factors depending on the applicable industry segment. For facilities in
the Onshore Petroleum and Natural Gas Production and in the Onshore
Petroleum and Natural Gas Gathering and Boosting industry segments, we
are proposing an emission factor of 21 scf/hr/device for continuous
high bleed devices in existing Table W-1A (proposed Table W-1) based on
study data for these industry segments. For facilities in the Onshore
Natural Gas Processing, Onshore Natural Gas Transmission Compression,
Underground Natural Gas Storage, and Natural Gas Distribution industry
segments, we are proposing an emission factor of 30 scf/hr/device for
continuous high bleed devices in proposed Table W-1 based on study data
from transmission compression stations. These proposed continuous bleed
emission factors consider emissions from pneumatic devices based on
measurements while the devices are in service, not just actuating.
    Because none of the three proposed calculation methods described in
section III.E.1 and 2 of this preamble would allow the use of the
current default population emission factor methodology for intermittent
bleed pneumatic devices, we are proposing to remove the population
emission factors for intermittent bleed pneumatic devices from existing
Tables W-1A, W-3B, and W-4B and not include them in proposed Table W-1.
The EPA requests comment on whether the EPA should instead retain the
use of default population emission factors as an alternative
calculation methodology (as Calculation Method 4) for sites, i.e.
include in the final rule an option for sites to not conduct
measurements or monitor intermittent bleed devices. If the population
emission factor calculation method is retained, the EPA requests
comment on the appropriate intermittent bleed pneumatic device emission
factors to include in the final rule. Based on our review of the
recently published pneumatic device study data, we would consider
revising the intermittent bleed pneumatic device emission factor for
facilities in the Onshore Petroleum and Natural Gas Production and in
the Onshore Petroleum and Natural Gas Gathering and Boosting industry
segments to 8.8 scf/hr/device. This emission factor considers emissions
from pneumatic devices based on measurements while the devices are in
service, not just actuating, and may include emissions from devices
that were malfunctioning during the time of the measurement. We have
limited new data specific to intermittent bleed pneumatic devices for
other industry segments. We would consider retaining the intermittent
bleed pneumatic device emission factor of 2.3 scf/hr/device for
facilities in other applicable industry segments; however, this
emission factor is based on engineering calculations and would likely
underestimate emissions from devices that are malfunctioning (e.g.,
bleeding continuously or bleeding more than expected during an
actuation). The EPA requests comment and supporting data regarding
potential revisions to the intermittent bleed pneumatic device
population emission factors, if the use of population emission factors
as a calculation methodology is retained.
    For more information regarding this review and development of the
proposed emission factors, see the subpart W TSD, available in the
docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
    Finally, we note that we are not proposing to revise or remove the
default population emission factor in existing Table W-1A (proposed
Table W-1) for natural gas driven pneumatic pumps. Reporters that do
not have or elect to install a flow meter on the natural gas supply
line dedicated to any one or more natural gas driven pneumatic pumps
and that do not elect to measure the volumetric flow rate of emissions
from all the natural gas driven pneumatic pumps vented directly to the
atmosphere at a well-pad or gathering and boosting site would be
required to continue using the current default population emission
factor for pneumatic pumps vented directly to the atmosphere, as
proposed Calculation Method 3. The existing emission factor is based on
the average stroke volumes and frequencies for a range of typical
pumps.\67\ In contrast to some other equipment for which emission
factors are currently used to calculate emissions (e.g., intermittent
bleed pneumatic devices), the emissions per unit of operating time for
a given pump are not expected to vary significantly due to malfunctions
as the pump ages. As such, we expect the natural gas

driven pneumatic pump emission factor to provide an acceptably accurate
estimate of the average hourly emissions from natural gas driven
pneumatic pumps. For this reason, we are proposing to retain the
emission factor calculation method for this source type.
---------------------------------------------------------------------------

    \67\ Methane Emissions from the Natural Gas Industry, Volume 13:
Chemical Injection Pumps, Final Report. GRI-94/0257.30 and EPA-600/
R-96-080m. Gas Research Institute and U.S. Environmental Protection
Agency. June 1996. Available in the docket for this rulemaking,
Docket Id. No. EPA-HQ-OAR-2023-0234.
---------------------------------------------------------------------------

    In the 2022 Proposed Rule we proposed clarifying the definition of
the time parameter in equation W-2 of the current rule. The current
definition is the ``average estimated number of hours in the operating
year that the pumps were operational.'' We proposed changing the word
``operational'' to ``in service (i.e., supplied with natural gas).''
This change was proposed to be consistent with the proposed change to
the time term in equation W-1 for pneumatic devices. This change was
proposed for the pneumatic device equation because the specified
emission factors were developed based on emission measurement tests
conducted over periods when the devices were actuating as well as
periods when they were not actuating (i.e., theoretical steady-state
continuous bleeding, or for intermittent devices, when they
theoretically were not emitting). However, after further review, we
determined that the current emission factor for pneumatic pumps was
developed based on observations of pump operation at several production
facilities (e.g., stroke rates and frequency of pump use) and pump
manufacturer data (e.g., gas consumption per volume of chemical pumped,
plunger diameter, and stroke length) for a variety of chemical
injection pumps.\68\ This means the emission factor represents
emissions when pumps are actuating, or, in other words, when they are
actively pumping liquid. Thus, we are now proposing to clarify the
definition of the term ``T'' in current equation W-2 (equation W-2B in
proposed 40 CFR 98.233(c)) by replacing the word ``operational'' with
``pumping liquid.'' We request comment on the potential for natural gas
to leak through a pump to the atmosphere when the pump is not actively
pumping liquid and the mechanism for such leakage.
---------------------------------------------------------------------------

    \68\ Methane Emissions from the Natural Gas Industry, Volume 13:
Chemical Injection Pumps, Final Report. GRI-94/0257.30 and EPA-600/
R-96-080m. Gas Research Institute and U.S. Environmental Protection
Agency. June 1996. Available in the docket for this rulemaking,
Docket Id. No. EPA-HQ-OAR-2023-0234.
---------------------------------------------------------------------------

4. Hours of Operation of Natural Gas Pneumatic Devices
    In correspondence with the EPA via e-GGRT, some reporters have
indicated that they are interpreting the term ``operational'' in the
definition of variable ``Tt'' in equation W-1 in 40 CFR
98.233(a) and the term ``operating'' in the reporting requirements in
40 CFR 98.236(b)(2) differently than the EPA intended. Both the current
emission factors and the proposed calculation methodologies described
in sections III.E.1 through III.E.3 of this preamble for natural gas
pneumatic devices were developed by taking both periods of actuation
and periods without actuation into account; \69\ in other words, the
emission factors are population emission factors considering all times
when the device was connected to natural gas supply line. To calculate
emissions accurately using the existing population emission factor, the
average number of hours used in equation W-1 should be the number of
hours that the devices of a particular type are in service (i.e., the
devices are receiving a measurement signal and connected to a natural
gas supply that is capable of actuating a valve or other device as
needed). Similarly, based on the calculation methodology for the site-
specific population emission factor in Calculation Method 2 or for the
leaker emission factor approach proposed in Calculation Method 3, the
number of hours that the devices of a particular type are in service
(i.e., the devices are receiving a measurement signal and connected to
a natural gas supply that is capable of actuating a valve or other
device as needed) must be used in the calculation, Therefore,
consistent with section II.D of this preamble, we are proposing to
revise the definition of variable ``Tt'' in existing
equation W-1 (proposed equation W-1B) in 40 CFR 98.233 and the
corresponding reporting requirements in proposed 40 CFR
98.236(b)(4)(ii)(C)(4), (b)(4)(iii)(C)(4), and (b)(5)(i)(C)(2) to use
the term ``in service (i.e., supplied with natural gas)'' rather than
``operational'' or ``operating,'' to clarify the original and current
intended meaning of that variable and term. We are also proposing to
use this ``in service'' language for the time variables in the newly
proposed equations W-1C and W-1D for the leaker factor approach for
intermittent bleed pneumatic devices under Calculation Method 3.
---------------------------------------------------------------------------

    \69\ As noted previously, the development of the current
emission factors for natural gas pneumatic devices is described in
Greenhouse Gas Emissions Reporting from the Petroleum And Natural
Gas Industry: Background Technical Support Document, U.S. EPA,
November 2010, (Docket Id. No. EPA-HQ-OAR-2009-0923-3610), also
available in the docket for this rulemaking, Docket Id. No. EPA-HQ-
OAR-2023-0234.
---------------------------------------------------------------------------

5. Natural Gas Pneumatic Devices and Natural Gas Driven Pneumatic Pumps
Routed to Control
    We understand that emissions from some natural gas pneumatic
devices and/or natural gas driven pneumatic pumps are routed to control
(i.e., a flare, combustion unit, or vapor recovery system). The
population emission factor is based on natural gas vented directly to
the atmosphere from these pneumatic devices/pumps and does not
accurately reflect emissions from controlled pneumatic devices/pumps.
Therefore, consistent with section II.B of this preamble, we are
proposing to revise 40 CFR 98.233(a) and (c) to clarify requirements
for calculating emissions from natural gas pneumatic devices and
natural gas driven pneumatic pumps, respectively, that are vented
directly to the atmosphere versus pneumatic devices/pumps that are
routed to control, consistent with the intent of the current rule. We
are proposing revisions to 40 CFR 98.233(a) and (c) to clarify that the
existing population emission factor calculation methodology is intended
to apply only to pneumatic devices/pumps vented directly to the
atmosphere. The proposed new calculation methodologies described in
sections III.E.1 and 2 of this preamble also specify that they apply
only to pneumatic devices/pumps vented directly to the atmosphere.
    We are proposing that flared emissions from natural gas pneumatic
devices or pumps are not required to be calculated and reported
separately from other flared emissions. We are proposing to specify
that instead emission streams from natural gas pneumatic devices or
pumps that are routed to flares are required to be included in the
calculation of total emissions from the flare according to the
procedures in 40 CFR 98.233(n) and reported as part of the total flare
stack emissions according to the procedures in 40 CFR 98.236(n), in the
same manner as emission streams from other source types that are routed
to the flare. Similarly, we are proposing that emissions from natural
gas pneumatic devices or pumps that are routed to a combustion unit are
required to be combined with other streams of the same fuel type and
used to calculate total emissions from the combustion unit as specified
in 40 CFR 98.233(z) and reported as part of the total emissions from
the combustion unit as specified in 40 CFR 98.236(z). We are also
proposing reporters would not calculate or report emissions from
natural gas pneumatic devices or pumps if the emissions are routed to
vapor

recovery and are not subsequently routed to a combustion device (e.g.,
are routed back to process or sales).
    We are also proposing to require in proposed 40 CFR 98.236(b)(2)
and 98.236(c)(2) reporting of the total number of continuous low bleed,
continuous high bleed, and intermittent bleed natural gas pneumatic
devices and the total number of natural gas driven pneumatic pumps at
the site (regardless of vent disposition), the number of these devices/
pumps that are vented to the atmosphere for at least a portion of the
year, and the number of these devices/pumps that are routed to control
for at least a portion of the year (which includes natural gas
pneumatic devices/pumps routed to a flare, combustion unit, or vapor
recovery system). The total count of pneumatic devices or pumps is a
proposed reporting element because the total count may not always be
equal to the sum of the other two counts. For example, a reporter that
switches from atmospheric venting to routing to control during a year
for a particular pneumatic device or pump would include that pneumatic
device or pump in both the count of devices or pumps that vent directly
to atmosphere and in the count of devices or pumps that are routed to
flares. However, that pneumatic device or pump would only be counted
once towards the total number of pneumatic devices or pumps, allowing
us to discern the number of devices or pumps that exclusively vent or
exclusively route to control. The number of pneumatic devices or pumps
vented directly to the atmosphere would be used in the verification of
annual reports to the GHGRP. The total count of pneumatic devices or
pumps at the facility and the number of pneumatic devices or pumps that
are routed to a flare, combustion, or vapor recovery would provide the
EPA with information to better characterize emissions from this source,
including how many pneumatic devices or pumps are controlled across the
industry and how the use of controls for pneumatic pumps changes across
multiple years.

F. Acid Gas Removal Unit Vents

1. Reporting of Methane Emissions From Acid Gas Removal Units
    Reporters currently report only CO2 emissions from AGR
vents using one of the four calculation methodologies provided in 40
CFR 98.233(d). In the 2010 subpart W TSD, the EPA explained that
``CH4 emissions from AGR vents are insignificant, 0.06
percent of the total volume of CO2 and CH4
emissions,'' leading to the decision at that time not to require
reporting of CH4 emissions from AGR vents.\70\ However, as
described in more detail later in this section, both the number and
size of the AGRs reported to the GHGRP in recent years are greater than
the values used in that initial assessment, so current nationwide
CH4 emissions are likely greater than estimated in the 2010
subpart W TSD.
---------------------------------------------------------------------------

    \70\ Greenhouse Gas Emissions Reporting from the Petroleum And
Natural Gas Industry: Background Technical Support Document, U.S.
EPA, November 2010, (Docket Id. No. EPA-HQ-OAR-2009-0923-3610), also
available in the docket for this rulemaking, Docket Id. No. EPA-HQ-
OAR-2023-0234.
---------------------------------------------------------------------------

    To determine the potential sources to be evaluated for inclusion in
the original subpart W, the EPA used the emissions for the year 2006 as
published in the 2008 U.S. GHG Inventory.\71\ As documented in the 2010
subpart W TSD, the EPA estimated that AGR vents emitted 643 MMscf of
CH4 that year, which corresponds generally to the 12,380 mt
CH4 from AGR vents shown in Table A-114 of the 2008 U.S. GHG
Inventory. The inputs for that estimate include the emission factor for
AGR vents from Volume 14: Glycol Dehydrators of the 1996 GRI/EPA study
(available in the docket for this rulemaking, Docket Id. No. EPA-HQ-
OAR-2023-0234), and an estimate of about 290 AGRs at processing plants,
scaled from the 1992 estimate of 371 AGRs presented in the GRI/EPA
study. However, the emission factor in the 1996 GRI/EPA study is based
on an AGR throughput of about 35 MMscf per day, while the average feed
rate of the AGRs reported at onshore natural gas processing plants in
RY2021 was around 78 MMscf per day and the average feed rate of all
reported AGRs in RY2021 was around 59 MMscf per day. In addition, there
were 391 AGRs reported at onshore natural gas processing plants and 579
total AGRs reported in RY2021. In other words, the total quantity of
natural gas treated in AGRs in RY2021 at onshore natural gas processing
plants was about three times the total amount of natural gas estimated
to be treated by the 2008 U.S. GHG Inventory. Therefore, the
CH4 emissions from AGR vents are likely to be significantly
greater than estimated in the 2010 subpart W TSD, and as such, the EPA
is proposing to amend 40 CFR 98.233(d) and 98.236(d) to require
calculation and reporting of those emissions. The proposed inclusion of
reporting for emissions of CH4 from AGR vents would improve
the coverage of total CH4 emissions reported to subpart W,
consistent with section II.A of this preamble. For more information on
the estimation of potential CH4 emissions from AGR vents,
see the subpart W TSD, available in the docket for this rulemaking,
Docket Id. No. EPA-HQ-OAR-2023-0234.
---------------------------------------------------------------------------

    \71\ U.S. EPA. Inventory of U.S. Greenhouse Gas Emissions and
Sinks 1990-2006. April 2008. Available at https://www.epa.gov/ghgemissions/inventory-us-greenhouse-gas-emissions-and-sinks-1990-2006 and in the docket for this rulemaking, Docket Id. No. EPA-HQ-
OAR-2023-0234.
---------------------------------------------------------------------------

    There are four calculation methods currently provided in 40 CFR
98.233(d) for calculating CO2 emissions from AGR vents.
Calculation Method 1 is to use a continuous emissions monitoring system
(CEMS) if one is installed (40 CFR 98.233(d)(1)), and Calculation
Method 2 requires the use of a vent flow meter if there is one
installed that is not part of a CEMS and use either a continuous gas
analyzer or quarterly gas samples for composition (40 CFR
98.233(d)(2)). If neither a CEMS nor a vent flow meter is installed,
reporters currently may use Calculation Method 3, engineering equations
(40 CFR 98.233(d)(3)), or Calculation Method 4, modeling simulation via
software (40 CFR 98.233(d)(4)).
    As part of this proposal, the EPA evaluated the existing
calculation methods for the purpose of proposing to require
CH4 emissions from AGR vents, and based on that assessment,
Calculation Methods 2, 3, and 4, are generally appropriate to use for
CH4. Calculation Method 1 is not considered an option for
CH4 because the EPA is not currently aware of continuous
CH4 monitors that meet the EPA's criteria for CEMS.\72\
Therefore, the EPA is proposing to specify that reporters must use
Calculation Method 2 to calculate CH4 emissions if they have
a vent flow meter installed (including the flow meter of a
CO2 CEMS) and is proposing to revise the subscripts of the
variables in equation W-3 slightly to specify that reporters should
calculate both CO2 and CH4. If there is no vent
flow meter, the EPA is proposing that reporters would choose between
Calculation Method 3 or Calculation Method 4. For Calculation Method 4,
the EPA is proposing to add the CH4 content of the feed
natural gas and the outlet natural gas as parameters that must be used
to characterize emissions. This specification is analogous to the
existing requirement to use acid gas content of the feed natural gas
and the acid gas content of outlet natural gas to characterize
CO2 emissions. For Calculation Method 3, the EPA is
proposing to revise the existing equations W-4A and W-4B and to add

a new equation W-4C. With the addition of CH4 as a component
for these equations, reporters would need to have information on four
parameters rather than the three they currently need to know. For more
information on the derivation of these proposed equations, see the
subpart W TSD, available in the docket for this rulemaking, Docket Id.
No. EPA-HQ-OAR-2023-0234. We request comment on whether these are the
appropriate methods for calculating CH4 from AGR vents,
including whether there are continuous CH4 monitors that
meet the EPA's criteria for CEMS.
---------------------------------------------------------------------------

    \72\ See https://www.epa.gov/emc/emc-continuous-emission-monitoring-systems for more information on CEMS.
---------------------------------------------------------------------------

    Although we used the 1996 GRI/EPA emission factor to assess the
potential magnitude of CH4 emissions from AGR vents, both in
the 2010 subpart W TSD and for an initial assessment of whether to
include additional reporting requirements in this proposal, we are not
proposing use of that emission factor as a method for calculating
emissions under subpart W. That emission factor is based on modeling of
an average system from many years ago, and as discussed earlier in this
section, the model AGR is much smaller than the AGRs reported to
subpart W more recently. The emission factor is per AGR, so it does not
take into account the feed rate of the AGR, the concentration of
CO2 entering the unit, or the level of treatment (i.e.,
concentration of CO2 exiting the unit).
    The EPA is also proposing to add relevant reporting elements for
CH4 from each AGR to 40 CFR 98.236(d). The additional data
elements include annual CH4 emissions vented directly to the
atmosphere; annual average volumetric fraction of CH4 in the
vent gas if using Calculation Method 2; additional inputs for
Calculation Method 3, depending on the equation used (i.e., as
applicable, the annual average volumetric fraction of CH4 in
the natural gas flowing out of the AGR, annual average volumetric
fraction of CH4 content in natural gas flowing into the AGR,
annual average volumetric fraction of CO2 in the vent gas
exiting the AGR and annual average volumetric fraction of
CH4 in the vent gas exiting the AGR); and the CH4
content of the feed natural gas and outlet natural gas if using
Calculation Method 4.
    Finally, we note that under the current provisions of subpart W,
reporters with AGRs routed to flares are required to report the
CO2 emissions from the AGR that pass through the flare as
AGR vent emissions, and the emissions that result from combustion of
any CH4 in the AGR vent stream are reported as flare stack
emissions. In the 2022 Proposed Rule, we proposed to provide more
clarity regarding how to determine the flow rate and composition of the
gas routed to a flare if Calculation Method 3 or 4 were used to
calculate CO2 emissions. Because we are proposing to require
reporting of CH4 emissions from AGR vents, there would be no
reason for subpart W to include special provisions for AGR vents routed
to flares that are different from the provisions for all other emission
source types routed to flares. Instead, the EPA is proposing that AGR
vents routed to a flare would follow the same calculation requirements
as other emission source types and would begin reporting flared AGR
emissions (CO2, CH4, and N2O) separately from
vented AGR emissions (CO2 and CH4). See section
III.N of this preamble for more information on the proposed flaring
calculation and reporting provisions. In a similar amendment, we are
proposing to specify that AGR vents routed to an engine would calculate
CO2, CH4, and N2O emissions using the provisions
of 98.233(z) or subpart C, whichever is applicable to that industry
segment. We are also proposing that AGRs routed to a flare or engine
for the entire year would report the information in proposed 40 CFR
98.236(d)(1) except for the calculation method, the indication of
whether any CO2 emissions were recovered and transferred
offsite, and the CO2 and CH4 emissions from the
unit. If the AGR routed to a flare or an engine only for part of the
year, the other information in proposed 40 CFR 98.236(d)(1) would be
required to be reported for the part of the year in which emissions
were vented directly to the atmosphere.
2. Calculation Method 4
    Reporters with AGRs that elect to calculate emissions using
Calculation Method 4 are currently required to calculate emissions
using any standard simulation software package that uses the Peng-
Robinson equation of state and speciates CO2 emissions.
According to existing 40 CFR 98.233(c)(4), the information that must be
used to characterize emissions include natural gas feed temperature,
pressure, flow rate, and acid gas content; outlet natural gas acid gas
content and temperature; unit operating hours; and solvent temperature,
pressure, circulation rate, and weight. These parameters currently must
be determined for typical operating conditions over the calendar year
by engineering estimate and process knowledge based on best available
data. Consistent with section II.B of this preamble, we are proposing
that the input parameters related to the natural gas feed that are used
for the simulation software must be obtained by measurement. Those
parameters include natural gas feed temperature, pressure, flow rate,
acid gas content, CH4 content, and, for nitrogen removal
units, nitrogen content. We are proposing that reporters would collect
measurements reflective of representative operating conditions over the
time period covered by the simulation. We are not proposing to change
the requirement that the other parameters must be determined for
operating conditions based on engineering estimate and process
knowledge.
    We are also proposing that the parameters that must be used to
characterize emissions should reflect operating conditions over the
time period covered by the simulation rather than just over the
calendar year. Under this proposed change, reporters could continue to
run the simulation once per year with parameters that are determined to
be representative of operating conditions over the entire year.
Alternatively, reporters would be allowed to conduct periodic
simulation runs to cover portions of the calendar year, as long as the
entire calendar year is covered. The reporter would then sum the
results at the end of the year to determine annual emissions. In that
case, the parameters for each simulation run would be determined for
the operating conditions over each corresponding portion of the
calendar year. Finally, we are proposing to clarify that the
information reported under 40 CFR 98.236(d)(2)(ii) should be provided
on an annual basis, either as an average across the year, or a total
for the year (in the case of operating hours for the unit).
    We are also proposing an additional change to the reported data for
reporters with AGRs that elect to calculate emissions using Calculation
Method 4. One of the required inputs to report is the solvent weight,
in pounds per gallon (under existing 40 CFR 98.236(d)(2)(iii)(L)). A
variety of different solvents may be used in an AGR (e.g., chemical
solvents such as monoethanolamine (MEA) and methyl diethanolamine
(MDEA), physical solvents such as SelexolTM and
Rectisol[supreg]), and the solubility of CO2 varies across
the different types of solvent. Requiring reporters to provide solvent
characteristics provides information about the type of solvent used so
the emissions calculated by the modeling run could be verified.
However, the ``solvent weight'' is the only data element related to the
identification of the solvent that is currently collected, and the
values reported across all reporters have been inconsistent over the
last few years, indicating that this data element is

likely not clear to reporters (e.g., some reporters appear to be
providing the density of the solvent and others appear to be providing
the amine concentration in weight percent). In addition, the densities
of common amine-based solvents are fairly close in value, so even among
reporters that are providing values within the expected range of
solvent densities, we have found it difficult to use this data element
to identify the solvent type. Finally, the current requirement to
report solvent weight does not specify how this value should be
determined, but given the precise values being reported, it appears
that reporters are either measuring the solvent or reporting a specific
value provided by the vendor.
    Therefore, we are proposing to replace the existing requirement to
report solvent weight with a requirement (proposed 40 CFR
98.236(d)(2)(iii)(N)) to report the solvent type and, for amine-based
solvents, the general composition. Reporters would choose the solvent
type option from a pre-defined list that most closely matches the
solvent type and, for amine-based solvents, the general composition,
used in their AGR. The standardized response options would include the
following: ``SelexolTM,'' ``Rectisol[supreg],''
``PurisolTM,'' ``Fluor SolventSM,''
``BenfieldTM,'' ``20 wt% MEA,'' ``30 wt% MEA,'' ``40 wt%
MDEA,'' ``50 wt% MDEA,'' and ``Other (specify).'' We are proposing to
use commercially available trade names in this list rather than
chemical compositions, as the trade names are more commonly used among
AGR operators and therefore more readily available. This proposed
amendment to collect standardized information about the solvent is
expected to result in more useful data that would improve verification
of reported data and better characterize AGR vent emissions, consistent
with section II.C of this preamble. It would also improve the quality
of the data reported compared to the apparently inconsistent
application of the current requirements. In addition, the solvent type
and composition rarely change from one year to the next, so once the
data element is reported the first time, most reporters would be able
to copy the response from the previous year's reporting form each year.
Therefore, the proposal to require reporters to select a solvent type
and composition from these standardized responses is also expected to
improve verification and the consistency of reported data compared to
the current requirement, consistent with section II.C of this preamble.
In the event that reporters use more than one type of solvent in their
AGR during the year, the proposed reporting requirement specifies that
reporters would select the option that corresponds to the solvent used
for the majority of the year.
3. Reporting of Flow Rates
    We are proposing several amendments to improve the quality and
verification of AGR flow rate information, consistent with sections
II.C of this preamble. Reporters are currently required to report the
total feed rate entering the AGR in units of million cubic feet per
year (existing 40 CFR 98.236(d)(1)(iii), proposed 40 CFR
98.236(d)(1)(iv)). The existing rule does not specify million standard
cubic feet per year or million actual cubic feet per year, so reporters
may provide this feed rate in either of those units of measure.
However, there is not currently a requirement for reporters to provide
the actual temperature and pressure for the total feed rate if it is
reported in million actual cubic feet, so it is difficult for the EPA
to tell which are the correct units of measure. Reporters also provide
flow rates that correspond with the calculation method chosen, and the
subpart W reporting form currently requests the temperature and
pressure corresponding to those flow rates, but they cannot necessarily
be used to clarify the units of measure for the total feed rate. For
example, for Calculation Method 1 or 2, reporters provide the annual
volume of gas vented from the AGR in cubic feet (existing 40 CFR
98.236(d)(2)(i)(B), proposed 40 CFR 98.236(d)(2)(i)(C)), but the
temperature and pressure of this vent gas does not correlate directly
to the temperature and pressure for the AGR feed rate. In addition,
while the reporting form requests the temperature and pressure
corresponding to various flow rates, those data elements are not
specifically included in 40 CFR 98.236(d), so there appears to be some
inconsistency between the flow rates reported and the temperature and
pressure reported. For example, in some cases, the flow rate appears to
be reported in standard cubic feet but the temperature and pressure
appear to represent actual conditions; in these cases, the temperature
and pressure may have been the values used to convert the flow rate
from actual conditions to the reported standard conditions, but it is
not clear. As a result, the EPA has found it difficult to verify the
AGR flow rates in some cases.
    Therefore, we are first proposing to require that the total annual
feed rate that is required to be reported for all AGRs regardless of
the how the emissions are calculated (existing 40 CFR
98.236(d)(1)(iii), proposed 40 CFR 98.236(d)(1)(iv)) would be reported
at standard conditions (i.e., in units of MMscf per year). The
revisions would make the units of measure for this total annual feed
rate more consistent with the natural gas throughputs reported for each
industry segment in existing 40 CFR 98.236(aa) and would standardize
the units of measure for this total annual feed rate across all AGRs.
Stakeholders have previously indicated that standard industry practice
for either calculating or measuring the flow of gas into or out of an
AGR would be in standard conditions.\73\ Based on the data reported
from RY2015 to RY2021, the EPA estimates that at least 80 percent of
the AGR total annual feed rates were reported in MMscf per year (for
the remaining 20 percent of the AGRs, the EPA either was able to
determine that the AGR feed rate was reported in million actual cubic
feet per year, or it is unclear whether the feed rate was reported in
actual or standard conditions). Therefore, this proposed revision is
not expected to result in changes for the majority of the reporters but
would improve the quality of the overall data.
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    \73\ E.g., see U.S. EPA. Response to Public Comments on
Greenhouse Gas Reporting Rule: 2014 Revisions and Confidentiality
Determinations for Petroleum and Natural Gas Systems, November 2014,
Comment EPA-HQ-OAR-2011-0512-0084-A2, Excerpt Number 73.
---------------------------------------------------------------------------

    Second, we are proposing to specifically require the temperature
and pressure that correspond to the flow rates reported for Calculation
Methods 1, 2, or 3 (reporters using Calculation Method 4 are already
required to report the temperature and pressure of the acid gas feed,
under existing 40 CFR 98.236(d)(2)(iii)(B) and (C)). Depending on the
calculation method selected, reporters are required to provide the vent
gas flow rate, flow rate of natural gas into the AGR, and/or the flow
rate of natural gas out of the AGR. The calculation methodologies in
existing 40 CFR 98.233(d)(1) through (3) and the reporting requirements
in existing 40 CFR 98.236(d)(2)(i) and (ii) accommodate use of flow
rates in either actual or standard conditions to calculate emissions.
The proposed additions, at proposed 40 CFR 98.236(d)(2)(i)(D) and (E)
and (d)(2)(ii)(I), (J), (L), and (M), specify that reported temperature
and pressure should be the actual temperature and pressure if the flow
rate is reported in actual conditions, or standard temperature and
pressure if the flow rate is reported in standard conditions. These
proposed additions would provide the EPA with the ability to verify the
emissions calculations more

efficiently and would provide a more consistent data set overall.

G. Dehydrator Vents

    Dehydrators are used to remove water from produced natural gas
prior to transferring the natural gas into a pipeline or to a gas
processing facility. Subpart W requires reporting of GHG emissions from
dehydrator vents at onshore petroleum and natural gas production,
onshore petroleum and natural gas gathering and boosting, and natural
gas processing facilities. Emissions are determined using one of the
calculation methodologies for glycol dehydrators provided in existing
40 CFR 98.233(e) based on the unit's annual average daily natural gas
throughput. For glycol dehydrator units with an annual average daily
natural gas throughput less than 0.4 MMscf per day, reporters currently
use population emission factors and equation W-5 to calculate
volumetric CO2 and CH4 emissions per existing 40
CFR 98.233(e)(2) (Calculation Method 2). For glycol dehydrator units
with an annual average daily natural gas throughput greater than or
equal to 0.4 MMscf per day, reporters must follow the provisions under
existing 40 CFR 98.233(e)(1), which require modeling GHG emissions
using a software program (e.g., AspenTech HYSYS[supreg] \74\ or GRI-
GLYCalcTM \75\) (Calculation Method 1). Facilities with
desiccant dehydrators calculate volumetric CO2 and
CH4 emissions using equation W-6 and the provisions of
existing 40 CFR 98.233(e)(3) (Calculation Method 3). In the 2022
Proposed Rule, the EPA proposed to remove the emissions calculation and
reporting requirements for desiccant dehydrators per 40 CFR
98.233(e)(3) and 40 CFR 98.236(e)(3). However, to avoid potential gaps
in emissions data and improve the accuracy of the data collected in the
GHGRP (consistent with section II.A of this preamble), the EPA is not
proposing the removal of desiccant dehydrator requirements in this
proposal.
---------------------------------------------------------------------------

    \74\ AspenTech HYSYS[supreg] software available from AspenTech
website (https://www.aspentech.com/).
    \75\ GRI-GLYCalcTM software available from Gas
Technology Institute website (https://sales.gastechnology.org/).
---------------------------------------------------------------------------

1. Selection of Appropriate Calculation Methodologies for Glycol
Dehydrators
    As noted in section III.G of this preamble, for dehydrators that
have an annual average of daily natural gas throughput that is less
than 0.4 MMscf per day, reporters currently use population emission
factors and equation W-5 to calculate volumetric CO2 and
CH4 emissions per Calculation Method 2 (40 CFR 98.233(e)(2))
and report emissions per 40 CFR 98.236(e)(2). Reporters with glycol
dehydrators that have an annual average of daily natural gas throughput
that is greater than or equal to 0.4 MMscf per day are currently
required to model their dehydrator emissions per Calculation Method 1
(40 CFR 98.233(e)(1)). Through requests submitted to the GHGRP Help
Desk and correspondence with the EPA via e-GGRT, reporters have
indicated the desire to use Calculation Method 1 for determining
emissions from dehydrators that have a throughput that is less than 0.4
MMscf per day, as they stated that the population emission factors
provided in 40 CFR 98.233(e)(2) are not always representative of their
dehydrators' actual emissions. Process simulations and models require
unit-specific inputs, so it is reasonable to expect that they would
result in more accurate emissions estimates for dehydrators that have
differing operating characteristics than those used to develop the
Calculation Method 2 emission factors. Therefore, we are proposing to
revise the calculation requirements of 40 CFR 98.233(e) to allow
reporters the ability to use Calculation Method 1 or Calculation Method
2 when determining emissions from dehydrators that have an annual
average of daily natural gas throughput that is less than 0.4 MMscf per
day. We are also proposing to specify that if a facility is required to
or elects to perform emissions modeling of a glycol dehydrator
consistent with the methodology outlined in 40 CFR 98.233(e)(1), they
must use the results of the model for estimating emissions under 40 CFR
98.233(e). It is the EPA's intention with this proposal that if
reporters conduct modeling for environmental compliance or reporting
purposes, including but not limited to compliance with Federal or state
regulations, air permit requirements, annual inventory reporting, or
internal review, they would use those results for reporting under
subpart W. The EPA is also proposing revisions to 40 CFR 98.236(e) to
specify the applicable reporting requirements based on the selected
calculation method rather than the throughput of the dehydrator. This
amendment is expected to improve the quality of the data collected,
consistent with section II.B of this preamble.
2. Controlled Dehydrators
    In correspondence with the EPA via e-GGRT, some reporters have
asked the EPA for guidance regarding calculating emissions from
dehydrators that are routed to different control devices throughout the
reporting year (e.g., dehydrators that are routed to vapor recovery and
subsequently vented to atmosphere or routed to a flare when the vapor
recovery device is not operating). Given the proposed amendments to the
calculation methodology and reporting of flare stack emissions
(discussed in section III.N of this preamble), we are proposing to
revise the methodologies for calculating emissions from dehydrator
vents controlled by a vapor recovery system, flare, or regenerator
firebox/fire tubes currently provided in 40 CFR 98.233(e)(5) and (6),
respectively. The new language in proposed 40 CFR 98.233(e)(4) provides
a methodology for calculating emissions vented directly to the
atmosphere during periods of time when emissions are not routed to the
vapor recovery system, flare, or regenerator firebox/fire tubes. For
flared dehydrator emissions, the proposed 40 CFR 98.233(e) provisions
would direct reporters to the proposed methodologies in 40 CFR
98.233(n). As a regenerator firebox/fire tubes does not meet the
definition of a flare per 40 CFR 98.238, we are proposing methodologies
for calculating combusted emissions from a regenerator firebox/fire
tubes in 40 CFR 98.233(e)(5) using the combustion source equations W-
39A, W-39B, and W-40 of 40 CFR 98.233(z)(3). We are also proposing new
reporting requirements for dehydrator units with emissions routed to a
firebox/fire tubes in proposed 40 CFR 98.236(e)(1)(xvi) and (xvii),
(e)(2)(v), and (e)(3)(vii) that are consistent with the reporting
requirements for combustion sources in 40 CFR 98.236(z)(2). By
proposing these amendments, the EPA seeks to enhance the overall
quality of the data collected under the GHGRP, consistent with sections
II.B and II.D of this preamble.
    The EPA is also proposing revisions to two terms consistent with
the proposed amendments for reporting for glycol dehydrators with an
annual average daily natural gas throughput greater than or equal to
0.4 MMscf per day. The EPA is proposing to amend the definition of
``dehydrator vent emissions'' in 40 CFR 98.6 to confirm that dehydrator
emissions reporting should include emissions from both the dehydrator
still vent, and if applicable, the dehydrator flash vent. We are also
proposing to remove the term ``reboiler'' from the definition, as the
term ``regenerator'' refers to the same piece of equipment. Finally, we
are proposing to expand the dehydrator control types referenced in the
definition to include regenerator fireboxes/fire tubes and vapor
recovery systems. Additionally,

the EPA is proposing to amend the definition of ``vapor recovery
system'' in 40 CFR 98.6 to clarify that routing emissions from a
dehydrator regenerator still vent or flash tank separator vent to the
regenerator firebox/fire tubes does not qualify as vapor recovery for
purposes of 40 CFR 98.233. The EPA has noted significant variability in
the dehydrator emissions values reported over the past several years,
with values ranging from extremely high to almost negligible emissions,
which indicates that there are likely inconsistencies in how these
terms are being interpreted among subpart W reporters. In proposing
these edits, the EPA expects to improve the quality of the emissions
data reported and confirm the original intent of these terms.
3. Calculation Method 1 for Glycol Dehydrators
    Reporters with glycol dehydrator units that calculate emissions
using Calculation Method 1 are currently required to determine
emissions using any standard simulation software package that uses the
Peng-Robinson equation of state to calculate the equilibrium
coefficient; speciates CH4 and CO2 emissions from
dehydrators; and has provisions to include regenerator control devices,
a separator flash tank, stripping gas and a gas injection pump or gas
assist pump. According to current 40 CFR 98.233(e)(1), the information
that must be used to characterize emissions include natural gas feed
flow rate and water content; outlet natural gas water content;
absorbent circulation pump type, circulation rate, and absorbent type;
use of stripping gas, use of flash tank separator (and disposition of
recovered gas), hours operated, wet natural gas temperature, pressure,
and composition. These parameters currently must be determined for
typical operating conditions over the calendar year by engineering
estimate and process knowledge based on best available data. Consistent
with section II.B of this preamble, we are proposing that the input
parameters related to the natural gas feed that are used for the
simulation software must be obtained by measurement. Those parameters
include feed natural gas flow rate, feed natural gas water content, wet
natural gas temperature and pressure at the absorber inlet, and wet
natural gas composition. We are proposing that reporters would collect
measurements reflective of representative operating conditions over the
time period covered by the simulation. We are not proposing to change
the requirement that the other parameters must be determined for
operating conditions based on engineering estimate and process
knowledge.
    We are also proposing that the parameters that must be used to
characterize emissions should reflect operating conditions over the
time period covered by the simulation rather than just over the
calendar year. Under this proposed change, reporters could continue to
run the simulation once per year with parameters that are determined to
be representative of operating conditions over the entire year.
Alternatively, reporters would be allowed to conduct periodic
simulation runs to cover portions of the calendar year, as long as the
entire calendar year is covered. The reporter would then sum the
results at the end of the year to determine annual emissions. In that
case, the parameters for each simulation run would be determined for
the operating conditions over each corresponding portion of the
calendar year. Finally, we are proposing to clarify that the
information reported under 40 CFR 98.236(e)(1) should be provided on an
annual basis, either as an average across the year, or a total for the
year (in the case of operating hours for the unit).
    Subpart W currently lists two example software options, AspenTech
HYSYS[supreg] and GRI-GLYCalcTM (GLYCalc), that meet the
software requirements in 40 CFR 98.233(e)(1). Reporters are not limited
to only using these two example software options. However, the EPA
recently approved the use of ProMax \76\ software simulations for
compliance with 40 CFR part 63, subpart HH, National Emission Standards
for Hazardous Air Pollutants from Oil and Gas Production Facilities
(hereafter referred to as ``NESHAP HH'').\77\ In the approval letter,
the EPA concluded that the ProMax model results are typically
equivalent or more conservative when compared to the results from the
GLYCalc model and the total capture condensation method used by the EPA
in its research. After considering this issue, we expect that ProMax
meets the specifications of existing 40 CFR 98.233(e)(1) and,
therefore, we are proposing to add ProMax as an example software
program for calculating dehydrator emissions in 40 CFR 98.233(e)(1) for
clarity for reporters. Consistent with the EPA's approval of ProMax for
NESHAP HH compliance, the EPA is proposing that if reporters elect to
use ProMax, they would be required to use version 5.0 or above.
---------------------------------------------------------------------------

    \76\ BRE Promax[supreg] software available from BRE website
(https://www.bre.com/).
    \77\ Letter from Steffan Johnson, Group Leader, Measurement
Technology Group, U.S. EPA Office of Air Quality Planning and
Standards, to Josh Ravichandran, Bryan Research & Engineering, LLC,
Re: Response to request for broad source category-wide approval for
use of Bryan Research & Engineering's process simulation software,
ProMax[supreg] (ProMax) in lieu of the GRI-GLYCalcTM
software (GLYCalc) for modeling glycol dehydration unit emissions in
demonstrating compliance with 40 CFR part 63, subpart HH, National
Emission Standards for Hazardous Air Pollutants from Oil and Gas
Production Facilities (Subpart HH). March 31, 2022. Available at
https://www.epa.gov/system/files/documents/2022-03/ravichandran-bre-promax-alt-final_147_signed.pdf and in the docket for this
rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
---------------------------------------------------------------------------

    As stated above, the EPA indicated in the referenced NESHAP HH
ProMax approval that ProMax emissions results may be more conservative
than emissions calculated using GLYCalc. In order to assess potential
emissions changes between reporting years, the EPA is also proposing
add a new provision under 40 CFR 98.236(e)(1)(xviii) to request
reporting of the modeling software used to calculate emissions for each
dehydrator unit using Calculation Method 1. We expect these proposed
amendments would improve the quality of the data collected, consistent
with section II.B of this preamble.
4. Calculation Method 1 Reporting
    The EPA has reviewed the subpart W glycol dehydrator data and
reporting requirements in existing 40 CFR 98.236(e) and has made a
preliminary determination that additional information would help to
more accurately characterize emissions from glycol dehydrators using
Calculation Method 1. The EPA is proposing under 40 CFR 98.236(e) to
require separate reporting of emissions for a modeled glycol
dehydrator's still vent and flash tank vent. These vents often use
different control techniques, so requiring the emissions and applicable
controls from these vents to be reported separately would ensure that
emissions are more accurately characterized. The proposed data elements
are included in the output files from the modeling software used for
glycol dehydrators and therefore, this provision is not expected to be
difficult for reporters to implement. We expect these proposed
amendments would improve the quality of the data collected, consistent
with section II.C of this preamble.\78\
---------------------------------------------------------------------------

    \78\ In the 2022 Proposed Rule, the EPA proposed to add several
new reporting requirements for Calculation Method 1 glycol
dehydrators under 40 CFR 98.236(e)(1) in an effort to find a
potential correlation between dehydrator emissions and operating
parameters. However, after consideration of comments received on the
2022 Proposed Rule, we have decided not to propose these additional
elements in this proposal.

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

    In the 2022 Proposed Rule, the EPA proposed to collect additional
information on Calculation Method 1 glycol dehydrators under 40 CFR
98.236(e)(1) in an effort to derive a correlation between vent flow
rate, absorbent circulation rate, and glycol pump type. Comments on the
2022 Proposed Rule indicated that this additional information request
would be unnecessarily burdensome to reporters. Therefore, we are not
proposing the reporting of additional data elements for this purpose in
this proposal.
5. Calculation Method 2 for Glycol Dehydrators
    As noted in section III.F.3 of this preamble, for glycol
dehydrators with an annual average daily natural gas throughput less
than 0.4 MMscf per day, reporters currently use population emission
factors and equation W-5 to calculate volumetric CO2 and
CH4 emissions per existing 40 CFR 98.233(e)(2) and report
emissions per existing 40 CFR 98.236(e)(2). Under these current
requirements, the count of glycol dehydrators with annual average daily
natural gas throughput less than 0.4 MMscf per day could include
dehydrators with annual average daily natural gas throughput of 0 MMscf
per day (i.e., glycol dehydrators that were not operated during the
reporting year). As a result, some annual reports include a nonzero
count of dehydrators per existing 40 CFR 98.236(e)(2)(i) without any
corresponding CO2 and CH4 emissions. In these
cases, it is not clear if the reporter did not report emissions because
emissions are not expected, the emissions data were inadvertently
omitted, or the nonzero count represents the total count of all
dehydrators with annual average daily natural gas throughput less than
0.4 MMscf per day, including those that were not in use.
    Therefore, the EPA is proposing to clarify in 40 CFR 98.233(e)(2)
that the dehydrators for which emissions are calculated should be those
with annual average daily natural gas throughput greater than 0 MMscf
per day and less than 0.4 MMscf per day (i.e., the count should not
include dehydrators that did not operate during the year). Similarly,
the EPA is proposing to clarify in 40 CFR 98.236(e)(2) introductory
text that the count of dehydrators in existing 40 CFR 98.236(e)(2)(i)
(proposed 40 CFR 98.236(e)(2)(ii)) should also be those with annual
average daily natural gas throughput greater than 0 MMscf per day and
less than 0.4 MMscf per day. These proposed amendments are expected to
improve implementation and verification of reported data, consistent
with section III.C of this preamble.
    Additionally, the EPA is proposing edits to the existing reporting
requirements in current 40 CFR 98.236(e)(2). Specifically, we are
proposing to revise the data collected under current 40 CFR
98.236(e)(2)(iii) (proposed 40 CFR 98.236(e)(2)(iv)) to emphasize the
original intent of the rule. Currently, the requirement is to report
whether any Calculation Method 2 dehydrator emissions are routed to a
control device other than a vapor recovery system or a flare or
regenerator firebox/fire tubes (and if so, the type of control
device(s) and count of units routing to each control). We are proposing
to specifically state that the reporting of ``other'' control devices
should only include control devices that reduce CO2 and/or
CH4 emissions. This proposed revision would allow the EPA to
verify the expected reductions in vented CO2 and/or
CH4 emissions due to the use of the control device. This
proposed amendment is expected to improve implementation and
verification of reported data, consistent with section III.C of this
preamble.
6. Desiccant Dehydrators
    Subpart W requires reporting of desiccant dehydrators as a
subcategory of dehydrator vents. The data required to be reported for
desiccant dehydrators is consistent with the information that is
reported for Calculation Method 2 for small glycol dehydrators: the
total number of desiccant dehydrator units, whether any emissions from
Calculation Method 3 units were routed to a vapor recovery system,
flare, or other control (and if so, the count of units utilizing each
of those controls), and the vented and/or combusted emissions from
desiccant dehydrators. In June 2022, the EPA proposed to remove the
reporting of desiccant dehydrators; however, as described in section
II.B of this preamble, CAA section 136(h) directs the EPA to ensure
that reporting under subpart W reflects total CH4 emissions,
and we are no longer proposing to remove this source. Instead, to
better implement and verify the desiccant dehydrator data reported
under subpart W (consistent with section II.C of this preamble), the
EPA is proposing several updates to the current desiccant dehydrator
reporting requirements of 40 CFR 98.236(e)(3).
    Specifically, we are proposing to remove the cross-references from
40 CFR 98.236(e)(3) to 40 CFR 98.236(e)(2)(i) through (iv) and instead
include all of the applicable reporting requirements from current 40
CFR 98.236(e)(2)(i) through (iv) for Calculation Method 2 glycol
dehydrators as reporting requirements for Calculation Method 3
desiccant dehydrators under 40 CFR 98.236(e)(3). Currently, the
language in 40 CFR 98.236(e)(3)(i) simply states that the same
information that is included under 40 CFR 98.236(e)(2)(i) through (iv)
should be reported for dehydrators that use desiccant. While we
acknowledge that the current language has been correctly interpreted by
reporters as-is, replicating the requirements under 40 CFR 98.236(e)(3)
would make the rule easier to follow and allow the EPA to further
clarify the required reporting data elements for desiccant dehydrators.
Additionally, the EPA is proposing to specify that only desiccant
dehydrators that were opened during the reporting year should be
included in the total number of desiccant dehydrators at the facility
under proposed 40 CFR 98.236(e)(3)(ii). This revision would align the
reported count of desiccant dehydrators with the applicability of
Calculation Method 3 methodology, which requires facilities to
calculate emissions from the amount of gas vented from vessels when
they are depressurized and opened for the desiccant refilling process.
Also, we are proposing to require reporting of the total volume of all
opened desiccant dehydrator vessels and the total number of desiccant
dehydrator openings in the calendar year as new data elements under
proposed 40 CFR 98.236(e)(3)(iii) and (iv), respectively. These data
elements are inputs into equation W-6 and should, therefore, be readily
available to facilities. With the change to reported number of
desiccant dehydrators under proposed 40 CFR 98.233(e)(3)(ii) and the
proposed addition of the two new data elements for vessel volume and
number of vessel openings, the EPA would be able to more effectively
verify the reported desiccant dehydrator emissions from each facility.
    The EPA is also proposing to revise the definitions of
``dehydrator'' and ``desiccant'' in 40 CFR 98.6 to conform with the
inclusion of desiccant dehydrators in subpart W. Currently, the
definition of ``dehydrator'' indicates that desiccant is an example of
a liquid absorbent. Since desiccants are solid materials, we are
proposing to remove desiccant from the list of example liquid
absorbents and instead define dehydrators as devices that use either a
liquid absorbent or a desiccant to remove water vapor from a natural
gas stream. The current definition of ``dehydrator'' also indicates
that the device is used to absorb water vapor.

However, since some desiccants work by adsorbing water, we are
proposing to replace the word ``absorb'' with ``remove.'' The
definition of ``desiccant'' indicates that desiccants ``include
activated alumina, pelletized calcium chloride, lithium chloride and
granular silica gel material.'' We are proposing to add ``molecular
sieves'' to the list of example desiccant because they are a common
type of desiccant. Since the list of example desiccants is not meant to
be exhaustive or all-inclusive, we are also proposing to replace the
word ``including'' with ``including, but not limited to.'' With these
changes, the proposed definition would clarify that desiccants
``include, but are not limited to, molecular sieves, activated alumina,
pelletized calcium chloride, lithium chloride and granular silica gel
material.'' We expect these proposed amendments would improve the
overall quality and completeness of the emissions data collected by the
GHGRP, consistent with section II.A of this preamble.
    Consistent with the proposed revisions to the definition of
``desiccant'' under 40 CFR 98.6, the EPA is proposing to add two
additional data elements to the desiccant dehydrator reporting
requirements in 40 CFR 98.236(e)(3). We are proposing to require
reporting of the count of opened desiccant dehydrators that used
deliquescing desiccant (e.g., calcium chloride or lithium chloride) and
the count of opened desiccant dehydrators that used regenerative
desiccant (e.g., molecular sieves, activated alumina, or silica gel)
present at the facility (proposed 40 CFR 98.236(e)(3)(ii)(B) and (C),
respectively). As regenerative desiccant dehydrators are not opened as
often as deliquescing desiccant dehydrators, the EPA would use this new
data to verify large swings in desiccant dehydrator emissions year-to-
year and to gain a better understanding of the distribution of
emissions between the two types of desiccant dehydrators. These
proposed amendments would improve verification of reported data and
ensure accurate reporting of emissions, consistent with section II.C of
this preamble.

H. Liquids Unloading

1. Selection of Calculation Method
    Subpart W currently requires reporting of emissions from well
venting for liquids unloading. Facilities currently calculate emissions
using measured flow rates under Calculation Method 1 (40 CFR
98.233(f)(1)) or engineering equations under Calculation Method 2 for
unloadings without plunger lifts (40 CFR 98.233(f)(2)) and Calculation
Method 3 for unloadings with plunger lifts (40 CFR 98.233(f)(3)). As
noted in the preamble to the NSPS OOOOb supplemental proposal,
facilities can face operational and safety issues managing liquids
unloading with the EPA noting in the preamble that there could be
situations where ``it is technically infeasible or not safe to perform
well liquids with zero emissions unloadings'' (87 FR 74781, December 6,
2022). The EPA believes these safety and operational issues can
possibly extend to taking measurements at wells with liquids unloading.
Therefore, the EPA is proposing to continue providing reporters the
option to use Calculation Methods 2 and 3 to calculate emissions from
liquids unloading. Both equations rely on well-specific data, including
well depth, tubing or casing diameter, and the flow line rate of gas,
to calculate well-level emissions. However, consistent with section
II.B of this preamble, the EPA is proposing that reporters with liquids
unloadings must calculate emissions from unloadings for each well at
least once every 3 consecutive calendar years or more frequently using
Calculation Method 1 to ensure that the engineering equations
accurately and consistently represent the quantity of emissions from
unloading events.
    To implement this change, the EPA is proposing to amend the
introductory text in 40 CFR 98.233(f) to add the requirement that
reporters must use Calculation Method 1 to calculate emissions from
well venting for liquids unloading every 3 consecutive calendar years
or more frequently. Calculation Method 1 currently requires reporters
to install a recording flow meter on the vent line used to vent gas
from the well to a separator or atmospheric tank and measure the flow
rate of the unloading events. The reporter must measure flow rates at
one or more wells in each sub-basin combination (sub-basin/plunger lift
indicator/automated/manual indicator) where wells are subject to
liquids unloading events. The average measured flow rate in standard
cubic feet per hour is then applied to each well with unloadings in the
same sub-basin combination for the time in hours during the year the
well is unloaded. To support implementation of this requirement, the
EPA is proposing to add 40 CFR 98.236(f)(2)(xi)(D) and
98.236(f)(2)(xii)(D) to require reporters to report the most recent
calendar year Calculation Method 1 was used to calculate emissions from
unloadings for the same sub-basin combination.
2. Reporting for Calculation Methods 2 and 3
    Under the current reporting requirements of 40 CFR 98.236(f),
facilities must report whether plunger lifts were used when using
Calculation Method 1 and must report the data elements used in
equations W-7A and W-7B. For Calculation Methods 2 and 3, however,
reporters currently only report a subset of the data elements used to
calculate emissions in equations W-8 and W-9. Specifically, for
Calculation Methods 2 and 3, reporters must provide a plunger lift
indicator (i.e., whether plunger lifts were used), total number of
wells with well venting for liquids unloading, the total number of
unloading events, and the casing diameter (Calculation Method 2) or the
tubing diameter (Calculation Method 3).
    In a 2019 study, Zaimes et al.\79\ evaluated various liquid
unloading scenarios, and the results indicated that differentiating
emissions only on the basis of type of unloading (plunger or non-
plunger lift) may not accurately assess emissions from this source. In
particular, Zaimes et al. noted that type of unloading should be
further differentiated for plunger lift unloadings between automated
and manual unloadings, suggesting further granularity is necessary to
properly characterize emissions. In particular, there could be
significant differences in the number and duration of unloadings and,
hence, differences in emissions between manual and automated plunger
lift unloadings and liquids unloading emissions. A manual unloading
occurs when field personnel attend to the well at the well-pad, for
example, to manually plunge a well at the site using a rig or other
method, to open a valve to direct flow to an atmospheric tank to clear
the well, or to manually shut-in the well to allow pressure to build in
the well-bore. Manual unloadings may be performed on a routine schedule
or on ``as needed'' basis. An automated unloading is performed without
manual interference. Examples of an automated unloading include a
timing and/or pressure device used to optimize intermittent shut-in of
the well before liquids choke off gas flow or to open and close valves,
continually operating equipment that does not require presence of an
operator such as rod pumping units, automated and unmanned plunger
lifts, or other

unloading activities that do not entail a physical presence at the
well-pad.
---------------------------------------------------------------------------

    \79\ Zaimes, G.G. et al. ``Characterizing Regional Methane
Emissions from Natural Gas Liquid Unloading.'' Environ. Sci.
Technol. 2019, 53, 4619-4629. Available in the docket for this
rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
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    The Zaimes et al. study did not evaluate manual and automated non-
plunger lift unloadings separately, but further differentiating non-
plunger lift unloadings between manual and automated unloadings in
subpart W could also improve data quality. Correspondence with
reporters via e-GGRT since subpart W reporting for the onshore
production segment began in 2011 indicates potentially meaningful
differences in the number of unloadings and emissions for manual versus
automated non-plunger lift unloadings. When the EPA finalized the
calculation methods and reporting requirements for well venting for
liquids unloading, the reporting requirements did not differentiate
between manual and automated non-plunger lift unloadings. However,
reporters have clearly affirmed the use of automated non-plunger lift
unloadings in response to multiple inquiries the EPA has made as part
of the annual report verification process.
    In addition, there are several data elements used to calculate
emissions from liquids unloading in equations W-8 and W-9 for
Calculation Methods 2 and 3 that are not currently required to be
provided. Specifically, reporters do not report well depth (Calculation
Method 2) or tubing depth (Calculation Method 3), the average flow-line
rate of gas, the hours that wells are left open to the atmosphere
during unloading events, and the shut-in, surface or casing pressure
(Calculation Method 2) or the flow-line pressure (Calculation Method
3). Requiring reporting of these data elements would improve
verification of annual reports to the GHGRP and would allow the EPA and
the public to replicate calculations and more confidently confirm
reported calculated emissions than is currently possible.
    The EPA is, therefore, proposing to revise the reporting
requirements in 40 CFR 98.236(f)(1) and (2) to require reporters to
include the following data elements, consistent with section II.C of
this preamble. In 40 CFR 98.236(f)(1), for Calculation Method 1, the
EPA is proposing that reporters would identify the type of unloading as
an automated or manual unloading in addition to identifying whether the
unloading is a plunger lift or non-plunger lift unloading. We are also
proposing in 40 CFR 98.236(f)(1) that reporters would report emissions
by unloading type combination (with or without plunger lifts, automated
or manual unloading). In addition, for each individual Calculation
Method 1 well that was tested during the year, we are proposing that
reporters would specify the type of unloading as automated or manual
unloading under 40 CFR 98.236(f)(1)(xi)(F) or 40 CFR
98.236(f)(1)(xii)(F), as applicable.
    For non-plunger lift unloadings that use Calculation Method 2 in 40
CFR 98.233(f)(2), the EPA is proposing in 40 CFR 98.236(f)(2) that
reporters would identify the type of non-plunger lift unloading as
automated or manual non-plunger lift unloading and that reporters would
report emissions and activity data separately for each unloading type
combination. In addition, for each well with non-plunger lift
unloadings, the EPA is proposing to revise and add requirements in
existing 40 CFR 98.236(f)(2)(ix) (proposed 40 CFR 98.236(f)(2)(xi) in
this proposed rule) to report the well depth for each well
(WDp) and the shut-in pressure, casing pressure or surface
pressure for each well, (SPp). Reporters would continue to
report the internal casing diameter (CDp) as is currently
required for non-plunger lift unloadings.
    For plunger lift unloadings that use Calculation Method 3 in 40 CFR
98.233(f)(3), the EPA is proposing in 40 CFR 98.236(f)(2) that
reporters would identify the type of plunger lift unloading as
automated or manual plunger lift unloading and that reporters would
report emissions and activity data separately for each unloading type
combination. In addition, for all each well with plunger lift
unloadings, the EPA is proposing to revise and add requirements in
existing 40 CFR 98.236(f)(2)(x) (proposed 40 CFR 98.236(f)(2)(xii) in
this proposed rule) to report the tubing depth (WDp) and the
flow-line pressure for each well in the sub-basin (SPp).
Reporters would continue to report the internal tubing diameter
(TDp) as is currently required for plunger lift unloadings.
    Finally, for each well with unloadings that uses Calculation Method
2 or 3, the EPA is proposing to add new requirements, as proposed 40
CFR 98.236(f)(2)(ix) and (x), to report the flow-line rate of gas
(SFRp) and the cumulative number of hours that the well is
left open to the atmosphere during unloading events (HRp,q),
respectively.
    To encourage accurate classification of manual and automated
unloadings for all calculation methods, the EPA is proposing to add new
terms in 40 CFR 98.238 for ``Manual liquids unloading'' and ``Automated
liquids unloading.'' The terms are proposed to be defined consistent
with the descriptions provided earlier in this section of this
preamble.
3. Other Clarifying Amendments
    The EPA is proposing an additional amendment to add clarity for
reporters with liquids unloadings. The EPA is proposing to specify in
the introductory text for 40 CFR 98.233(f) that calculation of
emissions from unloading events is required only when the well is
unloaded to the atmosphere or to a control device. The EPA is proposing
this change because these unloadings are the events that result in
emissions of GHG to the atmosphere. The proposed change, consistent
with sections II.C and II.D of this preamble, is intended to provide
clarity to reporters while also ensuring that the EPA continues to
receive accurate and relevant data.

I. Gas Well Completions and Workovers With Hydraulic Fracturing

    Reporters currently may use equation W-10A or W-10B to calculate
emissions from gas well completions and workovers with hydraulic
fracturing. Equation W-10A is used to calculate emissions from wells
using inputs obtained from a representative sample of wells within a
sub-basin and the ratio of the gas flowback rate to the production flow
rate, and equation W-10B is used to calculate emissions using inputs
obtained from all wells within a sub-basin and the flow rate and flow
volume of the gas vented or flared. In addition, reporters must use
Calculation Method 1 or Calculation Method 2 in existing 40 CFR
98.233(g)(1) for calculating inputs to equations W-12A and W-12B if
using equation W-10A. Calculation Method 1 relies on direct measurement
of gas flow rate during flowback to develop calculation inputs whereas
Calculation Method 2 uses an engineering equation to produce a
calculated flowback. Specifically, Calculation Method 2 uses the
measured gas pressure differential across the well choke to estimate
gas flow rate for natural gas well completions and workovers with
hydraulic fracturing. It is, therefore, often referred to as the
``Choke Flow'' equation. The Choke Flow equation is only available for
hydraulically fractured natural gas well completions and workovers. It
cannot be used for hydraulically fractured oil well completions and
workovers.
    The majority of onshore production facilities with hydraulically
fractured completions and workovers use equation W-10B to calculate
emissions. In RY2021, 118 onshore production facilities reported 2418
hydraulically fractured gas well completions or workovers. Only 15 of
those facilities used equation W-10A for emissions calculations for 385
gas well

completions or workovers. It is unknown what percentage of those
facilities use Calculation Method 2, as the calculation methodology is
not currently reported.
    Consistent with section II.B of this preamble, the EPA is proposing
to retain equations W-10A and W-10B, but is proposing to remove the
option in 40 CFR 98.233(g)(1) for reporters to use Calculation Method
2, the Choke Flow equation, when using equation W-10A. The EPA believes
that measurement of back flow rates is standard practice in the onshore
production segment, whether through measurement of every well
completion or workover or through measurement of a representative well
or workover. Moreover, this is supported by the large number of
reporters using equation W-10B compared with equation W-10A. The EPA
believes this proposal would improve reporting of emissions from
hydraulically fractured gas well completions and workovers while
impacting very few reporters due to the small number of reporters using
equation W-10A. The EPA understands that some reporters may be
concerned that there could be situations where direct measurement is
not possible for technical, operational or safety reasons; however,
subpart W provides requirements for use of missing data procedures as
specified in 40 CFR 98.235. The EPA is requesting comment on whether we
should retain Calculation Method 2 for gas well completions and
workovers with hydraulic fracturing. However, if the EPA retains
Calculation Method 2 following consideration of public comment on this
proposed rulemaking, the EPA expects we would also amend the reporting
requirements in the final rulemaking to improve data quality and
transparency. Specifically, if Calculation Method 2 is retained, the
EPA expects we would add a new reporting requirement in 40 CFR
98.236(g) for reporters that use equation W-10A to indicate whether the
backflow rate for the representative well was determined using
Calculation Method 1 or Calculation Method 2.

J. Blowdown Vent Stacks

1. Reporting Equipment Categories for Pipelines
    Subpart W currently requires reporting of blowdowns either using
flow meter measurements (40 CFR 98.233(i)(3)) or using unique physical
volume calculations by equipment or event types (40 CFR 98.233(i)(2)).
Stakeholders have indicated through correspondence with the EPA via e-
GGRT and the GHGRP Help Desk that the descriptions of the ``facility
piping'' and ``pipeline venting'' categories in 40 CFR 98.233(i)(2) as
it is currently written reference ``distribution'' pipelines but
compressor stations are generally not associated with distribution
pipelines. Therefore, the EPA is proposing to revise the descriptions
of the facility piping and pipeline venting categories in 40 CFR
98.233(i)(2) to reflect the EPA's intent regarding which equipment or
event type category is appropriate for each blowdown, consistent with
section II.D of this preamble. Our intent is that the ``facility
piping'' equipment category is limited to unique physical volumes of
piping (i.e., piping between isolation valves) that are located
entirely within the facility boundary. In contrast, the intent for the
``pipeline venting'' equipment category is that a portion of the unique
physical volume of pipeline is located outside the facility boundary
and the remainder, including the blowdown vent stack, is located within
the facility boundary. The proposed revisions to the equipment type
descriptions would clarify these distinctions. Additionally, we are
proposing to remove the reference to ``distribution'' pipelines in the
description of these two categories because we did not intend to limit
the pipeline venting category to unique physical volumes that include
such pipelines. We agree with the industry stakeholders who have
indicated that facilities subject to the blowdown vent stack reporting
requirements typically are connected to other pipelines such as
gathering pipelines or transmission pipelines, and on-site blowdowns
from sections of these pipelines should be reported. Finally, we note
that for the ``facility piping'' equipment category and the ``pipeline
venting'' equipment category, the existing phrase ``located within a
facility boundary'' in the descriptions of those categories generally
refers to being part of the facility as defined by the existing
provisions of subpart A or subpart W, as applicable, and we are not
proposing to change that portion of those descriptions. In other words,
blowdowns from unique physical volumes of gathering pipeline that are
entirely considered to be part of the ``facility with respect to
onshore petroleum and natural gas gathering and boosting'' as defined
in 40 CFR 98.238 would be assigned to the ``facility piping'' equipment
category. The ``pipeline venting'' equipment category would only apply
if the unique physical volume includes some sections of gathering
pipelines that are not part of the ``facility with respect to onshore
petroleum and natural gas gathering and boosting'' as defined in 40 CFR
98.238.
2. Blowdown Equipment Types
    As noted in section III.J.1 of this preamble, subpart W currently
requires reporting of blowdowns either using flow meter measurements
(40 CFR 98.233(i)(3)) or using unique physical volume calculations by
equipment or event types (40 CFR 98.233(i)(2)). When the Onshore
Natural Gas Transmission Pipeline industry segment was added to subpart
W in 2015, after considering public comments that indicated that the
existing equipment or event types were not appropriate for the new
segment, the EPA developed new equipment or event types that apply only
for the Onshore Natural Gas Transmission Pipeline industry segment (80
FR 64275, October 22, 2015). The new equipment or event types were
added to the introductory paragraph of 40 CFR 98.233(i)(2), where the
existing equipment or event types were already located, resulting in a
complex introductory paragraph. These changes also resulted in
identical third and last sentences in 40 CFR 98.233(i)(2) that
currently read as follows: ``If a blowdown event resulted in emissions
from multiple equipment types and the emissions cannot be apportioned
to the different equipment types, then categorize the blowdown event as
the equipment type that represented the largest portion of the
emissions for the blowdown event.''
    The EPA is proposing, consistent with section II.D of this
preamble, to move the listings of event types and the apportioning
provisions to a new 40 CFR 98.233(i)(2)(iv) so that the introductory
paragraph in 40 CFR 98.233(i)(2) would be more concise and provide
clearer information regarding which requirements are applicable for
each blowdown. Proposed 40 CFR 98.233(i)(2)(iv) includes separate
paragraphs for each set of equipment and event type categories and
would also provide clearer information regarding the applicable
requirements for each industry segment.
3. Blowdown Temperature and Pressure
    In the 2015 amendments to subpart W (80 FR 64262, October 22,
2015), the EPA added the Onshore Petroleum and Natural Gas Gathering
and Boosting industry segment and the Onshore Natural Gas Transmission
Pipeline industry segment and specified that both industry segments are
required to report emissions from blowdown vents. Stakeholders
representing the Onshore Petroleum and Natural Gas Gathering and
Boosting industry segment provided

comments on the proposed rule stating that the proposed definition of
facility would make equipment geographically dispersed, and blowdowns
may occur without personnel on-site or nearby, which would make it
difficult to collect the information needed to calculate emissions from
each blowdown (80 FR 64271, October 22, 2015). After considering those
comments, the EPA also specified in the final amendments to equation W-
14A that for emergency blowdowns at onshore petroleum and natural gas
gathering and boosting facilities, engineering estimates based on best
available information may be used to determine the actual temperature
and actual pressure.
    Since that time, the EPA has received questions through the GHGRP
Help Desk indicating that facilities in the Onshore Natural Gas
Transmission Pipeline industry segment also have unmanned blowdown
vents. Given that a ``facility with respect to the onshore natural gas
transmission pipeline segment'' is the total mileage of natural gas
transmission pipelines owned and operated by an onshore natural gas
transmission pipeline owner or operator, all of the blowdown vents at
that facility would be outside the fenceline of a transmission
compression station and would be geographically dispersed. The EPA
considers it reasonable to assume that those blowdown vents may also be
unmanned during an emergency blowdown, and thus it can similarly be
difficult to collect the information needed to calculate emissions from
each blowdown. Therefore, we are proposing to extend the provisions in
equation W-14A of 40 CFR 98.233(i)(2)(i) that allow use of engineering
estimates based on best available information to determine the
temperature and pressure of an emergency blowdown to the Onshore
Natural Gas Transmission Pipeline segment, which would align the
requirements for the two geographically dispersed industry segments
currently required to report blowdown vent stack emissions (Onshore
Natural Gas Transmission Pipeline and Onshore Petroleum and Natural Gas
Gathering and Boosting) and increase clarity of reporting requirements
for Onshore Natural Gas Transmission Pipeline reporters, consistent
with section II.D of this preamble. As described in section III.C.1 of
this preamble, we are also proposing to allow use of engineering
estimates to determine the temperature and pressure for emergency
blowdowns in equation W-14A for the geographically dispersed industry
segments that we are proposing would begin reporting emissions from
blowdown vent stacks (Onshore Petroleum and Natural Gas Production and
Natural Gas Distribution).
    In addition, similar provisions to allow use of engineering
estimates based on best available information to determine the
temperature and pressure of an emergency blowdown were not added to
equation W-14B of 40 CFR 98.233(i)(2)(i) in 2015 (80 FR 64262, October
22, 2015). We have reviewed this equation and have determined that this
omission was inadvertent. Therefore, we are proposing to add provisions
to equation W-14B of 40 CFR 98.233(i)(2)(i) to allow use of engineering
estimates to determine the temperature and pressure of an emergency
blowdown for both the geographically dispersed industry segments that
currently report blowdown vent stack emissions (Onshore Natural Gas
Transmission Pipeline and Onshore Petroleum and Natural Gas Gathering
and Boosting) as well as the geographically dispersed industry segments
that we are proposing would be required to begin reporting blowdown
vent stack emissions as described in section III.C.1 of this preamble
(Onshore Petroleum and Natural Gas Production and Natural Gas
Distribution), consistent with equation W-14A.

K. Atmospheric Storage Tanks

    Facilities in the Onshore Petroleum and Natural Gas Production and
Onshore Petroleum and Natural Gas Gathering and Boosting industry
segments are currently required to report CO2 and
CH4 emissions (and N2O emissions when flared)
from atmospheric pressure fixed roof storage tanks receiving
hydrocarbon liquids (hereafter referred to as ``atmospheric storage
tanks'').\80\ Reporters with gas-liquid separators or onshore petroleum
and natural gas gathering and boosting non-separator equipment (e.g.,
stabilizers, slug catchers) with annual average daily throughput of oil
greater than or equal to 10 barrels per day are required to calculate
annual CH4 and CO2 using Calculation Method 1 or
2 as described in existing 40 CFR 98.233(j)(1) and (2), respectively.
For wells flowing directly to atmospheric storage tanks without passing
through a separator with throughput greater than or equal to 10 barrels
per day, facilities must calculate annual CH4 and
CO2 emissions using Calculation Method 2. For hydrocarbon
liquids flowing to gas-liquid separators or non-separator equipment or
directly to atmospheric storage tanks with throughput less than 10
barrels per day, reporters must currently use Calculation Method 3 as
specified in existing 40 CFR 98.233(j)(3) to calculate annual
CO2 and CH4 emissions.
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    \80\ As described in section III.C.3 of this preamble, the EPA
is proposing to revise the source type in 40 CFR 98.233(j) from the
current name of ``onshore production and onshore petroleum and
natural gas gathering and boosting storage tanks'' to ``hydrocarbon
liquids and produced water storage tanks'' to reflect the proposal
to require reporting of storage tank emissions from additional
industry segments as well as to reflect the proposed addition of
reporting for produced water storage tanks. When used to describe
proposed amendments in this section, the general term ``atmospheric
storage tanks'' applies to the group of hydrocarbon liquids and
produced water storage tanks that would be reporting emissions if
these proposed amendments are finalized.
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1. Open Thief Hatches
    The purpose of a thief hatch on an atmospheric storage tank is
generally to allow access to the contents of the tank for sampling,
gauging, and determining liquid levels. The thief hatch also works
along with the vent valve to maintain safe tank operating pressures.
The EPA previously evaluated emissions from atmospheric storage tanks
as part of the 2016 amendments to subpart W (81 FR 86500, November 30,
2016) and determined that the subpart W calculation methodology in 40
CFR 98.233(j) already includes emissions from thief hatches or other
openings on atmospheric storage tanks in the Onshore Petroleum and
Natural Gas Production and Onshore Petroleum and Natural Gas Gathering
and Boosting industry segments. The subpart W calculation methodologies
for controlled atmospheric storage tanks include procedures for
determining emissions from storage tanks with a vapor recovery system
(existing 40 CFR 98.233(j)(4)) and storage tanks with a flare (existing
40 CFR 98.233(j)(5)). The procedure for determining emissions from a
tank with a vapor recovery system instructs reporters to adjust the
storage tank emissions downward by the magnitude of emissions recovered
using a vapor recovery system as determined by engineering estimate
based on best available data (existing 40 CFR 98.233(j)(4)(i)). The
procedure for determining emissions from an atmospheric storage tank
with a flare references 40 CFR 98.233(n), which currently instructs
reporters to use engineering calculations based on process knowledge,
company records, and best available data to determine the flow to the
flare if the flare does not have a continuous flow measurement device.
If a reporter sees emissions from a thief hatch or other opening on a
controlled atmospheric storage tank during an equipment leak survey

conducted using OGI, the reporter should consider that information as
part of the ``best available data'' used to calculate emissions from
that storage tank.
    However, it appears that reporters may not be accurately accounting
for emissions from open thief hatches on atmospheric storage tanks, as
many reporters claim 100 percent capture efficiency from vapor recovery
systems and flares. In order to emphasize the original intent of the
rule and ensure the accuracy of reported data, the EPA is proposing
several clarifying edits to 40 CFR 98.233(j)(4) and (5) (which, as
described in section III.K.3 of this preamble, would be combined in
proposed 40 CFR 98.233(j)(4)), consistent with sections II.B and II.C
of this preamble. We are proposing to specifically state that emissions
during times of reduced capture efficiency are required to be evaluated
to determine if adjustments are needed to the calculated recovered mass
from vapor recovery units or total emissions vented to atmosphere from
tanks. Reduced capture efficiency may occur during periods when the
control device is not operating or is bypassed when the control device
is operating, such as open thief hatches. The emissions that are not
captured by a vapor recovery system or sent to a flare must be
considered when calculating emissions from atmospheric storage tanks
vented directly to the atmosphere using Calculation Methods 1, 2, or 3.
    Further, we are proposing to provide a calculation methodology for
determining reduced capture efficiencies when a control device is in
use but a thief hatch is not properly seated or closed. We are
proposing to revise existing 40 CFR 98.233(j) to require facilities to
assume that no emissions are captured by the control device (0 percent
capture efficiency) when the thief hatch on a tank is open or not
properly seated. As described above, emissions during this time would
be reported as vented directly to the atmosphere as determined using
Calculation Methods 1, 2, or 3. Additionally, in order to accurately
quantify the time period that emissions are vented to atmosphere from
an open or not properly seated thief hatch, consistent with section
II.B of this preamble, the EPA is proposing in 40 CFR 98.233(j)(7) to
require either the use of a thief hatch sensor, if present and
operating, or if a thief hatch sensor is not present and operating,
visual inspection of the tank to monitor the thief hatch. We are
proposing that if a thief hatch sensor is present and operating on the
tank, sensor data must be used to inform the periods of time that a
thief hatch is open or not properly seated. The thief hatch sensor must
be capable of transmitting and logging data whenever a thief hatch is
open or not properly seated and when the thief hatch is subsequently
closed. Visual inspections would be required once per calendar year, at
a minimum, if a thief hatch sensor is not present and operating. If the
thief hatch is required to be monitored as a fugitive emissions
component to comply with NSPS OOOOb or the applicable EPA-approved
state plan or the applicable Federal plan in 40 CFR part 62, we are
proposing that visual inspections must be conducted at least as
frequent as the required visual, audible, or olfactory fugitive
emissions components surveys described in NSPS OOOOb or the applicable
EPA-approved state plan or the applicable Federal plan in 40 CFR part
62, or annually (whichever is more frequent). Similar to the provisions
of 40 CFR 98.233(q), if one visual inspection is conducted in the
calendar year and an open or not properly seated thief hatch is
identified, the reporter would be required to assume that the thief
hatch had been open for the entire calendar year. If multiple visual
inspections are conducted in the calendar year and an open or not
properly seated thief hatch is identified, the reporter would be
required to assume that the thief hatch had been open since the
preceding visual inspection (or the beginning of the year if the
inspection was the first performed in a calendar year) through the date
of the visual inspection (or the end of the year if the inspection was
the last performed in a calendar year). As discussed in the TSD for the
2016 amendments to subpart W, we determined that this methodology
provides an accurate quantification of emissions and it is consistent
with the timeframe required for subpart W annual reports.\81\ However,
we are requesting comment on expanding the start date of the open thief
hatch prior to the beginning of the reporting year. In this scenario,
if the reporter can identify the start date and it spans reporting
years, then that reporter would have to report the vented tank
emissions from an open thief hatch that occurred in each reporting year
and, if necessary, revise reports for the previous reporting year. The
EPA is also seeking comment on alternative methodologies for
quantifying the time that a thief hatch is left open or not properly
seated in lieu of a required visual inspection.
---------------------------------------------------------------------------

    \81\ 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-2023-0234.
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    The EPA is also proposing revisions to the atmospheric storage tank
reporting requirements in 40 CFR 98.236(j) with regard to open thief
hatches. Specifically, the EPA is proposing to require reporting of the
number of controlled atmospheric storage tanks with open or not
properly seated thief hatches within the reporting year, as well as the
total volume of gas vented through the open or not properly seated
thief hatches, for all calculation methods. 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.C of this
preamble.
    Stakeholders have voiced concerns through the GHGRP Help Desk
regarding the potential for double counting of tank thief hatch
emissions under 40 CFR 98.236(j), (q) and (r). The EPA has previously
confirmed that there is no potential for double counting thief hatches
in the methodologies provided in 40 CFR 98.233(q) and 40 CFR 98.233(r),
and we have also confirmed that there is no potential for double
counting thief hatches based on the proposed revisions to 40 CFR
98.236(j), (q) and (r). When determining leaks by population count per
40 CFR 98.233(r), the EPA is proposing updated major equipment emission
factors in existing Table W-1A (proposed Table W-1) that were developed
using Rutherford et al. (2021). Population emission factors are
presented by major equipment, which includes tanks--leaks; however, the
major equipment indicating venting emissions (e.g., tanks--
unintentional vents) were not included. For equipment leak surveys per
40 CFR 98.233(q), existing Table W-1E (proposed Table W-2) references
40 CFR 98.232(c)(21) and (j)(10) for onshore petroleum and natural gas
production and onshore petroleum and natural gas gathering and
boosting, respectively. These provisions, which describe the list of
components to be surveyed for equipment leaks, specifically state that
thief hatches or other openings on a storage vessel should not be
considered an ``other component.'' As such, we confirm that the
proposed thief hatch emissions reporting requirements in 40 CFR
98.236(j) would not overlap with the equipment leak emission reporting
requirements in 40 CFR 98.236(q) and (r). Also, we confirm that the
proposed thief hatch emissions reporting requirements would not overlap
with

emissions reporting in 40 CFR 98.236(y). As stated in section III.B of
this preamble, only thief hatch emissions that exceed the emissions
estimated under 40 CFR 98.233(j) by 250 mtCO2e or more, or
100 kg/hr of CH4 or more, would be included in the
calculation and reporting requirements for ``other large release
events.''
    The EPA is aware that there are circumstances other than open or
not properly seated thief hatches in which the capture efficiency of
the control device(s) for atmospheric storage tanks is reduced. These
circumstances include, but are not limited to, when the control device
is bypassed due to an open pressure relief device or when the
atmospheric storage tank covers and closed vent systems have openings
that allow emissions to vent directly to atmosphere. We are proposing
in 40 CFR 98.233(j)(4)(i)(D) to require facilities to account for time
periods of reduced capture efficiency from causes other than open or
not properly seated thief hatches when determining total emissions
vented directly to atmosphere based on best available data. However, we
are requesting comment on methodologies other than best available data
for identifying and quantifying time periods of reduced capture
efficiency in these situations. For example, the EPA is requesting
comment on the prevalence of pressure monitoring systems on atmospheric
storage tanks, how pressure monitoring systems can be used to identify
and determine the duration of periods of reduced capture efficiency due
to open pressure relief devices, and the cost of those pressure
monitoring systems.
2. Malfunctioning Dump Valves
    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 current 40 CFR
98.233(j)(6) (proposed 40 CFR 98.233(j)(5)) 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. The EPA is 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), (2), and (4). We are also
proposing to replace the ``n'' and ``o'' 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), (2), and (4).
    One of the inputs to equation W-16 is the total time the dump valve
did not close properly in the calendar year (Tn). Currently,
Tn may be estimated based on maintenance, operations, or
routine separator inspections that indicate the period of time when the
valve was malfunctioning in open or partially open position. In order
to improve the quality of the open dump valve emissions data collected,
consistent with section II.C of this preamble, the EPA is proposing to
formalize the requirement to perform routine visual inspections of
separator dump valves to determine if the valve is stuck in an open
position, thus allowing gas carry-through to the controlled tank(s).
    The EPA is proposing to revise the current provisions in 40 CFR
98.233(j)(6) (which is proposed 40 CFR 98.233(j)(5)) to require visual
inspection of the gas-liquid separator and determine if the liquid dump
valve is stuck in an open or partially open position. Incorporating
this proposed monitoring requirement would result in a more realistic
time estimate being used in equation W-16 and thus, more accurate
emissions reporting, consistent with section II.B of this preamble.
Visual inspections would be required once per calendar year, at a
minimum. Similar to the provisions of 40 CFR 98.233(q) and the proposed
section 40 CFR 98.233(j)(7), if one visual inspection is conducted in
the calendar year and a stuck dump valve is identified, the reporter
would be required to assume that the dump valve had been stuck open for
the entire calendar year. If multiple visual inspections are conducted
in the calendar year and a stuck dump valve is identified, the reporter
would be required to assume that the dump valve had been stuck open
since the preceding visual inspection (or the beginning of the year if
the inspection was the first performed in a calendar year) through the
date of the visual inspection (or the end of the year if the inspection
was the last performed in a calendar year). As discussed in the TSD for
the 2016 amendments to subpart W, we determined that this methodology
provides an accurate quantification of emissions and it is consistent
with the timeframe required for subpart W annual reports.\82\ We are
requesting comment on expanding the start date of the open thief hatch
prior to the beginning of the reporting year. In this scenario, if the
reporter can identify the start date and it spans reporting years, then
that reporter would have to report the vented tank emissions from an
open thief hatch that occurred in each reporting year and, if
necessary, revise reports for the previous reporting year.
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    \82\ 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-2023-0234.
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3. Applicability and Selection of Appropriate Calculation Methodologies
for Atmospheric Storage Tanks
    When determining the applicability of the different calculation
methodologies described in existing 40 CFR 98.233(j), reporters must
calculate their annual average daily throughput to determine whether
flow of hydrocarbon liquids through the gas-liquid separator, well, or
non-separator equipment is greater than or equal to 10 barrels per day.
Through the GHGRP Help Desk and correspondence with the EPA via e-GGRT,
it appears that reporters may be misinterpreting how hydrocarbon liquid
throughputs from gas-liquid separators should be determined.
Specifically, reporters appear to have differing conclusions regarding
whether the throughput determination should be based on flow into or
out of the separator and whether days when the separator was not
operating should be included when calculating the annual average.
Therefore, we are proposing revisions to the introductory text of 40
CFR 98.233(j) to emphasize the original intent of how the hydrocarbon
liquid throughputs should be determined. Specifically, we are proposing
to add language that clearly states that the annual average daily
throughput of hydrocarbon liquids should be based on

flow out of the separator, well, or non-separator equipment determined
over the actual days of operation. This amendment is expected to
clarify the rule, consistent with II.D of this preamble and improve the
quality of the data collected, consistent with section II.C of this
preamble.
    For hydrocarbon liquids flowing to gas-liquid separators or non-
separator equipment or directly to atmospheric storage tanks with
throughput greater than 0 barrels per day and less than 10 barrels per
day, reporters currently use population emission factors and equation
W-15 to calculate volumetric CO2 and CH4
emissions per Calculation Method 3 (40 CFR 98.233(j)(3)) and report
emissions per 40 CFR 98.236(j)(2). However, facilities with hydrocarbon
liquids flowing to gas-liquid separators or non-separator equipment or
directly to atmospheric storage tanks with throughput greater than or
equal to 10 barrels per day are given the option to either model their
tanks per Calculation Method 1 (40 CFR 98.233(j)(1)) or use a mass
balance approach per Calculation Method 2 (40 CFR 98.233(j)(2)).
Through the GHGRP Help Desk and correspondence with the EPA via e-GGRT,
reporters have expressed the desire to use Calculation Methods 1 or 2
for reporting emissions from storage tanks currently required to use
Calculation Method 3, as they stated that the population emission
factors provided in 40 CFR 98.233(j)(3) are not always representative
of their tanks' actual emissions. Calculation Methods 1 and 2 require
unit-specific inputs, so it is reasonable to expect that they would
result in more accurate emissions estimates for atmospheric storage
tanks that have differing operating characteristics than those used to
develop the Calculation Method 3 emission factors. Therefore, the EPA
is proposing to amend the requirements in 40 CFR 98.233(j) to specify
reporters may use Calculation Method 1, Calculation Method 2, or
Calculation Method 3 when determining emissions from hydrocarbon
liquids flowing to wells, gas-liquid separators, or non-separator
equipment with throughput greater than 0 barrels per day and less than
10 barrels per day. We are also proposing to specify in 40 CFR
98.233(j) that if a reporter is required or elects to perform emissions
modeling of an atmospheric storage tank consistent with the methodology
outlined in 40 CFR 98.233(j)(1), they must use the results of the model
for estimating emissions under 40 CFR 98.233(j). It is the EPA's
intention with this proposal that if reporters conduct modeling for
environmental compliance or reporting purposes, including but not
limited to compliance with Federal or state regulations, air permit
requirements, annual inventory reporting, or internal review, they
would use those results for reporting under subpart W. Consistent
revisions are also proposed for the reporting requirements in 40 CFR
98.236(j). These amendments are expected to improve the quality of the
data collected and provide flexibility to reporters, consistent with
section II.D of this preamble.
    The current requirements in 40 CFR 98.233(j) require calculation of
emissions from atmospheric pressure fixed roof storage tanks. As
discussed in section III.C of this preamble, the EPA evaluated the
sources included in present-day inventories of the oil and gas industry
in comparison with sources covered in subpart W and is proposing to
include additional sources in subpart W as a result of this evaluation.
Based on a similar evaluation, we are proposing to remove the ``fixed
roof'' language when referring to atmospheric pressure storage tanks
subject to 40 CFR 98.233(j). This would expand the reporting of tank
emissions to include floating roof tanks, which are a source included
in the 2022 U.S. GHG Inventory for the petroleum industry. We are also
proposing revisions to existing 40 CFR 98.236(j)(1)(x) and existing 40
CFR 98.236(j)(2)(i) to require separate reporting of the total count of
fixed roof and floating roof tanks at the facility. To provide
additional clarity for this proposed amendment, we are also proposing
to revise all instances of ``storage tanks,'' ``atmospheric tanks,''
and ``tanks'' in 40 CFR 98.233(j) and 40 CFR 98.236(j) to instead use
the term ``atmospheric pressure storage tanks.'' We are proposing to
define an atmospheric pressure storage tank as ``a vessel (excluding
sumps) operating at atmospheric pressure that is designed to contain an
accumulation of crude oil, condensate, intermediate hydrocarbon
liquids, or produced water and that is constructed entirely of non-
earthen materials (e.g., wood, concrete, steel, plastic) that provide
structural support. Atmospheric pressure storage tanks include both
fixed roof tanks and floating roof tanks. Floating roof tanks include
tanks with either an internal floating roof or an external floating
roof.'' We expect these proposed amendments would improve the overall
quality and completeness of the emissions data collected by the GHGRP,
consistent with section II.A of this preamble.
4. Controlled Atmospheric Storage Tanks
    In correspondence with the EPA via e-GGRT, some reporters have
asked the EPA for guidance regarding calculating emissions from
atmospheric storage tanks that are routed to different control devices
throughout the reporting year (e.g., tanks that are routed to vapor
recovery and subsequently vented to atmosphere or routed to a flare
when the vapor recovery device is not operating). Given the proposed
amendments to the calculation methodology and reporting of flare stack
emissions (discussed in section III.N of this preamble), we are
proposing to revise the methodologies for calculating emissions from
tanks controlled by a vapor recovery system or a flare currently
provided in 40 CFR 98.233(j)(4) and (5), respectively. The new language
in proposed 40 CFR 98.233(j)(4)(i) provides a methodology for
calculating emissions vented to atmosphere during periods of reduced
capture efficiency of the vapor recovery system or flare (e.g., when a
thief hatch is open or not properly seated). The provisions of proposed
40 CFR 98.233(j)(4)(ii) would require facilities to use engineering
estimates based on best available data to calculate recovered mass from
vapor recovery systems, and also clarifies that reporters must take
into account periods with reduced capture efficiency of the vapor
recovery system (e.g., when a thief hatch is open or not properly
seated or when the vapor recovery system is down for maintenance) when
calculating mass recovered. For flared atmospheric storage tank
emissions, the proposed 40 CFR 98.233(j) provisions would direct
reporters to the proposed methodologies in 40 CFR 98.233(n). By
proposing these amendments, the EPA seeks to enhance the overall
quality of the data collected under the GHGRP, consistent with section
II.D of this preamble.
5. Calculation Methods 1 and 2 for Atmospheric Storage Tanks
    Reporters with atmospheric storage tanks that calculate emissions
using Calculation Method 1 are currently required to determine
emissions using any standard simulation software package that uses the
Peng-Robinson equation of state, models flashing emissions, and
speciates CH4 and CO2 emissions from the
atmospheric storage tank. According to current 40 CFR 98.233(j)(1), the
information that must be used to characterize emissions include
separator or non-separator equipment temperature and pressure, sales or
stabilized hydrocarbon liquids API gravity, sales or stabilized

hydrocarbon liquids production rate, ambient air temperature and
pressure, and separator or non-separator equipment hydrocarbon liquids
composition and Reid vapor pressure. These parameters currently must be
determined for typical operating conditions over the calendar year by
engineering estimate and process knowledge based on best available
data. Consistent with section II.B of this preamble, we are proposing
that the input parameters related to the hydrocarbon liquid stream that
are used for the simulation software must be obtained by
measurement.\83\ Those parameters include separator or non-separator
equipment temperature and pressure, sales or stabilized hydrocarbon
liquids API gravity, sales or stabilized hydrocarbon liquids production
rate, and separator or non-separator equipment hydrocarbon liquids
composition and Reid vapor pressure. We are proposing that reporters
would collect measurements reflective of representative operating
conditions over the time period covered by the simulation. We are not
proposing to change the requirement that the other parameters must be
determined for operating conditions based on engineering estimate and
process knowledge.
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    \83\ As described in section III.C.3 of this preamble, the EPA
is also proposing to expand the applicability of 40 CFR 98.233(j)(1)
to include produced water tanks.
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    We are also proposing that the parameters that must be used to
characterize emissions should reflect operating conditions over the
time period covered by the simulation rather than just over the
calendar year. Under this proposed change, reporters could continue to
run the simulation once per year with parameters that are determined to
be representative of operating conditions over the entire year.
Alternatively, reporters would be allowed to conduct periodic
simulation runs to cover portions of the calendar year, as long as the
entire calendar year is covered. The reporter would then sum the
results at the end of the year to determine annual emissions. In that
case, the parameters for each simulation run would be determined for
the operating conditions over each corresponding portion of the
calendar year.
    For reporters with atmospheric storage tanks that calculate
emissions using Calculation Method 2, all CH4 and
CO2 in solution are assumed to be emitted from hydrocarbon
liquids. For flow to storage tanks after passing through a separator,
the CH4 and CO2 in solution is determined by
taking a sample of separator hydrocarbon liquids at separator pressure
and temperature. However, for flow to atmospheric storage tanks direct
from wells and flow to atmospheric storage tanks direct from non-
separator equipment, facilities may only use either the latest
compositional analysis already available at the facility or default
liquid and gas compositions from modeling software programs to
determine the CH4 and CO2 in solution; there is
currently no requirement to take a representative sample during the
calendar year. Consistent with these proposed amendments for
atmospheric tanks with emissions calculated using Calculation Method 1,
the EPA is proposing that the composition of the liquids flowing to all
tanks with emissions calculated using Calculation Method 2 must be
obtained by measurement, regardless of the source from which the
liquids are supplied. We are proposing to remove the provisions of 40
CFR 98.233(j)(2)(ii) and (iii) that allowed for representative
compositions to be used for tanks receiving liquids directly from wells
or non-separator equipment. These amendments are expected to improve
the accuracy of the data collected under the GHGRP, consistent with
section II.B of this preamble.
    Similar to the provision for dehydrators in 40 CFR 98.233(e)(1),
subpart W currently provides two example software options, AspenTech
HYSYS[supreg] or API 4697 E&P Tank, that meet the software requirements
in 40 CFR 98.233(j)(1). Under the existing requirements, reporters are
not limited using to these two software options when complying with 40
CFR 98.233(j)(1). However, many reporters have been using BRE's ProMax
software to model their tank emissions. In RY2021, based on responses
to 40 CFR 98.236(j)(1)(ii) (name of the software package used if using
Calculation Method 1), 59 percent of facilities reporting emissions
from Calculation Method 1 atmospheric storage tanks used ProMax as
their modeling software, compared to 30 percent using API 4697 E&P Tank
and 6 percent using AspenTech HYSYS[supreg]. Given the significant
majority of reporters using ProMax, and considering our proposed
addition and supporting rationale of ProMax to the list of example
software options in 40 CFR 98.233(e)(1), we are proposing to add ProMax
as an example software program for calculating atmospheric tank
emissions per 40 CFR 98.233(j)(1). Consistent with the EPA's proposed
revisions to 40 CFR 98.233(e)(1), the EPA is proposing to require
ProMax version 5.0 or above. We expect these proposed amendments would
improve the quality of the data collected, consistent with section II.C
of this preamble.
    Additionally, we are aware that several process simulation software
options have the ability to model emissions from atmospheric storage
tanks that are receiving hydrocarbon liquids directly from wells. As
such, the EPA is proposing to amend 40 CFR 98.233(j) such that
facilities with wells flowing directly to atmospheric storage tanks
without passing through a separator may use either Calculation Method
1, Calculation Method 2, or, for wells, gas-liquid separators, or non-
separator equipment with annual average daily throughput less than 10
barrels per day, Calculation Method 3. We are also proposing conforming
edits within 40 CFR 98.233(j)(1) and (2) and 40 CFR 98.236(j)(1) to
refer to parameters and requirements for wells flowing directly to
atmospheric storage tanks. These proposed amendments are expected to
improve the accuracy of reported emissions, consistent with section
II.B of this preamble.
    Stakeholders have indicated through correspondence with the EPA via
e-GGRT and the GHGRP Help Desk that flash emissions from atmospheric
storage tanks are often determined through laboratory measurement of
separator liquid gas to oil ratio (GOR). This emission calculation
methodology involves taking a pressurized sample of crude or condensate
from an upstream vessel (separator or non-separator equipment) and
flashing the sample in a laboratory. To do this, part of the sample is
brought to sampling temperature and pressure conditions, while another
portion of the sample is brought to storage tank temperature and
pressure conditions. The amount of gas released per volume of oil
generated is measured to estimate the GOR. The chemical composition of
the flash gas is then analyzed and the CH4 and
CO2 concentrations are determined. The GHG emissions can be
estimated by multiplying the GOR by the crude oil or condensate
throughput, and then applying the CH4 and/or CO2
composition to the total gas rate to estimate the CH4 and/or
CO2 emissions from the atmospheric storage tank. The EPA has
determined that this methodology does not meet the requirements of
Calculation Method 1 (as the emissions are not calculated using a
modeling software) or Calculation Method 2 (as the emissions are not
calculated assuming that all the CH4 and CO2 in
solution at separator temperature and pressure is emitted).

However, upon review of storage tank emissions calculation guidance
from states such as Louisiana \84\ and Texas,\85\ it appears that
companies may be performing this testing to meet state-level
requirements. Additionally, this methodology is included in the 2021
API Compendium as an option for determining atmospheric storage tank
emissions.
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    \84\ Louisiana Department Of Environmental Quality. ``Flash Gas
Calculation Methods.'' https://www.deq.louisiana.gov/page/flash-gas-calculation-methods.
    \85\ Texas Commission on Environmental Quality Air Permits
Division. May 2012. Calculating Volatile Organic Compounds (VOC)
Flash Emissions from Crude Oil and Condensate Tanks at Oil and Gas
Production Sites. Air Permit Reference Guide APDG 5942. Available at
https://www.tceq.texas.gov/assets/public/permitting/air/Guidance/NewSourceReview/guidance_flashemission.pdf and in the docket for
this rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
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    Therefore, we are seeking comment on adding laboratory measurement
of the GOR from a pressurized liquid sample as a new emission
calculation methodology for atmospheric storage tanks under 40 CFR
98.233(j). If this methodology were to be added to 40 CFR 98.233(j), we
anticipate providing an equation that would multiply the measured GOR
by the annual throughput of the hydrocarbon liquid stream to the
atmospheric storage tank (in barrels per year) to obtain the annual
volumetric flash gas emissions. The CO2 and CH4
emissions from the atmospheric storage tank would then be calculated
using CO2 and CH4 flash gas concentrations
determined from the laboratory analysis. Facilities utilizing this
methodology would report all data elements required under 40 CFR
98.236(j)(1), consistent with the reporting for Calculation Methods 1
and 2. We would also require additional data elements associated
specifically with this new calculation method, such as the annual
average GOR and total days of operation of the atmospheric storage
tank(s) at the facility, well-pad, or gathering and boosting site. We
specifically request comment on the accuracy of this methodology for
calculating GHG emissions (with emphasis on comparison with Calculation
Method 1 modeling), as well as how extensive its use may be in the oil
and gas industry.
6. Calculation Methods 1 and 2 Reporting
    For facilities reporting atmospheric storage tank emissions
calculated using Calculation Method 1 or Calculation Method 2, 40 CFR
98.236(j)(1) currently requires reporting of counts of the total number
of atmospheric storage tanks within the sub-basin or county (40 CFR
98.236(j)(1)(x)), the number of atmospheric storage tanks that are
controlled by a vapor recovery system (40 CFR 98.236(j)(1)(xii)(A)),
the number of atmospheric storage tanks that are controlled by a flare
(40 CFR 98.236(j)(1)(xiv)(A)), and the number of atmospheric storage
tanks that are not controlled by either a vapor recovery system or a
flare (40 CFR 98.236(j)(1)(xiii)(A)).\86\ Given the proposed amendments
to require reporting of CO2, CH4, and
N2O emissions from atmospheric storage tanks controlled by a
flare under 40 CFR 98.236(n) (discussed in section III.N of this
preamble), the EPA is proposing to reorganize the reporting
requirements in 40 CFR 98.236(j)(1) to collect each of these tank
counts under 40 CFR 98.236(j)(1)(x)(A) through (F).\87\ The EPA is also
proposing to move the reporting of CO2 and CH4
vented emissions and recovered mass to paragraph 40 CFR
98.236(j)(1)(xi) through (xiv). With this reorganization of the
emissions reporting requirements for atmospheric storage tanks, the EPA
expects to improve verification of atmospheric storage tank emissions,
consistent with section II.C of this preamble.
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    \86\ In the 2022 Proposed Rule, the EPA proposed updates to the
tank count reporting requirements in current 40 CFR 98.236(j)(1).
These revisions are not included in this proposal, as the current
tank count reporting requirements better align with the proposed
flare stack revisions discussed in section III.N of this preamble.
    \87\ 87 As discussed in section III.K.3 of this preamble, the
EPA is expanding this source to include both fixed roof and floating
roof atmospheric storage tanks. The total count of tanks within the
facility is proposed to be further divided into the count of fixed
roof atmospheric storage tanks and the count of floating roof
atmospheric storage tanks. Also, as discussed in section III.K.1 of
this preamble, the EPA is also proposing to collect the count of
controlled atmospheric storage tanks with open or not properly
seated thief hatches.
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    Additionally, the EPA is proposing to remove the requirement to
report an estimate of the number of atmospheric storage tanks that are
not on well-pads and that are receiving the facility's oil (existing 40
CFR 98.236(j)(1)(xi)), consistent with section II.C of this preamble.
This reporting requirement is currently, and under the proposed rule
would still be, redundant because all Onshore Petroleum and Natural Gas
Production facilities reporting atmospheric storage tank emissions
calculated using Calculation Method 1 or Calculation Method 2 must also
report the total number of atmospheric storage tanks in the sub-basin