Revise the affected facility definition to include all centrifugal
compressors (i.e., both wet seal and dry seal configurations), (2)
specify that self-contained wet seal centrifugal compressors meet the
NSPS OOOOb BSER requirements, and (3) set numerical emission limit
requirements for dry seal and self-contained wet seal centrifugal
compressors.
i. Wet Seal Centrifugal Compressors
    The EPA received comments that included specific data on the
November 2021 proposal related to emissions, costs, and the proposed
standards/analyses for wet seal centrifugal compressors.\178\ These
commenters asserted that actual wet seal centrifugal compressor
baseline emissions are significantly lower than the emissions estimates
that the EPA used in the November 2021 proposal's BSER analysis and
recommended that the EPA use updated emissions information reported
under GHGRP subpart W. One of the commenters provided information on
wet seal centrifugal compressor emissions for their sources in the
transmission segment and requested the EPA consider using it in any new
BSER analysis.\179\ This commenter also opined that the proposed 95
percent reduction standard is unclear insofar as there is no indication
of what value the reduction is to be measured against. This commenter
stated that for seals that emit de minimis levels of VOC or methane, it
would be impracticable to further reduce such emissions and that
assuming emissions can be calculated, the proposed BSER of routing
emissions to a control device or to a process would be cost
prohibitive.
---------------------------------------------------------------------------

    \178\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0415 and EPA-HQ-
OAR-2021-0317-1375.
    \179\ See Document ID No. EPA-HQ-OAR-2021-0317-1375.
---------------------------------------------------------------------------

    These same commenters also stated that the costs used by the EPA in
the November 2021 proposal's BSER analyses were not representative of
actual costs, and that the EPA had underestimated the costs for the
control options evaluated. One of the commenters provided detailed cost
information that they stated was more representative of actual costs
for three combustion scenarios, the option to route to a process for
control, and retrofit costs.
    Finally, these same commenters suggested that the EPA consider a de
minimis exemption, such as an exemption for limited use wet seal
centrifugal compressors or the establishment of an emissions
applicability threshold (referring to California's centrifugal
compressor requirements as an example) \180\ where a wet seal
compressor that has a measured flow rate less than a specified
threshold would be exempt from regulatory requirements.
---------------------------------------------------------------------------

    \180\ California's Regulation for Greenhouse Gas Emission
Standards for Crude Oil and Natural Gas Facilities rule (California
Code of Regulations, Title 17, Division 3, Chapter 1, Subchapter 10
Climate Change, Article 4, Subarticle 13, Section 95668(d)(4-9)).
---------------------------------------------------------------------------

    The EPA re-evaluated the November 2021 BSER in light of the
suggestions from commenters related to emissions and costs. We used
GHGRP subpart W emissions information because the GHGRP requires a
multi-step data verification process, which increases the confidence in
the reliability of data and resulting analyses.\181\ The methodology we
used for estimating emissions from compressors is consistent with the
methodology used for the November 2021 proposal. See 86 FR 63220
(November 15, 2021). The wet seal centrifugal compressor GHGRP subpart
W methane uncontrolled emissions/emissions factors are based on
volumetric emissions, which were converted to a mass emission rate for
this analysis. The resulting baseline uncontrolled emissions per wet
seal centrifugal compressor are 251 tpy methane (69.9 tpy VOC) from wet
seal compressors at gathering and boosting sites, 163 tpy methane (45.4
tpy VOC) from wet seal compressors at natural gas processing plants,
and 66 tpy methane (1.8 tpy VOC) from wet seal compressors at
transmission and storage facilities. These baseline uncontrolled
emissions per wet seal centrifugal compressor are higher than what we
used in the November 2021 proposal analysis for the gathering and
boosting segment (based on GHGRP subpart W emissions factor), but lower
for all other segments of the industry.\182\
---------------------------------------------------------------------------

    \181\ EPA (2020) Greenhouse Gas Reporting Program. U.S.
Environmental Protection Agency. Data reported as of August 7, 2021.
    \182\ U.S. Environmental Protection Agency. Supplemental
Background Technical Support Document for the Proposed New Source
Performance Standards (NSPS) and Emissions Guidelines (EG). August
2022.
---------------------------------------------------------------------------

    The same control options from the analysis for the November 2021
proposal (routing to a control device and routing to a process) were
evaluated with the above updates. Additionally, we evaluated a new
option to address dry seal centrifugal compressor emissions, as
discussed in more detail later in this section.
    Routing to a control device. As discussed in the November 2021
proposal, a combustion device generally achieves 95 percent reduction
of methane and VOC when operated according to the manufacturer
instructions. Therefore, for this analysis, we assumed that the
entrained natural gas from the seal oil that is removed in the
degassing process would be directed to a combustion device that
achieves a 95 percent reduction of methane and VOC emissions. The
combustion of the recovered gas creates secondary emissions of
hydrocarbons (NOX, CO2, and CO emissions).
Routing the captured gas from the centrifugal compressor wet seal
degassing system to a combustion device has associated capital and
operating costs. The capital and annual operating costs for the
installation of a combustion device used in the updated analysis
presented with this supplemental proposal are based on information
obtained from commenters regarding a new high-end enclosed
combustor.\183\ These costs were adjusted from 2021 dollars to 2019
dollars for consistency with the other analyses in this rulemaking. The
updated capital costs of $123,559 were annualized at 7 percent based on
an equipment life of 10 years. The total annualized capital costs were
estimated to be $17,592. The annual operating costs used are based, in
part, on costs assumed in the 2011 NSPS OOOO TSD and 2016 NSPS OOOOa
TSD,\184\ with the costs again updated to reflect 2019 dollars. The
resulting annual operating costs (including annual administrative,
taxes, and insurance costs) were estimated to be $105,472. Therefore,
the updated estimated total annual costs (including annualized capital
and operating costs) are $123,063 per compressor. There are no cost
savings estimated for this option because the recovered natural gas is
combusted.
---------------------------------------------------------------------------

    \183\ See Document ID No. EPA-HQ-OAR-2021-0317-1375.
    \184\ See Document ID Nos. EPA-HQ-OAR-2010-0505-0045 and EPA-HQ-
OAR-2010-0505-7631.
---------------------------------------------------------------------------

    As a result of the analysis and cost-effectiveness shown in Table
32 below, the EPA has determined that the costs of routing the captured
gas from the centrifugal compressor wet seal degassing system to a
control device are reasonable for the control of methane for the
gathering and boosting, processing and transmission, and storage
segments using both the single and multipollutant approaches. The EPA
also determined that the costs of routing the captured gas from the
centrifugal compressor wet seal degassing system to a control device
are reasonable for the control of VOC for the gathering and boosting
and processing segments using both the single and multipollutant
approaches.

    Routing to a process. As discussed above, another option for
reducing methane and VOC emissions from the compressor wet seal fluid
degassing system is to route the captured emissions back to the
compressor suction or fuel system or put them to another beneficial use
(referred to collectively as ``routing to a process''). One opportunity
to meet this requirement would be to route emissions via a CVS or to
any enclosed portion of a process unit (e.g., compressor or fuel gas
system) where the emissions are predominantly recycled, consumed in the
same manner as a material that fulfills the same function in the
process, transformed by chemical reaction into materials that are not
regulated materials, incorporated into a product, or recovered. For
purposes of this analysis, we assumed that routing methane and VOC
emissions from a wet seal fluid degassing system to a process reduces
methane and VOC emissions in amounts greater than or equal to the
emissions that would be reduced by a combustion device (i.e., greater
than or equal to 95 percent) because emissions are conveyed via a CVS
to an enclosed portion of a process that is operational where the
emissions are predominantly recycled and/or consumed in the same manner
as a material that fulfills the same function in the process. There are
no secondary impacts with the option to control emissions from
centrifugal wet seals by capturing gas and routing to a process. This
alternative is an existing compliance option under NSPS OOOO and NSPS
OOOOa. The EPA has historically assumed that the emissions reduced by
routing to a process are 95 percent or greater. Our understanding is
that routing gas from centrifugal compressor wet seal fluid degassing
systems to a process generally requires the use of a VRU or other
treatment to obtain a gas stream composition suitable to be returned to
the sales line or for use for another purpose. Unlike pneumatic
controllers and pneumatic pumps, (see section IV.D.1.b.iii of this
preamble for controllers and section IV.E.1.b.iii of this preamble for
pumps), the need to use a VRU or other treatment to obtain a gas stream
with a composition suitable to be returned to the sales line could
result in the use of treatment components that may vent to the
atmosphere or the need for maintenance where, for example, the VRU may
need to be bypassed for short periods (resulting in venting of some
emissions to the atmosphere). The EPA solicits comment on its
assumption that the emissions reduced by requiring the capture of gas
and routing to a process is 95 percent or greater. The EPA also is
soliciting comment on the prevalence of owners and operators complying
with NSPS OOOO and NSPS OOOOa or other rules by routing emissions from
the wet seal fluid degassing system to a process and the need for a VRU
in order to be able to route emissions from the wet seal fluid
degassing system to a process.
    The capital and annual costs for routing the seal oil degassing
system to a process used in the updated analysis are based on
information obtained from commenters.\185\ The updated capital costs
are estimated to be $600,636, and the annual costs were estimated to be
$85,517 (without savings), assuming a 10-year equipment life at 7
percent interest. Because the natural gas is not lost or combusted, the
value of the natural gas represents a savings to owners and operators
in the production (gathering and boosting) and processing segments.
Savings were estimated using a natural gas price of $3.13 per thousand
cubic feet (Mcf), which resulted in annual savings of $43,329 per year
at gathering and boosting stations and $28,164 per year at processing
plants.
---------------------------------------------------------------------------

    \185\ See Document ID No. EPA-HQ-OAR-2021-0317-1375.
---------------------------------------------------------------------------

    The updated analysis and cost effectiveness shown in Table 32
indicates that routing emissions to a process is cost effective for the
control of methane emissions for all of the evaluated segments using
the single pollutant approach and is also cost effective for methane
using the multipollutant approach for the gathering and boosting and
processing segments. Similarly, the updated analysis indicates that
routing emissions to a process for the control of VOC for the gathering
and boosting and processing segments is cost effective using both the
single and multipollutant approaches. However, as noted in the November
2021 proposal, although capturing leaking gas and routing to a process
has the advantage of both reducing emissions by at least 95 percent and
capturing the natural gas (which results in natural gas savings), the
EPA has received feedback that this option may not be viable in
situations where downstream equipment capable of handling a low-
pressure fuel source is unavailable.
    Maintenance and repair activities to meet numerical emission limit.
The EPA evaluated a third BSER option for this supplemental proposal
not considered for the November 2021 proposal: maintenance and repair
activities conducted to maintain emissions at or below 3 scfm, with
annual flow rate monitoring on the wet seal degassing vent (also
referred to as the numerical emission limit). We did so based on
comments indicating that a threshold monitoring option is a more
practical option for low-emitting centrifugal compressors with wet
seals (as compared to the proposed requirement to route to a control
device or to a process). This option would require owners and operators
to perform periodic flow rate monitoring, as well as preventative
maintenance and repair as necessary, on the wet seal degassing vent to
ensure compliance with the 3 scfm emission limit. The 3 scfm volumetric
flow rate emission limit is the same monitoring limit included in
California's Regulation for Greenhouse Gas Emission Standards for Crude
Oil and Natural Gas Facilities.\186\ California developed the 3 scfm
emission standard because this was the equivalent to an average dry
seal emission rate.\187\ The commenters specifically noted that low
emissions from centrifugal compressors equipped with wet seals are
largely a function of proper maintenance and that requiring a 95
percent reduction standard or routing to a process creates an
unintended result--the more careful an operator is with maintaining its
wet seals, the more difficult and costly (on a cost-per-ton basis)
controlling emissions in compliance with these requirements
becomes.\188\
---------------------------------------------------------------------------

    \186\ California Code of Regulations, Title 17, Division 3,
Chapter 1, Subchapter 10 Climate Change, Article 4, Subarticle 13,
Section 95668(d)(4-9).
    \187\ State of California. Air Resources Board Public Hearing to
Consider the Proposed Regulation for Greenhouse Gas Emission
Standards for Crude Oil and Natural Gas Facilities. Staff Report:
Initial Statement of Reasons. pg. 100.
    \188\ See Document ID No. EPA-HQ-OAR-2021-0317-1375.
---------------------------------------------------------------------------

    The types of maintenance and repair actions that may be needed to
maintain emissions at or below 3 scfm will vary considerably. One
commenter,\189\ a company that institutes an annual monitoring plan,
indicated that the actions needed to reduce emissions or maintain a
compressor such that it is low-emitting can range from correcting an
identified issue immediately with minor maintenance, replacing o-rings
on the filtration system, or having to rebuild the entire oil system.
The costs associated with these maintenance and corrective actions vary
significantly, from limited labor costs for a short repair activity to
a significant capital cost of equipment and labor to repair and/or
replace parts of the compressor. The EPA does not have specific costs
for the range of maintenance and/or repairs

that may be necessary to maintain a flow rate at or below than 3 scfm.
For the purposes of this analysis, the EPA selected an annual cost of
$25,000 to represent the average cost of performing the monitoring and
the necessary compressor wet seal maintenance. While we recognize
certain types of maintenance or corrective actions may result in costs
higher than $25,000 in one year, we believe that this is a conservative
estimate to represent an average, annual cost. The EPA specifically
solicits comments on the types of maintenance or corrective actions
that may be required to maintain an emission rate of 3 scfm or less
from wet seal degassing, along with representative costs.
---------------------------------------------------------------------------

    \189\ See Document ID No. EPA-HQ-OAR-2021-0317-1375.
---------------------------------------------------------------------------

    To estimate the cost effectiveness of this option, the EPA used the
same updated GHGRP subpart W ``uncontrolled'' emissions discussed above
for each centrifugal compressor with wet seals to represent baseline
emissions. The ``after control'' emissions levels were calculated based
on 3 scfm volumetric flow for 8,760 hours per year and the
representative composition of the gas in the different segments. This
calculation assumes that the emissions are, on average, 3 scfm for the
entire year. This represents a conservative estimate, as one commenter
\190\ indicated that the implementation of a similar program resulted
in average measured emissions of less than 0.5 scfm for compressors
with wet seals. Table 31 shows the baseline emissions, the emissions
after implementation of the numerical emission limit, and the emission
reductions for wet seal compressors.
---------------------------------------------------------------------------

    \190\ See Document ID No. EPA-HQ-OAR-2021-0317-1375.

    Table 31--Methane Baseline Emissions and Reductions After Implementation of the Numerical Emission Limit
               (Requirement To Maintain Flow Rate at or Below 3 scfm) Option--Wet Seal Compressors
----------------------------------------------------------------------------------------------------------------
                                                                     Methane emissions  (tpy)/
                                                                            compressor                Methane
                             Segment                             --------------------------------    emission
                                                                                After         reduction
                                                                   Baseline \a\   implementation       (tpy)
----------------------------------------------------------------------------------------------------------------
Gathering and Boosting..........................................             251              27             224
Processing......................................................             163              27             136
Transmission and Storage........................................              66              30              35
----------------------------------------------------------------------------------------------------------------
\a\ From GHGRP subpart W (Reporting Years 2015 to 2020--Average).
\b\ Calculated assuming total gas emissions are 3 scfm for 8,760 hours.

    As noted above, we assumed annual maintenance, monitoring, and
corrective action costs of $25,000 (without savings). Because the
natural gas is not lost or combusted, the value of that natural gas
represents a savings to owners and operators in the production
(gathering and boosting) and processing segments. Savings were
estimated using the emission reductions noted above and a natural gas
price of $3.13 per Mcf, which resulted in annual savings of $33,719 per
year at gathering and boosting stations and $20,486 per year at
processing plants.
    As a result of the wet seal centrifugal compressor analysis and
cost effectiveness shown in Table 32, the EPA has determined that the
costs of implementing a numerical emission limit are reasonable for the
control of methane for the gathering and boosting, processing, and
transmission and storage segments using both the single and
multipollutant approaches. The EPA has also determined that the costs
of implementation of a numerical emission limit is reasonable for the
control of VOC for the gathering and boosting and processing segments,
using both the single and multipollutant approaches.
    The estimated cost effectiveness values that would be associated
with: (1) Capturing and routing emissions to a combustion device, (2)
capturing and routing emissions to a process, and (3) conducting
maintenance and repair activities to meet a numerical emission limit (3
scfm) (referred to as the ``numerical limit of 3 scfm'') for
compressors with wet seals are provided in Table 32. In addition to the
cost effectiveness values, Table 32 provides a conclusion regarding
whether the estimated cost effectiveness value is within the range that
the EPA has typically considered to be reasonable. The ``overall''
reasonableness determination is classified as ``Y'' if the cost
effectiveness of either methane or VOC is within the range that the EPA
considers reasonable for that pollutant, or ``N'' if both the methane
and VOC cost effectiveness values are beyond the range that the EPA
considers reasonable on a multipollutant basis.

    Table 32--Summary of Wet Seal Centrifugal Compressor Cost Effectiveness by Regulatory Option and Industry
                                                     Segment
----------------------------------------------------------------------------------------------------------------
                                           Cost effectiveness ($/ton) \a\--reasonable?
                                ----------------------------------------------------------------
   Segment/regulatory option            Single pollutant                 Multipollutant            Overall \a\
                                ----------------------------------------------------------------
                                     Methane           VOC           Methane           VOC
----------------------------------------------------------------------------------------------------------------
Gathering and Boosting:
    Regulatory Option One--              $515-Y        $1,853-Y          $258-Y          $927-Y               Y
     Route Emissions to
     Combustion Device.........
    Regulatory Option Two--               879-Y         3,163-Y           440-Y         1,582-Y               Y
     Route Emissions to the
     Process...................
    Regulatory Option Three--             111-Y           401-Y            56-Y           201-Y               Y
     Numerical Limit of 3 scfm.
Processing:

    Regulatory Option One--               793-Y         2,851-Y           396-Y         1,425-Y               Y
     Route Emissions to
     Combustion Device.........
    Regulatory Option Two--             1,353-Y         4,866-Y           676-Y         2,433-Y               Y
     Route Emissions to the
     Process...................
    Regulatory Option Three--             183-Y           660-Y            92-Y           330-Y               Y
     Numerical Limit of 3 scfm.
Transmission and Storage:
    Regulatory Option One--             1,973-Y        71,240-N           987-Y        35,620-N               Y
     Route Emissions to
     Combustion Device.........
    Regulatory Option Two--             3,369-N       121,607-N         1,684-Y        60,804-N               Y
     Route Emissions to the
     Process...................
    Regulatory Option Three--             711-Y        25,650-N           355-Y        12,825-N               Y
     Numerical Limit of 3 scfm.
----------------------------------------------------------------------------------------------------------------
\a\ For the gathering and boosting and processing segments, the owners and operators realize the savings for the
  natural gas that is not emitted and lost. The cost effectiveness values shown do not consider these savings.
  Note that the consideration of savings does not impact whether the cost effectiveness of any of these options
  falls within the ranges considered reasonable by the EPA.
\b\ For overall cost effectiveness to be considered reasonable, either the cost effectiveness of methane or VOC
  on a single pollutant basis must be within the ranges considered reasonable by the EPA, or the cost
  effectiveness of both methane and VOC on a multipollutant basis must be within the ranges considered
  reasonable by the EPA.

    Summary of Control Options Evaluated. In summary, the EPA evaluated
three options for wet-seal centrifugal compressors: (1) Route emissions
to a control device, (2) route emissions to a process, and (3) conduct
maintenance and repair to maintain emissions at or below 3 scfm. The
EPA's relevant analyses found that, for all segments, the costs in
relation to the emission reductions were reasonable for all three
options. However, the options to route captured gas to a control device
or to a process achieve greater emission reductions than conducting
maintenance and repair to maintain 3 scfm. For example, for the
gathering and boosting segment, we estimated that the emissions reduced
under the 3 scfm numerical limit option for a representative
centrifugal compressor to be 89 percent, which is less than the routing
to a control or process options, which achieve 95 percent.\191\
Therefore, the EPA finds that the standard of performance for each
centrifugal compressor using a wet seal is 95 percent reduction of
methane and VOC emissions based on a BSER of capturing and routing
emissions from the wet seal degassing system to a combustion device for
new sources in the gathering and boosting, processing, and transmission
and storage segments. These reductions can also be achieved by routing
emissions from the wet seal degassing system to a process. Therefore,
as a compliance alternative, the EPA proposes to allow owners and
operators to meet the 95 percent standard of performance by routing
emissions from the wet seal degassing system to a process. The EPA
notes that if an owner or operator chooses to route to a process to
meet the 95 percent level of control, there are no secondary impacts.
If an owner or operator chooses to route to a combustion device to meet
the 95 percent level of control, the combustion of the recovered gas
creates secondary emissions of hydrocarbons (NOX,
CO2, and CO emissions).
---------------------------------------------------------------------------

    \191\ U.S. Environmental Protection Agency. Supplemental
Background Technical Support Document for the Proposed New Source
Performance Standards (NSPS) and Emissions Guidelines (EG).
Supporting Spreadsheets. August 2022.
---------------------------------------------------------------------------

    As discussed in section III.D of this preamble, NSPS KKK includes
standards for controlling VOC emissions from centrifugal compressors
with wet seals at natural gas processing plants. The standards provide
several options for compliance, including: (1) Operating the
centrifugal compressor with the barrier fluid at a pressure greater
than the compressor stuffing box pressure; (2) equipping the
centrifugal compressor with a barrier fluid system degassing reservoir
that is routed to a process or fuel gas system or connected by a CVS to
a control device that reduces VOC emissions by 95 percent or more; or
(3) equipping the centrifugal compressor with a system that purges the
barrier fluid into a process stream with zero VOC emissions to the
atmosphere. NSPS KKK exempts compressors from these requirements if the
compressor is either equipped with a CVS to capture and transport
leakage from the compressor drive shaft back to a process or fuel gas
system or to a control device that reduces VOC emissions by 95 percent,
or if the compressor is designated for no detectable emissions.
    For NSPS OOOOb, we are proposing that emissions from each
centrifugal compressor wet seal fluid degassing system require routing
to a control device that achieves a 95 percent reduction of VOC and
methane emissions, or by routing the emissions to a process that
achieves 95 percent reduction of VOC and methane emissions. Proposed
NSPS OOOOb is equivalent to one of the three options available under
NSPS KKK.
    Owners and operators of wet seal centrifugal compressors have been
complying with NSPS KKK since 1984. The EPA is requesting comments on
whether it would provide more regulatory consistency for owners,
operators, and implementing agencies if NSPS OOOOb were to incorporate
all compliance options provided in NSPS KKK for wet seal centrifugal
compressors at natural gas processing plants, as opposed to only
proposing the compliance option of routing to a control or process
proposed in this supplemental proposal.
ii. Lower-Emitting/Self-Contained Wet Seal Compressor Designs
    The November 2021 proposal solicited comment and information on
lower-emitting wet seal compressor designs. Commenters \192\ reported
that the process for wet seal degassing varies throughout the industry,
and some manufacturers have a configuration that is essentially a
closed process that ports the degassing emissions into the natural

gas line at the compressor suction. According to one industry commenter
that employs this type of wet seal centrifugal compressor, this
configuration typically includes a primary chamber where initial
degassing occurs (and is recovered), and chamber(s) with air sparging
to release and recover residual gas volumes entrained in the oil.
Rather than venting all of the de-gassing volumes, the emissions are
routed back to suction directly from the degassing/sparging chambers;
the oil is ultimately recycled to the lube oil tank where any small
amount of residual gas is released through a vent. One commenter stated
that field evaluation is not always feasible for this closed system
configuration but reported that testing and modeling demonstrates that
the residual natural gas volume vented is very small (much less than 1
percent of the total degassed natural gas volume). Another commenter
requested that the EPA clarify that certain existing closed-loop wet
seal systems be exempted from any regulatory proposal, or at a minimum,
that such systems should be considered in compliance with the BSER
currently applicable to wet seals.\193\
---------------------------------------------------------------------------

    \192\ See Document ID No. EPA-HQ-OAR-2021-0317-0415.
    \193\ See Document ID No. EPA-HQ-OAR-2021-0317-1375.
---------------------------------------------------------------------------

    Based on information indicating that closed-loop (self-contained)
systems are inherently low-emitting, the EPA is proposing that these
and similarly designed, self-contained wet seal centrifugal compressors
represent/meet BSER (consistent with the routing to a process or
control option). The EPA is proposing a definition for a ``self-
contained wet seal compressor'' as a ``wet seal compressor system that
is a closed process that ports the degassing emissions into the natural
gas line at the compressor suction (i.e., degassed emissions are
recovered).'' The de-gas emissions are routed back to suction directly
from the degassing/sparging chambers, and the oil is ultimately
recycled to the lube oil tank where any small amount of residual gas is
released through a vent. While the EPA recognizes the low emissions
associated with these self-contained wet seal centrifugal compressors,
we also recognize that there could be increased emissions due to leaks
or malfunctions. Therefore, the proposed rule includes the requirement
that owners or operators of self-contained wet seal centrifugal
compressors must comply with the 3 scfm numerical emission standard
described below for centrifugal compressors with dry seals. As
indicated above, the intent of requiring compliance with the 3 scfm
numerical standard is to ensure that self-contained wet seal
compressors are operating properly (without leaks or malfunctions)
since EPA understands that these compressors emit trivial amounts
(i.e., achieve greater than 99 percent control) when properly operated.
The EPA recognizes that where there is venting of any emissions from
these compressors, emissions would more than likely be nondetectable
for leaks, or would be at a rate lower than 3 scfm. The EPA solicits
comment on, and support for, whether a lower numerical limit is needed
to demonstrate proper operation of self-contained wet seal centrifugal
compressors and/or equivalency to the BSER. The EPA also solicits
comment on the feasibility of measuring the flow rate of self-contained
wet seal centrifugal compressors at a rate lower than 3 scfm.
    In addition to wet seal compressor systems that are self-contained,
one commenter \194\ reported information on another wet seal compressor
that was inherently low-emitting. The commenter stated that it has
facilities that use mechanical wet seals that generally have zero
emissions. They explained that the metal (tungsten carbide) is seated
against carbide, with oil pressing against the outside of the actual
seal. They noted that because the oil is not in contact with the
natural gas for these mechanical seals, these wet seals generally have
zero degassing emissions. The commenter requested that the EPA exclude
compressors utilizing mechanical wet seals from the wet seal compressor
requirements otherwise applicable to wet seal compressors. The EPA is
continuing to evaluate mechanical wet seal designs and the comments it
has already received on the issue, and is soliciting additional
information on these and other wet seal compressor designs (with
supporting emissions information) that are inherently low-emitting
under operating conditions.
---------------------------------------------------------------------------

    \194\ See Document ID No. EPA-HQ-OAR-2021-0317-0415.
---------------------------------------------------------------------------

iii. Dry Seal Compressors
    The EPA solicited comments on dry seal compressor emissions and
whether, and to what degree, operational or malfunctioning conditions
(e.g., low seal gas pressure, contamination of the seal gas, lack of
supply of separation gas, mechanical failure) have the potential to
impact methane and VOC emissions. The EPA further requested information
on whether owners and operators implement standard operating procedures
to identify and correct operational or malfunctioning conditions that
have the potential to increase emissions from dry seal systems, and
whether EPA should consider evaluating BSER and developing NSPS
standards for dry seal compressors.
    As the EPA has heard previously, the commenters noted that some dry
seal compressors have higher emissions than compressors with wet seals.
Based on input from a couple of commenters, we estimated the cost
effectiveness of conducting preventative maintenance and repair, as
needed, to maintain the volumetric flow rate from each centrifugal
compressor that uses a dry seal at or below 3 scfm (as done for those
with wet seals). The 3 scfm volumetric flow rate emission limit is the
same monitoring limit included in California's Regulation for
Greenhouse Gas Emission Standards for Crude Oil and Natural Gas
Facilities for wet seal compressors.\195\ California developed the 3
scfm emission standard because this was the equivalent to an average
dry seal emission rate.\196\ The EPA did not evaluate any other control
options for compressors with dry seals because they are inherently low-
emitting; increased emissions are generally the result of either
unforeseen upset conditions or poor maintenance.
---------------------------------------------------------------------------

    \195\ California Code of Regulations, Title 17, Division 3,
Chapter 1, Subchapter 10 Climate Change, Article 4, Subarticle 13,
Section 95668(d)(4-9).
    \196\ State of California. Air Resources Board Public Hearing to
Consider the Proposed Regulation for Greenhouse Gas Emission
Standards for Crude Oil and Natural Gas Facilities. Staff Report:
Initial Statement of Reasons. pg. 100.
---------------------------------------------------------------------------

    To estimate the cost effectiveness of this option, we used the 2019
GHGI ``uncontrolled'' emissions for dry seal compressors as the
baseline.\197\ The ``after control'' emissions levels were calculated
based on a threshold of 3 scfm volumetric flow for 8,760 hours per year
and the representative composition of the gas in the different
segments. This calculation assumes that the emissions are, on average,
3 scfm for the entire year. Table 33 shows the baseline emissions, the
emissions after implementation of the numerical emission limit, and the
emission reductions for dry seal compressors. The 3 scfm volumetric
flow emission limit is the same as described above for wet seal
centrifugal compressors.
---------------------------------------------------------------------------

    \197\ GHGI-Dry Seals.

      Table 33--Methane Baseline Emissions and Reductions After Implementation of the Annual Emission Limit
               (Requirement to Maintain Flow Rate at or Below 3 scfm) Option--Dry Seal Compressors
----------------------------------------------------------------------------------------------------------------
                                                                      Methane emissions (tpy)         Methane
                                                                 --------------------------------    emission
                             Segment                                                   After         reduction
                                                                   Baseline \a\   implementation       (tpy)
----------------------------------------------------------------------------------------------------------------
Gathering and Boosting..........................................              36               6              30
Processing......................................................              28               1              27
Transmission and Storage........................................              44               6              38
----------------------------------------------------------------------------------------------------------------
\a\ Based on GHGI. Emissions from dry-seal compressors are not estimated for gathering and boosting in the GHGI.
  The baseline emissions were calculated from the transmission and storage emissions (adjusted for the
  difference in gas composition).

    As discussed above for wet seal centrifugal compressors, there is a
wide range in the types of repairs needed (and associated costs) for
dry seal compressors. Given the lack of specific information on these
repairs and costs, we assumed the annual costs to comply with this
option to be $15,000 (without savings). This assumption is lower than
the comparable assumption for wet seals because annual operating and
maintenance costs for compressors with dry seals are lower than for
compressors with wet seals. The EPA specifically solicits comments on
the types of maintenance and corrective actions that may be required to
maintain an emissions rate of 3 scfm or less from centrifugal
compressors with dry seals, along with representative costs.
    Because natural gas emissions from a centrifugal compressor with
dry seals would be reduced by maintaining the emission rate at or below
3 scfm, the value of the retained natural gas that would have otherwise
been emitted represents a savings to owners and operators in the
production (gathering and boosting) and processing segments. Savings
were estimated using the emission reductions noted above and a natural
gas price of $3.13 per Mcf, which resulted in annual savings of $2,425
per year at gathering and boosting stations and $1,170 per year at
processing plants.
    The estimated cost effectiveness values that would be associated
with conducting maintenance and repair activities to meet a numerical
emission limit of 3 scfm for dry seal compressors are provided in Table
34. In addition to the cost effectiveness values, Table 34 provides a
conclusion regarding whether the estimated cost effectiveness value is
within the range that the EPA has typically considered to be
reasonable. The ``overall'' reasonableness determination is classified
as ``Y'' if the cost effectiveness of either methane or VOC is within
the range that the EPA considers reasonable for that pollutant, or
``N'' if both the methane and VOC cost effectiveness values are beyond
the range the EPA considers reasonable on a multipollutant basis.

                 Table 34--Summary of Dry Seal Centrifugal Compressor Cost Effectiveness by Industry Segment--Numerical Limit of 3 scfm
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                             Cost effectiveness ($/ton) \a\--reasonable?
                                                            ----------------------------------------------------------------------------
                          Segment                                      Single pollutant                       Multipollutant               Overall \b\
                                                            ----------------------------------------------------------------------------
                                                                  Methane              VOC              Methane              VOC
--------------------------------------------------------------------------------------------------------------------------------------------------------
Gathering and Boosting.....................................              930-Y            3,346-Y             $465-Y           $1,673-Y               Y
Processing.................................................            1,927-Y            6,933-N              964-Y            3,467-Y               Y
Transmission and Storage...................................              831-Y           29,997-N              415-Y           14,999-N               Y
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ For the gathering and boosting and processing segments, the owners and operators realize the savings for the natural gas that is not emitted and
  lost. The cost effectiveness values shown do not consider these savings. Note that the consideration of savings does not impact whether the cost
  effectiveness of any of these options falls within the ranges considered reasonable by the EPA.
\b\ For overall cost effectiveness to be considered reasonable, either the cost effectiveness of methane or VOC on a single pollutant basis must be
  within the ranges considered reasonable by the EPA, or the cost effectiveness of both methane and VOC on a multipollutant basis must be within the
  ranges considered reasonable by the EPA.

    Based on the consideration of the costs in relation to the emission
reductions for methane shown in Table 34, the costs to implement the
option to conduct preventative repair and maintenance so that each
centrifugal compressor with a dry seal maintains a volumetric flow rate
at or below 3 scfm is reasonable for all segments under both the single
pollutant and multipollutant approaches. Based on the consideration of
the costs in relation to the emission reductions for VOC, the costs of
this option are reasonable for the gathering and boosting segment under
both the single pollutant and multipollutant approaches. For the
processing segment, the costs for reducing VOC emissions are reasonable
under the multipollutant approach, but not the single pollutant
approach. Costs for reducing VOC emissions would not be reasonable for
implementing this approach for the transmission and storage segment.
Given that the costs of conducting preventative repair and maintenance
activities in order to maintain the volumetric flow rate from each
centrifugal compressor with a dry seal at or below 3 scfm are
reasonable, the EPA is proposing this option as BSER for compressors
with dry seals.
c. Summary of 2022 Proposal
i. Affected Facility
    Based on changes made and discussed in section IV.G.1.b of this
preamble, the EPA is proposing to redefine the affected facility to
include dry seal centrifugal compressors in addition to wet seal
centrifugal compressors. Therefore, a centrifugal compressor affected
facility would be defined as a single centrifugal compressor. Further,
the EPA is maintaining the proposed

specifications from the November 2021 proposal as applicable to
centrifugal compressors located at well sites and centralized
production facilities. Specifically, centrifugal compressors located at
centralized production facilities would be considered affected
facilities, while those located at well sites would not be affected
facilities under NSPS OOOOb.
ii. Requirements
    Wet Seal Centrifugal Compressors. The EPA is proposing that owners
or operators of centrifugal compressor affected facilities with wet
seals must comply with the GHG and VOC standards by reducing methane
and VOC emissions from each centrifugal compressor wet seal fluid
degassing system by 95 percent. As an alternative to routing the CVS to
a control device, an owner or operator may also route the CVS to a
process or utilize a self-contained wet seal centrifugal compressor. If
an owner or operator chooses to comply with this requirement either by
using a control device to reduce emissions or by routing to a process
to reduce emissions, an owner or operator must equip the wet seal fluid
degassing system with a cover and the cover must be connected through a
CVS meeting specified requirements (40 CFR 60.5411b(a) through (c)),
such as design and operation with no identifiable emissions, as
described in section IV.K of this preamble. If an owner or operator
uses a self-contained wet seal centrifugal compressor, an owner or
operator must ensure a volumetric flow rate at or below 3 scfm. In
addition to the flow rate monitoring required every 8,760 hours,
additional preventative or corrective measures may be required to
ensure compliance.
    Dry Seal Centrifugal Compressors. The EPA is proposing that the
standard of performance for centrifugal compressor dry seals is 3 scfm.
The proposed BSER is for an owner or operator to conduct preventative
maintenance and repair of their centrifugal compressors that use dry
seals, as needed, to maintain the volumetric flow rate from each
centrifugal compressor that uses a dry seal at or below 3 scfm. Owners
and operators of centrifugal compressors with dry seals must conduct
volumetric emissions measurements from each centrifugal compressor dry
seal vent on or before 8,760 hours of operation or previous measurement
and must use specified methods (similar to the flow rate monitoring
requirements specified under the GHGRP subpart W) in doing so. Owners
or operators must ensure that the volumetric emission measurements (in
operating mode or in stand-by-pressurized-mode) from each centrifugal
compressor dry seal vent are less than or equal to a flow rate 3 scfm
(in operating or standby pressurized mode) or a manifolded dry seal
compressor flow rate less than or equal to the number of compressors
multiplied by 3 scfm (in operating or standby pressurized mode). As
discussed in section IV.I the EPA is proposing the use of volumetric
flow rate which meet the requirements of Method 2D (40 CFR part 60,
appendix A) for testing emissions from reciprocating compressor rod
packing and the use of a high-volume sampler to measure the emissions
from either the reciprocating compressor rod packing or centrifugal
compressor seal vent (dry seals for NSPS OOOOb and all centrifugal
compressor wet and dry seals for EG OOOOc). For the high-volume
sampler, instead of relying on manufacturer defined procedures required
in GHGRP Subpart W, the EPA is proposing a defined set of procedures
and performance objectives to ensure consistent application of these
samplers. In an effort to allow for additional innovation for these
types of measurements, the EPA is also proposing to allow other
methods, subject to Administrator approval, that have been validated
according to Method 301 (40 CFR part 63, appendix A). Preventative
maintenance or other corrective actions may be necessary (in addition
to the monitoring every 8,760 hours of operation) in order for owners
or operators to ensure compliance at all times (consistent with the
general duty clause 40 CFR 60.5470b(b)) with the required flow rate of
3 scfm or less.
    Recordkeeping and Reporting Requirements. Specific recordkeeping
and reporting requirements would also apply for each wet seal
centrifugal compressor affected facility. Specifically, records and
annual reporting that identifies each centrifugal compressor using a
wet seal system that was constructed, modified, or reconstructed during
the reporting period would be required. In instances where a deviation
from the standard occurred during the reporting period and recorded, an
owner or operator would be required to provide information on the date
and time the deviation began, the duration of the deviation, and a
description of the deviation.
    For centrifugal compressors where compliance is achieved by using a
control device to reduce emissions, the following information would be
required in the annual report: dates of the cover and CVS inspections,
whether defects or leaks are identified, and the date of repair or the
date of anticipated repair if repair is delayed. Where bypass
requirements apply, reporting of the date and time of each bypass alarm
or each instance the key is checked out would be required.
    If complying with the centrifugal compressor requirements for wet
seal fluid degassing system by reducing VOC and methane emissions by 95
percent using a control device tested by the device manufacturer, the
annual report must include: the identification of the compressor with
the control device and the make, model, and date of purchase of the
control device. An owner or operator would also be required to record
and report the following: (1) Each instance where there is an inlet gas
flow rate exceedance, (2) each instance where there is no indication of
a pilot flame, and (3) each instance where there was a visible
emissions exceedance. The annual report would be required to include
the date and time the deviation began, the duration of the deviation,
and a description of the deviation. Finally, for each visible emissions
test following return to operation from a maintenance or repair
activity, the annual report would be required to include the date of
the visible emissions test, the length of the test, and the amount of
time visible emissions were present.
    If complying with the centrifugal compressor requirements for a wet
seal fluid degassing system by reducing VOC and methane emissions by 95
percent by using a control device not tested by the device
manufacturer, the following information must be included in the annual
report: identification of the control device not tested by the device
manufacturer, the identification of the compressor with the tested
control device, the date the performance test was conducted, the
pollutant(s) tested, and the performance test report conducted to
demonstrate that the control device is achieving, at a minimum, the
required 95 percent reduction.
    For each dry seal centrifugal compressor affected facility and
self-contained wet seal centrifugal compressor affected facility,
owners and operators would be required to track and report the
cumulative number of hours of operation since startup since the
previous screening/volumetric emissions measurement in order to
demonstrate compliance with their volumetric emissions measurements.
Additionally, a description of the method used and the results of the
volumetric emissions measurement or

emissions screening, as applicable, would be required in the annual
report.
2. EG OOOOc
a. Summary of 2021 Proposal
    The summary of the November 2021 proposal for EG OOOOc is
consistent with what was proposed for NSPS OOOOb (see section IV.G.1.a
of this preamble).
b. Changes to Proposal and Rationale
    The EPA is proposing changes and specific clarifications to the
November 2021 proposal presumptive standards for the EG OOOOc.
Specifically, we are proposing to: (1) Revise the designated facility
definition to include all centrifugal compressors, (2) include a
numerical emission limit requirements for dry and wet seal compressors,
and (3) allow owners and operators the option to comply with EG OOOOc
by reducing methane emissions by 95 percent by either routing to a
control device or to a process. The basis for these changes is
presented below.
    Wet Seal Centrifugal Compressors. Industry commenters expressed
particular concern about having to retrofit existing wet seal
centrifugal compressors to accommodate the November 2021 proposal that
would have required owners and operators to reduce methane emissions
from each centrifugal compressor wet seal fluid degassing system by 95
percent or greater. One commenter \198\ stated that the November 2021
proposal for wet seal centrifugal compressors would require
installation of an enclosed combustion device or a process flare in
nearly every case for their facilities. The commenter noted that, while
theoretically an enclosed combustion device could be installed to
control the minimal emissions on an individual wet seal compressor, a
combustion device cannot be located just anywhere, especially not in
close proximity to a transmission compressor station. The commenter
noted that a combustion device must be strategically located away from
combustible materials, which typically requires a significant
footprint, aboveground piping (above roadways), and in an elevated
location. In order to install such a device, they stated that they
would likely have to apply for and receive state and local permit
modifications, which are not certain to be approved in each case. The
commenter also stated that routing to a control device could present
safety concerns. For example, they note that attempts to capture a low-
pressure natural gas vent stream, such as that of the wet seal, could
result in inducing air into the gas stream, potentially creating a
combustible mixture. The commenter reports that one manufacturer has
previously ``caution[ed] the use of flaring with gas seal vented
emissions due to risk of the potential explosive hazard and back-
flashing.'' \199\ The commenter reports that it is ``[their] view
(concurrent with many users of our equipment) [that] flaring of
compressor seal emissions can introduce inherently dangerous conditions
with the potential for back-flashing and serious risk of explosion.
Solar therefore discourages flaring for this reason although some
customers have successfully implemented it.''
---------------------------------------------------------------------------

    \198\ See Document ID No. EPA-HQ-OAR-2021-0317-1375.
    \199\ See Document ID No. EPA-HQ-OAR-2021-0317-1375.
---------------------------------------------------------------------------

    With respect to the routing to process option, the same commenter
notes that, while theoretically feasible, a low flow gas stream (like
their facilities' gas streams) cannot be safely or technically re-
introduced back into their processes without significant, resource-
intensive, attention to that minor emissions stream. According to the
commenter, the unintended result would be that the additional equipment
that would need to be installed to accomplish this routing back to
process would not only be costly (discussed below) but could also
result in additional emissions from other sources.
    Based on these concerns, for existing wet seal centrifugal
compressors, the EPA is no longer proposing that BSER is 95 percent
reduction of methane emissions by routing emissions to a control device
or process. Instead, based on the updated analysis presented in this
supplemental proposal, the EPA is proposing that the standard of
performance for existing sources is a numerical emission limit of 3
scfm; the BSER is for an owner or operator to conduct preventative
maintenance and repair of their centrifugal compressors that use wet
seals, as needed, to maintain the volumetric flow rate from each
centrifugal compressor that uses a wet seal at or below 3 scfm. Owners
or operators would be required to conduct volumetric flow rate
measurements at least every 8,760 hours. As a compliance alternative,
the EPA is proposing to allow owners and operators the option to reduce
methane emissions by 95 percent or greater by routing emissions to a
control device or to a process, which would achieve emissions
reductions equal to or greater than the standard of performance of 3
scfm. The cost of application of the numerical emission limit
requirement at an existing source is the same as at a new source, and
the methane cost effectiveness would be the same as discussed in the
previous section for wet seal centrifugal compressors subject to NSPS
OOOOb. The cost effectiveness (without natural gas savings) of
complying with the numerical emission limit for methane emissions is
approximately $111 per ton of methane emissions reduced for the
gathering and boosting segment, $183 per ton of methane emissions
reduced for the processing segment, and $711 per ton of methane
emissions reduced for the transmission and storage segment. Considering
natural gas savings, the cost effectiveness of complying with the
numerical emission limit for methane emissions is an overall net
savings for the gathering and boosting segment, and $28 per ton of
methane emissions reduced for the processing segment.
    As discussed in section IV.G.1.i of this preamble NSPS KKK includes
standards for controlling VOC emissions from centrifugal compressors
with wet seals at natural gas processing plants. The standards provide
several options to comply, including: (1) Operating the centrifugal
compressor with the barrier fluid at a pressure that is greater than
the compressor stuffing box pressure; (2) equipping the centrifugal
compressor with a barrier fluid system degassing reservoir that is
routed to a process or fuel gas system or connected by a CVS to a
control device that reduces VOC emissions by 95 percent or more; or (3)
equipping the centrifugal compressor with a system that purges the
barrier fluid into a process stream with zero VOC emissions to the
atmosphere. NSPS KKK exempts compressors from these requirements if the
compressor is either equipped with a CVS to capture and transport
leakage from the compressor drive shaft back to a process or fuel gas
system or to a control device that reduces VOC emissions by 95 percent,
or if the compressor is designated for no detectable emissions.
    For EG OOOOc, the proposed presumptive standard would be a
numerical emission limit of 3 scfm and include an alternative
compliance method of reducing methane emissions by 95 percent by
routing to a control or process. The proposed presumptive standard of 3
scfm is less stringent than the regulatory compliance options under
NSPS KKK for centrifugal compressor at natural gas processing plants.
    Owners and operators of wet seal centrifugal compressors have been
complying with NSPS KKK since 1984. The EPA is requesting comments on
whether it would provide more

regulatory consistency for owners, operators, and implementing agencies
if EG OOOOc were to incorporate all compliance options provided in NSPS
KKK for wet seal centrifugal compressors at natural gas processing
plants instead of the 3 scfm emission limitation.
    Dry Seal Compressors. The application of the numerical emission
limit option at an existing source is the same as at a new source
because no additional equipment must be installed in order to comply
with the standards. Therefore, the cost of control would also be the
same (see section IV.G.1.b.i of this preamble). As a result, based on
the consideration of the costs in relation to the emission reductions
for methane, the costs to implement the numerical emission limit is
reasonable for all segments. Given that the costs of reducing methane
emissions by the implementation of the numerical emission limit are
reasonable, the EPA is proposing this option as BSER for existing
centrifugal compressors with dry seals.
c. Summary of 2022 Proposal
i. Designated Facility
    Based on changes made and discussed under section IV.F.2.b of this
preamble, the EPA is proposing to redefine the designated facility to
include dry seal compressors in addition to wet seal compressors.
Specifically, the designated facility is defined as a single
centrifugal compressor. Further, the EPA is proposing that centrifugal
compressors located at centralized production facilities would be
designated facilities, while centrifugal compressors located at well
sites would not be designated facilities, consistent with the November
2021 proposal.
ii. Requirements
    Wet and Dry Seal Centrifugal Compressors. The EPA is proposing that
owners or operators of centrifugal compressors with wet and dry seals
be required to conduct volumetric emission measurements (in operating
mode or in stand-by-pressurized-mode) from each centrifugal compressor
dry and wet seal vent using specified methods (similar to the flow rate
monitoring requirements specified under GHGRP subpart W). Owners and
operators would be required to conduct volumetric emissions
measurements from each centrifugal compressor wet and dry seal vent on
or before 8,760 hours of operation or previous measurement.
    The volumetric emissions measurement of the centrifugal compressor
wet and dry seal vent must be maintained to be less than or equal to a
flow rate of 3 scfm (in operating or standby pressurized mode) or a
manifolded dry and wet seal compressor flow rate less than or equal to
the number of compressors multiplied by 3 scfm (in operating or standby
pressurized mode). The same requirements specified in IV.G.1.c of this
preamble for dry seal compressors complying with the numerical emission
limit being proposed for NSPS OOOOb are being proposed for self-
contained wet seal centrifugal compressors under NSPS OOOOb and for dry
and wet seal centrifugal compressors complying with this option under
EG OOOOc.
    Compliance Alternative for Wet Seal Compressors. As a compliance
alternative to maintaining a flow rate at or below 3 scfm, the EPA is
proposing that an owner or operator of a centrifugal compressor
equipped with wet seals can comply with EG OOOOc by reducing methane
emissions from each centrifugal compressor wet seal fluid degassing
system by 95 percent, which achieves emission reductions greater than
or equal to the 3 scfm proposed presumptive standard. Options to meet
this emission reduction requirement include routing emissions via a CVS
to a control device or to the process. This standard can also be met by
an owner or operator utilizing a self-contained wet seal centrifugal
compressor. The same requirements specified in IV.G.1.c for wet seal
compressors complying with the requirements to reduce methane emissions
from each centrifugal compressor wet seal fluid degassing system by 95
percent are being proposed for wet seal compressors complying with this
option under EG OOOOc.

H. Combustion Control Devices

1. November 2021 Proposal
    The EPA proposed requiring 95 percent methane and VOC reduction for
certain affected/designated facilities (i.e., storage vessels, wet seal
centrifugal compressors, and associated gas from oil wells when a sales
line is not available) and solicited comments on several aspects of the
operational efficiency of combustion control devices and methods to
ensure continuous compliance with the required control efficiency.
Specifically, in the November 2021 proposal, the EPA solicited comments
on whether additional measures to ensure proper performance of flares
would be appropriate to ensure that flares meet the current 95 percent
control requirement. The EPA solicited similar comments for enclosed
combustion devices, particularly regarding creating comprehensive
specifications for an operating envelope under which a make/model can
achieve 98 percent reduction. The EPA also solicited comments on the
practicality of requiring combustion and non-combustion control systems
to meet a 98 percent reduction control requirement under operating
conditions present in the oil and gas industry. Finally, the EPA
solicited comment on new technologies that would provide real-time or
near real-time measurement of control efficiency, particularly for
flares.
2. Changes From November 2021 Proposal
    The EPA received comments on most aspects of the solicitation for
comments in the November 2021 proposal related to combustion control
devices, ranging from opposition to requirements as specific as
continuous pilots to recommendations for the use of advanced
technologies to continuously monitor flare combustion efficiency. As
described throughout this section, the EPA is proposing specific
additional requirements in response to comments on the November 2021
proposal and clarifying other requirements that were proposed in that
action.
    In this supplemental proposal, the EPA is proposing requirements
for various combustion control devices to develop consistent
monitoring, recordkeeping, and reporting requirements, regardless of
the affected/designated facility with which the control device is
associated. This is different than the compliance requirements for
control devices in NSPS OOOOa, which has separate requirements for
control devices used on storage vessel affected facilities, than those
used on centrifugal compressor affected facilities. The proposed
monitoring, recordkeeping, and reporting requirements related to
control devices are designed to ensure that these systems achieve the
required control efficiency, and they were established using methods
that limit the burden for owners and operators, while still ensuring
compliance with the required control efficiency.
    Flares. The EPA is proposing to include in both NSPS OOOOb and EG
OOOOc more comprehensive monitoring requirements for flares as
referenced to the General Provisions at 40 CFR 60.18. Specifically, the
General Provisions at 40 CFR 60.18 indicate four criteria needed for
good flare performance. These are: (1) Continuous pilot flame; (2) no
visible emissions except for a total of 5 minutes in a 2-

hour period; (3) minimum net heating value of gas sent to the flare;
and (4) maximum flare tip velocity. In NSPS OOOO and NSPS OOOOa, the
compliance requirements for flares include criteria to address
compliance with items 1 and 2 but do not include any requirements that
would ensure compliance with items 3 and 4 for any affected facilities
which reference flares as a control device option. That is, those
rules, which adopt by reference the flare requirements in 40 CFR 60.18
(i.e., the General Provisions to 40 CFR part 60) do not include
specific requirements specifying the minimum net heating value of gas
sent to the flare or the maximum flare tip velocity. One commenter on
the November 2021 proposal stated that the EPA must establish
continuous monitoring requirements for flares regardless of the control
efficiency required.\200\ One commenter noted that the General
Provisions at 40 CFR 60.18 state that the referencing subpart will
specify the monitoring requirements and indicated that the EPA must
specify these requirements in the new standards.\201\ The EPA agrees
with these commenters, especially noting that recent studies suggests
that 10 percent of flares in the Permian basin are either unlit or are
only burning a portion of the gas sent to the flare.\202\ Consequently,
the EPA concludes that the current operating and monitoring practices
and requirements for well sites and centralized production facilities
are not adequate to ensure flare control systems are operated
efficiently and is therefore, proposing compliance requirements to
ensure all aspects of the General Provisions at 40 CFR 60.18 are met at
all times. These include requirements to ensure a pilot flame is
present at all times through monitoring with a device such as a
thermocouple, ultraviolet beam sensor, or infrared sensor and
monitoring of NHV through use of a calorimeter, unless a demonstration
has been made that the NHV of the inlet gas to the flare consistently
exceeds the operating limit established in the rule. In other
rulemakings, for example recent amendments to the refining \203\ and
chemical sector \204\ rules, monitoring of the net heating value in the
combustion zone, instead of the heating value of the vent gas is
required. While this is important for an assisted flare, we anticipate
the oil and gas source category predominately will use unassisted
flares, because air-assisted flares require electricity and not all
sites will have access to electricity. The EPA finds that the
provisions at 40 CFR 60.18 are sufficient for unassisted flares because
the heat content of the gas at the flame is not diluted by an assist
stream of gas or air. The EPA requests comment on the universe of
unassisted and assisted flares in the oil and gas sector. See section
IV.H.3 of this preamble for details of the proposed compliance
requirements for flares.
---------------------------------------------------------------------------

    \200\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0844 and EPA-HQ-
OAR-2021-0317-1282.
    \201\ See Document ID No. EPA-HQ-OAR-2021-0317-1282.
    \202\ Permian Methane Analysis Project (PermianMAP) reporting
the results of 4 Environmental Defense Fund (EDF) surveys of over a
thousand flare stacks from February to November 2020. See https://www.permianmap.org/flaring-emissions.
    \203\ See 80 FR 75266 (December 1, 2015).
    \204\ See 85 FR 49132 (August 12, 2020).
---------------------------------------------------------------------------

    Enclosed Combustors. The EPA is proposing the same monitoring
requirements for enclosed combustion devices for all affected
facilities that use such devices to meet the applicable standards. We
are also proposing monitoring requirements for enclosed combustion
devices (which are not tested by the manufacturer) for which the
performance test does not correlate the combustion efficiency achieved
by the combustion device with temperature. (i.e., temperature is not
well correlated with combustion efficiency). NSPS OOOO and OOOOa have
separate monitoring requirements for control devices used for
centrifugal compressor affected facilities than for control devices
used for storage vessel affected facilities. This difference goes back
to the EPA's understanding of the landscape of the oil and gas industry
during the rulemaking process for NSPS OOOO and subsequent amendments
through 2016 which resulted in the promulgation of NSPS OOOOa.
Centralized production facilities were not identified within the EPA's
emissions inventory, and the EPA found that storage vessels were mostly
located at well sites which did not have other affected facilities
requiring control. The EPA expected these sites to take advantage of
the reduced compliance burden by using control devices tested by the
manufacturer. Further, during the reconsideration of aspects of NSPS
OOOO, the EPA determined that streamlined compliance options were
warranted for storage vessel affected facilities, in part because of
implementation issues at remote sites and the large number of storage
vessel affected facilities.\205\ In this action, the EPA is proposing
standards for additional affected facilities at well sites (i.e., oil
wells with associated gas that is routed to a control device) and
defining centralized production facilities (which include storage
vessel and compressor affected facilities requiring 95 percent
control). The EPA finds that the rationale used in NSPS OOOO and NSPS
OOOOa supporting streamlined monitoring for storage vessels no longer
holds true. Remote well sites still exist, but these sites also may be
subject to standards for oil well with associated gas and the
compliance burden is shared between those affected facilities to ensure
emissions from both storage vessels and oil wells with associated gas
are reduced by 95 percent. Further, the centralization of production
activities makes moot the concern about remote wells sites for these
centralized production facilities. As mentioned previously, recent
studies such as the study conducted in the Permian, indicate pervasive
issues with combustion sources \206\ and enforcement activities
conducted by the EPA and states have uncovered issues with proper
operation of enclosed combustors on storage vessels.\207\ For these
reasons, the EPA is proposing to align the monitoring requirements in
NSPS OOOOb and EG OOOOc to ensure that all control devices are subject
to the same monitoring requirements, regardless of the affected
facility being controlled.
---------------------------------------------------------------------------

    \205\ See 78 FR 58438 (September 23, 2013) and 81 FR 35897 (June
3, 2016).
    \206\ Permian Methane Analysis Project (PermianMAP) reporting
the results of 4 Environmental Defense Fund (EDF) surveys of over a
thousand flare stacks from February to November 2020. See https://www.permianmap.org/flaring-emissions.
    \207\ ``EPA Observes Emissions from Controlled Storage Vessels
at Onshore Oil and Gas Production Facilities.'' See https://www.epa.gov/sites/default/files/2015-09/documents/oilgascompliancealert.pdf.
---------------------------------------------------------------------------

    For thermal oxidizers/enclosed combustors for which temperature is
correlated with combustion efficiency and for catalytic oxidizers, the
EPA is proposing to include in NSPS OOOOb and EG OOOOc the same
monitoring requirements as required under NSPS OOOOa for centrifugal
compressor affected facilities, and consistent with the rationale in
this discussion, we are proposing to require these monitoring
requirements for all enclosed combustion devices, regardless of the
affected facility being controlled. Further, the EPA is proposing
additional initial compliance requirements for vapor recovery devices
and catalytic vapor incinerators, to ensure owners and operators have a
clear roadmap for initial compliance. Similarly, the EPA is proposing
additional continuous compliance requirements which specify how to
determine continuous compliance with the requirements for

catalytic vapor incinerators, regenerative-type carbon adsorption
systems, and carbon management for regenerative-type and
nonregenerative-type carbon adsorption systems.
    The EPA is also proposing monitoring requirements for enclosed
combustion devices not tested by a manufacturer for which temperature
is not well correlated with combustion efficiency. For enclosed
combustors for which temperature is not well correlated with combustion
efficiency, the EPA is proposing to incorporate requirements similar to
those proposed for flares, as the operation of these devices is similar
to the operation of a flare in that the combustibility of the gas
(NHV), operation without smoking (visible emissions) and a continuous
burning pilot flame are fundamental to ensuring 95 percent combustion.
One commenter suggested that monitoring of the pilot flame for enclosed
combustors was sufficient to provide assurance of effective emission
control.\208\ However, no data were provided to support this assertion
and available data and combustion theory science suggests that the net
heating value of the gas being sent to the combustor is also critical
to ensure proper combustion. As good combustion depends upon the fuel
having a minimum amount of heat content, if the gases from the affected
facility required to be controlled have low heat content at times, then
auxiliary fuel may be necessary to ensure good combustion during those
periods. That is, the same requirements that are needed to ensure
proper performance of flares also apply to enclosed combustors. Because
enclosed combustors often are associated with storage vessels which
have variable emissions events depending on working, breathing,
standing, or flashing losses, the EPA also is proposing that enclosed
combustors monitor inlet flow rate to ensure the control device
operates within the compliance envelope at which compliance with the 95
percent control efficiency was demonstrated.
---------------------------------------------------------------------------

    \208\ See Document ID No. EPA-HQ-OAR-2021-0317-0749.
---------------------------------------------------------------------------

    Condensers and Carbon Adsorption Systems. The EPA is proposing
consistent monitoring requirements for condensers and carbon adsorption
systems independent of the affected facility. NSPS OOOOa has specific
compliance requirements for condensers and carbon adsorption systems
used to control emissions from centrifugal compressor affected
facilities but less specific compliance requirements for vapor recovery
devices used for storage vessel affected facilities. In NSPS OOOOa,
owners and operators are required to conduct specific parameter
monitoring for condensers and carbon adsorption systems used to control
emissions from centrifugal compressor affected facilities, while owners
and operators are only required to conduct monthly inspections ``. . .
to ensure physical integrity of the control device according to the
manufacturer's instructions'' for vapor recovery devices used to
control storage vessel affected facilities. Monthly inspections do not
ensure the condenser temperature is adequate or that the carbon beds
are changed out or regenerated at a frequency to ensure the control
device is achieving at least 95 percent control efficiency. Therefore,
in NSPS OOOOb and EG OOOOc, the EPA is proposing that all affected and
designated facilities that use condensers or carbon adsorption systems
must meet the same monitoring requirements as outlined for centrifugal
compressor affected facilities in NSPS OOOOa.
    Manufacturer Tested Control Devices. The EPA is proposing to
require the same initial requirements for manufacturer testing of
control devices and ancillary monitoring requirements as required in
NSPS OOOO and NSPS OOOOa. In NSPS OOOO and NSPS OOOOa, the EPA included
this alternative to minimize issues associated with performance testing
of certain combustion control devices in the field. The requirements
were based on similar requirements in the oil and natural gas NESHAP
(40 CFR part 63, subparts HH and HHH) and which had been successfully
implemented for some time prior to the promulgation of NSPS OOOO and
NSPS OOOOa. In the 2011 proposal of the provisions for NSPS OOOO, we
stated ``[w]e believe that testing units that are not configured with a
distinct combustion chamber present several technical issues that are
more optimally addressed through manufacturer testing, and once these
units are installed at a facility, through periodic inspection and
maintenance in accordance with manufacturers' recommendations. One
issue is that an extension above certain existing combustion control
device enclosures will be necessary to get adequate clearance above the
flame zone. Such extensions can more easily be configured by the
manufacturer of the control device rather than having to modify an
extension in the field to fit devices at every site. Issues related to
transporting, installing and supporting the extension in the field are
also eliminated through manufacturer testing. Another concern is that
the pitot tube used to measure flow can be altered by radiant heat from
the flame such that gas flow rates are not accurate. This issue is best
overcome by having the manufacturer select and use the pitot tube best
suited to their specific unit. For these reasons, we believe the
manufacturers' test is appropriate for these control devices with
ongoing performance ensured by periodic inspection and maintenance. (76
FR 52785; August 23, 2011).
    Control Efficiency. As mentioned earlier in this section, the EPA
requested comment on whether the EPA should require 98 percent
reduction of methane and VOC emissions instead of 95 percent in the
November 2021 proposal. The EPA received comments stating that flares
can be designed to meet 98 percent control efficiency,\209\ but we also
received comments stating that variability in gas flow, pressure, and
quality would present challenges to achieving 98 percent control
efficiency, especially at low production wells.\210\
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    \209\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0604, EPA-HQ-
OAR-2021-0317-0605, EPA-HQ-OAR-2021-0317-0844, and EPA-HQ-OAR-2021-
0317-1286.
    \210\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0599, EPA-HQ-
OAR-2021-0317-0808, and EPA-HQ-OAR-2021-0317-0831.
---------------------------------------------------------------------------

    The EPA evaluated the costs associated with requiring 98 percent
reduction of methane and VOC emissions from storage vessels in order to
compare the cost-effectiveness for this option against the costs
associated with requiring 95 percent reduction. While the analysis was
specific for storage vessels, the conclusions drawn from this analysis
are generally applicable to other affected facilities because the size
range of control devices evaluated cover the range of controls used for
other affected facilities. Based on this evaluation, we conclude that
the additional reduction is not cost effective and would therefore not
represent the BSER for affected sources requiring an emissions
reduction through the use of a pollution control device. Specifically,
using this example for storage vessel affected facilities, the EPA
added the additional monitoring and operational costs expected to
ensure a 98 percent minimum destruction efficiency and found that it
would not be cost-effective to require control of storage vessels with
the potential for VOC emissions below 12 tpy or methane emissions below
40 tpy. However, at 95 percent reduction, it is considered cost-
effective to require control of storage vessels with potential VOC
emissions of 6 tpy and methane

emissions of 20 tpy.\211\ Therefore, requiring 98 percent reduction of
methane and VOC results in the control of fewer storage vessels, and
thus result in fewer overall emissions reductions. Consequently, the
EPA is proposing to maintain that the BSER for storage vessel affected
facilities is 95 percent reduction, as described in section IV.J of
this preamble. Because the analysis conducted covers the range of
control device sizes utilized by other affected facilities, similar
impacts on the BSER analysis are expected. Furthermore, because
individual sites would utilize a single control device for all
affected/designated facilities, it does not make sense to require
different emissions reduction standards for different affected/
designated facilities. For more detail on the analysis conducted to
assess the costs of control device monitoring see memorandum Analysis
of Monitoring Costs to Ensure 98 Percent Destruction Efficiency,
available in the docket for this action (Docket ID No. EPA-HQ-OAR-2021-
0317).
---------------------------------------------------------------------------

    \211\ The costs associated with the monitoring requirements
necessary to ensure a 95 percent reduction in methane and VOC
emissions is achieved were included in the cost analysis provided in
the November 2021 proposal. See the 2021 TSD for additional details
at Document ID No. EPA-HQ-OAR-2021-0317-0166 and accompanying
spreadsheets at Document ID No. EPA-HQ-OAR-2021-0317-0039.
---------------------------------------------------------------------------

3. Summary of Proposed Requirements for NSPS OOOOb and EG OOOOc
    The EPA is proposing that control devices used for any affected
facility must demonstrate that they meet a 95 percent VOC and methane
emission reduction requirement through a performance test (or for
condensers and carbon absorbers, through a design evaluation) or
manufacturer's performance test.
    In NSPS OOOOb and EG OOOOc, we are proposing the same control
device requirements for thermal vapor incinerators (including thermal
oxidizers and enclosed combustors) for which temperature is correlated
with destruction efficiency, catalytic vapor incinerators, condensers,
and carbon adsorption systems as were required in NSPS OOOOa (for
centrifugal compressor affected facilities). We are proposing that
these requirements apply to all affected facilities complying with the
standards by using one of these control devices.
    The EPA is proposing requirements for flares to be designed and
operated according to the provisions in 40 CFR 60.18 for all flares,
regardless of the affected facility type, except as noted below for
pressure-assisted devices. Further, we are proposing to require these
same general requirements for enclosed combustors not tested by the
manufacturer and for which temperature is not correlated with control
device performance. NSPS OOOO and NSPS OOOOa do not include criteria to
determine that temperature is (or is not) correlated with control
device performance. Criteria where temperature is well correlated could
include requirements that air flow to the burner is controlled and that
there is sufficient refractory in the stack to maintain high
temperature even at low flows. The EPA requests comment on whether
criteria should be developed for NSPS OOOOb and EG OOOOc, which
delineate when temperature is (or is not) correlated with control
device performance, and if so, in addition to the criteria above, what
criteria would be appropriate. The EPA is proposing to include
consistent initial and continuous compliance requirements to ensure
flares and enclosed combustion devices are maintaining efficient
combustion. As discussed previously in this section, there are 4
critical requirements in 40 CFR 60.18 that must be met to ensure proper
destruction efficiency.\212\ The proposed continuous compliance
requirements for each of these critical elements are described in the
following paragraphs.
---------------------------------------------------------------------------

    \212\ The four requirements are: (1) Continuous pilot flame; (2)
no visible emissions except for a total of 5 minutes in a 2-hour
period; (3) minimum net heating value of gas sent to the flare; and
(4) maximum flare tip velocity.
---------------------------------------------------------------------------

    First, the EPA is proposing to require all flares and enclosed
combustion devices \213\ to have a continuous pilot flame and install a
continuous parameter monitoring system capable of continuously (at
least once every 5 minutes) monitoring for the presence of a pilot or
combustion flame. This is in keeping with the requirements of the
General Provisions to require a continuous pilot flame. The EPA is
specifying more frequent monitoring intervals for the pilot light than
for other continuous parameter monitoring systems (which require a
minimum of one reading per hour) because the destruction efficiency
will rapidly fall to zero in the absence of a pilot or combustion
flame. Therefore, we determined that more frequent readings were needed
for the pilot flame monitoring system to ensure the flare or enclosed
combustion device achieves 95 percent destruction efficiency at all
times.
---------------------------------------------------------------------------

    \213\ This discussion in the rest of this section applies to
those enclosed combustion devices for which temperature is not
correlated with destruction efficiency.
---------------------------------------------------------------------------

    Second, the EPA is proposing to require inspections to monitor for
visible emissions using section 11 of EPA Method 22 of appendix A-7 of
part 60 (EPA Method 22). The observation period for the EPA Method 22
inspection would be 15 minutes. Visible emissions longer than 1 minute
during the 15-minute period would be a deviation of the standard. This
is consistent with similar requirements in NSPS OOOOa. The EPA is
proposing that these inspections would occur monthly, and at other
times as requested by the Administrator. For example, if the
Administrator observed a flare with intermittent visible emissions, the
Administrator may require the owner or operator to conduct an EPA
Method 22 inspection to determine whether the flare is exceeding the
visible emissions limit.
    Next, the EPA is proposing that flares and enclosed combustion
devices monitor the net heating value of the vent gas sent to the flare
or combustor. Owners and operators would install a continuous parameter
monitoring system, such as a calorimeter, to continuously determine the
net heating value of the gas sent to the flare or combustor.
Alternatively, the owner or operator could conduct an initial
assessment to demonstrate that the net heating value of the vent gas
sent to the flare or combustor consistently exceeds the required
minimum net heating value in 40 CFR 60.18 or the minimum net heating
value proposed for pressure-assisted flares.\214\ The proposed initial
demonstration consists of hourly monitoring over 10 days. The EPA is
proposing this frequency and duration of monitoring in order to provide
a large sampling set by which to assess the variability of the vent gas
sent to the combustion device and to adequately characterize the tails
of the distribution. When actively controlling net heating value,
operators will generally control at a set point 10 to 20 percent higher
than the limit to ensure they are meeting the limit at all times.
Therefore, the EPA concluded that a 20 percent cushion was a reasonable
minimum value for ``well above the threshold.'' To be considered
consistently above the net heating value threshold, greater than 90
percent of the measurements would need to be ``well above the
threshold,'' with no readings below the threshold. Based on these
considerations, the EPA

is proposing that if there are no hourly gas samples with a net heating
value below the required minimum net heating value and 20 or fewer
hourly gas samples are less than 1.2 times the required minimum net
heating value, then the gas stream is considered to be ``consistently
above the threshold'' and on-going continuous monitoring is not
required.
---------------------------------------------------------------------------

    \214\ Pressure-assisted devices are not required to comply with
the vent gas net heating value in 40 CFR 60.18. The EPA is proposing
alternative net heating value requirements for these devices as
discussed in detail below.
---------------------------------------------------------------------------

    Lastly, to ensure compliance with the maximum flare tip velocity
requirement in 40 CFR 60.18, for flares and enclosed combustion
devices, the EPA is proposing to require installation of a continuous
parameter monitoring system to determine the flow of gas sent to the
flare or combustor, except as noted below for pressure-assisted
devices. Alternatively, the owner or operator may conduct an initial
engineering assessment of the sources vented to the flare to
demonstrate that, based on the maximum pressure of these sources, the
maximum possible gas flow rate would not exceed the allowed maximum
flare tip velocity in 40 CFR 60.18 or the maximum design flow rate of
the enclosed combustor.
    The EPA has also determined that combustion devices may be
operating at gas flow rates that are too low to support efficient
combustion, resulting in uncombusted vented emissions. To address this
issue, the EPA is proposing to require that manufacturers establish
both a minimum and maximum flow rate during the testing performed under
40 CFR 60.5413b(d) and 40 CFR 60.5413c(d) to ensure these devices
operate efficiently in the field. Combustion control devices previously
tested by the manufacturer for which the manufacturer was able to
demonstrate the control device meets the performance requirements would
not need to perform new performance tests. The zero-level at which the
combustion control device was tested will be extracted from the
previously submitted performance test report and added to the
information on the EPA's website.\215\ For flares and enclosed
combustion devices not tested by the manufacturer under 40 CFR
60.5413b(d) or 40 CFR 60.5413c(d), the owner or operator would be
required to establish a minimum vent gas flow rate based on
manufacturer recommendations. Owners and operators would be required to
continuously monitor the vent gas flow rate to ensure that it is above
this minimum level whenever vent gas is sent to the flare or enclosed
combustion device. As an option, the owner or operator could install a
backpressure preventer which is set to operate at or above the minimum
inlet gas flow rate. The EPA is soliciting comment on this additional
requirement and whether there are additional situations where
continuous monitoring of the vent gas flow rate is unnecessary.
---------------------------------------------------------------------------

    \215\ Information on combustion control devices tested by the
manufacturer can be found at: https://www.epa.gov/stationary-sources-air-pollution/performance-testing-combustion-control-devices-manufacturers.
---------------------------------------------------------------------------

    For pressure-assisted devices, the EPA is proposing to include
special provisions in NSPS OOOOb/EG OOOOc, which include a minimum net
heating value (NHV) of the gas sent to the flare/combustor of 800
British thermal units per standard cubic feet (Btu/scf) and an
exemption from the maximum velocity requirements in 40 CFR 60.18.\216\
Pressure-assisted devices are designed to operate at high flare or
burner tip velocities and use this velocity to improve mixing of the
flared gas with surrounding air. For good combustion efficiency at
these high velocities, the flared gas must have higher heat content
than a non-pressure-assisted flare. The EPA evaluated pressure-assisted
flares and determined that these flares must have flare gas with an NHV
of 800 Btu/scf or higher to work efficiently.217 218 Also,
because the burners are specifically designed to have high flow rates,
the burner tip velocity typically exceeds the maximum flare tip
velocity limit in 40 CFR 60.18. The maximum velocity limits in 40 CFR
60.18 were set to prevent flame ``lift off'' or flame instability from
conventional flare tips. However, pressure-assisted flare tips are
specifically designed to operate efficiently at much higher velocities.
The EPA found that pressure assisted flares can operate efficiently at
these higher velocities. Therefore, the EPA is proposing that pressure-
assisted devices would not be subject to the maximum flare tip velocity
limit.
---------------------------------------------------------------------------

    \216\ Pressure-assisted devices would still be subject to the
requirements for a continuous pilot flame and the visible emissions
requirement, as well as the requirement to continuously monitor (or
perform an assessment) on the NHV of the vent gas.
    \217\ ``Notice of Final Approval for the Operation of a
Pressure-Assisted Multi-Point Ground Flare at Occidental Chemical
Corporation,'' 81 FR 23480, April 21, 2016, and ``Notice of Final
Approval for an Alternative Means of Emission Limitation at
ExxonMobil Corporation; Marathon Petroleum Company, LP (for Itself
and on Behalf of Its Subsidiary, Blanchard Refining, LLC); Chalmette
Refining, LLC; and LACC, LLC,'' 83 FR 46939, September 17, 2018.
    \218\ Because pressure-assisted flares generally do not use
assist gas, combustion zone NHV is the same as the flare gas NHV.
---------------------------------------------------------------------------

    Finally, the EPA is proposing operating requirements at 40 CFR
60.5417b(f) (and 40 CFR 60.5417c(f)) and specifying what constitutes a
deviation at 40 CFR 60.5417b(g) (and 40 CFR 60.5417c(g)) that are
consistent with the operating and monitoring requirements outlined in
this section and that are consistent across all affected facilities
using control devices. Further, these sections are referenced in the
recordkeeping and reporting requirements for each affected facility so
that the reporting requirements for affected facilities that use
control devices to comply with the standard have consistent control
device reporting requirements regardless of the type of affected
facility. The EPA is soliciting comment on all proposed requirements
for control devices described within this section.

I. Reciprocating Compressors

    In a reciprocating compressor, natural gas enters the suction
manifold and then flows into a compression cylinder, where it is
compressed by a piston driven in a reciprocating motion by the
crankshaft, which is powered by an internal combustion engine.
Emissions occur when natural gas leaks around the piston rod when
pressurized natural gas is in the cylinder. The compressor rod packing
system consists of a series of flexible rings that create a seal around
the piston rod to prevent gas from escaping between the rod and the
inboard cylinder head. However, over time, during operation of the
compressor, the rings become worn, and the packaging system needs to be
replaced to prevent excessive leaking from the compression cylinder.
1. NSPS OOOOb
a. November 2021 Proposal
    Based on the analysis presented in section XII.E.1 of the November
2021 proposal preamble (86 FR 63214-63220; November 15, 2021), the
proposed BSER for NSPS OOOOb for reducing GHGs and VOC from new
reciprocating compressors was the replacement of the rod packing based
on an annual monitoring threshold. Under the November 2021 proposal,
the owner or operator of a reciprocating compressor affected facility
would have been required to monitor the rod packing emissions annually
by conducting flow rate measurements. When the measured flow rate
exceeded 2 scfm (in pressurized mode), replacement of the rod packing
would have been required. As indicated at proposal, the 2 scfm flow
rate threshold was established based on manufacturer guidelines
indicating that a flow rate of 2 scfm or greater was considered
indicative of rod packing failure.\219\ Alternatively, the November
2021 proposal would have

also provided owners and operators the option of routing rod packing
emissions to a process via a CVS under negative pressure in order to
comply with the rule. The proposed option to route to a process is
allowed as an alternative under NSPS OOOOa because implementing this
option, where feasible, would achieve greater emission reductions than
the primary fixed schedule rod packing replacement BSER requirement
under NSPS OOOOa.
---------------------------------------------------------------------------

    \219\ 86 FR 63218 (November 15, 2021).
---------------------------------------------------------------------------

b. Changes From November 2021 Proposal
    The BSER analysis is unchanged from what was presented in the
November 2021 proposal (see 86 FR 63214-63220, section XII.E.
Reciprocating Compressors). The EPA is proposing changes and specific
clarifications to the November 2021 proposal standards for NSPS OOOOb.
For the proposed replacement of the rod packing based on an emission
limit and annual measurement requirement, we are proposing: (1) To
clarify that the standard of performance is a numeric standard (not a
work practice standard) of 2 scfm, (2) to allow for repair (in addition
to replacement) of the rod packing in order to maintain an emission
rate at or below 2 scfm; (3) to allow for monitoring based on 8,760
hours of operation instead of based on a calendar year. We are also
proposing regulatory text that clearly defines the required flow rate
measurement methods and/or procedures, repair and replacement
requirements, and recordkeeping and reporting requirements. For the
alternative option of routing rod packing emissions to a process via a
CVS under negative pressure, we are proposing to remove the negative
pressure requirement. These changes take into account comments received
on the November 2021 proposal, as explained below.
    The basis for the proposed changes and clarifications to the
replacement of the rod packing based on a flow rate monitoring
measurement for reciprocating compressors is presented in section
IV.I.1.b.i of this preamble. The basis for the proposed change to the
alternative option of routing rod packing emissions to a process via a
CVS under negative pressure is presented in section IV.I.1.b.ii of this
preamble. A summary of the proposed reciprocating compressor standards
is presented in section IV.I.1.b.iii of this preamble.
i. Numerical Emission Limit Standard Proposed Changes
    Changes to Format of the Standard. In re-considering the BSER
determination and standards for reciprocating compressors proposed in
November 2021, the EPA recognized that it is feasible to prescribe a
standard of performance, rather than a work practice standard,\220\ for
reciprocating compressors. Accordingly, the EPA is now proposing a
numerical emission limit requirement. The major difference between this
standard and what the EPA proposed in November 2021 is that under this
supplemental proposal, owners and operators would be required to
maintain emissions at or below the emission limit (emission flow rate
of 2 scfm) whereas under the November proposal, owners or operators
would have been required to change out the rod packing only after
discovering an exceedance of 2 scfm. The BSER is replacement of the rod
packing and/or other necessary repair and maintenance activities to
maintain emissions at or below 2 scfm.
---------------------------------------------------------------------------

    \220\ Under CAA section 111(h)(1), work practice standards are
appropriate only where ``it is not feasible to prescribe or enforce
a standard of performance.'' CAA section 111(h)(2) defines such
infeasibility as ``any situation in which the Administrator
determines that (A) a pollutant or pollutants cannot be emitted
through a conveyance designed and constructed to emit or capture
such pollutant, or that any requirement for, or use of, such a
conveyance would be inconsistent with any Federal, state, or local
law, or (B) the application of measurement methodology to a
particular class of sources is not practicable due to technological
or economic limitations.''
---------------------------------------------------------------------------

    Repair or Replacement. Commenters on the November 2021 proposal
urged the EPA to allow for repair as an alternative to complete
replacement of rod packing. The commenters pointed out that allowing
repair would be consistent with California's reciprocating compressor
rule requirements. See 17 California Code of Regulation section
95668(c)(3)(D).\221\ One commenter noted that, for older units,
replacing the rod packing does not always address emissions levels, as
other maintenance issues can contribute to cylinder emissions, such as
issues with the rod itself. The commenter added that providing the
flexibility to repair as well as replace the rod packing could
significantly impact personnel costs--while rod packing replacement on
older units can require approximately 32-man hours per cylinder, a
repair may entail a significantly lower level of effort and hours of
labor.\222\
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    \221\ Final Regulation Order. California Code of Regulations,
Title 17, Division 3, Chapter 1, Subchapter 10 Climate Change,
Article 4. Subarticle 13: Greenhouse Gas Emission Standards for
Crude Oil and Natural Gas Facilities.
    \222\ See Document ID No. EPA-HQ-OAR-2021-0317-0817.
---------------------------------------------------------------------------

    The EPA agrees with the commenters' suggestion. The intent of the
proposed reciprocating compressor standard was to require that the
volumetric flow rate be maintained at or below 2 scfm. If repair can
maintain the volumetric flowrate at or below 2 scfm without the need to
replace the rod packing, the intent of the proposed standards would be
met. Thus, under the proposed numerical emission limit, an owner or
operator would be allowed to repair or replace the rod packing in order
to maintain the volumetric flow rate at or below the 2 scfm emission
limit.
    Hours of Operation Versus Calendar Year. Commenters \223\ on the
November 2021 proposal recommended that the EPA consider requiring flow
rate monitoring based on a compressor's hours of operation totaling one
year (i.e., 8,760 hours) in lieu of requiring annual flow rate
measurements based on a calendar year. Commenters stated that using the
compressor's hours of operation would ensure that undue burden is not
placed on owners and operators where compressors are not operational
for multiple months or are used intermittently. The commenters
explained that basing flow rate measurement requirements on a
reciprocating compressor's hours of operation would allow owners and
operators to stagger maintenance activity throughout the year. The
comments further suggested that the EPA consider exemptions from the
rule for limited-use reciprocating compressors and changing the flow
rate measurement monitoring requirement frequency to every 2 years.
---------------------------------------------------------------------------

    \223\ See Document ID No. EPA-HQ-OAR-2021-0317-0415.
---------------------------------------------------------------------------

    In order to address limited-use reciprocating compressors and to
allow owners and operators flexibility when planning maintenance, the
EPA agrees that it makes sense to require periodic reciprocating
compressor flow rate monitoring based on the hours of operation (i.e.,
8,760 hours) in lieu of requiring monitoring based on a calendar year.
Thus, we are proposing to allow for periodic flow rate monitoring based
on 8,760 hours of operation instead of requiring monitoring on a
calendar year basis.
    Regulation Clarifications. Several commenters \224\ requested that
the EPA clearly state in the rule that the GHGRP subpart W methods be
allowed for the flow rate measurements. These commenters also requested
that the EPA clearly state the proposed reciprocating compressor annual
monitoring threshold and the repair and rod packing replacement
requirements. Specifically, they sought certainty

regarding the schedule for repair and ``delay of repair'' criteria to
ensure unnecessary restrictions are not placed on repair schedules, and
a clear explanation of operating requirements for measurement (i.e.,
when the unit is operating).
---------------------------------------------------------------------------

    \224\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0415, and EPA-
HQ-OAR-2021-0317-1375.
---------------------------------------------------------------------------

    The EPA considered the commenters' specific requests for clarity
within the requirements when developing the proposed regulatory text
and the desire to be consistent with the GHGRP subpart W. We recognize
this desire however we are concerned the flow rate measurements methods
under GHGRP subpart W are not as well-defined or prescriptive as the
methods the EPA requires for demonstrating compliance with an emission
standard. Instead, the EPA is proposing the use of volumetric flow rate
which meet the requirements of Method 2D (40 CFR part 60, appendix A)
for testing emissions from reciprocating compressor rod packing and the
use of a high-volume sampler to measure the emissions from proposing
either the reciprocating compressor rod packing or centrifugal
compressor seal vents (dry seals for NSPS OOOOb and all centrifugal
compressor wet and dry seals for EG OOOOc).\225\ For the high-volume
sampler, instead of relying on manufacturer defined procedures required
in GHGRP Subpart W, the EPA is proposing a defined set of procedures
and performance objectives to ensure consistent application of these
samplers. In an effort to allow for additional innovation for these
types of measurements, the EPA is also proposing to allow other
methods, subject to Administrator approval, that have been validated
according to Method 301 (40 CFR part 63, appendix A). The EPA solicits
comment on the use of the proposed performance test methods and
solicits comment on other methodologies that could be used to
demonstrate compliance with the centrifugal compressor dry seal vent,
centrifugal compressors for EG OOOOc, and reciprocating compressor rod
packing emission standards.
---------------------------------------------------------------------------

    \225\ See section IV.G. for discussion on centrifugal
compressors.
---------------------------------------------------------------------------

    The proposed NSPS OOOOb regulatory text also specifies that flow
rate monitoring be conducted in operating or standby pressurized mode,
and ``repair'' and ``delay of repair'' schedules, in addition to other
clarifying requirements. The EPA is proposing to require conducting
flow rate measurements during operating or standby pressurized mode
because the measured emissions would be representative of actual
emissions during operations. Repair schedules are proposed to require
repair of equipment in a timely manner to mitigate emissions. Delay of
repair would be allowed when owners and operators required more time to
repair equipment based on scenarios beyond the owner or operator's
control (e.g., issues with availability of equipment or where repair
necessitates a compressor shutdown when redundancy of compressors is
not available).
ii. Routing Emissions to a Process Via a Closed Vent System Under
Negative Pressure
    The EPA received comments on the November 2021 proposal related to
its proposed compliance alternative of routing rod packing emissions to
a process via a CVS under negative pressure. One commenter \226\ noted
that routing emissions to a process should not require negative
pressure, stating that some pressure differential is required to take
gas out of the rod packing vent and into the desired location. This
commenter further stated that the use of negative pressure can raise
safety and operational issues, and that operating a crankcase
collection system under negative pressure (i.e., in a vacuum) creates
the possibility of introducing oxygen into the system. This commenter
added that allowing for pressure differential without requiring
operation under negative pressure could lead to larger emission
reductions overall, and that the proposed negative pressure requirement
eliminates the ability to use technologies that could reduce emissions
further. Another commenter \227\ similarly reported that the use of
negative pressure presents safety concerns of creating an explosive
mixture of natural gas and atmospheric air, should there be any leak
between the negative pressure source and the packing vent. The
commenter stated that as long as the packing vent recovery system is at
a lower pressure; the packing vent gas will be recovered without
leaking to atmosphere and there will be no risk of introducing
atmospheric air to the natural gas.
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    \226\ See Document ID No. EPA-HQ-OAR-2021-0317-0817.
    \227\ See Document ID No. EPA-HQ-OAR-2021-0317-0745.
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    The November 2021 proposal included the requirement to route rod
packing emissions to a process via a CVS under negative pressure based
on information submitted by a petitioner \228\ on NSPS OOOO that
requested/suggested an alternative standard that would result in equal
to or greater emissions reductions than the rod packing replacement
standard. The petitioner's suggested alternative standard was to
capture emissions under negative pressure, thus allowing all emissions
to be routed to the engine. The petitioner suggested achieving this by
recovering vented emissions from the rod packing under negative
pressure and routing these emissions of otherwise vented gas to the air
intake of a reciprocating internal combustion engine that would burn
the gas as fuel to augment the normal fuel supply. The petitioner
reasoned that emission reductions would be commensurate with, or better
than, the reductions from the rod packing replacement standard. The EPA
acknowledged at the time (2014) that this technology may not be
applicable or feasible for every compressor installation and situation.
However, the EPA proposed this option as an alternative to the rod
packing replacement standards for those instances where it could be
applied.\229\
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    \228\ Letter from Veronica Nasser, REM Technologies, Inc., to
Lisa P. Jackson, EPA Administrator, Petition for Reconsideration.
    \229\ See 79 FR 41760-41761 (July 17, 2014).
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    In light of the comments received on the November 2021 proposal,
and an increased understanding of this type of approach, the EPA is
proposing to revise the compliance alternative by continuing to allow
emissions to be routed to a process via a CVS but removing the
requirement for this to occur under negative pressure. The intent of
requiring ``negative pressure'' was that there be sufficient pressure
differential such that emissions would be routed from the compressor
via the CVS to the process. The EPA did not intend to create a safety
issue or limit technologies that would achieve equivalent or greater
emission reductions than the work practice standard. Since such a
pressure differential would be created when the reciprocating
compressor is operating, specifying that emissions need to be routed to
a process via a CVS under negative pressure is unnecessary. As the
commenter noted, this is already understood for other sources where the
standards require routing of emissions through a CVS to a process or
control device.
    As noted above, routing emissions to a process is an existing
compliance option under NSPS OOOO and NSPS OOOOa and the EPA has
assumed that the emissions reduced by this option, where feasible to
implement, are greater than those achieved by the proposed BSER
requirement to implement maintenance and repair activities to maintain
the flow rate (as a surrogate for emissions) from the reciprocating
compressor rod packing at or below 2

scfm. The EPA solicits comment on its assumption that the emissions
reduced by requiring the capture of gas and routing to a process are
greater than the requirement to maintain the flow rate from the
reciprocating compressor rod packing at or below 2 scfm. The EPA also
is soliciting comment on the prevalence of owners and operators
complying with NSPS OOOO and NSPS OOOOa by capturing and routing
emissions from the reciprocating compressor rod packing to a process.
iii. Summary of Proposed Standards
    Affected Facility. The EPA is proposing to define a reciprocating
compressor affected facility as each reciprocating compressor, which is
a single reciprocating compressor. A reciprocating compressor located
at a well site is not an affected facility under this subpart. A
reciprocating compressor located at a centralized production facility
is an affected facility under this subpart.
    Numerical Emission Limit Standards. The proposed NSPS OOOOb
standard of performance for reciprocating compressor affected
facilities is a numerical emission limit of 2 scfm (in operating or
standby pressurized mode). The volumetric flow rate measurement from
each reciprocating rod packing must be maintained to be less than or
equal to a flow rate of 2 scfm (in operating or standby pressurized
mode). The proposed BSER is to repair or replace the rod packing and to
conduct other necessary repair and maintenance in order to maintain the
emission rate at or below 2 scfm. The proposed monitoring requirements
are to conduct volumetric flow rate measurements from each
reciprocating compressor rod packing using the proposed monitoring
methods in 40 CFR 60.5386b (which includes similar screening and flow
rate measurement methods as required under GHGRP subpart W).
    The EPA is proposing to require the first volumetric flow rate
measurements from a reciprocating compressor affected facility on or
before 8,760 hours of operation. Subsequent volumetric emissions
measurements from a reciprocating compressor affected facility would be
required on or before 8,760 hours of operation after the previous
measurement, or on or before 8,760 hours of operation after the date of
the most recent reciprocating compressor rod packing replacement,
whichever is later. Preventative maintenance or other corrective
actions may be necessary (in addition to monitoring every 8,760 hours
of operation) in order for owners or operators to ensure compliance at
all times (consistent with the general duty clause 40 CFR 60.5470b(b))
with the required flow rate of 2 scfm or less).
    Routing Emissions From the Rod Packing to a Process. Alternatively,
an owner or operator may choose to comply with NSPS OOOOb by routing
emissions from the rod packing to a process through a CVS. This option
would achieve greater than or equal to the 2 scfm numerical limit as
emissions would be routed to a process via a closed system which would
limit emissions from the rod packing from being vented to the
atmosphere. An owner or operator must ensure that the CVS is designed
to capture and route all gases, vapors, and fumes to a process (40 CFR
60.5411b(a) and (c)). Additionally, an owner or operator would be
required to design and operate the CVS with no detectable emissions and
would be subject to bypass requirements (as applicable). Initial,
monthly, and annual inspections (using OGI, EPA Method 21, or AVO (for
monthly inspections only)) would be required to check for defects and
detectable emissions.
    Recordkeeping and Reporting Requirements. Owners or operators
complying with the numerical emission limit must track and report in
their annual report the cumulative number of hours of operation of each
reciprocating compressor since startup, since the previous screening/
volumetric flow rate emissions measurement, or since the previous
reciprocating compressor repair/replacement of rod packing, as
applicable. Their annual report must also include a description of the
method used and the results of the volumetric flow rate measurement or
emissions screening, as applicable. Lastly, owners or operators must
maintain records and report each deviation from the emission limit
standard that occurred during the reporting period, the date and time
the deviation began, duration of the deviation and a description of the
deviation.
    For a reciprocating compressor affected facility complying with the
routing emissions from the rod packing to a process through a CVS, an
owner or operator would be required to maintain records and report each
reciprocating compressor that was constructed, modified, or
reconstructed during the reporting period that is complying by using
this option. In instances where a deviation from the standard has
occurred during the reporting period, an owner or operator would be
required to provide information on the date and time the deviation
began, the duration of the deviation, and a description of the
deviation. Additionally, they would be required to report of the dates
of each cover and CVS inspection, whether defects or leaks are
identified, and the date of repair or the date of anticipated repair if
repair is delayed would be included in the annual report. Where bypass
requirements apply, the date and time of each bypass alarm or each
instance the key is checked out would be included in the annual report.
2. EG OOOOc
    Based on the analysis presented in section XII.E.2 of the November
2021 proposal preamble (86 FR 63214-63220; November 15, 2021), the
proposed BSER for EG OOOOc for reducing methane emissions from existing
reciprocating compressors was the replacement of the rod packing based
on an annual monitoring threshold. Under the November 2021 proposal,
the owner or operator of a reciprocating compressor designated facility
would have been required to monitor the rod packing emissions annually
by conducting flow rate measurements. When the measured flow rate
exceeded 2 scfm (in pressurized mode), replacement of the rod packing
would have been required. Alternatively, the November 2021 proposal
would have also provided owners and operators the compliance
alternative of routing rod packing emissions to a process via a CVS
under negative pressure to comply with the rule.
a. Standard Proposed Changes
    Based on the same public comment considerations and reasoning as
explained above (see sections IV.I.1.b.i and ii of this preamble) for
the proposed NSPS OOOOb reciprocating compressor rule changes, the EPA
is proposing the same changes and requirements under EG OOOOc as
presumptive standards for designated facilities.
b. Summary of Proposed Standards
    Designated Facility. The EPA is proposing to define a reciprocating
compressor designated facility as each reciprocating compressor, which
is a single reciprocating compressor. A reciprocating compressor
located at a well site is not a designated facility under this subpart.
A reciprocating compressor located at a centralized production facility
is a designated facility under this subpart.
    Proposed Presumptive Standards. The proposed presumptive standards
and BSER for existing reciprocating compressors are the same as those
being proposed for new reciprocating compressors (see section
IV.I.1.b.iii of this preamble). The requirements to

monitor the volumetric flow rate from a reciprocating compressor based
on hours of operation, and to repair or replace the rod packing and to
conduct any necessary repair and maintenance in order to maintain a
flow rate at or below 2 scfm, would not result in any additional
capital expenditures or retrofit considerations that would warrant
different requirements. Alternatively, as with new sources, owners or
operators of existing reciprocating compressors would be allowed to
comply by routing rod packing emissions to a process via a CVS.

J. Storage Vessels

1. NSPS OOOOb
a. November 2021 Proposal
    Storage Vessel Affected Facility. In the November 2021 proposal,
the EPA proposed to retain the current VOC standards for storage
vessels (95 percent reduction) and proposed for the first-time
standards for reducing methane emissions from storage vessels (95
reduction). In addition, for both VOC and methane standards, the EPA
proposed to define a storage vessel affected facility as a tank battery
or a single storage vessel that is not part of a tank battery, with the
potential for VOC emissions of 6 tpy or greater.\230\ The standards in
NSPS OOOOa apply to single storage vessels with potential VOC emissions
of 6 tpy or greater, although the EPA has long observed that these
storage vessels are typically located as part of a tank battery. See 76
FR 52738, 52763 (August 23, 2011). Further, the 6 tpy applicability
threshold was established by directly correlating the cost to control
different levels of VOC emissions based on the use of a single vapor
recovery or combustion control device, regardless of the number of
storage vessels routing emissions to that control device, and control
of 6 tpy VOC was cost effective using that single control device. Id.
at 52763-64. Therefore, in the November 2021 proposal, the EPA proposed
to define a tank battery as a group of storage vessels that are
physically adjacent and that receive fluids from the same source (e.g.,
well, process unit, compressor station, or set of wells, process units,
or compressor stations) or which are manifolded together for liquid or
vapor transfer. The EPA proposed that to determine whether a single
storage vessel is an affected facility, the owner or operator would
compare the 6 tpy VOC threshold to the potential emissions from that
individual storage vessel; to determine whether a tank battery is an
affected facility, the owner or operator would compare the 6 tpy VOC
threshold to the aggregate potential emissions from the group of
storage vessels in the tank battery. For new, modified, or
reconstructed sources, the EPA proposed that if the potential VOC
emissions from a storage vessel or tank battery exceeds the 6 tpy
threshold, then it is a storage vessel affected facility and controls
would be required. Additionally, the EPA proposed an emissions limit
requiring 95 percent reduction as the BSER for reducing VOC and methane
emissions from new, modified, or reconstructed storage vessel affected
facilities. The EPA also requested comment on increasing combustion
efficiency to 98 percent control and on requiring additional monitoring
of the control device. See IV.G of this preamble for discussion related
to combustion control devices.
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    \230\ For the reasons explained in the November 2021 proposal,
the 6 tpy VOC applicability threshold would apply to both methane
and VOC standards.