Pursuant to CAA section 111(b), we are both amending subpart OOOO and adding a new subpart, OOOOa. We are amending subpart OOOO, which applies to facilities constructed, modified or reconstructed after August 23, 2011, (i.e., the original proposal date of subpart OOOO) and on or before September 18, 2015 (i.e., the proposal date of the new subpart OOOOa), and is amended only to include the revisions reflecting implementation improvements in response to issues raised in petitions for reconsideration. We are adding subpart OOOOa, which will apply to facilities constructed, modified or reconstructed after September 18, 2015, to include current VOC requirements already provided in subpart OOOO (as updated) as well as new provisions for GHGs and VOCs across the oil and natural gas source category as highlighted below in this section.
 	As the purpose of this action is to control and limit emissions of GHG and VOC, EPA seeks to confirm that all regulatory standards are met. Any owner or operator claiming technical infeasibility, nonapplicability, or exemption from the regulation has the burden to demonstrate the claim is reasonable based on the relevant information. In any subsequent review of a technical infeasibility or nonapplicability determination, or a claimed exemption, EPA will independently assess the basis for the claim to ensure flaring is limited and emissions are minimized, in compliance with the rule. Well-designed rules ensure fairness among industry competitors and are essential to the success of future enforcement efforts.
B. Centrifugal Compressors
      We are finalizing amendments to the 2012 NSPS, and adding new requirements to establish both VOC and GHG standards (in the form of limitations on methane emissions) for new, modified or reconstructed wet seal centrifugal compressors located across the oil and natural gas source category. Specifically, the final rule adds GHG standards to the current VOC standards for wet seal centrifugal compressors, as well as establishing GHG and VOC standards for those that are currently unregulated, with one exception. We are not establishing requirements for centrifugal compressors at well sites. As finalized, the standards require a 95 percent reduction of the emissions from each wet seal centrifugal compressor affected facility. 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 routing to a process.
C. Reciprocating Compressors
      We are finalizing amendments to the 2012 NSPS and adding new requirements to establish both VOC and GHG standards (in the form of limitations on methane emissions) for new, modified, or reconstructed reciprocating compressors located across the oil and natural gas source category. Specifically, the final rule adds GHG standards to the current VOC standards for reciprocating compressors, as well as establishing GHG and VOC standards for those that are currently unregulated, with one exception. We are not establishing requirements for reciprocating compressors at well sites. The standards, which are operational standards, require either replacement of the rod packing based on usage or routing of rod packing emissions to a process via a closed vent system under negative pressure. The owner or operator of a reciprocating compressor affected facility is required to monitor the duration (in hours) that the compressor is operated, beginning on the date of initial startup of the reciprocating compressor affected facility. On or before 26,000 hours of operation, the owner or operator is required to change the rod packing. Owners or operators can elect to change the rod packing every 36 months in lieu of monitoring compressor operating hours. As an alternative to rod packing replacement, owners and operators may route the rod packing emissions to a process via a closed vent system operated at negative pressure.
D. Pneumatic Controllers
      We are finalizing amendments to the 2012 NSPS and adding new requirements to establish both VOC and GHG standards (in the form of limitations on methane emissions) for new, modified, or reconstructed pneumatic controllers located across the oil and natural gas source category. Specifically, the final rule adds GHG standards to the current VOC standards for pneumatic controllers and establishes GHG and VOC standards for those that are currently unregulated. We are finalizing GHG (in the form of limitations on methane emissions) and VOC standards to control emissions by requiring use of low-bleed controllers in place of high-bleed controllers (i.e., natural gas bleed rate not to exceed 6 standard cubic feet per hour (scfh)) at all locations within the source category except for natural gas processing plants. For natural gas processing plants, we are finalizing standards to control GHG and VOC emissions by requiring that pneumatic controllers have 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). These standards apply to each newly installed, modified or reconstructed pneumatic controller (including replacement of an existing controller). The finalized standards provide exemptions for certain critical applications based on functional considerations.
E. Pneumatic Pumps
	We are finalizing standards for natural gas-driven diaphragm pumps. The standards require that GHGs (in the form of limitations on methane emissions) and VOC emissions from new, modified and reconstructed natural gas-driven diaphragm pumps located at well sites be reduced by 95 percent if either a control device or the ability to route to a process is already available onsite, unless it is technically infeasible at sites other than new developments (i.e., greenfield sites). In setting this requirement, the EPA recognizes that there may not be a control device or process available onsite. Our analysis shows that it is not cost-effective to require the owner or operator of a pneumatic pump affected facility to install a new control device or process onsite to capture emissions. If a control device or ability to route to a process is not available onsite, the pneumatic pump affected facility is not subject to the emission reduction provisions of the final rule. In other instances, there may be a control device available onsite, but it may not be capable of achieving a 95 percent reduction. In those cases, we are not requiring the owner or operator to install a new control device onsite or to retrofit the existing control device, however, we are requiring the owner or operator of a pneumatic pump affected facility at a well site to route the emissions to an 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 final rule will achieve emission reductions with regard to pneumatic pump affected facilities even if the only available control device cannot achieve a 95 percent reduction. For pneumatic pumps located at natural gas processing plants, the standards require that GHG and VOC emissions from natural gas-driven diaphragm pumps be zero.
F. Well Completions
      We are finalizing GHG standards (in the form of limiting methane emissions) for well completions of hydraulically fractured (or refractured) gas wells as well as GHG and VOC standards for well completions of hydraulically fractured (or refractured) oil wells. As explained in the proposal preamble, the BSER for these emission reductions are the same as the BSER for reducing VOC emissions from hydraulically fractured gas wells. Therefore, the operational standards finalized in this action are essentially the same as the VOC standards for hydraulically fractured gas wells promulgated in the 2012 NSPS. For the reason stated above, the well completion standards in this final rule apply to both gas and oil well completions.
      As with gas wells, for well completions of hydraulically fractured (or refractured) oil wells, we identified two subcategories of hydraulically fractured wells for which well completions are conducted: (1) Non-wildcat and non-delineation wells (subcategory 1 wells); and (2) wildcat and delineation wells (subcategory 2 wells). A wildcat well, also referred to as an exploratory well, is a well drilled outside known fields or is the first well drilled in an oil or gas field where no other oil and gas production exists. A delineation well is a well drilled to determine the boundary of a field or producing reservoir.
      We are finalizing operational standards for subcategory 1 wells that require a combination of reduced emissions completion (REC) and combustion. Compared to combustion alone, the combination of REC and combustion will maximize gas recovery and minimize venting to the atmosphere. The finalized standards for subcategory 2 wells require combustion.
      For subcategory 1 wells, we define the flowback period of a well completion as consisting of two distinct stages, the "initial flowback stage" and the "separation flowback stage." The initial flowback stage begins with the onset of flowback and ends when the flowback is routed to a separator. Routing of the flowback to a separator is required as soon as a separator is able to function (i.e., the operator must route the flowback to a separator unless it is technically infeasible for a separator to function). Any gas in the flowback prior to the point at which a separator begins functioning is not subject to control. The point at which the separator can function marks the beginning of the separation flowback stage. During this stage, the operator must do the following, unless technically infeasible to do so as discussed below: (1) route all salable quality gas from the separator to a gas flow line or collection system; (2) re-inject the gas into the well or another well; (3) use the gas as an onsite fuel source; or (4) use the gas for another useful purpose that a purchased fuel or raw material would serve. If the operator assesses all four options for use of recovered gas, and still finds it technically infeasible to route the gas as described, the operator must route the gas to a completion combustion device with a continuous pilot flame and document the technical infeasibility assessment according to §60.5420a(c) of this final rule, which describes the specific types of information required to document that the operator has exercised due diligence in making the assessment. No direct venting of gas is allowed during the separation flowback stage unless combustion creates a fire or safety hazard or can damage tundra, permafrost or waterways. The separation flowback stage ends when the well is shut in and the flowback equipment is permanently disconnected from the well or on startup of production. This also marks the end of the flowback period.
      The operator has a general duty to safely maximize resource recovery and minimize releases to the atmosphere over the duration of the flowback period. For subcategory 1 wells (except for low gas to oil ratio (GOR) and low pressure wells discussed below), the operator is required to have a separator onsite during the entirety of the flowback period. The operator is also required to document the stages of the completion operation by maintaining records of (1) the date and time of the onset of flowback; (2) the date and time of each attempt to route flowback to the separator; (3) the date and time of each occurrence in which the operator reverted to the initial flowback stage; (4) the date and time of well shut in; and (5) the date and time that temporary flowback equipment is disconnected. In addition, the operator must document the total duration of venting, combustion and flaring over the flowback period. All flowback liquids during the initial flowback period and the separation flowback period must be routed to a well completion vessel, a storage vessel or a collection system. Because the BSER for oil wells and gas wells are the same, the final rule applies these requirements to both oil and gas wells.
      For subcategory 2 wells, we are finalizing an operational standard that requires either (1) routing all flowback directly to a completion combustion device with a continuous pilot flame (which can include a pit flare) or, at the option of the operator, (2) routing the flowback to a well completion vessel and sending the flowback to a separator as soon as a separator will function and then directing the separated gas to a completion combustion device with a continuous pilot flame. For option 2, any gas in the flowback prior to the point when the separator will function is not subject to control. In either case, combustion is not required if combustion creates a fire or safety hazard or can damage tundra, permafrost or waterways. Operators are required to maintain the same records described above for category 1 wells.
      As with gas wells, we similarly recognize the limitation of "low pressure" oil wells from conducting REC. Therefore, consistent with the 2012 NSPS, low pressure wells are affected facilities and have the same requirements as subcategory 2 wells (wildcat and delineation wells). We have revised the definition of a "low pressure" well in response to comment.
      Further, wells with a GOR of less than 300 scf of gas per stock tank barrel of oil produced are affected facilities, but have no well completion requirements, providing the owner or operator maintains records of the low GOR certification and a claim signed by the certifying official.
      We are also retaining the provision from the 2012 NSPS, now at §60.5365a(a)(1), that a well that is refractured, and for which the well completion operation is conducted according to the requirements of §60.5375a(a)(1) through (4), is not considered a modified well and, therefore, does not become an affected facility for purposes of the well completion standards. We point out that such an exclusion of a "well" from applicability under the NSPS has no effect on the affected facility status of the "well site" for purposes of the fugitive emissions standards at §60.5397a.
G. Fugitive Emissions from Well Sites and Compressor Stations
       We are finalizing standards to control GHGs (in the form of limitations on methane emissions) and VOC emissions from fugitive emission components at well sites and compressor stations. Specifically, we are finalizing semiannual monitoring and repair of fugitive emission components at well sites and quarterly monitoring and repair at compressor stations. Monitoring of the components must be conducted using optical gas imaging (OGI), and repairs must be made if any visible emissions are observed. Method 21 may be used as an alternative monitoring method at a repair threshold level at 500 parts per million (ppm). Repairs must be made within 30 days of finding fugitive emissions and a resurvey of the repaired component must be made within 30 days of the repair using OGI or Method 21 at a repair threshold of 500 ppm. A monitoring plan that covers the collection of fugitive emissions components at well sites or compressor stations within a company-defined area must be developed and implemented.
H. Equipment Leaks at Natural Gas Processing Plants
      We are finalizing standards to control GHGs (in the form of limitations on methane emissions) from equipment leaks at new, modified or reconstructed natural gas processing plants. These requirements are the same as the VOCs equipment leak requirements in the 2012 NSPS and require the level of control established in NSPS part 60, subpart VVa, including a detection level of 500 ppm for certain pieces of equipment, as in the 2012 NSPS. As with VOC reduction, we believe that subpart VVa level of control reflects the best system of emission reductions for reducing methane emissions.
I. Liquids Unloading Operations
      The EPA stated in the proposal that we did not have sufficient information to propose a national standard for liquids unloading. However, the EPA requested comment on nationally applicable technologies and techniques that reduce GHG and VOC emissions from these events. Although the EPA received valuable information from the public comment process, the information was not sufficient to finalize a national standard representing BSER for liquids unloading.
      Specifically, we requested data and information on the level of GHG and VOC emissions per unloading event, the number of unloading events per year, and the number of wells that perform liquids unloading. In addition, we requested comment on (1) characteristics of the well that play a role in the frequency of liquids unloading events and the level of emissions; (2) demonstrated techniques to reduce the emissions from liquids unloading events, including the use of smart automation and the effectiveness and cost of these techniques; (3) whether there are demonstrated techniques that can be employed on new wells that will reduce the emissions from liquids unloading events in the future; and (4) whether emissions from liquids unloading can be captured and routed to a control device and whether this has been demonstrated in practice.
      The EPA received some information pertaining to our request for information. Specifically, the EPA received information on the frequency of unloading and on techniques to reduce emissions through capture or flaring and learned of some operators that have been able to achieve capture in practice. While we have gained better understanding of the practice of liquids unloading, the EPA did not receive the necessary information to identify an emission reduction technology that can be applied across the category of sources. We also considered the possibility of subcategorization. However, according to the information received, the differences in liquids unloading events (with respect to both frequency and emission level) are not due to differences in well size or type of wells at which liquids unloading is performed, but rather the specific conditions of a given well at the time the operator determines that well production is impaired such that unloading must be done. Operators select the technique to perform liquids unloading operations based on the conditions of the well each time production is impaired. Because well conditions change over time, each iteration of unloading may require repeating a single technique or attempting a different technique that may not have been appropriate under prior conditions. Given the differences in conditions at different wells when liquids unloading must be performed, the EPA did not receive information about techniques, individually or as a group, that helped us to identify a BSER under our CAA section 111(b) authority. The EPA continues to search for better means to address emissions associated with liquids unloading and is including this emissions source in the upcoming information gathering effort. Please refer to the RTC for additional discussion on liquids unloading.
J. Recordkeeping and Reporting
      We are finalizing recordkeeping and reporting requirements that are consistent with those in the current NSPS. The final rule requires owners or operators to submit initial notifications and annual reports, in addition to retaining records to assist in documenting that they are complying with the provisions of the NSPS.
      For new, modified, or reconstructed pneumatic controllers, owners and operators are not required to submit an initial notification for each piece of equipment; rather, they must report the installation of these affected facilities in their first annual report following the compliance period during which they were installed. Owners or operators of well affected facilities (consistent with current requirements for gas well affected facilities) are required to submit an initial notification no later than two days prior to the commencement of each well completion operation. This notification must include contact information for the owner or operator, the United States Well Number (formerly the American Petroleum Institute (API) well number), the latitude and longitude coordinates for each well, and the planned date of the beginning of flowback.
      In addition, initial annual reports are due no later than 90 days after the end of the initial compliance period, which is established in the rule. Subsequent annual reports are due no later than the same date each year as the initial annual report. The annual reports include information on all affected facilities that were constructed, modified or reconstructed during the previous year. A single report may be submitted covering multiple affected facilities, provided that the report contains all the information required by §60.5420a(b). This information includes general information on the company (e.g., company name), as well as information specific to individual affected facilities, such as the well ID associated with the affected facility (e.g., storage vessels) and the facility site name (e.g., "Compressor Station XYZ" or "Tank Battery 123") and the address of the affected facility.
      For well affected facilities, the information required in the annual report includes the location of the well, the United States well number, the date and time of the onset of flowback following hydraulic fracturing or refracturing, the date and time of each attempt to direct flowback to a separator, the date and time of each occurrence of returning to the initial flowback stage, and the date and time that the well was shut in and the flowback equipment was permanently disconnected or the startup of production, the duration of flowback, the duration of recovery to the flow line, duration of the recovery of gas for another useful purpose, duration of combustion, duration of venting, and specific reasons for venting in lieu of capture or combustion. For each well for which a technical infeasibility exemption is claimed, to route the recovered gas to any of the four options specified in §60.5375a(a)(1)(ii), the report includes the reasons for the claim of technical infeasibility with respect to all four options provided in that subparagraph.
      For each well for which an exemption is claimed the owner or operator must maintain records of the low GOR certification and submit a claim signed by the certifying official in the annual report. For each well for which an exemption is claimed for conditions in which combustion may result in a fire hazard or explosion, or where high heat emissions from a completion combustion device may negatively impact tundra, permafrost or waterways, the report should include the location of the well, the United States Well Number, the specific exception claimed, the starting date and ending date for the period the well operated under the exception, and an explanation of why the well meets the claimed exception. The annual report must also include records of deviations where well completions were not conducted according to the applicable standards.
      For centrifugal compressor affected facilities, information in the annual report must include an identification of each centrifugal compressor using a wet seal system constructed, modified or reconstructed during the reporting period, as well as records of deviations in cases where the centrifugal compressor was not operated in compliance with the applicable standards.
      For reciprocating compressors, information in the annual report must include the cumulative number of hours of operation or the number of months since initial startup or the previous reciprocating compressor rod packing replacement, whichever is later, or a statement that emissions from the rod packing are being routed to a process through a closed vent system under negative pressure.
      Information in the annual report for pneumatic controller affected facilities includes location and documentation of manufacturer specifications of the natural gas bleed rate of each pneumatic controller installed during the reporting period. For pneumatic controllers for which the owner is claiming an exemption from the standards, the annual report includes documentation that the use of a pneumatic controller with a natural gas bleed rate greater than 6 scfh is required and the reasons why. The annual report also includes records of deviations from the applicable standards.
      For pneumatic pump affected facilities, information in the annual report includes an identification of each pneumatic pump constructed, modified or reconstructed during the compliance period; if applicable, a certification that no control was available onsite and that there is no ability to route to a process; an identification of any sites that contain pneumatic pumps and installed a control device during the reporting period, where there was previously no control device or ability to route to a process at a site; and records of deviations in cases where the pneumatic pump was not operated in compliance with the applicable standards.
      The final rule includes new requirements for monitoring and repairing sources of fugitive emissions at well sites and compressor stations. An owner or operator must submit an annual report, which covers the collection of fugitive emissions components at well sites and compressor stations within an area defined by the company. The report must include the date and time of the surveys completed during the reporting year, the name of the operator performing the survey; the ambient temperature, sky conditions, and maximum wind during the survey; the type of monitoring instrument used; the number and type of components that were found to have fugitive emissions; the number and type of components that were not repaired during the monitoring survey; the number and type of difficult-to-monitor and unsafe-to-monitor components that were monitored; the date of the successful repair of the fugitive emissions component if it was not repaired during the survey; the number and type of fugitive emission components that were placed on delay of repair and the explanation of why the component could not be repaired and was placed on delay of repair; and the type of monitoring instrument used to resurvey a repaired component that could not be repaired during the initial monitoring survey. If an owner or operator chooses to use Method 21 to conduct the monitoring survey, they are required to keep records that include the type of monitoring instrument used and the fugitive emissions component identification. The owner or operator is required to keep a log for each affected facility. The log must include the date the monitoring survey was performed, the technology used to perform the survey, the number and types of equipment found to have fugitive emissions, a digital photograph or video of the monitoring survey when an OGI instrument is used to perform the monitoring survey, the date or dates of first attempt to repair the source of fugitive emissions, the date of repair of each source of fugitive emissions that could not be repaired during the initial monitoring survey, any source of fugitive emissions found to be technically infeasible or unsafe to repair and an explanation of why the component was placed on delay of repair, a list of the fugitive emissions components that were tagged as a result of not being repaired during the initial monitoring survey, and a digital photograph or video of each untagged fugitive emissions component that could not be repaired during the monitoring survey when the fugitive emissions were initially found. These digital photographs and logs must be available at the affected facility or the field office.
      Consistent with the current requirements of subpart OOOO, records must be retained for 5 years and generally consist of the same information required in the initial notification and annual reports. The records may be maintained either onsite or at the nearest field office.
 K. Reconsideration Issues Being Addressed
      The EPA is finalizing numerous items in subpart OOOO on which we granted reconsideration and proposed changes with some further adjustments as a result of public comment. To the extent that these items relate to subpart OOOOa, we are also finalizing the same provisions for purposes of consistency between the two rules. First, we are finalizing corrections to the storage vessel control device monitoring and testing provisions related to in-field performance testing of enclosed combustors, initial and ongoing performance testing for any enclosed combustors used to comply with the emissions standard for an affected facility, and consistent requirements for monitoring of visible emissions for all enclosed combustion units. We are also finalizing clarified applicability requirements for storage vessel affected facilities. Next, we are finalizing amendments to include initial compliance requirements for bypass devices and certain closed vent systems and provide an alternative in subpart OOOO. Specifically, the rule allows for either an alarm at the bypass device or a remote alarm. The EPA is not finalizing our proposal to require both forms of alarm under subpart OOOO to avoid retroactive requirements.
Additionally, the EPA is finalizing recordkeeping requirements for repair logs for control devices failing a visible emissions test. We are clarifying the due date for the initial annual report and finalizing that flares used to comply with subpart OOOO are subject to the design and operation requirements in the general provisions. Next, we clarify that the monitoring provisions of subpart VVa applicable to affected units of subpart OOOO do not extend to open-ended valves or lines. We are finalizing clarification to the initial compliance requirement specifically to identify that the 2012 rule already includes a provision similar to subpart KKK. The EPA is finalizing the exemption from the notification required for reconstruction to affected facility pneumatic controllers, centrifugal compressors, and storage vessels in subpart OOOOa. The EPA is finalizing provisions for management of waste from spent carbon canisters. The EPA is finalizing a definition of the term "capital expenditure" in subpart OOOO. The EPA is finalizing an exemption for certain water recycling vessels that EPA did not intend to be affected facility storage vessels under subparts OOOO or OOOOa. By exempting such vessels, EPA will address a disincentive for recycling of water for hydraulic fracturing. Lastly, the EPA is not finalizing continuous control device monitoring requirements for storage vessels and centrifugal compressor affected facilities in subpart OOOO. For additional discussion of these issues, please refer to section VI of this preamble and the RTC.
 L. Technical Corrections and Clarifications
 	We discovered 22 drafting errors in the proposal and have corrected these errors in the final rule. Please see section VI for a complete list of technical corrections and clarifications.
 M. Prevention of Significant Deterioration and Title V Permitting
 	In the proposed rule, we stated that the pollutant we were proposing to regulate was GHGs, not methane as a separately regulated pollutant. 80 FR 56593, 56600-01 (Sept. 18, 2015). As explained in section VII of this preamble, we are adding provisions to the final rule, analogous to what was included in Standards of Performance for Greenhouse Gas Emissions from New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units, 80 FR 64509 (Oct. 23 2015), to make clear in the regulatory text that the pollutant regulated by this rule is GHGs.
 N. Final Standards Reflecting Next Generation Compliance and Rule Effectiveness
       In making decisions on the final requirements for this rule, we have emphasized the value of requirements that reflect principles of Next Generation Compliance and Rule Effectiveness. EPA's Next Generation Compliance strategy includes designing rules that promote improved compliance and better environmental outcomes. Specifically, we are finalizing standards with the following Next Generation Compliance strategies: (1) electronic reporting via the EPA's Central Data Exchange (CDX), (2) clear applicability criteria (e.g., modification criteria), (3) incentives for intrinsically lower emitting equipment (e.g., solar pumps at gas plants are not affected facilities), (4) OGI technology for monitoring fugitive emissions, (5) digital picture reporting as an alternative for well completions ("REC PIX") and manufacturer installed control devices, (6) qualified professional engineer certification of technical infeasibility to connect a pneumatic pump to an existing control device, and (7) qualified professional engineer certification of closed vent system design. These requirements, or options for compliance, provide opportunities for owners and operators to reduce obligations by making particular choices, reduce the burden for both the regulated industry and the agencies providing oversight, and provide greater transparency for all parties, including the public.
 VI. Significant Changes Since Proposal
      This section identifies significant changes in this rule from the proposed rule. These changes reflect the EPA's consideration of over 900,000 comments submitted on the proposal and other information received since the proposal, while preserving the aims underlying the proposal. The final rule protects human health and the environment by improving the existing NSPS and adding emission reduction standards for additional significant sources of GHGs and VOCs, consistent with the CAA. The EPA sought to achieve this important goal by endeavoring, where possible, to consistently expand the 2012 NSPS requirements across the oil and natural gas sector while also accounting for the unique characteristics of each type of source in setting emission reduction requirements. In this section, we discuss the significant changes since proposal by source category and the broad background for those changes. More specific information regarding comments and our responses appears in section VIII and in materials available in the docket.
 A. Centrifugal Compressors
       For centrifugal compressors, comments and information available led us to finalize the standards as proposed. In the proposed rule, we proposed to require 95 percent reduction of emissions from each centrifugal compressor affected facility. The standard can be achieved by capturing and routing the emissions using a cover and closed vent system to a control device (i.e., combustion control device) that achieves an emission reduction of 95 percent, or by routing the captured emissions to a process. For additional details, please refer to section VIII, the TSD, and the RTC supporting documentation in the public docket.
 B. Reciprocating Compressors
      For the reciprocating compressors requirements, we are finalizing the standards as proposed, except with a slight modification to the definition of reciprocating compressor rod packing. In the proposed rule, we proposed to require replacement of rod packing on or before 26,000 hours or 3 years of operation, or alternatively to route emissions via a closed vent system under negative pressure. To account for segments of the industry in which reciprocating compressors operate in a pressurized mode for a fraction of the calendar year, the standard is based on the determination that 26,000 hours of operation are comparable to 3 years of continuous operation.
       In the final rule, we revised the definition of reciprocating compressor rod packing. The EPA received comment that the definition of rod packing should be included in the rule to clarify the intent to replace any component of the rod packing that was contributing to emissions from the rod packing assembly. Because we agree that this clarification is useful, we have revised the definition of reciprocating compressor rod packing in the final rule to mean a series of flexible rings in machined metal cups that fit around the reciprocating compressor piston rod to create a seal limiting the amount of compressed natural gas that escapes from the compressor, or any other mechanism that provides the same function of limiting the amount of compressed natural gas that escapes from the compressor. For additional details, please refer to section VIII, the TSD, and the RTC supporting documentation in the public docket.
 C. Pneumatic Controllers
      For pneumatic controllers, comments and information available led us to finalize the standards as proposed. We proposed to require the use of low-bleed controllers in place of high-bleed controllers (i.e., natural gas bleed rate not to exceed 6 scfh) at all locations within the source category, except for natural gas processing plants. For natural gas processing plants, the standards require control of GHG and VOC emissions by requiring that pneumatic controllers have 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).
      The final rule provides that certain pneumatic controllers, reflecting the particular functions they perform, have only tagging and recordkeeping and reporting requirements. As discussed in the proposal, the EPA identified situations where high-bleed controllers (i.e., controllers with a natural gas bleed rate greater than 6 scfh) are necessary because of functional requirements, such as positive actuation or rapid actuation. An example would be controllers used on large emergency shutdown valves on pipelines entering or exiting compressor stations. The 2012 NSPS accounts for this by providing an exemption to pneumatic controllers for which compliance would pose a functional limitation due to their actuation response time or other operating characteristics. The EPA is finalizing the same exemption for all pneumatic controllers across the source category. For additional details, please refer to section VIII, the TSD, and the RTC supporting documentation in the public docket.
 D. Pneumatic Pumps
      In the final rule, the EPA is finalizing requirements for pneumatic pumps that use control devices or processes that are already available onsite. At natural gas processing plants, the EPA proposed to require reductions of 100 percent of GHG (in the form of methane) and VOC emissions from all diaphragm pneumatic pumps. For locations other than natural gas processing plants, the EPA proposed to require reductions of 95 percent of GHG (in the form of methane) and VOC emissions from all natural gas-driven diaphragm pumps, if an existing control or process was available.
      The public comment process helped us to identify aspects of the proposed requirements that may not be practical or feasible in all cases, and commenters submitted additional information for us to analyze. In this final rule, based on our consideration of the comments received and other relevant information, we have made certain changes to the proposed standards for pneumatic pumps. The final standards require the GHG (in the form of a limitation on methane) and VOC emissions from new, modified, or reconstructed natural gas-driven diaphragm pumps located at well sites to be routed to an available control device or process onsite, unless such routing is technically infeasible at non-greenfield sites. We are not finalizing a technical infeasibility exemption at greenfield sites, where circumstances that could otherwise make control of a pneumatic pump technically infeasible at an existing location can be addressed in the site's design and construction. For pneumatic pumps located at a natural gas processing plant, the final rule requires the GHG (in the form of a limitation on methane) and VOC emissions from natural gas-driven diaphragm pumps to be zero.
      While we acknowledge that solar-powered, electrically-powered, and air-driven pumps cannot be employed in all applications, we encourage operators to use pumps other than natural gas-driven pneumatic pumps where their use is technically feasible. To incentivize the use of these alternatives, the final rule's definition of "pneumatic pump affected facility" described in §60.5365a(h) only includes natural gas-driven pumps. Pumps that are driven by means other than natural gas are not affected facilities subject to the pneumatic pump provisions of the NSPS and are not subject to any requirements under the final rule.
      Provided below are the significant changes since proposal that result from the information in the record and the comments that we received and our rationale for these changes. For additional details, please refer to section VIII, the TSD, and the RTC supporting documentation in the public docket.
 Piston Pumps
      The EPA received several comments concerning the level of GHG and VOC emissions from natural gas-driven pneumatic piston pumps. The comments focused on the small volume of gas discharged by these pumps and the intermittent nature of their use. Other commenters suggested that the EPA treat pneumatic pumps consistently with pneumatic controllers. The commenters state that the same bleed rate considerations should be applied to pneumatic pumps because they are similar devices. Other commenters discussed the technical infeasibility of controlling emissions from piston pumps due to the inability to move such a small and intermittent gas flow through a duct or pipe to a control device.
	We agree with commenters that pneumatic controller bleed rate considerations can serve as a useful guide in considering emission reduction requirements for pneumatic pumps. In response to these comments, we further evaluated the natural gas flow rate of pneumatic pumps and agree that piston pumps are inherently low-emitting because of their small size, design, and usage patterns. As discussed in the TSD to the proposed rule, we used natural gas emission rates between 2.2 to 2.5 scf/hr during operation of piston pumps. We determined these emission rates based on a joint report from the EPA and the Gas Research Institute on methane emissions from the natural gas industry. Our analysis of the currently available data, the information in the record, and consideration of public comments lead us to the conclusion that we should exclude piston pumps from coverage under the NSPS based on their inherently low emission rates. This approach is consistent with the manner in which we addressed low-bleed pneumatic controllers. After considering the inherently low emission rates of low-bleed pneumatic controllers, we determined that they should not be subject to the final rule requirements. Similarly, based upon the information that we have on the low emission rates of piston pumps, we are not establishing requirements for them in this final rule.
	We note that our best available emissions data for diaphragm pumps, as discussed in the TSD, indicates that the emission rate ranges from about 20 to 22 scf/hr during operation of a diaphragm pump. Based on our analysis of this data, we do not believe exclusion of diaphragm pumps from the definition of a pneumatic pump affected facility is warranted. As a result, we are retaining requirements for diaphragm pumps in the final rule.
 Pneumatic Pumps Located in the Gathering and Boosting and Transmission and Storage Segments
      We received comment that pneumatic pumps located in the transmission and storage segment generally have very low emissions. Similar to the arguments presented above for piston pumps, commenters contend that these low emission rate pumps should not be subjected to the final rule. In response to these comments, we reviewed our available information used in the proposed rule TSD to estimate the number of pneumatic pumps and the emission rates of these pumps in all segments of the oil and natural gas sector. In the TSD for the final rule, we noted that neither the GHGRP nor the GHG Inventory include data about pneumatic pumps or their emission rates in the natural gas transmission and storage segment. Because we currently have no reliable source of information indicating the prevalence of use of pneumatic pumps in this segment, nor what their emission rates would be if they are used, we are not finalizing pneumatic pump requirements for the transmission and storage segment at this time.
	We also reviewed the available GHGRP and GHG Inventory data for pneumatic pumps, which was limited to the production segment. We consider the production segment to include both well sites and the gathering and boosting segment. Our available data indicate that pneumatic pumps are used at well sites as well as emission data for those pumps, but are silent on the prevalence of use of pneumatic pumps in the gathering and boosting segment, and what their emission rates would be if they are used. As with pneumatic pumps in the transmission and storage segment, we are not finalizing pneumatic pump requirements for the gathering and boosting segments at this time because of the lack of information in the record to support finalizing requirements for these pumps.
	We note that the EPA is currently conducting a formal process to gather additional data on existing sources in the oil and natural gas sector. We believe that this data collection effort will provide additional information on the use and emissions of pneumatic pumps in the transmission and storage segment and gathering and boosting segment. Once we have obtained and analyzed these data, we will be better equipped to determine whether regulation of pneumatic pumps in the transmission and storage segment and gathering and boosting segment is warranted. See section III.E for more detail regarding the EPA's information collection request for existing sources.
 Technical Infeasibility
      We agree with comments that there may be circumstances, such as insufficient pressure or control device capacity, where it is technically infeasible to capture and route pneumatic pump emissions to a control device or process, and we have made changes in the final rule to include an exemption for these instances. The owner or operator must maintain records of an engineering evaluation and certification providing the basis for the determination that it is technically infeasible to meet the rule requirements. The rule does not allow the operator to claim the technical infeasibility exemption for a pneumatic pump affected facility at a greenfield site (defined as a site, other than a natural gas processing plant, which is entirely new construction), where circumstances that could otherwise make control of a pneumatic pump technically infeasible at an existing location can be addressed in the site's design and construction.
 Efficiency of Existing Control Devices
      As noted above, we are finalizing emission standards for new, modified, and reconstructed natural gas-driven diaphragm pumps located at well sites requiring emissions be reduced by 95 percent if either a control device or the ability to route to a process is already available onsite. In setting this requirement, the EPA recognizes that there may not be a control device or process available onsite. Our analysis shows that it is not cost-effective to require the owner or operator of a pneumatic pump affected facility to install a new control device or process onsite to capture emissions. In those instances, the pneumatic pump affected facility is not subject to the emission reduction provisions of the final rule.
      Commenters have also raised concerns, and we agree, that the control device available onsite may not be able to achieve a 95 percent emission reduction. We evaluated whether this requirement should only be triggered when a NSPS subpart OOOO or OOOOa compliant control device was onsite, which would alleviate the control efficiency concern raised by commenters. However, the EPA is concerned that significant emissions reductions would be lost as a result of limiting the required type of equipment that must be used to control pneumatic pump emissions to only those that are designed to achieve 95 percent emission reductions. We are not requiring the owner or operator to install a new control device on site that is capable of meeting a 95 percent reduction nor are we requiring that the existing control device be retrofitted to enable it to meet the 95 percent reduction requirement. However, we are requiring that the owner or operator of a pneumatic pump affected facility at well sites to route the emissions to an existing control device even if it 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 final rule will achieve emission reductions with regard to pneumatic pump affected facilities even if the only available control device on site cannot achieve a 95 percent reduction.
 Compliance Requirements
      In response to concerns about applicability of subpart OOOO or OOOOa compliance requirements, the EPA has clarified our intent in the final rule that existing control devices that are not already subject to subparts OOOO or OOOOa compliance requirements (i.e., control devices that are subject to other federal or state compliance requirements) are not subject to the performance specifications, performance testing, and monitoring requirements in this rule solely because they are controlling pneumatic pump emissions. We believe that control devices covered by other federal, state, or other regulations would be subject to compliance requirements under those provisions and, therefore, we have reasonable assurance that the devices will perform adequately, and we do not need to include existing controls that are not already covered by subparts OOOO and OOOOa under the compliance requirements for these subparts.
 Cost Analysis
       In response to commenters' concerns that the costs were underestimated for compliance with the pneumatic pump requirements, we revised the cost analysis using the average of our annualized costs and two additional annualized cost estimates provided by commenters. Commenters' cost estimate methodologies and inputs varied from EPA's cost estimate which prevented us from conducting a side-by-side comparison with our cost estimate, nor could we directly compare the commenters' estimates with one another. However, in order to take into account the cost estimates provided by the commenters, we revised our cost analysis using the average of our annualized costs and the two additional annualized cost estimates provided by commenters. This is the same approach we would have taken had we obtained cost quotes from three separate vendors to install the closed vent system, and which we believe is the most equitable procedure when there is insufficient information to distinguish between the three cost estimates. One commenter gave an estimated capital cost of $5,800 which is annualized to be $826. A second commenter gave an estimated capital cost of $8,500 which annualized to be $1,210. The proposed capital cost to route emissions through a closed vent system was $2,000 which when annualized is $285. Based on our revised cost analysis, the capital cost for routing the emissions to an existing control device or process is $5,433, and the annualized cost is $774. We more fully discuss our cost estimate analysis in the TSD.
      We evaluated the cost of control for routing emissions to an existing combustion device or process where we assign the cost equally to methane and VOC. For diaphragm pumps at well sites, the cost of reducing methane emissions is $235 per ton and the cost of reducing VOC emissions is $847 per ton, using the single-pollutant approach. Based on this revised cost analysis using additional cost information, we find that the cost of control for reducing methane emissions remains reasonable.
 Affected Facility Definition
       The EPA received comment that there was contradictory language in the proposal preamble and regulatory text regarding recordkeeping requirements for pneumatic pumps where no control device was on site. This lack of clarity was the result of the affected facility definition for pneumatic pumps. In the final rule, we have revised the definition to clarify that coverage under this rule is independent of availability of a control device on site. Specifically, all natural gas-driven diaphragm pumps at natural gas processing plants or well sites are affected facilities, except for pumps at well sites that operate less than 90 days per calendar year. The EPA has revised the final regulatory text to make clear that all pneumatic pumps affected facilities must be reported on the annual report and records maintained as applicable to control status of the pump.
 Timing of Initial Compliance
      The EPA is also finalizing requirements for pneumatic pump affected facilities at natural gas processing plants. The EPA is finalizing GHG and VOC emissions control requirements for pneumatic pump affected facilities at well sites if there is a control device or ability to route to a process available on site or subsequently installed on site. We are also finalizing a technical infeasibility exception when it is infeasible to route the pneumatic pump to the control device (or route to a process) at non-greenfield sites. An owner or operator applying this exemption must obtain a professional engineering assessment demonstrating the reasons for the exemption.
      As pointed out by commenters, the technical infeasibility exemption may be based on safety concerns that could arise when a control device is not designed to handle the additional stream from the pneumatic pump. Commenters also expressed concern about safety issues related to increased pressure on the rest of the closed vent system connected to the control device. In light of these comments, we believe that the proposed 60-day compliance period may be insufficient to identify a qualified professional engineer, obtain the necessary design documents for the existing control device and associated ductwork, evaluate the design documents in light of the increased flow from the pneumatic pump, make an assessment of the technical feasibility of routing the pneumatic pump to the control device, and issue the required certification. Therefore, we are finalizing the compliance period to begin on [insert date 180 days after publication of the final rule in the Federal Register] to allow sufficient time for these necessary tasks to be completed.
E. Well Completions
      For the well completion requirements, we proposed to require RECs, when technically feasible and in combination with a completion combustion device, for subcategory 1 wells. For subcategory 2 wells, we proposed an operational standard that would require minimization of venting of gas and hydrocarbon vapors during the completion operation through the use of a completion combustion device, with provisions for venting in lieu of combustion for situations in which combustion would present safety hazards. The proposed rule identified challenging issues for which we solicited comment in order to obtain additional information.
      The public comment process helped us to identify aspects of the proposed requirements that in practice may not be practical in all cases, and commenters submitted additional information for us to analyze. In this final rule, based on our consideration of the comments received and other relevant information, we have made certain changes to the proposed standards for well completions. The final rule refines the well completion requirements to reduce emissions and provide clarity for both operators and regulators. The EPA is finalizing well completion standards for hydraulically fractured or refractured wells. The final standards require a combination of REC and combustion at subcategory 1 wells and combustion at subcategory 2 wells and low pressure wells. Provided below are the significant changes since proposal that result from the comments we received and our rationale for these changes. For additional details, please refer to section VIII, the TSD, and the RTC supporting documentation in the public docket.
 Separator Function
      The EPA solicited comment on the use of a separator during flowback and whether a separator can be employed for every well completion. We received several comments identifying situations where a separator cannot function. Specifically, commenters noted instances where a separator cannot function due to very low gas flow from the well, contaminated gas flow, or low reservoir pressure requiring artificial lift techniques. Commenters indicate that because of these scenarios there can be a complete absence of a separation flowback stage during the well completion (which, according to the commenters, can be particularly common in some basins and fields). Commenters asserted that many of these circumstances can be anticipated prior to the onset of flowback. Furthermore, commenters stated that the requirement to have a separator onsite would likely cause the operator to incur a cost with no environmental benefit derived.
      We believe that commenters have presented legitimate situations where it would be technically infeasible to use a separator, which is required for performing a REC. The challenge is, however, that the factors that lead to technical infeasibility of a separator to function may not be apparent until the time the well completion occurs, at which time it is too late to provide the equipment and, as a result, the well completion will go forward without controls. Further, the commenters did not provide data, and we do not have sufficient data to consistently and accurately identify the subcategory or types of wells for which these circumstances occur regularly or what criteria would be used as the basis for an exemption to the REC requirement such that a separator would not be required to be onsite for these specific well completions. In order to accommodate these concerns raised by commenters, the final rule requires a separator to be onsite during the entire flowback period for subcategory 1 wells (i.e., non-exploratory or non-delineation wells, also known as development wells), but does not require performance of REC where a separator cannot function. We anticipate a subcategory 1 well to be producing or near other producing wells. We therefore anticipate REC equipment (including separators) to be onsite or nearby, or that any separator brought onsite or nearby can be put to use. For the reason stated above, we do not believe that requiring a separator onsite would incur cost with no environmental benefit.
      However, unlike subcategory 1 wells, subcategory 2 wells are in areas where gas composition is likely unknown and, therefore, there is less certainty that a separator can work at these wells. If the separator does not work, there are unlikely subcategory 1 wells nearby that can put the separator to use. For the reasons stated above, we are not requiring that a separator be onsite for the well completion of subcategory 2 wells.
      The EPA had proposed that, for subcategory 2 wells and low pressure wells, operators would be required to route flowback to a completion combustion device as soon as the separator was able to function. We had based the proposed requirement for these wells on our determination that BSER was combustion, and efficient combustion using traditional combustion devices could be achieved through separation of the gas from the liquid and solid flowback materials prior to routing to the completion combustion device.
      As discussed in the 2015 proposal, traditional combustion devices (e.g., flares or enclosed combustors) cannot work initially because the flowback following hydraulic fracturing consists for liquids, gases and sand in high-volume, multiphase slug flow. As a result, these devices can work only after a separator can function. While pit flares can be installed and used from the start, considering the makeup of the initial flowback, we believe there is little gas to be burned, and so we assume there is not an appreciable difference between the amount of emissions reductions between a traditional combustion device and a pit flare. In addition, we believe that pit flares have increased potential for secondary impacts compared to traditional flares, due to the potential for the incomplete combustion of natural gas across the pit flare plume.
      Although not required, some owners and operators may choose to separate the gas from the other flowback materials for water management or other purposes. If a separator is used, any separated gas can be routed to combustion. In light of all of the above, we are providing in the final rule two options for completions of subcategory 2 wells: (1) route all flowback directly to a completion combustion device (in that case a pit flare); or (2) should an owner or operator choose to use a separator, route the separated gas to a completion combustion device as soon as a separator is able to operate.
      We are providing the same two options for low pressure wells. We believe that wells cannot perform a REC if there is not sufficient well pressure or gas content during the well completion to operate the surface equipment required for a REC, and low pressure gas could prevent proper operation of the separator. Alternatively, when feasible, some owners and operators may choose to separate the gas from the other flowback materials for water management or other purposes. If a separator is used, any separated gas must be routed to combustion.
2. REC Feasibility
      The second instance for potential technical infeasibility occurs during the separation flowback stage, where operators cannot perform a REC and, therefore, must combust. The EPA received comment that additional requirements are necessary to ensure that flaring of the recovered gas during the separation flowback stage is limited to scenarios where all options included in our definition for REC -- (1) route the recovered gas from the separator into a gas flow line or collection system, (2) re-inject the recovered gas into the well or another well, (3) use the recovered gas as an onsite fuel source, or (4) use the recovered gas for another useful purpose that a purchased fuel or raw material would serve -- have been pursued and their technical infeasibility documented. Commenters identified factors such as the availability and capacity of gathering lines, right of way issues, the quality of gas, and ownership issues that could impact the ability of operators to capture and use gas. Commenters stated that the provision for technical infeasibility for operators to use the recovered gas is vague and runs counter to the improvements the EPA seeks to establish within the oil and gas industry. Other commenters urged the EPA to allow flaring only as a last resort by requiring advanced notification and detailed documentation of the technical infeasibility of capturing and using salable quality gas. Commenters further stated that flaring should be very rarely necessary, as the EPA has identified four separate options for using recovered gas. The commenter recommends that EPA add additional notification and reporting requirements to ensure that all four options have been pursued and their technical infeasibility documented. The EPA agrees that the exemption from REC due to technical infeasibility should be limited. However, as illustrated by the comments received, the circumstances under which a REC is technically infeasible are varied. It is, therefore, difficult to provide one definition that can address all scenarios.
      The EPA considered, but declined to require, advanced notification for the following reasons. Technical infeasibility can be an after-the-fact occurrence (i.e., gas was contaminated and not of salable quality or had characteristics prohibiting other beneficial use and, therefore, the gas was combusted); therefore, advanced notification may not always be possible. A case-by-case advance evaluation by a regulatory agency is also not feasible considering the large number of completions, the wide geographic dispersion of the completions and the remote location of many well sites. For these reasons, we are not requiring prior notification of the claim of the technical infeasibility exemption.
      Rather we have expanded recordkeeping requirements in the final rule to include: (1) detailed documentation of the reasons for the claim of technical infeasibility with respect to all four options provided in section 60.5375a(a)(1)(ii), including but not limited to, names and locations of the nearest gathering line; capture, re-injection, and reuse technologies considered; aspects of gas or equipment prohibiting use of recovered gas as a fuel onsite; and (2) technical considerations prohibiting any other beneficial use of recovered gas onsite. We emphasize that the exemption is limited to "technical" infeasibility (e.g., lack of infrastructure, engineering issues, safety concerns).
      In addition to the detailed documentation and recordkeeping requirement, the final rule requires that a separator be onsite during the entirety of the flowback period at subcategory 1 (developmental) wells, as described earlier. We believe these additional provisions will support a more diligent and transparent application of the intent of the technical infeasibility exemption from the REC requirement in the final rule. This information must be included in the annual report made available to the public 30 days after submission through the Compliance and Emissions Data Reporting Interface (CEDRI), allowing for public review of best practices and periodic auditing to ensure flaring is limited and emissions are minimized.
 Gas to Oil Ratio (GOR) Exclusion
      We are not finalizing the proposed exclusion of wells with low GOR from the definition of a well affected facility. However, in the final rule, low GOR wells are not subject to REC or combustion requirements. In order to ensure that low GOR claims are not being made without sufficient analysis and oversight, the final rule requires that records used to make the GOR determination must be retained and a certifying official must sign the low GOR determination.
      The EPA proposed that wells with a GOR of less than 300 scf of gas per barrel of oil produced would not be affected facilities subject to the well completion provisions of the NSPS. The reason for the proposed threshold GOR of 300 is that separators typically do not operate at a GOR less than 300, which is based on industry experience rather than a vetted technical specification for separator performance. Though in theory any amount of free gas could be separated from the liquid, in reality this is not practical given the design and operating parameters of separation units operating in the field.
      The EPA also solicited comment on how operators could identify low GOR wells (i.e., those with a GOR of less than 300 scf of gas per stock tank barrel of oil produced) prior to well completion, specifically the question of whether the GOR of nearby wells would be a reliable indicator in determining the GOR of a new or modified well. The EPA received comment stating that wells in the same area or reservoir could be used to indicate GOR prior to well completion. In light of the comments received and, upon further consideration, the EPA concludes that GOR of a well can be determined in advance. The EPA, therefore, does not believe that it is appropriate to prescribe in the final rule any specific way to determine the GOR for purposes of exempting low GOR wells from performing REC or combustion. However, to ensure that only those that, in fact, have GOR of less than 300 are exempt from the REC or combustion requirement; these wells remain affected facilities under the final rule. To ensure that their GORs are accurately determined, the final rule requires detailed documentation of their GOR determination as well as annual reporting and recordkeeping requirements. However, they are not subject to the REC or combustion requirement.
4. Low Pressure Wells
      We have revised the low pressure well definition in the final rule. In the 2012 NSPS, the EPA recognized that certain wells, which the EPA called ``low pressure gas wells,'' cannot implement a REC because of a lack of necessary reservoir pressure to flow gas at rates appropriate for the transportation of solids and liquids from a hydraulically fractured gas well against additional back pressure that would be caused by the REC equipment, thereby making a REC infeasible. The 2012 NSPS exempts these wells from REC and instead requires combustion of the recovered gas.
      In the EPA's proposed rule (80 FR 56611, September 18, 2015), in which we proposed to also regulate VOC and GHG emissions from oil wells, we proposed to amend the current requirements for low pressure gas wells to apply to all low pressure wells. We proposed to change the term "low pressure gas well" to "low pressure well" but keep the definition the same. The substance of the definition at proposal for ``low pressure well'' is the same as the currently codified definition for "low pressure gas well" in the 2012 NSPS. We solicited comment on whether this definition appropriately defined hydraulically fractured wells for which conducting a REC would be technologically infeasible or whether the definition should be revised to better characterize the criteria for all low pressure wells.
      In our proposed definition, the pressure of the flowback fluid (oil, gas, and water) immediately before it enters the flow line is calculated by equation (1) below:
            PL psia=0.445∙PRpsia-0.038∙Lft+67.578		Equation (1)
Where:
PL psia is the pressure of flowback fluid immediately before it enters the flow line;
PRpsia is the pressure of the reservoir containing oil, gas, and water; and
Lft is the depth of the well.
      The EPA proposed that if the pressure of flowback fluid immediately before it enters the flow line, PL , calculated using the above equation is less than the available line pressure, the well would be considered a low pressure well. Such a well would not be required to do a REC during flowback (i.e., collect and send the associated gas to the flow line). Instead, such a well would only be required to combust the gas in a completion combustion device.
      Commenters asked the EPA to provide a new definition of "low pressure oil well" to differentiate oil wells from gas wells. They stated that the definition of "low pressure well" set out in proposed section 60.5430a and taken from the definition of "low pressure gas well" in subpart OOOO (section 60.5430) is not appropriate for a low pressure oil well, because the surface and back pressure for oil wells is higher than that for gas wells. They further state that "...once the hydraulic fracture load stops coming back, a gas well will typically have much less liquids in the production tubing, making the surface pressure actually higher for the gas well vs. an oil well. This difference would be reflected in the 0.038 number which represents the gas gradient in the well, which would impart a back pressure. For oil wells this back pressure would be higher ..." In response to these comments, the EPA modified the existing low pressure gas well equation (equation (1) above) to add pressure drop resulting from flow of oil and water in a well.
      The EPA's evaluation of the steady flow of petroleum fluid (gas and oil) during flowback in wells resulted in the following modified equation, hereafter referred to as the low pressure well equation (equation 2 below):
PL psia=0.495xPR-qgqg+qo+qw0.05xPR+0.038xL-67.578-qoqg+qo+qwxρo144+qwqg+qo+qw0.433∙L 		Equation (2)
Where:
PL is the pressure of flowback fluid immediately before it enters the flow line, expressed in psia;
PR is the pressure of the reservoir containing oil, gas, and water, expressed in psia;
L is the true vertical depth of the well, expressed in feet;
qo,   qg,   qw are the flow rates of oil, gas, and water, respectively, in the well, expressed in cubic feet/second; and
ρo is the density of oil in the well, expressed in pounds per cubic feet.
      EPA's low pressure well equation is used to predict the pressure of the flowback fluid (oil, gas, and water) immediately before it enters the flow line. The low pressure well equation uses inputs similar to those required for the gas well definition and for which information is understood to be available before well completion activity starts at a well site. These inputs include reservoir (or formation) pressure; true vertical depth of the well; flow rates of oil, gas, and water in the well; and the density of oil in the well.
      As oil-gas-water mixture flows upwards in a well to a lower pressure location, oil and gas volumes change and some of the dissolved gas evolves out of solution in oil. These phenomena result in oil and gas densities and volumetric flows changing with well depth. Therefore, oil density, ρo, and volumetric flow rate, qo, for use in equation (2) are calculated using the known value of oil API gravity at a well site and the widely used correlations provided in Vasquez and Beggs (1980). The gas volumetric flow, qg, is calculated using widely used correlations provided in Guo and Ghalambor (2005). Details on using equation (2) to calculate the pressure of flowback fluid immediately before it enters the flow line, PL , can be found in the TSD in the public docket.
      As noted above, equation (2) is the low pressure well equation for all wells in the final rule. This equation predicts the pressure, PL, of the flowback fluid (oil, gas, and water) immediately before it enters the flow line during the separation flowback period. In response to comments, the EPA's final regulations require that this pressure be compared to the actual flow line pressure available at the well site. Wells with insufficient predicted pressure to produce into the flow line are required to combust the gas in a control device. Wells with sufficient pressure to produce into the flow line are required to capture the gas and produce it into the flow line.
      EPA further notes that equation (2) is a modification of equation (1) and adds pressure drop resulting from flows of oil and water. When characterizing a well with conditions of gas flow only (i.e., qo = qw = 0), equation (2) reduces to equation (1), the equation for gas wells. Also note that equation (2) for line pressure is derived using a vertical well. It is known that inclined wells exist in the field, which will experience a somewhat higher frictional drop due to longer flow length. Nonetheless, it is expected that equation (2) would be able to account for minor increases in pressure drop due to increased frictional drop at inclined wells because the frictional pressure drop component contributes a small amount to the total pressure drop (about 1 percent on average) and conservative assumptions were used in deriving equation (2)  -  notably, bottom hole pressure equals one-half of formation pressure.
      In addition to the revised low pressure well equation, we are providing, in the final definition of low pressure well, other characteristics of the well that would indicate that a well is a low pressure well. We believe that if the static pressure (i.e., pressure with the well shut in and not flowing) at the wellhead following hydraulic fracturing, and prior to the onset of flowback, is less than the flow line pressure at the sales meter, the well is a low pressure well without having to demonstrate that it is such by using the low pressure well equation in the final rule.
       Instead of using the equation, under the final rule, operators who suspect that a well may be a low pressure well have the option, for screening purposes, of performing a wellhead static pressure (i.e., pressure with the well shut in and not flowing) check following fracturing and prior to the onset of flowback. If the static pressure at the wellhead was less than the flow line pressure at the sales meter, then the well would be a low pressure well. We believe that such a comparison would be conservative because, for a given well, the static pressure (i.e., with no fluid movement through the well) would be higher than the dynamic pressure (i.e., with the well flowing) because there would be no pressure losses brought about by friction caused by material movement in the tubing string. For some wells, use of this method could eliminate the need for the detailed calculations provided in the low pressure well equation discussed above. For other wells (i.e., those wells where the static pressure was greater than the flow line pressure), it would be necessary for the operator to use the low pressure well equation.
      Commenters asserted that many oil reservoirs have pressure that is insufficient for wells to naturally flow even after hydraulic fracturing. The commenters stated that this can be evidenced by the prevalence of artificial lift equipment such as rod pumps visible across the landscape of many oil producing areas. The commenters cited examples of reservoirs such as the Permian Basin, where horizontal drilling is used to extend the life of existing producing formations. The commenters explained that many oil wells that are hydraulically fractured do not have sufficient reservoir pressure to flowback fracture fluids. One company estimated that 30 percent of its hydraulically fractured horizontal wells and 80 percent of its hydraulically fractured vertical wells in the Permian Basin require artificial lift to flowback. In these cases, the commenter explained, rod pumps are installed on the wells to artificially lift the fracture fluids to the surface. In light of the comments received, the EPA believes that wells that require artificial lift equipment for flowback of fracture fluids should be classified as low pressure wells, as we believe that performing a REC is technically infeasible for these wells.
      To meet the definition of low pressure well, the well must satisfy any of the criteria above. We have revised the definition in the regulatory text to reflect this change. Section VIII, the RTC document, the TSD, and other materials available in the docket provide more discussion of these topics.
      5. Timing of Initial Compliance
      The EPA proposed the well completion requirements that, if finalized, would apply to both oil and gas well completions using hydraulic fracturing. In the 2012 NSPS, we provided a phase-in approach in the gas well completion requirements due to the concern with insufficient REC and trained personnel if REC were required immediately for all gas well completions. However, we did not provide the same in this proposal on the assumption that the supplies of REC equipment and trained personnel have caught up with the demand and, therefore, are no longer an issue. While some commenters agreed, other commenters indicated that the proposed rule, which would dramatically increase the number of well completions subject to the NSPS, would lead to REC equipment shortages. One commenter estimated that it would take at least 6 months to obtain the necessary equipment, while another commenter estimated that it would take 24 months. One commenter noted that owners and operators have been drilling wells, but delaying completion, due to the current economic conditions affecting the industry, causing a suppressed equipment demand. Finally, one state regulatory agency recommended extending the compliance period to 120 days to allow sufficient time to contract for the necessary completion equipment.
      After reviewing the comments, we agree that some owners and operators may have difficulty complying with the REC requirements in the final rule in the near term due to the unavailability of REC equipment. Although REC equipment suppliers have increased production to meet the demand for gas well completions under subpart OOOO, the affected facility under subpart OOOOa includes both gas and oil wells and will more than double the number of wells requiring REC equipment over subpart OOOO. We believe this demand will likely lead to a short-term shortage of REC equipment. However, based on the prior experience, we believe that suppliers have both the capability and incentive to catch up with the demand quickly, as opposed to the longer terms suggested by the commenters; they likely already stepped up production since this rule was proposed last year in anticipation of the impending increase in demand. In light of the above, the final rule provides a phase-in approach that would allow a quick build-up of the REC supplies in the near term. Specifically, for subcategory 1 oil wells, the final rule requires combustion for well completions conducted before [insert date 180 days after publication of the final rule in the Federal Register] and REC if technically feasible for well completions conducted thereafter. For subcategory 2 and low pressure oil wells, the final rule requires combustion during well completion, which is the same as that required for completion of subcategory 2 and low pressure gas well in the 2012 NSPS. For gas well completions, which are already subject to well completion requirements in the 2012 NSPS, the requirements remain the same.
 F. Fugitive Emissions from Well Sites and Compressor Stations
      For fugitive emissions requirements for the source category, three principles or aims directed our efforts. The first aim was to produce a consistent and accountable program for a source to use to identify and repair fugitive emissions at well sites and compressor stations. A second aim was to provide an opportunity for companies to design and implement their own fugitive emissions monitoring and repair programs. The third aim was to focus the fugitive emissions monitoring and repair program on components from which we expected the greatest emissions, with consideration of appropriate exemptions. The fourth aim was to establish a program that would complement other programs currently in place. With these principles in mind, we proposed a detailed monitoring plan; semiannual requirements using OGI technology for monitoring to find and repair sources of fugitive emissions, which we had identified as the BSER; a shifting monitoring schedule based on performance; a 15-day timeframe for repairing and resurveying leaks; and an exemption for low production wells.
      The public comment process helped us to identify additional information to consider and provided an opportunity to refine the standards proposed. Commenters specifically identified concerns with the definition of modification for well sites and compressor stations, the monitoring plan, the fluctuating survey frequency, the overlap with state and federal requirements, use of emerging monitoring technologies, the initial compliance timeframe, and the relationship between production level and fugitive emissions.
      In this final rule, based on our consideration of the comments received and other relevant information, we have made changes to the proposed standards for fugitive emissions from well sites and compressor stations. The final rule refines the monitoring program requirements while still achieving the main goals. Below we describe the significant changes since proposal for specific topics related to fugitive emissions and our rationale for these changes. For additional details, please refer to section VIII, the TSD, and the RTC supporting documentation in the public docket.
1. Fugitive Emissions from Well Sites
a. Monitoring Frequency
       In conjunction with semiannual monitoring, the EPA co-proposed annual monitoring and solicited comment on the availability of trained OGI contractors and OGI instrumentation. 80 FR 56637, September 18, 2015. Commenters provided numerous comments and data regarding annual, semiannual and quarterly monitoring surveys. These comments largely focused on the cost, effectiveness, and feasibility of the different program frequencies. The EPA evaluated these comments and information, as well as certain production segment equipment counts from the 2016 public review draft GHG Inventory, which were developed from the data reported to the GHGRP. Based on the above information, the EPA updated its proposal assumptions on equipment counts per well site to use data from the 2016 public review draft update. This resulted in changes to the well site model plant. Specifically, the equipment count for meters/piping at a gas well site increased from 1 to 3, which tripled the component counts from meters/piping at these sites. In addition, the EPA developed a third model plant to represent associated gas well sites. This category includes wells with GOR between 300 and 100,000 standard cubic feet per barrel (scf/bbl), and the model plant is assumed to have the same component counts as the model oil well site, as well as components associated with meters/piping. The EPA used this information to re-evaluate the control options for annual, semiannual and quarterly monitoring. As shown in the TSD, the control cost, using OGI, based on quarterly monitoring is not cost-effective, while both semiannual and annual monitoring remain cost-effective for reducing GHG (in the form of methane) and VOC emissions. Because control costs for both semiannual and annual monitoring are cost-effective, we evaluated the difference in emissions reductions between the two monitoring frequencies and concluded that semiannual monitoring would achieve greater emissions reductions. Therefore, the EPA is finalizing the proposed semiannual monitoring frequency. Please see the RTC document in the public docket for further discussion. Even though the EPA has determined that semi-annual surveys for well sites is the BSER under this NSPS, this does not preclude the EPA from taking a different approach in the future, including requiring more frequent monitoring (e.g., quarterly).
b. Low Production Well Sites
      The EPA proposed to exclude low production well sites (i.e., well sites where the average combined oil and natural gas production is less than 15 barrels of oil equivalent (boe) per day averaged over the first 30 days of production) from the fugitive emissions monitoring and repair requirements for well sites. As we explained in the preamble to the proposed rule, we believed that these wells are mostly owned by small businesses and that fugitive emissions associated with these wells are generally low. 80 FR 56639, September 18, 2015. We were concerned about the burden on small businesses, in particular, where there may be little emission reduction to be achieved. Id. We specifically requested comment on the proposed exclusion and the appropriateness of the 15 boe per day threshold. We also requested data that would confirm that low production sites have low GHG and VOC fugitive emissions.
      Several commenters indicated that low production well sites should be exempt from fugitive emissions monitoring and that the 15 boe per day threshold averaged over the first 30 days of production is appropriate for the exemption, however, commenters did not provide data. Other commenters indicated that the low production well sites exemption would not benefit small businesses since these types of wells would not be economical to operate and few operators, if any, would operate new well sites that average 15 boe per day.
      Several commenters stated that the EPA should not exempt low production well sites because they are still a part of the cumulative emissions that would impact the environment. One commenter indicated that low production well sites have the potential to emit high fugitive emissions. Another commenter stated that low production well sites should be required to perform fugitive emissions monitoring at a quarterly or monthly frequency. One commenter provided an estimate of low producing gas and oil wells that indicated that a significant number of wells would be excluded from fugitive emissions monitoring.
      Based on the data from DrillingInfo, 30 percent of natural gas wells are low production wells, and 43 percent of all oil wells are low production wells. The EPA believes that low production well sites have the same type of equipment (e.g., separators, storage vessels) and components (e.g., valves, flanges) as production well sites with production greater than 15 boe per day. Because we did not receive additional data on equipment or component counts for low production wells, we believe that a low production well model plant would have the same equipment and component counts as a non-low production well site. This would indicate that the emissions from low production well sites could be similar to that of non-low production well sites. We also believe that this type of well may be developed for leasing purposes but is typically unmanned and not visited as often as other well sites that would allow fugitive emissions to go undetected. We did not receive data showing that low production well sites have lower GHG (principally as methane) or VOC emissions other than non-low production well sites. In fact, the data that were provided indicated that the potential emissions from these well sites could be as significant as the emissions from non-low production well sites because the type of equipment and the well pressures are more than likely the same. In discussions with us, stakeholders indicated that well site fugitive emissions are not correlated with levels of production, but rather based on the number of pieces of equipment and components. Therefore, we believe that the fugitive emissions from low production and non-low production well sites are comparable.
      Based on these considerations and, in particular, the large number of low production wells and the similarities between well sites with production greater than 15 boe per day and low production well sites in terms of the components that could leak and the associated emissions, we are not exempting low production well sites from the fugitive emissions monitoring program. Therefore, the collection of fugitive emissions components at all new, modified or reconstructed well sites is an affected facility and must meet the requirements of the fugitive emissions monitoring program.
c. Monitoring Using Method 21
      The EPA's analysis for the proposed rule found OGI to be more cost-effective at detecting fugitive emissions than the traditional protocol for that purpose, Method 21, and the EPA, therefore, identified OGI as the BSER for monitoring fugitive emissions at well sites. See 80 FR 56636, September 18, 2015. The EPA solicited comment on whether to allow Method 21 as an alternative fugitive emissions monitoring method to OGI. 80 FR 56638, September 18, 2015. We also solicited comment on the repair threshold for components that are found to have fugitive emissions using Method 21. Id.
      Numerous industry, state, and environmental commenters indicated that Method 21 is preferred or should be allowed as an alternative to OGI, citing availability, costs, and training associated with OGI.
      Several commenters indicated that the EPA should set the Method 21 fugitive emissions repair threshold at 10,000 ppm, the level at which our recent work indicates that fugitive emissions are generally detectable using OGI instrumentation provided that the right operating conditions (e.g., wind speed and background temperature) are present. 80 FR 56635, September 18, 2015. Some commenters stated that the repair threshold should be 500 ppm to achieve a high level of fugitive emission reductions while other commenters state that a 500 ppm repair threshold would target fugitive emissions that would not provide meaningful reductions.
      The issue of the repair threshold when Method 21 is used is a critical decision. As discussed in the preamble to the proposed rule, Method 21, at an appropriate repair threshold, is capable of achieving the same or better emission reductions as OGI. However, at proposal, we determined that Method 21 was not cost-effective at a semiannual monitoring frequency with a repair threshold of 500 ppm.
      While we agree with the importance of allowing the use of Method 21 as an alternative, we need to ensure that its use does not result in fewer emissions reductions than what would otherwise be achieved using OGI, which is the BSER based on our analysis. Available data show that OGI can detect fugitive emissions at a concentration of at least 10,000 ppm when restricting its use during certain environmental conditions such as high wind speeds. Due to the dynamic nature for the OGI detection capabilities, OGI may also image emissions at a lower concentration when environmental conditions are ideal. Because an OGI instrument can only visualize emissions and not the corresponding concentration, any components with visible emissions, including those emissions that are less than 10,000 ppm, would be repaired. Method 21 is capable of detecting fugitive emissions at concentrations well below 10,000 ppm. However, if the repair threshold was set at 10,000 ppm, an owner or operator would not have to repair any leaks that are less than 10,000 ppm, thereby foregoing the reductions that would otherwise be achieved by using the OGI. For the reason outlined in this section, 10,000 ppm is not an appropriate repair threshold for Method 21.
      Using information provided by commenters, we evaluated the methane and VOC emission reductions associated with the use of Method 21 at repair thresholds of 10,000 ppm and 500 ppm, the two levels recommended by the various commenters. We used AP-42 emission factors to determine the emissions from fugitive emissions components that were found to be leaking using a Method 21 instrument and concluded that emissions reductions are lower than when OGI is used to survey the same components. The lower emission reductions are due to fugitive emissions with a concentration lower than 10,000 ppm not being found using the Method 21 instrument when it is calibrated to detect emissions at a threshold of 10,000 ppm or greater.
      We then calculated the emission reductions that result from using a Method 21 instrument to conduct a monitoring survey at a repair threshold of 500 ppm. At this threshold, the operator would have to repair every component found to have fugitive emissions over 500 ppm threshold. This results in emission reductions greater than the emissions reductions that would be achieved if OGI were used instead. For the reasons stated in this section, using Method 21 to conduct monitoring surveys at a repair threshold of 500 ppm is better than, or at least equivalent to, using OGI to conduct the same survey; we are allowing it in the final rule as an alternative to the use of OGI. We acknowledge that the cost of conducting a survey using Method 21 may be more expensive than using OGI; however, some owners or operators may still chose to use Method 21 for convenience or due to the lack of availability of OGI instruments or trained personnel. Therefore, to ensure that it achieves at least the level of emission reduction to be achieved using the OGI, the final rule allows the use of Method 21 with a repair threshold of 500 ppm.
      Based on interest in having Method 21 as an approved alternative, we are finalizing it as an alternative to OGI. Allowing Method 21 as an alternative will address some of the uncertainty expressed by small entities that indicated a concern with needing to purchase an OGI instrument or hire trained OGI contractors to perform their monitoring surveys. We are finalizing Method 21 as an alternative to OGI for monitoring fugitive emissions components at a repair threshold of an instrument reading of 500 ppm or greater. We are also finalizing specific recordkeeping and reporting requirements when Method 21 is used to perform a monitoring survey.
d. Shifting of Monitoring Frequency Based on Performance
      The EPA proposed shifting monitoring frequencies (ranging from annual to quarterly monitoring) based on the percentage of components that are found to have fugitive emissions during a monitoring survey. We solicited comment on the proposed monitoring approach, including the proposed metrics of one percent and three percent to determine monitoring frequency or whether the monitoring frequency thresholds should be based on a specific number of components that are found to have fugitive emissions. In addition, the EPA solicited comment on whether a performance-based frequency or a fixed-frequency program was more appropriate.
      Most commenters opposed performance-based monitoring frequency. They raised specific concerns that performance-based monitoring and shifting monitoring frequencies would be costly, time-consuming, and impose a complex administrative burden for the industry and states. For example, commenters pointed out that an owner may have hundreds or even thousands of well sites and a potentially ever-changing survey schedule for each of those sites would present an untenable logistical hurdle. Most of the commenters stated that the EPA should finalize a fixed monitoring frequency to provide a level of certainty to owners and operators for planning future schedules of survey crews.
      The EPA considered these comments and agrees that imposing a performance-based monitoring schedule would require operators to develop an extensive administrative program to ensure compliance. Under the performance-based monitoring, owners and operators would need to count all of the components at the well sites, affix identification tags on each component or develop detailed piping and instrument diagram. During each monitoring survey, owners and operators would need to calculate the percentage of leaking fugitive emissions components to determine the next monitoring frequency schedule.
      We also agree that the shifting monitoring frequencies could cause regulated entities additional administrative burden to determine compliance since the monitoring frequencies could change each year, but the correct frequency may not be reflected in the operating permit. This could also result in fugitive emissions being undetected longer due to less frequent monitoring. We believe that the potential for a performance - based approach to encourage greater compliance is outweighed in this case by these additional burdens and the complexity it would add. Therefore, the EPA is finalizing a fixed-frequency monitoring instead of performance-based monitoring.
e. Fugitive Emissions Components Repair and Resurvey
      The EPA proposed that components that are a source of fugitive emissions must be repaired or replaced as soon as practicable and, in any case, no later than 15 calendar days after detection of the fugitive emissions. For sources of fugitive emissions that cannot be repaired within 15 days of finding the emissions, due to technical infeasibility or unsafe conditions, the EPA proposed that the components could be placed on a delay of repair until the next scheduled shutdown or within six months, whichever is earlier. We also proposed that a repaired fugitive emissions component be resurveyed within 15 days of the repair. The EPA solicited comment on all three aspects.
      Commenters voiced various opinions regarding the requirements. Many commenters shared concerns that the 15-day window for repairs is too short, due to factors such as remoteness of equipment locations, unsuccessful repair attempts, and multiple components needing repair. Other commenters preferred the 15-day window, in the interest of achieving immediate mitigation of health and safety risks and alignment with standards in several states.
      Multiple commenters provided comments on the proposed delay of repair standards, including concerns about delays lasting longer than six months due to availability of supplies needed to complete repairs and information regarding the frequency of delayed repairs. Some commenters also indicated that in some cases, requiring prompt repairs could lead to more emissions than if repairs were able to be delayed, for example if a well shut-in or vent blow-down is required.
      Regarding the 15-day window to resurvey repairs to fugitive emissions components, multiple commenters stated that the final rule should allow 30 days for the resurvey, due to the potential need for specialized personnel for the resurvey, while others considered 15 days to be adequate. Regarding performance of the resurvey, many commenters also suggested that soap bubbles, as specified in section 8.3.3 of Method 21, be allowed to determine if the components have been repaired.
      After considering the comments above, the EPA agrees that repairs for some sources of fugitive emissions at a well site may take multiple attempts or require additional equipment that is not readily available and may take longer than 15 days to repair. Well sites, unlike chemical plants or refineries, may be located in remote areas and it is unlikely that they would have warehouses or maintenance shops nearby where spare equipment or tools are kept that would be needed to perform repairs within 15 days. We also recognize that fugitive emissions must be alleviated as soon as practicable. We believe that allowing an additional 15 days for repair would give owners and operators enough time to get the parts or the personnel needed to repair or replace the components that could not be repaired during the initial monitoring survey. Therefore, we are finalizing 30 days for the repair of fugitive emissions sources. However, we do recognize that some state LDAR programs require repairs to be made within 5 to 15 days of finding a leak. We encourage operators to continue to fix leaks within that timeframe, since the majority of leaks are fixed when they are found. We do expect that the majority of components will not need the additional 15 days for repair.
      The EPA agrees, based on our review of the comments, that only a small percentage of components would not be able to be repaired during that 30 day period. We also agree that a complete well shutdown or a well shut-in may be necessary to repair certain components, such as components on the wellhead, and this could result in greater emissions than what would be emitted by the leaking component. The EPA does not agree that unavailability of supplies or custom parts is a justification for delaying repair (i.e., beyond the 30 days for repair provided in this final rule) since the operator can plan for repair of fugitive emission components by having stock readily accessible or obtaining the parts within 30 days after finding the fugitive emissions.
      Based on available information, it may be two years before a well is shut-in or shutdown. Therefore, to avoid the excess emissions (and cost) of prematurely forcing a shutdown, we are amending the rule to allow 2 years to fix a leak where it is determined to be technically infeasible to repair within 30 days; however, if an unscheduled or emergency vent blowdown, compressor station shutdown, well shutdown, or well shut-in occurs during the delay of repair period, the fugitive emissions components would need to be fixed at that time. The owner or operator will have to record the number and types of components that are placed on delay of repair and record an explanation for each delay of repair.
      Method 21 allows a user to spray a soap solution on components that are operating under certain conditions (e.g., no continuous moving parts or no surface temperatures above the boiling point or below the freezing point of the soap solution) to determine if any soap bubbles form. If no bubbles form, the components are deemed to be operating with no detected emissions. We note that spraying soap solution to confirm whether a component has been repaired may not work for all fugitive emissions components, such as a leak found under the hood of the thief hatch because it would be difficult to apply the soap solution or observe bubbles. However, we believe that this alternative will provide some owners and operators a simple, low cost way to confirm that a fugitive emissions component has been repaired. This would also allow the resurveys to be performed by the same personnel that completed the repairs instead of other certified monitoring personnel or hired contractors that would have to come back to verify the repairs. Therefore, we are finalizing the use of the alternative screening procedures specified in Section 8.3.3 of Method 21 for resurveying repaired fugitive emissions components, where appropriate.
      For owners or operators that cannot use soap spray to verify repairs, we are allowing an additional 30 days for resurvey of the repaired fugitive emissions components, to allow time for contractors or designated OGI personnel to perform the resurvey because they are not typically the same personnel that would perform the repairs.
f. Definition of "Fugitive Emission Component"
      As just discussed, we proposed monitoring, repair, and resurvey of "fugitive emission components." The EPA solicited comment on the proposed definition of fugitive emissions components. Commenters indicated that, as proposed, the fugitive emissions component definition is too broad and vague, because it contains both equipment and component types, and suggested that the EPA modify the definition to be more targeted and easier for states and other regulatory authorities to determine compliance, and recommended other definitions, such as that used by the state of Colorado.
      The EPA agrees with commenters that, as proposed, the fugitive emissions component definition may cause confusion due to inclusion of equipment types, such as uncontrolled storage vessels that are potential sources of vented emissions (as opposed to fugitive emissions), in the definition.
      Therefore, we are finalizing changes to the definition to remove equipment types and identify specific components, such as valves and flanges, that have the potential to be sources of fugitive emissions and that, when surveyed and repaired, would significantly reduce GHG and VOC emissions. This targeted list will remove the ambiguity of the proposed definition and will allow owners and operators to consistently identify fugitive emissions at well sites. We are finalizing the following definition for fugitive emissions components:
      Fugitive emissions component means any component that has the potential to emit fugitive emissions of methane or VOC at a well site or compressor station, including valves, connectors, pressure relief devices, open-ended lines, flanges, covers and closed vent systems not subject to §60.5411a, thief hatches or other openings on a controlled storage vessel, compressors, instruments, and meters. Devices that vent as part of normal operations, such as natural gas-driven pneumatic controllers or natural gas-driven pumps, are not fugitive emissions components, insofar as the natural gas discharged from the device's vent is not considered a fugitive emission. Emissions originating from other than the vent, such as the thief hatch on a controlled storage vessel, would be considered fugitive emissions.
       As finalized, the definition also aligns closely with other states' and federal agencies' definitions of fugitive emissions components by targeting similar components to the components in those definitions. Owners and operators can therefore monitor one set of components while complying with the requirements of this final rule and other state or federal fugitive emissions monitoring programs.
g. Timing of the Initial Monitoring Survey
      The EPA proposed that the initial monitoring be conducted within 30 days after the initial startup of the first well completion or modification of a well site. EPA solicited comment on whether the proposal provides an appropriate amount of time to begin conducting fugitive emissions monitoring. We received a wide variety of comments and suggestions for the appropriate time for fugitive emissions monitoring to begin.
      Several commenters indicated that initial monitoring should begin after production starts, because time is needed to close out the drilling activities. The commenters further stated that completion activities and the transition from completion to production at well sites is unpredictable and temporary completion equipment may still be onsite 30 days after the "initial startup of the first well completion." One commenter indicated that production may not begin immediately after a well completion, so initial monitoring should not begin until after production starts.
      The EPA acknowledges that at the time of a well completion all of the associated permanent equipment may not be present and conducting the initial monitoring survey may not capture all of the fugitive emissions components that would be in operation during production. In addition, we believe it is important to conduct the initial survey soon after the permanent equipment is in place to catch any improperly installed or defective equipment that may have substantial fugitive emissions immediately after installation. We believe that the permanent equipment will be in place at the startup of production (i.e., the initial flow following the end of the flowback when there is continuous recovery of saleable quality gas). Therefore, the startup of production more accurately reflects the start of normal operations and would capture any fugitive emissions from the newly constructed or modified components at the well site. Therefore, we are finalizing that the startup of production marks the beginning of the initial monitoring survey period for the collection of fugitive emissions components.
      Furthermore, based on the comments received, we are concerned that the tasks required prior to conducting an initial survey would take more than the 30 days we had proposed. Because each new or modified well site must be covered by a monitoring plan for a company-defined area, owners and operators must visit and assess each new or modified well site in order to incorporate it into a newly developed or modified monitoring plan for that area. They also need to secure certified monitoring survey contractors or monitoring instruments. In addition, they need to ensure that other compliance requirements will be met, such as recordkeeping and reporting. In light of the activities described above, the EPA is requiring in the final rule that the initial survey be conducted within 60 days from the startup of production.
      While 60 days from startup of production is sufficient time to conduct the initial survey once the underlying program infrastructure is established, we recognize that the initial establishment of the required program's infrastructure and the initial round of monitoring surveys will require additional time. Most importantly, additional time is needed to secure the necessary equipment or trained personnel, according to one OGI instrument manufacturer, which commented that they would need to increase production of key components for the OGI instrument to meet demand. The OGI manufacturer also indicated that they would need to scale up the number of personnel needed to provide OGI training and service of the equipment. We are concerned that currently there is not sufficient equipment and trained personnel to meet the demand imposed by this final rule in the near term. Accordingly, it will be necessary to have a window of time for trained personnel to work through this backlog. Furthermore, as previously mentioned, an owner or operator will need to develop a monitoring plan that would apply to each well site located within the company-defined area, which requires an assessment of each well site. Therefore, before a plan can be developed or modified, the owner or operator would need time to visit each well site within the company-defined area. Based on the information that we used to develop the model well site plants, each company-defined area may consist of up to 22 well sites within a 70-mile radius of a central or district office. In light of the above, the initial site visits and development of the monitoring plan would require a significant amount of time. Time is also needed to secure certified monitoring survey contractors or monitoring instruments. In addition, owners and operators will need to plan the logistics of the initial activities in order to comply with the requirements. This includes time to set up recordkeeping systems and to train personnel to manage the fugitive emissions monitoring program. These corporate systems are critical for submitting the notification of initial and subsequent annual compliance status.
      As noted above, once programs are established and equipment supplies have caught up, well owners will be able to add additional affected facilities to existing programs and, thus, this longer timeline will not be needed. Therefore, in order to provide time for owners and operators to establish the initial groundwork of their fugitives program, we are requiring that the initial monitoring survey must take place by [insert date 1 year after publication of the final rule in the Federal Register] or within 60 days of the startup of production, whichever is later.  We anticipate that sources will begin to phase in these requirements as additional devices and trained personnel become available. For additional discussion, please refer to the materials in the docket.
h. Monitoring Plan
      The EPA proposed that owners or operators develop a corporate-wide fugitive emissions monitoring plan that specifies the measures for locating sources and the detection technology to be used. We also proposed that, in addition to the corporate-wide monitoring plan, owners or operators develop a site-specific fugitive emissions monitoring plan that specifies information such as the number of fugitive emission components that pertains to that single site. The EPA solicited comment on the required elements of the proposed corporate-wide monitoring plan; specifically, the EPA asked for comment on whether other techniques, such as visual inspections to help identify indicators of potential leaks, should be included within the monitoring plan.
      Some commenters agreed with the EPA's proposal to require a corporate-wide fugitive monitoring plan but expressed concerns about the elements of the plan, while others objected that the proposed plan is overly prescriptive and costly, with particular concerns about including requirements for a walking path and for digital photographs. Other commenters suggested changing the scope of monitoring plans to accommodate variations in locations of contractors and equipment.
      We considered these comments, and we have made the following changes to the proposal in the final rule.
      First, the final rule requires owners or operators to develop a fugitive emission monitoring plan for well sites within a company-defined area instead of corporate-wide and site-specific monitoring plans. This will give companies the flexibility to group well sites that are located within close proximity, under common control within a field or district, or that are managed by a single group of personnel. This would also afford owners and operators of well sites within different basins the ability to tailor their plans for the specific elements within each basin (i.e., geography, well site characterization, emission profile). Information we received indicates that, in many cases, several sites within a specific geographic area may have similar equipment and would use the same contractors, company-owned monitoring instruments, or company personnel to perform the monitoring surveys. Based on a study conducted for the city of Fort Worth, Texas, we estimate that, on average, there are 22 well sites within a company's specific geographic region. In this study, a total of 375 well pads were identified in the Fort Worth area, and these well pads were owned and operated by 17 different companies, or an average of 22 well pads per company. We believe these data provide a reasonable estimate of the number of well sites operated by a company in a specific geographic region. Therefore, we are removing the proposed corporate-wide and site-specific monitoring plan requirements and finalizing requirements that owners and operators develop a fugitive emissions monitoring plan for each of the company-defined areas that covers the collection of fugitive emissions components at well sites. As a result, the final rule requires owners and operators to develop a plan that describes the sites generally, including descriptions of equipment, plans for how they will monitor, etc., that apply to all similar sites. This will allow owners and operators to develop a monitoring plan for groups of similar well sites within an area for ease of implementation and compliance.
      Second, we have made changes in the final rule to the proposed digital photograph requirements. We believe concerns regarding the burden of printing or transmitting digital pictures within the annual report are the result of unclear language in the proposed rule. Our intent was to require the owner or operator to include one or more digital photographs of the survey being performed. However, we inadvertently included that text within the requirement for each fugitive emission. It was not our intent to require a digital photograph of each fugitive emission in the annual report; instead we wanted to ensure, through pictorial documentation, that the monitoring survey had been performed. After consideration of the comments received, we believe we can further streamline this requirement. Because a source with fugitive emissions during the reporting period is subject to other recordkeeping and reporting requirements, this provides sufficient documentation that the survey was performed. Therefore, we have removed the proposed requirement to provide a digital photograph in the annual report for each required monitoring survey. We are requiring owners and operators to retain a record of each monitoring survey performed with optical gas imaging by keeping one or more digital photographs or videos captured with the OGI instrument. The photograph or video must either include the latitude and longitude of the collection of fugitive emissions components imbedded within the photograph or video or must consist of an image of the monitoring survey being performed with a separately operating GPS device within the same digital picture or video, provided that the latitude and longitude output of the GPS unit can be clearly read in the image.
      Third, with the allowance for Method 21 monitoring as an alternative to OGI instrument monitoring, we are finalizing a requirement that sources of fugitive emissions (e.g., a leaking fugitive emissions component) that cannot be repaired during the initial monitoring survey either be temporarily tagged for identification for repair or be digitally photographed or video recorded in a way that identifies the location of the fugitive emissions component needing repair. If an owner or operator chooses to digitally photograph the leaking component(s) instead of using identification tags, the photograph will meet the requirement to take a digital photograph during a monitoring survey, as long as the digital photograph is taken with the OGI instrument and includes the latitude and longitude either imbedded in the photograph or visible in the picture.
      Fourth, we are finalizing the walking path requirement with minor changes. We are revising the walking path terminology to observation path in order to clarify that our intent is focused on the field of view of the OGI instrument, not the physical location of the OGI operator. We believe this terminology change will alleviate commenters' concerns regarding the potentially overly prescriptive nature of the defined walking path with transient interferences, environmental obstructions, weather conditions and safety issues. This revision also clarifies our intent to allow for the use of all types of OGI instruments (e.g., mounted, handheld or remote controlled).
      The purpose of the observation path is to ensure that the OGI operator visualizes all of the components that must be monitored, just as a Method 21 operator in a traditional leak detection program surveys all of the components. In the traditional scenario, the owner or operator tags all of the equipment that must be monitored, and when the Method 21 operator subsequently inspects the affected facility, the operator scans each component's tag and notes the component's instrument reading. The EPA realizes that this is a time-consuming practice. Additionally, while the Method 21 operator must contact each component with the probe of the Method 21 instrument and monitor it individually, we recognize that with OGI, the operator can be away from the components and still monitor several components simultaneously.
      Recognizing these aspects of traditional and OGI leak detection methods, we want to offer owners and operators an alternative to the traditional tagging approach. However, because we are no longer requiring a traditional log of instrument readings, the rule must provide another way to ensure that the compliance obligation to monitor all equipment is met. We believe that the observation path requirement effectively ensures that an operator looks at all of the required components but reduces the burden of tagging and logging associated with traditional Method 21 programs. Unlike the tagging and logging requirement associated with traditional Method 21 programs, the requirement to develop an observation path is a one-time requirement (as long as the path does not need to change due to the addition of components). We do not expect facilities to create overly detailed process and instrumentation diagrams to describe the observation path. The observation path description could be a simple schematic diagram of the facility site or an aerial photograph of the facility site, as long as such a photograph clearly shows locations of the components and the OGI operator's walking path. As a result, we do not believe that the requirement to document the observation path is burdensome.
i. Provision for Emerging Technology
      As the EPA noted in the 2015 proposal, fugitive emissions monitoring is a field of emerging technology, and major advances are expected in the near future. 80 FR at 56639. We are seeing a rapidly growing push to develop and produce low-cost monitoring technologies to find fugitive and direct methane and VOC emissions sooner and at lower levels than current technology allows, thus enhancing the ability of operators to detect fugitive emissions. During the development of the proposed rule, the EPA solicited comments and information on emerging technologies that could potentially be used to detect fugitive emissions at well sites or compressor stations and how these technologies could be used (e.g., as standalone monitors or in conjunction with OGI). Several commenters indicated that methane and VOC leak detection technology is undergoing continuous and rapid development and innovation, potentially yielding, for example, continuous emissions monitoring technologies, and urged the EPA to allow emerging technology to be used for fugitive emissions monitoring. The EPA agrees that continued development of these cost effective technologies is important and that the final rule should encourage and accommodate it to the extent possible.
      Fugitive emissions monitoring and repair is a work practice standard, as allowed under section 111(h)(1) of the CAA. A work practice standard is an emission limitation that is not necessarily in a numeric format, such as the visualization of fugitive emissions using OGI. As described in section 111(h)(3), the Administrator may approve an alternative means of emission limitation for a work practice standard if it can be proven that an equal reduction in emissions will be achieved. To that end, pursuant to CAA section 111(h)(3), we are establishing in the final rule a process for the agency to permit the use of innovative technology for reducing fugitive emissions at well sites and/or compressor stations. Specifically, under the final rule, owners or operators may submit a request to the EPA for "an alternative means of emission limitation" where a technology has been demonstrated to achieve a reduction in emissions at least equivalent to the reduction in emissions achieved under the work practice or operational requirements for reducing fugitive emissions at well sites and/or compressor stations in subpart OOOOa.
      To facilitate the application and review process, the final rule includes information to be provided in the application that would be needed for us to expeditiously evaluate the emerging technology. Such information must include a description of the emerging technology and the associated monitoring instrument or measurement technology; a description of the method and data quality used to ensure the effectiveness of the technology; a description of the method detection limit of the technology and the action level at which fugitive emissions would be detected; a description of the quality assurance and control measures employed by the technology; field data that verify the feasibility and detection capabilities of the technology; and any restrictions for using the technology.
      This process will allow for the use of any currently emerging technology or any technology that is developed in the future that is capable of achieving methane and VOC emission reductions at levels that are at least equivalent to reductions achieved when using OGI or Method 21 for fugitive emissions monitoring. This process will also allow for the use of alternative fugitive emissions monitoring approaches such as periodic, continuous, fixed, mobile, or a hybrid approach.  Consistent with section 111(h)(3), any application will be publicly noticed in the Federal Register, which the EPA intends to provide within six months after receiving a complete application, including all required information for evaluation.  The EPA will provide an opportunity for public hearing and comment on the application and on intended action the EPA might take. The EPA intends to make a final determination within six months after the close of the public comment period. The EPA will also publish its final determination in the Federal Register. If final determination is a denial, the EPA will provide reasoning for denial and recommendations for further development and evaluation of the emerging technology, if appropriate.
j. Definition of Well Site