number of controlled tanks with open or unseated thief hatches within
the reporting year, as well as the total volume of gas vented through
the open or unseated thief hatches. With these new reporting elements,
the EPA seeks to quantify the impact of open thief hatches on
atmospheric storage tanks and enhance the overall quality of the data
collected under the GHGRP, consistent with section II.A.4 of this
preamble.
    Malfunctioning dump valves and atmospheric storage tanks with
flares. For Onshore Petroleum and Natural Gas Production and Onshore
Petroleum and Natural Gas Gathering and Boosting facilities with
atmospheric storage tank emissions calculated using Calculation Method
1 (40 CFR 98.233(j)(1)) or Calculation Method 2 (40 CFR 98.233(j)(2)),
reporters must also follow the procedures in 40 CFR 98.233(j)(6) and
use equation W-16 to calculate emissions from occurrences of gas-

liquid separator dump valves not closing properly. Equation W-16
estimates the annual volumetric GHG emissions at standard conditions
from each storage tank resulting from the malfunctioning dump valve on
the gas-liquid separator using a correction factor, the total time the
dump valve did not close properly in the calendar year, and the hourly
storage tank emissions. Per the definition of the variable
``En'' in equation W-16, the input hourly storage tank
emissions should be those calculated using Calculation Methods 1 or 2
and should be adjusted downward by the magnitude of emissions recovered
using a vapor recovery system, if applicable. However, the definition
of the variable ``En'' in equation W-16 does not include the
procedure to be used for emissions from malfunctioning dump valves and
atmospheric storage tanks that are flared. In order to address any
confusion for reporters, the EPA is proposing to amend the definition
of the variable ``En'' in equation W-16 to include flared
storage tank emissions as determined in paragraph 40 CFR 98.233(j)(5),
consistent with section II.A.5 of this preamble. The EPA is also
proposing to revise the equation variables (particularly the
subscripts) in equation W-16 to clarify the intent of this equation. We
are proposing to revise the variable ``En'' to
``Es,i'' to further clarify that these are the volumetric
atmospheric storage tank emissions determined using the procedures in
40 CFR 98.233(j)(1) through (5). We are also proposing to replace the
``n'' and ``p'' subscripts in the other variables with a ``dv''
subscript to indicate that these are the emissions from periods when
the gas-liquid separator dump valves were not closed properly and that
the emissions from these periods should be added to the emissions
determined using the procedures in 40 CFR 98.233(j)(1) through (5).
    Composition of hydrocarbon liquids. Under 40 CFR 98.236(j)(1)(vii)
and (viii), reporters with atmospheric storage tank emissions
calculated using Calculation Method 1 or Calculation Method 2 are
required to provide the minimum and maximum concentrations (mole
fractions) of CO2 and CH4 in the tank flash gas.
Reporting of emissions and activity data for atmospheric storage tanks
is aggregated at the sub-basin or county level, and the minimum and
maximum flash gas concentrations were expected to provide the EPA with
a broad characterization of the often-significant number of tanks
reported for each sub-basin or county. However, through correspondence
with reporters via e-GGRT, the EPA has found that the minimum and
maximum flash gas concentrations do not accurately represent the
majority of atmospheric storage tanks within the reported sub-basins
and counties. Thus, the EPA is proposing to revise these two reporting
requirements to request the flow-weighted average concentration (mole
fraction) of CO2 and CH4 in the flash gas, rather
than the minimum and maximum values. Consistent with section II.A.4 of
this preamble, the EPA expects that these revisions would improve both
the representative nature of the data collected and the process of
verifying annual reported atmospheric storage tanks emissions data
under the GHGRP.
h. Associated Gas Venting and Flaring
    Associated gas venting. Associated gas venting or flaring is the
venting or flaring of natural gas that originates at wellheads that
also produce hydrocarbon liquids and occurs either in a discrete
gaseous phase at the wellhead or is released from the liquid
hydrocarbon phase by separation. Venting associated gas involves
directly releasing associated gas into the atmosphere at the well pad
or tank battery. Flaring associated gas is a common, and usually
preferred, alternative to venting for safety and environmental reasons.
Subpart W requires reporters to calculate annual emissions from
associated gas venting and flaring using equation W-18, which uses the
gas-to-oil ratio (GOR), volume of oil produced, and volume of
associated gas sent to sales to calculate the volume of gas vented.
Associated gas venting emissions are then calculated using the results
of equation W-18 and the gas composition determined using 40 CFR
98.233(u), and associated gas flaring emissions are calculated by
applying the calculation method of flare stacks in 40 CFR 98.233(n) to
the associated natural gas volume and gas composition determined for
the associated gas stream routed to the flare.
    As discussed further in section III.J.1.i of this preamble, the EPA
is proposing several amendments to the calculation and reporting
requirements for flare stacks that would impact associated gas flaring
emissions. One of the proposed amendments would provide for the use of
continuous flow measurement devices for the purposes of calculating
flared emissions. Similarly, for associated gas venting emissions, we
are proposing provisions to specify that if a continuous flow
measurement device is present, it must be used to determine the volume
of gas vented rather than equation W-18. We are proposing corresponding
reporting requirements for associated gas venting emissions, including
requiring an indication of whether a continuous flow monitor or
continuous composition analyzer was used and the flow-weighted mole
fractions. Finally, we are proposing to specify that if all of the
volumetric emissions from associated gas venting and flaring in the
sub-basin were determined using a continuous flow measurement device
rather than equation W-18 (i.e., equation W-18 was not used for any
wells in the sub-basin), then reporting of the GOR, the volume of oil
produced, and the volume of gas sent to sales for wells with associated
gas venting or flaring is not required for that sub-basin.
    Oil and gas volumes. As noted previously in this section, subpart W
requires reporters to calculate annual emissions from associated gas
venting and flaring using equation W-18. Two of the inputs in the
equation are the volume of oil produced and volume of associated gas
sent to sales for each well in the sub-basin during time periods in
which associated gas was vented or flared. However, based on the values
reported, there seems to be confusion among some reporters regarding
the inputs to these equations. For example, for some reporters, when
the reported volume of gas sent to sales during time periods in which
associated gas was vented or flared under 40 CFR 98.236(m)(6) is summed
across all sub-basins at the facility, the total is the same as the
total volume of gas sent to sales for the facility reported under 40
CFR 98.236(aa)(1)(i)(B). If these reporters are accurately reporting
the volume of gas sent to sales and using that volume in equation W-18,
then the associated gas venting and flaring emissions are likely
overstated, as it is unlikely that all wells are venting or flaring
associated gas 100 percent of the time. If the reporters are using
accurate volumes of gas sent to sales during time periods in which
associated gas was vented or flared for their emissions calculations
but reporting total gas sent to sales, then the activity data reported
do not match the emissions, leading to an inconsistent data set.
Therefore, the EPA is proposing to add the word ``only'' to the
definitions of the terms Vp,q and SGp,q in
equation W-18 (40 CFR 98.233(m)(3)) and to the reporting requirements
for those data elements in 40 CFR 98.236(m)(5) and (6). Consistent with
section II.A.5 of this preamble, these proposed amendments would reduce
reporter confusion regarding the volumes that should be used in the

emissions calculations and the volumes that should be reported.
i. Flare Stack Emissions
    Flare stacks are an emission source type subject to emissions
reporting by facilities in seven of the ten industry segments in the
Petroleum and Natural Gas Systems source category.\74\
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    \74\ Flare stacks are an emission source type subject to
emissions reporting by facilities in the following industry
segments: Onshore Petroleum and Natural Gas Production, Onshore
Petroleum and Natural Gas Gathering and Boosting, Onshore Natural
Gas Processing, Onshore Natural Gas Transmission Compression,
Underground Natural Gas Storage, LNG Import and Export Equipment,
and LNG Storage.
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    Total CO2, CH4, and N2O emissions
from each flare are required to be calculated using the methodology
specified in 40 CFR 98.233(n). In addition to calculating total
emissions from a flare, reporters must also separately calculate the
flared emissions from several types of emission sources.\75\ The
methodology for calculating source-specific flared emissions is
specified in the applicable paragraph of 40 CFR 98.233 for each source
type. The procedures in the source-specific paragraphs of the rule
cross-reference the calculation procedures in 40 CFR 98.233(n), but
they also specify that the volume and composition of the gas routed to
the flare are required to be determined according to the procedures for
estimating vented emissions from the specific source type. For example,
40 CFR 98.233(e)(6) specifies that the volume and gas composition to
use in calculating flared emissions from dehydrators must be determined
according to the procedures for calculating vented emissions from
dehydrators as specified in 40 CFR 98.233(e)(1) through (5). Since
source-specific flared emissions often are a portion of the total
emissions from a flare, 40 CFR 98.233(n)(9) specifies that the total
CO2, CH4, and N2O for a particular
flare must be adjusted downward by the amount of the source-specific
emissions that are calculated for the same flare; this ensures that
emissions from a flare are not double counted (i.e., reported for both
the flare stacks source type and another emission source type). The
resulting CO2, CH4, and N2O emissions
to report for that flare according to 40 CFR 98.236(n)(9) through (11)
should be only what is left after subtracting all of the source-
specific flared emissions from the total emissions.
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    \75\ Facilities separately calculate the flared emissions from
the following types of emission sources (if required for the
applicable industry segment, per 40 CFR 98.232): dehydrator vents,
well venting during completions and workovers with hydraulic
fracturing, gas well venting during completions and workovers
without hydraulic fracturing, onshore production and onshore
petroleum and natural gas gathering and boosting storage tanks,
transmission storage tanks, well testing venting and flaring, and
associated gas venting and flaring.
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    This calculation and reporting paradigm often means zero mass
emissions are reported for the flare because all of the mass emissions
are reported as flared emissions from other source types. However, even
when the only streams routed to a flare are from source types that are
subject to flared emissions reporting, the flare name or ID and all
activity data related to the streams that are routed to the flare and
the flare operating characteristics still must be reported under 40 CFR
98.236(n). These activity data include the volume of gas routed to the
flare, average CO2 and CH4 mole fractions in the
flared gas, flare combustion efficiency, fraction of flared gas routed
to the flare when it was unlit, and indicators of whether a continuous
flow measurement device and a continuous gas analyzer were used on the
gas stream routed to the flare. These flare ID and activity data
reporting requirements are specified in 40 CFR 98.236(n)(1) through
(8). In the rare cases that a CEMS is used on the outlet of a flare,
then according to 40 CFR 98.236(n)(12), only the flare ID and the
measured CO2 emissions must be reported.
    Reporting requirements for flared emissions. Many reporters have
provided information through the GHGRP Help Desk and in correspondence
with the EPA via e-GGRT indicating that reporters are not interpreting
the reporting requirements as written and as the EPA intended for
flares that receive gas from sources that are subject to source-
specific flared emissions reporting (e.g., atmospheric tanks). A key
misconception is that the adjustment requirement in 40 CFR 98.233(n)(9)
applies to all flare data, not just the mass emissions (as intended).
Thus, some reporters provide information for a flare only if some of
the mass emissions from the flare are due to combustion of gas from
source types that are not subject to source-specific flared emissions
reporting (i.e., miscellaneous flared sources). Although these
reporters generally correctly report the mass emissions from the flare
that are due to the miscellaneous flared sources, they incorrectly
limit their activity data reporting to those same streams. The EPA has
procedures in its verification process to identify such errors; if
errors are identified, the EPA notifies the reporter, who can resolve
the issue by correcting the data and resubmitting their annual GHG
report. Some reporters have also indicated that it is confusing to
report activity data for a flare in one table in the reporting form
(i.e., Table N.1), but to report the emissions in different tables;
they suggest that it would be clearer to report all flare activity data
and emissions related to a particular emission source type together in
one location. One industry stakeholder, GPA Midstream, also suggested
that flare activity data should be reported in the same manner that
flared emissions are reported. In other words, instead of providing a
single comprehensive record of the activity data per flare as is
currently required by 40 CFR 98.236(n), the activity data for flared
streams for a particular emission source (e.g., associated gas or
atmospheric storage tanks) should be reported with the flared emissions
for the same emission source type. According to GPA Midstream, this
reporting approach would be simpler and easier for reporters to follow
than the current requirements.\76\ We reviewed the flare reporting
requirements based on this feedback, and we are proposing several
revisions to the reporting requirements to improve the quality of the
reported data, consistent with section II.A.4 of this preamble.
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    \76\ Letter from Matt Hite, GPA Midstream Association, to Mark
de Figueiredo, U.S. EPA, Re: Additional Information on Suggested
Part 98, Subpart W Rule Revisions to Reduce Burden. September 13,
2019. Available in the docket for this rulemaking, Docket Id. No.
EPA-HQ-OAR-2019-0424.
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    First, we are proposing to modify the reporting requirements so
that the existing requirements in 40 CFR 98.236(n) would apply only to
flares that receive gas from miscellaneous flared sources. The activity
data to report would be limited to the streams from the miscellaneous
flared sources, and the CO2, CH4, and
N2O emissions to report would be the emissions that are
calculated from combustion of the same streams. In addition, we would
add comparable activity data reporting requirements to the reporting
required for all of the source types for which flared emissions
reporting is currently required (e.g., 40 CFR 98.236(e) for
dehydrators, 40 CFR 98.236(g) for completions and workovers with
hydraulic fracturing). The activity data reporting would be on the same
basis as the emissions reporting. For example, activity data for glycol
dehydrators with an annual average daily natural gas throughput greater
than or equal to 0.4 MMscf per day would be related to the flared
streams from each dehydrator because flared emissions are reported per
dehydrator. Activity data to be

reported for associated gas streams, on the other hand, would be
aggregated over all associated gas streams routed to flares in a sub-
basin because flared associated gas emissions are reported per sub-
basin. In addition, for completions and workovers with hydraulic
fracturing, flaring during the initial flowback period may not be
possible; therefore, some of the wells that report as part of a
``flared'' well type combination because most of the gas is flared may
also include emissions from gas that is vented before flaring begins.
To improve our understanding of the characteristics of the ``flared''
emissions from completions and workovers with hydraulic fracturing, we
are proposing that reporters would indicate in 40 CFR 98.236(g)(10)(i)
whether the total emissions reported under 40 CFR 98.236(g)(8) and (9)
include emissions from venting during the initial flowback period.
These proposed amendments would better align the flared emissions and
activity data for source types for which flared emissions reporting is
currently required.
    Second, in the current rule, 40 CFR 98.236(n)(7) and (8) require
reporting of the CH4 and CO2 mole fractions in
feed gas that are used in equations W-19 and W-20 to calculate total
emissions from a flare. The intent was for reporters to provide the
average values used to calculate total emissions from the flare.
However, the rule language is not clear on this point, and it appears
some reporters have interpreted these data elements in different ways.
It appears that one common interpretation is to report the mole
fraction for the emissions source type with the most flared emissions.
Because that interpretation does not align with the EPA's intent,
clarification of this reporting requirement is needed to improve the
verification process. Thus, we are proposing to modify these reporting
elements, both in 40 CFR 98.236(n) (proposed to be moved to 40 CFR
98.236(n)(1)(ix) and (x)) and for all the proposed activity data
reporting elements for individual source types that are subject to
source-specific flared emissions reporting as described above.
Specifically, we are proposing to require the flow-weighted annual
average mole fraction of CH4 over all streams from a
particular emission source type that are used in equation W-19 to
calculate the reported flared CH4 emissions from that
emission source type (and used in equation W-20 to calculate
CO2 emissions). For example, if a flare receives gas from an
acid gas removal vent and a blowdown vent stack, both of which are
miscellaneous flared sources, then the CH4 mole fraction to
report should be the flow-weighted annual average value from the acid
gas removal vent and each blowdown through the blowdown vent stack. The
CO2 mole fractions to report would also be a flow-weighted
annual average determined in the same manner.
    Third, reporters are required to use equation W-40 to calculate
N2O emissions from flares. Variables in the equation are the
volume of gas routed to the flare and the HHV of the gas. The volume of
gas routed to the flare must be reported, but the HHV is not reported.
As a result, when reported N2O emissions differ
significantly from the amount that would be expected if using the
default HHV, it can be difficult for the EPA to determine whether the
reported emissions are an error or if the difference is due to the use
of a site-specific HHV. To improve the verification process and
potentially reduce the amount of communication with reporters via e-
GGRT, we are proposing to add a reporting element that would require
reporters to indicate whether each reported N2O value is
based on the default HHV, a site-specific HHV(s), or both the default
and site-specific HHVs. The proposed reporting element would be added
in 40 CFR 236(n)(4)(iv) for miscellaneous flared sources, and it would
be included as one of the proposed activity data reporting elements for
each of the other source types that are subject to source-specific
flared emissions reporting. Providing an option to indicate that both
types of HHVs are used is needed because some reported flared
N2O emissions are aggregated values over all flares in a
sub-basin or county (e.g., for atmospheric tanks), and a reporter may
choose to use different methods for the flares in each sub-basin or
county. In addition to improving the verification process, knowledge of
site-specific HHVs would allow the EPA to assess how well the default
HHV characterizes flared gas streams in different industry segments and
basins.
    Fourth, an additional finding from the currently reported data is
that a number of facilities in the Onshore Petroleum and Natural Gas
Production industry segment, the Onshore Petroleum and Natural Gas
Gathering and Boosting industry segment, and the Onshore Natural Gas
Processing industry segment report significant amounts of emissions
from miscellaneous flared sources. It is not clear what sources are
generating the large amount of gas that is routed to these flares. To
help clarify the source types that are generating large amounts of
flared gas, we are proposing in 40 CFR 98.236(n)(1)(v) to require
reporting by facilities in these three industry segments of an estimate
of the fraction of the gas burned in the flare that is obtained from
other facilities specifically for flaring as opposed to being generated
in on-site operations. As an example, if an owner or operator has an
onshore petroleum and natural gas production and an onshore petroleum
and natural gas gathering and boosting facility in the same basin and
routes associated gas from wells in the onshore petroleum and natural
gas production facility to a flare that is defined as part of the
onshore petroleum and natural gas gathering and boosting facility, then
the flared emissions would be reported by the onshore petroleum and
natural gas gathering and boosting facility as emissions from ``other
flare stacks'' sources under the current rule (or from miscellaneous
flared sources under the proposed amendments). If the other gas streams
routed to the flare are from sources at the onshore petroleum and
natural gas gathering and boosting facility, then for this proposed
reporting requirement, the onshore petroleum and natural gas gathering
and boosting facility report would include an estimate of the fraction
of the total gas burned in the flare that is associated gas from the
onshore petroleum and natural gas production facility. We request
comment on the types of sources that may be generating these large
emissions and whether other reporting elements could be specified that
would better achieve the EPA's objective of clearly characterizing the
sources of flared emissions from facilities in the three industry
segments identified above. For example, one potential additional
reporting element could be a requirement to describe the primary source
of miscellaneous flared emissions for any flare that reports
CO2 emissions greater than an amount that would be
determined if such a reporting requirement were finalized.
    Finally, one objective of the current flare reporting requirements
is to obtain information on the total number of flares and their
operating characteristics. If the proposed changes to flare activity
data requirements as described previously in this section were
finalized, then additional amendments to reporting requirements would
be needed to continue collecting flare-specific information. Thus, we
are proposing to require reporting of a list of all flare IDs per
facility and add reporting for a series of flare-specific data
elements. One of the proposed flare reporting elements is the total
volume of

gas routed to the flare. This information is consistent with current
reporting requirements and would be helpful in conducting verification
of other reported flare data because the sum of the total volume from
all flares should be equal to the sum of the disaggregated volumes
reported for all flared emissions source types. The total volumes per
flare also would provide information on the range of flare sizes in
different industry segments and would be useful in analyses for
potential future policy decisions related to flares. Another of the
proposed flare reporting elements is a list of the subpart W emission
source types that routed emissions to the flare stack. This proposed
data element would improve verification of other reported flare data as
well as provide information regarding the types of sources that are
combined and routed to the same flare. We are also proposing a few new
flare-specific reporting elements to help us better understand the
state of flaring in the industry, such as an indication of the type of
the flare (e.g., open ground-level flare, enclosed ground-level flare,
open elevated flare, or enclosed elevated flare) and the type of flare
assist (e.g., unassisted, air-assisted (with indication of single-,
dual-, or variable-speed fan), steam-assisted, or pressure-assisted).
Further, researchers conducting remote sensing tests of emissions from
flares have reported detecting much larger quantities of emissions from
un-lit flares than is evident from the GHGRP data. To help us better
understand the prevalence of emissions from un-lit flares, we are
proposing to add requirements to report an indication of whether the
flare has a continuous pilot or autoigniter, whether the presence of
flame is continuously monitored if the flare has a continuous pilot,
and an indication of how the reporter identifies periods when the flare
is not lit if the flare does not have a continuous pilot. These
proposed data elements would be added in 40 CFR 98.236(n). This
paragraph of subpart W would be rearranged into two subparagraphs. The
first subparagraph, 40 CFR 98.236(n)(1), would include the current
activity data and emissions data reporting elements but would be
revised to be specific to miscellaneous flared sources (as discussed
previously), and the proposed flare-specific reporting elements would
be added in the second subparagraph, 40 CFR 98.236(n)(2).
    Definition of flare stack emissions. In response to a verification
message in e-GGRT, one reporter noted that the definition of the term
``flare stack emissions'' in 40 CFR 98.238 does not include
CO2 that is in streams routed to the flare. The term is
currently defined to mean ``CO2 and N2O from
partial combustion of hydrocarbon gas sent to a flare plus
CH4 emissions resulting from the incomplete combustion of
hydrocarbon gas in flares.'' Based on this definition, the reporter
concluded that CO2 in streams routed to the flare are not to
be reported as flare stack emissions. However, the current definition,
which was added to the 2010 Final Revisions Rule after consideration of
comments on the 2010 re-proposal, does not clearly convey the EPA's
intent that the CO2 that enters a flare should be reported
as flare stack emissions. This intent is evident from the fact that
equation W-20 includes a term for the inlet gas volume times the
CO2 mole fraction in the inlet gas. Additionally, in a
response to a comment on the 2010 proposed rule, the EPA clearly stated
that the total quantity of CO2, including both combusted
CO2 (i.e., CO2 created in the flare) and
uncombusted CO2 (i.e., CO2 that entered and
simply passed through the flare), is to be calculated. Another issue
with the current definition is that it implies N2O emissions
only result from partial combustion of hydrocarbons in the gas routed
to the flare. This is likely the primary mechanism for generating
N2O emissions when combusting fuels that include nitrogen-
containing compounds. However, natural gas and field gas have
negligible amounts of fuel-bound nitrogen. For combustion of these
fuels, it appears the N2O is generated primarily from
converting thermal NOX under certain operating conditions in
the flare. To eliminate the unintended inconsistency between the
definition and the intent that CO2 in gas routed to the
flare is to be reported as emissions from the flare, to clarify the
requirement to calculate and report total CO2 that leaves
the flare, and to clarify the source of flared N2O
emissions, we are proposing to revise the definition of the term
``flare stack emissions'' to mean CO2 in gas routed to a
flare, CO2 from partial combustion of hydrocarbons in gas
routed to a flare, CH4 resulting from the incomplete
combustion of hydrocarbons in gas routed to a flare, and N2O
resulting from operation of a flare.
    Calculation methodology for flared emissions. In addition to
proposing changes to the flare reporting requirements as discussed
above, we are also proposing to clarify language in the emission
calculation procedures of 40 CFR 98.233(n) that we believe may be
ambiguous for flares that do not have CEMS, consistent with section
II.A.5 of this preamble. The procedures for determining the volume and
composition of gas routed to flares for use in the emission calculation
equations for a particular emission source type are currently specified
in two places for each source type. Each source type-specific paragraph
in 40 CFR 98.233 specifies calculation methodologies for that emissions
source type, as do 40 CFR 98.233(n)(1) and (2). The procedures in the
source type-specific requirements specify only that the volume and
composition of the flared gas are to be determined using the procedures
for estimating vented emissions from that source type, but they also
cross-reference the calculation method in 40 CFR 98.233(n) for
determining the emissions from the flaring of that gas stream. However,
40 CFR 98.233(n)(1) and (2) specify that if continuous flow or
composition measurement devices are used on the gas to the flare, then
data from those devices must be used to calculate emissions; otherwise,
estimates may be used. The intent is that the procedures in 40 CFR
98.233(n) should take precedence, but this may not be clear to all
reporters. Additionally, the procedures for continuous measurement
devices in 40 CFR 98.233(n)(1) and (2) refer to devices ``on the
flare'' or ``on gas to the flare.'' The intent is that the procedures
should apply to devices regardless of whether they are on a stream
routed from a single emission source or on a stream routed to a flare
that includes streams combined from multiple emission source types, but
this is not explicitly described. A third potential ambiguity is that
procedures in 40 CFR 98.233(n)(1) and (2) do not specify how to
disaggregate data collected with a continuous measurement device when
the device measures a combined stream from more than one emission
source type.
    To clarify these requirements, we are proposing to specify all of
the potential options for determining volume and composition of gas to
the flare(s) in the applicable sections of 40 CFR 98.233 for each of
the emission source types that have flared emissions reporting
requirements. In general, the volume of gas would be determined by a
continuous flow measurement device, if available, or using the methods
for determining vented emissions for the applicable emission source
type. If the measured volume includes flow from multiple source types
routed to the same flare, reporters would use process knowledge and
best available data to determine the portion of the total flow

from each emission source type.\77\ Similarly, the composition of the
gas from the emission source type would be determined by a continuous
composition analyzer, if available, or using the methods for
determining the composition of the vented emissions for the applicable
emission source type. Alternatively, if multiple source types are
routed to one flare and the gas routed to the flare from each of those
source types is expected to have similar compositions, the reporter
could measure the composition of the total gas to the flare using a
continuous composition analyzer just upstream of the flare and apply
the results to each of the applicable source types. The source-specific
sections of 40 CFR 98.233 would then cross-reference only 40 CFR
98.233(n)(3) through (8) for the applicable calculation equations and
procedures for determining combustion efficiency, converting volumetric
emissions to mass emissions, and the separate procedures that apply if
a CEMS is used on gases from the flare. As part of this proposed
amendment, we would also remove 40 CFR 98.233(n)(9); with these
proposed calculation methodology clarifications and the reporting
clarifications described earlier in this section, a general direction
to correct flare emissions to avoid double counting would no longer be
necessary (however, a provision specifically to avoid double counting
of CO2 emissions from acid gas removal units that route
emissions to a flare would still be needed, as discussed later in this
section). We recognize that the proposed changes introduce some
repetition to the regulatory text overall because the requirements for
each emission source type are similar. However, clearly describing the
applicable procedures for each source type separately rather than
trying to generally describe a single set of consolidated procedures
would make the rule easier for reporters to understand, and we request
comment on whether the proposed changes achieve this goal.
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    \77\ The proposed revisions to 40 CFR 98.233(n)(1) would remove
``company records'' from the existing list of information upon which
engineering calculations may be based. In this instance, the use of
``company records'' was intended to refer generally to facility
records rather than the specific type of records as defined in 40
CFR 98.3, and we expect that general facility records are covered by
the proposed inclusion of process knowledge and best available data.
Therefore, we are proposing to remove the defined term ``company
records'' solely to avoid confusion for reporters; this amendment is
not intended to indicate a change in the engineering calculations.
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    Calculation methodologies for flared emissions from acid gas
removal vents. We are also proposing source type-specific provisions
for calculating and reporting emissions from acid gas removal vents
routed to flares that are related to the proposed calculation
methodology clarifications described earlier in this section,
consistent with section II.A.5 of this preamble. Reporters are
currently required to report the CO2 removed from the
natural gas as CO2 emissions from acid gas removal vents,
and that quantity is not affected (i.e., the CO2 is not
converted to another compound) when the acid gas vent stream is routed
to a flare, engine, or sulfur recovery plant. Therefore, the current
rule does not require reporters to separate emissions vented directly
to the atmosphere from emissions routed through a flare, engine, or
sulfur recovery plant. Instead, as noted earlier in this section, 40
CFR 98.233(n)(9) specifies that the total CO2 for a flare
that receives gas from acid gas removal vents must be adjusted downward
by the amount of the CO2 emissions that are calculated for
those acid gas removal vents. In other words, the CO2
emissions that are calculated for the acid gas removal vents are
reported under 40 CFR 98.236(d) and not under 40 CFR 98.236(n).
    Because the reporting of emissions from acid gas removal vents
routed to a flare is addressed differently in the current rule from the
reporting of flared emissions for all other source types, we are
proposing amendments for acid gas removal vents routed to flares that
are slightly different than the proposed amendments for other sources.
First, as noted previously in this section, we are proposing to remove
40 CFR 98.233(n)(9) because it would be unnecessary for other source
types in light of the other amendments previously described. However,
for acid gas removal vents routed to flares, an adjustment would still
be necessary for CO2 emissions. Therefore, we are proposing
to add provisions in 40 CFR 98.233(d)(12) for calculating emissions
from acid gas removal vents routed to flares (as described in more
detail in the next paragraph) and proposing to add a clarification to
the requirement to report CO2 emissions from flare stacks
(40 CFR 98.236(n)(9), proposed to be moved to 40 CFR 98.236(n)(1)(xi))
indicating that the reported CO2 emissions should not
include emissions from acid gas removal vents reported under 40 CFR
98.236(d)(1)(v) to prevent double counting of emissions.
    Second, we reviewed the calculation methods for acid gas removal
vents and flares, and we are proposing amendments to more closely align
the methods for acid gas removal vents routed to flares. For acid gas
removal vents, Calculation Method 1 (40 CFR 98.233(d)(1)) is required
to be used if a vent has a CEMS installed, and Calculation Method 2 (40
CFR 98.233(d)(2)) is required to be used if a vent has a continuous
flow monitor. If there is no CEMS or flow monitor installed, then
reporters currently must use Calculation Methods 3 or 4 (40 CFR
98.233(d)(3) or (4), which are estimation methods based on the volume
of natural gas treated and the acid gas contents of the inlet and
outlet natural gas. However, because these are estimation methods
rather than methods based on measurements, the EPA has found through
the verification process and correspondence with reporters via e-GGRT
that these methods can sometimes result in estimated volumetric
CO2 emissions from acid gas removal vents routed to a flare
that are greater than the reported total volume of gas routed to that
flare. Therefore, we are proposing new provisions in 40 CFR
98.233(d)(12) for reporters routing acid gas removal vents to flares.
The first set of amendments would apply to acid gas removal vents that
are routed to any dedicated flare as well as acid gas removal vents
comingled with emissions from other source types and routed to flares
with no continuous monitors for either the flow or composition of the
comingled gas stream. In either of these cases, reporters would
continue to calculate CO2 emissions using one of the
Calculation Methods 1 through 4, as applicable for the type of
monitoring available, and would continue to report those emissions
under 40 CFR 98.236(d) rather than 40 CFR 98.236(n). Reporters would
also incorporate the flow rate and composition of the acid gas removal
vent stream into the calculation of total flare emissions from
miscellaneous flared sources. For acid gas removal vent streams
comingled with emissions from other source types and routed to flares
with continuous monitoring of the flow and/or composition of the
comingled gas stream, we are proposing that reporters would first
determine the total emissions from the flare stacks and then use site-
specific engineering estimates based on best available data to estimate
the portion of the total flared CO2 emissions that is from
the acid gas removal vents. In this case, we are proposing that
reporters would select ``Routed to a flare [Sec.  98.233(d)(12)(ii)]''
as the calculation method. We are also proposing new reporting
requirements for acid gas removal vents routed to flares; in addition
to the current requirements to report the CO2 emissions
under 40 CFR 98.236(d)(1)(v),

we are proposing to add the identification of the flare to which the
acid gas removal vent is routed.
j. Compressors
    Compressors are used across the petroleum and natural gas industry
to raise the pressure of and convey natural gas or CO2. The
two main types of compressors used in the industry are centrifugal
compressors and reciprocating compressors. Subpart W requires Onshore
Petroleum and Natural Gas Production and Onshore Petroleum and Natural
Gas Gathering and Boosting facilities to calculate compressor emissions
using population emission factors. Population emission factors are
multiplied by the count of equipment, in this case compressors of a
certain type, to calculate emissions. For the Onshore Natural Gas
Processing, Onshore Natural Gas Transmission Compression, Underground
Natural Gas Storage, LNG Storage, and LNG Import and Export Equipment
industry segments, subpart W requires facilities to annually measure
the emissions from the compressor sources applicable to the mode the
compressor is in at the time of the measurement; facilities also have
the option to continuously measure emissions from a compressor source.
The annual measurements are called ``as found'' measurements because
the compressors are to be measured in the mode in which they are found
when the measurements are made. The ``as found'' measurements are
required for each centrifugal and reciprocating compressor at least
annually, but only for those compressor emission sources that have
measurement requirements for the mode in which they are found (i.e.,
the defined ``compressor mode-source combinations''), as described in
the following paragraph.
    Subpart W defines the following ``compressor sources'': wet seal
degassing vent (for centrifugal compressors only); rod packing
emissions (for reciprocating compressors only); blowdown valve leakage
through the blowdown vent (for both centrifugal and reciprocating
compressors) and unit isolation valve leakage through the open blowdown
vent without blind flanges (for both centrifugal and reciprocating
compressors). Subpart W also defines the following ``compressor
modes'': operating-mode (for both centrifugal and reciprocating
compressors), standby-pressurized-mode (for reciprocating compressors
only \78\), and not-operating-depressurized-mode (for both centrifugal
and reciprocating compressors). Some compressor sources may only
release emissions during certain compressor modes. Therefore, subpart W
uses the term ``compressor mode-source combination'' to refer to the
specific compressor sources that must be measured based on the mode in
which the compressor is found.
---------------------------------------------------------------------------

    \78\ Currently, subpart W does not require measurements for
centrifugal compressors in standby-pressurized-mode and therefore
does not define this mode for centrifugal compressors.
---------------------------------------------------------------------------

    For centrifugal compressors, subpart W requires measurement in the
following compressor mode-source combinations: wet seal oil degassing
vents in operating-mode, blowdown valve leakage through the blowdown
vent in operating-mode, and unit isolation valve leakage through an
open blowdown vent without blind flanges in not-operating-
depressurized-mode. For reciprocating compressors, subpart W requires
measurement in the following compressor mode-source combinations: rod
packing emissions in operating-mode, blowdown valve leakage through the
blowdown vent in operating-mode, blowdown valve leakage through the
blowdown vent in standby-pressurized-mode, and unit isolation valve
leakage through an open blowdown vent without blind flanges in not-
operating-depressurized-mode.
    The EPA is proposing several amendments related to the ``as found''
measurement requirements to improve the quality of data collected for
compressors. First, standby-pressurized-mode was not included as a mode
for centrifugal compressors in the subpart W definition of ``compressor
mode'' and no compressor mode-source combinations were defined for
centrifugal compressors in standby-pressurized-mode. While centrifugal
compressors are seldom in the standby-pressurized-mode, there have been
several occasions when reporters have indicated through the GHGRP Help
Desk that a centrifugal compressor was in this mode during the ``as
found'' measurement. This has led to confusion from reporters regarding
how to report the data from the measurements performed. To address this
issue, we are proposing to add standby-pressurized-mode to the defined
modes for centrifugal compressors (40 CFR 98.238) and require
measurement of volumetric emissions from the wet seal oil degassing
vent and volumetric emissions from blowdown valve leakage through the
blowdown vent when the compressor is found in this mode (40 CFR
98.233(o)(1)(i)(C) as proposed), consistent with sections II.A.2 and
II.A.5 of this preamble.
    Second, dry seals on centrifugal compressors were not included in
the subpart W definition of ``compressor source'' and no compressor
mode-source combinations were defined for dry seals on centrifugal
compressors. While emissions from wet seal oil degassing vents are
expected to be larger than from dry seals, dry seals may still
contribute to centrifugal compressor emissions. Additionally, the
measurement crew will already be at the centrifugal compressor to make
the ``as found'' measurement for blowdown valve leakage. Therefore, to
better characterize the emissions from dry seal centrifugal
compressors, we are proposing to add dry seal vents to the defined
compressor sources for centrifugal compressors (40 CFR 98.238) and
require measurement of volumetric emissions from the dry seal vents in
both operating-mode and in standby-pressurized-mode (40 CFR
98.233(o)(2)(iii) as proposed), consistent with section II.A.2 of this
preamble. Proposed measurement methods for the dry seal vents are
similar to those provided for reciprocating compressor rod packing
emissions and would include the use of temporary or permanent flow
meters, calibrated bags, and high volume samplers. Screening methods
may also be used to determine if a quantitative measurement is
required. Acoustical screening or measurement methods are not
applicable to dry seal vents because these emissions are not a result
of through-valve leakage. These proposed revisions include a proposed
new reporting requirement to report the number of dry seals on
centrifugal compressors and the reporting of emission measurements made
on the dry seals.
    Third, we are proposing to revise 40 CFR 98.233(p)(1)(i) to require
measurement of rod packing emissions for reciprocating compressors when
found in the standby-pressurized-mode because recent studies indicate
that rod packing emissions can occur while the compressor is in this
mode.\79\ The inclusion of this compressor mode-source combination
would more accurately reflect compressor emissions, consistent with
section II.A.2 of this preamble. Furthermore, the measurement crew will
already be at the compressor to make the ``as found''

measurement for blowdown valve leakage and several reporters already
make these measurements.
---------------------------------------------------------------------------

    \79\ Subramanian, R. et al. ``Methane Emissions from Natural Gas
Compressor Stations in the Transmission and Storage Sector:
Measurements and Comparisons with the EPA Greenhouse Gas Reporting
Program Protocol.'' Environ. Sci. Technol. 49, 3252-3261. 2015.
Available in the docket for this rulemaking, Docket Id. No. EPA-HQ-
OAR-2019-0424.
---------------------------------------------------------------------------

    Fourth, we are proposing to revise the allowable methods for
measuring wet seal oil degassing vents. Since the inception of subpart
W, the only method provided in 40 CFR 98.233(o)(2)(ii) for measuring
volumetric flow from wet seal oil degassing vents has been the use of a
temporary or permanent flow meter. The limitation in methods allowed
for wet seal oil degassing vents was due to the expectation that the
volumetric flows may exceed the quantitative limits of these other
methods. In reviewing the data reported for the wet seal oil degassing
vent, we found that the measured flow rates using flow meters are often
within the limits of other measurement methods allowed for other
compressor sources. We also found that many reporters have overlooked
the restriction on the methods allowed for wet seal oil degassing vents
and often reported using other measurement methods (e.g., high volume
samplers). We have found that most of these measured flow rates appear
to be within the capacity limits of a typical high volume sampler. In
the small minority of cases in which flow rates would be outside of the
capacity limit of the instrument, facilities can use an alternate
method, consistent with the requirements for other compressor source
measurements. Consequently, we concluded that the measurement methods
allowed for wet seal oil degassing vents could be expanded to include
the use of calibrated bags and high volume samplers. Therefore, we are
proposing to revise 40 CFR 98.233(o)(2)(ii) to allow the use of
calibrated bags and high volume samplers. However, we are not proposing
to allow the use of screening methods because wet seal oil degassing
vents are expected to always have some natural gas flow. Therefore, we
are proposing to retain and clarify this unique limitation on the use
of screening methods for wet seal oil degassing vent measurement
methods. This proposed revision would provide greater flexibility and
improved clarity of the wet seal oil degassing provisions consistent
with section II.A.2 of this preamble.
    Fifth, we are proposing to remove acoustic leak detection from the
screening and measurement methods allowed for manifolded groups of
compressor sources. As noted in 40 CFR 98.234(a)(5), acoustic leak
detection is applicable only for through-valve leakage. The acoustic
method can be applied to individual compressor sources associated with
through-valve leakage (i.e., blowdown valve leakage or isolation valve
leakage), but it cannot be applied to a vent that contains a group of
manifolded compressor sources downstream from the individual valves or
other sources that may be manifolded together. The inclusion of this
method for manifolded compressor sources was in error and we are
proposing to remove it from 40 CFR 98.233(o)(4)(ii)(D) and (E) and 40
CFR 98.233(p)(4)(ii)(D) and (E) to improve accuracy of the
measurements, consistent with section II.A.2 of this preamble.
    Sixth, we are proposing a number of clarifications to the
references to the allowed measurement methods to correct errors and
improve the clarity of the rule, consistent with section II.A.5 of this
preamble. These proposed revisions include: revising 40 CFR
98.233(o)(1)(i)(A) and (B) to reference 40 CFR 98.233(o)(2)(i) instead
of specific subparagraphs of that paragraph that may be construed to
limit the methods allowed for blowdown or isolation valve leakage
measurements; revising 40 CFR 98.233(p)(1)(i)(A), (B) and (C) to
reference 40 CFR 98.233(p)(2)(i) instead of specific subparagraphs of
that paragraph that may be construed to limit the methods allowed for
blowdown or isolation valve leakage measurements; revising 40 CFR
98.233(p)(1)(i)(A) and (C) (as proposed) to reference ``paragraph
(p)(2)(ii) or (iii) of this section as applicable'' instead of only
``paragraph (p)(2)(ii)'' to clarify that measurement of rod packing
emissions without an open-ended vent line are to be made according to
40 CFR 98.233(p)(2)(iii); and revising 40 CFR 98.233(p)(2)(ii)(C) and
(iii)(A) to clarify that acoustic leak detection is not an applicable
screening method for rod packing emissions (not a through-valve
leakage).
    In addition to these proposed revisions to the ``as found''
measurement requirements, we are also proposing to clarify the language
at 40 CFR 98.233(o)(10) and (p)(10) for compressors at Onshore
Petroleum and Natural Gas Production or Onshore Petroleum and Natural
Gas Gathering and Boosting facilities, consistent with section II.A.2
of this preamble. The compressor emission factors for these industry
segments are specific to uncontrolled wet seal oil degassing vents on
centrifugal compressors and uncontrolled rod packing emissions for
reciprocating compressors. The language in 40 CFR 98.233(o) and (p)
clearly indicates that the provisions of 40 CFR 98.233(o)(10) and
(p)(10) do not apply for controlled compressor sources. However,
proposed revisions are necessary to provide clarity regarding the
compressor sources for which emissions are required to be calculated
under 40 CFR 98.233(o)(10) and (p)(10) and reported under 40 CFR
98.236(o)(5) and (p)(5). Specifically, we are proposing minor revisions
to 40 CFR 98.233(o)(10) and the corresponding reporting requirements in
40 CFR 98.236(o)(5) to clarify that the compressor count used in
equation W-25 should be the number of centrifugal compressors with
atmospheric (i.e., uncontrolled) wet seal oil degassing vents.
Similarly, we are proposing minor revisions to 40 CFR 98.233(p)(10) and
the corresponding reporting requirements in 40 CFR 98.236(p)(5) to
clarify that the compressor count used in equation W-29D should be the
number of reciprocating compressors with atmospheric (i.e.,
uncontrolled) rod packing emissions. Finally, we are proposing to add
requirements to report the total number of centrifugal compressors at
the facility and the number of centrifugal compressors that have wet
seals to 40 CFR 98.236(o)(5) and proposing to add a requirement to
report the total number of reciprocating compressors at the facility to
40 CFR 98.236(p)(5). These additional data would provide the EPA with
an improved understanding of the total number of compressors and the
number of compressors that are controlled (i.e., routed to flares,
combustion, or vapor recovery systems) in the Onshore Petroleum and
Natural Gas Production and Onshore Petroleum and Natural Gas Gathering
and Boosting industry segments, consistent with section II.A.4 of this
preamble.
k. Equipment Leak Surveys
    Addition of leaker emission factors for survey methods other than
method 21. Subpart W reporters are required to quantify emissions from
equipment leaks using the calculation methods in 40 CFR 98.233(q)
(equipment leak surveys) and/or 40 CFR 98.233(r) (equipment leaks by
population count). The equipment leak survey method uses the count of
leakers detected with one of the subpart W leak detection methods in 40
CFR 98.234(a), subpart W leaker emission factors, and operating time to
estimate the emissions from equipment leaks. The current leaker
emission factors applicable to onshore petroleum and natural gas
production and onshore petroleum and natural gas gathering and boosting
facilities are found in Table W-1E of subpart W. These leaker emission
factors are based on the EPA's Protocol for Equipment Leak Emission
Estimates published in 1995 (Docket Id. No. EPA-HQ-OAR-2009-0927-0043),
also available in the docket for this

rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424. The leaker emission
factors are provided for components in gas service, light crude
service, and heavy crude service that are found to be leaking via
several different screening methods. In addition to being component-
and service-specific, subpart W currently provides two different sets
of leaker emission factors: one based on leak rates for leaks
identified by Method 21 (see 40 CFR part 60, appendix A-7) using a leak
definition of 10,000 ppm and one based on leak rates for leaks
identified by Method 21 using a leak definition of 500 ppm. Currently,
the other leak screening methods provided in subpart W (OGI, infrared
laser beam illuminated instrument, and acoustic leak detection device)
use the leaker emission factors based on Method 21 data with a leak
definition of 10,000 ppm.
    In the years that have followed the adoption of these emission
factors into subpart W, there have been numerous studies regarding
emissions from equipment leaks that provide measurement data to
quantify leaker emission factors for OGI screening methods at onshore
petroleum and natural gas production and onshore petroleum and natural
gas gathering and boosting facilities.\80\ These studies found that OGI
identifies fewer yet larger leaks than the EPA's Method 21.
Specifically, the average leaker emission factor determined from OGI
leak detection surveys is often a factor of two or more larger than
leaker emission factors determined when using Method 21 leak detection
surveys. Therefore, the application of the same leaker emission factor
to leaking components detected with OGI and Method 21 with a leak
definition of 10,000 ppm, as is currently done in subpart W, likely
understates the emissions from leakers detected with OGI.
---------------------------------------------------------------------------

    \80\ See, e.g., ERG (Eastern Research Group, Inc.) and Sage
(Sage Environmental Consulting, LP). City of Fort Worth Natural Gas
Air Quality Study: Final Report. July 13, 2011, available at https://www.fortworthtexas.gov/departments/development-services/gaswells/air-quality-study/final; Allen, D.T., et al. ``Measurements of
methane emissions at natural gas production sites in the United
States.'' Proceedings of the National Academy of Sciences of the
United States of America, Vol. 110, no. 44. pp. 17768-17773, October
29, 2013, available at http://dept.ceer.utexas.edu/methane/study.
Docket Item No. EPA-HQ-OAR-2014-0831-0006; Pacsi, A.P., et al.
``Equipment leak detection and quantification at 67 oil and gas
sites in the Western United States.'' Elem Sci Anth, 7: 29,
available at https://doi.org/10.1525/elementa.368. 2019; Zimmerle,
D., et al. ``Methane Emissions from Gathering Compressor stations in
the U.S.'' Environmental Science & Technology 2020, 54(12), 7552-
7561, available at https://doi.org/10.1021/acs.est.0c00516. The
documents are also available in the docket for this rulemaking,
Docket Id. No. EPA-HQ-OAR-2019-0424.
---------------------------------------------------------------------------

    Based on our review of these studies, we are proposing to amend the
leaker emission factors in Table W-1E for onshore petroleum and natural
gas production and onshore petroleum and natural gas gathering and
boosting facilities to include separate emission factors for leakers
detected with OGI, consistent with section II.A.1 of this preamble.
These emission factors were developed by combining the data from
Zimmerle et al. (2020) and Pacsi et al. (2019) to provide OGI leaker
emission factors by site type (i.e., gas or oil). These studies were
selected as the basis for the proposed OGI emission factors because
they included recent measurements of subpart W-specified equipment leak
components from both oil and gas production and gathering and boosting
sites in geographically diverse locations. 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-2019-0424.
    At onshore petroleum and natural gas production and onshore
petroleum and natural gas gathering and boosting facilities, very few
facilities use infrared laser beam illuminated instruments or acoustic
leak detection devices to conduct equipment leak surveys and there are
no data available to develop leaker emission factors specific to these
methods. Based on our understanding of these alternative methods, we
expect that their leak detection thresholds would be most similar to
OGI, so that the average emissions per leak identified by these
alternative methods would be similar to the emissions estimated using
the proposed OGI leaker factors. Therefore, we are proposing that, if
these alternative methods are used to conduct leak surveys, the
proposed OGI leaker emission factors would be used to quantify the
emissions from the leaks identified using these other monitoring
methods.
    For onshore petroleum and natural gas gathering and boosting
facilities, all components are considered to be in gas service
consistent with the language in 40 CFR 98.233(q)(2)(iv); thus, the gas
service factors from Table W-1E should be applied to all leakers. In
order to make clear how onshore petroleum and natural gas production
facilities should apply these revised emission factors, we are
proposing to amend 40 CFR 98.233(q)(2)(iii) to state that onshore
petroleum and natural gas production facilities must use the
appropriate default whole gas leaker emission factors consistent with
the well type, where components associated with gas wells are
considered to be in gas service and components associated with oil
wells are considered to be in oil service as listed in Table W-1E to
this subpart.
    As described previously, our analysis of measurement study data
from onshore production and gathering and boosting facilities
demonstrates that the OGI screening method finds fewer and larger leaks
than Method 21. Consequently, the leaker emission factors derived using
measurement data from the OGI screening method are larger than those
derived using the measurement data from Method 21 screening method. We
expect that the leaker emission factors for other industry segments
that are based on measurements of Method 21-identified leaks may
similarly underestimate the emissions from leaking equipment when OGI
(or other alternative methods besides Method 21) are used to detect the
leaks. Therefore, we are proposing to apply the ``OGI enhancement''
factor identified from measurement study data in the onshore production
and gathering and boosting industry segments to the leaker emission
factors for the other subpart W industry segments as a means to
estimate an OGI emission factor set. Analogous to the proposed changes
in Table W-1E for the Onshore Petroleum and Natural Gas Production and
Onshore Petroleum and Natural Gas Gathering and Boosting industry
segments, this results in the addition of an emission factor set
specific to OGI, infrared laser beam illuminated instrument, or
acoustic leak detection device screening methods. The proposed emission
factor sets are included in Tables W-2A, W-3A, W-4A, W-5A, W-6A, and W-
7 for the Onshore Natural Gas Processing, Onshore Natural Gas
Transmission Compression, Underground Natural Gas Storage, LNG Storage,
LNG Import and Export Equipment, and Natural Gas Distribution industry
segments, respectively. A detailed description 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-2019-0424.
    As an alternative to the proposed revised default leaker emission
factors, we are also proposing an option that would allow reporters to
quantify emissions from equipment leak components in 40 CFR 98.233(q)
by performing direct measurement of equipment leaks and calculating
emissions using those measurement results, consistent with section
II.A.2 of this preamble. The proposed amendments would provide that

facilities with components subject to 40 CFR 98.233(q) can elect to
perform direct measurement of leaks using one of the subpart W
measurement methods in 40 CFR 98.234(b) through (d) such as calibrated
bagging or a high volume sampler. To use this proposed option, all
leaks identified during a ``complete leak detection survey'' must be
quantified; in other words, reporters could not use leaker emission
factors for some leaks and quantify other leaks identified during the
same leak detection survey. For the Onshore Petroleum and Natural Gas
Production industry segment, a complete leak detection survey would be
the fugitive emissions monitoring of a well site conducted to comply
with NSPS OOOOa, NSPS OOOOb, or the applicable EPA-approved state plan
or the applicable Federal plan in 40 CFR part 62 or, if the reporter
elected to conduct the leak detection survey, a complete survey of all
equipment on a single well-pad. For the Onshore Petroleum and Natural
Gas Gathering and Boosting industry segment, a complete leak detection
survey would be the fugitive emissions monitoring of a compressor
station to comply with NSPS OOOOa, NSPS OOOOb, or the applicable EPA-
approved state plan or the applicable Federal plan in 40 CFR part 62
or, if the reporter elected to conduct the leak detection survey, a
complete survey of all equipment at a gathering ``compressor station''
or at a ``centralized oil production site'' (and we are proposing to
define these terms in 40 CFR 98.238, as described in section III.J.1.p
of this preamble). For downstream industry segments (e.g., Onshore
Natural Gas Transmission Compression), a complete leak detection survey
is facility-wide, and therefore, the election to perform direct
measurement of leaks would also be facility-wide. In other words, this
option would allow the use of measurement data directly when all leaks
identified are quantitatively measured.
    The proposed amendments rely specifically on quantitative
measurement methods already provided in the rule. We are seeking
comment on alternative methods for quantifying leaks for use for these
equipment leak measurements (and for ``as found'' compressor
measurements) along with supporting information and data. The
supporting information should include description of the method,
limitations on the applicability of the method, and calibration
requirements. Supporting data should include accuracy assessments
relative to other quantitative measurement methods provided in the
rule.
    Finally, as part of this overall amendment, we are also proposing
to remove the additional Method 21 screening when a survey is conducted
using a method other than Method 21. Currently, facilities using survey
methods other than Method 21 to detect equipment leaks may then screen
the equipment identified as leaking using Method 21 to determine if the
leak measures greater than 10,000 parts per million by volume (ppmv)
(see, e.g., 40 CFR 98.234(a)(1)). If the Method 21 screening of the
leaking equipment is less than 10,000 ppmv, then reporters may consider
that equipment as not leaking. In the 2016 subpart W revisions, we
added a leak detection methodology at 40 CFR 98.234(a)(6) (proposed to
be moved to 40 CFR 98.234(a)(1)(ii)) for using OGI in accordance with
NSPS OOOOa, which does not include an option for additional Method 21
screening. As noted in response to comments on the subpart W proposal
regarding the absence of this optional additional Method 21 screening
when using OGI in accordance with NSPS OOOOa, the additional screening
of OGI-identified leaking equipment using Method 21 requires additional
effort from reporters (81 FR 86500, November 30, 2016). Furthermore, as
noted previously in this section, the average emissions of leakers
identified by OGI are greater than leaks identified by Method 21.
Directly applying the number of OGI-identified leaks to the subpart W
leaker emission factor specific to that survey method would provide the
most accurate estimate of emissions, while selectively screening OGI-
identified leaks using Method 21 to reduce the number of reportable
leakers would yield a low bias in the reported emissions. Therefore, we
are proposing to require reporters to directly use the leak survey
results for the monitoring method used to conduct the complete leak
survey and are proposing to eliminate this additional Method 21
screening provision. In addition to providing more accurate emissions
data consistent with section II.A.2 of this preamble, the removal of
the additional monitoring step would streamline and improve
implementation consistent with section II.B.2 of this preamble.
    Amendments related to oil and natural gas standards and emissions
guidelines in 40 CFR part 60. As noted in the introduction to section
III.J of this preamble, the EPA recently proposed NSPS OOOOb and EG
OOOOc for oil and natural gas new and existing affected sources,
respectively. Under the proposed standards in NSPS OOOOb and the
proposed presumptive standards in EG OOOOc, owners and operators would
be required to implement a fugitive emissions monitoring and repair
program for the collection of fugitive emissions components at well
site and compressor station affected sources. In addition, the proposed
NSPS OOOOb and EG OOOOc include a proposed appendix K to 40 CFR part
60, an OGI-based method for detecting leaks and fugitive emissions from
all components that is not currently provided in subpart W. The EPA
also proposed provisions in NSPS OOOOb and EG OOOOc for equipment leak
detection and repair at onshore natural gas processing facilities.
Similar to the 2016 amendments to subpart W (81 FR 4987, January 29,
2016), the EPA is proposing to revise the calculation methodology for
equipment leaks in subpart W so that data derived from equipment leak
and fugitive emissions monitoring conducted under NSPS OOOOb or the
applicable approved state plan or applicable Federal plan in 40 CFR
part 62 would be used to calculate emissions, consistent with section
II.A.2 of this preamble.
    First, under these proposed amendments, facilities with certain
fugitive emissions components at a well site or compressor station
subject to NSPS OOOOb or an applicable approved state plan or
applicable Federal plan in 40 CFR part 62 would use the data derived
from the NSPS OOOOb or 40 CFR part 62 fugitive emissions requirements
along with the subpart W equipment leak survey calculation methodology
and leaker emission factors to calculate and report their GHG emissions
to the GHGRP. Specifically, the proposed amendments would expand the
cross-reference to 40 CFR 60.5397a to include the analogous
requirements in NSPS OOOOb or 40 CFR part 62. Facilities with fugitive
emissions components not subject to the standards in the proposed NSPS
OOOOb or addressed by the presumptive standards in the proposed EG
OOOOc and subject to 40 CFR part 62 would continue to be able to elect
to calculate subpart W equipment leak emissions using the leak survey
calculation methodology and leaker emission factors (as is currently
provided in 40 CFR 98.233(q)). Therefore, reporters with other fugitive
emission sources at subpart W facilities not covered by NSPS OOOOb or
40 CFR part 62 (e.g., sources subject to other state regulations and
sources participating in the Methane Challenge Program or other
voluntarily

implemented programs) would continue to have the opportunity to
voluntarily use the proposed leak detection methods to calculate and
report their GHG emissions to the GHGRP. To facilitate this proposed
requirement, we are also proposing to clarify that fugitive emissions
monitoring conducted to comply with NSPS OOOOa, NSPS OOOOb, or an
applicable approved state plan or applicable Federal plan in 40 CFR
part 62 is considered a ``complete leak detection survey,'' so that
onshore petroleum and natural gas production and onshore petroleum and
natural gas gathering and boosting facilities can use NSPS OOOOb or 40
CFR part 62 fugitive emission surveys directly for their subpart W
reports. In a corresponding amendment, we are also proposing to expand
the current reporting requirement in 40 CFR 98.236(q)(1)(iii) to
require reporters to indicate if any of the surveys of well sites or
compressor stations used in calculating emissions under 40 CFR
98.233(q) were conducted to comply with the fugitive emissions
standards in NSPS OOOOb or an applicable approved state plan or
applicable Federal plan in 40 CFR part 62.\81\ We request comment on
these proposed amendments and whether there are other provisions or
reporting requirements relative to NSPS OOOOb or EG OOOOc that we
should consider for subpart W.
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    \81\ We are similarly proposing to revise the existing reporting
requirement related to NSPS OOOOa, such that reporters would report
whether any of the surveys of well sites or compressor stations used
in calculating emissions under 40 CFR 98.233(q) were conducted to
comply with the fugitive emissions standards in NSPS OOOOa (rather
than simply reporting whether the facility has well sites or
compressor stations subject to the fugitive emissions standards in
NSPS OOOOa).
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    Second, we are proposing to revise 40 CFR 98.234(a) to clarify and
consolidate the requirements for OGI and Method 21 in 40 CFR
98.234(a)(1) and (2), respectively. In the 2016 amendments to subpart W
(81 FR 4987, January 29, 2016), the EPA added 40 CFR 98.234(a)(6) and
(7) to provide OGI and Method 21 as specified in NSPS OOOOa as leak
detection survey methods. In part, structuring the amendment this way
allowed the EPA to provide the NSPS OOOOa leak detection methods as
allowable methods under subpart W without affecting the requirements
for facilities and industry segments not subject to NSPS OOOOa.
However, as the EPA continues to propose additional standards with
slightly different variations on OGI and Method 21, it would be
unnecessarily convoluted to continue to add those methods and cross-
references to each standard to the end of 40 CFR 98.234(a). Therefore,
the EPA is proposing to move 40 CFR 98.234(a)(1) and 40 CFR
98.234(a)(6) to 40 CFR 98.234(a)(1)(i) and 40 CFR 98.234(a)(1)(ii),
respectively, which would consolidate the OGI-based methods in 40 CFR
98.234(a)(1). Similarly, the EPA is proposing to revise 40 CFR
98.234(a)(2) such that 40 CFR 98.234(a)(2)(i) is Method 21 with a leak
definition of 10,000 ppm and 40 CFR 98.234(a)(2)(ii) is Method 21 with
a leak definition of 500 ppm. This proposed amendment would effectively
move 40 CFR 98.234(a)(7) to 40 CFR 98.234(a)(2)(ii). The references to
``components listed in Sec.  98.232'' would be replaced with a more
specific reference to 40 CFR 98.233(q)(1). The references to specific
provisions in 40 CFR 60.5397a in 40 CFR 98.234(a)(6) and (7) would be
moved to 40 CFR 98.234(a)(1)(ii) and 40 CFR 98.234(a)(2), as
applicable.
    The EPA proposed in NSPS OOOOb and EG OOOOc that owners and
operators would detect leaks using an OGI-based monitoring method
following the concurrently proposed appendix K to 40 CFR part 60. We
are proposing to include that same method in subpart W at 40 CFR
98.234(a)(1)(iii) to ensure that reporters would be able to comply with
the proposed subpart W requirement to use data derived from the NSPS
OOOOb or 40 CFR part 62 fugitive emissions requirements for purposes of
calculating emissions from equipment leaks. As part of the proposal of
NSPS OOOOb and EG OOOOc, the EPA proposed an alternative screening
approach for fugitive emissions from well sites and compressor stations
that would allow the use of advanced measurement technologies to detect
large equipment leaks. If emissions are detected using one of these
advanced technologies, facilities would be required to conduct
monitoring using OGI or Method 21 to identify and repair specific
leaking equipment. Additionally, even if no large emissions are
identified, facilities using these advanced technologies would still be
required to conduct annual fugitive emissions monitoring using OGI or
Method 21. The EPA's intent in this proposed rule for subpart W is that
the results of those NSPS OOOOb and 40 CFR part 62 OGI or Method 21
surveys would be used for purposes of calculating emissions for subpart
W, as OGI and Method 21 are capable of identifying leaks from
individual components and they are leak detection methods provided in
subpart W. The EPA also requests comment on additional methods or
advanced technologies that can identify individual leaking components.
Based on the information received, the EPA would need to review the
specific method and leak detection data collected using that method to
determine what default leaker emission factors would apply for that
method and whether any adjustments might be needed to the subpart W
equipment leak survey calculation methodology when using that method.
Following that review, the EPA may undertake a rulemaking process to
include the additional leak detection method(s) in 40 CFR 98.234(a).
    Third, we are proposing subpart W requirements for onshore natural
gas processing facilities consistent with certain requirements for
equipment leaks in the proposed NSPS OOOOb or EG OOOOc. Currently,
onshore natural gas processing facilities must conduct at least one
complete survey of all the components listed in 40 CFR 98.232(d)(7)
each year, and each complete survey must be considered when calculating
emissions according to 40 CFR 98.233(q)(2). Under the equipment leak
detection and repair program included in proposed NSPS OOOOb and the EG
OOOOc presumptive standards, different component types may be monitored
on different frequencies, so all equipment at the facility is not
always monitored at the same time. According to the current
requirements in 40 CFR 98.233(q), surveys that do not include all of
the applicable equipment at the facility are not considered complete
surveys and are not used for purposes of calculating emissions.
Therefore, we are proposing that for onshore natural gas processing
facilities subject to NSPS OOOOb or an applicable approved state plan
or the applicable Federal plan in 40 CFR part 62 would use the data
derived from each equipment leak survey conducted as required by NSPS
OOOOb or 40 CFR part 62 along with the subpart W equipment leak survey
calculation methodology and leaker emission factors to calculate and
report GHG emissions to the GHGRP, even if a survey required for
compliance with NSPS OOOOb or 40 CFR part 62 does not include all the
component types listed in 40 CFR 98.232(d)(7).
    Under this proposed amendment, reporters would still have to meet
the subpart W requirement to conduct at least one complete survey of
all applicable equipment at the facility per year, so if there were
components listed in 40 CFR 98.232(d)(7) not included in any NSPS OOOOb
or 40 CFR part 62-required surveys conducted during the year (e.g.,
connectors that are monitored only once every 4 years), reporters

subject to NSPS OOOOb or 40 CFR part 62 would need to either add those
components to one of their required surveys, making that a complete
survey for purposes of subpart W, or conduct a separate complete survey
for purposes of subpart W. We expect that reporters with onshore
natural gas processing plants implementing traditional leak detection
and repair programs are already making similar decisions regarding how
to meet the requirement to conduct a complete survey for subpart W, and
our intention with this proposed amendment is not to change those
decisions. Rather, this amendment would specify that surveys conducted
pursuant to NSPS OOOOb or 40 CFR part 62 that do not include all
component types listed in 40 CFR 98.232(d)(7) would be used for
calculating emissions along with each complete survey.
    We are also proposing to add leaker emission factors for all survey
methods for ``other'' components that would be required to be monitored
under NSPS OOOOb or an approved state plan or applicable Federal plan
in 40 CFR part 62 or that reporters elect to survey that are not
currently included in subpart W. These proposed total hydrocarbon
leaker emission factors are the same as the total hydrocarbon leaker
emission factors for the Onshore Natural Gas Transmission Compression
and the Underground Natural Gas Storage industry segments (Table W-3A
and Table W-4A, respectively). For more information on the derivation
of the original emission factors, see the TSD for the final subpart W
standards,\82\ and for more information on the derivation of the
emission factors proposed to be added to Table W-2B, see the TSD for
the 2016 amendments to subpart W.\83\ In a corresponding amendment, we
are also proposing to expand the reporting requirement in 40 CFR
98.236(q)(1)(iii) to require onshore natural gas processing reporters
to indicate if any of the surveys used in calculating emissions under
40 CFR 98.233(q) were conducted to comply with the equipment leak
standards in NSPS OOOOb or an applicable approved state plan or the
applicable Federal plan in 40 CFR part 62. We request comment on the
proposed amendments to subpart W for onshore natural gas processing
facilities subject to the equipment leak provisions of NSPS OOOOb or 40
CFR part 62, as well as whether there are other provisions or reporting
requirements for these facilities that we should consider.
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    \82\ 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-2019-0424.
    \83\ Greenhouse Gas Reporting Rule: Technical Support for Leak
Detection Methodology Revisions and Confidentiality Determinations
for Petroleum and Natural Gas Systems. November 1, 2016. Docket Id.
No. EPA-HQ-OAR-2015-0764-0066; also available in the docket for this
rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424.
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    Finally, in our review of subpart W equipment leak requirements for
onshore natural gas processing facilities, we found that the leak
definition for the Method 21-based requirements for processing plants
in NSPS OOOOa (as well as proposed NSPS OOOOb and EG OOOOc presumptive
standards) is not consistent with the leak definition in the Method 21
option in current 40 CFR 98.234(a)(1), which is the only Method 21-
based method available to onshore natural gas processing facilities
under subpart W. Based on this review, and to complement the proposed
addition of default leaker emission factors for survey methods other
than Method 21 (as described previously in this preamble), we are
proposing several additions to the equipment leak survey requirements
for the Onshore Natural Gas Processing industry segment, beyond those
amendments already described related to the proposed NSPS OOOOb and EG
OOOOc presumptive standards. First, we are proposing default leaker
emission factors for Method 21 at a leak definition of 500 ppm in Table
W-2A. As with the proposed ``other'' leaker emission factors, these
proposed leaker emission factors are the same as the total hydrocarbon
leaker emission factors for the Onshore Natural Gas Transmission
Compression and the Underground Natural Gas Storage industry segments
(Table W-3A and Table W-4A, respectively). For more information on the
derivation of those emission factors, see the TSD for the 2016
amendments to subpart W.\84\ In addition, we are proposing to add 40
CFR 98.233(q)(1)(v) to indicate that onshore natural gas processing
facilities not subject to NSPS OOOOb or an approved state plan or the
applicable Federal plan in 40 CFR part 62 may use any method specified
in 40 CFR 98.234(a), including Method 21 with a leak definition of 500
ppm and OGI following the provisions of appendix K to 40 CFR part 60.
This proposed amendment would ensure that equipment leak surveys
conducted using any of the approved methods in subpart W would be
available for purposes of calculating emissions, not just those surveys
conducted using one of the methods currently provided in 40 CFR
98.234(a)(1) through (5).
---------------------------------------------------------------------------

    \84\ Greenhouse Gas Reporting Rule: Technical Support for Leak
Detection Methodology Revisions and Confidentiality Determinations
for Petroleum and Natural Gas Systems. November 1, 2016. Docket Id.
No EPA-HQ-OAR-2015-0764-0066; also available in the docket for this
rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424.
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l. Equipment Leaks by Population Count
    As noted in section III.J.1.k of this preamble, subpart W reporters
are required to quantify emissions from equipment leaks using the
calculation methods in 40 CFR 98.233(q) (equipment leak surveys) and/or
40 CFR 98.233(r) (equipment leaks by population count), depending upon
the industry segment. The equipment leaks by population count method
uses the count of equipment components, subpart W emission factors
(e.g., Table W-1A for the Onshore Petroleum and Natural Gas Production
industry segment), and operating time to estimate emissions from
equipment leaks. For the Onshore Petroleum and Natural Gas Production
and Onshore Petroleum and Natural Gas Gathering and Boosting industry
segments, the count of equipment components may be determined by
counting each component individually for each facility (Component Count
Method 2) or the count of equipment components may be estimated using
the count of major equipment and subpart W default average component
counts for major equipment (Component Count Method 1) in Tables W-1B
and W-1C, as applicable. Reporters in other industry segments must
count each applicable component at the facility. We are proposing
several amendments to the calculation methodology provisions of 40 CFR
98.233(r) and the reporting requirements in 40 CFR 98.236(r) to improve
the quality of the data collected, consistent with sections II.A.1,
II.A.4, and II.A.5 of this preamble.
    Onshore petroleum and natural gas production and onshore petroleum
and natural gas gathering and boosting population count method. The
current population emission factors for the Onshore Petroleum and
Natural Gas Production and Onshore Petroleum and Natural Gas Gathering
and Boosting industry segments are found in Table W-1A of subpart W.
The gas service population emission factors are based on the 1996 Gas
Research Institute (GRI)/EPA study Methane Emissions from the Natural
Gas Industry, Volume 8: Equipment Leaks (available in the docket for
this rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424). The oil service
population emission factors are based on the American Petroleum
Institute's (API) Emission Factors for Oil

and Gas Production Operations, Publication 4615 published in 1995.
    As noted previously in this section, when estimating emissions
using the population count method, onshore petroleum and natural gas
production facilities and onshore petroleum and natural gas gathering
and boosting facilities have the option to use actual component counts
(i.e., Component Count Method 2) or to estimate their component counts
using the count of major equipment (e.g., wellhead) and default
component counts per major equipment (e.g., valves per wellhead)
included in Tables W-1B and W-1C of subpart W (i.e., Component Count
Method 1). In reviewing subpart W data, we find that the vast majority
(greater than 95 percent) of onshore production and natural gas
gathering and boosting facilities use Component Count Method 1 to
estimate the count of components.
    It is important to note that both the population count emission
factors and the default component counts per major equipment included
in Tables W-1A, W-1B and W-1C are service-specific (i.e., gas or oil)
as well as region-specific (i.e., eastern or western U.S.). The
regional designations are provided by U.S. state in Table W-1D of
subpart W such that a facility would determine the facility's region
and select the appropriate region- and service-specific factors.
    In the years that have followed the adoption of these emission
factors into subpart W, there have been numerous studies regarding
emissions from equipment leaks at onshore production and gathering and
boosting facilities. Two recent field studies, Pacsi et al. (2019) \85\
and Zimmerle et al. (2020),\86\ have performed an equipment and
component inventory alongside equipment leak screening and measurement
results. Another recent study, Rutherford et al. (2021),\87\ included
synthesis and analysis of measurements from component-level field
studies. These studies provide the necessary data to develop and
compare study-estimated population emission factors as well as study-
estimated default component counts per major equipment to those in
subpart W. Comparison of the study-estimated default component counts
per major equipment found that the subpart W values underestimate the
count of components found on major equipment in the field (Zimmerle et
al., 2020; Pacsi et al., 2019). Regarding a comparison of the
population emission factors and component counts per major equipment
between the subpart W eastern and western values, Zimmerle et al.
(2020) was the only field study to include both eastern and western
facilities, and the study values showed ``no statistically significant
differences between eastern and western U.S. regions.'' Rutherford et
al. (2021) also found their study-estimated population emission factors
to be higher than those in subpart W, noting that one of the
contributing factors to this difference was the use of the eastern
factors in subpart W, which appear to significantly undercount
emissions. Rutherford et al. (2021) noted that the impact of the use of
the eastern factors has grown over time as the production in the
eastern region of the U.S. has increased from less than 5 percent of
gas produced to nearly 30 percent of the gas produced.
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    \85\ Pacsi, A. P. et al. Equipment leak detection and
quantification at 67 oil and gas sites in the Western United States.
Elementa (2019). https://doi.org/10.1525/elementa.368. Available in
the docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424.
    \86\ Zimmerle, D., et al. Methane Emissions from Gathering
Compressor Stations in the U.S. Environmental Science & Technology
54 (12), 7552-7561 (2020). https://doi.org/10.1021/acs.est.0c00516.
Available in the docket for this rulemaking, Docket Id. No. EPA-HQ-
OAR-2019-0424.
    \87\ Rutherford, J.S., Sherwin, E.D., Ravikumar, A.P. et al.
Closing the methane gap in US oil and natural gas production
inventories. Nat Commun 12, 4715 (2021). https://doi.org/10.1038/s41467-021-25017-4. Available in the docket for this rulemaking,
Docket Id. No. EPA-HQ-OAR-2019-0424.
---------------------------------------------------------------------------

    Based on our review of these studies, we are proposing to amend the
population count method for onshore petroleum and natural gas
production and onshore petroleum and natural gas gathering and boosting
facilities using these more recent study data, consistent with section
II.A.1 of this preamble. These proposed amendments include new
population emission factors that are on a per major equipment basis
rather than a per component basis. As mentioned previously, the vast
majority of reporters estimate the component counts using Component
Count Method 1. By providing emission factors on a major equipment
basis instead of by component, we would eliminate the step to estimate
the number of components. All facilities would be able to inventory
their major equipment and consistently apply the same emissions factor
to estimate emissions. This would reduce reporter burden and reduce the
number of errors in the calculation of emissions, as we find that
numerous facilities incorrectly estimate the number of components using
Component Count Method 1 while providing consistently estimated
emission results. The major equipment emission factors were developed
by combining data from Zimmerle et al. (2020) and Pacsi et al. (2019)
to provide population emission factors by major equipment and site type
(i.e., gas or oil). The emission factors were derived by summing the
leaker emissions by major equipment type, including wellhead,
separator, meters/piping, compressor, acid gas removal unit,
dehydrator, header, heater treater, and storage vessel, by the reported
site type and dividing those leaker emissions by the count of major
equipment screened to yield an emission factor in units of scf whole
gas/hour-equipment. Specific to meters/piping and consistent with
current requirements related to meters/piping at 40 CFR
98.233(r)(2)(i)(A), we are proposing in 40 CFR 98.233(r)(2) to specify
that one meters/piping equipment should be included per well-pad for
onshore petroleum and natural gas production operations and the count
of meters in the facility should be used for this equipment category at
onshore petroleum and natural gas gathering and boosting facilities. As
a consequence of the broader scope of equipment surveyed in the Pacsi/
Zimmerle studies, the proposed emission factors include more pieces of
major equipment than are currently included in subpart W. The
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-2019-0424. The proposed major equipment
emission factors would replace the component-based emission factors in
the current Table W-1A. We are also proposing to revise the titles of
Tables W-1B, W-1C, and W-1D to clarify that they apply to reporting
years up to and including RY2022. These tables would not apply to
subsequent reporting years as they provide activity data that would no
longer be needed for the population count method for these industry
segments. We are seeking comment on the approach of providing
population count emission factors by major equipment.
    We note that the application of these emission factors is by site
type such that for onshore petroleum and natural gas production
facilities, gas well sites should use the proposed gas service emission
factors and oil well sites should use the proposed oil service emission
factors. Similarly, for onshore petroleum and natural gas gathering and
boosting facilities, we consider all equipment to be in gas service
consistent with the language in 40 CFR 98.233(r)(2); thus, the proposed
gas service factors from Table W-1A should be applied to all equipment
counts. We

are proposing language clarifying the service-specific application of
these emission factors specifically for onshore petroleum and natural
gas production in 40 CFR 98.233(r)(2).
    Natural Gas Distribution Emission Factors. Natural Gas Distribution
companies quantify the emissions from equipment leaks from pipeline
mains and services, below grade transmission distribution transfer
stations, and below grade metering-regulating stations following the
procedures in 40 CFR 98.233(r). This method uses the count of
equipment, subpart W population emission factors in Table W-7 (proposed
to be moved to Table W-8), and operating time to estimate emissions.
The population emission factors for pipeline mains and services in
Table W-7 (proposed to be moved to Table W-8) are based on information
from the 1996 GRI/EPA study.\88\ Specifically for plastic mains,
additional data are sourced from a 2005 ICF analysis.\89\ The
population emission factors for pipeline mains are published per mile
of main by pipeline material and emission factors for pipeline services
are published per service by pipeline material. The population emission
factors for below grade stations in Table W-7 (proposed to be moved to
Table W-8) are based on information from the 1996 GRI/EPA study.\90\
The population emission factors for below grade transmission-
distribution transfer stations and below grade metering-regulating
stations are published per station by three inlet pressure categories
(>300 psig, 100-300 psig, <100 psig).
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    \88\ GRI/EPA. Methane Emissions from the Natural Gas Industry,
Volume 9: Underground Pipelines. Prepared for Gas Research Institute
and U.S. Environmental Protection Agency National Risk Management
Research Laboratory by L.M. Campbell, M.V. Campbell, and D.L.
Epperson, Radian International LLC. GRI-94/0257.2b, EPA-600/R-96-
080i. June 1996. Available in the docket for this rulemaking, Docket
Id. No. EPA-HQ-OAR-2019-0424.
    \89\ ICF. Fugitive Emissions from Plastic Pipe, Memorandum from
H. Mallya and Z. Schaffer, ICF Consulting to L. Hanle and E.
Scheehle, EPA. June 30, 2005. Available in the docket for this
rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424.
    \90\ GRI/EPA. Methane Emissions from the Natural Gas Industry,
Volume 10: Metering and Pressure Regulating Stations in Natural Gas
Transmission and Distribution. Prepared for Gas Research Institute
and U.S. Environmental Protection Agency National Risk Management
Research Laboratory by L.M. Campbell and B.E. Stapper, Radian
International LLC. GRI-94/0257.27, EPA-600/R-96-080j. June 1996.
Available in the docket for this rulemaking, Docket Id. No. EPA-HQ-
OAR-2019-0424.
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    The EPA is proposing to update the population emission factors in
Table W-7 (proposed to be moved to Table W-8) to subpart W using the
results of studies and information that were not available when the
rule was finalized in 2010. Notably, the EPA reviewed recent studies
and updated the emission factors for several natural gas distribution
sources, including pipeline mains and services and below grade
stations, for the 2016 U.S. GHG Inventory.\91\ \92\ The majority of the
U.S. GHG Inventory updates were based on data published by Lamb et al.
in 2015.\93\ Since the time that the 2016 U.S. GHG Inventory updates
were made, additional studies for pipeline distribution mains have been
published and reviewed by the EPA, notably Weller et al. in 2020.\94\
Our assessment of the studies published since subpart W was finalized
supports revising the emission factors for pipelines in the Natural Gas
Distribution industry segment of subpart W. For more information on the
review and analysis of the various studies, see the subpart W TSD,
available in the docket for this rulemaking (Docket Id. No. EPA-HQ-OAR-
2019-0424).
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    \91\ U.S. EPA. Inventory of U.S. Greenhouse Gas Emissions and
Sinks: Revisions under Consideration for Natural Gas Distribution
Emissions. December 2015. Available at https://www.epa.gov/sites/production/files/2016-02/documents/proposed_revisions_to_ng_distribution_segment_emissions.pdf and in
the docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424.
    \92\ U.S. EPA. Inventory of U.S. Greenhouse Gas Emissions and
Sinks 1990-2014: Revisions to Natural Gas Distribution Emissions.
April 2016. Available at https://www.epa.gov/sites/production/files/2016-08/documents/final_revision_ng_distribution_emissions_2016-04-14.pdf and in the docket for this rulemaking, Docket Id. No. EPA-HQ-
OAR-2019-0424.
    \93\ Lamb, B.K. et al. ``Direct Measurements Show Decreasing
Methane Emissions from Natural Gas Local Distribution Systems in the
United States.'' Environ. Sci. Technol. 2015, 49, 5161-5169.
Available in the docket for this rulemaking, Docket Id. No. EPA-HQ-
OAR-2019-0424.
    \94\ Weller, Z.D.; Hamburg, S.P.; and Von Fischer, J.C. 2020.
``A National Estimate of Methane Leakage from Pipeline Mains in
Natural Gas Local Distribution Systems.'' Environ. Sci. Technol.
2020, 54(1), 8958. Available in the docket for this rulemaking,
Docket Id. No. EPA-HQ-OAR-2019-0424.
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    The population emission factors for distribution mains and services
are a function of the average measured leak rate (scf/hr) and the
frequency of annual leaks observed (leaks/mile-year or leaks/service-
year) by pipeline material (e.g., protected steel, plastic). The Lamb
et al. and Weller et al. studies utilized different approaches for
quantifying leak rates and determining the pipeline material-specific
frequency of annual leaks. The Lamb et al. study quantified leaks from
distribution mains and services using a high volume sampling method and
some downwind tracer measurements and estimated the frequency of leaks
by pipeline material using company records and Department of
Transportation (DOT) repaired leak records from six local distribution
companies (LDCs). This methodology was consistent with the GRI/EPA
study. The Weller et al. study quantified leaks from only distribution
mains using the Advanced Mobile Leak Detection (AMLD) technique, which
involves mobile surveying using high sensitivity instruments and
algorithms that predict the leak location and size, attributed leaks to
the pipeline material using geographic information system (GIS) data,
and estimated the frequency of leaks using modeling.
    During our assessment of the Lamb et al. and Weller et al. studies,
we identified the method for leak quantification as being a key
strength of the Lamb et al. study and the significantly larger sample
size used in estimating the annual leak frequency as being a key
strength of the Weller et al. study. In order to take advantage of the
strengths of both studies, we are proposing to amend the subpart W
emission factors for distribution mains using the measurements from
Lamb et al. combined with the pipeline material specific leaks per mile
data from Weller et al. We are proposing to amend the subpart W
emission factors for distribution services using the measurements from
Lamb et al. only, consistent with the emission factors used in the 2016
U.S. GHG Inventory, because services were not included in the Weller et
al. study. See the subpart W TSD, available in the docket for this
rulemaking (Docket Id. No. EPA-HQ-OAR-2019-0424) for more information
on our assessment of both studies and the derivation of the proposed
emission factors from the data published by Lamb et al. and Weller et
al. We are seeking comments on the approach of combining data from both
studies to update the distribution mains emission factors. As
alternatives to the proposed amendments, we also considered updating
the distribution mains emission factors using data from each study
independently. Accordingly, we are also seeking comment on whether
using data only from Lamb et al., consistent with the emission factors
used in the U.S. GHG Inventory, or only from Weller et al. to update
the distribution mains emission factors would be preferable over the
combined approach included in this proposal, and if so, which study is
preferred and why.
    For below grade stations, the 2016 U.S. GHG Inventory also began
applying a new emission factor from the data published by Lamb et al.
to the count of stations to estimate emissions from these sources. In
order to assess the

appropriateness of incorporating this revision into the subpart W
requirements for below grade stations (i.e., replacing the set of below
grade emission factors by station type and inlet pressure with one
single emission factor), the EPA performed an analysis of the reported
subpart W data for below grade stations compared to data from the
recent studies (see the subpart W TSD, available in the docket for this
rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424). We found that the
subpart W reported station count combined with the current subpart W
emission factors yields an average emission factor similar to the U.S.
GHG Inventory emission factor; as such, using either set of emission
factors would yield approximately the same emissions results for the
GHGRP.
    Therefore, we are proposing to amend the emission factors for below
grade transmission-distribution transfer stations and below grade
metering-regulating stations in Table W-7 (proposed to be moved to
Table W-8) to a single emission factor without regard to inlet
pressure. We are also proposing to amend the corresponding section
header in Table W-7 (proposed to be moved to Table W-8) for below grade
station emission factors and the references to Table W-7 (proposed to
be moved to Table W-8) in 40 CFR 98.233(r)(6)(i) to clarify the
emission factor that should be applied to both types of below grade
stations (i.e., transmission-distribution transfer and metering-
regulating). This proposed amendment would impact the reporting
requirements as well, as it would consolidate six emission source types
to two emission source types (below grade transmission-distribution
transfer stations and below grade metering-regulating stations, without
differentiating between inlet pressures) for purposes of reporting
under 40 CFR 98.236(r)(1). This proposed amendment would improve the
data quality through use of more recent emission factors and would be
consistent with changes made to the U.S. GHG Inventory. It would also
result in reporting of fewer data elements, consistent with section
II.B.3 of this preamble.
    Gathering pipeline emission factors. Facilities in the Onshore
Petroleum and Natural Gas Gathering and Boosting industry segment
quantify the emissions from equipment leaks from gathering pipelines
following the procedures in 40 CFR 98.233(r). This method uses the
count of equipment, subpart W population emission factors in Table W-
1A, and operating time to estimate emissions. The population emission
factors for gathering pipeline mains in Table W-1A are based on leak
rates from natural gas distribution companies and gathering pipeline-
specific activity data as provided in the 1996 GRI/EPA study.\95\ The
population emission factors for gathering pipelines are published per
mile by pipeline material.
---------------------------------------------------------------------------

    \95\ GRI/EPA. Methane Emissions from the Natural Gas Industry,
Volume 9: Underground Pipelines. Prepared for Gas Research Institute
and U.S. Environmental Protection Agency National Risk Management
Research Laboratory by L.M. Campbell, M.V. Campbell, and D.L.
Epperson, Radian International LLC. GRI-94/0257.2b, EPA-600/R-96-
080i. June 1996. Available in the docket for this rulemaking, Docket
Id. No. EPA-HQ-OAR-2019-0424.
---------------------------------------------------------------------------

    As noted previously in this section, the EPA is proposing to update
the natural gas distribution population emission factors in Table W-7
(proposed to be moved to Table W-8) to subpart W using the results of
studies and information that were not available when the rule was
originally finalized. In particular, the EPA is proposing to update the
leak rate portion of the emission factor based on data published by
Lamb et al. in 2015.\96\ The EPA has reviewed the recent studies
published for onshore petroleum and natural gas gathering and boosting
facilities as well as the additional studies for pipeline distribution
mains, and none of the studies provide new emissions data or activity
data specific to gathering pipelines. Therefore, consistent with the
updates to the emission factors for distribution mains, and consistent
with section II.A.1 of this preamble, we are proposing to revise the
gathering pipeline population emission factors to use the leak rates
from Lamb et al. (2015). We are not proposing to update the activity
data (leaks per mile of pipeline) portion of the emission factors, as
the information in the 1996 GRI/EPA study continues to be the best
available data specific to gathering pipelines. For more information on
the proposed updates to the gathering pipeline population emission
factors, see the subpart W TSD, available in the docket for this
rulemaking (Docket Id. No. EPA-HQ-OAR-2019-0424).
---------------------------------------------------------------------------

    \96\ Lamb, B.K. et al. ``Direct Measurements Show Decreasing
Methane Emissions from Natural Gas Local Distribution Systems in the
United States.'' Environ. Sci. Technol. 2015, 49, 5161-5169.
Available in the docket for this rulemaking, Docket Id. No. EPA-HQ-
OAR-2019-0424.
---------------------------------------------------------------------------

m. Other Large Release Events
    We are proposing to add an additional emissions source, referred to
as ``other large release events'' to capture abnormal emission events
that are not fully accounted for using existing methods in subpart W,
consistent with section II.A.3 of this preamble. Most of the emission
sources and methodologies included in subpart W characterize emissions
that routinely occur at oil and gas facilities as part of their normal
operations. While some sources covered by subpart W methodologies, such
as equipment leaks, may represent ``malfunctioning'' equipment, these
sources are ubiquitous across the oil and gas sector, are generally
small, and have been studied and characterized. On the other hand,
there have been several large, atypical release events at oil and gas
facilities over the last few years where it was difficult to
sufficiently include these emissions in annual GHGRP reports. For
example, a storage wellhead leak at Aliso Canyon released approximately
100,000 metric tons of CH4 between October 2015 and February
2016 and a well blowout in Ohio released an estimated 40,000 to 60,000
tons of CH4 in a 20-day period in 2018. The emissions from
these types of releases were not well represented using the existing
calculation methodologies in subpart W because these were not common or
predictable events.\97\ Because these events can significantly
contribute to the total GHG emissions from this sector, we are
proposing new calculation methods for estimating the GHG emissions from
other large release events in 40 CFR 98.233(y) and requirements for
reporting other large release events in 40 CFR 98.236(y). These
proposed additional calculation and reporting requirements would apply
to all subpart W industry segments and would improve the accuracy of
emissions reported under subpart W and enhance the overall quality of
the data collected under the GHGRP.
---------------------------------------------------------------------------

    \97\ The EPA notes that the full emissions from this event were
included in the U.S. GHG Inventory based on the results of multiple
measurement studies.
---------------------------------------------------------------------------

    The new calculation requirements being proposed rely on measurement
data or engineering estimates of the amount of gas released and
measurement data, if available, or process knowledge (best available
data) to estimate the composition of the released gas. 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. This is equivalent to approximately
500,000 scf of pipeline quality natural gas. We selected this proposed
threshold to capture reporting for large emission events, such as well
blowouts, well releases, and large pressure relief venting. In order to
establish this reporting threshold, we first assessed other emission
sources that we considered large. Specifically,

we considered completions of hydraulically fractured wells that are not
controlled (i.e., not performed using reduced emission completions) to
be large emissions events. Based on analysis of GHGRP data of wells
that are not reduced emission completions and that vent, the U.S. GHG
Inventory developed an average emission factor of about 360
mtCO2e for these events. Because this is an average
emissions 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.
    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 will be less than this average value. The 250
mtCO2e threshold is approximately equivalent to 500,000 scf
of natural gas, which compares reasonably well with the lower range of
well blowouts expected based on the average emission factor of 2.5
MMscf per event.
    We also find that the 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
conclude 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-2019-0424. 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 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, 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. 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.1.g 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-2019-0424.
    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
event because such events are so rare that they generally do not exist
when measurement studies are conducted. Additionally, skewing the
emission factors used to account for such an event would yield
erroneously high emissions from normal operations for nearly all
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, 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.
    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 reporting requirement that would
require subpart W reporters to indicate whether an ``other large
release event'' was identified under any provisions of NSPS OOOOb or an
applicable approved state plan or applicable Federal plan in 40 CFR
part 62. As described in section III.J.1.k of this preamble, the EPA
proposed a fugitive emissions monitoring program in NSPS OOOOb and EG
OOOOc, including an alternative screening approach for fugitive
emissions from well sites and compressor stations that would allow the
use of advanced measurement technologies to detect emissions. 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
methane satellite imagery, would not be specifically included as
measurement methods in 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.
n. Combustion
    Methane slip from compressor engines. All facilities reporting
under subpart W except those in the Onshore Natural Gas Transmission
Pipeline industry segment must include combustion emissions in their
annual report. Facilities in the Onshore Petroleum and Natural Gas
Production, Onshore Petroleum and Natural Gas Gathering and Boosting,
and Natural Gas Distribution industry segments calculate emissions in
accordance with the provisions in 40 CFR 98.233(z) and report
combustion emissions per 40 CFR 98.236(z). Reporters in the other
industry segments calculate and report combustion emissions under
subpart C (General Stationary Fuel Combustion Sources). The authors of
several recent studies have examined combustion emissions at Onshore
Petroleum and Natural Gas Gathering and Boosting facilities and have
demonstrated that a significant portion of emissions can result from
unburned methane entrained in the exhaust of natural gas compressor
engines (also referred to as ``combustion slip'' or ``methane slip'').
These studies contend that emissions from natural gas compressor
engines included in the GHGRP are significantly underestimated because
they do not account for combustion slip.\98\ The EPA performed a review
of each of these studies and the U.S. GHG Inventory to determine
whether and how combustion slip emissions have been incorporated into
published data and how the incorporation of combustion slip would
affect the emissions from the petroleum and natural gas system sector
reported to the GHGRP (see the subpart W TSD, available in the docket
for this rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424).
---------------------------------------------------------------------------

    \98\ Zimmerle et al., Characterization of Methane Emissions from
Gathering Compressor Stations: Final Report (October 2019 Revision)
and Vaughn et al., ``Methane Exhaust Measurements at Gathering
Compressor Stations in the United States,'' Environmental Science &
Technology. 2021, 55 (2), 1190-1196, both available in the docket
for this rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424.
---------------------------------------------------------------------------

    Based on the EPA's review and analysis, there appears to be
combustion slip for all compressor engine types at oil and gas
facilities. In addition, while the recent studies are focused on the
Onshore Petroleum and Natural Gas Gathering and Boosting industry
segment, the EPA's literature review found the presence of combustion
slip in different industry segments, so it appears that combustion slip
is dependent on the type of engine and not the application (i.e., we
expect combustion slip from compressor engines regardless of the
industry segment). Therefore, the EPA is proposing to revise the
methodologies for determining combustion emissions from compressor
engines to account for combustion slip, consistent with section II.A.3
of this preamble. For the three subpart W industry segments that
calculate combustion emissions per 40 CFR 98.233(z), we are proposing
to accomplish this with two amendments to the calculation methods and
the addition of one new reporting requirement. For compressor engines
in those subpart W industry segments that combust natural gas and
qualify to determine emissions using the subpart C calculation
methodologies per 40 CFR 98.233(z)(1) and proposed new
98.233(z)(2),\99\ we are proposing that reporters would use subpart-W
specific emission factors by engine design class (e.g., 2-stroke lean-
burn, 4-stroke lean-burn, 4-stroke rich-burn, or other) in proposed new
Table W-9 rather than the emission factors in Table C-2. For compressor
engines that combust natural gas and determine emissions per 40 CFR
98.233(z)(2) (proposed to be moved to 40 CFR 98.233(z)(3)), we are
proposing updated combustion efficiency value(s) ([eta]) by engine
design class to be used in equations W-39A and W-39B that would reflect
combustion slip. We are also proposing to add a reporting requirement
to 40 CFR 98.233(z)(2) to specify the design class of reported internal
combustion units that are compressor-drivers to facilitate verification
of the selected emission factors and efficiencies, as applicable, and
the resulting emissions.
---------------------------------------------------------------------------

    \99\ See section III.J.2.f of this preamble for information on
the proposed amendments to 40 CFR 98.233(z) to increase the
flexibility for reporters to use the subpart C calculation
methodologies.
---------------------------------------------------------------------------

    In an analogous amendment for the reporters in the other subpart W
industry segments that calculate and report combustion emissions under
subpart C, we are proposing that they also use subpart W-specific
emission factors rather than the emission factors in Table C-2.
Currently, these facilities use either equation C-8, C-8a, C-8b, C-9,
C-9a, C-9b, or C-10 in 40 CFR 98.33(c), as it corresponds to the Tier
methodology selected to estimate their CO2 emissions, to
estimate CH4 emissions. These equations rely on the use of a
default CH4 emission factor from Table C-2 to estimate
emissions. As described in section III.B of this preamble, the emission
factor term definition in each of these equations is proposed to be
amended to reference Table W-9 rather than Table C-2 specifically for
quantifying emissions from compressor-drivers. We are also proposing to
add a footnote to Table C-2 to specify that the default CH4
emission factor should only be used for combustion devices that are not
compressor-drivers.
    Clarifications of calculation methodologies. As noted previously in
this section, Onshore Petroleum and Natural Gas Production, Onshore
Petroleum and Natural Gas Gathering and Boosting, and Natural Gas
Distribution facilities report combustion emissions calculated in
accordance with 40 CFR 98.233(z) instead of reporting under subpart C.
Stakeholders (e.g., GPA Midstream) have identified several concerns
with the requirements in 40 CFR 98.233(z). First, GPA Midstream has
indicated that for fuels using the existing provisions of 40 CFR
98.233(z)(2) to calculate emissions, the requirements for determining
the gas composition could result in inaccurate calculations of