Unlike in NSPS OOOOa which, as amended by the 2020 Technical Rule, set VOC monitoring frequency based on production level, the EPA is proposing that the OGI monitoring frequency be based on the site level methane baseline emissions, as determined, in part, through equipment/component count emission factors. The EPA is proposing the calculation of the total site-wide methane emissions, including fugitive emissions from components, emissions from natural gas-driven pneumatic controllers, natural gas-driven pneumatic pumps, storage vessels, as well other regulated and non-regulated emission sources. Specifically, we are proposing that owners or operators would calculate the site-level baseline methane emissions using a combination of population-based emission factors and storage vessel emissions. For each natural gas-driving pneumatic pump, continuous bleed natural gas-driven pneumatic controller, and intermittent bleed natural gas-driven pneumatic controller located at the well site, the owner or operator would apply the population emission factors for all components found in Table W-1A of GHGRP subpart W. For each piece of major production and processing equipment and each wellhead located at the well site, the owner or operator would first apply the default average component counts for major equipment found in Table W-1B and Table W-1C of GHGRP subpart W, and then apply the component-type emission factors for the population of valves, connectors, open-ended lines, and PRVs found in Table 2-8 of the 1995 Emissions Protocol. Finally, the owner or operator would use the calculated potential methane emissions after applying control (if applicable) for each storage vessel tank battery located at the well site. The sum of the emissions estimated for all equipment at the site would be used as the baseline methane emissions for determining the applicable monitoring frequency. The EPA requests comment on whether the proposed methodologies for calculating site-level baseline methane emissions are appropriate for these emission sources, and if not, what methodologies would be more appropriate. Furthermore, the EPA requests comment on whether site-level baseline methane emissions should be determined using a baseline emissions survey instead of the proposed methodology, and if so, what methodologies should be used to quantify emissions from the survey such as measurement or emission factors based on leaking component emission factors. The EPA also solicits comment on specific methodologies, rather than conclusory statements, to support commenters' positions. The EPA also requests comment on whether there are additional production and processing equipment that should be included in the site-level baseline methane emissions. For example, the EPA is aware that there could be emission sources such as engines, dehydrator venting, compressor venting, and associated gas venting at a well site. If such equipment should be included in the site-level baseline, the EPA requests comment on methodologies for quantifying emissions for purposes of the baseline.
      Based on the analysis described in section XII.A.1, the potential for fugitive emissions is impacted more by the number and type of equipment at the site, and not by the volume of production. Therefore, the EPA believes it is more appropriate to use site-specific emissions estimates based on the number and type of equipment located at the individual site to determine the monitoring frequency. Table 13 summarizes the proposed site level baseline methane thresholds for the proposed monitoring frequencies, which according to our analysis would achieve the greatest cost-effective emission reductions.
      As noted below, the EPA solicits comment on all aspects of the proposed tiered approach to monitoring that is summarized in Table 13. Although we are proposing no monitoring where site-level baseline methane emissions are below 5 tpy, the EPA is also soliciting comment on whether a different approach to fugitive emissions surveys, such as the use of emerging technologies as discussed in section XI.A.1 would be appropriate in place of the ground based OGI surveys. As discussed there, the use of emerging technologies would allow for a potentially more cost-effective approach to identifying and mitigating large emission events should they occur.
 TABLE 13. PROPOSED WELL SITE MONITORING FREQUENCIES BASED ON SITE-LEVEL BASELINE METHANE EMISSIONS
                Site-level Baseline Methane Emissions Threshold
                            OGI Monitoring Frequency
                              >0 and <5 tpy
                             No monitoring required
                              >=5 and <15 tpy
                                   Semiannual
                                   >=15 tpy
                                   Quarterly

       Where quarterly monitoring is proposed, subsequent quarterly monitoring would occur at least 60 days apart. Where semiannual monitoring is proposed, subsequent semiannual monitoring would occur at least 4 months apart and no more than 7 months apart. We are proposing to retain the provision in the 2016 NSPS OOOOa that the quarterly monitoring may be waived when temperatures are below 0 ℉ for two of three consecutive calendar months of a quarterly monitoring period.
      The EPA has previously required the use of OGI technology to detect fugitive emissions of methane and VOC from the oil and gas sector (i.e., well sites and compressor stations). However, the EPA had not developed a protocol for its use even though the EPA has previously mentioned the need for an OGI protocol during other rulemakings where OGI has been proposed for leak detection. Today, the EPA is proposing a draft protocol for the use of OGI as Appendix K to 40 CFR part 60. The EPA notes that while this protocol is being proposed for use in the oil and gas sector, the applicability of the protocol is broader. The protocol is applicable to surveys of process equipment using OGI cameras in the entire oil and gas upstream and downstream sectors from production to refining to distribution where a subpart in those sectors references its use.
      As part of the development of Appendix K, the EPA conducted an extensive literature review on the technology development as well as observations on current application of OGI technology. Approximately 150 references identify the technology, applications, and limitations of OGI. The EPA also commissioned multiple laboratory studies and OGI technology evaluations. Additionally, on November 9 and 10, 2020, the EPA held a virtual stakeholder workshop to gather input on development of a protocol for the use of OGI. The information obtained from these efforts was used to develop the technical support document for Appendix K, which provides technical analyses, experimental results, and other supplemental information used to evaluate and develop standardized procedures for the use of OGI technology in monitoring for fugitive emissions of VOCs, HAPs, and methane from industrial environments.
      Appendix K outlines the proposed procedures that instrument operators must follow to identify leaks or fugitive emissions using a hand-held, field portable infrared camera. Additionally, Appendix K contains proposed specifications relating to the required performance of qualifying infrared cameras, required operator training and verification, determination of an operating window for performing surveys, and requirements for a monitoring plan and recordkeeping. The EPA is requesting comment on all aspects of the draft OGI protocol being proposed as Appendix K to 40 CFR part 60.
       Once fugitive emissions are detected during the OGI survey, we are proposing that a first attempt at repair must be made within 30 days of detecting the fugitive emissions, with final repair, including resurvey to verify repair, completed within 30 days after the first attempt. These repair requirements are the same as those in the current NSPS OOOOa (as amended in the 2020 Technical Rule for VOC). Because large emission events contribute disproportionately to emissions, the EPA is soliciting comment on how to structure a requirement that would tier repair deadlines based on the severity of the fugitive emissions. In order for such a structure to work, there would need to be a way to qualify which fugitive emissions are smaller and which are larger, as the initial monitoring with OGI will not provide this information. One approach could be to define broad categories of leaks and make assumptions about the magnitude of emissions for those broad categories. For example, an open thief hatch would be considered a very large leak due to the surface opening size, and it would need to be remedied on the tightest timeframe, whereas a leaking connector would be considered a small leak based on historical emissions factors and could be repaired on a more lenient timeframe. The EPA is soliciting comments on how this approach could be structured, particularly the types of leaks that would fall into each broad category and the appropriate repair timeframes for each of the categories. The EPA is also soliciting comment on other approaches that could also be implemented for repairing fugitive emissions in a tiered structure. Finally, we are proposing to retain the requirement for owners and operators to develop a fugitive emissions monitoring plan that covers all the applicable requirements for the collection of fugitive emissions components located at a well site and includes the elements specified in the proposed Appendix K when using OGI.
       The affected facilities include well sites with major production and processing equipment and centralized tank batteries. As in the 2020 Technical Rule, the EPA is proposing to not include "wellhead only well sites," as affected facilities when the well site is a wellhead only well site at the date it becomes subject to the rule. Based on the proposed site-level baseline methane emissions calculation methodology, wellhead only sites would only calculate emissions from fugitive components (e.g., valves, connectors, flanges, and open-ended lines) that are located on the wellhead. We believe these sites would not exceed the 5 tpy threshold to require monitoring. However, unlike the 2020 Technical Rule, the EPA is proposing that when a well site later removes all major production and processing equipment such that it becomes a wellhead only well site, it must recalculate the emissions in order to determine if a different frequency is then required. In this proposal, the definitions for "wellhead only well site" and "well site" would be the same as those finalized in the 2020 Technical Rule. Specifically, "wellhead only well site" means "for purposes of the fugitive emissions standards, a well site that contains one or more wellheads and no major production and processing equipment." The term "major production and processing equipment" refers to "reciprocating or centrifugal compressors, glycol dehydrators, heater/treaters, separators, and storage vessels collecting crude oil, condensate, intermediate hydrocarbon liquids, or produced water." The EPA is soliciting comment on whether any other equipment not included in this definition should be added in order to clearly specify what well sites are considered wellhead only sites. Specifically, the EPA is soliciting comment on the inclusion of natural gas-driven pneumatic controllers, natural gas-driven pneumatic pumps, and pumpjack engines in the definition of "major production and processing equipment." A "well site" means "one or more surface sites that are constructed for the drilling and subsequent operation of any oil well, natural gas well, or injection well. For purposes of the fugitive emissions standards, a well site includes a centralized production facility. Also, for purposes of the fugitive emissions standards, a well site does not include: (1) UIC Class II oilfield disposal wells and disposal facilities; (2) UIC Class I oilfield disposal wells; and (3) the flange immediately upstream of the custody meter assembly and equipment, including fugitive emissions components, located downstream of this flange."
       In addition to retaining the above definitions, the EPA is also proposing a new definition for "centralized production facility" for purposes of fugitive emissions requirements for well sites, where a "centralized tank battery" is "one or more permanent storage tanks and all equipment at a single stationary source used to gather, for the purpose of sale or processing to sell, crude oil, condensate, produced water, or intermediate hydrocarbon liquid from one or more offsite natural gas or oil production wells. This equipment includes, but is not limited to, equipment used for storage, separation, treating, dehydration, artificial lift, combustion, compression, pumping, metering, monitoring, and flowline. Process vessels and process tanks are not considered storage vessels or storage tanks. A centralized production facility is located upstream of the natural gas processing plant or the crude oil pipeline breakout station and is a part of producing operations." Additional discussion on centralized production facilities is included in section XI.K.
       The EPA is not proposing any change to the current definition of modification as it relates to fugitive emissions requirements at well sites or centralized production facilities. Specifically, modification occurs at a well site when (1) a new well is drilled at an existing well site; (2) a well at an existing well site is hydraulically fractured; or (3) a well at an existing well site is hydraulically refractured. Similarly, modification occurs at a centralized production facility when (1) any of the actions above occur at an existing centralized production facility; (2) a well sending production to an existing centralized production facility is modified as defined above for well sites; or (3) a well site subject to the fugitive emissions standards for new sources removes all major production and processing equipment such that it becomes a wellhead only well site and sends production to an existing centralized production facility.
 b. EG OOOOc
	For existing well sites (for EG OOOOc), we are proposing a presumptive standard that follows the same fugitive monitoring and repair program as for new sources. For the reasons discussed in section XII.A.2, the BSER analysis for existing sources supports proposing a presumptive standard for reducing methane emissions from the collection of fugitive emissions components located at existing well sites that is the same as what the EPA is proposing for new, reconstructed, or modified sources (for NSPS OOOOb). The EPA did not identify any factors specific to existing sources that would alter the analysis performed for new sources to make that analysis different for existing well sites. The EPA determined that the OGI technology, methane emission reductions, costs, and cost effectiveness discussed above for the collection of fugitive emissions components at new well sites are also applicable for the collection of fugitive emissions components at existing well sites. Further, the fugitive emissions requirements are a work practice, therefore they would not require the installation of controls or the retrofit of equipment, which can generally be an additional factor for consideration for existing sources. Therefore, the EPA found is appropriate to use the analysis developed for the proposed NSPS OOOOb to also develop the BSER and proposed presumptive standards for the EG OOOOc.
	Based on the information available at this time, the EPA thinks the large number of existing well sites, many of which are not complex and are owned or operated by small businesses, warrants soliciting comment on whether existing well sites (or a subcategory thereof) could have different emission profiles due to certain site characteristics or other factors that would suggest a different presumptive standard is appropriate.
	Finally, we are soliciting comment on all aspects of the proposed fugitive emissions requirements for both new and existing well sites, including whether we should use the tiering approach, whether the tiers we have defined are appropriate, and the monitoring requirements for each tier, including whether it would be cost-effective to monitor at more frequent intervals than proposed in the absence of an alternative utilizing emerging technologies.
 4. Fugitive Emissions from Compressor Stations
	The current NSPS for reducing fugitive emissions from the collection of fugitive emissions components located at a compressor station is a fugitive emissions monitoring and repair program requiring quarterly OGI monitoring. Based on our analysis, which is summarized in section XII.A.1.b, the EPA is proposing quarterly OGI monitoring requirement for both methane and VOC as it continues to reflect the BSER for reducing both emissions from fugitive components at new, modified, and reconstructed compressor stations. Likewise, the EPA is also proposing quarterly monitoring as a presumptive GHG standard (in the form of limitation on methane emissions) for the collection of fugitive emissions components located at existing compressor stations. The affected compressor stations include gathering and boosting, transmission, and storage compressor stations.
 a. NSPS OOOOb
 	We are proposing that the quarterly monitoring using OGI be conducted in accordance with the proposed Appendix K described above in section XI.A.3, which outlines procedures that must be followed to identify leaks using OGI. We are proposing to retain the current requirements that monitoring must begin within 90 days of startup of the station (or startup after modification), with subsequent quarterly monitoring occurring at least 60 days apart. Also, quarterly monitoring may be waived when temperatures are below 0 ℉ for two of three consecutive calendar months of a quarterly monitoring period. We are also not proposing any change to the following repair-related requirements: Specifically, a first attempt at repair must be made within 30 days of detecting the fugitive emissions, with final repair, including resurvey to verify repair, completed within 30 days after the first attempt. In addition, owners and operators must develop a fugitive emissions monitoring plan that covers all the applicable requirements for the collection of fugitive emissions components located at a compressor station. In conjunction with the proposed requirement that monitoring be conducted in accordance with the proposed Appendix K, we are proposing to require that the monitoring plan also include elements specified in the proposed Appendix K when using OGI.
b. EG OOOOc
	For existing sources, we are proposing a presumptive standard that includes the same fugitive emissions monitoring and repair program as for new sources. For the reasons discussed in section XII.A.2, the BSER analysis for existing sources supports proposing a presumptive standard for reducing methane emissions from the collection of fugitive emissions components located at existing compressor stations that is the same as what the EPA is proposing for new, modified, or reconstructed sources (for NSPS OOOOb).
	Similar to well sites, we are soliciting comment on all aspects of the proposed quarterly monitoring for both new and existing compressor stations, including whether more frequent monitoring would be appropriate in the absence of an alternative approach utilizing emerging technologies. We are also soliciting information on several additional topics. First, the EPA is soliciting comment and data to assess whether compressor stations should be subcategorized for the NSPS and/or the EG. For example, some industry stakeholders have asserted that station throughput directly correlates to the operating pressures, equipment counts, and condensate production, which would influence fugitive emissions at the station. They suggested that subcategorization based on design throughput capacity for the compressor station may be appropriate, especially for older existing sites where the conditions at the station would result in minimal methane emissions, but where equipment could be older and more prone to leaks and malfunctions. We are specifically seeking information related to throughputs where fugitive emissions of methane are demonstrated to be minimal below a certain capacity. While this specific example was raised in the context of existing sources only, the EPA is also soliciting comment on whether new, modified, or reconstructed compressor stations could encounter the same issue and therefore necessitate similar subcategorization. Should information provided through this solicitation support subcategorization for the NSPS and/or the EG, including possible exemptions from monitoring if a subcategory is shown to have such low fugitive emissions that it is not cost effective to control, the EPA may consider subcategorization through a supplemental proposal.
      Next, for compressor stations, we are soliciting comment on delayed repairs by existing sources when parts are not readily available and must be special ordered. In comments submitted to the EPA as part of the stakeholder outreach conducted prior to this proposal, industry stakeholders stated that the EPA "should acknowledge that existing sources are older pieces of equipment so there is a higher likelihood that replacement parts will not be readily available; therefore, a lack of available parts should be an appropriate cause to delay a repair." Industry stakeholders further explained that operators will need to special order replacement parts. Further, they stated in their comments that operators should be afforded 30 days to schedule the repair once they have received the replacement part. The EPA is soliciting comment and data to better understand the breadth of this issue with replacement parts for existing compressor stations. Additionally, we are soliciting comment on whether 30 days following receipt of the replacement part is appropriate for completing delayed repairs at existing compressor stations. We are also soliciting comment on the specific records that should be maintained and/or reported to justify delayed repairs as a result of part availability issues. Depending on the additional information received, the EPA may consider proposing changes to the proposed EG for compressor stations through a supplemental proposal. Finally, as discussed in section XI.A.3, the EPA is soliciting comment on whether repairs at compressor stations should be made based on severity of the emissions found. Please refer to section XI.A.3 for additional details on this solicitation for comment.
B. Storage Vessels
1. NSPS OOOOb
      The current NSPS in OOOOa for storage vessels is to reduce VOC emissions by 95 percent, and the standard applies to a single storage vessel with a potential for 6 or more tpy of VOC emissions. Based on our analysis, which is summarized in section XII.B.1, the EPA is proposing to retain the 95 percent reduction standard as it continues to reflect the BSER for reducing VOC emissions from new storage vessels. The EPA is also proposing to set GHG standards (in the form of limitations on methane emissions) for storage vessels in this action. Because the BSER for reducing VOC and methane emissions are the same, the proposed GHG standard is to reduce methane emissions by 95 percent. The EPA continues to support the capture of gas vapors from storage vessels rather than the combustion of what can be an energy-rich saleable product. We incentivize this by recognizing the use of vapor recovery as a part of the process, therefore the storage vessel emissions would not contribute to the site's potential-to-emit.
      Under the current NSPS for storage vessels, an affected facility is a single storage vessel with potential VOC emissions of 6 tpy or greater. The EPA is proposing to include a tank battery as a storage vessel affected facility. The EPA proposes to define a tank battery as a group of storage vessels that are physically adjacent and that receive fluids from the same source (e.g., well, process unit, compressor station, or set of wells, process units, or compressor stations) or which are manifolded together for liquid or vapor transfer.
      To determine whether a single storage vessel is an affected facility, the owner or operator would compare the 6 tpy VOC threshold to the potential emissions from that individual storage vessel; to determine whether a tank battery is an affected facility, the owner or operator would compare the 6 tpy VOC threshold to the aggregate potential emissions from the group of storage vessels. For new, modified, or reconstructed sources, if the potential VOC emissions from a storage vessel or tank battery exceeds the 6 tpy threshold, then it is a storage vessel affected facility and controls would be required. This is consistent with the EPA's initial determination in the 2012 NSPS OOOO that controlling VOC emissions as low as 6 tpy from storage vessels is cost-effective. The proposed standard of 95 percent reduction of methane and VOC emissions, which is the same as the current VOC standard in the 2012 NSPS OOOO and 2016 NSPS OOOOa, can be achieved by capturing and routing the emissions utilizing a cover and closed vent system that routes captured emissions to a control device that achieves an emission reduction of 95 percent, or that routes captured emissions to a process.
      Finally, we are proposing specific provisions to clarify what circumstances constitute a modification of an existing storage vessel affected facility (single storage vessel or tank battery), and thus subject it to the proposed NSPS instead of the EG. The EPA is proposing that a single storage vessel or tank battery is modified when physical or operational changes are made to the single storage vessel or tank battery that result in an increase in the potential methane or VOC emissions. Physical or operational changes would be defined to include: (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 tank battery or single storage vessel 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). 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 tank battery to determine if a modification has occurred. The existing tank battery will only become subject to the proposed NSPS if it is modified pursuant to this definition of modification and its potential VOC emissions exceed the proposed 6 tpy VOC emissions threshold.
2. EG OOOOc
      Based on our analysis, which is summarized in section XII.B.2, the EPA is proposing EG for existing storage vessels which include a presumptive GHG standard (in the form of limitation on methane emissions). For existing sources under the EG, the EPA is proposing to define a designated facility as an existing tank battery with potential methane emissions of 20 tpy or greater. The proposed definition of a tank battery in the EG is the same as the definition proposed for new sources; however, since the designated pollutant in the context of the EG is methane, determination of whether a tank battery is a designated facility would be based on its potential methane emissions only. Our analysis shows that it is cost effective to control an existing tank battery with potential methane emissions 20 tpy or higher. Similar to the proposed NSPS, we are proposing a presumptive standard that includes a 95 percent reduction of the methane emissions from each existing tank battery that qualifies as a designated facility. Such a standard could be achieved by capturing and routing the emissions by utilizing a cover and closed vent system that routes captured emissions to a control device that achieves an emission reduction of 95 percent, or routes emission back to a process.
C. Pneumatic Controllers
 1. NSPS OOOOb
      The current NSPS OOOOa regulates both continuous bleed natural gas driven pneumatic controllers that are located at an onshore natural gas processing plants and those that are not located at an onshore natural gas processing plant. For the former, the current NSPS requires a zero natural gas bleed rate. For the latter, the current NSPS requires the pneumatic controller to operate at a natural gas bleed rate no greater than 6 scfh. The current NSPS does not regulate intermittent natural gas driven pneumatic controllers at any location.
      Based on our analysis, which is summarized in section XII.C.1, the EPA is proposing to update the current NSPS as follows. First, the EPA is proposing to two separate types of affected facilities for pneumatic controllers which include each single continuous bleed natural gas driven pneumatic controller at a site and the collection of all natural gas driven intermittent vent controllers at a site. The EPA proposes to include intermittent pneumatic controllers as an affected facility, because intermittent devices represent a large majority of the overall population of pneumatic controllers and of emissions from these sources, and are prone to malfunctions that lead to significant discharges of methane and can be readily detected and remedied through regular fugitive emissions monitoring. Second, because the options available for reducing or eliminating emissions from pneumatic controllers depend significantly on the availability of onsite power, the EPA has identified two subcategories for pneumatic controllers located in the production, including gathering and boosting, and transmission and storage segments: (1) natural gas driven pneumatic controllers at sites with onsite power available (subcategory 1); and (2) natural gas driven pneumatic controllers at sites where onsite power is not available (subcategory 2). Onsite power can mean access to the electric grid or to power generated by an onsite power generation station capable of providing electricity to the entire site; installation of electric services is not required for this purpose.  For both subcategories, the EPA proposes that the definitions of affected facility remain the same as described above and in section XII.C.1 in more detail.
      For subcategory 1, we are proposing a requirement that all controllers (continuous bleed and intermittent vent) must have a VOC and methane emission rate of zero, which can be achieved by using non-emitting pneumatic controllers such as air-driven pneumatic controllers, electric controllers, and self-contained pneumatic controllers. For each individual continuous bleed pneumatic controller in subcategory 2, the EPA is proposing a standard of a natural gas bleed rate not to exceed 6 scfh. Additionally, for each single intermittent natural gas-driven pneumatic controller in subcategory 2, we propose to require fugitive monitoring to verify proper actuation and that venting does not occur during idle times. We propose to define an intermittent natural gas-driven pneumatic controller to mean a 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. Please refer to sections XI.A and XII.A of this preamble which summarize and detail the proposed fugitive monitoring and repair provisions.
       For natural gas processing plants, the EPA is proposing to define the affected facility as the collection of all gas-driven pneumatic controllers, including intermittent natural gas-driven pneumatic controllers. For the collection of pneumatic controllers located at onshore natural gas processing plants, the EPA proposes to retain the current standards for GHGs (in the form of limitations on methane) and VOC, which is a zero natural gas bleed rate (i.e., they are operated by means other than natural gas, such as being driven by compressed instrument air).
2. EG OOOOc
      In this action, the EPA is proposing to subcategorize designated facilities (existing sources) in the same manner as the definitions described above for pneumatic controller affected facilities for subcategory 1, subcategory 2, and natural gas processing, as proposed for new sources. For the reasons discussed in section XII.C.2, the BSER analysis for existing sources supports proposing presumptive standards for reducing methane emissions from existing pneumatic controllers in these subcategories that is the same as what the EPA is proposing for new, modified, or reconstructed sources (for NSPS OOOOb).
D. Well Liquids Unloading Operations
      Well liquids unloading operations, which are currently unregulated under the NSPS OOOOa, refer to unloading of liquids that have accumulated over time in gas wells and are impeding or halting production. The EPA is proposing standards in the NSPS OOOOb to reduce methane and VOC emissions during liquids unloading operations.
1. NSPS OOOOb
      We are proposing standards to reduce VOC and methane emissions from each well that conducts a liquids unloading operation. Based on our analysis, which is summarized in section XII.D.1, we are proposing a standard under NSPS OOOOb that requires owners or operators to perform liquids unloading with zero methane or VOC emissions. In the event that it is technically infeasible or not safe to perform liquids unloading with zero emissions, the EPA is proposing to require that an owner or operator establish and follow BMPs to minimize methane and VOC emissions during liquids unloading events to the extent possible.
	The EPA is co-proposing two regulatory approach options to implement the rule requirements.
	For Option 1, the affected facility would be defined as every well that undergoes liquids unloading. This would mean that wells that utilize a non-emitting method for liquids unloading would be affected facilities and subject to certain reporting and recordkeeping requirements. These requirements would include records of the number of unloadings that occur, the method used. A summary of this information would also be required to be reported in the annual report. The EPA also recognizes that under some circumstances venting could occur when a selected liquids unloading method that is designed to not vent to the atmosphere is not properly applied (e.g., a technology malfunction or operator error). Under the proposed rule Option 1 owners and operators in this situation would be required to record and report these instances, as well as document and report the length of venting, what actions were taken to minimize venting to the maximum extent possible.
	For wells that utilize methods that vent to the atmosphere, the proposed rule would require that owners or operators (1) document why it is infeasible to utilize a non-emitting method due to technical, safety, or economic reasons; (2) develop BMPs that ensure that emissions during liquids unloading are minimized; (3) follow the BMPs during each liquids unloading and maintain records demonstrating they were followed; (4) report the number of liquids unloading events in an annual report, as well as the unloading events when the BMP was not followed. While the proposed rule would not dictate the specific practices that must be included, it would specify the types and nature of the practices. Examples of the types and nature of the required practice elements are provided in XII.D.1.e.
	For Option 2, the affected facility would be defined as every well that undergoes liquids unloading using a method that is not designed to totally eliminate venting. The significant difference in this option is that wells that utilize non-venting methods would not be affected facilities that are subject to the NSPS OOOOb. Therefore, they would not have requirements other than to maintain records to demonstrate that they did not use non-venting methods and were not subject to NSPS OOOOb. The requirements for wells that use methods that vent would be the same as described above under Option 1.
      There are several techniques owners and operators can choose from to unload liquids, including manual unloading, velocity tubing or velocity strings, beam or rod pumps, electric submergence pumps, intermittent unloading, gas lift (e.g., use of a plunger lift), foam agents, wellhead compression, and routing the gas to a sales line or back to a process. Although the unloading method employed by an owner or operator can itself be a method that can be employed in such a way that mitigates/eliminates venting of emissions from a liquids unloading event, indicating a particular method to meet a particular well's unloading needs is a production engineering decision. Based on available information, liquids unloading operations are often conducted in such a way that eliminates venting to the atmosphere and there are many options that include techniques and procedures that an owner or operator can choose from to achieve this standard.
	However, the EPA recognizes that there may be reasons that a non-venting method is infeasible for a particular well, and the proposed rule would allow for the use of BMPs to reduce the emissions to the maximum extent possible for such cases (discussed in section XII.D of this preamble). BMPs include, but are not limited to, following specific steps that create a differential pressure to minimize the need to vent a well to unload liquids and reducing wellbore pressure as much as possible prior to opening to atmosphere via storage tank, unloading through the separator where feasible, and requiring closure of all well head vents to the atmosphere and return of the well to production as soon as practicable. For example, where a plunger lift is used, the plunger lift can be operated so that the plunger returns to the top and the liquids and gas flow to the separator. Under this scenario, venting of the gas can be minimized and the gas that flows through the separator can be routed to sales. In situations where production engineers select an unloading technique that results or has the potential to vent emissions to the atmosphere, owners and operators already often implement BMPs in order to increase gas sales and reduce emissions and waste during these (often manual) liquids unloading activities.
2. EG OOOOc
	The EPA has determined that each well liquids unloading event represents a modification, which will make the well subject to new source standards under the NSPS. Therefore, after the effective date of NSPS OOOOb, the first time a well undergoes liquids unloading it will become subject to NSPS OOOOb. This will mean that there will never be a well that undergoes liquids unloading that will be existing. Therefore, we are not proposing presumptive standards under the subpart OOOOc EG.
E. Reciprocating Compressors
1. NSPS OOOOb
      The current NSPS in OOOOa for reducing VOC and methane emissions from reciprocating compressors is to replace the rod packing on or before 26,000 hours of operation or 36 calendar months, or to route emissions from the rod packing to a process through a closed vent system under negative pressure. The affected facility is each reciprocating compressor, with the exception of reciprocating compressors located at well sites. Based on the analysis in section XII.E.1, the proposed BSER for reducing GHGs and VOC from new reciprocating compressors is replacement of the rod packing based on an annual monitoring threshold. Under this proposal for the NSPS, we would continue to retain, as an alternative, the option of routing rod packing emissions to a process via a closed vent system under negative pressure. In this proposed updated standard, the owner or operator of a reciprocating compressor affected facility would be required to monitor the rod packing emissions annually using a flow measurement. When the measured leak rate exceeds 2 scfm (in pressurized mode), replacement of the rod packing would be required.
      As mentioned above, reciprocating compressors that are located at well sites are not affected facilities under the 2016 NSPS OOOOa. The EPA previously excluded them because we found the cost of control to be unreasonable. 81 FR 35878. Our current analysis, as summarized in section XII.E.1, continues to support this exclusion for a subset of well sites so this proposal for NSPS OOOOb includes that same exclusion for well sites that are not centralized production facilities. See section XI.K for additional details on centralized production facilities. As described in that section, the EPA is proposing to apply the proposed standards to reciprocating compressors located at centralized production facilities.
2. EG OOOOc
       Based on the analysis in section XII.E.2, the EPA is proposing EG that include a presumptive GHG standard (in the form of limitation on methane emissions) for existing reciprocating compressors that is the same as the proposed NSPS, including applying these presumptive standards to reciprocating compressors located at existing centralized tank batteries.
F. Centrifugal Compressors
1. NSPS OOOOb
       The current NSPS in OOOOa for wet seal centrifugal compressors is 95 percent reduction of GHGs and VOC emissions. The affected facility is each wet seal centrifugal compressor, with the exception of wet seal centrifugal compressors located at well sites. Based on the analysis in section XII.F.1, the BSER for reducing GHGs and VOC from new, reconstructed, or modified wet seal centrifugal compressors is the same as the current standard, which is 95 percent reduction of GHG and VOC emissions. The standard can be achieved by capturing and routing the emissions, using a cover and closed vent system, to a control device that achieves an emission reduction of 95 percent, or by routing captured emissions to a process.
       As discussed above, wet seal centrifugal compressors that are located at well sites are not affected facilities under the 2016 NSPS OOOOa. The EPA previously excluded them because data available at the time did not suggest there were a large number of wet seal centrifugal compressors located at well sites. 81 FR 35878. Our analysis continues to support this exemption for wet seal centrifugal compressors located at well sites that are not centralized production facilities. See section XI.K for additional details on centralized production facilities. As described in that section, the EPA is proposing to apply the proposed standards to reciprocating compressors located at centralized production facilities.
2. EG OOOOc
       Based on the analysis in section XII.F.2, the EPA is proposing EG that include a presumptive GHG standard (in the form of limitation on methane emissions) for existing wet seal centrifugal compressors that is the same as the NSPS, including applying these presumptive standards to wet seal centrifugal compressors at existing centralized tank batteries.
G. Pneumatic Pumps
1. NSPS OOOOb
       The current NSPS in OOOOa regulates individual natural gas driven diaphragm pneumatic pumps at well sites and at onshore natural gas processing plants. The current NSPS for a natural gas driven diaphragm pneumatic pump at well sites requires 95 percent control of GHGs and VOCs if there is an existing control device or process on site where emissions can be routed. There are two exceptions to the 95 percent control requirement: (1) the existing control or process achieves less than 95 percent reduction; or (2) it is technically infeasible to route to the existing control device or process. The current NSPS for a natural gas driven diaphragm pneumatic pump at an onshore natural gas processing plant is zero natural gas emissions, based on natural gas as a surrogate for VOC and GHG, the two regulated pollutants.
      Based on our analysis, which is summarized in section XII.G.1, we are proposing to retain the current standard for a natural gas driven diaphragm pneumatic pump at well sites because the BSER for reducing VOC and methane emissions from such pumps at a well site continues to be routing to a combustion device or process, but only if the control device or process is already available on site. As before, the current analysis continues to show that it is not cost-effective to require the owner or operator of a pneumatic pump to install a new control device or process onsite to capture emissions. The EPA is proposing to retain the current alternative of routing emissions to a process, as such control would achieve at least 95 percent control but may not always be feasible. Thus, if a control device or the ability to route to a process is not available onsite, the pneumatic pump affected facility would not be subject to the 95 percent control requirement. Moreover, there may be a control device or process available onsite, but it may not be capable of achieving a 95 percent reduction. In those cases, we propose to retain the current standard to require the owner or operator to route the emissions to such existing control device even it if achieves a level of emissions reduction less than 95 percent. In those instances, the owner or operator must maintain records demonstrating the percentage reduction that the control device is designed to achieve. In this way, the standard would achieve emission reductions with regard to pneumatic pump affected facilities even if the only available control device cannot achieve a 95 percent reduction.
      We are also proposing to expand the applicability of the standard currently in NSPS OOOOa by including all natural gas driven diaphragm pumps in the production segment (i.e., including the gathering and boosting segment) and the transmission and storage segment as affected facilities. We are proposing the same standards for these segments as those described above for natural gas driven diaphragm pumps at well sites because the BSER is the same.
       We are not proposing any change to the current standard of zero natural gas emission for natural gas driven diaphragm pneumatic pumps located at onshore natural gas processing plants as our analysis discussed in section XII.G.1 demonstrates this standard remains the BSER.
2. EG OOOOc
       The EPA is proposing EG that include a presumptive methane standard that is the same as described above for the NSPS OOOOb for existing natural gas driven diaphragm pneumatic pumps located at well sites and all other sites in the production segment (except processing plants) and transmission and storage segment where an existing control device exists. The EPA's proposed emissions guidelines also include a presumptive methane standard for pneumatic pumps located at onshore natural gas processing plants that is the same as the proposed NSPS described above. Based on the analysis in section XII.G.2, the BSER for reducing GHGs from new and existing natural gas driven diaphragm pneumatic pumps are the same.
H. Equipment Leaks at Natural Gas Processing Plants
 	Based on our analysis, which is summarized in section XII.H.1, the EPA is proposing to update the NSPS for reducing VOC and methane emissions from equipment leaks at onshore natural gas processing plants. Further, based on the same analysis in section XII.H.1 and the EPA's understanding that it is appropriate to apply that same analysis to existing sources, the EPA is also proposing EG that include these same LDAR requirements as presumptive standards for reducing methane leaks from existing equipment at onshore natural gas processing plants.
 	The EPA is proposing to expand the definition of an affected facility (referred to as a "equipment within a process unit") and establish a new standard for reducing equipment leaks of VOC and methane emissions from new, modified, and reconstructed process units at onshore natural gas processing plants. This proposed standard would require (1) the use of OGI monitoring to detect equipment leaks from pumps, valves, and connectors, and (2) retain the current requirements in the 2016 NSPS OOOOa (which incorporates by reference specific provisions of 40 CFR part 60, subpart VVa ("NSPS VVa")) for PRDs, open-ended valves or lines, and closed vent systems and equipment designated with no detectable emissions.
 	First, we are proposing to remove a threshold that excludes certain equipment within a process unit from being subject to the equipment leaks standards for onshore natural gas processing plants. While the current definition of an affected facility includes all equipment, except compressors, that is in contact with a process fluid containing methane or VOCs (i.e., each pump, PRD, open-ended valve or line, valve, and flange or other connector), the standards apply only to equipment "in VOC service," which "means the piece of equipment contains or contacts a process fluid that is at least 10 percent VOC by weight." We are proposing to remove this VOC concentration threshold from the LDAR requirements for the following reasons. First, a VOC concentration threshold bears no relationship to the LDAR for methane and is therefore not an appropriate threshold for determining whether LDAR for methane applies. Second, since there would be no threshold for requiring LDAR for methane, any equipment not in VOC service would still be required to conduct LDAR for methane even if not for VOC, thus rendering this VOC concentration threshold irrelevant.
	Second, for all pumps, valves, and connectors located within an affected process unit at an onshore natural gas processing plant, we are proposing to require the use of OGI to identify leaks from this equipment on a bimonthly frequency (i.e., once every other month), which according to our analysis is the BSER for identifying and reducing leaks from this equipment. OGI monitoring would be conducted in accordance with the proposed Appendix K, which is included in this action and outlines the proposed procedures that must be followed to identify leaks using OGI. As an alternative to bimonthly monitoring using OGI, we are proposing to allow affected facilities the option to comply with the requirements of NSPS VVa, which are the current requirements in the 2016 NSPS OOOOa. As explained in X.I, our analysis shows that the proposed standards, which use OGI, achieve equivalent reduction of VOC and methane emissions as the current standards, which are based on EPA Method 21, but at a lower cost. While we no longer consider EPA Method 21 to be the BSER for reducing methane and VOC emissions from equipment leaks at onshore natural gas processing plants, we are retaining NSPS VVa as an alternative for owners and operators who prefer using EPA Method 21.
       Third, we are proposing to require a first attempt at repair for all leaks identified with OGI within 5 days of detection, and final repair completed within 15 days of detection. We are also proposing definitions for "first attempt at repair" and "repaired." The proposed definitions would apply to the equipment leaks standards at natural gas processing plants as well as to fugitive emissions requirements at well sites and compressor stations. The proposed definition of "first attempt at repair" is "an action taken for the purpose of stopping or reducing fugitive emissions or equipment leaks to the atmosphere. First attempts at repair include, but are not limited to, the following practices where practicable and appropriate: tightening bonnet bolts; replacing bonnet bolts; tightening packing gland nuts; or injecting lubricant into lubricated packing." The proposed definition for "repaired" is "fugitive emissions components or equipment are adjusted, replaced, or otherwise altered, in order to eliminate fugitive emissions or equipment leaks as defined in this subpart and resurveyed to verify that emissions from the fugitive emissions components or equipment are below the applicable leak definition." Repairs can include replacement with low-emissions ("low-e") valves or valve packing, where commercially available, as well as drill-and-tap with a low-e injectable. These low-e equipment meet the specifications of API 622 or 624. Generally, a low-e valve or valve packing product will include a manufacturer written warranty that it will not emit fugitive emissions at a concentration greater than 100 ppm within the first five years. Further, we are proposing to incorporate the delay of repair provisions that are in 40 CFR 60.482-9a of NSPS VVa (and incorporated into NSPS OOOOa). These provisions would allow the delay of repairs where it is technically infeasible to complete repairs within 15 days without a process unit shutdown and require repair completion before the end of the next process unit shutdown.
       Fourth, we are proposing to retain the current requirements in NSPS OOOOa for open-ended valves or lines, closed vent systems and equipment designated with no detectable emissions, and PRDs. For open-ended valves or lines, we propose to retain the requirements in 40 CFR 60.482-6a of NSPS VVa. Specifically, we are proposing that each open-ended valve or line in a new or existing process unit must be equipped with a closure device (i.e., cap, blind flange, plug, or a second valve) that seals the open end at all times except during operations requiring process fluid flow through the open-ended valve or line. The EPA is soliciting comment on requiring OGI monitoring (or EPA Method 21 monitoring for those opting for that alternative) on these open-ended valves or lines equipped with closure devices to ensure no emissions are going to the atmosphere. Specifically, the EPA is soliciting information that would aid in determining what additional costs would be incurred from either OGI or EPA Method 21 monitoring and repair of leaking open-ended valves or lines, and information on leak rates and concentrations of emissions, where monitoring has been performed.
      While the EPA is proposing to retain the no detectable emission requirement in NSPS OOOOa for closed vent systems and equipment designated as having no detectable emissions (e.g., valves or PRDs), the EPA is also soliciting comment on whether bimonthly OGI monitoring according to the proposed Appendix K is appropriate to demonstrate compliance with this requirement. The current NSPS requires the closed vent systems and the other equipment described above to operate with no detectable emissions, as demonstrated by an instrument reading of less than 500 ppm above background with EPA Method 21. On December 22, 2008, the EPA issued a final rule titled, "Alternative Work Practice to Detect Leaks from Equipment" (AWP). In that final rule, the EPA did not permit the use of OGI for this equipment, stating, "the AWP is not appropriate for monitoring closed vent system, leakless equipment, or equipment designated as non-leaking. While the AWP will identify leaks with larger mass emission rates, tests conducted with both the AWP and the current work practice indicate the AWP, at this time, does not identify very small leaks and may not be able to identify if non-leaking/leakless equipment are truly nonleaking because the detection sensitivity of the optical gas imaging instrument is not sufficient." 73 FR 78204. The EPA is soliciting information that would support the use of OGI for closed vent systems and equipment designated with no detectable emissions at new and existing process units, including comment on applying the proposed bimonthly OGI monitoring requirement on this equipment in place of the NSPS VVa annual EPA Method 21 monitoring.
       Finally, the EPA is proposing to retain the emission standards for PRDs found in 40 CFR 60.482-4a of NSPS VVa. This provision requires that PRDs be operated with no detectable emissions, except during pressure releases at new and existing process units. As stated above, the EPA is soliciting comment on the use of OGI to demonstrate that PRDs are meeting this operational emission standard.
2. EG OOOOc
       The EPA is proposing EG that include a presumptive methane standard that is the same as described above for the NSPS OOOOb for equipment leaks at existing onshore natural gas processing plants. Based on the analysis in section XII.H.2, the BSER for reducing GHGs from equipment leaks at new and existing onshore natural gas processing plants are the same.
I. Well Completions
      Based on our understanding that there are no advances in technologies or practices, which is summarized in section XII.I, the EPA is proposing to retain the reduced emission completion standards as it continues to reflect the BSER for reducing methane and VOC emissions from well completions at hydraulically fractured (or refractured) wells. These proposed standards are the same as those for natural gas and oil wells regulated in the 2012 NSPS OOOO and 2016 NSPS OOOOa, as amended in the 2020 Technical Rule for VOC and proposed in section X.B.1 for methane. Because of the nature of well completions, any completion (or recompletion) is considered a new or modified well affected facility, therefore, the EPA does not believe there are existing well affected facilities to which a EG OOOOc presumptive standard for well completions would apply.
J. Sweetening Units
	Based on our understanding that no advances in technologies or practices are available to reduce SO2 emissions from sweetening units, as described in section XIII.J, the EPA is proposing to retain the standards as it continues to reflect the BSER. These proposed standards are the same as those for sweetening units regulated in the 2016 NSPS OOOOa, and as amended in the 2020 Technical Rule.
K. Centralized Production Facilities
	The EPA is also proposing a new definition for "centralized production facility," which is "one or more permanent storage tanks and all equipment at a single stationary source used to gather, for the purpose of sale or processing to sell, crude oil, condensate, produced water, or intermediate hydrocarbon liquid from one or more offsite natural gas or oil production wells. This equipment includes, but is not limited to, equipment used for storage, separation, treating, dehydration, artificial lift, combustion, compression, pumping, metering, monitoring, and flowline. Process vessels and process tanks are not considered storage vessels or storage tanks. A centralized production facility is located upstream of the natural gas processing plant or the crude oil pipeline breakout station and is a part of producing operations." The EPA is proposing this definition to (1) specify how the fugitive emissions requirement apply to centralized production facilities, (2) specify how exemptions related to 40 CFR part 60, subparts K, Ka, or Kb ("NSPS Kb) may apply, and (3) specify what standards would apply to reciprocating and centrifugal compressors located at these facilities.
	First, the EPA is proposing to specify how the fugitive emission requirements apply to centralized production facilities. The 2016 NSPS OOOOa, as originally promulgated, provided that "[f]or purposes of the fugitive emissions standards at 40 CFR 60.5397a, [a] well site also means a separate tank battery surface site collecting crude oil, condensate, intermediate hydrocarbon liquids, or produced water from wells not located at the well site (e.g., centralized tank batteries)." 40 CFR 60.5430a. The inclusion of centralized tank batteries in the definition of well site was used to clarify the boundary of a well site for purposes of the fugitive emissions requirements. Further, in the RTC for the 2016 NSPS OOOOa we stated, "[o]ur intent is to limit the oil and gas production segment up to the point of custody transfer to an oil and natural gas mainline pipeline (including transmission pipelines) or a natural gas processing plant. Therefore, the collection of fugitive emissions components within this boundary are a part of the well site." The EPA continues to define these facilities as a type of well site but is proposing a separate definition to provide further clarity, especially as it relates to when these facilities are modified, and thus become subject to the fugitive emissions requirements in NSPS OOOOb. The EPA has determined it is appropriate to rename this site as a centralized production facility and to provide the specific definition above to avoid confusion with the storage vessel affected facility, of which applicability is determined for a tank battery, and to better specify the facility name based on the basic function the site performs (i.e., production operations).
	Second, the EPA has received questions related to whether NSPS Kb would apply to the storage vessels at centralized production facilities. There is an exemption in NSPS Kb for storage vessels in the producing operations that are below a specific size. Specifically, 40 CFR 60.110(b)(4) exempts "vessels with a design capacity less than or equal to 1,589.874 m[3] used for petroleum or condensate stored, processed, or treated prior to custody transfer." This exemption is a revision of an exemption originally promulgated in 40 CFR part 60, subpart K ("NSPS K"). NSPS K "does not apply to storage vessels for the crude petroleum or condensate stored, processed, and/or treated at a drilling and production facility prior to custody transfer." 40 CFR 60.110(b). In that final rule the EPA explained that, "[t]he storage of crude oil and condensate at producing fields is specifically exempted from the standard." 39 FR 9312. While "producing fields" were not explicitly defined, NSPS K defined the terms "custody transfer" and "drilling and production facility". For purposes of NSPS K, custody transfer means "the transfer of produced crude petroleum and/or condensate, after processing and/or treating in the producing operations, from storage tanks or automatic transfer facilities to pipelines or any other forms of transportation." 40 CFR 60.111(g). Drilling and production facility means "all drilling and servicing equipment, wells, flow lines, separators, equipment, gathering lines, and auxiliary nontransportation-related equipment used in the production of crude petroleum but does not include natural gasoline plants." 40 CFR 60.111(h). The definition of "custody transfer" was later also incorporated into 40 CFR part 60, subpart Ka ("NSPS Ka"), NSPS Kb, and 40 CFR part 63, subpart HH (National Emission Standards for Hazardous Air Pollutants from Oil and Natural Gas Production Facilities).
	Instead of a categorical exemption for storage vessels located at drilling and production facilities, NSPS Ka, and subsequently NSPS Kb, adopted threshold-based exemptions that are based on the capacity of an individual storage vessel used to store petroleum (crude oil) or condensate prior to custody transfer. In NSPS Ka, the EPA stated "[t]his exemption applies to storage between the time that the petroleum liquid is removed from the ground and the time that custody of the petroleum liquid is transferred from the well or producing operations to the transportation operations" 45 FR 23377. In NSPS Kb, the EPA further stated that "[t]he promulgated standards for petroleum liquid storage vessels specifically exempted vessels with a capacity less than 420,000 gallons and storing petroleum (crude oil) and condensate prior to custody transfer (production vessels). The emission controls that are applicable to the storage vessels included in the standards being proposed are not applicable to production vessels." 49 FR 29701.
 	The EPA continues to find it inappropriate to use the controls required by NSPS K, Ka, and Kb on storage vessels located in the production segment, especially where flash emissions are prevalent. Specifically, the NSPS K, Ka, and Kb control requirements include provisions allowing the use of floating roofs to reduce emissions from storage tanks. Floating roofs are not designed to store liquid (or gases) under pressure. Pressurized liquid sent to a storage vessel from a well or separator or other process that operates above atmospheric pressure may contain dissolved gases. These gases will be released or "flash" from the liquid as the fluid comes to equilibrium with atmospheric pressure within the storage vessel. The flash gas will either be released from gaps in the seal system or from "rim vents" on the floating roof. The rim vent may be an open tube or may be fitted with a low-pressure relief valve, but it is specifically designed to allow any gas entrained or dissolved in the storage liquid to be released above the floating roof. That is, floating roofs are not designed to prevent the release of flash gas, they are only designed to limit the volatilization of a liquid that occurs when the storage liquid is directly exposed with unsaturated air. Since a significant portion of emissions from storage vessels at well sites or centralized production facilities are from flash gas, floating roofs are much less effective at reducing storage vessel emissions than venting these emissions through a CVS to a control or recovery device.
	Further, it is the EPA's understanding that these centralized production facilities carry out the same operations that would be conducted at the individual well sites. Therefore, the EPA is proposing a definition of "centralized production facility" that clearly specifies these facilities are located within the producing operations. Therefore, if all other conditions are met, storage vessels at these centralized facilities would meet the exemption criteria for NSPS Kb.
	Finally, the EPA is now proposing to define centralized production facilities separately from well sites because the number and size of equipment, particularly reciprocating and centrifugal compressors, is larger than standalone well sites which would not be included in the proposed definition of "centralized production facilities" above. In the 2016 NSPS OOOOa, the EPA exempted reciprocating and centrifugal compressors located at well sites from the applicable compressor standards.
      Reciprocating compressors that are located at well sites are not affected facilities under the 2016 NSPS OOOOa. The EPA previously excluded them because we found the cost of control to be unreasonable. 81 FR 35878. However, as mentioned above, the EPA believes the definition of "well site" in NSPS OOOOa may cause confusion regarding whether reciprocating compressors located at centralized production facilities are also exempt from the standards. In our current analysis, described in section XII.E, we find it is appropriate to apply the same emission factors to reciprocating compressors located at centralized production facilities as those used for reciprocating compressors at gathering and boosting compressor stations. Given the results of that analysis, the EPA is proposing to apply the proposed NSPS OOOOb and presumptive standards in EG OOOOc to reciprocating compressors located at centralized production facilities. The new definition above is intended to apply the results of the EPA's analysis. We believe that this new definition is necessary in the context of reciprocating compressors to distinguish between these compressors at centralized production facilities where the EPA has determined that the standard should apply, and these compressors at standalone well sites where the EPA has determined that the standard should not apply. See section XII.E for more details of those proposed standards.
      Similarly, wet seal centrifugal compressors that are located at well sites are not affected facilities under the 2016 NSPS OOOOa. The EPA previously excluded them because data available at the time did not suggest there were a large number of wet seal centrifugal compressors located at well sites. 81 FR 35878. In our current analysis, described in section XII.F, we find it is appropriate to apply the same emission factors to wet seal centrifugal compressors located at centralized production facilities as those used for these same compressors at gathering and boosting compressor stations. Given the results of that analysis, the EPA is proposing to apply the proposed NSPS OOOOb and presumptive standards in EG OOOOc to wet seal centrifugal compressors located at centralized production facilities. See section XII.F for more details of those proposed standards.
L. Recordkeeping and Reporting
	The EPA is proposing to require electronic reporting of performance test reports, annual reports, and semiannual reports through the Compliance and Emissions Data Reporting Interface (CEDRI). (CEDRI can be accessed through the EPA's Central Data Exchange (CDX) at https://cdx.epa.gov/.) A description of the electronic data submission process is provided in the memorandum Electronic Reporting Requirements for New Source Performance Standards (NSPS) and National Emission Standards for Hazardous Air Pollutants (NESHAP) Rules, available in the docket for this action. Performance test results collected using test methods that are supported by the EPA's Electronic Reporting Tool (ERT) as listed on the ERT website at the time of the test would be required to be submitted in the format generated through the use of the ERT or an electronic file consistent with the xml schema on the ERT website, and other performance test results be submitted in portable document format (PDF) using the attachment module of the ERT. For semiannual and annual reports, the owner or operator would be required to use the appropriate spreadsheet template to submit information to CEDRI.
	The EPA is also proposing to allow owners and operators the ability to seek extensions for submitting electronic reports for circumstances beyond the control of the facility, i.e., for a possible outage in CDX or CEDRI or for a force majeure event, in the time just prior to a report's due date. The EPA is providing these potential extensions to protect owners and operators from noncompliance in cases where they cannot successfully submit a report by the reporting deadline for reasons outside of their control. The decision to accept the claim of needing additional time to report is within the discretion of the Administrator.
      Electronic reporting is required in the amended 2016 NSPS OOOOa, and the EPA believes that the electronic submittal of these reports in the proposed NSPS OOOOb will increase the usefulness of the data contained in those reports, is in keeping with current trends in data availability, will further assist in the protection of public health and the environment, and will ultimately result in less burden on the regulated community. Electronic reporting can also eliminate paper-based, manual processes, thereby saving time and resources, simplifying data entry, eliminating redundancies, minimizing data reporting errors, and providing data quickly and accurately to the affected facilities, air agencies, the EPA, and the public. Moreover, electronic reporting is consistent with the EPA's plan to implement EO 13563 and is in keeping with the EPA's agency-wide policy developed in response to the White House's Digital Government Strategy.
 	In addition to the annual and semiannual reporting requirement, the EPA is soliciting comment on what elements, if any, are appropriate for more frequent reporting, and what mechanism would be appropriate for the collection and public dissemination of this information. For example, it may be appropriate to make information related to large emission events public in a timelier manner than the annual reporting period. Therefore, the EPA is soliciting comment on the appropriate mechanism to use for this type of report, including how the data would be reported, who would manage that reporting system, the frequency at which the data should be reported, the potential benefits of more frequent reporting for reducing emissions, the associated burden with this type of reporting and ways to mitigate that burden, and other considerations that should be taken into account.
M. Prevention of Significant Deterioration and Title V Permitting
 	The pollutant we are proposing to regulate is GHGs, not methane as a separately regulated pollutant. As explained in section XV of this preamble, we are proposing to add provisions to NSPS OOOOb and EG OOOOc, analogous to what was included in the 2016 NSPS OOOOa and other rules regulating GHGs from electric utility generating units, to make clear in the regulatory text that the pollutant regulated by this rule is GHGs. The proposed addition of these and other provisions is intended to address some of the potential implications on the CAA Prevention of Significant Deterioration (PSD) preconstruction permit program and the CAA title V operating permit program.
XII. Rationale for Proposed NSPS OOOOb and EG OOOOc
      The following sections provide the EPA's BSER analyses and the resulting proposed NSPS to reduce methane and VOC emissions and the resulting proposed EG, which include presumptive standards, to reduce methane emissions from across the Crude Oil and Natural Gas source category. Our general process for evaluating BSER for the emission sources discussed below included: (1) identification of available control measures; (2) evaluation of these measures to determine emission reductions achieved, associated costs, non-air environmental impacts, energy impacts and any limitations to their application; and (3) selection of the control techniques that represent BSER. As discussed in the 2016 NSPS OOOOa, the available control technologies will reduce both methane and VOC emissions at the same time. The revised BSER analysis we have undertaken for the sources addressed in the proposed NSPS OOOOb continues to support this conclusion. CAA Section 111 also requires the consideration of cost in determining BSER. Section IX describes how the EPA evaluates the cost of control for purposes of this rulemaking. Sections XII.A through XII.I provide the BSER analysis and the resulting proposed NSPS and EG for the individual emission sources contemplated in this action. Please note that there are minor differences in some values presented in various documents supporting this action. This is because some calculations have been performed independently (e.g., TSD calculations focused on unit-level cost-effectiveness and RIA calculations focused on national impacts) and include slightly different rounding of intermediate values. Further, for this proposed EG the EPA is proposing to translate the degree of emission limitation achievable through application of the BSER (i.e., level of stringency) into presumptive standards.
A. Proposed Standards for Fugitive Emissions from Well Sites and Compressor Stations
1. NSPS OOOOb
      There are several potential sources of fugitive emissions throughout the Crude Oil and Natural Gas Production source category. Fugitive emissions occur when connection points are not fitted properly or when seals and gaskets start to deteriorate. Changes in pressure and mechanical stresses can also cause components or equipment to emit fugitive emissions. Poor maintenance or operating practices, such as improperly reseated pressure relief valves (PRVs) or worn gaskets and springs on thief hatches on controlled storage vessels are also potential causes of fugitive emissions. Additional sources of fugitive emissions include agitator seals, connectors, pump diaphragms, flanges, instruments, meters, open-ended lines, PRDs such as PRVs, pump seals, valves or controlled liquid storage tanks.
      The 2021 GHGI estimates methane emissions of 72.2 MMT CO2 Eq. from onshore production in 2019 (the most recent year of estimates). Of this amount, equipment leaks account for around 10 MMT CO2 Eq. In addition, fugitive emissions may be represented in other categories of the GHGI production segment; for example, a portion of fugitive emissions are also expected to be related to emissions from malfunctioning pneumatic devices. Methane emissions from pneumatic devices are estimated to be 45.7 MMT CO2 Eq. within onshore production, according to the 2021 GHGI. According to the 2021 GHGI, the gathering and boosting segment is estimated to emit 40.9 MMT CO2 Eq. Of this amount, equipment leaks are estimated to be 2.4 MMT CO2 Eq. In the 2016 OOOOa Rule, the EPA promulgated standards to control GHGs (in the form of limitations on methane emissions) and VOC emissions from fugitive emissions components located at well sites and compressor stations. These standards required a fugitive emissions monitoring and repair program, where well sites and compressor stations had to be monitored semiannually and quarterly, respectively.
      As a result of the review of these requirements pursuant to CAA section 111(b)(1)(B), the EPA is proposing to control methane and VOC emissions by requiring semiannual monitoring for well sites with site-level baseline methane emissions greater than or equal to 5 tpy and less than 15 tpy; quarterly monitoring for well sites with site-level baseline methane emissions greater than or equal to 15 tpy; and quarterly monitoring for all compressor stations, which include gathering and boosting, transmission, and storage compressor stations. At well sites, the composition of gas is predominantly methane (approximately 70 percent). Therefore, monitoring for methane emissions would be required before monitoring for VOC emissions. For this reason, we chose to use methane as the threshold for our determination.
      In addition to the requirements to monitor for fugitive emissions from components based on the proposed definition of an affected facility under the fugitive emissions monitoring requirements of proposed NSPS OOOOb, the EPA is proposing to require use of the fugitive emissions monitoring program to demonstrate that "subcategory 2 natural gas-driven intermittent pneumatic controllers" (i.e., those located at a site without power) are meeting the proposed standard applicable to those affected facilities, which prohibits venting during idle periods. While these intermittent controllers are their own separate affected facilities instead of being part of the collection of  the fugitive emission components affected facilities, we are proposing that they be monitored in conjunction with fugitive components affected facilities located at the same well site or compressor station in accordance with the proposed fugitive emissions standards applicable to that well site or compressor station, as explained in section XII.D.  Accordingly, the cost of monitoring these intermittent controllers is evaluated in this section. As shown in section XII.A.1, this cost does not substantially change the cost of the OGI survey required for fugitive emissions components since monitoring intermittent controllers does not increase the survey time unless they are found to be malfunctioning.
      Previously the BSER analyses for fugitive emissions from well sites in the 2016 NSPS OOOOa and the 2020 Technical Rule were based on "model" plants, without regard to the actual types and number of equipment (and corresponding fugitive emission potential) at individual sites. The EPA developed separate model plants based on production levels for the 2020 Technical Rule, but that effort was based on very limited data and there were considerable comments received on the uncertainty regarding the relationship between the fugitive emissions and production levels. The EPA has now determined that its prior model plant approach cannot adequately account of various factors that affect the level of fugitive emissions. Such factors include the wide variation in the well characteristics, type of oil and gas products and production levels, gas composition, and types of equipment at well sites. Therefore, the EPA has revised the fundamental approach for estimating the baseline emissions from well sites as the foundation for the BSER analysis, where these baseline emissions will be determined for each site using site-specific information. Based on this new approach, described in more detail below, the EPA determined that the BSER for reducing methane and VOC from well sites would be monitoring frequencies based on a well site's baseline methane emissions. The EPA concluded that the model plant approach used in previous analyses for compressor stations is still a sound means to evaluate BSER.
a. Fugitive Emissions from Well Sites
      Oil and natural gas production practices and equipment vary from well site to well site. A well site can serve one well or multiple wells. Some production sites may include only a single wellhead that is extracting oil or natural gas from the ground, while other sites may include multiple wellheads with a number of operations such as production, extraction, recovery, lifting, stabilization, separation and/or treating of petroleum and/or natural gas (including condensate). In addition, the 2016 NSPS OOOOa definition of well site also includes centralized tank batteries to clarify the boundary of a well site for purposes of the fugitive emissions requirements. The equipment to perform these operations (including piping and associated components, compressors, generators, separators, storage vessels, and other equipment) has components that may be sources of fugitive emissions. Therefore, the number of components with the potential for fugitive emissions can vary depending on the number of wells and the number of major production and processing equipment at the site. Another factor that impacts the operations at a well site, and the resulting fugitive emissions potential, is the nature of the oil and natural gas being extracted. This can range from well sites that only extract and handle "dry" natural gas to those that extract and handle heavy oil.
      As noted above, in both the 2016 NSPS OOOOa and subsequent amendments in the 2020 Technical Rule, the EPA relied on a model plant approach to estimate emissions from well sites. Model plants were developed to provide a representation of well sites across the spectrum. Separate production-based model plants using component counts to determine baseline emissions were developed. The basic approach used was to assign a number of specific equipment types for each well site model plant and then to estimate the number of components based on assigned numbers of components per equipment type. Primarily, the well site model plants utilized information from the DrillingInfo HPDI(R) database, the 1996 EPA/GRI Study, EPA's GHG Inventory, and GHGRP subpart W. Fugitive model plants were originally developed for the 2015 NSPS OOOOa proposed rule and evolved over time in response to new information and public comments. More information on the history of the model plant development can be found in the 2015 NSPS Proposal TSD, the 2016 NSPS Final TSD, the 2018 NSPS Proposal TSD, and the 2020 NSPS Final TSD.
      In this proposal, the EPA is shifting away from using model plants for well sites for the BSER analysis and is instead using an individual site-level emission-calculation approach in order to better characterize and take into account the differences at individual well sites that can lead to a vast range in the magnitude of fugitive emissions, which a model plant cannot do. Provided below is a more detailed explanation of the issues concerning the previous model plant approach, followed by a description of the site-specific baseline emission calculation approach, which is similar to the State of Colorado's LDAR program.
      In the 2020 Technical Rule, the EPA created separate model plants to represent fugitive emissions from low production well sites (those producing 15 boe or less per day) and non-low production well sites, as it was generally assumed that low producing sites would have fewer major production and processing equipment and thus lower fugitive emissions. This prior estimate of baseline emissions was calculated using model plant site designs with assumed populations of major production and processing equipment and fixed fugitive emissions component counts. While the estimated baseline emissions from the two model plants differ due to the difference in the assumed populations of major production and processing equipment and fixed fugitive emissions component counts, the estimated baseline emissions were intended to represent the baseline emissions for all well sites represented by each model plant. Since that rulemaking, further analysis of existing and new information indicates that there is significant variation in the operations, and types and quantity of equipment at well sites across the U.S., and the EPA has concluded that the previous model plant approach may not be reflective of differences in baseline fugitive emissions from all the different well sites.  Further, the potential for fugitive emissions at any given site is impacted more by the number and type of equipment at the site and maintenance practices, and not by the volume of production. Given these limitations in utilizing model plants to analyze fugitive emission reduction programs at well sites with widely varying configurations, operations, and production levels, we find it appropriate to shift away from using model plants and instead rely on the potential fugitive emissions at the individual site in our BSER analysis and resulting proposed standards. Therefore, this new analysis, which is described below, is conducted on this basis.
      This site-specific baseline emissions calculation approach is similar to the State of Colorado's LDAR program. The concept is that each site calculates its baseline methane emissions for all the equipment at the site, the number and type of equipment at the well site, the number of fugitive emissions components associated with each piece of equipment, and the site-specific gas composition. The fugitive monitoring frequency would be based on the baseline site-specific methane emissions level calculated based on this information. This calculation is described in detail in section XI.A.3. We believe that this approach will more accurately depict the emissions profile at each individual well site. As a result, the EPA is conducting the BSER analysis based on site-level baseline methane emissions, where the analysis will be performed in increments of 1 tpy of site-level baseline methane emissions as discussed more below.
      During the rulemaking for the 2016 NSPS OOOOa, the EPA analyzed two options for reducing fugitive methane and VOC emissions at well sites: a fugitive emissions monitoring program based on individual component monitoring using EPA Method 21 for detection combined with repairs and 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 semiannual monitoring of well sites using OGI as the BSER. 81 FR 35856. 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 the use of 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 biennial, annual, semiannual, quarterly, and monthly survey frequency for well sites.
The regulatory concept for the proposed NSPS OOOOb is that the required frequency of fugitive monitoring would be based on total site baseline methane emissions.
	For the BSER analyses, we selected for evaluation total site-wide methane and VOC emissions increments of 1 tpy of site-level baseline methane emissions ranging from 1 tpy to 50 tpy. For purposes of estimating fugitive emissions and emissions reductions achievable via the OGI-based monitoring program, we assume that 50 percent of the total site emissions are fugitive emissions that can be mitigated through an OGI-based program (the other 50 percent of the site emissions are emissions that are "allowed"). While this could be overstating or understating the percentage of emissions that are fugitive, and that can be mitigated through the fugitive program, the EPA concludes this is a reasonable assumption for this analysis because certain emissions, such as those from a low-bleed natural gas-driven pneumatic controller, will occur as part of normal operations and would not be considered fugitive emissions. The EPA acknowledges that the site-level baseline methane emissions calculated may not account for the presence of large emission events when they occur. However, the EPA has found it inappropriate to apply a factor that assumes every site is experiencing a large emission event annually based on information suggesting that only a small percentage of sites experience these events at any given time.
      In 2015, we evaluated the potential emission reductions from the implementation of an OGI monitoring program where we assigned an emission reduction of 40, 60 and 80 percent to annual, semiannual, and quarterly monitoring survey frequencies, respectively. The EPA re-evaluated the control efficiencies under different monitoring frequencies for the 2020 Technical Rule based on comments received on the 2018 proposal and concluded that the assigned control efficiencies described above can be expected from the corresponding monitoring frequencies using OGI. No other information reviewed since that time 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 biennial survey frequency for well sites assuming an achievable reduction frequency of 30 percent, and monthly monitoring where information evaluated indicated monthly OGI monitoring has the potential of reducing emissions up towards 90 percent.
      Therefore, for the BSER analysis, the emission reduction estimates were calculated as follows, using the 5 tpy methane total site-wide methane emissions as an example. Application of the 50-percent assumption discussed above results in a fugitive emission estimate of 2.5 tpy of methane. The methane emission reductions for an annual program (40 percent reduction), semiannual program (60 percent reduction), and quarterly program (80 percent reduction) would be 1 tpy, 1.5 tpy, and 2 tpy, respectively.
      It is worth noting that these calculations are based on the expected reductions from "typical" component equipment leaks that occur with well-maintained sites. The EPA is aware of situations where equipment malfunctions related to equipment components can cause large emission events that are described in detail in section XII.A.3. In these cases, we expect the emission reductions associated with the different monitoring frequencies evaluated would be significantly higher than assumed above and is the reason we solicit comment on programs using emerging technologies to identify and quantify large emission sources. As acknowledged above, the 50 percent estimate of fugitive emissions could be over or under-estimating the percentage of emissions that are fugitives, however, the EPA believes this estimate is reasonably representative and captures the average distribution of emissions across typical well sites based on information available at this time. Given the intermittent and stochastic nature of large emission events, it is difficult to apply emission factors that predict the probability of a site experiencing these events within any timeframe. As stated above, the EPA finds it inappropriate to apply a factor that assumes every site is experiencing a large emission event annually given the available data. However, we recognize there is a lot of study on this topic and solicit additional information on large emission events that may further inform the EPA's calculations, including the potential to develop factors that take into account a distribution of emissions across well sites and the associated emissions reductions achieved when large emission events are included in the calculation.
      We evaluated the costs of a monitoring and repair program under various monitoring frequencies. For well sites, the capital costs associated with the fugitives monitoring program were estimated to be $1,030 per well site. These capital costs include the cost of developing the fugitive emissions monitoring plan and purchasing or developing a recordkeeping data management system specific to fugitive emissions monitoring and repair. Consistent with the analyses used for the 2016 NSPS OOOOa and 2020 Technical Rule, the EPA assumes that each company will develop a monitoring plan and recordkeeping system that covers a company-defined area, which is assumed to include 22 well sites. This assumption is used because there are several elements of the fugitive monitoring program that are not site-specific. The total company-defined area (22 well site) capital costs are divided evenly to arrive at the $1,030 capital cost per well site estimate.
      When evaluating the annual costs of the fugitive emissions monitoring and repair requirements (i.e., monitoring, repair, repair verification, data management licensing fees, recordkeeping, and reporting), the EPA considers costs at the individual site level. Estimates for these costs were updated extensively as part of the 2020 Technical Rule, and the EPA has made further updates for this proposal based on more recent information and to add costs related to the repair of intermittent controllers that are not meeting the proposed standard to not vent when idle. With these updates, the estimated annual costs of the fugitive emissions program at well sites are estimated to range from $2,490 for biennial monitoring to $8,140 for monthly monitoring. These total annual costs include annualization of the up-front cost at 7 percent interest rate over 8 years. We note these costs are representative of the average annual costs expected at well sites, where larger sites may have larger costs associated with longer surveys or potentially more repairs, while smaller sites may experience the opposite with shorter surveys or potentially less repairs. Therefore, we believe the costs developed for well sites are representative of OGI fugitives monitoring program costs and reflect the best information available at this time.
      At well sites, there are savings associated with the gas not being released. The value of the natural gas saved is assumed to be $3.13/Mcf of recovered gas. Annual costs were also calculated considering these savings.
      As discussed in the introduction to this section and in section XI.C, 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 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. While these intermittent controllers are their own separate affected facility, we are proposing that they be monitored in conjunction with the fugitive emissions components located at the same well site to verify proper actuation and that venting does not occur during idle times. For this reason, the cost of monitoring these intermittent controllers are evaluated in this discussion regarding fugitive emissions. We have included an additional cost to repair a potentially malfunctioning or improperly operating controllers ($600) in the annual cost of the fugitive emissions program presented above.
      We created a matrix that includes, for each site-wide methane emission level, the capital (up front) cost, annual costs (with and without the consideration of savings), emission reductions for methane and VOC, and cost effectiveness (dollar per tons of emission reduction). Cost effectiveness was calculated using two approaches; the single pollutant approach where all the costs are assigned to the reduction of one pollutant; and the multipollutant approach, where half the costs are assigned to the methane reduction and half to the VOC reduction, see discussion in preamble section IX. This was repeated for each site-wide methane emissions level for each monitoring frequency. There were several trends shown in this matrix. As noted above, the same annual cost was applied for each monitoring frequency across all site-wide emission levels. Therefore, as the emissions (and potential emission reductions) increased, the fugitive emissions monitoring became more cost-effective. For example, for semiannual monitoring, the cost effectiveness ranged from $10,700 per ton of methane reduced (for a 1 tpy site-wide methane site) to $210 per ton (for a 50 tpy site-wide methane site). Also, because the emission reduction increase was greater than the cost increase with increasing monitoring frequency, the fugitive emissions monitoring became more cost-effective with increasing monitoring frequency. For example, for a 10 tpy site-wide methane site, the methane cost effectiveness for annual monitoring was $1,500 per ton, $1,070 per ton for semiannual monitoring, and $1,050 per ton for quarterly monitoring. This trend did not extend to monthly monitoring, as the cost of monthly monitoring increases significantly (almost double) compared to quarterly monitoring, while the emission reduction only increased by 10 percent. The complete matrix is available in the TSD for this rulemaking.
      The next step in the EPA's BSER analysis was to balance combinations of the baseline site-wide emission level and monitoring frequency where the maximum emission reduction could be achieved while the cost effectiveness was considered reasonable. First, the EPA determined the minimum baseline methane emissions above which ground based OGI monitoring was considered reasonable. To do this, we evaluate the baseline methane emissions in increments of 1 tpy and then identified the lowest baseline for each monitoring frequency that was reasonable. When considering the single-pollutant approach, we found that monitoring at any frequency may be reasonable when the total site-level baseline methane emissions are at least 5 tpy. When considering the multipollutant approach, we found that baseline may shift to at least 4 tpy total site-level baseline methane emissions. Table 14 summarizes this information for each monitoring frequency evaluated.
TABLE 14. SUMMARY OF EMISSION REDUCTIONS AND COST-EFFECTIVENESS FOR SITE-LEVEL BASELINE METHANE EMISSIONS OF 4 AND 5 TPY
                             Monitoring Frequency
                            Annual Cost ($/yr/site)
                     Methane Emission Reduction (tpy/site)
                       VOC Emission Reduction (tpy/site)
                               Single-Pollutant
                                Multipollutant

                          Methane Cost-Effectiveness
                                    ($/ton)
                            VOC Cost-Effectiveness
                                    ($/ton)
                          Methane Cost-Effectiveness
                                    ($/ton)
                            VOC Cost-Effectiveness
                                    ($/ton)
5 tpy site-level baseline methane emissions
Biennial
                                    $2,500
                                     0.75
                                     0.21
                                    $3,300
                                    $12,000
                                    $1,700
                                    $6,000
Annual
                                    $3,000
                                     1.00
                                     0.28
                                    $3,000
                                    $10,800
                                    $1,500
                                    $5,400
Semiannual
                                    $3,200
                                     1.50
                                     0.42
                                    $2,100
                                    $7,700
                                    $1,100
                                    $3,800
Quarterly
                                    $4,200
                                     2.00
                                     0.56
                                    $2,100
                                    $7,600
                                    $1,100
                                    $3,800
Monthly
                                    $8,100
                                     2.25
                                     0.63
                                    $3,600
                                    $13,000
                                    $1,800
                                    $6,500
4 tpy site-level baseline methane emissions
Biennial
                                    $2,500
                                     0.60
                                     0.17
                                    $4,200
                                    $14,000
                                    $2,100
                                    $7,500
Annual
                                    $3,000
                                     0.80
                                     0.22
                                    $3,700
                                    $13,500
                                    $1,900
                                    $6,700
Semiannual
                                    $3,200
                                     1.20
                                     0.33
                                    $2,700
                                    $9,600
                                    $1,300
                                    $4,800
Quarterly
                                    $4,200
                                     1.60
                                     0.44
                                    $2,600
                                    $9,500
                                    $1,300
                                    $4,700
Monthly
                                    $8,100
                                     1.80
                                     0.50
                                    $4,500
                                    $16,300
                                    $2,300
                                    $8,100

      Based on the information summarized in Table 14, the costs appear to be reasonable for either semiannual or quarterly monitoring when site-level baseline methane emissions are 5 tpy or greater under the single pollutant approach or 4 tpy or greater under the multipollutant approach. Since 2016, owners and operators have been conducting semiannual monitoring pursuant to NSPS OOOOa, state requirements, or voluntarily, thus allowing us to conclude the cost is reasonable for that frequency. Additionally, the cost is comparable to the costs found reasonable in the both the 2016 NSPS OOOOa and 2020 Technical Rule for both the single pollutant approach for methane or multipollutant approach. The additional emission reductions achieved by adopting a minimum threshold of 4 tpy are 0.3 to 0.4 tpy for semiannual and quarterly monitoring, respectively, but it is unclear if there would be additional costs associated with achieving those reductions. We can, however, evaluate the incremental costs of going from semiannual to quarterly monitoring. The incremental costs of semiannual to quarterly monitoring for an emissions baseline of 5 tpy methane is $2,000/ton methane and $7,200/ton VOC. The incremental costs of semiannual to quarterly monitoring for an emissions baseline of 4 tpy methane is $2,500/ton methane and $9,000/ton VOC. While $2,500/ton methane reduced may be somewhat higher than what we can confidently conclude is cost-effective, $9,000/ton VOC reduced is well above what we have historically considered cost-effective for VOC reduction, as is $7,200/ton VOC reduced. Given the uncertainty of the incremental costs associated with achieving the additional 0.3 tpy methane reductions (0.09 tpy VOC reductions) when setting an emission threshold of 4 tpy, the EPA is not proposing using this minimum threshold. Therefore, the EPA is proposing that semiannual monitoring is appropriate for well sites with total site-level baseline methane emissions of at least 5 tpy.
      Where total site-level baseline methane emissions are below 5 tpy, the information currently available to the EPA does not show ground based OGI monitoring at any frequency to be cost-effective. The EPA seeks comment on all aspects of our analysis, including comment on our estimates of the costs and emission reduction benefits associated with OGI monitoring at this cohort of sites or other information and data that would support the feasibility and cost-effectiveness of OGI monitoring at these sites. We also believe that at emissions below 5 tpy methane, a more targeted approach to identifying which well sites are actually experiencing large emission events (which the emerging technologies for which the EPA seeks comment in section X.A.1 would enable) may be more appropriate than requiring ground based OGI surveys at regular frequencies. For example, if the EPA were to instead adopt a program that utilizes emerging technologies in a supplemental proposal, all owners and operators of well sites (regardless of site-level baseline methane emissions estimates) would have the ability to screen for emissions across a larger area, and thus target ground OGI surveys at those sites where screening identifies emissions, instead of requiring OGI at a set frequency at large numbers of sites that may not have fugitive emissions at the time of the survey.  As noted elsewhere in this section, the EPA seeks information, data and analysis that would support the establishment of ongoing monitoring requirements at all well sites, including at the cohort of sites with baseline methane emissions below 5 tpy, using these emerging technologies  -  including information on the capabilities of these emerging technologies, methodologies for their use, and the costs and emission reductions associated with using these emerging technologies as part of a regulatory monitoring regime.  Finally, as we stated in section XX, for sites below 5 tpy, we are proposing obligations to demonstrate that their emissions are and remain below 5 tpy.
      Further, 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 5 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. Further, it is our understanding that the emission factors for natural gas-driven pneumatic pumps and natural gas-driven pneumatic controllers are representative of pneumatic devices that are associated with this major production and processing equipment, and not pneumatic devices associated with the wellhead itself. Additionally, storage vessels would not be present. Therefore, the only emissions would be calculated based on the fugitive emissions components associated with the wellhead, which we believe would never be above 5 tpy.
      Having established a baseline where semiannual monitoring is reasonable (5 tpy methane), we next evaluated whether there are baseline emissions where quarterly or monthly monitoring is reasonable. Following the same incremental procedure discussed above, we evaluated methane emissions in 1 tpy increments starting at 5 tpy to determine when quarterly or monthly monitoring is reasonable. Table 15 summarizes the incremental costs of semiannual to quarterly, and quarterly to monthly, for baseline methane emissions between 5 tpy and 20 tpy (in 5 tpy increments).
TABLE 15. SUMMARY OF INCREMENTAL COST-EFFECTIVENESS FOR FUGITIVE MONITORING AT WELL SITES
                  Site-Level Baseline Methane Emissions (tpy)
                      Incremental Annual Cost ($/yr/site)
               Incremental Methane Emission Reduction (tpy/site)
                 Incremental VOC Emission Reduction (tpy/site)
                        Incremental Cost-Effectiveness

                                Methane ($/ton)
                                  VOC ($/ton)
Incremental for semiannual to quarterly
5
                                    $1,000
                                     0.50
                                     0.14
                                    $2,000
                                    $7,200
10
                                    $1,000
                                     1.00
                                     0.28
                                    $1,000
                                    $3,600
15
                                    $1,000
                                     1.50
                                     0.42
                                     $670
                                    $2,400
20
                                    $1,000
                                     2.00
                                     0.55
                                     $500
                                     $1800
Incremental for quarterly to monthly
5
                                    $3,900
                                     0.25
                                     0.07
                                    $15,700
                                    $56,600
10
                                    $3,900
                                     0.50
                                     0.14
                                    $7,900
                                    $28,300
15
                                    $3,900
                                     0.75
                                     0.21
                                    $5,200
                                    $18,900
20
                                    $3,900
                                     1.00
                                     0.28
                                    $3,900
                                    $14,100

      The information summarized in Table 15 clearly demonstrates that monthly OGI monitoring is not reasonable at any of these thresholds. Therefore, we are not proposing monthly OGI monitoring for any well sites. For the incremental costs of going from semiannual to quarterly monitoring, it appears reasonable at either 10, 15, or 20 tpy methane thresholds. The EPA also weighed information provided by environmental groups that suggested gas well sites with production above 15 boe per day have baseline site emissions of 15.5 tpy methane. As stated in section X.A.1, while the EPA has proposed to remove the exemption for low production well sites in NSPS OOOOa (and chosen to utilize site-level emissions in NSPS OOOOb), we are still concerned this analysis may not adequately reflect the cost burden on small businesses, many of which own or operate lower producing well sites. Therefore, the EPA is proposing to require quarterly OGI monitoring at well sites with total site-level baseline methane emissions of 15 tpy or greater (which data indicates represents non-low producing sites), and semiannual OGI monitoring at well sites with total site-level baseline methane emissions greater than or equal to 5 tpy and less than 15 tpy.
      In summary, based on the analysis described above, the EPA selected three baseline total site-wide methane emission levels to represent thresholds that would determine the monitoring frequency. These are (1) well sites with total site-wide methane emissions less than 5 tpy (baseline VOC emissions 1.59 tpy), (2) well sites with total site-side methane emissions of 5 tpy or greater but less than 15 tpy, and (3) well sites with total site-wide methane emissions of 15 tpy or greater (baseline VOC emissions 4.17 tpy). The corresponding proposed monitoring frequency for these thresholds are (1) no monitoring for sites with baseline methane emissions less than 5 tpy (but sites must calculate and maintain a record of the baseline emission calculation), (2) semiannual monitoring for sites with baseline methane emissions greater than or equal to 5 tpy but less than 15 tpy, and (3) quarterly monitoring for sites with baseline methane emissions greater than or equal to 15 tpy.
      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 small wells that have low production and thus, low revenues. As explained above, the EPA developed and analyzed separate "low production" model plants in the past but has since recognized that there is not always a direct correlation between production and fugitive emissions due to the significant variation in the operations, and types and quantity of equipment at well sites across the U.S. irrespective of production level. The lack of a direct correlation between production and fugitive emissions has also been pointed out by commenters that represent both industry and environmental NGOs. We think that the burden imposed by the fugitive monitoring requirements differs depending on the numbers and types of equipment required to be monitored; therefore, we anticipate low production well sites with few major production and processing equipment would likely have baseline fugitive methane emissions below 5 tpy and thereby not be subject to the proposed ground based OGI monitoring frequencies. We believe that this revised approach to establishing fugitive emission monitoring requirements will address the concerns of small operators, while focusing leak detection and repair requirements on sites that are estimated to have greater fugitive emissions and correspondingly greater potential to reduce those emissions cost-effectively. Each site will calculate their site-wide methane emissions based on the actual equipment on site, and determine the frequency of monitoring required, if any. The EPA is specifically soliciting comments on how this revised approach helps identify those sources that have higher potential for fugitive emissions and if it lessens the burden on small sites with limited equipment and emission reductions potential.
      The 2016 NSPS OOOOa requires a fugitive emissions monitoring and repair program, where well sites are monitored semiannually. Well sites have successfully met this standard, though the EPA does not have information on how many of those sites are owned or operated by small businesses, or the number of low production sites that have been subject to the 2016 NSPS OOOOa standards. Also, several state agencies have rules that require at least semiannual monitoring for well sites. For example, Colorado's Regulation 7 Control of Ozone via Ozone Precursors and Control of Hydrocarbons via Oil and Gas Emissions requires a semiannual inspection frequency for well production facilities with uncontrolled actual VOC emissions between 2 and 12 tpy. Quarterly inspections are required for well sites with uncontrolled actual VOC emissions between 12 and 20 tpy (and between 12 and 50 tpy for facilities with storage tanks). Colorado Regulation 7 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). 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. 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. These examples of state rules requiring monitoring as frequently as monthly in some cases, and production continuing is a demonstration of the reasonableness of monitoring fugitive emissions components on at least a semiannual basis for well sites.
      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 our conclusions described in the cost-effectiveness analysis.
      In light of the above, we find that BSER for reducing methane and VOC emissions from well sites with site-level baseline methane emissions less than 5 tpy is no ground based OGI monitoring. For well sites with site-level baseline methane emissions greater than and equal to 5 tpy and less than 15 tpy, we find that BSER is semiannual monitoring. For well sites with site-level baseline methane emissions greater than and equal to 15 tpy, we find that BSER is quarterly monitoring. Therefore, for NSPS OOOOb, we are proposing to require semiannual monitoring for well sites with site-level baseline methane emissions greater than and equal to 5 tpy and less than 15 tpy, and quarterly monitoring for well sites with site-level baseline methane emissions greater than and equal to 15 tpy. This monitoring includes monitoring of subcategory 2 natural gas-driven intermittent pneumatic controllers to ensure they are not venting during idle. While the EPA believes that well sites with intermittent controllers will also have equipment with emissions that will exceed the 5 tpy minimum threshold proposed, we are soliciting comment on whether there are instances where intermittent controllers are located at well sites that would not exceed 5 tpy for site-level baseline methane emissions, and on appropriate means to ensure compliance with the proposed standard for subcategory 2 intermittent controllers to not vent when idle.
 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. 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 TSD and in the 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.