estimated to be $26,000 and $46,000, for small and medium-sized plants
respectively. The cost of a new solar-powered electronic controller
system is

estimated to be $28,000 and $52,000, for small and medium-sized plants
respectively. The estimated annualized capital costs, assuming a 15-
year equipment lifetime and a 7 percent interest rate, are $2,800 and
$5,040, respectively for a system powered with electricity from the
grid or other power source for small and medium-sized plants, and
$3,090 and $5,630, respectively, for a solar-powered system for small
and medium-sized plants.
    For the production segment, considering the slightly more expensive
solar-powered system, under the single pollutant approach, the
estimated cost effectiveness is $550 per ton of methane avoided and
$1,970 per ton of VOC avoided for a small plant and $500 per ton of
methane avoided and $1,810 per ton of VOC avoided for a medium-sized
plant. Using the multipollutant approach where half the cost of control
is assigned to the methane reduction and half to the VOC reduction, the
estimated cost effectiveness is $275 per ton of methane avoided and
$980 per ton of VOC avoided for a small plant and $250 per ton of
methane avoided and $900 per ton of VOC avoided for a medium-sized
plant in the production segment. When considering the cost of saving
the natural gas that would otherwise be emitted for the production
segment, the cost effectiveness is $370 per ton of methane avoided and
$1,320 per ton of VOC avoided for a small plant and $320 per ton of
methane avoided and $1,150 per ton of VOC avoided for a medium-sized
plant. Using the multipollutant approach, the estimated cost
effectiveness is $185 per ton of methane avoided and $660 per ton of
VOC avoided for a small plant and $160 per ton of methane avoided and
$580 per ton of VOC avoided for a medium-sized plant in the production
segment. These values are well within the range of what the EPA
considers to be reasonable for methane and VOC using both the single
pollutant and multipollutant approaches.
    For the natural gas transmission and storage segment, considering
the slightly more expensive solar-powered system, the estimated cost
effectiveness is $750 per ton of methane avoided and $27,200 per ton of
VOC avoided for a small plant and $990 per ton of methane avoided and
$35,700 per ton of VOC avoided for a medium-sized plant. Using the
multipollutant approach, the estimated cost effectiveness is $380 per
ton of methane avoided and $13,600 per ton of VOC avoided for a small
plant and $490 per ton of methane avoided and $17,800 per ton of VOC
avoided for a medium-sized plant. Transmission and storage facilities
do not own the natural gas; therefore, revenues from reducing the
amount of natural gas emitted/lost was not applied for this segment.
While the cost effectiveness values for VOC are higher than the range
of what the EPA considers to be reasonable for VOC, the cost
effectiveness for methane is within the range of what the EPA considers
to be reasonable for methane using the single pollutant approach.
    For the large model plants, the zero-emissions option evaluated was
the use of instrument air systems. For the production segment, the
emissions avoided would be 24.9 tpy methane and 6.9 tpy VOC, and in the
transmission and storage segment 10.0 tpy methane and 0.3 tpy VOC. The
cost of a new instrument air system is estimated to be $96,000 and the
estimated annualized capital costs, assuming a 15-year equipment
lifetime and a 7 percent interest rate, are $10,500. For the production
segment, under the single pollutant approach, the estimated cost
effectiveness is $420 per ton of methane avoided and $1,520 per ton of
VOC avoided. Using the multipollutant approach, the estimated cost
effectiveness is $210 per ton of methane avoided and $760 per ton of
VOC avoided. When considering the cost of saving the natural gas that
would otherwise be emitted for the production segment, the cost
effectiveness is $240 per ton of methane avoided and $860 per ton of
VOC avoided. Using the multipollutant approach, the estimated cost
effectiveness is $120 per ton of methane avoided and $430 per ton of
VOC avoided in the production segment. These values are well within the
range of what the EPA considers to be reasonable for methane and VOC
using both the single pollutant and multipollutant approaches.
    For the natural gas transmission and storage segment, the estimated
cost effectiveness is $1,050 per ton of methane avoided and $38,000 per
ton of VOC avoided. Using the multipollutant approach, the estimated
cost effectiveness is $530 per ton of methane avoided and $19,000 per
ton of VOC avoided. Transmission and storage facilities do not own the
natural gas; therefore, revenues from reducing the amount of natural
gas emitted/lost was not applied for this segment. While the cost
effectiveness values for VOC are higher than the range of what the EPA
considers to be reasonable for VOC, the cost effectiveness for methane
is within the range of what the EPA considers to be reasonable for
methane using the single pollutant approach.
    Note that the annual costs for these zero-emissions controllers are
based on the annualized capital costs only. While we assume the
maintenance costs for electric controllers is less than the costs for
natural gas-driven controllers, there are costs associated with the use
of electricity that are not incurred for natural gas-driven
controllers. We solicit comments on whether such operational costs
should be included in these estimates, as well as information regarding
these costs.
    The capital costs of solar-powered controllers include the cost of
the batteries, which represents around 7 percent of the total cost of a
solar-powered system. As noted above, the capital cost was annualized
assuming a 15-year lifetime, however batteries for a solar system may
have a shorter life. We are soliciting comment on the life of these
batteries and, if this life is shorter than 15 years, how the costs of
these batteries should be included as a maintenance cost for solar
powered systems.
    The EPA finds that the cost effectiveness for both the low bleed
and zero-emissions options are reasonable for sites in the production
and natural gas transmission and storage segments. The incremental cost
effectiveness in going from the low bleed option to the zero-emissions
option is estimated to be $390 and $340 per ton of additional methane
eliminated for small and medium-sized plants ($1,400 and $1,200 per ton
of VOC), respectively, in the production segment and $640 and $870 per
ton of additional methane eliminated for small and medium-sized plants
($23,000 and $31,500 per ton of VOC), respectively, in the transmission
and storage segment. The incremental cost effectiveness in going from
the low bleed option to the non-emissions option is estimated to be
$260 and $940 per ton of additional methane and VOC avoided,
respectively, for large plants in the production segment and to be $940
and $34,000 per ton of additional methane and VOC avoided,
respectively, for large plants in the transmission and storage segment.
These incremental costs of control do not consider savings for the
production segment. The EPA believes the incremental costs of control
are reasonable for methane and VOC in the production segment, and for
methane in the transmission and storage segment.
    As discussed above, several States and Canadian provinces require
the use of controllers that do not emit methane or VOC throughout the
Oil and Natural Gas Industry, which further demonstrates the
reasonableness of this option and that there are no technical barriers
inhibiting the use of electronic controllers or instrument air systems
at sites in the production and transmission

and storage segments. In 2015, the EPA concluded that, ``[a]t sites
without available electrical service sufficient to power an instrument
air compressor, only gas driven pneumatic devices are technically
feasible in all situations.'' (80 FR 56623, September 18, 2015).
However, since that time, at least two States and two Canadian
provinces have adopted regulations that require zero emitting
controllers at all new sites. The EPA evaluated these rules, and
considers these rules, along with the basic understanding that sources
in these areas are able to comply with the rules, evidence that the
feasibility issues that led to the EPA's previous decision not to
require zero emission controllers in 2015 have been overcome. Further,
the EPA recognizes that industry commenters on the proposed Colorado
rule raised some of the same technical feasibility issues that have
been presented to the EPA in the past, including battery storage
capacity issues, weather-related issues, and mechanical issues related
to vibration.\257\ However, despite these issues being raised, Colorado
finalized the requirement that new controllers have a natural gas bleed
rate of zero at all sites, even though without power. The EPA has
considered new information since 2016 and has now concluded that use of
zero-emission controllers is technically feasible subject to a
particular proposed exception discussed below. The EPA specifically
requests comments on this conclusion. The EPA further solicits comment
on market availability of zero-emission options.
---------------------------------------------------------------------------

    \257\ Pneumatic Controller Task Force Report to the Air Quality
Control Commission. Pneumatic Controller Field Study and
Recommendations. Colorado Department of Public Health and
Environment. Air Pollution Control Division. June 1, 2020.
---------------------------------------------------------------------------

    Secondary impacts from the use of electronic controllers and
instrument air systems are indirect, variable, and dependent on the
electrical supply used to power the compressor or controllers. These
impacts are expected to be minimal. For example, it is estimated that
the electricity needed to operate a compressor is only around 0.4 kW/
hour/controller when the compressor is operating. No other secondary
impacts are expected. The EPA solicits comment on whether owners and
operators would use diesel generators to generate power to run zero-
emissions controllers. The EPA recognizes that diesel generators would
generate formaldehyde emissions and there could be associated secondary
impacts. The EPA does not intend for diesel generators to be used.
    In light of the above, we find that the BSER for reducing methane
and VOC emissions from natural gas-driven pneumatic controllers at
production and transmission and storage sites is the use of zero-
emissions controllers. Therefore, for NSPS OOOOb, we are proposing to
require zero emissions of methane and VOC to the atmosphere for all
pneumatic controllers at production and transmission and storage sites.
    Both NSPS OOOO and NSPS OOOOa allow the use of high-bleed pneumatic
controllers at production sites and natural gas-driven continuous bleed
controllers at natural gas processing plants if it is determined that
the use of such a pneumatic controller affected facility with a bleed
rate greater than the applicable standard is required ``based on
functional needs, including but not limited to response time, safety
and positive actuation.'' See 40 CFR 60.5390(a) and 60.5390a(a). This
exemption was based on comments received on the 2011 proposed NSPS OOOO
rule. There, ``[t]he commenters suggest exemptions that address
situations such as those where the natural gas includes impurities that
could increase the likelihood of fouling a low-bleed pneumatic
controller, such as paraffin or salts; where weather conditions could
degrade pneumatic controller performance; during emergency conditions;
where flow is not sufficient for low-bleed pneumatic controllers; where
electricity is not available; and where engineering judgment recommends
their use to maintain safety, reliability or efficiency.'' (77 FR
49520, August 16, 2012). These reasons to allow for an exemption based
on functional need were based on the inability of a low-bleed
controller to meet the functional requirements of an owner/operator
such that a high-bleed controller would be required in certain
instances. Since we are now proposing that nearly all pneumatic
controllers have a methane and VOC emission rate of zero, subject to
exemption explained below, we do not believe that the reasons cited
above are still applicable. Therefore, the proposed rule does not
include an exemption based on functional need. The EPA is requesting
comment regarding the possibility of situations where functional
requirements/needs dictate that a natural gas-driven controller that
emits any amount of VOC and/or methane be used. For example, are there
situations where a zero-emission controller cannot be used due to
functional needs such that an owner/operator must use a low-bleed
controller or an intermittent controller instead? Comments requesting
such an exemption should include details of the specific functional
need and why all zero-emission controller options are not suitable.
    For many sites, the EPA believes that the most feasible zero-
emission option will be solar-powered controllers. The EPA recognizes
that solar-powered controllers are dependent on sunshine, and in areas
at higher latitudes that undergo prolonged periods without sunshine,
this option could be problematic to implement due to the technical
limitations of solar panels coupled with the practical realities
related to the hours of sunshine received. Therefore, the proposed rule
includes an exemption from the zero-emission requirement for pneumatic
controllers at sites in Alaska that do not have access to power (i.e.,
electricity from the grid or produced using natural gas on-site). Sites
with power have clearly demonstrated that zero emissions from
controllers is achievable, and therefore the EPA is not proposing to
exempt pneumatic controllers at sites in Alaska that have power. The
proposed exemption would only apply to pneumatic controllers at sites
located in Alaska that do not have access to power. In those
situations, affected facilities would not be required to comply with
the zero-emission standard, but instead must use low-bleed pneumatic
controllers (unless a high bleed device is needed for functional
reasons) and must monitor any intermittent controllers in conjunction
with the fugitives monitoring program to ensure they are not venting
when idle. The EPA is soliciting comment on this proposed exemption.
Specifically, the EPA is interested in comments regarding the technical
feasibility of solar panels to power pneumatic controllers in Alaska.
The EPA is also interested in comments regarding whether there are
other locations outside of Alaska where such an exemption may be
warranted. In submitting responses to this request, commenters should
be mindful that two Canadian Provinces, which are north of any U.S.
State other than Alaska, require zero-emitting controllers at all new
sites.
Natural Gas Processing Plants
    Natural gas processing plants typically have higher numbers of
pneumatic controllers than production and transmission and storage
sites. Model plants were also used for this analysis, specifically the
model plants used are the same as those used for the 2011 and 2015 BSER
analyses, and include small, medium, and large sites.

The number of controllers is 15, 63, and 175 for small, medium, and
large model plants, respectively. All controllers at these sites are
assumed to be continuous, but the number of low bleed and high bleed
devices is not specified for the model plants. It was assumed that each
controller emitted 1 tpy methane, as derived from Volume 12 of a 1996
GRI report.\258\ In addition, it was assumed that the portion of
natural gas that is methane is 82.8 percent in the natural gas
processing segment, and the specific VOC to methane ratio assumed was
0.278 pounds VOC per pound methane. For detailed information on the
configuration of these model plants, see the NSPS OOOOb and EG TSD,
which is available in the docket.
---------------------------------------------------------------------------

    \258\ Radian International LLC. Methane Emissions from the
Natural Gas Industry, Vol. 12: Pneumatic Devices. Prepared for the
Gas Research Institute and Environmental Protection Agency. EPA-600/
R-96-080k. June 1996.
---------------------------------------------------------------------------

    For natural gas processing plants, the only option evaluated was
the requirement to use zero-emission controllers. For our analysis, we
examined the use of instrument air, which is the most commonly used
controller technology at natural gas processing plants. For this
analysis, we used cost data from the 2011 NSPS OOOO TSD updated to 2019
dollars. The updated capital costs for an instrument air system at a
natural gas processing plant ranges from $20,000 to $162,000, depending
on the system size. The annualized costs were based on a 7 percent
interest rate and a 10-year equipment life. This equated to an
annualized cost of approximately $13,000 to $96,000 per system. The
emissions reduction associated with the installation of an instrument
air system over natural gas-driven pneumatic controllers ranged from
approximately 15 to 175 tpy methane and 4.2 to 49 tpy VOC per system.
The cost effectiveness is estimated to range from approximately $550 to
$900 per ton methane eliminated $2,000 to $3,100 per ton VOC
eliminated. When considering the costs of saving the natural gas that
would otherwise be emitted, the cost effectiveness improves, with a
cost effectiveness of $370 to $700 per ton of methane eliminated and
$1,300 to $2,500 per ton of VOC eliminated. These cost effectiveness
values are presented on a single pollutant basis, and the cost of
control on a multipollutant basis is 50 percent of these values. These
values are well within the range of what the EPA considers to be
reasonable for methane and VOC using both the single pollutant and
multipollutant approaches.
    The 2012 NSPS OOOO and 2016 NSPS OOOOa require a zero-bleed
emission rate for pneumatic controllers at natural gas processing
plants. Natural gas processing plants have successfully met this
standard for many years now. Further, several State agencies have rules
that include this zero-bleed requirement for controllers at natural gas
processing plants. This is further demonstration of the reasonableness
of a zero methane and VOC emission standard for pneumatic controllers
at natural gas processing plants.
    We find the cost effectiveness of eliminating methane and VOC
emissions using both the single pollutant and multipollutant approaches
to be reasonable.
    Secondary impacts from the use of instrument air systems are
indirect, variable, and dependent on the electrical supply used to
power the compressor. These impacts are expected to be minimal, and no
other secondary impacts are expected.
    In light of the above, we find that the BSER for reducing methane
and VOC emissions from natural gas-driven pneumatic controllers at
natural gas processing plants is the use of zero-emissions controllers.
Therefore, for NSPS OOOOb, we are proposing to require a natural gas
emission rate of zero for all pneumatic controllers at natural gas
processing plants. However, we recognize that there may be technical
limitations in some situations where zero-emissions controllers may not
be feasible, and therefore, we are proposing an allowance for the use
of natural gas-driven pneumatic controllers with an emission rate of
methane and VOC greater than zero where needed due to functional
requirements in this BSER determination. Justification of this
functional need must be provided in an annual report and maintained in
records.
f. Use of Combustion Devices and VRUs
    Another option that could potentially be used to reduce emissions
from pneumatic controllers is to collect the emissions from natural gas
driven continuous bleed controllers and intermittent vent controllers
and route the emissions through a closed vent system to a control
device or process. This option is allowed in some State rules. While
the EPA did not evaluate the cost effectiveness of this option due to a
lack of available information regarding control system costs and
feasibility across sites, we think this option could be cost effective
for owners and operations in certain situations, particularly if the
site already has a control device to which the emissions from
controllers could be routed. As this option could be used to achieve
significant methane and VOC emission reductions (95 percent or
greater), we are soliciting comment on whether this is a control
technique used in the industry to reduce emissions from natural gas-
driven pneumatic controllers. We are also interested in information
related to the performance testing, monitoring, and compliance
requirements associated with these control devices. Finally, we are
interested in ideas as to how this option could potentially fit with
the proposed requirements for pneumatic controllers. For example, if an
owner or operator determines that a natural gas-driven pneumatic
controller is required for functional need reasons, the EPA could
require that emissions be collected and routed to a control device that
achieves 95, or 98, percent control.
2. EG OOOOc
    The EPA evaluated BSER for the control of methane from existing
pneumatic controllers (designated facilities) in all segments in the
Crude Oil and Natural Gas source category covered by the proposed NSPS
OOOOb and translated the degree of emission limitation achievable
through application of the BSER into a proposed presumptive standard
for these facilities that essentially mirrors the proposed NSPS OOOOb.
    First, based on the same criteria and reasoning as explained above,
the EPA is proposing to define the designated facilities in the context
of existing pneumatic controllers as those that commenced construction
on or before November 15, 2021. Based on information available to the
EPA, we did not identify any factors specific to existing sources that
would indicate that the EPA should change these definitions as applied
to existing sources. As such, for purposes of the emission guidelines,
the definition of a designated facility in terms of pneumatic
controllers is each individual natural gas driven pneumatic controller
(continuous bleed or intermittent vent) that vents to the atmosphere.
    Next, the EPA finds that the control options evaluated for new
sources for NSPS OOOOb are appropriate for consideration in the context
of existing sources under the EG OOOOc. The EPA finds no reason to
evaluate different, or additional, control measures in the context of
existing sources because the EPA is unaware of any control measures, or
systems of emission

reduction, for pneumatic controllers that could be used for existing
sources but not for new sources.
    Next, the methane emission reductions expected to be achieved via
application of the control measures identified above for new sources
are also expected to be achieved by application of the same control
measures to existing sources. The EPA finds no reason to believe that
these calculations would differ for existing sources as compared to new
sources because the EPA believes that the baseline emissions of an
uncontrolled source are the same, or very similar, and the efficiency
of the control measures are the same, or very similar, compared to the
analysis above. This is also true with respect to the costs, non-air
environmental impacts, energy impacts, and technical limitations
discussed above for the control options identified.
    For the most part, the information presented above regarding the
costs related to new sources and the NSPS are also applicable for
existing sources. The instance where the EPA estimated a difference in
the costs between a new and existing source was for the retrofit of an
existing production site to use instrument air at sites equipped with
electrical power. While the equipment needed is the same as for new
sites, it may be more difficult to design and install a retrofitted
system. Therefore, the EPA estimates the costs for design and
installation to be twice that of the costs for new systems (from
approximately $32,000 for new systems to approximately $64,000 for
existing systems), resulting in the capital cost of the system being
approximately $127,000 with an annualized cost of approximately
$14,000.
    As noted above, the EPA's analysis for this proposal only examined
the cost of instrument air for the large model plant. The total
elimination of methane emissions (25 tons per year methane for
production sites and 10 tons per year methane for transmission and
storage sites) would be the same for existing sources as presented
above for new sources. Considering the cost difference, the cost
effectiveness for production sites is $560 per ton of methane
eliminated without considering savings, and $365 per ton when
considering savings. For the transmission and storage segment, the cost
effectiveness is $1,400 per ton of methane eliminated. These values are
within the range of what the EPA considers to be reasonable for
methane. Since none of the other factors are different for existing
sources when compared to the information discussed above for new
sources, the EPA concludes that BSER for existing sources and the
proposed presumptive standard for EG OOOOc to be the requirement to use
zero-emission controllers. This proposed EG includes the exemption from
the zero-emission standard for pneumatic controllers in Alaska as
explained above in the context of the proposed NSPS OOOOb.
b. Possible Phase-In Approach for Existing Sources
    The EPA recognizes there could be different compliance time
approaches that could be implemented for existing pneumatic
controllers. The EPA's proposal for compliance times State plans must
include to meet the requirements of the EG can be found in Section
XIV.E. As explained there, the EPA is proposing that State plans must
generally include a 2-year timeline for compliance in the proposed EG,
but is also soliciting comment on the possibility of the EG requiring
different compliance timelines for different emission points.
Specifically, in the context of pneumatic controllers, the EPA is
further soliciting comment on including a phase-in approach in the EG.
The EPA recognizes that a phase-in approach may only be appropriate for
existing sources as new facilities could presumably plan for zero-
emission controllers during construction. A phase-in period could span
a number of years (e.g., 2 years), to allow owners and operators to
prioritize conversion of natural gas-driven controllers at existing
sites based on specific factors (e.g., focus first on sites with onsite
power, sites with highest production, sites with the highest number of
controllers). A phase-in approach could also result in the conversion
of a certain percentage of sites within a given area (e.g., State or
basin). For example, the State of Colorado requires a minimum of 40
percent of sites to be converted after 2 years, with 15 percent in year
1 and 25 percent in year 2. The EPA also recognizes potential
challenges with a phase-in approach, such as difficulties with
enforcement and calculation of the percentage converted due to the
frequency at which sites may change ownership. The EPA solicits comment
on all aspects of the EG requiring State plans to include a phase-in
approach, and whether the agency should consider this type of approach
rather than a single compliance time. The EPA also solicits comment on
cost and feasibility factors that would enter into adopting and
designing a phase-in timeline.
c. Natural Gas Processing Plants
    The information presented above regarding the emissions, emission
reduction options and their effectiveness, costs, and other factors
related to new natural gas processing plants and the NSPS are also
applicable for existing sources. Therefore, the EPA concludes that BSER
for existing sources and the EG OOOOc for natural gas processing plants
is the requirement to use zero-emission controllers.

D. Proposed Standards for Well Liquids Unloading Operations

1. NSPS OOOOb
a. Background
    In the 2015 NSPS OOOOa proposal (80 FR 56614-56615, September 18,
2015), the EPA stated that based on available information and input
received from stakeholders on the 2014 Oil and Natural Gas Sector
Liquids Unloading Processes review document,\259\ sufficient
information was not available to propose a standard for liquids
unloading.
---------------------------------------------------------------------------

    \259\ U.S. Environmental Protection Agency. Oil and Natural Gas
Sector Liquids Unloading Processes. Report for Oil and Natural Gas
Sector. Liquids Unloading Processes Review Panel. April 2014.
---------------------------------------------------------------------------

    At that time, the EPA requested comment on technologies and
techniques that could be applied to new gas wells to reduce emissions
from liquids unloading events in the future. In the 2016 NSPS OOOOa
final rule (81 FR 35846, June 3, 2016), the EPA stated that, although
the EPA received valuable information from the public comment process,
the information was not sufficient to finalize a national standard
representing BSER for liquids unloading at that time.
    For this proposal, the EPA conducted a review of available
information, including new information that became available after the
2016 NSPS OOOOa rulemaking. As a result of this review, the EPA is
proposing a zero VOC and methane emission standard under NSPS OOOOb for
liquid unloading, which can be achieved using non-venting liquids
unloading methods. In the event that it is technically infeasible or
not safe to perform liquids unloading with zero emissions, the EPA is
proposing to require that an owner or operator establish and follow
BMPs to minimize methane and VOC emissions during liquids unloading
events to the extent possible. These proposed requirements apply to
each well liquids unloading event.
    An overall description of liquids unloading, the definition of a
modification, the definition of affected facility, our BSER analysis,
and the proposed format of the standard are presented below.

b. Description
    In new gas wells, there is generally sufficient reservoir pressure/
gas velocity to facilitate the flow of water and hydrocarbon liquids
through the well head and to the separator to the surface along with
produced gas. In mature gas wells, the accumulation of liquids in the
wellbore can occur when the bottom well pressure/gas velocity
approaches the average reservoir pressure (i.e., volumetric average
fluid pressure within the reservoir across the areal extent of the
reservoir boundaries).\260\ This accumulation of liquids can impede and
sometimes halt gas production. When the accumulation of liquids results
in the slowing or cessation of gas production (i.e., liquids loading),
removal of fluids (i.e., liquids unloading) is required in order to
maintain production. These gas wells therefore often need to remove or
``unload'' the accumulated liquids so that gas production is not
inhibited.
---------------------------------------------------------------------------

    \260\ Gordon Smith Review. Oil & Natural Gas Sector Liquids
Unloading Processes. Submitted: June 16, 2014. Pg. 4.
---------------------------------------------------------------------------

    The 2019 U.S. GHGI estimates almost 175,800 metric tpy of methane
emissions from liquids unloading events for natural gas systems.
Specifically, this includes almost 175,800 metric tpy from natural gas
production, 98,900 metric tpy of which is from liquids unloading events
that use a plunger lift, and 76,900 metric tpy from liquids unloading
events that do not use a plunger lift. The overall total represents 3
percent of the total methane emissions estimated from natural gas
systems.
    In addition to the GHGI information, we also examined the
information submitted under GHGRP subpart W. Specifically, we examined
the GHGRP subpart W liquids unloading emissions data reported for
Reporting Years 2015 to 2019. The liquids unloading emissions reported
under GHGRP subpart W include emissions from venting wells, including
those wells that vent during events that use a plunger lift and wells
that vent during events that do not use a plunger lift. The information
reported shows that methane emissions from liquids unloading for a well
range from 0 to over 1,000 metric tons (1,100 tons) per year. While the
single well with liquids unloading emissions of 1,100 tpy appears to be
an outlier, there were over 65 subbasins with reported average liquids
unloading emissions of 50 tpy or greater per well when disaggregating
data by year and calculation method. There were over 1,000 wells
reporting in these subbasins. In addition, there were almost 300 sub-
basins with reported average liquids unloading methane emissions of 10
tpy or greater per well. There were almost 8,000 wells reporting in
these subbasins.
    Another source of information reviewed related to emissions
information from liquids unloading was a study published in 2015 by
Allen, et al. (University of Texas (UT) Study).\261\ \262\ The UT Study
collected monitoring data across regions of the U.S. Among other
findings in this report, for wells that vent more than 100 times per
year, the average methane emissions per well per year were 27 metric
tpy, with 95 percent confidence bounds of 10 to 50 Mg/yr (based on the
confidence bounds in the emissions per event). The monitoring data
shows that methane emissions from liquids unloading for a well range
from 1 to 19,500 Mscf per year, or 0.02 to 406 tpy.\263\ As indicated
by the UT study \264\ emissions information, a small fraction of wells
account for a large fraction of liquids unloading emissions.
---------------------------------------------------------------------------

    \261\ D.T. Allen, D.W. Sullivan, D. Zavala-Araiza, A.P. Pacsi,
M. Harrison, K. Keen, M.P. Fraser, A. Daniel Hill, B.K. Lamb, R.F.
Sawyer, J.H. Seinfeld, Methane emissions from process equipment at
natural gas production sites in the United States: Liquid
unloadings. Environ. Sci. Technol. 49, 641-648 (2015). doi:10.1021/
es504016r Medline. (UT Study).
    \262\ D.T. Allen, D.W. Sullivan, D. Zavala-Araiza, A.P. Pacsi,
M. Harrison, K. Keen, M.P. Fraser, A. Daniel Hill, B.K. Lamb, R.F.
Sawyer, J.H. Seinfeld. Methane Emissions from Process Equipment at
Natural Gas Production Sites in the United States: Liquid
Unloadings--Supporting Information; (UT Study--SI). Table S5-1, pg.
21.
    \263\ UT Study--SI. Tables S3-1 to S3-3, pgs. 11-14.
    \264\ UT Study. pg. 642.
---------------------------------------------------------------------------

c. Modification
    As noted in section XII.D.1.b, new wells typically do not require
liquids unloading until the point that the accumulation of liquids
impedes or even stops gas production. At that point, the well must be
unloaded of liquids to improve the gas flow. One method to accomplish
this involves the intentional manual venting of the well to the
atmosphere to improve gas flow. This is done using various techniques.
One common manual unloading technique diverts the well's flow,
bypassing the production separator to a lower pressure source, such as
an atmospheric pressure tank. Under this scenario, venting to the
atmospheric tank occurs because the separator operates at a higher
pressure than the atmospheric tank and the well will temporarily flow
to the atmospheric tank (which has a lower pressure than the
pressurized separator). Natural gas is released through the tank vent
to the atmosphere until liquids are unloaded and the flow diverted back
to the separator. As discussed later in this section, the EPA has
received feedback that there are technical difficulties with flaring
vented emissions as a result of the intermittent and surging flow
characteristic of venting for liquids unloading, and the changing
velocities during an unloading event.
    Since each unloading event constitutes a physical or operational
change to the well that has the potential to increase emissions, the
EPA is proposing to determine each event of liquids unloading
constitutes a modification that makes a well an affected facility
subject to the NSPS. See 40 CFR 60.14(a) (``any physical or operational
change to an existing facility which results in an increase in the
emission rate to the atmosphere of any pollutant to which a standard
applies shall be considered a modification within the meaning of
section 111 of the Act''). The EPA solicits comment on this
determination.
d. Definition of Affected Facility
    Given that we have proposed to determine that every liquids
unloading event is a modification, the next step is to define the
affected facility. The EPA recognizes that methods are commonly
employed that significantly reduce, or even eliminate, emissions from
liquids unloading. Therefore, the EPA is co-proposing two options on
how a modified well due to a liquids unloading event would be covered
under the rule.
    Under the first option, the affected facility subject to the
requirements of NSPS OOOOb would be defined as every well that
undergoes liquids unloading after the effective date of the final rule.
Under this scenario, a well that undergoes liquids unloading is an
affected facility regardless of whether the liquids unloading approach
used results in venting to the atmosphere. This option posits that
techniques employed to unload liquids that do not increase emissions
are not to be considered in whether the unloading event is an affected
facility or not, since the liquids unloading event in their absence
could result in an emissions increase. This is somewhat analogous to a
physical change to an existing storage vessel that resulted in the
ability to increase throughput, and thus emissions. This physical
change could result in an increase in emissions even if emissions were
captured and routed back to a process such that the level of pollutant
actually emitted to the atmosphere did not change. Under this scenario,
the EPA could request and obtain compliance and enforcement information
on non-venting liquids

unloading event methods commonly employed (simple records and reporting
requirements), as well as venting liquids unloading events.
    Under the second option, the affected facility would be defined as
every well that undergoes liquids unloading using a method that is not
designed to totally eliminate venting (i.e., that results in emissions
to the atmosphere). Under this scenario, if an owner or operator
employs a method to unload liquids that does not vent to the
atmosphere, the liquids unloading event would not constitute an
increase in emissions and therefore, the well would not be an affected
facility. As such, the first liquids unloading event that vents to the
atmosphere after the effective date of the final rule, would be an
affected facility subject to the requirements of NSPS OOOOb. This
option could create an enforcement information and compliance gap.
Specifically, the EPA would not be able to obtain compliance assurance
information on liquids unloading events and emissions/methods and there
could be a decreased incentive for owners or operators to ensure that
no unexpected emission episodes occur when a method designed to be non-
venting is used.
    The EPA solicits comments on the two affected facility definition
options being co-proposed. Specifically, we request comment on whether
there are implementation and/or compliance assurance concerns that
arise with applying either of the co-proposed options. In addition, we
request comment on if there are any appropriate exemptions for
operations that may be unlikely to result in emissions, such as
wellheads that are not operating under positive pressure.
e. 2021 BSER Analysis
    The choice of what liquids unloading technique to employ is based
on an operator well-by-well and reservoir-by-reservoir engineering
analysis. Because liquids unloading operations entail a number of
complex science and engineering considerations that can vary across
well sites, there is no single technological solution or technique that
is optimal for liquids unloading at all wells. Rather, a large number
of differing technologies, techniques and practices (i.e., ``methods'')
have been developed to address the unique characteristics of individual
wells so as to manage liquids and maintain production. These methods
include, but are not limited to, manual unloading, velocity tubing or
velocity strings, beam or rod pumps, electric submergence pumps,
intermittent unloading, gas lift (e.g., use of a plunger lift), foam
agents, wellhead compression, and routing the gas to a sales line or
back to a process.
    Selecting a particular method to meet a particular well's unloading
needs must be based on a production engineering decision that is
designed to remove the barriers to production. The situation is further
complicated as the best method for a particular well can change over
time. At the onset of liquids loading, techniques that rely on the
reservoir energy are typically used. Eventually a well's reservoir
energy is not sufficient to remove the liquids from the well and it is
necessary to add energy to the well to continue production.
    In the 2016 NSPS OOOOa final rule preamble, the EPA acknowledged
that operators must select the technique to perform liquids unloading
operations based on the conditions of the well each time production is
impaired. During the development of the 2016 NSPS OOOOa rule, the EPA
considered subcategorization based on the potential for well site
liquids unloading emissions but determined that the differences in
liquids unloading events (with respect to both frequency and emissions
level) are due to specific conditions of a given well at the time the
operator determines that well production is impaired such that
unloading must be done. Since owners and operators must select the
technique to perform an unloading operation based on those conditions,
and because well conditions change over time, each iteration of
unloading may require repeating a single technique or attempting a
different technique that may not have been appropriate under prior
conditions. As noted above, we recognized that the choice of method to
unload liquids from a well needs to be a production engineering
decision based on the characteristics of the well at the time of the
unloading, and owners and operators need the flexibility to select a
method that is effective and can be safely employed. No information has
become available since 2016 that leads the EPA to reach a different
conclusion regarding subcategorization of wells for the purpose of
developing standards to address liquids unloading emissions. Further,
the EPA acknowledges the need for owners and operators to have the
flexibility to select the most appropriate method(s) and recognize that
any standard must not impede this flexibility.
    Many methods used for liquids unloading do not result in any
venting to the atmosphere, provided that the method is properly
executed. High-level summaries of a few of these methods are provided
below.\265\
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    \265\ ``Oil and Natural Gas Sector Liquids Unloading
Processes''. Report for Oil and Natural Gas Sector Liquids Unloading
Processes Review Panel. Prepared by U.S. EPA OAQPS. April 2014.
    \265\ 80 FR 56593, September 18, 2015.
---------------------------------------------------------------------------

    A commonly used method employed in the field is the use of a
plunger lift system. While plunger lift systems often are used in a way
to minimize emissions, under certain conditions they can be operated to
unload liquids in a manner that eliminates the need to vent to the
atmosphere. Plunger lifts use the well's own energy (gas/pressure) to
drive a piston or plunger that travels the length of the tubing in
order to push accumulated liquids in the tubing to the surface.
Specific criteria regarding well pressure and liquid to gas ratio can
affect applicability. Candidate wells for plunger lift systems
generally do not have adequate downhole pressure for the well to flow
freely into a gas gathering system. Optimized plunger lift systems
(e.g., with smart well automation) can decrease the amount of gas
vented by up to and greater than 90 percent, and in some instances can
reduce the need for venting due to overloading. Plunger lift costs
range from $1,900 to $20,000.\266\ Adding smart automation can cost
anywhere between an estimated $4,700 to $18,000 depending on the
complexity of the well. Natural Gas STAR estimates that the annual cost
savings from avoided emissions from the use of an automated system
ranges anywhere between $2,400 and $10,241 per year.\267\
---------------------------------------------------------------------------

    \266\ U.S. Environmental Protection Agency. Installing Plunger
Lift Systems in Gas Wells. Office of Air and Radiation: Natural Gas
Star Program. Washington, DC. 2006.
    \267\ U.S. Environmental Protection Agency. (U.S. EPA) 2011.
Options for Removing Accumulated Fluid and Improving Flow in Gas
Wells. Office of Air and Radiation: Natural Gas Star Program.
Washington, DC. 2011. pg. 1.
---------------------------------------------------------------------------

    Other artificial lifts (e.g., rod pumps, beam lift pumps, pumpjacks
and downhole separator pumps) are typically used when there is
inadequate pressure to use a plunger lift, and the only means of
liquids unloading to keep gas flowing is downhole pump technology.
Artificial lifts can be operated in a manner that produces no
emissions. The use of an artificial lift requires access to a power
source. The capital and installation costs (including location
preparation, well clean out, artificial lift equipment and pumping
unit) is estimated to be $41,000 to $62,000/well, with the average cost
of a pumping unit being between $17,000 to $27,000. \268\
---------------------------------------------------------------------------

    \268\ U.S. EPA, 2011. pg. 9.

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

    Velocity tubing is smaller diameter production tubing that reduces
the cross-sectional area of flow, increasing the flow velocity and
achieving liquids removal without blowing emissions to the atmosphere.
Generally, a gas flow velocity of 1,000 feet per minute (fpm) is
necessary to remove wellbore liquids. Velocity tubing strings are
appropriate for low volume natural gas wells upon initial completion or
near the end of their productive lives with relatively small liquids
production and higher reservoir pressure. Candidate wells include
marginal gas wells producing less than 60 Mcfd. Similarly, coil tubing
can also be used in wells with lower velocity gas production (i.e.,
seamed coiled tubing may provide better lift due to elimination of
turbulence in the flow stream). The proper use of velocity tubing is
considered to be a ``no emissions'' solution. It is also low
maintenance and effective for low volumes lifted. Velocity lifting can
be deployed in combination with foaming agents (discussed below). The
capital and installation costs are estimated to range anywhere from
$7,000 to $64,000 per well.\269\ Installation requires a well workover
rig to remove existing production tubing and placement of the smaller
diameter tubing string in the well.
---------------------------------------------------------------------------

    \269\ U.S. EPA, 2011. pg. 8.
---------------------------------------------------------------------------

    The use of foaming agents (soap, surfactants) as a method to unload
liquids is implemented by the injection of foaming agents in the
casing/tubing annulus by a chemical pump on a timer basis. The gas
bubbling of the soap-water solution creates gas-water foam which is
more easily lifted to the surface for water removal. This, like the use
of artificial lifts, requires power to run the surface injection pump.
Additionally, foaming agents work best if the fluid in the well is at
least 50 percent water and are not effective for natural gas liquids or
liquid hydrocarbons. This method requires that the soap supply be
monitored. If the well is still unable to unload fluid, smaller tubing
may be needed to help lift the fluids. Foaming agents and velocity
tubing are reported as possibly being more effective when used in
combination. No equipment is required in shallow wells. In deep wells,
a surfactant injection system requires the installation of surface
equipment and regular monitoring. Foaming agents are reported as being
low cost ``no emissions'' solution. The capital and startup costs to
install soap launchers and velocity tubing is estimated to range
between $7,500 and $67,880, with the monthly cost of the foaming agent
is approximately $500 per well or approximately $6,000 per year.\270\
---------------------------------------------------------------------------

    \270\ U.S. EPA. 2011. Pg. 8.
---------------------------------------------------------------------------

    These are just a few examples of demonstrated methods that are
being used in the industry to unload accumulated liquids that impair
production, that can be implemented without venting and, thus, without
emissions. As stressed earlier, the selection of a specific method must
be made based on well-specific characteristics and conditions.
    Since GHGRP subpart W only requires reporting of liquids unloading
events that resulted in venting of methane, no information is submitted
regarding those wells that utilize a non-venting method. The EPA is
also not aware of information that specifies the total number of wells
that need to undergo liquids unloading. A 2012 report sponsored by the
API and American Natural Gas Alliance (ANGA) \271\ provided more
definitive insight into the number of wells that use non-venting
liquids unloading methods. This report indicated that an estimated 21.1
percent of plunger equipped wells vent, and 9.3 percent of non-plunger
equipped wells vent. The EPA interprets this to mean that almost 80
percent of plunger-equipped wells, and over 90 percent of non-plunger-
equipped wells perform liquids unloading and utilize non-venting
methods.
---------------------------------------------------------------------------

    \271\ Shires, T. URS Corporation and Lev-On, M. the LEVON Group.
Characterizing Pivotal Sources of Methane Emissions from Natural Gas
Production. Summary and Analysis of API and ANGA Survey Responses.
Prepared for the American Petroleum Institute and the American
Natural Gas Alliance. September 21, 2012.
---------------------------------------------------------------------------

    As noted above, there is a tremendous range in the emissions from
liquids unloading reported for individual wells. Further, as discussed
above, the costs for the non-venting methods range considerably. Also,
as discussed above, we have determined that the myriad of possible
reservoir conditions and unloading methods do not lend to any
reasonable subcategorization of the industry for which representative
wells could be designed. Therefore, it is not possible to develop a
``model'' well, or even a series of model wells, that can be used to
conduct the type of analysis frequently performed for BSER
determinations that calculates a cost per ton of emissions reduced (or
in this case eliminated).
    Based on the highest costs included in the cost examples provided
above, the cost effectiveness of a non-venting method would be
considered reasonable for wells with annual methane emissions from
liquids unloading of 16 tpy or greater, or VOC emissions of 3 tpy or
greater. This upper range is based on the cost of the combination of
velocity tubing and soap launchers. The upper range of the capital cost
cited above was $67,800. Annualizing this capital cost at a 7 percent
interest rate over 10 years, and adding in the $6,000 per year foaming
agent cost, results in a total annual cost of $15,600. Given the total
elimination of emissions, the cost effectiveness for a well with 16 tpy
methane emissions would be $980 per ton of methane reduced, which is a
level that the EPA considers reasonable for methane. Similarly, for
VOC, the cost effectiveness for a well with 3 tpy VOC emissions would
be $5,200 per ton of VOC reduced. This is also a level that the EPA
considers reasonable. Given the range of costs, it could be reasonable
even for some wells with annual liquids unloading methane emissions as
low as 2.5 tpy ($400 per ton of methane reduced (velocity tubing)), or
VOC emissions as low as 0.2 tpy ($5,000 per ton of VOC reduced
(velocity tubing)). Based on the GHGRP subpart W data for the years
2015 through 2019, around 50 percent of the wells that performed
liquids unloading and reported emissions reported emissions higher than
these levels.
    While owners and operators must select a liquids unloading method
that is applicable for the well-specific conditions, they have the
choice of many methods that can be used to eliminate venting/emissions
from liquids unloading events. While we do not have information to
calculate the specific percentage of total wells undergoing liquids
unloading that use non-venting methods, available information suggests
that a majority of wells that undergo liquids unloading do not vent.
The EPA solicits information on the number (or percent) of liquids
unloading events that vent to the atmosphere versus do not vent to the
atmosphere under normal conditions and whether there are technical
obstacles (other than costs) that would not allow liquids unloading to
be performed without venting.
    CAA section 111(a) requires that the standard reflect the BSER that
the EPA determines ``has been adequately demonstrated.'' An
``adequately demonstrated system'' is one that ``has been shown to be
reasonably reliable, reasonably efficient, and which can reasonably be
expected to serve the interests of pollution control without becoming
exorbitantly costly in an economic or environmental way.'' Essex Chem.,
486 F.2d at 433. For the reasons explained above and further elaborated
below, the EPA considers non-venting methods such as those described
above

to have been adequately demonstrated as the BSER for liquids unloading
events. The complete elimination of emissions from liquids unloading
with these non-venting methods have been adequately demonstrated in
practice. The EPA notes that as part of decisions regarding liquids
unloading, one goal of owners and operators is to eliminate venting to
prevent the loss of product (natural gas) that could be routed to the
sales line. States currently encourage the use of methods to eliminate
emissions unless venting of emissions is necessary for safety reasons
or when it is technically infeasible to not vent to unload liquids from
the wellbore. For example, Pennsylvania has a general plan approval
and/or general operating permit application (BAQ-GPA/GP-5A) that
specifies that an owner or operator that conducts wellbore liquids
unloading operations shall use best management practices including, but
not limited to, plunger lift systems, soaping, swabbing, unless venting
is necessary for safety to mitigate emissions during liquids unloading
activities (Best Available Technology (BAT) Compliance Requirements
under Section L of the General Permit).
    As discussed previously, a majority of wells already conduct
liquids unloading operations without venting to the atmosphere. Also,
as discussed previously, there are multiple non-venting liquids
unloading methods that an owner and operator can select based on a
well's specific characteristics and conditions. Our evaluation of costs
shows that there are non-venting liquids unloading methods that could
be employed to unload liquids that are reasonable given a wide range of
emission levels. Finally, there are no negative secondary environmental
impacts that would result from the implementation of methods that would
eliminate venting of methane and VOC emissions to the atmosphere. In
light of the above, the EPA considers non-venting liquids unloading
methods to have been adequately demonstrated to represent BSER for
reducing methane and VOC emissions during liquids unloading events.
    An ``adequately demonstrated'' system needs not be one that can
achieve the standard ``at all times and under all circumstances.''
Essex Chem., 486 F.2d at 433. That said, as discussed below, the EPA
recognizes that there may be reasons that a non-venting method is
infeasible for a particular well, and the proposed rule would allow for
the use of BMPs to reduce the emissions to the maximum extent possible.
    The EPA recognizes that there may be safety and technical reasons
why venting to the atmosphere is necessary to unload liquids. In
addition, it is possible that a well production engineer has already
explored non-venting options and determined that there was no feasible
option due to its specific characteristics and conditions. For
scenarios where a liquids unloading method employed requires venting to
the atmosphere, the EPA evaluated requiring BMPs that would minimize
venting to the maximum extent possible. There are several States that
require the development and implementation of BMPs that minimize
emissions from liquids unloading events that vent. For example,
Colorado requires specified BMPs to eliminate or minimize vented
emissions from liquids unloading. The rule requires that all attempts
be made to unload liquids without venting unless venting is required
for safety reasons. If venting is required, the rule requires that
owners and operators be on site and that they ensure that any venting
is limited to the maximum extent practicable. Specific BMPs evaluated
are based on State rules that require BMPs to minimize emissions during
liquids unloading events are to require operators to monitor manual
liquids unloading events onsite and to follow procedures that minimize
the need to vent emissions during an event. This includes following
specific steps that create a differential pressure to minimize the need
to vent a well to unload liquids and reducing wellbore pressure as much
as possible prior to opening to atmosphere via storage tank, unloading
through the separator where feasible, and requiring closure of all well
head vents to the atmosphere and return of the well to production as
soon as practicable. For example, where a plunger lift is used, the
plunger lift can be operated so that the plunger returns to the top and
the liquids and gas flow to the separator. Under this scenario, venting
of the gas can be minimized and the gas that flows through the
separator can be routed to sales. In situations where production
engineers select an unloading technique that results or has the
potential to vent emissions to the atmosphere, owners and operators
already often implement BMPs in order to increase gas sales and reduce
emissions and waste during these (often manual) liquids unloading
activities. We performed a cost and impacts evaluation of the use of
BMPs to reduce emissions from liquids unloading. This evaluation is
provided in the NSPS OOOOb and EG TSD for this rulemaking.
    Another potential method for reducing emissions from liquids
unloading is to capture the vented gas from an unloading event and
route it to a control device. At the time the Crude Oil and Natural Gas
Sector Liquids Unloading Processes draft review document was submitted
to reviewers, the EPA noted that, although the EPA was not aware of any
specific instances where combustion devices/flares were used to control
emissions vented from unloading events, the EPA requested information
on the technical feasibility of flaring as an emissions control option
for liquids unloading events. Feedback received from reviewers
indicated that there are technical reasons that flaring during liquids
unloading is not a feasible option.\272\ Reviewers emphasized that, in
order to flare gas during liquids unloading, the liquids would need to
be separated from the well stream, and the intermittent and surging
flow characteristics of venting for liquids unloading, changing
velocities during an unloading, and flare ignition considerations for a
sporadically used flare (i.e., would require either a continuous pilot
or electronic igniter) would make use of a flare technically and
financially infeasible.273 274 The reviewers indicated that
separating the liquids from the well stream would require the well
stream to flow through a separator with sufficient backpressure to
separate the gas and liquids. One reviewer noted that after separating
the liquids from the well stream the gas would then be piped to flare
system, where the backpressure needed to operate the separator would
affect the performance of a plunger lift system (if used). Based on
feedback received on the technical and cost feasibility of using a
flare to control vented emissions from liquids unloading events
indicating that a flare cannot be used in all situations, we did not
consider this option any further in this proposal. However, the EPA is
soliciting comments about the use of control devices to reduce
emissions from liquids unloading events. Specifically, we request
information on the types of wells and unloading events for which
routing to control is feasible

and effective, the level of emission reduction achieved, and the
testing and monitoring requirements that apply.
---------------------------------------------------------------------------

    \272\ U.S. Environmental Protection Agency. Oil and Natural Gas
Sector Liquids Unloading Processes. Report for Crude Oil and Natural
Gas Sector. Liquids Unloading Processes Review Panel. April 2014.
    \273\ Gordon Smith Review. Oil and Natural Gas Sector Liquids
Unloading Processes. Review Submitted: June 16, 2014. Pg. 31.
    \274\ Jim Bolander, P.E., Senior Vice President, Southwestern
Energy (SWN). Review Submitted: April 2014. Pg. 8.
---------------------------------------------------------------------------

    A similar potential method is to capture the vented gas from an
unloading event and route it to the sales line or back to a process.
This could potentially represent another method that results in zero
emissions. While this is not a mitigation option that has been
specifically mentioned for emissions from liquids unloading, it is a
common option for other emission sources in the oil and natural gas
production segment. The EPA is soliciting comments about the option to
collect and route emissions back to the sales line or to a process.
Specifically, we request information on the types of wells and
unloading events for which this option is feasible (if any). If this
option is feasible, we also request information on the specifics of the
equipment and processes needed to accomplish this, as well as the
costs.
    In conclusion, the EPA evaluated several options and identified the
use of non-venting methods as the BSER for reducing methane and VOC
emissions during liquids unloading events. However, the EPA recognizes
there could be situations where it is infeasible to utilize a non-
venting method. Therefore, the EPA proposes to allow for the
development and implementation of BMPs to reduce emissions to the
extent possible during liquids unloading where it is infeasible to
utilize a non-venting method.
f. Format of the Standard
    As discussed under section XII.D.1.d of this preamble, the EPA is
co-proposing two regulatory approaches to implement the BSER
determination.
    For Option 1, the affected facility would be defined as every well
that undergoes liquids unloading. This would mean that wells that
utilize a non-venting method for liquids unloading would be affected
facilities and subject to certain reporting and recordkeeping
requirements. These requirements would include records of the number of
unloadings that occur and the method used. A summary of this
information would also be required to be reported in the annual report.
The EPA also recognizes that under some circumstances venting could
occur when a selected liquids unloading method that is designed to not
vent to the atmosphere is not properly applied (e.g., a technology
malfunction or operator error). Under the proposed rule Option 1 owners
and operators in this situation would be required to record and report
these instances, as well as document and report the length of venting
and what actions were taken to minimize venting to the maximum extent
possible.
    For wells that utilize methods that vent to the atmosphere, the
proposed rule would require that they: (1) Document why it is
infeasible to utilize a non-venting method due to technical, safety, or
economic reasons; (2) develop BMPs that ensure that emissions during
liquids unloading are minimized; (3) follow the BMPs during each
liquids unloading event and maintain records demonstrating they were
followed; (4) report the number of liquids unloading events in an
annual report, as well as the unloading events when the BMP was not
followed. While the proposed rule would not dictate the specific
practices that must be included, it would specify minimum acceptance
criteria required for the types and nature of the practices. Examples
of the types and nature of the required practice elements for BMP are
provided in section XII.D.1.e, such as those contained in Colorado's
rule. The EPA is specifically requesting comment on the minimum
elements that should be required in BMPs and the specificity that the
proposed rule should include regarding these elements.
    An advantage of this regulatory option is that it would provide
information to the EPA on the number of liquids unloading events that
occur and the types of unloading methods used. Having this important
information would enhance the EPA, the industry, and the public's
knowledge of emissions from liquids unloading. Option 1 would also
provide incentive for owners and operators to ensure that non-venting
methods are applied as they are designed such that unexpected emissions
do not occur as the result of technology malfunctions or operator
error. However, it would result in some recordkeeping and reporting
burden for wells that already use or plan to use non-venting methods
that would not be incurred under Option 2.
    For Option 2, the affected facility would be defined as every well
that undergoes liquids unloading using a method that is not designed to
eliminate venting. The significant difference in this option is that
wells that utilize non-venting methods would not be affected facilities
that are subject to the NSPS OOOOb. Therefore, they would not have
requirements other than to maintain records to demonstrate that they
used non-venting liquids unloading methods. The requirements for wells
that use methods that vent would be the same as described above under
Option 1.
    The EPA believes that this option would provide additional
incentive for owners and operators to seek ways to overcome potential
infeasibility issues to ensure that their wells are not affected
facilities and subject to reporting and recordkeeping requirements.
This would ultimately result in lower emissions. However, this would
not provide the EPA information to have a more comprehensive
understanding of emissions and emission reduction methods from liquids
unloading. It would also not provide incentive for owners and operators
to ensure that no unexpected emission episodes occur when a method
designed to be non-venting is used.
2. EG OOOOc
    As described above, the EPA is proposing that each unloading event
represents a modification, which will make the well subject to new
source standards under NSPS. Therefore, existing wells that undergo
liquids unloading would become subject to NSPS OOOOb. This will mean
that there will never be a well that undergoes liquids unloading that
will be ``existing'' for purposes of CAA section 111(d). Therefore,
there is no need for emissions guidelines or an associated presumptive
standard under EG OOOOc for liquids unloading operations.

E. Proposed Standards for Reciprocating Compressors

1. NSPS OOOOb
a. Background
    The 2012 NSPS OOOO and the 2016 NSPS OOOOa applied to each
individual new or reconstructed reciprocating compressor, except for
those compressors located at a well site, or those located at an
adjacent well site and servicing more than one well site. The 2016 NSPS
OOOOa required the reduction of methane and VOC emissions from new,
reconstructed, or modified reciprocating compressors by replacing rod
packing systems within 26,000 hours or 36 months of operation,
regardless of the condition of the rod packing. As an alternative, the
2016 NSPS OOOOa allowed owners or operators to collect the emissions
from the rod packing using a rod packing emissions collection system
that operates under negative pressure and route the rod packing
emissions to a process through a closed vent system.
    In determining BSER for reciprocating compressors in 2016, the EPA
determined that the previous determination for NSPS OOOO conducted in
2011/2012 still represented BSER in 2016. In the 2012 determination the
EPA first concluded that the piston rod packing wear

produces fugitive emissions that cannot be captured and conveyed to a
control device, and that an operational standard pursuant to section
111(h) of the CAA was appropriate. The EPA conducted analyses of the
costs and emission reductions of the replacement of rod packing every 3
years or 26,000 hours of operation and determined that the costs per
ton of emissions reduced were reasonable for the industry, with the
exception of compressors at well sites. Based on the 2011 BSER
analysis, requiring replacement of rod packing every 3 years or 26,000
hours of operation for well site reciprocating compressors was not
considered cost effective (almost $57,000 per ton of VOC reduced).\275\
No other more stringent control options were evaluated at that time.
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    \275\ 2011 NSPS OOOO TSD. pg. 6-17.
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    For this review of the NSPS, the EPA focused on these control
options which were previously assessed for the 2012 NSPS OOOO and the
2016 NSPS OOOOa. In addition, we evaluated an option that would require
annual monitoring to determine if the rod packing needed to be
replaced. This option is in contrast to the option where replacement is
required on a fixed (e.g., 3 year) schedule. For this review, BSER was
evaluated for reciprocating compressors at gathering and boosting
stations in the production segment (considered to be representative of
emissions from reciprocating compressors at centralized production
facilities), at natural gas processing plants, and at sites in the
transmission and storage segment. In 2012 and in 2016, the EPA
determined that the cost effectiveness of replacement of the rod
packing based on the fixed 3-year (or 26,000 hours) schedule was
unreasonable for reciprocating compressors located at the well site
(discussed below). No new information has become available to change
this determination. Therefore, we did not include reciprocating
compressors located at well sites in our evaluation of regulatory
options.
    However, as discussed in section XI.L (Centralized Production
Facilities) of this preamble, the EPA believes the definition of ``well
site'' in NSPS OOOOa may cause confusion regarding whether
reciprocating compressors located at centralized production facilities
are also exempt from the standards. The EPA is proposing a new
definition for a ``centralized production facility''. The EPA is
proposing to define centralized production facilities separately from
well sites because the number and size of equipment, particularly
reciprocating and centrifugal compressors, is larger than standalone
well sites which would not be included in the proposed definition of
``centralized production facilities''. This proposal is necessary in
the context of reciprocating compressors to distinguish between these
compressors at centralized production facilities where the EPA has
determined that the standard should apply, and compressors at
standalone well sites where the EPA has determined that the standard
should not apply. In our current analysis, described below, we consider
the reciprocating compressor gathering and boosting segment emission
factor as being representative of reciprocating compressor emissions
located at centralized production facilities. As such, the EPA is
proposing that reciprocating compressors located at centralized
production facilities would be subject to the standards in NSPS OOOOb
and the EG in subpart OOOOc, but reciprocating compressors at well
sites (standalone well sites) would not.
    As a result of the EPA's review of NSPS OOOOa, we are proposing
that BSER is to replace the rod packing when, based on annual flow rate
measurements, there are indications that the rod packing is beginning
to wear to the point where there is an increased rate of natural gas
escaping around the packing to unacceptable levels. We are proposing
that if annual flow rate monitoring indicates a flow rate for any
individual cylinder as exceeding 2 scfm, an owner or operator would be
required to replace the rod packing.
b. Description
    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 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.
    As discussed previously, emissions from a reciprocating compressor
occur when, over time, during operation of the compressor, the rings
that form a seal around the piston rod that prevents gas from escaping
become worn. This results in increasing emissions from the compression
cylinder. Based on the 2021 GHGI,\276\ the methane emissions from
reciprocating compressors in 2019 represented 14 percent of the total
methane emissions from natural gas systems in the Crude Oil and Natural
Gas Industry sector. For segments where the GHGI included a breakdown
of methane emissions for reciprocating compressors, the reported
emissions were 309,500 metric tons for the gathering and boosting
segment, 46,700 metric tons for the processing segment, 406,500 metric
tons for the transmission segment, and 103,200 metric tons for the
storage segment.
---------------------------------------------------------------------------

    \276\ U.S. Environmental Protection Agency. Inventory of U.S.
Greenhouse Gas Emissions and Sinks (1990-2019). Published in 2021.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2019.
---------------------------------------------------------------------------

c. Affected Facility
    For purposes of the NSPS, the reciprocating compressor affected
facility is a single reciprocating compressor. A reciprocating
compressor located at a well site, or an adjacent well site and
servicing more than one well site, is not an affected facility under
the proposed rule for the NSPS OOOOb. As discussed above, the EPA is
proposing that the affected facility includes reciprocating compressors
located at centralized production facilities and the affected facility
exception for ``a well site, or an adjacent well site servicing more
than one well site'' applies to standalone well sites and not
centralized production facilities.
d. 2021 BSER Analysis
    The methodology used for estimating emissions from reciprocating
compressor rod packing is consistent with the methodology developed for
the 2012 NSPS OOOO BSER analysis and then also used to support the 2016
NSPS OOOOa BSER. This approach uses volumetric methane emission factors
referenced in the EPA/GRI study \277\ as the basis, multiplied by the
density of methane. These factors were per cylinder, so they were
multiplied by the average number of cylinders per reciprocating
compressor at each oil and gas industry segment, the pressurized factor
(percentage of hours per year the compressor was pressurized), and
8,760 hours (number of hours in a year). Once the methane emissions
were calculated, VOC emissions were calculated by multiplying the
methane by ratios developed based on representative gas composition.
The specific ratios that were used for this analysis were 0.278

pounds VOC per pound of methane for the production and processing
segments, and 0.0277 pounds VOC per pound of methane for the
transmission and storage segment. The resulting baseline emissions from
reciprocating compressors were 12.3 tpy methane (3.4 tpy VOC) from
gathering and boosting stations, 23.3 tpy methane (6.5 tpy VOC) from
natural gas processing plants, 27.1 tpy methane (0.75 tpy VOC) from
transmission stations, and 28.2 tpy methane (0.78 tpy VOC) from storage
facilities.
---------------------------------------------------------------------------

    \277\ EPA/GRI. (1996). Methane Emissions from the Natural Gas
Industry: Volume 8--Equipment Leaks.
---------------------------------------------------------------------------

    Reducing emissions that result from the leaking of natural gas past
the piston rod packing can be accomplished through several approaches
including: (1) Specifying a frequency for the replacement of the
compressor rod packing, (2) monitoring the emissions from the
compressor and replacing the rod packing when the results exceed a
specified threshold, (3) specifying a frequency for the replacement of
the piston rod, (4) requiring the use of specific rod packing
materials, and/or (5) capturing the leaking gas and routing it either
to a process or a control device.
    There was either insufficient information to establish BSER or it
was determined that the option cannot be applied in all situations for
approach options (3) through (5). These are discussed briefly below.
    Like the packing rings, piston rods on reciprocating compressors
also deteriorate. Piston rods, however, wear more slowly than packing
rings, having a life of about 10 years.\278\ Rods wear ``out-of-round''
or taper when poorly aligned, which affects the fit of packing rings
against the shaft (and therefore the tightness of the seal) and the
rate of ring wear. An out-of-round shaft not only seals poorly,
allowing more leakage, but also causes uneven wear on the seals,
thereby shortening the life of the piston rod and the packing seal.
Replacing or upgrading the rod can reduce reciprocating compressor rod
packing emissions. Also, upgrading piston rods by coating them with
tungsten carbide or chrome reduces wear over the life of the rod. We
assume that operators will choose, at their discretion, when to
replace/realign or retrofit the rod as part of regular maintenance
procedures and replace the rod when appropriate when the compressor is
out of service for other maintenance such as rod packing replacement.
Although replacing/realigning or retrofitting the rod has been
identified as a potential methane and VOC emission reduction option for
reciprocating compressors, there is insufficient information on its
emission reduction potential and use throughout the industry.
Therefore, we did not evaluate this option any further as BSER for this
proposal.
---------------------------------------------------------------------------

    \278\ U.S. Environmental Protection Agency. Lessons Learned from
Natural Gas STAR Partners. Reducing Methane Emissions from
Compressor Rod Packing Systems. Natural Gas STAR Program. 2006.
---------------------------------------------------------------------------

    Although specific analyses have not been conducted, there may be
potential for reducing methane and VOC emissions by updating rod
packing components made from newer materials, which can help improve
the life and performance of the rod packing system. One option is to
replace the bronze metallic rod packing rings with longer lasting
carbon-impregnated Teflon rings. Compressor rods can also be coated
with chrome or tungsten carbide to reduce wear and extend the life of
the piston rod. Although changing the rod packing material has been
identified as a potential methane and VOC emission reduction option for
reciprocating compressors, there is insufficient information on its
emission reduction potential and use throughout the industry.
Therefore, we did not evaluate this option any further as BSER for this
proposal.
    The 2016 NSPS OOOOa includes the alternative to route the emissions
from reciprocating compressors to a process. One estimate obtained by
the EPA states that a gas recovery system can result in the elimination
of over 99 percent of methane emissions that would otherwise occur from
the venting of the emissions from the compressor rod packing. The
emissions that would have been vented are combusted in the compressor
engine to generate power. It was estimated that, if a facility is able
to route rod packing vents to a VRU system, it is possible to recover
approximately 95-100 percent of emissions. As a comparison, the EPA
estimated that the 3-year/26,000-hour changeout results in between 55
and 80 percent emission reduction. Therefore, an option to achieve
additional emission reductions could be to require routing the
reciprocating compressor emissions to a process/through a closed vent
system under negative pressure. Although this was a control option
considered in the 2016 NSPS OOOOa (and included as an alternative), the
EPA did not require routing to a process for all compressors because at
that time there was insufficient information to require this as a
control for all reciprocating compressors. The EPA received feedback
that this option cannot be applied in every installation, and has not
received any new information that indicates this has changed. Thus,
this option was not considered further as a requirement but for this
proposal, as with the 2016 NSPS OOOOa, it is considered to be an
acceptable alternative to mitigate methane and VOC emissions where it
is technically feasible to apply.
    Similarly, another option evaluated as having the potential to
achieve methane and VOC emission reductions was to require the
collection of emissions in a closed vent system and routing them to a
flare or other control device. If the gas is routed to a flare,
approximately 95 percent of the methane and VOC would be reduced. The
EPA has expressed historically and maintains that combustion is not
believed to be a technically feasible control option for reciprocating
compressors because, as detailed in the 2011 NSPS OOOO TSD, routing of
emissions to a control device can cause positive back pressure on the
packing, which can cause safety issues due to gas backing up in the
distance piece area and engine crankcase in some designs. The EPA has
not identified any new information to indicate that this has changed.
Therefore, this option was not considered further as BSER for this
proposal.
    The remaining two control option approaches that were evaluated
further for this proposal include: (1) Specifying a frequency for the
replacement of the compressor rod packing (equivalent to the frequency
used in the 2016 NSPS OOOOa BSER control level), and (2) monitoring the
emissions from the compressor and replacing the rod packing when the
results exceed a specified threshold. Both of these approaches would
reduce the escape of natural gas from the piston rod. No wastes would
be created (other than the worn packing that is being replaced) and no
wastewater would be generated.
    As noted previously, periodically replacing the packing rings
ensures the correct fit is maintained between packing rings and the
rod, thereby limiting emissions occurring around the flexible rings
that fit around the shaft by recreating a seal against leakage that may
have been lost due to wear. The potential emission reductions for
reciprocating compressors at gathering and boosting stations,
processing plants, and transmission and storage facilities were
calculated by comparing the average rod packing emissions with the
average emissions from newly installed and worn-in rod packing. As
noted above, because the EPA concluded that the cost effectiveness of
this option was extremely unreasonable for reciprocating compressors at
well sites in previous BSER analyses (see the 2011 NSPS OOOO TSD,
section 2.2; 80 FR 56620, September 18, 2015), and since no new
information was identified that

would change this outcome as it relates to stand alone well sites,
reductions and costs were not re-evaluated in this analysis for
reciprocating compressors at production well sites.
    The emissions after the replacement of the rod packing were
calculated using the methodology used under previous NSPS actions (see
NSPS OOOOb and EG TSD, section 7.1). The resulting emission reductions
used for the analysis represented the emission reductions expected in
the year the rod packing is replaced. It is expected that there would
be an increase in the emissions (and decrease in the emission
reductions) from a compressor where the rod packing was replaced the
second and third years before the next replacement. As noted above,
this assumed reduction was between 55 and 80 percent depending on the
location of the compressor.
    The costs of replacing rod packing were obtained from a Natural Gas
STAR Lessons Learned document \279\ and the dollars were converted to
2019 dollars. The estimated cost to replace the packing rings in 2019
dollars was estimated to be $1,920 per cylinder. It was assumed that
rod packing replacement would occur during planned shutdowns and
maintenance, and therefore no additional travel costs would be incurred
for implementing a rod packing replacement program. Since the assumed
number of cylinders differs for reciprocating compressors at different
segments, this means the capital costs also vary. These estimated
capital costs are $6,350 at gathering and boosting and transmission
stations, $4,800 at processing plants, and $8,650 at storage stations.
---------------------------------------------------------------------------

    \279\ EPA (2006). Lessons Learned: Reducing Methane Emissions
from Compressor Rod Packing Systems. Natural Gas STAR. Environmental
Protection Agency.
---------------------------------------------------------------------------

    The 26,000-hour replacement frequency used for the cost impacts in
the 2011 NSPS OOOO TSD and 2016 NSPS OOOOa TSD was determined using a
weighted average of the annual percentage of time that reciprocating
compressors are pressurized. The weighted average percentage was
calculated to be 98.9 percent. This percentage was multiplied by the
total number of hours in 3 years to obtain a value of 26,000 hours.
This calculates to an average of 3.8 years for gathering and boosting
compressors, 3.3 years for processing compressors, 3.8 years for
transmission compressors, and 4.4 years for storage compressors. The
calculated years were assumed to be the equipment life of the
compressor rod packing and were used to calculate the capital recovery
factor for each of the segments. Assuming an interest rate of 7
percent, the capital recovery factors were calculated to be 0.3093,
0.3498, 0.3093, and 0.2695 for the gathering and boosting part of
production, processing, transmission, and storage segments,
respectively.
    The capital costs were calculated using the average rod packing
cost noted above and the average number of cylinders per compressor
(which differs depending on sector segment). The annual capital costs
were calculated using the capital costs and the capital recovery
factors. The estimated annual costs ranged from $1,700 at processing
plants to just over $2,300 at storage facilities. Note that these
estimated costs represent the costs, and associated emission
reductions, that would occur in the year when the rod packing was
changed. There would be no costs for the other two years in the three-
year cycle. The costs presented for gathering and boosting segment
reciprocating compressors represent the estimated costs assumed for
reciprocating compressors located at centralized production facilities.
    There are monetary savings associated with the amount of natural
gas saved with reciprocating compressor rod packing replacement.
Monetary savings associated with the amount of gas saved with
reciprocating compressor rod packing replacement were estimated using a
natural gas price of $3.13 per Mcf. Estimated savings were only applied
for gathering and boosting stations and processing plants, as it is
assumed the owners of the compressor station do not own the natural gas
that is compressed at the station.
    Using the single pollutant approach, where all the costs are
assigned to the reduction of one pollutant, the cost effectiveness of
replacement of the reciprocating rod packing within 26,000 hours or 36
months of operation, regardless of the condition of the rod packing, is
approximately $290 per ton of methane reduced for gathering and
boosting ($100 per ton if gas savings are considered), $90 per ton of
methane reduced for the processing segment (net savings if gas savings
are considered), $90 per ton of methane reduced for the transmission
segment, and $110 per ton of methane reduced for the storage segment.
Using the multipollutant approach, where half the cost of control is
assigned to the methane reduction and half to the VOC reduction, the
cost effectiveness of replacement of the reciprocating rod packing
within 26,000 hours or 36 months of operation, regardless of the
condition of the rod packing, is approximately $140 per ton of methane
reduced for gathering and boosting ($50 per ton if gas savings are
considered), $45 per ton of methane reduced for the processing segment
(net savings if gas savings are considered), $45 per ton of methane
reduced for the transmission segment, and $50 per ton of methane
reduced for the storage segment.
    Using the single pollutant approach, where all the costs are
assigned to the reduction of one pollutant, the VOC cost effectiveness
of replacement of the reciprocating rod packing within 26,000 hours or
36 months of operation, regardless of the condition of the rod packing,
is approximately $1,030 per ton of VOC reduced for gathering and
boosting ($380 per ton if gas savings are considered), $330 per ton of
VOC reduced for the processing segment (net savings if gas savings are
considered), $3,260 per ton of VOC reduced for the transmission
segment, and $3,860 per ton of VOC reduced for the storage segment.
Using the multipollutant approach, where half the cost of control is
assigned to the methane reduction and half to the VOC reduction, the
cost effectiveness of replacement of the reciprocating rod packing
within 26,000 hours or 36 months of operation, regardless of the
condition of the rod packing, is approximately $520 per ton of VOC
reduced for gathering and boosting ($190 per ton if gas savings are
considered), $160 per ton of VOC reduced for the processing segment
(net savings if gas savings are considered), $1,630 per ton of VOC
reduced for the transmission segment, and $1,930 per ton of VOC reduced
for the storage segment.
    As an alternative to replacing the rod packing on a fixed schedule,
another option is to replace the rod packing when, based on
measurements, there are indications that the rod packing is beginning
to wear to the point where there is an increased rate of natural gas
escaping around the packing to unacceptable levels. This is an approach
required by the California Greenhouse Gas Emission Regulation and in
Canada. The California Greenhous Gas Emission Regulation requires that
the rod packing/seal be tested during periodic inspections and, if the
rod packing/seal leak concentration exceeds the specified threshold of
2 scfm/cylinder, repairs must be made within 30 days.\280\ Similarly,
certain Canadian jurisdictions require periodic monitoring measurements
of rod packing vent

volumes (typically annually) for existing reciprocating compressors.
Where specified vent volumes are exceeded, the rules require corrective
action be taken to reduce the flow rate to below or equal to a
specified limit, as demonstrated by a remeasurement. Vent volume
thresholds specified that would result in the need for corrective
action vary from 0.49 to 0.81 scfm/cylinder.\281\
---------------------------------------------------------------------------

    \280\ State of California Air Resources Board (CARB).
``Regulation for Greenhouse Gas Emission Standards for Crude Oil and
Natural Gas Facilities.'' Oil and Gas Final Regulation Order
(ca.gov).
    \281\ Canadian Federal standards: http://gazette.gc.ca/rp-pr/p2/2018/2018-04-26-x1/pdf/g2-152x1.pdf; Discussion Draft Regulation
26.11.41 (maryland.gov); MAP-Technical-Report-December-19-2019-
FINAL.pdf (nm.gov).
---------------------------------------------------------------------------

    This approach is similar to an approach identified in the Natural
Gas STAR Program referred to as ``Economic Packing and Piston Rod
Replacement.'' \282\ Under this approach, facilities use specific
financial objectives and monitoring data to determine emission levels
at which it is cost effective to replace rings and rods. Benefits of
calculating and utilizing this ``economic replacement threshold''
include methane and VOC emission reductions and natural gas cost
savings. Using this approach, one Natural Gas STAR partner reportedly
achieved savings of over $233,000 annually at 2006 gas prices. An
economic replacement threshold approach can also result in operational
benefits, including a longer life for existing equipment, improvements
in operating efficiencies, and long-term savings. The EPA is not
proposing to establish a financial objective or economic replacement
threshold in this proposal, but the costs and emission reductions of
replacing rod packing based on monitoring from this program were
considered in the analysis discussed below.
---------------------------------------------------------------------------

    \282\ U.S. Environmental Protection Agency. Lessons Learned from
Natural Gas STAR Partners. Reducing Methane Emissions from
Compressor Rod Packing Systems. Natural Gas STAR Program. 2006.
---------------------------------------------------------------------------

    The elements of such a program include establishing a frequency of
monitoring, identifying a threshold where action is required to reduce
emissions, and specifying the action for reducing emissions. The option
defined by the EPA and evaluated below is for annual monitoring and
requiring the replacement of the rod packing if the measured flow rate
for any individual cylinder exceeds 2 scfm. This threshold is
consistent with California's regulation. However, this option differs
from the California regulation in that it would require a complete
replacement of the rod packing if this threshold is exceeded, where
California allows repair sufficient to reduce the flow rate back below
2 scfm. 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.\283\
---------------------------------------------------------------------------

    \283\ 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. pgs. 96-97.
---------------------------------------------------------------------------

    We estimated the emission reductions from requiring annual flow
rate monitoring and repair/replacement of packing when the measured
flow rate exceeds 2 scfm total gas during pressurized operation. Based
on California's background regulatory documentation, information
provided to the State indicated that the average leak rate for those
compressors emitting more than 2 scfm was about 3 scfm during
pressurized operation, and less than 2 scfm during pressurized idle and
unpressurized states. Therefore, we assumed that the leak rate for
compressors emitting more than 2 scfm was about 3 scfm during
pressurized operation. As indicated above for the fixed schedule rod
packing replacement option, based on the 2011 NSPS OOOO TSD and 2016
NSPS OOOOa TSD, the average emissions from a newly installed rod
packing are assumed to be 11.5 scfh per cylinder.\284\ Using a ratio of
0.829 methane: Total natural gas ratio, 3 scfm total gas is
approximately 2.49 scfm (149.2 scfh) methane. This compressor emission
rate, which was used for all industry segments, was converted to an
annual mass emission rate by applying segment-specific pressurized
factors, then converted to a mass basis.
---------------------------------------------------------------------------

    \284\ 2011 TSD, pg. 6-13.
---------------------------------------------------------------------------

    The estimated percent reduction in methane emissions that would be
achievable from reducing 149.2 scfh methane/cylinder to 11.5 scfh
methane/cylinder (average emissions from a newly installed rod packing/
cylinder) is 92 percent. We applied this percent reduction in methane
emissions and estimated reciprocating compressor methane and VOC
emission reductions that would be achieved from repairing/replacing rod
packing based on the annual flow rate monitoring option. The
calculations assume that all cylinders are emitting at 3 scfm, and that
the rod packings for all compressor cylinders are replaced. This
represents the emission reductions expected for the year in which the
rod packings are replaced. Emissions would be expected to increase (and
emission reductions decrease) in subsequent years until the next time
the annual measurements require that the rod packing be replaced.
    The capital and annual costs of replacing the rod packings are the
same as presented above for the fixed interval rod packing replacement
option. In addition, this option would include the costs associated
with the annual flow measurements. The estimated costs of this
monitoring are based on the costs for annual flow rate monitoring under
GHGRP subpart W for similar flow rate annual measurement requirements
($597). The capital costs associated with replacing compressor rod
packing would only occur in the year when packing is required to be
replaced. The monitoring costs would be incurred every year.
    Additionally, the cost estimates assume that the packing of all
compressor cylinders would need to be replaced (which is unlikely to be
the case in many instances) and are therefore conservative estimates.
Support information for the California rule cites data indicating that
approximately 14 percent of compressors measurements indicated a leak
rate of over 2 scfm per cylinder. Based on an average of 3.45
cylinders/compressor, California assumed that the packing for 2
cylinders/compressor would need to be replaced to come into compliance
with the 2 scfm standard (57.9 percent).\285\
---------------------------------------------------------------------------

    \285\ Based on Appendix B. Economic Analysis. State of
California. Air Resources Board. Proposed Regulation for Greenhouse
Gas Emission Standards for Crude Oil and Natural Gas Facilities. pg.
B-28. Notice Package for Oil and Gas Reg (ca.gov); State of
California. Air Resources 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.
Date of Release: May 31, 2016. pg. 99.
---------------------------------------------------------------------------

    Using the single pollutant approach, where all the costs are
assigned to the reduction of one pollutant, the cost effectiveness of
the annual monitoring option is approximately $230 per ton of methane
reduced for gathering and boosting ($40 per ton if gas savings are
considered), $110 per ton of methane reduced for the processing segment
(net savings if gas savings are considered), $100 per ton of methane
reduced for the transmission segment, and $110 per ton of methane
reduced for the storage segment. Using the multipollutant approach,
where half the cost of control is assigned to the methane reduction and
half to the VOC reduction, the cost effectiveness of replacement of the
reciprocating rod packing based on the annual monitoring approach is
approximately $110 per ton of methane reduced for gathering and
boosting ($20 per ton if gas savings are considered), $50 per ton of
methane reduced for the processing segment (net savings if gas savings
are considered), $50 per ton of methane reduced for the transmission

segment, and $60 per ton of methane reduced for the storage segment.
    Using the single pollutant approach, where all the costs are
assigned to the reduction of one pollutant, the VOC cost effectiveness
of the annual monitoring option is approximately $810 per ton of VOC
reduced for gathering and boosting ($160 per ton if gas savings are
considered), $380 per ton of VOC reduced for the processing segment
(net savings if gas savings are considered), $3,700 per ton of VOC
reduced for the transmission segment, and $4,100 per ton of VOC reduced
for the storage segment. Using the multipollutant approach, where half
the cost of control is assigned to the methane reduction and half to
the VOC reduction, the cost effectiveness of replacement of the
reciprocating rod packing based on the annual monitoring approach is
approximately $410 per ton of VOC reduced for gathering and boosting
($80 per ton if gas savings are considered), $190 per ton of VOC
reduced for the processing segment (net savings if gas savings are
considered), $1,850 per ton of VOC reduced for the transmission
segment, and $2,040 per ton of VOC reduced for the storage segment.
    We also assessed the incremental cost effectiveness of the annual
monitoring option compared to the fixed 3-year/26,000 replacement
schedule. Using the single pollutant approach, where all the costs are
assigned to the reduction of one pollutant, the incremental cost
effectiveness (without natural gas savings) from the fixed replacement
option to the annual monitoring option for methane is approximately
$130 per ton for gathering and boosting stations, $210 per ton for
processing plants, $180 per ton for transmission stations, and $140 per
ton for storage facilities. For VOC, the incremental cost effectiveness
is approximately $480 per ton for gathering and boosting stations, $750
per ton for processing plants, $6,600 per ton for transmission
stations, and $5,150 per ton for storage facilities.
    The cost effectiveness of both options (fixed schedule and annual
monitoring) are reasonable for methane and VOC using either the single
pollutant or multipollutant approach. The incremental cost
effectiveness in going from the fixed schedule option to the annual
monitoring option is reasonable for all scenarios, with the exception
of VOC for transmission stations. Therefore, based on the consideration
of the costs in relation to the emission reductions, the EPA finds that
the annual monitoring option is the most reasonable option.
    Further, as discussed above, California requires reciprocating
compressor annual rod packing flow rate monitoring and repair and or
replacement of the packing where flow rate monitoring indicates a
measurement that exceeds 2 scfm. This further supports the
reasonableness of a monitoring program.
    Neither the fixed schedule rod packing replacement option nor the
rod packing replacement based on annual monitoring option would result
in secondary emissions impacts as both options would reduce the escape
of natural gas from the piston rod. No wastes would be created (other
than the worn packing that is being replaced) and no wastewater would
be generated. An advantage related to the replacement of rod packing
for reciprocating compressors based on annual rod packing monitoring is
that it would only require replacement of the rod packing where
monitoring of the rod packing indicates wear and increasing flow rate/
emissions to unacceptable levels. This optimizes the output of capital
expenditures to focus on emissions control where an increased emissions
potential is identified.
    In light of the above we determined that annual rod pack flow rate
monitoring and replacement of the packing where flow rate monitoring
indicates a measurement that exceeds 2 scfm represents BSER for NSPS
OOOOb for this proposal for all segments including reciprocating
compressors located at centralized productions facilities (with the
exception of compressors at stand-alone well sites). As in the 2016
NSPS OOOOa, the EPA is proposing to allow the collection and routing of
emissions to a process as an alternative standard because that option
would achieve emission reductions equivalent to, or greater than, the
proposed standard for NSPS OOOOb.
    The affected facility based on EPA's review would continue to be
each reciprocating compressor not located at a well site, or an
adjacent well site and servicing more than one well site. As discussed
above, the EPA is proposing a new definition for a ``centralized
production facility''. The EPA is proposing to define centralized
production facilities separately from well sites because the number and
size of equipment, particularly reciprocating and centrifugal
compressors, is larger than standalone well sites which would not be
included in the proposed definition of ``centralized production
facilities''. Thus, the EPA is proposing that reciprocating compressors
located at centralized production facilities would be subject to the
standards in NSPS in OOOOb, but reciprocating compressors at well sites
(standalone well sites) would not.
2. EG OOOOc
    The EPA evaluated BSER for the control of methane from existing
reciprocating compressors (designated facilities) in all segments in
the Crude Oil and Natural Gas source category covered by the proposed
NSPS OOOOb and translated the degree of emission limitation achievable
through application of the BSER into a proposed presumptive standard
for these facilities that essentially mirrors the proposed NSPS OOOOb.
    First, based on the same criteria and reasoning as explained above,
the EPA is proposing to define the designated facility in the context
of existing reciprocating compressors as those that commenced
construction on or before November 15, 2021. Based on information
available to the EPA, we did not identify any factors specific to
existing sources that would indicate that the EPA should alter this
definition as applied to existing sources. Next, the EPA finds that the
control measures evaluated for new sources for NSPS OOOOb are
appropriate for consideration for existing sources under the EG OOOOc.
The EPA finds no reason to evaluate different, or additional, control
measures in the context of existing sources because the EPA is unaware
of any control measures, or systems of emission reduction, for
reciprocating compressors that could be used for existing sources but
not for new sources. Next, the methane emission reductions expected to
be achieved via application of the control measures identified above to
new sources are also expected to be achieved by application of the same
control measures to existing sources. The EPA finds no reason to
believe that these calculations would differ for existing sources as
compared to new sources because the EPA believes that the baseline
emissions of an uncontrolled source are the same, or very similar, and
the efficiency of the control measures are the same, or very similar,
compared to the analysis above. This is also true with respect to the
costs, non-air environmental impacts, energy impacts, and technical
limitations discussed above for the control options identified.
    The EPA has not identified any costs associated with applying these
controls at existing sources, such as retrofit costs, that would apply
any differently than, or in addition to, those costs assessed above
regarding application of the identified controls to new sources. The
cost effectiveness values for the

proposed presumptive standard of replacement of the rod packing based
on an annual monitoring threshold is approximately $230 per ton of
methane reduced ($40 per ton if gas savings are considered) for the
gathering and boosting segment (including reciprocating compressors
located at centralized tank facilities), $110 per ton of methane
reduced for the processing segment (net savings if gas savings are
considered), $100 per ton of methane reduced for the transmission
segment, and $110 per ton of methane reduced for the storage segment.
    In summary, the EPA did not identify any factors specific to
existing sources, as opposed to new sources, that would alter the
analysis above for the proposed NSPS OOOOb as applied to the designated
pollutant (methane) and the designated facilities (reciprocating
compressors). As a result, the proposed presumptive standard for
existing reciprocating compressors is as follows.
    For reciprocating compressors in the gathering and boosting segment
(including reciprocating compressors located at centralized tank
facilities), processing, and transmission and storage segments, the
presumptive standard is replacement of the rod packing based on an
annual monitoring threshold. Specifically, the presumptive standard
would require an owner or operator of a reciprocating compressor
designated facility to monitor the rod packing flow rate annually. When
the measured leak rate exceeds 2 scfm (in pressurized mode), the
standard would require replacement of the rod packing. As an
alternative, the presumptive standard would be routing rod packing
emissions to a process via a closed vent system under negative
pressure.

F. Proposed Standards for Centrifugal Compressors

1. NSPS OOOOb
a. Background
    The 2012 NSPS OOOO and the 2016 NSPS OOOOa applied to each wet seal
compressor not located at a well site, or an adjacent well site and
servicing more than one well site. The 2016 NSPS OOOOa required methane
and VOC emissions be reduced from each centrifugal compressor wet seal
fluid degassing system by 95.0 percent. Compliance with this
requirement allowed routing of emission from the wet seal fluid
degassing system to a control device or to a process. Dry seal
compressors were not subject to requirements under the 2016 NSPS OOOOa.
    In determining BSER for wet seal compressors in 2016, the EPA
determined that the previous determination for NSPS OOOO conducted in
2011/2012 still represented BSER for the control of VOC in 2016. In
addition, the EPA determined that analogous control of methane
represented BSER. In the 2012 determinations, the EPA conducted
analyses of the cost and emission reductions of (1) requiring the
conversion of a wet seal system to a dry seal system, and (2) routing
to a control device or process. The 2011 NSPS OOOO rule (76 FR 52738,
52755, August 23, 2011) proposed an equipment standard that would have
required the use of dry seals to limit the VOC emissions from new
centrifugal compressors. At that time, the EPA solicited comments on
the emission reduction potential, cost, and any technical limitations
for the option of routing the gas back to a low-pressure fuel stream to
be combusted as fuel gas. In addition, in 2011 (76 FR 52738), the EPA
solicited comments on whether there are situations or applications
where a wet seal is the only option, because a dry seal system is
infeasible or otherwise inappropriate. The EPA received information
indicating that the integration of a centrifugal compressor into an
operation may require a certain compressor size or design that is not
available in a dry seal model, and in the case of capture of emissions
with routing to a process, there may not be down-stream equipment
capable of handling a low-pressure fuel source. In the final 2012 NSPS
OOOO rule, the EPA made the determination that the replacement of wet
seals with dry seals and routing to a process was not technically
feasible or practical for some centrifugal compressors, and also that
the costs per ton of emissions reduced were reasonable for routing
emissions to a control device or process. No other more stringent
control options were evaluated at that time. During the development of
the 2016 NSPS OOOOa rule, the EPA reviewed available information on
control options for wet seal compressors and did not identify any new
information to indicate that this has changed.
    For this review, the EPA also focused on these control options.
BSER was evaluated for wet-seal centrifugal compressors at gathering
and boosting stations (considered to be representative of emissions
from centrifugal compressors at centralized production facilities) in
the production segment, at natural gas processing plants, and at sites
in the transmission and storage segment. During the development of the
2012 NSPS OOOO and 2016 NSPS OOOOa rulemakings, our data indicated that
there were no centrifugal compressors located at well sites. Since the
2012 NSPS OOOO and 2016 NSPS OOOOa rulemakings, we have not received
information that would change our understanding that there are no
centrifugal compressors in use at well sites.
    However, as discussed in section XI.L (Centralized Production
Facilities) of this preamble, the EPA believes the definition of ``well
site'' in NSPS OOOOa may cause confusion regarding whether centrifugal
compressors located at centralized production facilities are also
exempt from the standards. The EPA is proposing a new definition for a
``centralized production facility''. The EPA is proposing to define
centralized production facilities separately from well sites because
the number and size of equipment, particularly reciprocating and
centrifugal compressors, is larger than standalone well sites which
would not be included in the proposed definition of ``centralized
production facilities''. This proposal is necessary in the context of
centrifugal compressors to distinguish between these compressors at
centralized production facilities where the EPA has determined that the
standard should apply, and compressors at standalone well sites where
the EPA has determined that the standard should not apply. In our
current analysis, described below, we consider the centrifugal
compressor gathering and boosting segment emission factor as being
representative of centrifugal compressor emissions located at
centralized production facilities. As such, the EPA is proposing that
centrifugal compressors located at centralized production facilities
would be subject to the standards in NSPS OOOOb and the EG in subpart
OOOOc, but centrifugal compressors at well sites (standalone well
sites) would not.
    In addition to the requirement to reduce methane and VOC emissions
from each centrifugal compressor wet seal fluid degassing system by
95.0 percent, the 2016 NSPS OOOOa requires compressor components to be
monitored as fugitive emissions components and leaks found are to be
repaired under the fugitive emissions monitoring requirements of 40 CFR
60.5397a. The monitoring frequency depends on source (i.e., well sites,
compressor stations) and sector segment. These fugitive emissions
components were not considered part of the centrifugal compressor
affected facility.
    Based on the EPA's review of NSPS OOOOa, we are proposing that BSER
continues to be that methane and VOC

emissions be reduced from each centrifugal compressor wet seal fluid
degassing system by 95.0 percent.
b. Description
    Centrifugal compressors use a rotating disk or impeller to increase
the velocity of the natural gas where it is directed to a divergent
duct section that converts the velocity energy to pressure energy.
These compressors are primarily used for continuous, stationary
transport of natural gas in the processing and transmission systems.
Some centrifugal compressors use wet (meaning oil) seals around the
rotating shaft to prevent natural gas from escaping where the
compressor shaft exits the compressor casing. The wet seals use oil
which is circulated at high pressure to form a barrier against
compressed natural gas leakage. The circulated oil entrains and adsorbs
some compressed natural gas that may be released to the atmosphere
during the seal oil recirculation process. Off gassing of entrained
natural gas from wet seal centrifugal compressors is not suitable for
sale and is either released to the atmosphere, flared, or routed back
to a process.
    Some centrifugal compressors utilize dry seal systems. Dry seal
systems minimize leakage by using the opposing force created by
hydrodynamic grooves and springs. The hydrodynamic grooves are etched
into the surface of the rotating ring affixed to the compressor shaft.
When the compressor is not rotating, the stationary ring in the seal
housing is pressed against the rotating ring by springs. When the
compressor shaft rotates at high speed, compressed natural gas has only
one pathway to leak down the shaft, and that is between the rotating
and stationary rings. This natural gas is pumped between the grooves in
the rotating and stationary rings. The opposing force of high-pressure
natural gas pumped between the rings and springs trying to push the
rings together creates a very thin gap between the rings through which
little natural gas can leak. While the compressor is operating, the
rings are not in contact with each other and, therefore, do not wear or
need lubrication. O-rings seal the stationary rings in the seal case.
Historically, the EPA has considered dry seal centrifugal compressors
to be inherently low-emitting and has never required control of
emissions from dry seal compressors. The EPA has received
feedback,\286\ however, that there are some wet seal compressor system
designs that are also low emitting when compared to dry seal
compressors and is soliciting comment on lower emitting wet seal
compressor system designs and dry seal compressor emissions in this
proposed action.
---------------------------------------------------------------------------

    \286\ Conference Call. Prepared by Tora Consulting. December 19,
2018.
---------------------------------------------------------------------------

    The 2021 U.S. GHGI estimates over 166,700 metric tpy of methane
emissions in 2019 from compressors from natural gas systems. For the
natural gas processing and transmission segments, wet seal compressor
methane emissions are estimated to be about 78,700 metric tons and dry
seal compressor methane estimated emissions are estimated to be about
88,000 metric tons.\287\ The wet seal and dry seal compressor methane
emission estimates reflect the increasing prevalence of the use of dry
seals over wet seals and emissions control requirements that require
the control of emissions from wet seal compressors. The methane
emissions from centrifugal compressors represent 3 percent of the total
methane emissions from natural gas systems in the Oil and Natural Gas
Industry sector.
---------------------------------------------------------------------------

    \287\ U.S. Environmental Protection Agency. Inventory of U.S.
Greenhouse Gas Emissions and Sinks (1990-2019). Published in 2021.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2019.
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c. Affected Facility
    For purposes of the NSPS, the centrifugal compressor affected
facility is a single centrifugal compressor using wet seals. A
centrifugal compressor located at a well site, or an adjacent well site
and servicing more than one well site, is not an affected facility
under the proposed rule for NSPS OOOOb. As discussed above, the EPA is
proposing that the affected facility includes centrifugal compressors
located at centralized production facilities and the affected facility
exception for ``a well site, or an adjacent well site servicing more
than one well site'' applies to standalone well sites and not
centralized production facilities.
d. 2021 BSER Analysis
    The methodology we used for estimating emissions from compressors
is consistent with the methodology developed for the 2012 NSPS OOOO
BSER analysis, which was also used to support the 2016 NSPS OOOOa
BSER.\288\ The wet-seal centrifugal compressor methane uncontrolled
emission factors are based on the volumetric emission factors used for
the GHGI, which were converted to a mass emission rate using a density
of 41.63 pounds of methane per thousand cubic feet. The VOC emissions
were calculated using the ratio of 0.278 pounds VOC per pound of
methane for the production and processing segments, and 0.0277 pounds
VOC per pound of methane for the transmission and storage segment. The
resulting baseline uncontrolled emissions per centrifugal compressor
are 157 tpy methane (43.5 tpy VOC) from wet-seal compressors at
gathering and boosting sites, 211 tpy methane (58.7 tpy VOC) from wet-
seal compressors at natural gas processing plants, 157 tpy methane (4.3
tpy VOC) from wet-seal compressors at transmission compressor stations,
and 117 (3.24 tpy VOC) from wet-seal compressors at storage facilities.
Since the emission factors for dry seal compressors are approximately
lower than wet seal compressors,\289\ the EPA considered requiring dry
seals as a replacement to wet seals as a control option in 2011. The
EPA proposed dry seals as a replacement to wet seals to control VOC
emissions at that time. Based on comments received on the proposal that
dry seal compressors were not feasible in all instances based on costs
and technical reasons, the EPA did not finalize the proposal that dry
seal compressors represented BSER. Instead, the EPA separately
evaluated the control options for wet seal compressors (77 FR 49499-
49500, 49523, August 16, 2012). In the 2015 NSPS OOOOa proposed rule,
the EPA maintained that available information since the 2012 NSPS OOOO
rule continued to show that dry seal compressors cannot be use in all
circumstances. The EPA has not identified any new information since
that time that indicates that dry seal compressors as a replacement for
wet seal compressors is technically feasible in all circumstances.
Thus, we did not evaluate the replacement of a wet seal system with a
dry seal system as BSER for controlling emissions from wet seal systems
for the NSPS OOOOb proposal.
---------------------------------------------------------------------------

    \288\ 2011 NSPS OOOO TSD, section 6.2.2; 2016 NSPS OOOOa TSD,
section 7.2.2.
    \289\ 2011 NSPS OOOO TSD, Table 6-2, pg. 6-4; 2016 NSPS OOOOa
TSD, Table 7-2, pg. 104.
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    In addition to soliciting comment and information on lower-emitting
wet seal compressor designs (that emit less than dry seal compressors),
the EPA is soliciting information on dry seal compressor emissions.
Feedback received (noted above) on lower emitting wet seal compressor
designs included concern that lower emitting wet seal systems were
being replaced by higher emitting (but still low emitting) dry seal
systems because they were not subject to the NSPS. Given that the trend
has been that wet seal compressor systems are increasingly being
replaced by dry seal compressor systems, the EPA solicits 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 also solicits comment on whether
owners and operators implement standard operating procedures to
identify and correct operational or malfunction conditions that have
the potential to increase emissions from dry seal systems. Finally, the
EPA solicits comments on whether we should consider evaluating BSER and
developing NSPS standards for dry seal compressors.
    The control options to reduce emissions from centrifugal
compressors evaluated include control techniques that reduce emissions
from leaking of natural gas from wet seal compressors by capturing
leaking gas and route it either to (1) a control device (combustion
device), or (2) to the process. We evaluated the costs and impacts of
both of these options.
    Combustion devices are commonly used in the Crude Oil and Natural
Gas Industry to combust methane and VOC emission streams. Combustors
are used to control VOC and methane emissions in many industrial
settings, since the combustor can normally handle fluctuations in
concentration, flow rate, heating value and inert species content.\290\
A combustion device generally achieves 95 percent reduction of methane
and VOC when operated according to the manufacturer instructions. 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