wells each year (and 410,000 existing wells) to which the proposed
fugitive emissions requirements will apply.\228\ Various studies
demonstrate that the vast majority of emissions come from a relatively
small subset of wells.\229 230\

The EPA would like to ensure that resources and effort are focused on
those wells that emit the most methane and VOC. Moreover, given the
diversity of ownership, while our cost assumption that distributes the
costs of recordkeeping evenly across 22 sites within a company-defined
area is a reasonable estimate for the population as a whole, it may
underestimate the costs and therefore overestimate the cost-
effectiveness for owners with fewer than 22 well sites (and conversely,
underestimate cost-effectiveness for owners with more than 22 well
sites). In order to best focus resources and effort on the well sites
with the greatest emissions and more accurately capture costs,
particularly for owners with fewer well sites, the EPA requests comment
on the number of wells that likely emit at each baseline emissions
level, and the baseline emissions level of wells generally owned by
owners with few wells. The EPA anticipates that it may refine its BSER
determination for well sites through its supplemental proposal based on
the information gathered from commenters.
---------------------------------------------------------------------------

    \228\ Estimated well counts are based on non-wellhead only
sites. Based on information provided by API, we assume that 27% of
sites are wellhead only; see Memoranda for Meetings with the
American Petroleum Institute (API), September 23, 2021, located at
Docket ID No. EPA-HQ- OAR-2021-0317. Absent additional information,
we also assume that 27% of wells are wellhead only. The estimated
new well count reflects the arithmetic average of well counts over
the analysis horizon in the RIA, 2023-2035. The estimated existing
well count reflects the total in 2026, which is the first year that
we estimate impacts for the emissions guidelines.
    \229\ Brandt, A., Heath, G., Cooley, D. (2016) Methane leaks
from natural gas systems follow extreme distributions. Environ. Sci.
Technol., DOI: 10.1021/acs.est.6b04303.
    \230\ Zavala-Araiza, D., Alvarez, R., Lyon, D, et al. (2016).
Super-emitters in natural gas infrastructure are caused by abnormal
process conditions. Nat Commun 8, 14012 (2017). https://www.nature.com/articles/ncomms14012.
---------------------------------------------------------------------------

    Taking these factors into account, and as explained in more detail
below, the EPA proposes to conclude that (1) BSER for well sites with a
baseline site-wide emissions level of less than 3 tpy is no regular
monitoring, but that to help ensure that these sites actually emit at
less than 3 tpy, a one-time survey (following each calculation of site-
level baseline methane emissions) would be required to ensure that any
abnormalities are addressed; (2) BSER for well sites with a baseline
site-wide emissions level of 3 tpy or greater is quarterly monitoring.
Because of the uncertainties discussed above, and as explained in more
detail below, the EPA further co-proposes to conclude that BSER for
well sites with a baseline site-wide emissions level of 3 tpy or
greater and less than 8 tpy is semiannual monitoring. Our co-proposal
is the same as our main proposal with regard to well sites whose
baseline site-wide emissions are less than 3 tpy (no regular
monitoring, but a one-time survey) and whose emissions are 8 tpy or
greater (quarterly monitoring). The EPA estimates that a majority of
fugitive emissions (approximately 86%) can be attributed to wells with
site-wide baseline emissions of 3 tpy or greater, where 54% can be
attributed to wells with site-wide baseline emissions of 8 tpy or
greater.\231\
---------------------------------------------------------------------------

    \231\ Percentages were estimated for the baseline scenario in
the RIA for the 2030 analysis year by combining the bin percentages
presented in RIA Table 2-4 with the projected well site activity
data documented in the RIA.
---------------------------------------------------------------------------

    Proposed BSER for Well Sites with Baseline Emissions Less Than 3
tpy. As noted, in both our main proposal and our co-proposal, we
propose to conclude that BSER for well sites with baseline emissions of
less than 3 tpy is no regular monitoring, but a one-time survey to help
ensure that these sites actually emit at less than 3 tpy.
    Based on the matrix described above, the EPA determined that where
total site baseline methane emissions are 2 tpy, semiannual and
quarterly monitoring costs approximately $2,700/ton methane reduced,
while biennial and annual monitoring costs approximately $4,000/ton
methane reduced. The costs for VOC reductions range from $10,000 to
$15,000/ton VOC reduced for quarterly to biennial monitoring,
respectively. These costs are outside the range of what we are
proposing to consider cost effective on a single-pollutant basis for
both methane and VOC. See Section IX.B. However, when considered on a
multipollutant basis, the costs of semiannual and quarterly monitoring
are approximately $1,350 per ton methane reduced, and approximately
$5,000 per ton of VOC, which we do consider cost-effective. Thus, for
sites with total baseline methane emissions of 2 tpy, we conclude that
regular monitoring at semiannual or quarterly frequencies would be
cost-effective.\232\
---------------------------------------------------------------------------

    \232\ The NSPS OOOOb and EG OOOOc TSD also provide costs for
monitoring at 1 tpy, which is not considered cost-effective at any
frequency evaluated.
---------------------------------------------------------------------------

    We do not propose to conclude that routine monitoring with OGI is
the BSER for sites with baseline emissions of less than 3 tpy, however,
for several reasons. While the estimates for semiannual and quarterly
monitoring are within what we consider to be cost effective for well
sites with baseline emissions of 2 tpy, in light of the large cohort of
relatively lower-emitting sites, we are concerned that our cost
effectiveness estimates may not accurately capture the costs, and
therefore cost-effectiveness, of routine monitoring with OGI for
businesses that own relatively few well sites. Throughout the
development of the 2016 NSPS OOOOa, and in subsequent analyses and
rulemaking actions, industry stakeholders have consistently stated that
the fugitive monitoring requirements are particularly burdensome for
smaller entities that own fewer well sites. The EPA believes that many
of these smaller entities are likely to own well sites with baseline
emissions of less than 3 tpy, a category that tends to include smaller
and less complex facilities with few or no major pieces of production
and processing equipment.\233\ And as noted, the EPA would like to
ensure that resources and effort are focused on well sites with
significant emissions. Given the possibility that our cost-
effectiveness analysis has overestimated the average number of sites,
and therefore underestimated the cost-effectiveness, for this cohort of
well sites, the EPA is proposing no regular monitoring at sites with
baseline site-wide emissions of less than 3 tpy.
---------------------------------------------------------------------------

    \233\ Anna M. Robertson, Rachel Edie, Robert A. Field, David
Lyon, Renee McVay, Mark Omara, Daniel Zavala-Araiza, and Shane M.
Murphy. ``New Mexico Permian Basin Measured Well Pad Methane
Emissions Are a Factor of 5-9 Times Higher Than U.S. EPA
Estimates.''
    Environmental Science & Technology 2020 54 (21), 13926-13934.
DOI: 10.1021/acs.est.0c02927.
---------------------------------------------------------------------------

    While the EPA is proposing to conclude that BSER for well sites
with total site-level baseline methane emissions less than 3 tpy is no
regular monitoring, we believe it is essential to ensure that well
sites in this monitoring tier are operating in a well-controlled
manner, and are not experiencing leaks or malfunctions that would cause
their emissions to exceed 3 tpy. Therefore, the EPA is proposing a
requirement for owners and operators to conduct a survey, and perform
repairs as needed, to demonstrate that the well site is free of leaks
or malfunctions and is therefore operating in a manner consistent with
the baseline methane emissions calculation.\234\ This survey could
employ any method available that would demonstrate the actual emissions
are consistent with the baseline calculation, including, but not
limited to, the use of OGI, EPA Method 21 (which includes provisions
for a soap bubble test), or alternative methane detection technologies
like those discussed in the proposed screening alternative in section
XI.A.5.
---------------------------------------------------------------------------

    \234\ We anticipate that during the survey to confirm their
baseline methane emissions and thus exemption status, sources would
also repair the leaks found, consistent with our understanding of
the standard industry practice.
---------------------------------------------------------------------------

    The EPA seeks comment on all aspects of this proposed BSER
determination, including information, data, and analysis that would
shed further light on the factors and concerns just expressed and that
would support the establishment of ongoing monitoring requirements at
the cohort of sites with baseline methane emissions below 3 tpy. Among
other things, the EPA seeks

comment on the ownership profile of well sites with site-wide baseline
emissions less than 3 tpy, the extent to which well sites in this
cohort are owned by firms that own relatively few wells, and the
relative economic costs associated with requiring regular OGI
monitoring at these wells. The EPA also seeks information that would
improve our understanding of the overall number of wells that would
fall in this cohort of sites, and the contribution these wells make to
overall fugitive emissions. And the EPA seeks comment on our estimates
of the costs and emission reduction associated with OGI monitoring at
this cohort of sites, or other data and analysis that would provide
support for regular OGI monitoring at these sites. In addition, the EPA
notes that the advanced measurement technologies that form the basis of
our proposed alternative screening option in section XI.A.5 could be
particularly well-suited for rapidly and cost-effectively detecting
recurrences of large emitting events at sites with baseline emissions
below 3 tpy. Accordingly, the EPA seeks comment that could inform
whether to require the use of these technologies for ongoing monitoring
at this cohort of sites, including information on the capabilities of
these emerging technologies, methodologies for their use, and the costs
and emission reductions associated with using these advanced
measurement technologies as part of a mandatory monitoring regime. If
appropriate, and based on input received during the comment period, the
EPA may consider further addressing monitoring requirements for sites
with baseline emissions below 3 tpy as part of a supplemental proposal.
    Additionally, the EPA is soliciting comment on different criteria,
such as the number of well sites owned by a specific owner, that could
better account for factors that may affect the costs of fugitive
emissions monitoring. As noted, while the EPA has presented costs on an
individual site-level, we have also distributed the costs of
recordkeeping evenly across an assumed 22 sites within a company-
defined area. While this may be appropriate for companies with larger
ownership, it is likely underestimating the cost (and overestimating
the cost-effectiveness) on owners with fewer sites. Information
provided on small businesses, including ownership thresholds, could be
used to further determine differences in OGI monitoring requirements at
well sites through a supplemental proposal.
    Further, the EPA is soliciting comment on whether the presence of
specific major production and processing equipment types at a well site
warrants a separate monitoring frequency consideration even where the
calculated total site-level baseline methane emissions are below 3 tpy.
As mentioned throughout this preamble, the EPA is concerned about the
presence of large emission events, which various studies have shown are
most often attributed to specific equipment. This equipment includes
separators paired with onsite storage vessels, combustion devices, and
intermittent pneumatic controllers.235 236 237 Therefore,
the EPA is soliciting comment on whether well sites with these specific
types of equipment present must conduct at least semiannual monitoring,
regardless of the total site-level baseline methane emissions
calculated, including those sites calculated below 3 tpy.
---------------------------------------------------------------------------

    \235\ Id.
    \236\ Tyner, David R., Johnson, Matthew R., ``Where the Methane
Is--Insights from Novel Airborne LiDAR Measurements Combined with
Ground Survey Data.'' Environmental Science & Technology 2021 55
(14), 9773-9783. DOI: 10.1021/acs.est.1c01572.
    \237\ Rutherford, J.S., Sherwin, E.D., Ravikumar, A.P. et al.
Closing the methane gap in US oil and natural gas production
emissions inventories. Nat Commun 12, 4715 (2021). https://doi.org/10.1038/s41467-021-25017-4.
---------------------------------------------------------------------------

    Finally, the EPA believes there is a subset of well sites (i.e.,
wellhead only well sites) that will never have baseline methane
fugitive emissions of 3 tpy or greater. Therefore, the proposed rule
would not define these sites as affected facilities, thus removing the
need for these sites to determine baseline emissions. As defined in the
2020 Technical Rule, a ``wellhead only well site'' is ``a well site
that contains one or more wellheads and no major production and
processing equipment.'' The term ``major production and processing
equipment'' is defined as including reciprocating or centrifugal
compressors, glycol dehydrators, heater/treaters, separators, and
storage vessels collecting crude oil, condensate, intermediate
hydrocarbon liquids, or produced water. As described earlier in this
section, sites will calculate their baseline methane emissions using a
combination of population-based emission factors and storage vessel
emissions. The population-based emission factors include emissions from
wellheads, reciprocating and centrifugal compressors, glycol
dehydrators, heater/treaters, separators, natural gas-driven pneumatic
pumps, and natural gas-driven pneumatic controllers (both continuous
and intermittent). By definition, a wellhead only well site would not
have emissions associated with the major production and processing
equipment, which includes storage vessels. Further, this proposed rule
would not allow the use of natural gas-driven pneumatic controllers at
any location (except on the Alaska North Slope), including wellhead
only well sites. Therefore, the only emissions would be calculated
based on the fugitive emissions components associated with the
wellhead, which we believe would never be above 3 tpy.
    Proposed BSER for Sites with Baseline Emissions of 3 tpy or
Greater. The EPA next evaluated what frequency of OGI monitoring is
BSER for well sites where the total site-level baseline methane
emissions are 3 tpy or greater. Table 14 summarizes the cost-
effectiveness information for each monitoring frequency evaluated at
this threshold.

                   Table 14--Summary of Emission Reductions and Cost-Effectiveness for Site-Level Baseline Methane Emissions of 3 TPY
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Single-pollutant                 Multipollutant
                                                              Methane      VOC emission  ---------------------------------------------------------------
          Monitoring frequency              Annual cost      emission     reduction (tpy/  Methane cost-     VOC cost-     Methane cost-     VOC cost-
                                            ($/yr/site)      reduction         site)       effectiveness   effectiveness   effectiveness   effectiveness
                                                            (tpy/site)                        ($/ton)         ($/ton)         ($/ton)         ($/ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                       3 tpy site-level baseline methaneemissions
--------------------------------------------------------------------------------------------------------------------------------------------------------
Biennial................................          $2,500            0.90            0.25          $2,800         $10,000          $1,400          $5,000
Annual..................................           3,000            1.20            0.33           2,500           9,000           1,250           4,500
Semiannual..............................           3,200            1.80            0.50           1,800           6,400             900           3,200
Quarterly...............................           4,200            2.40            0.67           1,800           6,300             900           3,200
Monthly.................................           8,100            2.70            0.75           3,000          11,000           1,500           5,400
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Based on the information summarized in Table 14, the average costs
per ton reduced appear to be reasonable for either semiannual or
quarterly monitoring when site-level baseline methane emissions are 3
tpy or greater under the single pollutant approach for methane
(biennial, annual, or monthly are outside of what the EPA considers
reasonable for VOCs in the single pollutant approach), or reasonable at
any frequency under the multipollutant approach.
    In addition to considering the average costs per ton reduced for
these sites, the EPA also evaluated the incremental cost associated
with progressing to greater monitoring frequencies. To conduct this
analysis, the EPA first considered semiannual monitoring for these
sites as a baseline for comparison. Since 2016, owners and operators
have been conducting semiannual monitoring pursuant to NSPS OOOOa,
State requirements, or voluntarily, thus demonstrating the
reasonableness of that frequency. Additionally, the cost is comparable
to the costs found reasonable in the 2016 NSPS OOOOa \238\ for both the
single pollutant approach for methane or multipollutant approach for
both methane and VOC. To determine if quarterly monitoring is
reasonable for sites with total baseline methane emissions of 3 tpy, we
evaluated the incremental costs of going from semiannual to quarterly
monitoring. The incremental costs of semiannual to quarterly monitoring
for an emissions baseline of 3 tpy methane is $1,700/ton methane and
$6,000/ton VOC using the single pollutant approach (and $800/ton
methane and $3,000/ton VOC using the multipollutant cost effectiveness
approach). These incremental costs are within the range we find
reasonable in this proposal under the single pollutant approach for
methane and under the multipollutant approach.
---------------------------------------------------------------------------

    \238\ The 2020 Technical Rule amended only the VOC standards in
the 2016 NSPS OOOOa and, as discussed in section X.A, incorrectly
identified $738/ton as the highest value that the EPA found cost
effective for methane reduction in the 2016 NSPS OOOOa.
---------------------------------------------------------------------------

    We next evaluated monthly monitoring for this cohort. As shown in
Table 14, monthly monitoring appears reasonable under the
multipollutant approach. Therefore, we evaluated the incremental costs
of going from quarterly monitoring to monthly monitoring to determine
if monthly monitoring is appropriate. Table 15 summarizes these
incremental costs. As shown in Table 15, the incremental cost of going
from quarterly to monthly monitoring when baseline emissions are 3 tpy
is $13,000/ton methane and $47,000/ton VOC under the single pollutant
approach ($6,500/ton methane and $23,500/ton VOC under the
multipollutant approach). In both approaches, these costs are outside
the range of what we are proposing to consider cost effective. See
Section IX.B.
    Based on the analysis described above, we propose to find that
quarterly monitoring at well sites with total site-level baseline
methane emissions of 3 tpy or greater is the BSER. We note that
California requires quarterly inspections for all well sites under its
LDAR requirements in Code of Regulations, Title 17, Division 3, Chapter
1, Subchapter 10 Climate Change, Article 4, Article Subarticle 13:
Greenhouse Gas Emission Standards for Crude Oil and Natural Gas
Facilities, which supports a conclusion that quarterly monitoring at
these sites is feasible and cost-effective.\239\
---------------------------------------------------------------------------

    \239\ https://ww2.arb.ca.gov/sites/default/files/classic/regact/2016/oilandgas2016/ogfro.pdf.
---------------------------------------------------------------------------

    Accordingly, the EPA's primary proposal is to conclude that BSER
for well sites with total site-level baseline emissions of less than 3
tpy is no regular monitoring (but a one-time survey) and that BSER for
well sites with total site-level baseline emissions of 3 tpy or greater
is quarterly monitoring and repair.
    While the EPA is proposing quarterly OGI monitoring for well sites
with total site-level baseline methane emissions of 3 tpy or greater,
we are concerned this cost-effectiveness analysis may not fully account
for the numerosity and diversity of sites and their potential emission
profiles. We further note that some States with established fugitive
emissions monitoring programs have provided for more graduated
frequencies that recognize this diversity among sites. For example,
Colorado's Regulation 7 Control of Ozone via Ozone Precursors and
Control of Hydrocarbons via Oil and Gas Emissions \240\ requires a
tiered inspection frequency regime that provides for semiannual
monitoring at site-wide baseline emissions thresholds that far exceed
the EPA's proposed 3 tpy threshold. Under the Colorado regulations, a
semiannual inspection frequency is required for well production
facilities with uncontrolled actual VOC emissions between 2 and 12 tpy
(corresponding to approximately 7 to 43 tpy methane). Quarterly
inspections are required for well sites without storage tanks and with
uncontrolled actual VOC emissions between 12 and 20 tpy (corresponding
to approximately 43 to 72 tpy methane), and for well sites with storage
tanks and with uncontrolled actual VOC emissions between 12 and 50 tpy
(corresponding to approximately 43 to 180 tpy methane). Colorado
Regulation 7 also requires monthly inspections for well production
facilities without storage tanks with uncontrolled actual VOC emissions
above 20 tpy (and above 50 tpy for facilities with storage tanks). The
proposed thresholds for quarterly monitoring in this action are more
stringent than the Colorado regulations when compared using the gas
composition ratio of 0.28 VOC to methane that is used in our BSER
analysis. Specifically, the VOC emissions associated with a site-level
baseline methane emission rate of 3 tpy are 0.83 tpy VOC, less than
half the VOC threshold that requires semiannual monitoring and 14.5
times lower than the VOC threshold requiring quarterly monitoring in
Colorado.
---------------------------------------------------------------------------

    \240\ https://cdphe.colorado.gov/aqcc-regulations.
---------------------------------------------------------------------------

    Although Colorado's regulations are most directly comparable to the
EPA's proposed approach, other States also provide for more graduated
monitoring frequencies. For example, Ohio's General Permits 12.1 and
12.2 initially require quarterly monitoring for well sites, followed by
a reduced monitoring frequency of semiannual or annual monitoring
depending on the fraction of equipment found to be leaking.\241\
---------------------------------------------------------------------------

    \241\ https://epa.ohio.gov/dapc/genpermit/oil-and-gas-well-site-production.
---------------------------------------------------------------------------

    When considering these State programs, particularly the comparison
of our proposal to Colorado's thresholds; the fact that our cost-
effectiveness calculation may not account for the diversity of
emissions and sites; and the concerns we have raised regarding the
cost-effectiveness for businesses with fewer well sites than are
assumed in our cost-effectiveness analysis (many of whom we anticipate
are small businesses), the EPA believes it is also appropriate to co-
propose semiannual monitoring for well sites in a middle cohort--those
with total site-level baseline emissions of 3 tpy or greater and less
than 8 tpy. We seek comment on the number and ownership profile of
wells that would fall into this category to better understand whether
semiannual monitoring is an appropriate monitoring frequency for sites
in this range.
    To inform this analysis, we evaluated methane emissions in 1 tpy
increments starting at 3 tpy. Tables 15a and 15b summarize the total
costs and incremental costs of semiannual to quarterly for baseline
methane

emissions of 3 tpy or greater and less than 8 tpy.

              Table 15a--Summary of Total Cost-Effectiveness for Fugitive Monitoring at Well Sites
----------------------------------------------------------------------------------------------------------------
                                                      Single pollutant cost-           Multipollutant cost-
                                                           effectiveness                   effectiveness
   Site-level baseline methane    Annual cost ($/---------------------------------------------------------------
         emissions (tpy)             yr/site)       Methane ($/                     Methane ($/
                                                       ton)         VOC ($/ton)        ton)         VOC ($/ton)
----------------------------------------------------------------------------------------------------------------
                                              Semiannual Monitoring
----------------------------------------------------------------------------------------------------------------
3...............................          $3,200          $1,800          $6,400            $890          $3,200
4...............................           3,200           1,300           4,800             670           2,400
5...............................           3,200           1,100           3,800             530           1,900
6...............................           3,200             890           3,200             440           1,600
7...............................           3,200             760           2,700             380           1,400
8...............................           3,200             670           2,400             330           1,200
----------------------------------------------------------------------------------------------------------------
                                              Quarterly Monitoring
----------------------------------------------------------------------------------------------------------------
3...............................           4,200           1,800           6,300             880           3,200
4...............................           4,200           1,300           4,700             660           2,400
5...............................           4,200           1,000           3,800             530           1,900
6...............................           4,200             880           3,200             440           1,600
7...............................           4,200             750           2,700             380           1,400
8...............................           4,200             660           2,400             330           1,200
----------------------------------------------------------------------------------------------------------------

           Table 15B--Summary of Incremental Cost-Effectiveness for Fugitive Monitoring at Well Sites
----------------------------------------------------------------------------------------------------------------
                                                    Incremental                   Incremental cost-effectiveness
                                    Incremental       methane       Incremental  -------------------------------
   Site-level baseline methane    annual cost ($/    emission      VOC emission
         emissions (tpy)             yr/site)     reduction (tpy/ reduction (tpy/   Methane ($/     VOC ($/ton)
                                                       site)           site)           ton)
----------------------------------------------------------------------------------------------------------------
                                     Incremental for semiannual to quarterly
----------------------------------------------------------------------------------------------------------------
3...............................          $1,000            0.60            0.17          $1,700          $6,000
4...............................           1,000            0.80            0.22           1,250           4,500
5...............................           1,000            1.00            0.27           1,000           3,600
6...............................           1,000            1.20            0.33             840           3,000
7...............................           1,000            1.40            0.39             720           2,600
8...............................           1,000            1.60            0.45             630           2,250
----------------------------------------------------------------------------------------------------------------

    While there is no obvious cutoff point, the EPA anticipates that
well sites with calculated baseline emissions of 8 tpy or greater will
generally consist of complex sites comprising multiple wellheads and/or
one or more of the major pieces of production or processing equipment
that are known to have a propensity for causing large emissions events.
The EPA also believes it is possible that at 8 tpy and greater, well
sites are both more likely to be owned by companies with a larger
number of sites and that the owners of these wells are likely to be
larger companies. Lastly, the EPA estimates that a large share of
fugitive emissions (approximately 54%) can be attributed to wells with
site-wide baseline emissions of 8 tpy or greater.\242\ For these
reasons, the EPA believes that an 8 tpy threshold for quarterly
monitoring would appropriately focus resources on the wells with the
largest emissions profiles, and that concerns about on the costs for
small owners or operators are most attenuated for this cohort of
relatively large and high-emitting sites. As noted above, we seek
comment on whether it is sensible to have a middle cohort with a
semiannual monitoring requirement and, if so, what the bounds of that
cohort should be. In making this determination, the EPA is particularly
interested in comments regarding the number and ownership profiles of
well sites that may fall into this middle cohort.
---------------------------------------------------------------------------

    \242\ Percentage estimated using the analysis underpinning the
baseline scenario in the RIA for the 2030 analysis year.
---------------------------------------------------------------------------

    As required by section 111, the EPA's proposed BSER analysis for
fugitive emissions from all well sites has considered nonair quality
health and environmental impacts. No secondary gaseous pollutant
emissions or wastewater are generated during the monitoring and repair
of fugitive emissions components. There are some emissions that would
be generated by contractors conducting the OGI camera monitoring
associated with driving to and from the site for the fugitive emissions
survey. Using AP-42 mobile emission factors and assuming a distance of
70 miles to the well site, the emissions generated from semiannual
monitoring at a well site (140 miles to and from the well site twice a
year) is estimated to be 0.35 lb/yr of hydrocarbons, 6.0 lb/yr of CO
and 0.40 lb/yr of NOx. No other secondary impacts are
expected. We do not believe these secondary emissions are so
significant as to affect the proposed determinations described above.
    In summary, based on the analysis described above, the EPA is
proposing OGI monitoring based on tiered total site-wide baseline
methane emission levels to represent thresholds that would determine
the monitoring frequency. For well sites with total site-level methane
emissions less than 3 tpy,

the EPA is proposing to require a one-time survey to demonstrate that
the well site is free of leaks or other abnormal conditions that are
not accounted for in the baseline calculation. For well sites with
total site-level methane emissions of 3 tpy or greater, the EPA is
proposing quarterly monitoring at all sites. Lastly, the EPA is co-
proposing semiannual monitoring for well sites with total site-level
methane emissions of 3 tpy or greater and less than 8 tpy, and
quarterly monitoring for all sites with baseline emissions of 8 tpy or
greater. As noted earlier, site-level baseline emission levels would be
calculated by owners and operators for each site based on prescribed
population emission factors for components and equipment at the site,
combined with an assessment of potential methane emission from storage
vessels (after applying controls).
b. Fugitive Emissions From Compressor Stations
    The EPA continues to utilize the model plant approach in estimating
baseline fugitive emissions from compressor stations. Unlike well
sites, we believe that compressor station designs are less variable and
that model plants are an effective construct to analyze fugitive
emission control programs. The EPA has evaluated feedback received from
several industry stakeholders related to development of compressor
station model plants over multiple years since the original 2015 NSPS
OOOOa proposal were model plants for compressor stations (including
those at gathering and boosting stations, transmission stations, and
storage facilities) were first introduced. Consistent with this early
approach for estimating emissions from compressor stations, the EPA
still believes the model plant approach is the best way to assess
fugitive emissions from compressor stations, in the absence of
information indicating otherwise. Baseline model plant emissions for
compressor stations can reasonably be calculated using equipment
counts, fugitive emissions component counts, and emissions factors from
the 1995 Emissions Protocol. The EPA has evaluated each specific model
plant for gathering and boosting, transmission, and storage, based on
information that has become available, and model plants were updated
where information indicated an update was appropriate. For example,
information from actual compressor stations in operation provided by
GPA Midstream for several of their member companies representing
numerous sites across the country, was used to refine the gathering and
boosting model plant in 2020. Refinements have also been made to the
transmission and storage model plants based on information received
from companies in these segments. The size and equipment located at
compressor stations do not vary as widely as at well sites, and
therefore emissions are expected to be less variable as well.
Furthermore, stakeholders have not indicated that a model plant
approach is not reasonable. For these reasons, the EPA retains a model
plant approach for compressor stations which are representative in
estimating fugitive emissions.
    There are three types of compressor stations in the Crude Oil and
Natural Gas source category: (1) Gathering and boosting stations, (2)
transmission stations, and (3) storage stations. The equipment
associated with these compressor stations vary depending on the volume
of natural gas that is transported and whether any treatment of the gas
occurs, such as the removal of water or hydrocarbons. The model plants
developed for these sites include all equipment (including piping and
associated components, compressors, generators, separators, storage
vessels, and other equipment) and associated components (e.g., valves
and connectors) that may be sources of fugitive emissions associated
with these operations. One model plant was developed for each of the
three types of compressor stations described above, which are discussed
in detail in the 2020 NSPS OOOOa TSD and in the NSPS OOOOb and EG TSD
supporting this action. For gathering and boosting stations, the
fugitive baseline emissions were estimated to be 16.6 tpy of methane
and 4.6 tpy of VOC. For transmission stations, the fugitive baseline
emissions were estimated to be 40.4 tpy of methane and 1.1 tpy of VOC.
For storage stations, the fugitive baseline emissions were estimated to
be 142.2 tpy of methane and 3.9 tpy of VOC.
    As with well sites, in the original BSER analysis for the 2016 NSPS
OOOOa rulemaking, two options for reducing fugitive methane and VOC
emissions at compressor stations were identified, which were (1) a
fugitive emissions monitoring program based on individual component
monitoring using EPA Method 21 for detection combined with repairs and
(2) a fugitive emissions monitoring program based on the use of OGI
detection combined with repairs. Finding that both methods achieve
comparable emission reduction but OGI was more cost effective, the EPA
ultimately identified quarterly monitoring of compressor stations using
OGI as the BSER. 81 FR 35862. While there are several new fugitive
emissions technologies under development, the EPA needs additional
information and better understanding of these technologies, and they
are therefore not being evaluated as potential BSER at this time. For
this analysis for both the NSPS and the EG, we re-evaluated OGI as
BSER. In the discussion below, we evaluate OGI control options based on
varying the frequency of conducting the survey and fugitive emissions
repair threshold (i.e., the visible identification of methane or VOC
when an OGI instrument is used). For this analysis, we considered
annual, semiannual, quarterly, and monthly survey frequency for
compressor stations.
    In 2015, we evaluated the potential emission reductions from the
implementation of an OGI monitoring program where an emission reduction
of 40, 60 and 80 percent for annual, semiannual, and quarterly
monitoring survey frequencies, respectively, were determined
appropriate. No other information reviewed since 2015 indicates that
the assigned reduction frequencies are different than previously
established and the reduction efficiencies are consistent with what
current information indicates. In addition, we also evaluated monthly
monitoring for compressor stations where information evaluated
indicated monthly OGI monitoring has the potential of reducing
emissions up towards 90 percent.
    We evaluated the costs of monitoring and repair under various
monitoring frequencies described above, including the cost of OGI
monitoring via the camera survey, repair costs, resurvey costs,
monitoring plan development and the cost of a recordkeeping system. For
compressor stations, the capital cost associated with the fugitives
monitoring program were estimated to be $3,090 for each gathering and
boosting compressor station, which includes development of a fugitive
emissions monitoring plan for a company-defined area (assumed to
include 7 gathering and boosting compressor stations) and database
management development or licensing for recordkeeping. These capital
costs are divided evenly amongst the 7 gathering and boosting
compressor stations in the company-defined area for purposes of the
model plant analysis, consistent with the 2016 NSPS OOOOa and 2020
Technical Rule analyses. The capital cost associated with the fugitives
monitoring program for transmission and storage compressor stations was
estimated at $23,880, which is for a single transmission and storage
compressor station. The annual costs

include the capital recovery cost (calculated at a 7 percent interest
rate for 10 years), survey and repair costs, database management fees,
and recordkeeping and reporting costs. The annual costs estimated for
compressor stations range from $6,350 for annual monitoring to $33,220
for monthly monitoring at gathering and boosting compressor stations.
For transmission compressor stations, the annual costs estimated range
from $12,900 for annual monitoring to $39,770 for monthly monitoring.
For storage compressor stations, the annual costs estimated range from
$17,000 for annual monitoring to $43,860 for monthly monitoring.
    As discussed above, the EPA is proposing that natural gas-driven
intermittent vent controllers at production and natural gas
transmission sites in Alaska without electricity would be subject to a
standard that prohibits emissions when the controller is idle.
Intermittent pneumatic controllers are designed to vent during
actuation only, but these devices are known to malfunction and operate
incorrectly which causes them to release natural gas to the atmosphere
when idle. For sites in Alaska that do not have electricity located in
the production segment (well sites, gathering and boosting stations,
and centralized tank batteries) and in the transmission and storage
segment, the EPA is proposing to define intermittent natural gas-driven
pneumatic controllers as an affected facility and proposing to apply a
standard that these controllers only vent during actuation and not when
idle. See section XII.C on pneumatic controllers for a full explanation
of this standard. We have determined that it would be efficient and
reasonable to verify proper actuation and that venting does not occur
during idle times by proposing that these devices are monitored along
with fugitive emissions components at a site to ensure these devices
are meeting the standard. We believe the cost of monitoring of
intermittent pneumatic controllers will be absorbed by the cost of the
fugitive emissions program, and that little to no additional cost would
be associated with monitoring these devices on the fugitive emissions
components monitoring schedule. If compressor stations have
electricity, they would be required to have non-emitting controllers,
and no additional costs are expected to be incurred relayed to repair
and/or replacement of malfunctioning intermittent vent controllers.
    At gathering and boosting compressor stations there are savings
associated with the gas not being released. The value of the natural
gas saved is assumed to be $3.13 per Mcf of recovered gas. Transmission
and storage compressor stations do not own the natural gas; therefore,
revenues from reducing the amount of natural gas emitted/lost was not
applied for this segment.
    The EPA evaluated the cost-effectiveness of monitoring for each
sub-type of compressor station, starting with evaluating whether
quarterly monitoring remains the BSER. The 2016 NSPS OOOOa requires a
fugitive emissions monitoring and repair program, where compressor
stations have to be monitored quarterly. Compressor stations have
successfully met this standard. Further, several State agencies have
rules that require quarterly monitoring at compressor stations. For
example, Colorado's Regulation 7 Control of Ozone via Ozone Precursors
and Control of Hydrocarbons via Oil and Gas Emissions \243\ requires a
semiannual inspection frequency for compressor stations with
uncontrolled actual VOC emissions between 2 and 12 tpy, a quarterly
inspection frequency for compressor stations with uncontrolled actual
VOC emissions between 12 and 50 tpy, and monthly inspections for
compressor stations with uncontrolled actual VOC emissions above 50
tpy. California requires quarterly inspections under their LDAR
requirements \244\ and similarly, Ohio's General Permit 18.1 also
requires quarterly monitoring for compressor stations.\245\ These
examples of State rules, where quarterly monitoring appears to be the
lowest monitoring frequency required with one exception where the VOC
baseline emissions were extraordinarily high, is a demonstration of the
reasonableness of monitoring fugitive emissions components on a
quarterly basis for compressor stations.
---------------------------------------------------------------------------

    \243\ https://cdphe.colorado.gov/aqcc-regulations.
    \244\ https://ww2.arb.ca.gov/sites/default/files/classic/regact/2016/oilandgas2016/ogfro.pdf.
    \245\ https://www.epa.state.oh.us/dapc/genpermit/ngcs/GP_181.
---------------------------------------------------------------------------

    Given the apparent reasonableness of quarterly monitoring as
discussed above, the EPA evaluated whether it was reasonable to require
monthly monitoring for compressor stations. Table 16 summarizes the
cost, emission reductions, and cost-effectiveness of quarterly and
monthly OGI monitoring at compressor stations for the single pollutant
approach, while Table 17 summarizes the multi-pollutant approach.

                     Table 16--Summary of the Single Pollutant Cost of Control for Compressor Station Fugitive Emissions Monitoring
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Emission reductions        Methane cost     VOC cost of
                                           Capital cost   Annual cost ($/ Annual cost w/ -------------------------------- of control w/o    control w/o
               Model plant                      ($)             yr)       savings ($/yr)  Methane  (tons/                   savings ($/     savings ($/
                                                                                yr)        VOC (tons/yr)       ton)            ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                  Quarterly Monitoring
--------------------------------------------------------------------------------------------------------------------------------------------------------
Gathering & Boosting....................          $3,100         $13,400         $11,000            13.3             3.7          $1,000          $3,600
Transmission............................          23,900          19,900          19,900            32.3             0.9             600          22,300
Storage.................................          23,900          24,000          24,000           114.0             3.2             200           7,600
                                         ---------------------------------------------------------------------------------------------------------------
    Compressor Program Weighted Average.  ..............  ..............  ..............  ..............  ..............             900           4,400
                                         ---------------------------------------------------------------------------------------------------------------
                                                                   Monthly Monitoring
--------------------------------------------------------------------------------------------------------------------------------------------------------
Gathering & Boosting....................           3,100          33,200          30,500            15.0             4.2           2,200           8,000
Transmission............................          23,900          39,800          39,800            36.4             1.0           1,100          39,500
Storage.................................          23,900          43,900          43,900           128.2             3.5             340          12,400
                                         ---------------------------------------------------------------------------------------------------------------
    Compressor Program Weighted Average.  ..............  ..............  ..............  ..............  ..............           1,800           9,300
--------------------------------------------------------------------------------------------------------------------------------------------------------

                      Table 17--Summary of the Multi-Pollutant Cost of Control for Compressor Station Fugitive Emissions Monitoring
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Emission reductions        Methane cost     VOC Cost of
                                           Capital cost   Annual cost ($/ Annual cost w/ -------------------------------- of control w/o    control w/o
               Model plant                      ($)             yr)       savings ($/yr)  Methane (tons/                    savings ($/     savings ($/
                                                                                yr)        VOC (tons/yr)       ton)            ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                  Quarterly Monitoring
--------------------------------------------------------------------------------------------------------------------------------------------------------
Gathering & Boosting....................          $3,100         $13,400         $11,000            13.3             3.7            $500          $1,800
Transmission............................          23,900          19,900          19,900            32.3             0.9             300          11,100
Storage.................................          23,900          24,000          24,000           114.0             3.2             100           3,800
                                         ---------------------------------------------------------------------------------------------------------------
    Compressor Program Weighted Average.  ..............  ..............  ..............  ..............  ..............             430           2,200
                                         ---------------------------------------------------------------------------------------------------------------
                                                                   Monthly Monitoring
--------------------------------------------------------------------------------------------------------------------------------------------------------
Gathering & Boosting....................           3,100          33,200          30,500            15.0             4.2           1,100           4,000
Transmission............................          23,900          39,800          39,800            36.4             1.0             550          19,800
Storage.................................          23,900          43,900          43,900           128.2             3.5             200           6,200
                                         ---------------------------------------------------------------------------------------------------------------
    Compressor Program Weighted Average.  ..............  ..............  ..............  ..............  ..............             900           4,600
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Based on the single pollutant approach, both quarterly and monthly
frequencies are reasonable for methane emissions, while only quarterly
is reasonable for VOC emissions. Like described for well sites, owners
and operators of compressor stations have been monitoring quarterly
since 2016 pursuant to NSPS OOOOa, State requirements, or voluntarily,
which suggests these costs are reasonable. These costs for quarterly
monitoring are also comparable to those found reasonable in both the
2016 NSPS OOOOa and the 2020 Technical Rule. Further, both frequencies
are reasonable under the multipollutant approach when considering the
total cost-effectiveness compared to a baseline of no OGI monitoring.
    The EPA then looked at the incremental costs of going from
quarterly to monthly monitoring. Quarterly monitoring achieves an
emission reduction ranging from 13.3 tpy at gathering and boosting
compressor stations to 114 tpy at storage compressor stations. Monthly
monitoring achieves additional reductions ranging from 1.7 tpy at
gathering and boosting compressor stations to 14.2 tpy at storage
compressor stations. However, these additional reductions are achieved
at $9,400/ton methane (and nearly $50,000/ton VOC). The EPA finds that
achieving these additional emissions reductions is not reasonable for
the cost, given the only small fraction of additional reductions
realized at monthly monitoring. Based on the cost analysis summarized
above, we find that the cost effectiveness of quarterly monitoring for
compressor stations is reasonable.
    Finally, no secondary gaseous pollutant emissions or wastewater are
generated during the monitoring and repair of fugitive emissions
components. There are some emissions that would be generated by the OGI
camera monitoring contractors with respect to driving to and from the
site for the fugitive emissions survey. Using AP-42 mobile emission
factors and assuming a distance of 70 miles to the compressor station,
the emissions generated from quarterly monitoring at a compressor
station (140 miles to and from the compressor station four times a
year) is estimated to be 0.70 lb/yr of hydrocarbons, 12.0 lb/yr of CO
and 0.80 lb/yr of NOX. No other secondary impacts are
expected.
    In light of the above, we find that the BSER for reducing methane
and VOC emissions from all compressor stations, including gathering and
boosting stations, transmission stations, and storage stations is
quarterly monitoring for this proposal. Therefore, for NSPS OOOOb, we
are proposing to require quarterly monitoring for all compressor
stations.
2. EG OOOOc
    The EPA also evaluated BSER for the control of fugitive emissions
at existing well sites and compressor stations. The findings were that
the controls evaluated for new sources for NSPS OOOOb are appropriate
for consideration under the EG OOOOc. Further, the EPA finds that the
OGI monitoring, methane emission reductions, costs, and cost
effectiveness results discussed above for new sources are also
applicable for existing sources.
    Therefore, for the EG OOOOc, the EPA is proposing presumptive
standards to require quarterly monitoring for well sites with site-
level baseline methane emissions greater than and equal to 3 tpy.
Further, we are co-proposing semiannual monitoring for well sites with
site-level baseline methane emissions greater than and equal to 3 tpy
and less than 8 tpy, and quarterly monitoring for well sites with site-
level baseline methane emissions greater than and equal to 8 tpy. We
find the costs reasonable for existing well sites with total site-level
baseline methane emissions greater than or equal to 3 tpy to conduct
quarterly OGI monitoring at an incremental cost of $1,700/ton methane
reduced. We are aware that there is a large percentage of existing well
sites that are likely owned and operated by small businesses. We
continue to be concerned about the burden of frequent OGI monitoring on
these small businesses and are requesting comment consistent with our
solicitation for new sources.
    The EPA also finds, and is proposing, that the BSER for reducing
methane emissions from all existing compressor stations, including
gathering and boosting stations, transmission stations, and storage
stations is quarterly monitoring. For compressor stations, we find that
both quarterly (at $430/ton methane reduced) and monthly monitoring (at
$900/ton methane reduced) are reasonable when looking at total cost-
effectiveness against a baseline of no monitoring, however, at an
incremental cost of $9,400/ton methane reduced, monthly monitoring is
not reasonable. Therefore, for the EG OOOOc, we are proposing a
presumptive standard of quarterly monitoring for all compressor
stations.

3. Alternative Screening Using Advanced Measurement Technology
    As discussed throughout this preamble, the EPA recognizes the
existence large emission events. In certain instances, these situations
could be caused by severely and continuously leaking components that
would be identified and corrected via the routine OGI-based periodic
monitoring program, but only on a quarterly or semiannual basis.
Moreover, some large emission events are intermittent and stochastic in
nature and may not be identified via these OGI surveys. Since the 2016
NSPS OOOOa, significant strides have occurred in developing and
deploying methane detection technologies that can detect fugitive
emissions (especially large emission events) in a potentially faster
and more cost-effective manner than traditional techniques such as OGI
and EPA Method 21. The EPA has continued following the development of
these technologies and their applications through various public
programs, such as the DOE ARPA-E programs, which have focused on the
development of cost-effective tools to locate and measure methane
emissions. Additionally, the EPA has continued discussions with
stakeholders, including academic researchers and private industry, as
they develop and evaluate novel tools for the detection and
quantification of methane emissions in the oil and gas sector. As noted
in section VII.B, the EPA also held a two-day workshop in August 2021
to hear perspectives on these new technologies. Some of the promising
technologies now emerging include, but are not limited to, fixed-base
and open path sensor networks, unmanned aircraft systems (UAS) equipped
with methane detection equipment, the use of high-end instruments for
mobile measurements on the ground and in the air, and satellite
observations with advanced optical techniques.
    As the EPA learned during the Methane Detection Technology
Workshop, industry has utilized these advanced measurement technologies
to supplement existing fugitive emissions programs and to quickly
identify unexpected emissions events (e.g., emissions from controlled
storage vessels) in order to make repairs as quickly as possible.\246\
While most of these advanced measurement technologies are not sensitive
enough to pin-point the exact same emission sources as the current
fugitive emission detection programs, many can more quickly detect the
largest emissions sources (e.g., malfunctions and undersized or non-
performing major equipment), and they can also find emissions that may
be missed by fugitive emission surveys (e.g., component-level leaks on
valves, connectors, and meters). Moreover, the EPA understands the
stochastic nature, distribution, and frequency of these large emission
events across sites and over time is uncertain, and that these events
occur sporadically at an individual site in ways that may take longer
to detect or might not be detected through a periodic fugitive
emissions survey using traditional technologies. Integrating advanced
emission detection technologies into this rule--whether deployed by
owner-operators themselves or by third parties--could be a valuable way
to reduce fugitive emissions more cost-effectively and rapidly detect
and remedy ``super-emitting'' events that make an outsize contribution
to overall emissions from this source category.
---------------------------------------------------------------------------

    \246\ See summary report of the EPA's Methane Detection Workshop
located at Docket ID No. EPA-HQ-OAR-2021-0317.
---------------------------------------------------------------------------

    There are many other advantages to these advanced measurement
technologies over technologies currently used for fugitive emissions
detection (i.e., OGI and EPA Method 21 technologies). For instance,
these advanced measurement technologies may be less susceptible to
operator error or judgment than traditional methods of leak detection,
thus making surveys more consistent and reliable. Many of these
technologies can survey broader areas than can be effectively surveyed
with field personnel, drastically reducing the driving time from site
to site, which could have potential cost and safety benefits and allow
for more frequent monitoring, which could allow for the identification
and mitigation of large volume methane emissions sooner than OGI or EPA
Method 21 surveys.
    As described in section XI.A.5, the EPA is proposing an alternative
work practice for detecting fugitive emissions that incorporates these
advanced measurement technologies. There were a number of presentations
during the Methane Detection Technology Workshop that discussed the
detection capabilities of various methane measurement technologies
which could be used for a screening approach. Given the diverse array
of advanced technologies that are now in use, and the rapid pace at
which these technologies are being refined and new technologies are
being developed, the EPA believes that it is appropriate to articulate
a foundational set of performance criteria and documentation
requirements for this alternative work practice that can be applied to
multiple existing and forthcoming technologies. Based on the
information available to the Agency, including the information
presented in the Methane Detection Technology Workshop, the EPA
believes setting a minimum detection threshold of 10 kg/hr methane
might be appropriate for use in determining what technologies and in
what deployment platforms (e.g., fixed, ground and aerial) are
appropriate for a potential screening alternative within the proposed
NSPS OOOOb and EG OOOOc. Therefore, the specific alternative work
practice that the EPA is proposing includes a provision that would
allow the use of any technology with a minimum detection threshold of
10 kg/hr.
    Although we have focused this discussion on advanced measurement
technologies, the EPA is also soliciting comment on whether there are
ways to utilize existing technologies to screen for large emission
events. For example, could gauges or meters be utilized to identify
potential large losses between the wellhead and the custody meter
assembly.
    Further, the EPA is seeking comment on very simple AVO checks that
could be performed in conjunction with the periodic OGI monitoring
surveys to help identify potential large emission events. For example,
two often-cited causes of super-emitter sources are unlit flares and
separator dump valves that are stuck open allowing unintentional gas
carry-through to emit from storage vessels. The additional time and
cost required to perform visual inspections to see if the flare pilot
light is working, or to see if a dump valve is stuck open, would be
minimal. Yet the benefits of simple AVO inspections could be
significant. The EPA is soliciting comment on this concept, as well as
comments on the common items that could be included on a checklist for
such low-burden AVO inspections in conjunction with fugitive
monitoring.

B. Proposed Standards for Storage Vessels

1. NSPS OOOOb
a. Background
    In the 2012 NSPS OOOO, the EPA established VOC standards for
storage vessels. Based on our review of these standards, we are
proposing to retain the current standard of 95 percent reduction.
However, the EPA is proposing to redefine the affected facility to
include a tank battery. Specifically, the EPA is proposing to define a
storage vessel affected facility as a single storage vessel or a group
of storage vessels that are physically adjacent and that receive fluids
from the

same source (e.g., well, process unit, or set of wells or process
units) or manifolded together for the transfer of liquid or vapors. In
this definition, we consider tanks to be physically adjacent when they
are near or next to each other and may or may not be connected or piped
together. In addition, the EPA is proposing methane standards for new,
reconstructed, and modified storage vessels under the proposed NSPS
OOOOb. Both the proposed revised VOC standards and the proposed methane
standards would be the same (i.e., 95 percent reduction of emissions
from storage vessel affected facilities as defined above in this
proposal). These reductions can be achieved by utilizing a cover and
closed vent system to capture and route the emissions to a control
device that achieves an emission reduction of 95 percent, or by routing
the captured emissions to a process.
    Both methane and VOC emissions from storage vessels are a result of
working, breathing and flashing losses. Working losses occur when
vapors are displaced due to the emptying and filling of storage
vessels. Breathing losses are the release of gas associated with daily
temperature fluctuations when the liquid level remains unchanged.
Flashing losses occur when a liquid with dissolved gases is transferred
from a vessel with higher pressure (e.g., separator) to a vessel with
lower pressure (e.g., storage vessel), thus allowing dissolved gases
and a portion of the liquid to vaporize or flash. In the Crude Oil and
Natural Gas source category, flashing losses occur when crude oils or
condensates flow into a storage vessel from a separator operated at a
higher pressure. Typically, the higher the operating pressure of the
upstream separator, the greater the flash emissions from the storage
vessel. Temperature of the liquid may also influence the amount of
flash emissions. Lighter crude oils and condensate generally flash more
hydrocarbons than heavier crude oils.
b. Definition of Affected Facility
    The current standards apply to single storage vessels with
potential VOC emissions of 6 tpy or greater, although the EPA has long
observed that these storage vessels are typically located as part of a
tank battery. 76 FR 52738, 52763 (Aug. 23, 2011). Further, the 6 tpy
applicability threshold was established by directly correlating VOC
emissions to throughput, was based on the use of a single combustion
control device, regardless of the number of storage vessels routing
emissions to that control device, and control of 6 tpy VOC was cost
effective using that single control device. Id. at 52763-64. Over the
years, there have been questions and issues raised regarding how to
calculate the potential VOC emissions from individual storage vessels
that are part of a tank battery. The EPA attempted to address this
issue through various amendments to NSPS OOOO and NSPS OOOOa,\247\ most
recently in the 2020 Technical Rule. In the 2020 Technical Rule, the
EPA continued to recognize that tank batteries are more prevalent than
individual storage vessels. While the 2020 Technical Rule included
amendments to the calculation methodology for determining potential VOC
emissions from storage vessels that are part of a tank battery, the EPA
has now determined that it is more appropriate to evaluate the control
of methane and VOC emissions from tank batteries \248\ as a whole
instead of each individual storage vessel within a tank battery.\249\
In this review the EPA evaluated regulatory options based on the use of
a single control device to reduce both methane and VOC emissions from a
tank battery, which is consistent with the 2012 NSPS OOOO, 2016 NSPS
OOOOa, and subsequent amendments to each of those rules. The EPA
believes that this approach will simplify applicability criteria for
owners and operators of storage vessels, and more accurately aligns
with the EPA's original intent of how storage vessel affected facility
status should be determined.
---------------------------------------------------------------------------

    \247\ See 79 FR 79018 and 80 FR 48262.
    \248\ For purposes of this analysis and the resulting proposed
standards, the term ``tank battery'' refers to a single storage
vessel or a group of storage vessels that are physically adjacent
and that receive fluids from the same source (e.g., well, process
unit, or set of wells or process units) or which are manifolded
together for liquid or vapor transfer.
    \249\ This approach would no longer allow facilities to apply
certain criteria and average the total potential VOC emissions of
the tank battery across the number of storage vessels in the battery
to determine a per-vessel potential for VOC emissions.
---------------------------------------------------------------------------

c. Modification
    Section 60.14(a) of the general provisions to part 60 defines
modification as follows: ``Except as provided in paragraphs (e) and (f)
of this section, 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. . . .'' We also note that 40 CFR 60.14(f)
states that ``Applicable provisions set forth under an applicable
subpart of this part shall supersede any conflicting provisions of this
section.'' The EPA understands the difficulty assessing emissions from
storage vessels and seeks to provide clarity on actions that are
considered modification of a tank battery by explicitly listing these
in the proposed NSPS OOOOb. We evaluated circumstances that would lead
to an increase in the VOC and methane emissions from a tank battery and
therefore constitute a modification of an existing tank battery. A
modification of an existing tank battery would then require the tank
battery owner or operator to assess the potential emissions relative to
the proposed NSPS instead of the EG.
    The EPA is proposing that a single storage vessel or tank battery
is modified when any of the following physical or operational changes
are made: (1) The addition of a storage vessel to an existing tank
battery; (2) replacement of a storage vessel such that the cumulative
storage capacity of the existing tank battery increases; and/or (3) an
existing single storage vessel or tank battery that receives additional
crude oil, condensate, intermediate hydrocarbons, or produced water
throughput (from actions such as refracturing a well or adding a new
well that sends these liquids to the tank battery). For both items 1
and 2, even if the type and quantity of fluid processed remains the
same, the increased storage capacity will lead to higher breathing
losses and thereby increase the VOC emissions from the tank battery
relative to the VOC emissions prior to the vessel addition or
replacement. Therefore, we conclude that these actions are a
modification of the tank battery. However, we are soliciting comment to
help us better understand the effect of the proposed definition number
1 and 2 on the number of new storage vessels or tank batteries that
would be subject to the NSPS. Under the current definition of a storage
vessel affected facility in NSPS OOOOa, which is each single storage
vessel that meets the 6 tpy applicability threshold, a new storage
vessel that is installed in an existing tank battery is an affected
facility (assuming the 6 tpy applicability threshold is met for the
single storage vessel) whether the new storage vessel is a replacement
or an addition to the tank battery. However, under the proposed
definition number 1 and 2 above, the NSPS OOOOb is triggered only if
the new storage vessel is an addition to the tank battery or is of
bigger capacity than the storage vessel it is replacing in a tank
battery. We therefore solicit comment on how often a storage vessel in
a tank battery is replaced with one that is of bigger capacity, or
whether the need to increase a tank battery's capacity is

generally accomplished by adding storage vessels as opposed to
replacing an existing one with a bigger one. We further solicit comment
on whether, under our proposed definition of a tank battery (i.e., a
single storage vessel or a group of storage vessels that are physically
adjacent and that receive fluids from the same source (e.g., well,
process unit, or set of wells or process units)), the replacement of a
storage vessel in a tank battery should also require the assessment of
the potential VOC and methane emissions from the tank battery.
    Item 3 will increase the volumetric throughput of the tank battery
relative to the throughput prior to storage of the additional fluid.
This will increase the working losses and potentially increase the
flashing losses from the tank battery, depending on the properties of
the new fluid stream. In any event, adding a new fluid stream to an
existing tank battery increases the VOC emissions from that tank
battery relative to just prior to the addition of a new fluid stream
and is therefore considered a modification of the tank battery.
    The EPA is proposing to require that the owner or operator
recalculate the potential VOC emissions when any of these actions occur
on an existing single storage vessel or tank battery to determine if
the modification may require control of VOC emissions. The existing
single storage vessel or tank battery will only become subject to the
proposed NSPS if it is modified pursuant to this proposed definition of
modification and its potential VOC emissions exceed the proposed 6 tpy
VOC emissions threshold for the tank battery.
d. Technology Review
    The available control techniques for reducing methane and VOC
emissions from storage vessels include routing the emissions from the
storage vessels to a combustion control device or a VRU, which would
route the emission to a process (including a gas sales line). These are
the same control systems that were evaluated under the 2012 NSPS OOOO.
While floating roofs can also be used to reduce emissions from many
storage vessel applications, including at natural gas processing plants
and compressor stations, floating roofs are not effective at reducing
emissions from storage vessels that have flashing losses (e.g., storage
vessels at well sites or centralized production facilities). Besides
the control options described above, we did not find other available
control options through our review, including review of the RACT/BACT/
LAER Clearinghouse.
    In the development of the 2012 NSPS OOOO, we found that using
either a VRU or a combustion control device could achieve a 95 percent
or higher VOC emission reduction efficiency. Available information
since then continues to support that such devices can achieve a 95
percent control efficiency for both methane and VOC emissions. We are
not proposing to require higher control efficiency because, in order to
achieve a minimum of 95 percent control efficiencies on a continuous
basis, operators will need to design and operate the control to achieve
greater than 95 percent. Thus, while the control device may commonly
operate at greater than 95 percent control efficiencies, there may be
process fluctuations in heat loads, inlet backpressure, and other
variables that may affect performance that may lower the control
efficiencies achieved. For example, there are field conditions, such as
high winds that may influence combustion efficiencies.\250\ We also
note that, while the EPA established operating and monitoring
requirements to ensure flares achieve a 98 percent control efficiency
at petroleum refineries in 40 CFR part 63, subpart CC, these
requirements include sophisticated monitoring and operational controls
and tend to lead to additional fuel use and greater secondary impacts
than combustion systems targeting to achieve a minimum of 95 percent
control efficiency. Considering these factors, we conclude that,
consistent with CAA section 111(a) definition of a ``standard of
performance,'' 95 percent control efficiency as the minimum allowable
control efficiency at any time continues to reflect ``the degree of
emission limitation achievable'' through the application of the BSER
for tank batteries (a combustor or a VRU). We solicit comment on the
issues described above for requiring higher than 95 percent
reduction.\251\
---------------------------------------------------------------------------

    \250\ EPA. April 2012. Parameters for Properly Designed and
Operated Flares. Prepared for U.S. Environmental Protection Agency,
Office of Air Quality Planning and Standards, Research Triangle
Park, NC.
    \251\ Further, in section XIII.E (solicitation of comment on
control device efficiency), the EPA solicits comment on the level of
reduction that can be reliably achieved using a flare and what
measures need to be in place to assure such reduction.
---------------------------------------------------------------------------

    During pre-proposal outreach, some small businesses raised a
concern that the NSPS OOOOa requirement for a continuous pilot light
for a storage vessel control device generated more emissions than it
prevented for storage vessels with low emissions. Specifically, small
business representatives raised concerns that there are situations
where propane or other fossil fuel must be used to maintain continuous
pilot lights for flares used as control devices on storage vessels that
do not produce enough emissions. The EPA is interested in whether the
benefits of reducing emissions with these control devices are negated
by the need to burn additional fossil fuels and whether there are
additional factors that lead to variability in emissions from storage
vessels that could be used to more narrowly target these requirements
to limit the unnecessary operation of flares. We are soliciting comment
from all stakeholders on this issue.
e. Control Options and BSER Analysis
    For this proposal, the EPA evaluated regulatory options based on
different potential emissions thresholds for VOC and methane. We
assumed the potential tank battery emissions were reduced by 95 percent
using either a VRU or a combustion control device. Since VRUs recover
saleable products, we also estimated the value of the recovered product
when VRUs were used. The EPA encourages the use of VRUs to capture and
sell the emissions from the storage vessels by classifying VRUs as part
of the process, therefore emission recovered would not be included in
the potential emissions at a site.
    For new, modified, or reconstructed sources, we evaluated the cost
of control using a single combustion device (or VRU) on a single
storage vessel as well as a tank battery made up of multiple storage
vessels. To do this, we evaluated the use of a single control device
achieving 95 percent reduction of VOC and methane emissions at the
following potential emission thresholds: 6 tpy VOC from a single
storage vessel; 3 and 6 tpy VOC from a tank battery; and 1.3 tpy, 5.3
tpy, 20 tpy, and 50 tpy methane from a tank battery. Based on our cost
analysis we propose to retain the 6 tpy applicability threshold.
    The estimated all-in capital costs for a single combustion control
device are approximately $80,000. The estimated annualized costs
include the capital recovery cost (calculated at a 7 percent interest
rate for 15 years) and labor costs for operations and maintenance and
are estimated at approximately $31,500/yr. The estimated capital costs
for a VRU sized for a source with potential VOC emissions of 6 tpy are
approximately $32,000 and the estimated annualized costs are estimated
at approximately $24,000/yr not considering any potential recovery
credits from sales. More information on this cost analysis

is available in the NSPS OOOOb and EG TSD for this proposal.
    Based on our analysis, the cost effectiveness of controlling VOC
and methane emissions from a tank battery with the potential for VOC
emissions of 6 tpy, under the single pollutant approach where all the
costs are assigned to the reduction of VOC, is $5,540 per ton of VOC
eliminated assuming the use a single combustion control device. As
explained above, storage vessels are commonly located adjacent to one
another as part of tank battery, which allows the vapors from the
storage vessels within the tank battery to be collected and routed to a
single control device, when one is used. The single pollutant cost
effectiveness for a VRU to control a tank battery with potential VOC
emissions of 6 tpy is approximately $4,000 per ton of VOC eliminated.
As shown in section IX, costs ranging from $4,000 to $5,540 per ton of
VOC reduced are within the range that the EPA considers to be cost
effective for reducing VOC emissions. Because it is cost effective to
reduce the VOC emissions from a tank battery with potential VOC
emissions of 6 tpy or greater, one of the two targeted pollutants in
this action, it is cost effective to reduce both VOC and methane
emissions from a single storage vessel or a tank battery at that level.
Based on our estimate, a tank battery with potential 6 tpy VOC
emissions has potential 1.3 tpy of methane emissions. Because storage
vessels contain crude oil, condensate, intermediate hydrocarbons, or
produced water, which are approximately 80 percent VOC, the methane
emissions from storage vessels are generally less than the VOC
emissions.
    We also evaluated the cost effectiveness at a lower VOC threshold
of 3 tpy. As shown in the NSPS OOOOb and EG TSD, the single pollutant
cost effectiveness for controlling a tank battery with potential
emissions of 3 tpy ranges from $7,500 to $11,000. As shown in section
IX, costs ranging from $7,500 to $11,000 per ton of VOC reduced is not
within the range that the EPA considers to be cost effective for
reducing VOC emissions. Using the multipollutant approach, the VOC cost
effectiveness is between $3,800 and $5,500, which is considered
reasonable, but the methane cost effectiveness is between $17,000 and
$25,000 for any of the methane thresholds assessed in conjunction with
3 tpy VOC limit, which is considered unreasonable. Therefore, the 3 tpy
VOC control option was not considered reasonable at this time using
either the single pollutant or multipollutant approach.
    Our analysis also shows that, under the single pollutant approach
where all the costs are assigned to the reduction of methane and zero
to VOC, it is cost effective to control a single storage vessel or a
tank battery with potential methane emissions of 20 tpy (at costs
ranging from $1,250 to $1,660 per ton methane). Based on our estimate,
a tank battery with potential methane emissions of 20 tpy would have
the potential VOC emissions of 91 tpy, 95 percent of which would be
reduced at zero cost. Under the multipollutant cost-effectiveness
approach, where half of the cost is allocated to methane reduction and
the other half to VOC reduction, it is cost effective to control a tank
battery with potential methane emissions of 10 tpy and corresponding
potential VOC emissions of 46 tpy, at an average cost of $1,500 per ton
methane reduced and $330 per ton VOC reduced. In light of the above, 6
tpy of VOC is the lowest threshold that is cost effective to control
both VOC and methane emissions. Therefore, the EPA is proposing to
define the affected facility for purposes of regulating both VOC and
methane emissions as a tank battery with potential VOC emissions of 6
tpy or greater.
2. EG OOOOc
    The EPA is proposing presumptive standards for reducing methane
emissions from existing storage vessels. For purposes of the EG, we are
proposing to define a designated facility as a single storage vessel or
tank battery with the potential for methane emissions of 20 tpy or
greater. For purposes of the EG, we are proposing the same definition
of a storage vessel affected facility, which is a single storage vessel
or a group of storage vessels that are physically adjacent and that
receive fluids from the same source (e.g., well, process unit, or set
of wells or process units).
    The available controls for reducing methane emissions from existing
tank batteries are the same as those for reducing methane and VOC
emissions from new, modified and reconstructed tank batteries. In
assessing the control costs for existing sources, we applied a 30
percent retrofit factor to the capital and installation costs to
account for added costs of manifolding existing storage vessels and
installing the control system on an existing tank battery. When
applying controls to new sources, there is limited additional costs in
designing the fixed roof with fittings to manifold the vapors and
installing the closed vent piping or ducts during the tank installation
process. For existing sources, installing fittings on an existing tank
may require special lifts to access the roof and cut new ports in the
roof. This may also require the tank to be taken out of service to
conduct these installations, which requires additional time and labor.
Additionally, when installing controls as part of the design for a new
source, the facility layout can be designed to accommodate the control
systems near the tank battery and the control device can be installed
with the same crew installing the storage vessels, minimizing
additional installation costs. For existing sources, there may be other
equipment near the tanks that may require the control equipment to be
further from the tank battery, which increases materials and
installation costs. Also, control equipment costs will include the full
costs of crew mobilization. Therefore, it is more expensive to install
controls at an existing tank battery than to install controls as part
of a new tank battery. We considered the same regulatory options based
on potential methane emissions thresholds of 1.3 tpy, 5.3 tpy, 20 tpy,
and 50 tpy per tank battery.
    The estimated capital costs for a single combustion control device
for emissions in this range are approximately $103,000. The estimated
annual costs include the capital recovery cost (calculated at a 7
percent interest rate for 15 years) and labor costs for operations and
maintenance and are estimated at approximately $34,000. The costs for
VRU are more variable than combustion control systems and dependent on
the potential emissions for which the VRU is designed to recover. The
estimated capital costs for a VRU sized for a source with potential
methane emissions of 20 tpy device are approximately $106,000 and the
estimated annualized costs are approximately $49,000/yr not considering
any potential recovery credits. With a VRU, the recovered VOC and
methane are recovered as salable products. Considering the value of
recovered product, the annualized cost for VRU sized to recover
potential methane emissions of 20 tpy is estimated to be $26,000/yr.
More information on this cost analysis is available in the NSPS OOOOb
and EG TSD for this proposal.
    The resulting cost effectiveness, for the application of a single
combustion control device or VRU to achieve a 95 percent emission
reduction ranges from $19,000 to $27,400 per ton of methane eliminated
at a threshold of 1.3 tpy methane. This cost is not considered
reasonable. Next, we evaluated the cost effectiveness at a methane
threshold of 5.3 tpy, which ranged from $10,000 to $13,700 per ton of
methane reduced,

which is also not considered reasonable. At a threshold of 20 tpy
methane, the cost effectiveness ranges from $1,400 to $1,800 per ton
methane reduced. At a threshold of 50 tpy methane, the cost
effectiveness ranges from $340 to $720 per ton methane reduced. When we
considered the application of these options at a national level, the
overall cost effectiveness of the 20 tpy potential methane emissions
threshold was $400 per ton methane reduced without considering product
recovery credits and has a net cost savings considering product
recovery credits. Additionally, the incremental cost effectiveness of
the 20 tpy option relative to the 50 tpy potential methane emissions
threshold was approximately $900 per ton additional methane reduced
when considering product recovery credits.
    Based on the cost analysis summarized above, we find that the cost
effectiveness for achieving 95 percent emission reduction of methane
from a tank battery with potential methane emissions of 20 tpy is
reasonable for methane. A cost-effective value of $1,800/ton of methane
reduction is comparable to the estimated methane cost-effectiveness
values for the controls identified as BSER for the 2016 NSPS OOOOa and
which we consider to be representative of reasonable control cost for
reducing methane emissions from the Crude Oil and Natural Gas source
category, as explained in section IX.B. We further note that both
California and Colorado require 95 percent reduction of methane
(California) and hydrocarbon (Colorado) emissions from storage vessels.
For California, existing separator and tank systems with an annual
emission rate greater than 10 tpy methane must control emissions using
a vapor collection system that reduces emissions by at least 95
percent.\252\ For Colorado, storage vessels that emit greater than or
equal to 2 tpy of actual uncontrolled VOC emissions must reduce VOC
emissions by 95 percent.\253\ These requirements, which are comparable
to the proposed presumptive standards, are further indication that the
cost of implementing the proposal is reasonable and not excessive.
---------------------------------------------------------------------------

    \252\ See sections 95668 and 95671 of California Code of
Regulations, Title 17, Division 3, Chapter 1, Subchapter 10 Climate
Change, Article 4.
    \253\ See section I.D.3.a of Colorado Department of Public
Health and Environment, ``Control of Ozone via Ozone Precursors and
Control of Hydrocarbons via Oil and Gas Emissions (Emissions of
Volatile Organic Compounds and Nitrogen Oxides), Regulation Number
7'' (5 CCR 1001-9), July 2021.
---------------------------------------------------------------------------

3. Legally and Practicably Enforceable Limits
    In addition to the BSER analysis described above, the EPA is
clarifying the term ``legally and practicably enforceable limits'' as
it related to storage vessel affected facilities in the proposed NSPS
OOOOb and EG OOOOc. In the 2016 NSPS OOOOa, the EPA stated that ``any
owner or operator claiming technical infeasibility, nonapplicability,
or exemption from the regulation has the burden to demonstrate the
claim is reasonable based on the relevant information. In any
subsequent review of a technical infeasibility or nonapplicability
determination, or a claimed exemption, the EPA will independently
assess the basis for the claim to ensure flaring is limited and
emissions are minimized, in compliance with the rule.'' See 81 FR
35824, 35844 (June 3, 2016).
    In the context of storage vessels under both the 2012 NSPS OOOO and
2016 NSPS OOOOa, the EPA has learned that numerous owners and operators
claim that their storage vessels are not affected facilities under 40
CFR 60.5365(e) and 40 CFR 60.5365a(e). This claim is made based on a
determination that the potential for VOC emissions is less than 6 tpy
when taking into account requirements under a legally and practicably
enforceable limit in an operating permit or other requirement
established under a Federal, State, local or Tribal authority.\254\
However, when the EPA has reviewed the limits considered by these
facilities as legally and practicably enforceable, we have become aware
that the limits do not require a reduction in emissions; they are often
self-imposed or of such a general nature as to be unenforceable or
otherwise lack measures to assure the required emission reduction. For
example, a permit contains an emission limit of 2 tpy for a single
storage vessel, but does not contain any performance testing
requirements, continuous or other monitoring requirements,
recordkeeping and reporting, or other requirements that would ensure
that emissions are maintained below the emissions limit in the permit.
In National Mining Ass'n v. EPA, 59 F.3d 1351 (D.C. Cir. 1995), the
court explained what constitutes ``effective'' control in assessing a
source's potential to emit. According to the court, while ``effective''
controls need not be Federally enforceable, ``EPA is clearly not
obliged to take into account controls that are only chimeras and do not
really restrain an operator from emitting pollution.'' Id. at 1362. The
court also emphasized that these non-Federally enforceable controls
must stem from state or local government regulations, and not
``operational restrictions that an owner might voluntarily adopt.'' Id.
at 1362. Further, as a general ``default rule,'' the burden of proof
falls ``upon the party seeking relief.'' Schaffer ex rel. Schaffer v.
Weast, 546 U.S. 49, 57-58, 126 S.Ct. 528, 163 L.Ed.2d 387 (2005).
---------------------------------------------------------------------------

    \254\ 40 CFR 60.5365(e) and 40 CFR 60.5365a(e)(1) and (2) allow
owners and operators to take into account these requirements when
calculating the potential VOC emissions.
---------------------------------------------------------------------------

    In light of the above, the EPA is proposing to include a definition
for a ``legally and practicably enforceable limit'' as it relates to
limits used by owners and operators to determine the potential for VOC
emissions from storage vessels that would otherwise be affected
facilities under these rules. The intent of this proposed definition is
to provide clarity to owners and operators claiming the storage vessel
is not an affected facility in the Oil and Gas NSPS due to legally and
practicably enforceable limits that limit their potential VOC emissions
below 6 tpy. This definition is being proposed for NSPS OOOOb and the
proposed presumptive standard included in EG OOOOc. This proposed
definition of ``legally and practicably enforceable limit'' is
consistent with the EPA's historic position on what is considered
``legally and practicably enforceable,'' as tailored to storage vessels
in the oil and gas sector that would otherwise be affected facilities
under these rules. The proposed definition is as follows:
    ``For purposes of determining whether a single storage vessel or
tank battery is an affected facility, a legally and practicably
enforceable limit must include all of the following elements:
    i. A quantitative production limit and quantitative operational
limit(s) for the equipment, or quantitative operational limits for the
equipment;
    ii. an averaging time period for the production limit in (i) (if a
production-based limit is used) that is equal to or less than 30 days;
    iii. established parametric limits for the production and/or
operational limit(s) in (i), and where a control device is used to
achieve an operational limit, an initial compliance demonstration
(i.e., performance test) for the control device that establishes the
parametric limits;
    iv. ongoing monitoring of the parametric limits in (iii) that
demonstrates continuous compliance with the production and/or
operational limit(s) in (i);
    v. recordkeeping by the owner or operator that demonstrates
continuous

compliance with the limit(s) in (i-iv); and
    vi. periodic reporting that demonstrates continuous compliance.''
    In this proposed definition, the EPA is not addressing the various
ways in which a State or other authority's permit may be issued since
the format of permit issuances varies by jurisdiction. The proposed
definition of ``legally and practicably enforceable'' does not specify
limits, monitoring requirements, or recordkeeping. Instead, the owner
or operator should work with the permitting authority to establish
specific limits, monitoring requirements and recordkeeping that will
ensure any permitted emission limit is achieved. Only those limits that
include the elements described above will be considered ``legally and
practicably enforceable'' for purposes of determining the potential for
VOC emissions from a single storage vessel or tank battery, and thus
applicability (or non-applicability) of each single storage vessel or
tank battery as an affected facility under the rule.
    This proposed definition will provide clarity to owners and
operators in what limits are necessary to ensure they have
appropriately determined their single storage vessels or tank batteries
are affected facilities under the proposed NSPS OOOOb or designated
facilities under the proposed EG OOOOc. Further, as stated in the 2016
NSPS OOOOa, well-designed rules ensure fairness among industry
competitors and are essential to the success of future enforcement
efforts. 81 FR 35844 (June 3, 2016). The EPA is soliciting comment on
this proposed definition from all stakeholders.

C. Proposed Standards for Pneumatic Controllers

1. NSPS OOOOb
a. Background
    In the 2012 NSPS OOOO, the EPA established VOC standards for
natural gas-driven pneumatic controllers. Specifically, subpart OOOO
established a natural gas bleed rate limit of 6 scfh for individual,
continuous bleed, natural gas-driven controllers located in the
production segment. Continuous bleed, natural gas-driven controllers
with a bleed rate of 6 scfh or less are commonly called ``low bleed''
controllers. However, that rule also allowed for the use of ``high
bleed'' controllers (those with a bleed rate over 6 scfh) where
required by functional needs such as response time, safety, and
positive actuation. At natural gas processing plants, subpart OOOO
implemented a VOC standard that required a bleed rate of zero (``zero
bleed'' or ``no bleed''). The rule also included allowances for the use
of continuous bleed natural gas-driven controllers at natural gas
processing plants where required by functional needs.
    In the 2016 NSPS OOOOa, the EPA extended the 6 scfh natural gas
bleed rate standard to the natural gas transmission and storage segment
and established GHG standards for all segments. Effectively, the 2016
NSPS OOOOa required low bleed controllers to reduce methane and VOC
emissions from the production and transmission and storage segments and
required a bleed rate of zero for pneumatic controllers at natural gas
processing plants. Like the 2012 NSPS OOOO, the 2016 NSPS OOOOa
included allowances for the use of continuous high bleed controllers in
the production and transmission and storage segments and continuous
natural gas-driven pneumatic controllers at natural gas processing
plants where required by functional needs.
    Emissions from natural gas-driven intermittent vent pneumatic
controllers were not addressed in either the 2012 NSPS OOOO or the 2016
NSPS OOOOa. This was because, when operated and maintained properly,
methane and VOC emissions from intermittent controllers are
substantially lower (by an order of magnitude) than emissions from
other types of natural gas-driven controllers. However, the EPA is now
aware that these intermittent controllers often malfunction and vent
during idle periods. Emissions factors considering this fact are around
four times higher than the factors for low-bleed controllers. Further,
as presented in subsection c of this section, methane emissions from
intermittent controllers make up a significant portion of the overall
methane emissions from all natural gas and petroleum system sources in
the GHGI. As such, the EPA is now proposing to reduce emissions from
intermittent controllers via NSPS OOOOb.
b. Affected Facility Definitions and Zero Emissions Standard
    As a result of the review of these requirements in the 2016 NSPS
OOOOa, the previous BSER determinations, and the consideration of new
information, including State regulations that have been enacted since
2016, the EPA is proposing GHG (methane) and VOC standards for natural
gas-driven pneumatic controllers in all segments of the industry
included in the Crude Oil and Natural Gas source category (i.e.,
production, processing, transmission and storage).
    First, in terms of the definition of an affected facility, the EPA
is proposing to revise the types of pneumatic controllers that are
affected facilities to include both continuous bleed controllers and
intermittent vent controllers. For continuous bleed controllers, an
affected facility is each single continuous bleed natural gas-driven
pneumatic controller that vents to the atmosphere. For intermittent
vent controllers, an affected facility is each single natural gas-
driven pneumatic controller that is not designed to have a continuous
bleed rate but is designed to only release natural gas to the
atmosphere as part of the actuation cycle. These affected facility
definitions apply for pneumatic controllers in both the production and
transmission and storage segments, as well as for those at natural gas
processing plants.
    Next, in terms of standards, we are proposing a requirement that
all controllers (continuous bleed and intermittent vent) in the
production and natural gas transmission and storage segments must have
a methane and VOC emission rate of zero. Controllers that emit zero
methane and VOC to the atmosphere can include, but are not limited to,
air-driven pneumatic controllers (also referred to as instrument air-
driven or compressed air-driven controllers), mechanical controllers,
electronic controllers, and self-contained natural gas-driven pneumatic
controllers. While these ``zero-emissions controllers'' would not
technically be affected facilities because they are not driven by
natural gas (air-driven, mechanical, and electronic) or because they do
not vent to the atmosphere, owners and operators should maintain
documentation if they would like to be able to demonstrate to permit
writers or enforcement officials that there are no methane or VOC
emissions from the controllers and that these controllers are not
affected facilities and are not subject to the rule. The proposed
standard would apply to both continuous bleed and intermittent vent
controllers at these sites.
    For all natural gas processing plants, we are proposing to
essentially retain the 2016 NSPS OOOOa standard that requires that
controllers must have a methane and VOC emission rate of zero (i.e.,
zero-emissions controllers must be used). However, we are proposing to
slightly change the wording of the standard from subparts OOOO and
OOOOa, which require a ``bleed rate of zero.'' Many natural gas
processing plants use pneumatic controllers that are powered by
compressed air, which

can technically have a compressed air bleed rate greater than zero. Put
another way, some controllers that are powered with compressed air can
allow some of that compressed air to leave the controller and thus be
released into the atmosphere (they can ``bleed'' compressed air).
However, since the compressed air does not contain any natural gas,
methane, or VOC, we are clarifying the standard by proposing to require
that pneumatic controllers at natural gas processing plants have a
methane and VOC emission rate of zero.
    In both NSPS OOOO and OOOOa, there is an exemption from the
standards in cases where the use of 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. The EPA is not
maintaining this exemption in the proposed NSPS OOOOb, except for in
very limited circumstances explained below. As discussed below, the
reasons to allow for an exemption based on functional need in NSPS OOOO
and OOOOa 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 pneumatic controllers have a methane and VOC emission
rate of zero, we do not believe that the reasons related to the use of
low bleed controllers are still applicable.
    The proposed rule also does include an exemption from the zero-
emission requirement for pneumatic controllers in Alaska at locations
where electricity power is not available. In these situations, the
proposed standards would require the use of a low-bleed controller
instead of high-bleed controller. The proposed rule also includes the
exemption for pneumatic controllers in Alaska at sites without power
that would allow the use of high-bleed controllers instead of low-bleed
based on functional needs. In addition, inspections of intermittent
vent controllers to ensure they are not venting during idle periods
described above would also be required at sites in Alaska without
power.
c. Description
    Pneumatic controllers are devices used to regulate a variety of
physical parameters, or process variables, using air or gas pressure to
control the operation of mechanical devices, such as valves. The
valves, in turn, control process conditions such as levels,
temperatures and pressures. When a pneumatic controller identifies the
need to alter a process condition, it will open or close a control
valve. In many situations across all segments of the Oil and Natural
Gas Industry, pneumatic controllers make use of the available high-
pressure natural gas to operate or control the valve. In these
``natural gas-driven'' pneumatic controllers, natural gas may be
released with every valve movement (intermittent) and/or continuously
from the valve control. Pneumatic controllers can be categorized based
on the emissions pattern of the controller. Some controllers are
designed to have the supply-gas provide the required pressure to power
the end-device, and the excess amount of gas is emitted. The emissions
of this excess gas are referred to as ``bleed,'' and this bleed occurs
continuously. Controllers that operate in this manner are referred to
as ``continuous bleed'' pneumatic controllers. These controllers can be
further categorized based on the rate of bleed they are designed to
have. Those that have a bleed rate of less than or equal to 6 scfh are
referred to as ``low bleed,'' and those with a bleed rate of greater
than 6 scfh are referred to as ``high bleed.'' Another type of
controller is designed to release gas only when the process parameter
needs to be adjusted by opening or closing the valve, and there is no
vent or bleed of gas to the atmosphere when the valve is stationary.
These types of controllers are referred to as ``intermittent vent''
pneumatic controllers. A third type of natural gas-driven controller
releases gas to a downstream pipeline instead of the atmosphere. These
``self-contained'' types of controllers can be used in applications
with very low pressure.
    As discussed above, emissions from natural gas-powered pneumatic
controllers occur as a function of their design. Self-contained
controllers do not emit natural gas to the atmosphere. Continuous bleed
controllers using natural gas as the power source emit a portion of
that gas at a constant rate. Intermittent vent controllers using
natural gas as the power source are designed to emit natural gas only
when the controller sends a signal to open or close the valve, which is
called actuation. From continuous bleed and intermittent vent
controllers, another source of emissions is from improper operation or
equipment malfunctions. In some instances, a low bleed controller may
emit natural gas at a higher level than it is designed to do (i.e.,
over 6 scfh) or an intermittent vent controller could emit continuously
or near continuously rather than only during actuation.
    Not all pneumatic controllers are driven by natural gas. At sites
with power, electrically powered pneumatic devices or pneumatic
controllers using compressed air can be used. As these devices are not
driven by pressurized natural gas, they do not emit any natural gas to
the atmosphere, and consequently, they do not emit VOC or methane to
the atmosphere. In addition, some controllers operate mechanically
without a power source or operate electronically rather than
pneumatically. At sites without electricity provided through the grid
or on-site electricity generation, mechanical controllers and
electronic controllers using solar power can be used.
    The emissions from natural gas-powered pneumatic controllers
represent a significant portion of the total emissions from the Oil and
Natural Gas Industry. In the 2021 GHGI, the estimated methane emissions
for 2019 from pneumatic controllers were 700,000 metric tons of methane
for petroleum systems and 1.4 million metric tons for natural gas
systems. These levels represent 45 percent of the total methane
emissions estimated from all petroleum systems (i.e., exploration
through refining) sources and 22 percent of all methane emissions from
natural gas systems (i.e., exploration through distribution). The vast
majority of these emissions are from natural gas-driven intermittent
vent controllers, which the EPA is proposing to define as an affected
facility for the first time in NSPS OOOOb. Of the combined methane
emissions from pneumatic controllers in the petroleum systems and
natural gas systems production segments, emissions from intermittent
vent controllers make up 88 percent of the total. Continuous high bleed
and low bleed controllers make up 8 and 4 percent, respectively.
d. Control Options
    In identifying control options for this NSPS OOOOb proposal, we re-
examined the options previously evaluated in the rulemakings to
promulgate the 2012 NSPS OOOO and the 2016 NSPS OOOOa, and also
examined State rules with requirements for pneumatic controllers that
achieve emission reductions beyond those achieved by NSPS OOOOa. For
NSPS subparts OOOO and OOOOa, we identified options for reducing
emissions from continuous bleed natural gas-driven pneumatic
controllers. These options included using low bleed controllers in
place of

high bleed controllers, enhanced maintenance (i.e., periodic inspection
and repair), and using zero-emissions controllers. For the production
and transmission and storage segments, only the option to require low
bleed controllers was fully analyzed in these previous analyses. Based
on the EPA's determination at that time that electricity was ``likely
unavailable'' at production and transmission and storage sites, the EPA
did not fully consider instrument air or electronic controllers. The
EPA also did not evaluate enhanced maintenance, as it was concluded
that the highly variable nature of determining the proper methods of
maintaining a controller could incur significant costs. The EPA did not
evaluate options to reduce emissions from intermittent vent controllers
in either the 2012 or 2016 NSPS.
    Three U.S. States (California, Colorado, and New Mexico) and two
Canadian provinces (Alberta and British Columbia) have rules or
proposed rules that achieve emission reductions beyond those achieved
by NSPS OOOOa. Starting on January 1, 2019, and subject to certain
exceptions, a California rule requires that all new and existing
continuous bleed devices must not vent natural gas to the atmosphere.
The rule allows low bleed devices installed prior to January 1, 2016,
to continue to operate, provided that annual testing is performed to
verify that the low bleed rate is maintained. A Colorado rule adopted
in February 2021, requires that all new controllers are no-bleed
controllers (which includes self-contained natural gas-driven
controllers), and over a period of two years, a sizeable portion of
existing controllers must be retrofit to have a natural gas bleed rate
of zero. New Mexico has proposed a rule that would require an emission
rate of zero from all controllers located at sites with access to
electrical power. The Canadian provinces of Alberta (effective 2022)
and British Columbia (effective 2021) also regulate emissions from
pneumatic controllers. In British Columbia, pneumatic devices that emit
natural gas must not be used at new sources and at existing gas
processing plants and large compressor stations, and in Alberta, owners
and operators must prevent or control (by 95 percent) vent gas from new
pneumatic controllers. While the terminology differs across these
regulations, the EPA believes that all these requirements (with the
exception of the 95 percent reduction requirement in Alberta) are very
similar to if not the same as the zero methane and VOC emission
requirement being proposed by the EPA for NSPS OOOOb.
    From EPA's review of our past BSER analysis as well as reviewing
these other rules, several options were identified for the BSER
analysis for NSPS OOOOb to reduce methane and/or VOC emissions from
natural gas-driven pneumatic controllers. These include the following:
(1) Use of low bleed natural gas-driven pneumatic controllers in the
place of high bleed natural gas-driven pneumatic controllers; (2)
require zero emissions from intermittent vent controllers except during
actuation, and (3) prohibit the emissions of methane and VOC from all
pneumatic controllers (i.e., establish a zero methane and VOC emission
standard for both continuous bleed and intermittent bleed controllers).
e. 2021 BSER Analysis
Production and Transmission and Storage Segments
    For production and transmission and storage sites, the EPA
evaluated two options. The first was an option to require the use of
low bleed natural gas-driven pneumatic controllers in the place of high
bleed natural gas-driven pneumatic controllers, along with a
requirement that natural gas-driven intermittent vent pneumatic
controllers only discharge natural gas during actuation. We also
evaluated an option of establishing a zero methane and VOC emissions
standard, which we propose to determine represents the BSER for
production and natural gas transmission and storage sites.
    The first option evaluated was the use of low bleed natural gas-
driven pneumatic controllers in the place of high bleed natural gas-
driven pneumatic controllers. In the analysis of this option, we
examined the emissions reduction potential, the cost of implementation,
and the cost effectiveness in terms of cost per ton of emissions
eliminated.
    The emission reduction potential of using a low bleed controller in
place of a high bleed controller depends on the actual bleed rate of
each device, which varies from device to device. Using average emission
factors for each device type, the difference in emissions can be
estimated on a per-controller basis. We estimated this difference
between a low bleed and a high bleed device to be an 84 percent
reduction for controllers in the production segment and a 92 percent
reduction in emissions in the transmission and storage segment,
equating to a difference of 2.1 tpy methane and 0.6 tpy VOC per
controller in the production segment and 2.9 tpy methane and 0.08 tpy
VOC per controller in the transmission and storage segment. The cost of
a new low bleed natural gas-driven pneumatic controller is
approximately $255 higher than the cost of a new high bleed device. On
an annualized basis, assuming a 15-year equipment lifetime and a 7
percent interest rate, the cost is $28 per year per low bleed
controller. Under the single pollutant approach where all the costs are
assigned to the reduction of one pollutant, the estimated cost
effectiveness is $13 per ton of methane avoided and $48 per ton of VOC
avoided per controller in the production segment. 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 $7 per ton of methane avoided and $24 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
shows an overall savings under both the single pollutant and
multipollutant approaches. For the natural gas transmission and storage
segment, the cost effectiveness is $10 per ton methane avoided and $355
per ton VOC avoided per controller using the single pollutant method,
and $5 per ton of methane and $178 per ton of VOC avoided per
controller using the multipollutant method. 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. 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.
    We also evaluated a requirement that natural gas-driven
intermittent vent pneumatic controllers only discharge natural gas
during actuations. This emissions reduction option would be required in
conjunction with a requirement to use low bleed controllers in place of
high bleed controllers. The average emission factor determined by an
industry study for natural gas-driven intermittent vent controllers,
including both properly and improperly operating controllers, is 9.2
scfh natural gas.\255\ Comparing this to the emission factor for a
properly operating intermittent vent controller of 0.3 scfh natural gas
illustrates the significant potential for reductions from a program
that

identifies intermittent vent controllers that are improperly operating
and repairing, replacing, or altering their operating conditions so
they may function properly. To ensure these devices are emitting
natural gas only during actuations in accordance with their design,
there would be no equipment expenditure or associated capital costs;
however, emissions monitoring or inspections, combined with repair as
needed, would be necessary to ensure this proper operation is achieved.
We considered requiring independent inspections specifically for
intermittent vent controllers but concluded that it would be more
efficient to couple inspections of these controllers with the
inspections of equipment for leaks under the fugitive monitoring
program (see section XII.A of this preamble).
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    \255\ API Field Measurement Study: ``Pneumatic Controllers EPA
Stakeholder Workshop on Oil and Gas.'' November 7, 2019--Pittsburgh
PA. Paul Tupper.
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    The second option we evaluated was a zero methane and VOC emissions
standard. While applicability of both the 2012 NSPS OOOO and the 2016
NSPS OOOOa are based on an individual pneumatic controller (as is the
proposed definition of affected facility under NSPS OOOOb), zero-
emissions controller options are more appropriately evaluated as
``site-wide'' controls. While individual natural gas-driven pneumatic
controllers can be switched to other types of natural-gas driven
pneumatic controllers (e.g., high bleed to low bleed types or low bleed
to self-contained), the implementation of some zero-emissions
controllers options would require equipment that would presumably be
used for all the controllers at the site. For example, in order to
utilize instrument air driven controllers, a compressor and related
equipment would need to be installed. For the vast majority of
situations, the EPA does not believe that an owner and operator would
install a compressor just for a single controller, but rather would
instead install a site-wide system to provide compressed air to all the
controllers at the site. Therefore, to adequately account for the costs
of the system, including the controllers and the common equipment, we
evaluated these zero-emissions controller options using ``model''
plants.
    These model plants include assumptions regarding the number of each
type of pneumatic controller at a site. Emissions were estimated for
each of the model plants using a calculation based on of the number of
controllers at the plant and emission factors for each controller.
Three sizes of model plants (i.e., small, medium, and large) were
developed and used for both the production and transmission and storage
segments. Each model plant contained one high bleed natural gas-driven
controller and increasing numbers of low bleed and intermittent natural
gas-driven controllers. For the production segment, the controller-
specific emission factors used are from a recent study conducted by the
American Petroleum Institute,\256\ and are 2.6 scfh, 16.4 scfh, and 9.2
scfh total natural gas emissions for low bleed, high bleed, and
intermittent bleed controllers, respectively. This API study did not
cover the transmission and storage segment; therefore, the emission
factors from GHGRP subpart W were used, which are 1.37 scfh, 18.2 scfh,
and 2.35 scfh for low bleed, high bleed, and intermittent bleed
controllers, respectively. It was assumed that the portion of natural
gas that is methane is 82.9 percent in the production segment and 92.8
percent in the transmission and storage segment. Further, it was
assumed that VOCs were present in natural gas at a certain level
compared to methane. The specific ratios assumed were 0.278 pounds VOC
per pound methane in the production segment and 0.0277 pounds VOC per
pound methane in the transmission and storage segment. This information
results in estimated emissions for a single natural gas-driven
pneumatic controller in the production segment of 0.39, 2.48, and 1.39
tpy methane and 0.1, 0.7, and 0.4 tpy VOC per low bleed, high bleed,
and intermittent vent controller, respectively. The emissions for a
single natural gas-driven pneumatic controller in the transmission and
storage segment are 0.23, 3.08, and 0.40 tpy methane and 0.006, 0.08,
and 0.01 tpy VOC per low bleed, high bleed, and intermittent vent
controller, respectively.
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    \256\ API Field Measurement Study: ``Pneumatic Controllers EPA
Stakeholder Workshop on Oil and Gas.'' November 7, 2019--Pittsburgh
PA. Paul Tupper.
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    Based on the factors described above and the number of each type of
controller in each model plant, baseline emissions for the model plants
were calculated. For the production model plants, the baseline
emissions were calculated to be 5.7 tpy methane and 1.6 tpy VOC for the
small model plant (assumes fewer controllers on site than medium
plant), 11.2 tpy methane and 3.1 tpy VOC for the medium model plant
(assumes more controllers on site than small plant), and 24.9 tpy
methane and 6.9 tpy VOC for the large model plant (assumes more
controllers on site than the medium plant). For the transmission and
storage model plants, the baseline emissions were calculated to be 4.1
tpy methane and 0.1 tpy VOC for the small model plant, 5.7 tpy methane
and 0.2 tpy VOC for the medium model plant, and 10.0 tpy methane and
0.3 tpy VOC for the large model plant. For detailed information on the
configuration of these model plants and the calculation of the baseline
emissions, see the NSPS OOOOb and EG TSD for this rulemaking, which is
available in the docket.
    Instrument air controllers and electronic controllers were the two
zero emission options evaluated. Both these options require electricity
to operate. Instrument air systems use compressed air as the signaling
medium for pneumatic controllers and pneumatic actuators, whereas
electronic controllers send an electric signal to an electric actuator
(rather than sending a pneumatic signal to a pneumatic actuator). As
instrument air systems are usually installed at facilities where there
is a high concentration of pneumatic control valves, electrical power
from the grid, and the presence of an operator that can ensure the
system is properly functioning, we evaluated the use of instrument air
for the large model plant with more controllers and the use of
electronic controllers, which can be powered by solar panels, at the
small and medium-sized model plant with less controllers. The emission
reduction potential of using these zero-emissions controllers rather
than natural-gas-driven pneumatic controllers is 100 percent since
these systems eliminate all natural gas emissions (they do not emit any
VOC or methane). Based on the information available to the EPA during
development of this proposal, these two zero-emissions options were the
only two analyzed. The EPA solicits comment on the other potential
zero-emission options for these sites (mechanical-only controllers,
self-contained natural gas-driven controllers, and natural gas-driven
controllers where the emissions are captured and routed to a process).
    For the small and medium-sized model plants, the zero-emissions
option evaluated was the use of electronic controllers. The respective
emissions reduction for small and medium-sized plants would be 5.7 and
11.2 tpy methane and 1.6 and 3.1 tpy VOC in the production segment and
4.1 and 5.7 tpy methane and 0.11 and 0.16 tpy VOC in the transmission
and storage segment. The cost of a new electronic controller system
using electricity from the grid or other on-site power generation is