning devices could be identified using a 2-minute monitoring
duration, but malfunctioning devices could not be identified
effectively using a typical ``leak survey'' monitoring duration, which
is on the order of a few seconds. However, if a pneumatic device is
observed to be malfunctioning in the first minute, there is no need to
continue to monitor that device. Therefore, we are proposing that a
minimum monitoring duration of 2 minutes or until a malfunction is
identified be used for the purpose of identifying malfunctioning
intermittent bleed pneumatic controllers.
    Under Calculation Method 3, we are proposing that all intermittent
bleed pneumatic devices that are vented directly to the atmosphere
present at the facility (except those for which natural gas supply is
measured according to Calculation Method 1) would have to be monitored
to identify malfunctioning devices at regular intervals, with a
complete cycle of measurements being completed in no more than 5 years
for facilities in the Onshore Petroleum and Natural Gas Production and
in the Onshore Petroleum and Natural Gas Gathering and Boosting
industry segments. Additionally, we are proposing that when monitoring
is conducted at a particular well-pad or gathering and boosting site,
all pneumatic devices at that well-pad or gathering and boosting site
must be monitored in the same year. This would help enhance the
representativeness of the measurement data. For facilities in the
Onshore Natural Gas Processing, Onshore Natural Gas Transmission
Compression, Underground Natural Gas Storage, and Natural Gas
Distribution industry segments, we are proposing the monitoring
interval to be dependent on the number of intermittent bleed pneumatic
devices at the facility. For facilities with 100 or fewer natural gas
intermittent bleed pneumatic devices, we are proposing monitoring of
all devices annually. For facilities with 101 to 200 devices, we are
proposing measurement of all devices in a 2-year period. The proposed
interval period increases with every 100 devices, until reaching a
maximum cycle time of 5 years for facilities with 401 or more natural
gas pneumatic devices vented directly to the atmosphere. The 100-device
increment was selected because we estimated that this would be the
typical number of devices that could be monitored following the
proposed methods in an 8-hour period. For all industry segments, we are
proposing that, if you elect to monitor your pneumatic devices over
multiple years, you must monitor approximately the same number of
devices each year.
    Under Calculation Method 3, if a ``leak'' is observed from the
intermittent bleed pneumatic device for more than 5 seconds during a
device actuation, then the device is considered to be
``malfunctioning'' and the malfunctioning device emission factor
(similar to a leaker emission factor) would be applied to that device.
Emissions from intermittent bleed pneumatic devices that were not
observed to be malfunctioning would be calculated based on the default
emission factor for ``properly functioning'' intermittent bleed
pneumatic devices. We are proposing in the definition of the variable
``Tz'' in proposed equation W-1C that the time that a device
is assumed to be malfunctioning would be determined following the same
procedures as the determination of the duration of equipment leaks
identified during a leak survey conducted under 40 CFR 98.233(q) (see
the variable ``Tp,z'' in equation W-30 for equipment leaks).
For example, if only one survey of intermittent bleed natural gas
pneumatic devices is conducted during the reporting year, then any
device found to be malfunctioning during the survey would be required
to be assumed to be malfunctioning for the entire year.
    If a complete survey of intermittent bleed pneumatic devices is
completed over multiple years, we are proposing equation W-1D be used
to calculate the emissions. As proposed, this equation uses the ratio
of the number of intermittent bleed devices identified to be
malfunctioning during the current reporting year to the total number of
intermittent bleed devices monitored during the reporting year to
estimate the number of malfunctioning and properly functioning
intermittent bleed devices for the intermittent bleed devices that were
not monitored during the reporting year.
    Under Calculation Method 3, we are proposing that emissions from
continuous bleed pneumatic controllers (other than those for which the
natural gas supply flow is measured as specified in Calculation Method
1) would be determined either by annually measuring the emissions from
the pneumatic device vent following the methods provided in Calculation
Method 2 or by using applicable default population emission factors for
continuous high bleed and continuous low bleed pneumatic devices.
    Reporters using proposed Calculation Method 3 would report for each
the well-pad, gathering and boosting site, or facility, as applicable,
the total number of natural gas pneumatic devices by type, the method
used to estimate emissions from continuous bleed natural gas pneumatic
devices, the frequency of monitoring for intermittent devices, the
number of years in a monitoring cycle, the number of devices at the
facility, the number monitored in the reporting year, the number found
to be malfunctioning, the average time the malfunctioning devices were
assumed to be malfunctioning under proposed 40 CFR 98.236(b)(5), the
average time that devices that were monitored but were not detected as
malfunctioning year were in service (i.e., supplied with natural gas)
during the calendar year, and the GHG emissions for each type of
natural gas pneumatic device.
    For more information regarding this proposed alternative
calculation methodology for natural gas intermittent bleed pneumatic
devices, see the subpart W TSD, available in the docket for this
rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
3. Revisions to Emission Factors
    As noted in section III.E of this preamble, subpart W currently
requires calculation of GHG emissions from natural gas pneumatic device
venting using default population emission factors multiplied by the
number of devices and the average time those devices are ``in-service''
(i.e., supplied with natural gas). Correspondingly, the current default
population factors for natural gas pneumatic devices were

developed by taking both periods of actuation and periods without
actuation into account. Subpart W provides two sets of pneumatic device
emission factors, one for devices in the Onshore Petroleum and Natural
Gas Production and Onshore Petroleum and Natural Gas Gathering and
Boosting industry segments and one for the Onshore Natural Gas
Transmission Compression and Underground Natural Gas Storage industry
segments. Each set of emission factors consists of emission factors for
three different types of natural gas pneumatic devices: continuous low
bleed devices, continuous high bleed devices, and intermittent bleed
devices.\65\
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    \65\ The development of the current emission factors for natural
gas pneumatic devices is described in Greenhouse Gas Emissions
Reporting from the Petroleum And Natural Gas Industry: Background
Technical Support Document, U.S. EPA, November 2010, (Docket Id. No.
EPA-HQ-OAR-2009-0923-3610), also available in the docket for this
rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
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    The EPA has become aware of several studies on emissions from
natural gas pneumatic device vents since subpart W was first
promulgated. For example, in April 2015, the EPA reviewed three
recently published studies on emissions from pneumatic devices (also
referred to as ``pneumatic controllers'' within the studies as well as
in NSPS OOOOa, proposed NSPS OOOOb, and proposed EG OOOOc) at onshore
production facilities and evaluated those studies for use in the U.S.
GHG Inventory.\66\ As part of this proposed rulemaking, we have
reviewed these and other available studies to evaluate the potential
for revisions to the natural gas pneumatic device emission factors in
subpart W. As part of our review, we found there are significantly more
data available now by which to characterize pneumatic device emissions.
Therefore, consistent with section II.B of this preamble, we are
proposing to amend the emission factors for all industry segments for
which emissions from natural gas pneumatic device vents must be
calculated.
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    \66\ U.S. EPA. Inventory of U.S. Greenhouse Gas Emissions and
Sinks: Potential Revisions to Pneumatic Controller Emissions
Estimate (Production Segment). April 2015. Available at https://www.epa.gov/sites/production/files/2015-12/documents/ng-petro-inv-improvement-pneumatic-controllers-4-10-2015.pdf.
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    Under Calculation Method 3 for pneumatic devices, default
population emission factors can be used for continuous bleed devices.
Therefore, for continuous low bleed pneumatic devices, we are proposing
an emission factor of 6.8 standard cubic feet per hour per device (scf/
hr/device) based on the available measurement data, which considers
devices that may be malfunctioning (i.e., having higher steady state
bleed rates than specified by the manufacturer) for all applicable
industry segments in proposed Table W-1. For continuous high bleed
pneumatic devices, we are proposing different population emission