Subpart W defines the following "compressor sources": wet seal degassing vent (for centrifugal compressors only); rod packing emissions (for reciprocating compressors only); blowdown valve leakage through the blowdown vent (for both centrifugal and reciprocating compressors) and unit isolation valve leakage through the open blowdown vent without blind flanges (for both centrifugal and reciprocating compressors). Subpart W also defines the following "compressor modes": operating-mode (for both centrifugal and reciprocating compressors), standby-pressurized-mode (for reciprocating compressors only), and not-operating-depressurized-mode (for both centrifugal and reciprocating compressors). Some compressor sources may only release emissions during certain compressor modes. Therefore, subpart W uses the term "compressor mode-source combination" to refer to the specific compressor sources that must be measured based on the mode in which the compressor is found. For centrifugal compressors, subpart W requires measurement in the following compressor mode-source combinations: wet seal oil degassing vents in operating-mode, blowdown valve leakage through the blowdown vent in operating-mode, and unit isolation valve leakage through an open blowdown vent without blind flanges in not-operating-depressurized-mode. For reciprocating compressors, subpart W requires measurement in the following compressor mode-source combinations: rod packing emissions in operating-mode, blowdown valve leakage through the blowdown vent in operating-mode, blowdown valve leakage through the blowdown vent in standby-pressurized-mode, and unit isolation valve leakage through an open blowdown vent without blind flanges in not-operating-depressurized-mode.
The EPA is proposing several amendments related to the "as found" measurement requirements to improve the quality of data collected for compressors. First, standby-pressurized-mode was not included as a mode for centrifugal compressors in the subpart W definition of "compressor mode" and no compressor mode-source combinations were defined for centrifugal compressors in standby-pressurized-mode. While centrifugal compressors are seldom in the standby-pressurized-mode, there have been several occasions when reporters have indicated through the GHGRP Help Desk that a centrifugal compressor was in this mode during the "as found" measurement. This has led to confusion from reporters regarding how to report the data from the measurements performed. To address this issue, we are proposing to add standby-pressurized-mode to the defined modes for centrifugal compressors (40 CFR 98.238) and require measurement of volumetric emissions from the wet seal oil degassing vent and volumetric emissions from blowdown valve leakage through the blowdown vent when the compressor is found in this mode (40 CFR 98.233(o)(1)(i)(C) as proposed), consistent with sections II.A.2 and II.A.5 of this preamble.
Second, dry seals on centrifugal compressors were not included in the subpart W definition of "compressor source" and no compressor mode-source combinations were defined for dry seals on centrifugal compressors. While emissions from wet seal oil degassing vents are expected to be larger than from dry seals, dry seals may still contribute to centrifugal compressor emissions. Additionally, the measurement crew will already be at the centrifugal compressor to make the "as found" measurement for blowdown valve leakage. Therefore, to better characterize the emissions from dry seal centrifugal compressors, we are proposing to add dry seal vents to the defined compressor sources for centrifugal compressors (40 CFR 98.238) and require measurement of volumetric emissions from the dry seal vents in both operating-mode and in standby-pressurized-mode (40 CFR 98.233(o)(2)(iii) as proposed), consistent with section II.A.2 of this preamble. Proposed measurement methods for the dry seal vents are similar to those provided for reciprocating compressor rod packing emissions and would include the use of temporary or permanent flow meters, calibrated bags, and high volume samplers. Screening methods may also be used to determine if a quantitative measurement is required. Acoustical screening or measurement methods are not applicable to dry seal vents because these emissions are not a result of through-valve leakage. These proposed revisions include a proposed new reporting requirement to report the number of dry seals on centrifugal compressors and the reporting of emission measurements made on the dry seals.
Third, we are proposing to revise 40 CFR 98.233(p)(1)(i) to require measurement of rod packing emissions for reciprocating compressors when found in the standby-pressurized-mode because recent studies indicate that rod packing emissions can occur while the compressor is in this mode. The inclusion of this compressor mode-source combination would more accurately reflect compressor emissions, consistent with section II.A.2 of this preamble. Furthermore, the measurement crew will already be at the compressor to make the "as found" measurement for blowdown valve leakage and several reporters already make these measurements.
Fourth, we are proposing to revise the allowable methods for measuring wet seal oil degassing vents. Since the inception of subpart W, the only method provided in 40 CFR 98.233(o)(2)(ii) for measuring volumetric flow from wet seal oil degassing vents has been the use of a temporary or permanent flow meter. The limitation in methods allowed for wet seal oil degassing vents was due to the expectation that the volumetric flows may exceed the quantitative limits of these other methods. In reviewing the data reported for the wet seal oil degassing vent, we found that the measured flow rates using flow meters are often within the limits of other measurement methods allowed for other compressor sources. We also found that many reporters have overlooked the restriction on the methods allowed for wet seal oil degassing vents and often reported using other measurement methods (e.g., high volume samplers). We have found that most of these measured flow rates appear to be within the capacity limits of a typical high volume sampler. In the small minority of cases in which flow rates would be outside of the capacity limit of the instrument, facilities can use an alternate method, consistent with the requirements for other compressor source measurements. Consequently, we concluded that the measurement methods allowed for wet seal oil degassing vents could be expanded to include the use of calibrated bags and high volume samplers. Therefore, we are proposing to revise 40 CFR 98.233(o)(2)(ii) to allow the use of calibrated bags and high volume samplers. However, we are not proposing to allow the use of screening methods because wet seal oil degassing vents are expected to always have some natural gas flow. Therefore, we are proposing to retain and clarify this unique limitation on the use of screening methods for wet seal oil degassing vent measurement methods. This proposed revision would provide greater flexibility and improved clarity of the wet seal oil degassing provisions consistent with section II.A.2 of this preamble.
Fifth, we are proposing to remove acoustic leak detection from the screening and measurement methods allowed for manifolded groups of compressor sources. As noted in 40 CFR 98.234(a)(5), acoustic leak detection is applicable only for through-valve leakage. The acoustic method can be applied to individual compressor sources associated with through-valve leakage (i.e., blowdown valve leakage or isolation valve leakage), but it cannot be applied to a vent that contains a group of manifolded compressor sources downstream from the individual valves or other sources that may be manifolded together. The inclusion of this method for manifolded compressor sources was in error and we are proposing to remove it from 40 CFR 98.233(o)(4)(ii)(D) and (E) and 40 CFR 98.233(p)(4)(ii)(D) and (E) to improve accuracy of the measurements, consistent with section II.A.2 of this preamble.
Sixth, we are proposing a number of clarifications to the references to the allowed measurement methods to correct errors and improve the clarity of the rule, consistent with section II.A.5 of this preamble. These proposed revisions include: revising 40 CFR 98.233(o)(1)(i)(A) and (B) to reference 40 CFR 98.233(o)(2)(i) instead of specific subparagraphs of that paragraph that may be construed to limit the methods allowed for blowdown or isolation valve leakage measurements; revising 40 CFR 98.233(p)(1)(i)(A), (B) and (C) to reference 40 CFR 98.233(p)(2)(i) instead of specific subparagraphs of that paragraph that may be construed to limit the methods allowed for blowdown or isolation valve leakage measurements; revising 40 CFR 98.233(p)(1)(i)(A) and (C) (as proposed) to reference "paragraph (p)(2)(ii) or (iii) of this section as applicable" instead of only "paragraph (p)(2)(ii)" to clarify that measurement of rod packing emissions without an open-ended vent line are to be made according to 40 CFR 98.233(p)(2)(iii); and revising 40 CFR 98.233(p)(2)(ii)(C) and (iii)(A) to clarify that acoustic leak detection is not an applicable screening method for rod packing emissions (not a through-valve leakage).
In addition to these proposed revisions to the "as found" measurement requirements, we are also proposing to clarify the language at 40 CFR 98.233(o)(10) and (p)(10) for compressors at Onshore Petroleum and Natural Gas Production or Onshore Petroleum and Natural Gas Gathering and Boosting facilities, consistent with section II.A.2 of this preamble. The compressor emission factors for these industry segments are specific to uncontrolled wet seal oil degassing vents on centrifugal compressors and uncontrolled rod packing emissions for reciprocating compressors. The language in 40 CFR 98.233(o) and (p) clearly indicates that the provisions of 40 CFR 98.233(o)(10) and (p)(10) do not apply for controlled compressor sources. However, proposed revisions are necessary to provide clarity regarding the compressor sources for which emissions are required to be calculated under 40 CFR 98.233(o)(10) and (p)(10) and reported under 40 CFR 98.236(o)(5) and (p)(5). Specifically, we are proposing minor revisions to 40 CFR 98.233(o)(10) and the corresponding reporting requirements in 40 CFR 98.236(o)(5) to clarify that the compressor count used in Equation W-25 should be the number of centrifugal compressors with atmospheric (i.e., uncontrolled) wet seal oil degassing vents. Similarly, we are proposing minor revisions to 40 CFR 98.233(p)(10) and the corresponding reporting requirements in 40 CFR 98.236(p)(5) to clarify that the compressor count used in Equation W-29D should be the number of reciprocating compressors with atmospheric (i.e., uncontrolled) rod packing emissions. Finally, we are proposing to add requirements to report the total number of centrifugal compressors at the facility and the number of centrifugal compressors that have wet seals to 40 CFR 98.236(o)(5) and proposing to add a requirement to report the total number of reciprocating compressors at the facility to 40 CFR 98.236(p)(5). These additional data would provide the EPA with an improved understanding of the total number of compressors and the number of compressors that are controlled (i.e., routed to flares, combustion, or vapor recovery systems) in the Onshore Petroleum and Natural Gas Production and Onshore Petroleum and Natural Gas Gathering and Boosting industry segments, consistent with section II.A.4 of this preamble.
k. Equipment Leak Surveys
Addition of Leaker Emission Factors for Survey Methods Other than Method 21. Subpart W reporters are required to quantify emissions from equipment leaks using the calculation methods in 40 CFR 98.233(q) (equipment leak surveys) and/or 40 CFR 98.233(r) (equipment leaks by population count). The equipment leak survey method uses the count of leakers detected with one of the subpart W leak detection methods in 40 CFR 98.234(a), subpart W leaker emission factors, and operating time to estimate the emissions from equipment leaks. The current leaker emission factors applicable to onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting facilities are found in Table W-1E of subpart W. These leaker emission factors are based on the EPA's Protocol for Equipment Leak Emission Estimates published in 1995 (Docket Id. No. EPA-HQ-OAR-2009-0927-0043), also available in the docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424. The leaker emission factors are provided for components in gas service, light crude service, and heavy crude service that are found to be leaking via several different screening methods. In addition to being component- and service-specific, subpart W currently provides two different sets of leaker emission factors: one based on leak rates for leaks identified by Method 21 (see 40 CFR part 60, appendix A-7) using a leak definition of 10,000 ppm and one based on leak rates for leaks identified by Method 21 using a leak definition of 500 ppm. Currently, the other leak screening methods provided in subpart W (OGI, infrared laser beam illuminated instrument, and acoustic leak detection device) use the leaker emission factors based on Method 21 data with a leak definition of 10,000 ppm.
In the years that have followed the adoption of these emission factors into subpart W, there have been numerous studies regarding emissions from equipment leaks that provide measurement data to quantify leaker emission factors for OGI screening methods at onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting facilities. These studies found that OGI identifies fewer yet larger leaks than the EPA's Method 21. Specifically, the average leaker emission factor determined from OGI leak detection surveys is often a factor of two or more larger than leaker emission factors determined when using Method 21 leak detection surveys. Therefore, the application of the same leaker emission factor to leaking components detected with OGI and Method 21 with a leak definition of 10,000 ppm, as is currently done in subpart W, likely understates the emissions from leakers detected with OGI.
Based on our review of these studies, we are proposing to amend the leaker emission factors in Table W-1E for onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting facilities to include separate emission factors for leakers detected with OGI, consistent with section II.A.1 of this preamble. These emission factors were developed by combining the data from Zimmerle et al. (2020) and Pacsi et al. (2019) to provide OGI leaker emission factors by site type (i.e., gas or oil). These studies were selected as the basis for the proposed OGI emission factors because they included recent measurements of subpart W-specified equipment leak components from both oil and gas production and gathering and boosting sites in geographically diverse locations. The precise derivation of the proposed emission factors is discussed in more detail in the subpart W TSD, available in the docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424.
At onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting facilities, very few facilities use infrared laser beam illuminated instruments or acoustic leak detection devices to conduct equipment leak surveys and there are no data available to develop leaker emission factors specific to these methods. Based on our understanding of these alternative methods, we expect that their leak detection thresholds would be most similar to OGI, so that the average emissions per leak identified by these alternative methods would be similar to the emissions estimated using the proposed OGI leaker factors. Therefore, we are proposing that, if these alternative methods are used to conduct leak surveys, the proposed OGI leaker emission factors would be used to quantify the emissions from the leaks identified using these other monitoring methods.
For onshore petroleum and natural gas gathering and boosting facilities, all components are considered to be in gas service consistent with the language in 40 CFR 98.233(q)(2)(iv); thus, the gas service factors from Table W-1E should be applied to all leakers. In order to make clear how onshore petroleum and natural gas production facilities should apply these revised emission factors, we are proposing to amend 40 CFR 98.233(q)(2)(iii) to state that onshore petroleum and natural gas production facilities must use the appropriate default whole gas leaker emission factors consistent with the well type, where components associated with gas wells are considered to be in gas service and components associated with oil wells are considered to be in oil service as listed in Table W-1E to this subpart.
As described previously, our analysis of measurement study data from onshore production and gathering and boosting facilities demonstrates that the OGI screening method finds fewer and larger leaks than Method 21. Consequently, the leaker emission factors derived using measurement data from the OGI screening method are larger than those derived using the measurement data from Method 21 screening method. We expect that the leaker emission factors for other industry segments that are based on measurements of Method 21-identified leaks may similarly underestimate the emissions from leaking equipment when OGI (or other alternative methods besides Method 21) are used to detect the leaks. Therefore, we are proposing to apply the "OGI enhancement" factor identified from measurement study data in the onshore production and gathering and boosting industry segments to the leaker emission factors for the other subpart W industry segments as a means to estimate an OGI emission factor set. Analogous to the proposed changes in Table W-1E for the Onshore Petroleum and Natural Gas Production and Onshore Petroleum and Natural Gas Gathering and Boosting industry segments, this results in the addition of an emission factor set specific to OGI, infrared laser beam illuminated instrument, or acoustic leak detection device screening methods. The proposed emission factor sets are included in Tables W-2A, W-3A, W-4A, W-5A, W-6A, and W-7 (proposed to be moved to Table W-7A) for the Onshore Natural Gas Processing, Onshore Natural Gas Transmission Compression, Underground Natural Gas Storage, LNG Storage, LNG Import and Export Equipment, and Natural Gas Distribution industry segments, respectively. A detailed description of the proposed emission factors is discussed in more detail in the subpart W TSD, available in the docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424.
As an alternative to the proposed revised default leaker emission factors, we are also proposing an option that would allow reporters to quantify emissions from equipment leak components in 40 CFR 98.233(q) by performing direct measurement of equipment leaks and calculating emissions using those measurement results, consistent with section II.A.2 of this preamble. The proposed amendments would provide that facilities with components subject to 40 CFR 98.233(q) can elect to perform direct measurement of leaks using one of the subpart W measurement methods in 40 CFR 98.234(b) through (d) such as calibrated bagging or a high volume sampler. To use this proposed option, all leaks identified during a "complete leak detection survey" must be quantified; in other words, reporters could not use leaker emission factors for some leaks and quantify other leaks identified during the same leak detection survey. For the Onshore Petroleum and Natural Gas Production industry segment, a complete leak detection survey would be the fugitive emissions monitoring of a well site conducted to comply with NSPS OOOOa, NSPS OOOOb, or the applicable EPA-approved state plan or the applicable Federal plan in 40 CFR part 62 or, if the reporter elected to conduct the leak detection survey, a complete survey of all equipment on a single well-pad. For the Onshore Petroleum and Natural Gas Gathering and Boosting industry segment, a complete leak detection survey would be the fugitive emissions monitoring of a compressor station to comply with NSPS OOOOa, NSPS OOOOb, or the applicable EPA-approved state plan or the applicable Federal plan in 40 CFR part 62 or, if the reporter elected to conduct the leak detection survey, a complete survey of all equipment at a gathering "compressor station" or at a "centralized oil production site" (and we are proposing to define these terms in 40 CFR 98.238, as described in section III.J.1.p of this preamble). For downstream industry segments (e.g., Onshore Natural Gas Transmission Compression), a complete leak detection survey is facility-wide, and therefore, the election to perform direct measurement of leaks would also be facility-wide. In other words, this option would allow the use of measurement data directly when all leaks identified are quantitatively measured.
The proposed amendments rely specifically on quantitative measurement methods already provided in the rule. We are seeking comment on alternative methods for quantifying leaks for use for these equipment leak measurements (and for "as found" compressor measurements) along with supporting information and data. The supporting information should include description of the method, limitations on the applicability of the method, and calibration requirements. Supporting data should include accuracy assessments relative to other quantitative measurement methods provided in the rule.
Finally, as part of this overall amendment, we are also proposing to remove the additional Method 21 screening when a survey is conducted using a method other than Method 21. Currently, facilities using survey methods other than Method 21 to detect equipment leaks may then screen the equipment identified as leaking using Method 21 to determine if the leak measures greater than 10,000 parts per million by volume (ppmv) (see, e.g., 40 CFR 98.234(a)(1)). If the Method 21 screening of the leaking equipment is less than 10,000 ppmv, then reporters may consider that equipment as not leaking. In the 2016 subpart W revisions, we added a leak detection methodology at 40 CFR 98.234(a)(6) (proposed to be moved to 40 CFR 98.234(a)(1)(ii)) for using OGI in accordance with NSPS OOOOa, which does not include an option for additional Method 21 screening. As noted in response to comments on the subpart W proposal regarding the absence of this optional additional Method 21 screening when using OGI in accordance with NSPS OOOOa, the additional screening of OGI-identified leaking equipment using Method 21 requires additional effort from reporters (81 FR 86500, November 30, 2016). Furthermore, as noted previously in this section, the average emissions of leakers identified by OGI are greater than leaks identified by Method 21. Directly applying the number of OGI-identified leaks to the subpart W leaker emission factor specific to that survey method would provide the most accurate estimate of emissions, while selectively screening OGI-identified leaks using Method 21 to reduce the number of reportable leakers would yield a low bias in the reported emissions. Therefore, we are proposing to require reporters to directly use the leak survey results for the monitoring method used to conduct the complete leak survey and are proposing to eliminate this additional Method 21 screening provision. In addition to providing more accurate emissions data consistent with section II.A.2 of this preamble, the removal of the additional monitoring step would streamline and improve implementation consistent with section II.B.2 of this preamble.
Amendments Related to Oil and Natural Gas Standards and Emissions Guidelines in 40 CFR part 60. As noted in the introduction to section III.J of this preamble, the EPA recently proposed NSPS OOOOb and EG OOOOc for oil and natural gas new and existing affected sources, respectively. Under the proposed standards in NSPS OOOOb and the proposed presumptive standards in EG OOOOc, owners and operators would be required to implement a fugitive emissions monitoring and repair program for the collection of fugitive emissions components at well site and compressor station affected sources. In addition, the proposed NSPS OOOOb and EG OOOOc include a proposed Appendix K to 40 CFR part 60, an OGI-based method for detecting leaks and fugitive emissions from all components that is not currently provided in subpart W. The EPA also proposed provisions in NSPS OOOOb and EG OOOOc for equipment leak detection and repair at onshore natural gas processing facilities. Similar to the 2016 amendments to subpart W (81 FR 4987, January 29, 2016), the EPA is proposing to revise the calculation methodology for equipment leaks in subpart W so that data derived from equipment leak and fugitive emissions monitoring conducted under NSPS OOOOb or the applicable approved state plan or applicable Federal plan in 40 CFR part 62 would be used to calculate emissions, consistent with section II.A.2 of this preamble.
First, under these proposed amendments, facilities with certain fugitive emissions components at a well site or compressor station subject to NSPS OOOOb or an applicable approved state plan or applicable Federal plan in 40 CFR part 62 would use the data derived from the NSPS OOOOb or 40 CFR part 62 fugitive emissions requirements along with the subpart W equipment leak survey calculation methodology and leaker emission factors to calculate and report their GHG emissions to the GHGRP. Specifically, the proposed amendments would expand the cross-reference to 40 CFR 60.5397a to include the analogous requirements in NSPS OOOOb or 40 CFR part 62. Facilities with fugitive emissions components not subject to the standards in the proposed NSPS OOOOb or addressed by the presumptive standards in the proposed EG OOOOc and subject to 40 CFR part 62 would continue to be able to elect to calculate subpart W equipment leak emissions using the leak survey calculation methodology and leaker emission factors (as is currently provided in 40 CFR 98.233(q)). Therefore, reporters with other fugitive emission sources at subpart W facilities not covered by NSPS OOOOb or 40 CFR part 62 (e.g., sources subject to other state regulations and sources participating in the Methane Challenge Program or other voluntarily implemented programs) would continue to have the opportunity to voluntarily use the proposed leak detection methods to calculate and report their GHG emissions to the GHGRP. To facilitate this proposed requirement, we are also proposing to clarify that fugitive emissions monitoring conducted to comply with NSPS OOOOa, NSPS OOOOb, or an applicable approved state plan or applicable Federal plan in 40 CFR part 62 is considered a "complete leak detection survey," so that onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting facilities can use NSPS OOOOb or 40 CFR part 62 fugitive emission surveys directly for their subpart W reports. In a corresponding amendment, we are also proposing to expand the current reporting requirement in 40 CFR 98.236(q)(1)(iii) to require reporters to indicate if any of the surveys of well sites or compressor stations used in calculating emissions under 40 CFR 98.233(q) were conducted to comply with the fugitive emissions standards in NSPS OOOOb or an applicable approved state plan or applicable Federal plan in 40 CFR part 62. We request comment on these proposed amendments and whether there are other provisions or reporting requirements relative to NSPS OOOOb or EG OOOOc that we should consider for subpart W.
Second, we are proposing to revise 40 CFR 98.234(a) to clarify and consolidate the requirements for OGI and Method 21 in 40 CFR 98.234(a)(1) and (2), respectively. In the 2016 amendments to subpart W (81 FR 4987, January 29, 2016), the EPA added 40 CFR 98.234(a)(6) and (7) to provide OGI and Method 21 as specified in NSPS OOOOa as leak detection survey methods. In part, structuring the amendment this way allowed the EPA to provide the NSPS OOOOa leak detection methods as allowable methods under subpart W without affecting the requirements for facilities and industry segments not subject to NSPS OOOOa. However, as the EPA continues to propose additional standards with slightly different variations on OGI and Method 21, it would be unnecessarily convoluted to continue to add those methods and cross-references to each standard to the end of 40 CFR 98.234(a). Therefore, the EPA is proposing to move 40 CFR 98.234(a)(1) and 40 CFR 98.234(a)(6) to 40 CFR 98.234(a)(1)(i) and 40 CFR 98.234(a)(1)(ii), respectively, which would consolidate the OGI-based methods in 40 CFR 98.234(a)(1). Similarly, the EPA is proposing to revise 40 CFR 98.234(a)(2) such that 40 CFR 98.234(a)(2)(i) is Method 21 with a leak definition of 10,000 ppm and 40 CFR 98.234(a)(2)(ii) is Method 21 with a leak definition of 500 ppm. This proposed amendment would effectively move 40 CFR 98.234(a)(7) to 40 CFR 98.234(a)(2)(ii). The references to "components listed in § 98.232" would be replaced with a more specific reference to 40 CFR 98.233(q)(1). The references to specific provisions in 40 CFR 60.5397a in 40 CFR 98.234(a)(6) and (7) would be moved to 40 CFR 98.234(a)(1)(ii) and 40 CFR 98.234(a)(2), as applicable.
The EPA proposed in NSPS OOOOb and EG OOOOc that owners and operators would detect leaks using an OGI-based monitoring method following the concurrently proposed appendix K to 40 CFR part 60. We are proposing to include that same method in subpart W at 40 CFR 98.234(a)(1)(iii) to ensure that reporters would be able to comply with the proposed subpart W requirement to use data derived from the NSPS OOOOb or 40 CFR part 62 fugitive emissions requirements for purposes of calculating emissions from equipment leaks. As part of the proposal of NSPS OOOOb and EG OOOOc, the EPA proposed an alternative screening approach for fugitive emissions from well sites and compressor stations that would allow the use of advanced measurement technologies to detect large equipment leaks. If emissions are detected using one of these advanced technologies, facilities would be required to conduct monitoring using OGI or Method 21 to identify and repair specific leaking equipment. Additionally, even if no large emissions are identified, facilities using these advanced technologies would still be required to conduct annual fugitive emissions monitoring using OGI or Method 21. The EPA's intent in this proposed rule for subpart W is that the results of those NSPS OOOOb and 40 CFR part 62 OGI or Method 21 surveys would be used for purposes of calculating emissions for subpart W, as OGI and Method 21 are capable of identifying leaks from individual components and they are leak detection methods provided in subpart W. The EPA also requests comment on additional methods or advanced technologies that can identify individual leaking components. Based on the information received, the EPA would need to review the specific method and leak detection data collected using that method to determine what default leaker emission factors would apply for that method and whether any adjustments might be needed to the subpart W equipment leak survey calculation methodology when using that method. Following that review, the EPA may undertake a rulemaking process to include the additional leak detection method(s) in 40 CFR 98.234(a).
Third, we are proposing subpart W requirements for onshore natural gas processing facilities consistent with certain requirements for equipment leaks in the proposed NSPS OOOOb or EG OOOOc. Currently, onshore natural gas processing facilities must conduct at least one complete survey of all the components listed in 40 CFR 98.232(d)(7) each year, and each complete survey must be considered when calculating emissions according to 40 CFR 98.233(q)(2). Under the equipment leak detection and repair program included in proposed NSPS OOOOb and the EG OOOOc presumptive standards, different component types may be monitored on different frequencies, so all equipment at the facility is not always monitored at the same time. According to the current requirements in 40 CFR 98.233(q), surveys that do not include all of the applicable equipment at the facility are not considered complete surveys and are not used for purposes of calculating emissions. Therefore, we are proposing that for onshore natural gas processing facilities subject to NSPS OOOOb or an applicable approved state plan or the applicable Federal plan in 40 CFR part 62 would use the data derived from each equipment leak survey conducted as required by NSPS OOOOb or 40 CFR part 62 along with the subpart W equipment leak survey calculation methodology and leaker emission factors to calculate and report GHG emissions to the GHGRP, even if a survey required for compliance with NSPS OOOOb or 40 CFR part 62 does not include all the component types listed in 40 CFR 98.232(d)(7).
Under this proposed amendment, reporters would still have to meet the subpart W requirement to conduct at least one complete survey of all applicable equipment at the facility per year, so if there were components listed in 40 CFR 98.232(d)(7) not included in any NSPS OOOOb or 40 CFR part 62-required surveys conducted during the year (e.g., connectors that are monitored only once every 4 years), reporters subject to NSPS OOOOb or 40 CFR part 62 would need to either add those components to one of their required surveys, making that a complete survey for purposes of subpart W, or conduct a separate complete survey for purposes of subpart W. We expect that reporters with onshore natural gas processing plants implementing traditional leak detection and repair programs are already making similar decisions regarding how to meet the requirement to conduct a complete survey for subpart W, and our intention with this proposed amendment is not to change those decisions. Rather, this amendment would specify that surveys conducted pursuant to NSPS OOOOb or 40 CFR part 62 that do not include all component types listed in 40 CFR 98.232(d)(7) would be used for calculating emissions along with each complete survey.
We are also proposing to add leaker emission factors for all survey methods for "other" components that would be required to be monitored under NSPS OOOOb or an approved state plan or applicable Federal plan in 40 CFR part 62 or that reporters elect to survey that are not currently included in subpart W. These proposed total hydrocarbon leaker emission factors are the same as the total hydrocarbon leaker emission factors for the Onshore Natural Gas Transmission Compression and the Underground Natural Gas Storage industry segments (Table W-3A and Table W-4A, respectively). For more information on the derivation of the original emission factors, see the TSD for the final subpart W standards, and for more information on the derivation of the emission factors proposed to be added to Table W-2B, see the TSD for the 2016 amendments to subpart W. In a corresponding amendment, we are also proposing to expand the reporting requirement in 40 CFR 98.236(q)(1)(iii) to require onshore natural gas processing reporters to indicate if any of the surveys used in calculating emissions under 40 CFR 98.233(q) were conducted to comply with the equipment leak standards in NSPS OOOOb or an applicable approved state plan or the applicable Federal plan in 40 CFR part 62. We request comment on the proposed amendments to subpart W for onshore natural gas processing facilities subject to the equipment leak provisions of NSPS OOOOb or 40 CFR part 62, as well as whether there are other provisions or reporting requirements for these facilities that we should consider.
Finally, in our review of subpart W equipment leak requirements for onshore natural gas processing facilities, we found that the leak definition for the Method 21-based requirements for processing plants in NSPS OOOOa (as well as proposed NSPS OOOOb and EG OOOOc presumptive standards) is not consistent with the leak definition in the Method 21 option in current 40 CFR 98.234(a)(1), which is the only Method 21-based method available to onshore natural gas processing facilities under subpart W. Based on this review, and to complement the proposed addition of default leaker emission factors for survey methods other than Method 21 (as described previously in this preamble), we are proposing several additions to the equipment leak survey requirements for the Onshore Natural Gas Processing industry segment, beyond those amendments already described related to the proposed NSPS OOOOb and EG OOOOc presumptive standards. First, we are proposing default leaker emission factors for Method 21 at a leak definition of 500 ppm in Table W-2A. As with the proposed "other" leaker emission factors, these proposed leaker emission factors are the same as the total hydrocarbon leaker emission factors for the Onshore Natural Gas Transmission Compression and the Underground Natural Gas Storage industry segments (Table W-3A and Table W-4A, respectively). For more information on the derivation of those emission factors, see the TSD for the 2016 amendments to subpart W. In addition, we are proposing to add 40 CFR 98.233(q)(1)(v) to indicate that onshore natural gas processing facilities not subject to NSPS OOOOb or an approved state plan or the applicable Federal plan in 40 CFR part 62 may use any method specified in 40 CFR 98.234(a), including Method 21 with a leak definition of 500 ppm and OGI following the provisions of appendix K to 40 CFR part 60. This proposed amendment would ensure that equipment leak surveys conducted using any of the approved methods in subpart W would be available for purposes of calculating emissions, not just those surveys conducted using one of the methods currently provided in 40 CFR 98.234(a)(1) through (5).
l. Equipment Leaks by Population Count
As noted in section III.J.1.k of this preamble, subpart W reporters are required to quantify emissions from equipment leaks using the calculation methods in 40 CFR 98.233(q) (equipment leak surveys) and/or 40 CFR 98.233(r) (equipment leaks by population count), depending upon the industry segment. The equipment leaks by population count method uses the count of equipment components, subpart W emission factors (e.g., Table W-1A for the Onshore Petroleum and Natural Gas Production industry segment), and operating time to estimate emissions from equipment leaks. For the Onshore Petroleum and Natural Gas Production and Onshore Petroleum and Natural Gas Gathering and Boosting industry segments, the count of equipment components may be determined by counting each component individually for each facility (Component Count Method 2) or the count of equipment components may be estimated using the count of major equipment and subpart W default average component counts for major equipment (Component Count Method 1) in Tables W-1B and W-1C, as applicable. Reporters in other industry segments must count each applicable component at the facility. We are proposing several amendments to the calculation methodology provisions of 40 CFR 98.233(r) and the reporting requirements in 40 CFR 98.236(r) to improve the quality of the data collected, consistent with sections II.A.1, II.A.4, and II.A.5 of this preamble.
Onshore Petroleum and Natural Gas Production and Onshore Petroleum and Natural Gas Gathering and Boosting Population Count Method. The current population emission factors for the Onshore Petroleum and Natural Gas Production and Onshore Petroleum and Natural Gas Gathering and Boosting industry segments are found in Table W-1A of subpart W. The gas service population emission factors are based on the 1996 Gas Research Institute (GRI)/EPA study Methane Emissions from the Natural Gas Industry, Volume 8: Equipment Leaks (available in the docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424). The oil service population emission factors are based on the American Petroleum Institute's (API) Emission Factors for Oil and Gas Production Operations, Publication 4615 published in 1995.
As noted previously in this section, when estimating emissions using the population count method, onshore petroleum and natural gas production facilities and onshore petroleum and natural gas gathering and boosting facilities have the option to use actual component counts (i.e., Component Count Method 2) or to estimate their component counts using the count of major equipment (e.g., wellhead) and default component counts per major equipment (e.g., valves per wellhead) included in Tables W-1B and W-1C of subpart W (i.e., Component Count Method 1). In reviewing subpart W data, we find that the vast majority (greater than 95 percent) of onshore production and natural gas gathering and boosting facilities use Component Count Method 1 to estimate the count of components.
It is important to note that both the population count emission factors and the default component counts per major equipment included in Tables W-1A, W-1B and W-1C are service-specific (i.e., gas or oil) as well as region-specific (i.e., eastern or western U.S.). The regional designations are provided by U.S. state in Table W-1D of subpart W such that a facility would determine the facility's region and select the appropriate region- and service-specific factors.
In the years that have followed the adoption of these emission factors into subpart W, there have been numerous studies regarding emissions from equipment leaks at onshore production and gathering and boosting facilities. Two recent field studies, Pacsi et al. (2019) and Zimmerle et al. (2020), have performed an equipment and component inventory alongside equipment leak screening and measurement results. Another recent study, Rutherford et al. (2021), included synthesis and analysis of measurements from component-level field studies. These studies provide the necessary data to develop and compare study-estimated population emission factors as well as study-estimated default component counts per major equipment to those in subpart W. Comparison of the study-estimated default component counts per major equipment found that the subpart W values underestimate the count of components found on major equipment in the field (Zimmerle et al., 2020; Pacsi et al., 2019). Regarding a comparison of the population emission factors and component counts per major equipment between the subpart W eastern and western values, Zimmerle et al. (2020) was the only field study to include both eastern and western facilities, and the study values showed "no statistically significant differences between eastern and western U.S. regions." Rutherford et al. (2021) also found their study-estimated population emission factors to be higher than those in subpart W, noting that one of the contributing factors to this difference was the use of the eastern factors in subpart W, which appear to significantly undercount emissions. Rutherford et al. (2021) noted that the impact of the use of the eastern factors has grown over time as the production in the eastern region of the U.S. has increased from less than 5 percent of gas produced to nearly 30 percent of the gas produced.
Based on our review of these studies, we are proposing to amend the population count method for onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting facilities using these more recent study data, consistent with section II.A.1 of this preamble. These proposed amendments include new population emission factors that are on a per major equipment basis rather than a per component basis. As mentioned previously, the vast majority of reporters estimate the component counts using Component Count Method 1. By providing emission factors on a major equipment basis instead of by component, we would eliminate the step to estimate the number of components. All facilities would be able to inventory their major equipment and consistently apply the same emissions factor to estimate emissions. This would reduce reporter burden and reduce the number of errors in the calculation of emissions, as we find that numerous facilities incorrectly estimate the number of components using Component Count Method 1 while providing consistently estimated emission results. The major equipment emission factors were developed by combining data from Zimmerle et al. (2020) and Pacsi et al. (2019) to provide population emission factors by major equipment and site type (i.e., gas or oil). The emission factors were derived by summing the leaker emissions by major equipment type, including wellhead, separator, meters/piping, compressor, acid gas removal unit, dehydrator, header, heater treater, and storage vessel, by the reported site type and dividing those leaker emissions by the count of major equipment screened to yield an emission factor in units of scf whole gas / hour-equipment. Specific to meters/piping and consistent with current requirements related to meters/piping at 40 CFR 98.233(r)(2)(i)(A), we are proposing in 40 CFR 98.233(r)(2) to specify that one meters/piping equipment should be included per well-pad for onshore petroleum and natural gas production operations and the count of meters in the facility should be used for this equipment category at onshore petroleum and natural gas gathering and boosting facilities. As a consequence of the broader scope of equipment surveyed in the Pacsi/Zimmerle studies, the proposed emission factors include more pieces of major equipment than are currently included in subpart W. The derivation of the proposed emission factors is discussed in more detail in the subpart W TSD, available in the docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424. The proposed major equipment emission factors would replace the component-based emission factors in the current Table W-1A. We are also proposing to revise the titles of Tables W-1B, W-1C, and W-1D to clarify that they apply to reporting years up to and including RY2022. These tables would not apply to subsequent reporting years as they provide activity data that would no longer be needed for the population count method for these industry segments. We are seeking comment on the approach of providing population count emission factors by major equipment.
We note that the application of these emission factors is by site type such that for onshore petroleum and natural gas production facilities, gas well sites should use the proposed gas service emission factors and oil well sites should use the proposed oil service emission factors. Similarly, for onshore petroleum and natural gas gathering and boosting facilities, we consider all equipment to be in gas service consistent with the language in 40 CFR 98.233(r)(2); thus, the proposed gas service factors from Table W-1A should be applied to all equipment counts. We are proposing language clarifying the service-specific application of these emission factors specifically for onshore petroleum and natural gas production in 40 CFR 98.233(r)(2).
Natural Gas Distribution Emission Factors. Natural Gas Distribution companies quantify the emissions from equipment leaks from pipeline mains and services, below grade transmission distribution transfer stations, and below grade metering-regulating stations following the procedures in 40 CFR 98.233(r). This method uses the count of equipment, subpart W population emission factors in Table W-7 (proposed to be moved to Table W-7B), and operating time to estimate emissions. The population emission factors for pipeline mains and services in Table W-7 (proposed to be moved to Table W-7B) are based on information from the 1996 GRI/EPA study. Specifically for plastic mains, additional data are sourced from a 2005 ICF analysis. The population emission factors for pipeline mains are published per mile of main by pipeline material and emission factors for pipeline services are published per service by pipeline material. The population emission factors for below grade stations in Table W-7 (proposed to be moved to Table W-7B) are based on information from the 1996 GRI/EPA study. The population emission factors for below grade transmission-distribution transfer stations and below grade metering-regulating stations are published per station by three inlet pressure categories (>300 psig, 100-300 psig, < 100 psig).
The EPA is proposing to update the population emission factors in Table W-7 (proposed to be moved to Table W-7B) to subpart W using the results of studies and information that were not available when the rule was finalized in 2010. Notably, the EPA reviewed recent studies and updated the emission factors for several natural gas distribution sources, including pipeline mains and services and below grade stations, for the 2016 U.S. GHG Inventory.[,]  The majority of the U.S. GHG Inventory updates were based on data published by Lamb et al. in 2015. Since the time that the 2016 U.S. GHG Inventory updates were made, additional studies for pipeline distribution mains have been published and reviewed by the EPA, notably Weller et al. in 2020. Our assessment of the studies published since subpart W was finalized supports revising the emission factors for pipelines in the Natural Gas Distribution industry segment of subpart W. For more information on the review and analysis of the various studies, see the subpart W TSD, available in the docket for this rulemaking (Docket Id. No. EPA-HQ-OAR-2019-0424).
The population emission factors for distribution mains and services are a function of the average measured leak rate (scf/hr) and the frequency of annual leaks observed (leaks/mile-year or leaks/service-year) by pipeline material (e.g., protected steel, plastic). The Lamb et al. and Weller et al. studies utilized different approaches for quantifying leak rates and determining the pipeline material-specific frequency of annual leaks. The Lamb et al. study quantified leaks from distribution mains and services using a high volume sampling method and some downwind tracer measurements and estimated the frequency of leaks by pipeline material using company records and Department of Transportation (DOT) repaired leak records from six local distribution companies (LDCs). This methodology was consistent with the GRI/EPA study. The Weller et al. study quantified leaks from only distribution mains using the Advanced Mobile Leak Detection (AMLD) technique, which involves mobile surveying using high sensitivity instruments and algorithms that predict the leak location and size, attributed leaks to the pipeline material using geographic information system (GIS) data, and estimated the frequency of leaks using modeling.
During our assessment of the Lamb et al. and Weller et al. studies, we identified the method for leak quantification as being a key strength of the Lamb et al. study and the significantly larger sample size used in estimating the annual leak frequency as being a key strength of the Weller et al. study. In order to take advantage of the strengths of both studies, we are proposing to amend the subpart W emission factors for distribution mains using the measurements from Lamb et al. combined with the pipeline material specific leaks per mile data from Weller et al. We are proposing to amend the subpart W emission factors for distribution services using the measurements from Lamb et al. only, consistent with the emission factors used in the 2016 U.S. GHG Inventory, because services were not included in the Weller et al. study. See the subpart W TSD, available in the docket for this rulemaking (Docket Id. No. EPA-HQ-OAR-2019-0424) for more information on our assessment of both studies and the derivation of the proposed emission factors from the data published by Lamb et al. and Weller et al. We are seeking comments on the approach of combining data from both studies to update the distribution mains emission factors. As alternatives to the proposed amendments, we also considered updating the distribution mains emission factors using data from each study independently. Accordingly, we are also seeking comment on whether using data only from Lamb et al., consistent with the emission factors used in the U.S. GHG Inventory, or only from Weller et al. to update the distribution mains emission factors would be preferrable over the combined approach included in this proposal, and if so, which study is preferred and why.
For below grade stations, the 2016 U.S. GHG Inventory also began applying a new emission factor from the data published by Lamb et al. to the count of stations to estimate emissions from these sources. In order to assess the appropriateness of incorporating this revision into the subpart W requirements for below grade stations (i.e., replacing the set of below grade emission factors by station type and inlet pressure with one single emission factor), the EPA performed an analysis of the reported subpart W data for below grade stations compared to data from the recent studies (see the subpart W TSD, available in the docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424). We found that the subpart W reported station count combined with the current subpart W emission factors yields an average emission factor similar to the U.S. GHG Inventory emission factor; as such, using either set of emission factors would yield approximately the same emissions results for the GHGRP.
Therefore, we are proposing to amend the emission factors for below grade transmission-distribution transfer stations and below grade metering-regulating stations in Table W-7 (proposed to be moved to Table W-7B) to a single emission factor without regard to inlet pressure. We are also proposing to amend the corresponding section header in Table W-7 (proposed to be moved to Table W-7B) for below grade station emission factors and the references to Table W-7 (proposed to be moved to Table W-7B) in 40 CFR 98.233(r)(6)(i) to clarify the emission factor that should be applied to both types of below grade stations (i.e., transmission-distribution transfer and metering-regulating). This proposed amendment would impact the reporting requirements as well, as it would consolidate six emission source types to two emission source types (below grade transmission-distribution transfer stations and below grade metering-regulating stations, without differentiating between inlet pressures) for purposes of reporting under 40 CFR 98.236(r)(1). This proposed amendment would improve the data quality through use of more recent emission factors and would be consistent with changes made to the U.S. GHG Inventory. It would also result in reporting of fewer data elements, consistent with section II.B.3 of this preamble.
Gathering Pipeline Emission Factors. Facilities in the Onshore Petroleum and Natural Gas Gathering and Boosting industry segment quantify the emissions from equipment leaks from gathering pipelines following the procedures in 40 CFR 98.233(r). This method uses the count of equipment, subpart W population emission factors in Table W-1A, and operating time to estimate emissions. The population emission factors for gathering pipeline mains in Table W-1A are based on leak rates from natural gas distribution companies and gathering pipeline-specific activity data as provided in the 1996 GRI/EPA study. The population emission factors for gathering pipelines are published per mile by pipeline material.
As noted previously in this section, the EPA is proposing to update the natural gas distribution population emission factors in Table W-7 (proposed to be moved to Table W-7B) to subpart W using the results of studies and information that were not available when the rule was originally finalized. In particular, the EPA is proposing to update the leak rate portion of the emission factor based on data published by Lamb et al. in 2015. The EPA has reviewed the recent studies published for onshore petroleum and natural gas gathering and boosting facilities as well as the additional studies for pipeline distribution mains, and none of the studies provide new emissions data or activity data specific to gathering pipelines. Therefore, consistent with the updates to the emission factors for distribution mains, and consistent with section II.A.1 of this preamble, we are proposing to revise the gathering pipeline population emission factors to use the leak rates from Lamb et al. (2015). We are not proposing to update the activity data (leaks per mile of pipeline) portion of the emission factors, as the information in the 1996 GRI/EPA study continues to be the best available data specific to gathering pipelines. For more information on the proposed updates to the gathering pipeline population emission factors, see the subpart W TSD, available in the docket for this rulemaking (Docket Id. No. EPA-HQ-OAR-2019-0424).
m. Other Large Release Events
We are proposing to add an additional emissions source, referred to as "other large release events" to capture abnormal emission events that are not fully accounted for using existing methods in subpart W, consistent with section II.A.3 of this preamble. Most of the emission sources and methodologies included in subpart W characterize emissions that routinely occur at oil and gas facilities as part of their normal operations. While some sources covered by subpart W methodologies, such as equipment leaks, may represent "malfunctioning" equipment, these sources are ubiquitous across the oil and gas sector, are generally small, and have been studied and characterized. On the other hand, there have been several large, atypical release events at oil and gas facilities over the last few years where it was difficult to sufficiently include these emissions in annual GHGRP reports. For example, a storage wellhead leak at Aliso Canyon released approximately 100,000 metric tons of CH4 between October 2015 and February 2016 and a well blowout in Ohio released an estimated 40,000 to 60,000 tons of CH4 in a 20-day period in 2018. The emissions from these types of releases were not well represented using the existing calculation methodologies in subpart W because these were not common or predictable events. Because these events can significantly contribute to the total GHG emissions from this sector, we are proposing new calculation methods for estimating the GHG emissions from other large release events in 40 CFR 98.233(y) and requirements for reporting other large release events in 40 CFR 98.236(y). These proposed additional calculation and reporting requirements would apply to all subpart W industry segments and would improve the accuracy of emissions reported under subpart W and enhance the overall quality of the data collected under the GHGRP.
The new calculation requirements being proposed rely on measurement data or engineering estimates of the amount of gas released and measurement data, if available, or process knowledge (best available data) to estimate the composition of the released gas. The proposed requirement to calculate and report GHG emissions from other large release events would be limited to events that release at least 250 mtCO2e per event. This is equivalent to approximately 500,000 scf of pipeline quality natural gas. We selected this proposed threshold to capture reporting for large emission events, such as well blowouts, well releases, and large pressure relief venting. In order to establish this reporting threshold, we first assessed other emission sources that we considered large. Specifically, we considered completions of hydraulically fractured wells that are not controlled (i.e., not performed using reduced emission completions) to be large emissions events. Based on analysis of GHGRP data of wells that are not reduced emission completions and that vent, the U.S. GHG Inventory developed an average emission factor of about 360 mtCO2e for these events. Because this is an average emissions factor, some uncontrolled hydraulically fractured completions will be below this average and some above. From this assessment, we considered 250 mtCO2e to be a reasonable emissions threshold for a "large" event.
While 250 mtCO2e is much lower than the emissions from the Aliso Canyon or Ohio well blowout releases, we determined that a 250 mtCO2e threshold would be needed to capture most well blowouts. There are limited data to quantify an "average" well blowout, but the 2021 U.S. GHG Inventory uses an oil well blowout emission factor of 2.5 MMscf per event. As this is an average, many well blowouts will be less than this average value. The 250 mtCO2e threshold is approximately equivalent to 500,000 scf of natural gas, which compares reasonably well with the lower range of well blowouts expected based on the average emission factor of 2.5 MMscf per event.
We also find that the 250 mtCO2e threshold (approximately equivalent to 500,000 scf natural gas release) is a reasonable threshold for requiring individual assessments of releases. In subpart Y (Petroleum Refineries), we established event-specific emission calculation requirements for startup, shutdown, or malfunction releases to a flare exceeding 500,000 scf per day (40 CFR 98.253(b)(1)(iii)). While the subpart Y threshold is per day rather than per event, it is also specific to flared emissions. For flared emissions to exceed a 250 mtCO2e threshold, approximately 4 MMscf of natural gas would have to be released to the flare, which is well above the subpart Y "per day" threshold for flares. Thus, we conclude that the 250 mtCO2e per event threshold is an appropriate size threshold for requiring event-specific emission calculations to be performed. More information regarding our review and characterization of types of other large release events is included in the subpart W TSD, available in the docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424. Emissions from smaller or routine release events would still be reported, as applicable, under the source-specific calculation and reporting requirements in subpart W.
We are proposing a definition of "other large release events" in 40 CFR 98.238 to clarify the types of releases that must be characterized for this new emissions source and specify that other large release events include, but are not limited to, well blowouts, well releases, releases from equipment rupture, fire, or explosions. Currently, there are no calculation methodologies or reporting requirements for these types of large releases in subpart W. The proposed definition would also include large pressure relief valve releases from process equipment other than onshore production and onshore petroleum and natural gas gathering and boosting storage tanks that are not included in the blowdown definition. While subpart W currently includes emission factors for pressure relief devices, these equipment leak emission factors only account for leaks past a pressure relief valve that is in the closed position, not releases from the complete opening of these valves. The proposed definition specifies that pressure relief valve releases from onshore production and onshore petroleum and natural gas gathering and boosting storage tanks would not be considered other large release events because the calculation methodology for these storage tanks currently assumes all flash gas will be emitted. As noted in section III.K.1.g of this preamble, pressure relief emission releases from onshore production and onshore petroleum and natural gas gathering and boosting storage tanks generally occur from the thief hatch and these releases must be accounted for when calculating the fraction of flash gas that is recovered or sent to a flare, if applicable. A more detailed discussion of certain other emissions events we have identified and expect to be subject to the "other large release events" proposed amendments is included in the subpart W TSD available in the docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424.
As part of the proposed definition of "other large release events" in 40 CFR 98.238, we are also proposing that other large release events include releases from equipment for which the existing calculation methodologies in subpart W would significantly underestimate the episodic nature of these emissions. For example, subpart W contains population emission factors and leaker emission factors for estimating equipment leak emissions for storage wellheads. Thus, it is possible to argue that subpart W includes calculation methodologies for the equipment responsible for the Aliso Canyon release. However, the calculation methodologies in subpart W do not accurately estimate emissions from such an uncharacteristically large event because such events are so rare that they generally do not exist when measurement studies are conducted. Additionally, skewing the emission factors used to account for such an event would yield erroneously high emissions from normal operations for nearly all reporting facilities. Thus, we determined that it is more accurate for facility-specific reporting to account for these large releases on a per event basis. Therefore, if a single leak or event has emissions that exceed the emissions estimated by an applicable methodology included in subpart W by 250 mtCO2e or more, we are proposing that such releases would be included in the definition of "other large release events" and that reporters would be required to calculate and report the GHG emissions from these events using the proposed requirements for other large release events.
Further, we are proposing to define the terms "well release" and "well blowout" in 40 CFR 98.238 to assist reporting facilities with differentiating between these types of release events that could potentially occur at wells. We find that a well blowout is generally distinguished by a complete loss of well control for a long duration of time and a well release is characterized as a short period of uncontrolled release (not the controlled pre-separation stage of well flowback in a hydraulically fractured completion) followed by a period of controlled release in which control techniques were successfully implemented.
Finally, we are proposing a reporting requirement that would require subpart W reporters to indicate whether an "other large release event" was identified under any provisions of NSPS OOOOb or an applicable approved state plan or applicable Federal plan in 40 CFR part 62. As described in section III.J.1.k of this preamble, the EPA proposed a fugitive emissions monitoring program in NSPS OOOOb and EG OOOOc, including an alternative screening approach for fugitive emissions from well sites and compressor stations that would allow the use of advanced measurement technologies to detect emissions. As part of that proposal, the EPA also requested comment on how to evaluate and design a requirement for owners and operators to investigate and remediate large emission events, which could include the use of alternative screening techniques and advanced measurement technologies, all of which, if finalized, could potentially be used to identify "other large release events" under subpart W. While some methods that could be used to identify and estimate the magnitude of these "other large release events," such as monitors installed on mobile vehicles or aircraft or methane satellite imagery, would not be specifically included as measurement methods in subpart W, these methods may be used to quantify the emissions release for "other large release events" under the "engineering estimates" and "best available data" provisions of the proposed calculation methodology. To improve the EPA's understanding of the technologies and methods used to identify reported "other large release events," including the impact of periodic screenings with advanced measurement technologies on the identification of large release events, we are proposing reporting provisions that would require reporters to indicate whether each "other large release event" was identified as part of compliance with NSPS OOOOb or the applicable state plan or applicable Federal plan in 40 CFR part 62.
n. Combustion
Methane Slip from Compressor Engines. All facilities reporting under subpart W except those in the Onshore Natural Gas Transmission Pipeline industry segment must include combustion emissions in their annual report. Facilities in the Onshore Petroleum and Natural Gas Production, Onshore Petroleum and Natural Gas Gathering and Boosting, and Natural Gas Distribution industry segments calculate emissions in accordance with the provisions in 40 CFR 98.233(z) and report combustion emissions per 40 CFR 98.236(z). Reporters in the other industry segments calculate and report combustion emissions under subpart C (General Stationary Fuel Combustion Sources). The authors of several recent studies have examined combustion emissions at Onshore Petroleum and Natural Gas Gathering and Boosting facilities and have demonstrated that a significant portion of emissions can result from unburned methane entrained in the exhaust of natural gas compressor engines (also referred to as "combustion slip" or "methane slip"). These studies contend that emissions from natural gas compressor engines included in the GHGRP are significantly underestimated because they do not account for combustion slip. The EPA performed a review of each of these studies and the U.S. GHG Inventory to determine whether and how combustion slip emissions have been incorporated into published data and how the incorporation of combustion slip would affect the emissions from the petroleum and natural gas system sector reported to the GHGRP (see the subpart W TSD, available in the docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424).
Based on the EPA's review and analysis, there appears to be combustion slip for all compressor engine types at oil and gas facilities. In addition, while the recent studies are focused on the Onshore Petroleum and Natural Gas Gathering and Boosting industry segment, the EPA's literature review found the presence of combustion slip in different industry segments, so it appears that combustion slip is dependent on the type of engine and not the application (i.e., we expect combustion slip from compressor engines regardless of the industry segment). Therefore, the EPA is proposing to revise the methodologies for determining combustion emissions from compressor engines to account for combustion slip, consistent with section II.A.3 of this preamble. For the three subpart W industry segments that calculate combustion emissions per 40 CFR 98.233(z), we are proposing to accomplish this with two amendments to the calculation methods and the addition of one new reporting requirement. For compressor engines in those subpart W industry segments that combust natural gas and qualify to determine emissions using the subpart C calculation methodologies per 40 CFR 98.233(z)(1) and proposed new 98.233(z)(2), we are proposing that reporters would use subpart-W specific emission factors by engine design class (e.g., 2-stroke lean-burn, 4-stroke lean-burn, 4-stroke rich-burn, or other) in proposed new Table W-8 rather than the emission factors in Table C-2. For compressor engines that combust natural gas and determine emissions per 40 CFR 98.233(z)(2) (proposed to be moved to 40 CFR 98.233(z)(3)), we are proposing updated combustion efficiency value(s) (η) by engine design class to be used in Equations W-39A and W-39B that would reflect combustion slip. We are also proposing to add a reporting requirement to 40 CFR 98.233(z)(2) to specify the design class of reported internal combustion units that are compressor-drivers to facilitate verification of the selected emission factors and efficiencies, as applicable, and the resulting emissions.
In an analogous amendment for the reporters in the other subpart W industry segments that calculate and report combustion emissions under subpart C, we are proposing that they also use subpart W-specific emission factors rather than the emission factors in Table C-2. Currently, these facilities use either Equation C-8, C-8a, C-8b, C-9, C-9a, C-9b, or C-10 in 40 CFR 98.33(c), as it corresponds to the Tier methodology selected to estimate their CO2 emissions, to estimate CH4 emissions. These equations rely on the use of a default CH4 emission factor from Table C-2 to estimate emissions. As described in section III.B of this preamble, the emission factor term definition in each of these equations is proposed to be amended to reference Table W-8 rather than Table C-2 specifically for quantifying emissions from compressor-drivers. We are also proposing to add a footnote to Table C-2 to specify that the default CH4 emission factor should only be used for combustion devices that are not compressor-drivers.
Clarifications of Calculation Methodologies. As noted previously in this section, Onshore Petroleum and Natural Gas Production, Onshore Petroleum and Natural Gas Gathering and Boosting, and Natural Gas Distribution facilities report combustion emissions calculated in accordance with 40 CFR 98.233(z) instead of reporting under subpart C. Stakeholders (e.g., GPA Midstream) have identified several concerns with the requirements in 40 CFR 98.233(z). First, GPA Midstream has indicated that for fuels using the existing provisions of 40 CFR 98.233(z)(2) to calculate emissions, the requirements for determining the gas composition could result in inaccurate calculations of emissions for some facilities. In particular, 40 CFR 98.233(z)(2)(ii) currently specifies that to determine the concentrations of hydrocarbon constituents in the flow of gas to the unit, reporters must either use a continuous gas composition analyzer (if one is present) or the procedures in the applicable paragraph in 40 CFR 98.233(u)(2) of this section. For onshore petroleum and natural gas gathering and boosting facilities, 40 CFR 98.233(u)(2) specifies use of the annual average gas composition based on the most recent available analysis of the gas received at the facility. However, GPA Midstream explained that onshore petroleum and natural gas gathering and boosting facilities do not necessarily use the gas received at their facility for combustion. For example, if the gas received at the facility is not suitable for combustion, they may mix the gas with purchased natural gas. In that case, the annual average composition of gas received at the facility would not be representative of the gas sent to the combustion unit (as required by 40 CFR 98.233(z)(2)), which could result in inaccurate emissions. Therefore, the EPA is proposing to revise the language in 40 CFR 98.233(z)(2)(ii) (proposed to be moved to 40 CFR 98.233(z)(3)(ii)(B)) to allow the use of engineering estimates based on best available data to determine the concentration of gas hydrocarbon constituent in the flow of gas to the unit. This proposed amendment would allow reporters to use the best information available to determine the gas composition while maintaining the option for reporters to use 40 CFR 98.233(u)(2) if they do not have other stream-specific information. In addition to improving the accuracy of the emissions calculated and therefore the quality of data collected, consistent with section II.A.2 of this preamble, this proposed amendment is expected to provide additional flexibility for reporters, consistent with section II.B.2 of this preamble.
Second, GPA Midstream indicated that the existing provisions of 40 CFR 98.233(z)(1)(ii) are unclear and that some member companies have been interpreting those provisions to mean that reporters with combustion sources at onshore petroleum and natural gas production facilities, at onshore petroleum and natural gas gathering and boosting facilities, and at natural gas distribution facilities must use the calculation methodologies in subpart W rather than subpart C (even given the provisions in 40 CFR 98.233(z)(1) that reference subpart C for certain fuels). The existing provisions of 40 CFR 98.233(z)(1)(ii) are intended to refer only to the reporting requirements and are not intended to define which calculation methodologies can be used. In the current rule, the provisions in the 40 CFR 98.233(z)(1) introductory text define which calculation methodologies can be used, and 40 CFR 98.233(z)(1)(ii) simply indicates that all reporters with combustion sources at onshore petroleum and natural gas production facilities, at onshore petroleum and natural gas gathering and boosting facilities, and at natural gas distribution facilities must report those emissions in the e-GGRT system under subpart W rather under subpart C. As part of the amendments described in this section, consistent with section II.A.5 of this preamble, 40 CFR 98.233(z)(1)(ii) is proposed to be moved to 40 CFR 98.233(z)(4), and we are proposing wording changes to be clear that this paragraph refers only to reporting. We are also proposing to add a reference to this new paragraph 40 CFR 98.233(z)(4) in both 40 CFR 98.233(z)(1)(ii) and 98.233(z)(2)(ii) (as proposed to be amended).
o. Leak Detection and Measurement Methods
Acoustic Leak Detection. For emission source types for which measurements are required, subpart W specifies the methods that may be used to make those measurements in 40 CFR 98.234(a). To improve the quality of the data when an acoustic leak detection device is used, consistent with section II.A.2 of this preamble, we are proposing two revisions to the acoustic measurement requirements in 40 CFR 98.234(a)(5). First, for stethoscope type acoustic leak detection devices (i.e., those designed to detect through-valve leakage when put in contact with the valve body and that provide an audible leak signal but do not calculate a leak rate), we are proposing that a leak is detected if an audible leak signal is observed or registered by the device. Second, we are proposing that if a leak is detected using a stethoscope type device, then that leak must be measured using one of the quantification methods specified in 40 CFR 98.234(b) through (d) and that leak measurement must be reported regardless of the volumetric flow rate measured. These proposed revisions would improve the accuracy of emissions reported for compressors and transmission tanks when an acoustic leak detection device is used.
High Volume Samplers. We are proposing two revisions to the high volume sampler methods to improve the quality of the data when high volume samplers are used for flow measurements, consistent with section II.A.2 of this preamble. First, we are proposing to add detail to 40 CFR 98.234(d)(3) to clarify the calculation methods associated with high volume sampler measurements. Generally, high volume samplers measure methane flow, not whole gas flow. However, the current calculation methods in 40 CFR 98.234(d)(3) treat the measurement as a whole gas measurement. Therefore, we are clarifying the calculation methods needed if the high volume sampler outputs methane flow in either a mass flow or volumetric flow basis. Specifically, we are proposing methods to determine natural gas (whole gas) flows based on measured methane flows.
Second, we are proposing to add a paragraph at 40 CFR 98.234(d)(5) to clarify how to assess the capacity limits of a high volume sampler. Currently, 40 CFR 98.234(d) simply states to "Use a high volume sampler to measure emissions within the capacity of the instrument"; there is no other information provided to clarify what "within the capacity of the instrument" means or how it is determined. We understand that there are different manufacturers, but most common high volume samplers report maximum sampling rates of 10 to 11 cubic feet per minute (cfm) and maximum methane flow quantitation limits of 6 to 8 cfm. Based on our review of reported high volume sampler measurements, we found that 2 to 5 percent of high volume sampler measurements for all types of compressor sources (for both centrifugal and reciprocating compressors) are likely at or beyond the expected capacity limits of the high volume sampler instrument. Considering actual sampling rates, gas collection efficiencies near the sampling rates, and reported methane quantitation limits relative to maximum sampling rates, we determined that whole gas flow rates exceeding 70 percent of the device's maximum rated sampling rate is an indication that the device will not accurately quantify the volumetric emissions, which we deem to exceed the capacity of the device. Therefore, we are proposing to specify that methane flows above the manufacturer's methane flow quantitation limit or total volumetric flows exceeding 70 percent of the manufacturer's maximum sampling rate indicate that the flow is beyond the capacity of the instrument and that flow meters or calibrated bags must be used to quantify the flow rate. For more information on our review, see the subpart W TSD, available in the docket for this rulemaking (Docket Id. No EPA-HQ-OAR-2019-0424).
p. Onshore Petroleum and Natural Gas Gathering and Boosting Compressor Stations
The EPA received feedback from GPA Midstream that a count of compressor stations per Onshore Petroleum and Natural Gas Gathering and Boosting facility would provide the EPA with improved data on the number and type of equipment at gathering and boosting stations, which could help to better inform future rulemakings. In addition, the EPA could use information on the count of compressor stations to improve the process of verifying annual reports to the GHGRP. As an example, a facility with high emissions for a particular source type compared to other facilities in the same basin might currently be identified as a potential outlier. However, if the report also indicated that the facility has a large number of compressor stations compared to other facilities, the EPA could use that information during report verification to confirm the high emissions without needing to contact the facility owner or operator. Therefore, the EPA is proposing to add a requirement in 40 CFR 98.236(aa)(10)(v) to report the count of compressor stations for facilities in the Onshore Petroleum and Natural Gas Gathering and Boosting industry segment, consistent with section II.A.4 of this preamble. Additionally, the count of compressor stations per facility would allow for refinements to the activity data used by the U.S. GHG Inventory. In particular, the calculated national-level compressor station activity data used by the U.S. GHG Inventory could be informed by reported compressor station counts for Onshore Petroleum and Natural Gas Gathering and Boosting facilities subject to subpart W, which improves the U.S. GHG Inventory estimate of total national emissions. The EPA is also proposing a definition of "compressor station" in 40 CFR 98.238 to be used for the purposes of this reporting requirement to reduce any potential reporter confusion.
Based on the definition of Onshore Petroleum and Natural Gas Gathering and Boosting industry segment, this industry segment also includes "centralized oil production sites." These are sites that collect oil from multiple well pads but that do not have compressors (i.e., are not "compressor stations"). Therefore, we are proposing to add a requirement in 40 CFR 98.236(aa)(10)(vi) to report the count of centralized oil production sites for facilities in the Onshore Petroleum and Natural Gas Gathering and Boosting industry segment, consistent with section II.A.4 of this preamble. We are also proposing to add a definition of "centralized oil production site" in 40 CFR 98.238 to be used for the purposes of this reporting requirement. These proposed additional data elements would enhance the overall quality of the data collected under the GHGRP.
q. Onshore Natural Gas Transmission Pipeline Throughput Information
Similar to Natural Gas Distribution facilities, Onshore Natural Gas Transmission Pipeline facilities are currently required to report five throughput volumes under subpart W, as specified in 40 CFR 98.236(aa)(11). These five data reporting elements include: the quantity of natural gas received at all custody transfer stations; the quantity of natural gas withdrawn from in-system storage; the quantity of gas added to in-system storage; the quantity of gas transferred to third parties; and the quantity of gas consumed by the transmission pipeline facility for operational purposes. As noted in section III.J.2.g of this preamble, the EPA has received stakeholder comments on the reporting elements for Natural Gas Distribution facilities, including questions submitted to the GHGRP Help Desk, regarding the term "in-system storage." Although the questions were specific to Natural Gas Distribution facilities, the term "in-system storage" is also included in the throughput reporting elements for Onshore Natural Gas Transmission Pipeline facilities at 40 CFR 98.236(aa)(11)(ii) and (iii). After consideration of the stakeholder comments, the EPA is proposing to clarify the term "in-system." Specifically, we are proposing to amend 40 CFR 98.236(aa)(11)(ii) and (iii) to clarify that "in-system" withdrawals/additions of natural gas from storage are specifically referring to Underground Natural Gas Storage and LNG Storage facilities that are owned and operated by the onshore natural gas transmission pipeline owner or operator that do not report under subpart W as direct emitters themselves. These amendments are expected to improve data quality consistent with section II.A.5 of this preamble.
2. Proposed Revisions to Streamline and Improve Implementation for Subpart W
As further described in section II.B of this preamble, we are also proposing amendments to remove, reduce, or simplify requirements that would streamline and improve implementation while maintaining the quality of the data collected under Part 98. To determine which reporting requirements and data elements of subpart W to propose amending, the EPA reviewed correspondence with reporters during the annual verification of GHGRP data, questions submitted to the GHGRP Help Desk and the responses provided, and the specific regulatory language of subpart W. As a result of that process, the EPA is proposing to eliminate, clarify, or otherwise amend select calculation methodologies and reporting requirements as described in this section. Consistent with section II.B.2 of this preamble, some of the proposed amendments would add monitoring or reporting flexibility for certain calculation methodologies. Other proposed revisions would remove reporting requirements that are redundant with data already reported to the EPA or no longer being used at this time, as further described in section II.B.3 of this preamble.
a. Dehydrator Vents
Removal of Requirements for Desiccant Dehydrators. Subpart W currently requires reporting of desiccant dehydrators as a subcategory of dehydrator vents. Based on the data reported to date, the emissions from these sources are less than 0.1 percent of total reported emissions from dehydrator vents (in RY2020, desiccant dehydrators contributed 760 mtCO2e of the total 3.35 million mtCO2e from all dehydrator vent emissions). In addition, it appears that a significant percentage of the emissions reported to date may be from molecular sieve dehydrators; however, we never intended to require reporting of emissions from such units, and based on the definition of "dehydrator" in 40 CFR 98.6, we do not read the rule to require such reporting. In RY2015 through RY2020, about 60 percent of the facilities that reported counts of desiccant dehydrators also reported emissions of 0 mtCO2e (516 out of 897 reporters), and more than one-quarter of the reported desiccant dehydrators were at facilities that reported 0 emissions from desiccant dehydrators (1,888 out of 7,139 units). Furthermore, facilities that report emissions from desiccant dehydrators in a given year may not have depressurized every one of their desiccant dehydrators in that year, but this cannot be determined from the reported data because emissions are reported at the facility level instead of per dehydrator. This pattern of emissions reporting is consistent with the expected results for molecular sieve dehydrators because such units typically are opened (depressurized) only once every few years. Thus, a significant percentage of the reported emissions from desiccant dehydrators may be from units that are not subject to reporting, meaning that the actual emissions from desiccant dehydrators would be less than the reported 0.1 percent of the total dehydrator emissions. Therefore, we are proposing to remove requirements for desiccant dehydrators from 40 CFR 98.233(e)(3) and (4) and 40 CFR 98.236(e)(3) of subpart W, consistent with section II.B.2 and II.B.3 of this preamble. As a corollary to the proposed removal of the desiccant dehydrator requirements, we are also proposing to remove the definition of "desiccant" and to revise the definition of "dehydrator" in 40 CFR 98.6, as discussed in section III.A of this preamble.
As an alternative to removing the requirements for all desiccant dehydrators, we considered revising 40 CFR 98.233(e)(3) to clarify that only devices with desiccant that absorb water (as opposed to those containing materials that adsorb water) are subject to the GHGRP. That change would be consistent with the original intent, as evidenced by the definitions of "desiccant" and "dehydrator" in 40 CFR 98.6, and it would clarify that molecular sieve units (which contain material that adsorbs water) are not subject to subpart W. That change also would reduce the number of reporters. However, we are not proposing that option because the reported emissions would be extremely small relative to other dehydrator emissions. We request comment on other advantages and disadvantages of this option relative to the proposed plan of deleting requirements for desiccant dehydrators and whether commenters think there are potential benefits of this option that outweigh potential drawbacks.
Although this proposal would remove the desiccant dehydrator requirements from subpart W, other requirements in subpart W may then apply instead. Currently, 40 CFR 98.233(e)(3) and 40 CFR 98.233(i) specify that desiccant dehydrator emissions calculated using Equation W-6 do not have to be calculated separately under the blowdown vent stacks provisions in 40 CFR 98.233(i). However, because we are proposing to remove the desiccant dehydrator provisions, the EPA is also proposing to remove the exception at the end of the 40 CFR 98.233(i) introductory paragraph. Thus, the blowdown provisions in 40 CFR 98.233(i) would apply, provided that the volume of space in a desiccant dehydrator that is depressurized to atmosphere is greater than 50 cubic feet. Similarly, in the absence of desiccant dehydrator provisions, if the emissions from depressurizing desiccant dehydrators are routed to a flare, then the emissions would be subject to the requirements for flare stack emissions in 40 CFR 98.233(n). We note that while these emissions may still be reported to the EPA if the proposal to remove the desiccant dehydrator provisions is finalized, they would no longer be required to be calculated and reported separately, which would still streamline implementation for reporters.
Clarification of Count for Glycol Dehydrators with Annual Average Daily Natural Gas Throughput Less Than 0.4 MMscf per Day. As noted in section III.J.1.d of this preamble, for glycol dehydrators with an annual average daily natural gas throughput less than 0.4 MMscf per day, reporters currently use population emission factors and Equation W-5 to calculate volumetric CO2 and CH4 emissions per 40 CFR 98.233(e)(2) and report emissions per 40 CFR 98.236(e)(2). Under these current requirements, the count of glycol dehydrators with annual average daily natural gas throughput less than 0.4 MMscf per day could include dehydrators with annual average daily natural gas throughput of 0 MMscf per day (i.e., glycol dehydrators that were not operated during the reporting year). As a result, some annual reports include a nonzero count of dehydrators per 40 CFR 98.236(e)(2)(i) without any corresponding CO2 and CH4 emissions. In these cases, it is not clear if the reporter did not report emissions because emissions are not expected, the emissions data were inadvertently omitted, or the nonzero count represents the total count of all dehydrators with annual average daily natural gas throughput less than 0.4 MMscf per day, including those that were not in use.
Therefore, the EPA is proposing to clarify in 40 CFR 98.233(e)(2) that the dehydrators for which emissions are calculated should be those with annual average daily natural gas throughput greater than 0 MMscf per day and less than 0.4 MMscf per day (i.e., the count should not include dehydrators that did not operate during the year). Similarly, the EPA is proposing to clarify that the count of dehydrators in 40 CFR 98.236(e)(2)(i) should also be those with annual average daily natural gas throughput greater than 0 MMscf per day and less than 0.4 MMscf per day. These amendments are expected to streamline and improve implementation, consistent with section II.B.3 of this preamble.
b. Blowdown Vent Stacks
Blowdown Equipment Types. Subpart W currently requires reporting of blowdowns either using flow meter measurements (40 CFR 98.233(i)(3)) or using unique physical volume calculations by equipment or event types (40 CFR 98.233(i)(2)). When the Onshore Natural Gas Transmission Pipeline industry segment was added to subpart W in 2015, public commenters indicated that the existing equipment or event types were not appropriate for the new segment, so the EPA developed new equipment or event types that apply only for the Onshore Natural Gas Transmission Pipeline industry segment (80 FR 64275, October 22, 2015). The new equipment or event types were added to the introductory paragraph of 40 CFR 98.233(i)(2), where the existing equipment or event types were already located, resulting in a complex introductory paragraph. Also, both the third sentence and last sentence in 40 CFR 98.233(i)(2) currently read as follows: "If a blowdown event resulted in emissions from multiple equipment types and the emissions cannot be apportioned to the different equipment types, then categorize the blowdown event as the equipment type that represented the largest portion of the emissions for the blowdown event." According to this provision, when a blowdown event consists of emissions from two or more equipment types, the emissions must be apportioned to each applicable equipment type, unless such apportionment is not possible.
The EPA is proposing to move the listings of event types and the apportioning provisions to a new 40 CFR 98.233(i)(2)(iv) so that the introductory paragraph in 40 CFR 98.233(i)(2) would be more concise and provide clearer information regarding which requirements are applicable for each blowdown. Proposed 40 CFR 98.233(i)(2)(iv) includes separate paragraphs for each set of equipment and event type categories and would also provide clearer information regarding the applicable requirements for each industry segment.
Blowdown Temperature and Pressure. In the 2015 amendments to subpart W (80 FR 64262, October 22, 2015), the EPA added the Onshore Petroleum and Natural Gas Gathering and Boosting industry segment and the Onshore Natural Gas Transmission Pipeline industry segment and specified that both industry segments are required to report emissions from blowdown vents. Stakeholders representing the Onshore Petroleum and Natural Gas Gathering and Boosting industry segment provided comments on the proposed rule stating that the proposed definition of facility would make equipment geographically dispersed, and blowdowns may occur without personnel on-site or nearby, which would make it difficult to collect the information needed to calculate emissions from each blowdown (80 FR 64271, October 22, 2015). As a result of those comments, the EPA also specified in the final amendments to Equation W-14A that for emergency blowdowns at onshore petroleum and natural gas gathering and boosting facilities, engineering estimates based on best available information may be used to determine the actual temperature and actual pressure.
Since that time, the EPA has received questions through the GHGRP Help Desk indicating that facilities in the Onshore Natural Gas Transmission Pipeline industry segment also have unmanned blowdown vents. Given that a "facility with respect to the onshore natural gas transmission pipeline segment" is the total mileage of natural gas transmission pipelines owned and operated by an onshore natural gas transmission pipeline owner or operator, all of the blowdown vents at that facility would be outside the fenceline of a transmission compression station and would be geographically dispersed. The EPA considers it reasonable to assume that those blowdown vents may also be unmanned. Therefore, we are proposing to extend the provisions in Equation W-14A of 40 CFR 98.233(i)(2)(i) that allow use of engineering estimates based on best available information to determine the temperature and pressure of an emergency blowdown to the Onshore Natural Gas Transmission Pipeline segment, which would align the requirements for the two geographically dispersed industry segments (Onshore Natural Gas Transmission Pipeline and Onshore Petroleum and Natural Gas Gathering and Boosting) and increase flexibility for Onshore Natural Gas Transmission Pipeline reporters, consistent with section II.B.2 of this preamble.
In addition, similar provisions to allow use of engineering estimates based on best available information to determine the temperature and pressure of an emergency blowdown were not added to Equation W-14B of 40 CFR 98.233(i)(2)(i) in 2015 (80 FR 64262, October 22, 2015). We have reviewed this equation and have determined that this omission was inadvertent. Therefore, we are proposing to add provisions to Equation W-14B to allow use of engineering estimates to determine the temperature and pressure of an emergency blowdown for both the Onshore Natural Gas Transmission Pipeline and Onshore Petroleum and Natural Gas Gathering and Boosting industry segments, consistent with Equation W-14A.
c. Atmospheric Storage Tanks
Calculation Methods 1 and 2 Reporting. For facilities reporting atmospheric storage tank emissions calculated using Calculation Method 1 or Calculation Method 2, 40 CFR 98.236(j)(1) requires reporting of counts of the total number of atmospheric storage tanks within the sub-basin or county, the number of atmospheric storage tanks that are controlled by a vapor recovery system, the number of atmospheric storage tanks that are controlled by a flare, and the number of atmospheric storage tanks that are not controlled by either a vapor recovery system or a flare. As atmospheric storage tanks are typically controlled by both a vapor recovery system and a flare, these counts allow for overlap and cause confusion among reporters. Additionally, atmospheric storage tanks may be included in multiple categories of counts if the facility elects to add an emissions control partway through the reporting year.
Therefore, the EPA is proposing to reorganize the reporting requirements in 40 CFR 98.236(j)(1) to reduce overlap between several of the current data elements that are reported by control methodology. Specifically, the EPA is proposing to collect only the total number of tanks within the sub-basin or county, the count of atmospheric tanks that routed emissions to vapor recovery and/or flares at any point during the reporting year, and the count of atmospheric tanks that vented gas directly to the atmosphere and did not control emissions using a vapor recovery system or flares at any point during the reporting year.
For consistency with the revisions to the atmospheric storage tank count data elements, the EPA is proposing to require separate reporting of emissions for tanks that did not control emissions using a vapor recovery system or flares at any point during the reporting year and for tanks that routed emissions to vapor recovery and/or flares at any point during the reporting year. For tanks that do not control emissions using a vapor recovery system or flares at any point during the reporting year, facilities would report CO2 and CH4 emissions resulting from venting gas directly to the atmosphere. For tanks that rout emissions to vapor recovery and/or flares at any point during the reporting year, facilities would report CO2, CH4, and N2O emissions from flares and the total mass of CO2 and CH4 that was recovered using a vapor recovery system in addition to the CO2 and CH4 emissions resulting from venting gas directly to the atmosphere. With this reorganization of the emissions reporting requirements for atmospheric storage tanks, the EPA expects to streamline reporting and reduce redundancy between data elements, consistent with section II.B.3 of this preamble.
Additionally, the EPA is proposing to remove the requirement to report an estimate of the number of atmospheric storage tanks that are not on well-pads and that are receiving the facility's oil (40 CFR 98.236(j)(1)(xi)), consistent with section II.B.3 of this preamble. This reporting requirement is redundant because all Onshore Petroleum and Natural Gas Production facilities reporting atmospheric storage tank emissions calculated using Calculation Method 1 or Calculation Method 2 must also report the total number of atmospheric tanks in the sub-basin per 40 CFR 98.236(j)(1)(x).
Calculation Method 3 Reporting. For hydrocarbon liquids flowing to gas-liquid separators or non-separator equipment or directly to atmospheric storage tanks with throughput less than 10 barrels per day, reporters follow the Calculation Method 3 methodology specified in 40 CFR 98.233(j)(3) and Equation W-15. Equation W-15 uses population emission factors and the count of applicable separators, wells, or non-separator equipment to determine the annual total volumetric GHG emissions at standard conditions. The associated reporting requirements in 40 CFR 98.236(j)(2)(i)(E) through (F) require reporters to delineate the count used in Equation W-15 into the number of wells with gas-liquid separators in the basin and those without gas-liquid separators. The EPA has received feedback through correspondence with reporters via e-GGRT that these reporting requirements are unclear. After consideration of this feedback, the EPA has made a preliminary determination that these reporting requirements are not consistent with the language used in the definition of the "Count" variable in Equation W-15, nor are they inclusive of all equipment to be included in the count.
Therefore, the EPA is proposing to revise 40 CFR 98.236(j)(2)(i)(E) to completely align the requirement with the total "Count" input variable in Equation W-15. The EPA proposes to amend the language in 40 CFR 98.236(j)(2)(i)(E) to request the total number of separators, wells, or non-separator equipment in the basin used to calculate Calculation Method 3 storage tank emissions. The current language in 40 CFR 98.236(j)(2)(i)(E) requests the number of wells with gas-liquid separators in the basin, which is only a subset of the equipment included in the "Count" variable. Further, the EPA is proposing to remove the reporting requirement in 40 CFR 98.236(j)(2)(i)(F), which requires reporting of the number of wells without gas-liquid separators in the basin. Both of the current data elements in 40 CFR 98.236(j)(2)(i)(E) and 40 CFR 98.236(j)(2)(i)(F) have been determined to be no longer as useful for present program or policy purposes, as they do not correlate with the calculated Calculation Method 3 atmospheric tank emissions. These changes would streamline the requirements for all facilities reporting atmospheric storage tanks emissions using Calculation Method 3. Consistent with section II.B.3 of this preamble, reporters would no longer be required to determine two separate counts that may not be representative of the inputs used in Equation W-15.
In addition, the provisions in 40 CFR 98.236(j)(2)(ii) and (iii) require facilities to separately report Calculation Method 3 emissions from atmospheric storage tanks that did not control emissions with flares and those that controlled emissions with flares, respectively. Using the calculation procedures provided in 40 CFR 98.233(j)(3) through (5), when a facility adds a flare control to an atmospheric storage tank in the middle of a reporting year, facilities are required to separately calculate emissions that are not flared from emissions that are flared from that tank, sum these emissions values, and report all emissions from the tank as part of the sub-basin or county flared tanks total per the requirements of 40 CFR 98.236(j)(2)(iii). In an effort to streamline and improve implementation consistent with section II.B.2 of this preamble, the EPA is proposing to clarify that for storage tanks using Calculation Method 3, reporters would calculate either flared or vented emissions for a tank, but not both. Specifically, the EPA is proposing to add language in 40 CFR 98.233(j)(5) that specifies that if the flare captured flash gas from at least half of the annual hydrocarbon liquids received by the tank for which emissions were calculated using Calculation Method 3, flared emissions would be calculated according to 40 CFR 98.233(j)(5) (i.e., as if all flash gas generated from a tank during the entire reporting year is sent to a flare). The EPA is also proposing to amend 40 CFR 98.236(j)(2)(iii) to specify that the reporting requirements in that section only apply to tanks whose emissions were calculated using Calculation Method 3 that used flares to control emissions from at least half the annual hydrocarbon liquids received. The EPA is proposing a corresponding change to 40 CFR 98.236(j)(2)(ii), which would require reporting of the Calculation Method 3 emissions from the remaining atmospheric storage tanks that either used flares to control emissions from less than half the annual hydrocarbon liquids received or did not control any emissions with a flare. The emissions from these remaining atmospheric storage tanks would be calculated as venting directly to the atmosphere for the entire year (i.e., emissions from tanks that flared for less than half of the year would not be calculated using the flare procedures provided in 40 CFR 98.233(j)(5)).
d. Flared Transmission Storage Tank Vent Emissions
Reporters in the transmission compression industry segment currently are required to report flared emissions specific to their transmission storage tanks separately from other flare stack emissions. In the years RY2015 through RY2020, between one and six facilities per year reported having a transmission tank vent stack routed to a flare, and each of these facilities reported no leaks. As a result, the reported flared emissions from transmission storage tank vent stacks in each of the last 6 years have been 0 metric tons of CO2, CH4, and N2O. Based on these results, the EPA has made a preliminary determination that continued reporting of source-specific flared emissions from transmission tanks would not likely provide new insights or knowledge of the industry sector, emissions, or trends. Therefore, consistent with section II.B.3 of this preamble, the EPA is proposing that transmission tanks be classified as a miscellaneous flared source such that any flared emissions from the tanks in the future would be reported collectively with flared emissions from all miscellaneous flared sources as specified in 40 CFR 98.236(n)(1). The EPA is proposing to retain the current requirements in 40 CFR 98.233(k)(1) and (2) to monitor the tank vent stack annually for leaks and to quantify the leak rate if a leak is detected. As an alternative to these source-specific requirements, a reporter also would be allowed to continuously measure either total flow from the transmission tank vent stack or the comingled total flow into the flare, consistent with the existing requirement in 40 CFR 98.233(n)(1). Flow data determined by either of these methods would still be needed to calculate total flared emissions from the miscellaneous flared sources. Reporting requirements would remain essentially the same except that flared mass emissions would no longer be reported under 40 CFR 98.236(k)(3). Note that if we decide not to finalize the proposed changes described in this section after considering public comment, then we alternatively propose that we would finalize flare activity data reporting requirements for flared emissions from transmission storage tank vent stacks consistent with the activity data reporting for other source types that have source-specific flared emissions reporting requirements as described in the "Calculation Methodology for Flared Emissions" subsection in section III.J.1.i of this preamble. The proposed rule language under this alternative would be added to 40 CFR 98.233(k)(5), and it would be similar to proposed language for other flared sources (e.g., well testing in 40 CFR 98.233(l)(6) and associated gas flaring in 40 CFR 98.233(m)(5)). One difference is that an option to continuously measure combined streams into a flare would not be allowed for transmission tanks because it would not be possible to tell if there were any scrubber dump valve leaks if only a combined emissions stream is measured. We request comment on the advantages and disadvantages of both approaches we are considering relative to the current requirements.
e. Compressors
As noted in section III.J.1.j of this preamble, reporting requirements for compressors in the Onshore Natural Gas Processing, Onshore Natural Gas Transmission Compression, Underground Natural Gas Storage, LNG Storage, and LNG Import and Export Equipment industry segments include requirements to conduct "as found" measurements for the compressor mode-source combination in which the compressor is found. In addition, if a given compressor was not measured in not-operating-depressurized-mode during the "as found" measurements for three consecutive years, a measurement in not-operating-depressurized-mode is currently required to be taken during the next planned scheduled shutdown of the compressor, per 40 CFR 98.233(o)(1)(i)(C) and (p)(1)(i)(D). This provision requires reporters to schedule an extra "as found" measurement to make this required measurement if the compressor was not found in this mode when the regularly scheduled "as found" measurements were taken.
We are proposing to eliminate this requirement to conduct a measurement in not-operating-depressurized-mode at least once every three years, consistent with section II.B.2 of this preamble. We originally included this requirement in subpart W in order to obtain a sufficient amount of data for this mode (75 FR 74458, November 30, 2010). However, based on data collected under subpart W thus far, many compressors are in not-operating-depressurized-mode for 30 percent of the time or more. As such, the extra measurements are unnecessary, and we are proposing to eliminate this requirement and make the annual "as found" measurements true "as found" measurements. We are also proposing to remove the reporting requirement to indicate if the compressor had a scheduled depressurized shutdown during the reporting year (40 CFR 98.236(o)(1)(xiv) and 40 CFR 98.236(p)(1)(xiv)) because that information is only collected to verify compliance with the requirement to conduct a measurement in not-operating-depressurized-mode at least once every three years.
In addition, centrifugal and reciprocating compressors are the only sources for which capture for fuel use and thermal oxidizers are specifically listed as dispositions for emissions that would otherwise be vented. The EPA's intent with the provisions is to differentiate flares, which are combustion devices that combust waste gases without energy recovery (per 40 CFR 98.238), from combustion devices with energy recovery, including for fuel use. However, some thermal oxidizers combust waste gases without energy recovery and therefore may instead meet the subpart W definition of flare. To avoid confusion, and to clarify that the EPA's intent is generally to treat emissions routed to flares and combustion devices other flares consistently, we are proposing to remove the references to fuel use and to thermal oxidizers in 40 CFR 98.233(o) and (p) and 40 CFR 98.236(o) and (p). Instead, we are proposing to define "routed to combustion" in 40 CFR 98.238 to specify the types of non-flare combustion equipment for which reporters would be expected to calculate emissions. In particular, for the Onshore Petroleum and Natural Gas Production, Onshore Petroleum and Natural Gas Gathering and Boosting, and Natural Gas Distribution industry segments, "routed to combustion" means the combustion equipment specified in 40 CFR 98.232(c)(22), (i)(7), and (j)(12), respectively (i.e., the combustion equipment for which emissions must be calculated per 40 CFR 98.233(z)). For all other industry segments, "routed to combustion" means the stationary combustion sources subject to subpart C. The proposed definition of "routed to combustion" would apply for all subpart W emission sources for which that term appears (e.g., natural gas driven pneumatic pumps).
Finally, we are proposing to remove some data elements that are redundant between 40 CFR 98.236(o)(1) and (2) for centrifugal compressors and between 40 CFR 98.236(p)(1) and (2) for reciprocating compressors. Specifically, 40 CFR 98.236(o)(1)(vi) and 40 CFR 98.236(p)(1)(vi) require reporters to indicate which individual compressors are part of a manifolded group of compressor sources, and 40 CFR 98.236(o)(1)(vii) through (ix) and 40 CFR 98.236(p)(1)(vii) through (ix) require reporters to indicate whether individual compressors have compressor sources routed to flares, vapor recovery, or combustion. However, 40 CFR 98.236(o)(2)(ii)(A) and 40 CFR 98.236(p)(2)(ii)(A) require the same information for each compressor leak or vent rather than by compressor. The information collected for each leak or vent is more detailed and is the information used for emissions calculations. Therefore, the EPA is proposing to remove the redundant reporting requirements in 40 CFR 98.236(o)(1)(vi) through (ix) and 40 CFR 98.236(p)(1)(vi) through (ix), consistent with section II.B.3 of this preamble.
f. Combustion
Subpart W refers reporters in the Onshore Petroleum and Natural Gas Production, Onshore Petroleum and Natural Gas Gathering and Boosting, and Natural Gas Distribution industry segments to the calculation methodologies in subpart C to determine combustion emissions for certain fuels. Specifically, 40 CFR 98.233(z)(1) specifies that reporters may use any tier of subpart C if the fuel combusted is listed in Table C-1; the paragraph further specifies that the subpart C methodologies may only be used for fuel meeting the definition of "natural gas" in 40 CFR 98.238 if it is also of pipeline quality specification and has a minimum HHV of 950 Btu per standard cubic foot (Btu/scf). If the fuel is natural gas that does not meet these criteria, field gas, process vent gas, or a blend containing field gas or process vent gas, 40 CFR 98.233(z)(1) specifies that the procedures in 40 CFR 98.233(z)(2) should be used to calculate combustion emissions. Stakeholders (e.g., GPA Midstream) have identified several concerns with these requirements. In general, they have stated that the ability to use subpart C calculation methodologies is unclear and too restrictive. We are proposing several amendments to these provisions to address these concerns and increase the flexibility of the calculation methods, consistent with section II.B.2 of this preamble.
First, GPA Midstream has indicated that it is not clear whether field gas that is of pipeline quality meets the criteria to use the subpart C methodologies under 40 CFR 98.233(z)(1), and "field gas" is not defined within subpart W or subpart A (General Provisions). The terms "field gas" and "field quality" are frequently used interchangeably by the industry, but the EPA also recognizes that some streams in the Onshore Petroleum and Natural Gas Gathering and Boosting industry segment that industry would generally call "field gas" can be natural gas (as defined in 40 CFR 98.238) of pipeline quality with a minimum HHV of 950 Btu/scf. GPA Midstream stated that the procedures in 40 CFR 98.233(z)(2) are more burdensome than the subpart C methodologies and asked that the EPA clarify that "field gas" streams of pipeline quality can use the subpart C methodologies. After review of these comments, the EPA is proposing to revise 40 CFR 98.233(z)(1) to remove the references to field gas and process vent gas and include only the characteristics for the fuels that can use subpart C methodologies. The EPA's intent is to clarify that a stream colloquially referred to as "field gas" that otherwise meets the three criteria to use the subpart C methodologies for combustion emissions (i.e., (1) meets the definition of "natural gas" in 40 CFR 98.238; (2) is of pipeline quality specification; and (3) has a minimum HHV of 950 Btu/scf) may use subpart C methodologies. The EPA is also proposing conforming edits to 40 CFR 98.233(z)(2) (proposed to be moved to 40 CFR 98.233(z)(3)) for consistency.
Second, reporters have indicated in questions submitted to the GHGRP Help Desk that the term "pipeline quality" is also not defined in subpart W, leading to confusion over whether some fuel streams meet the criteria to use the subpart C calculation methodologies per 40 CFR 98.233(z)(1). In addition, GPA Midstream has opined that the emissions calculated using subpart C and subpart W calculation methodologies are similar for many fuel streams that are not natural gas of pipeline quality specification with a minimum HHV of 950 Btu/scf. Therefore, they have suggested that the EPA should allow subpart C calculation methodologies to be used for a wider variety of fuels (if not all fuels in the segments that report combustion emissions under subpart W).
We have reviewed the analysis in GPA Midstream's May 18, 2016 letter and conducted our own analysis of additional hypothetical fuel compositions. In general, we observed that the agreement of emissions as calculated using subpart C calculation methodologies for natural gas and using subpart W calculation methodologies varies based on the composition, with the largest differences resulting for fuel streams with high CO2 content. We also observed that for these fuels, emissions calculated using subpart W calculation methodologies generally showed better agreement with emissions calculated using the subpart C calculation methodology for natural gas when using a site-specific HHV (Tier 2) than with emissions calculated using the subpart C calculation methodology that uses a default HHV (Tier 1). For more information on our fuel composition analysis and the comparison of emissions using various composition thresholds, see the subpart W TSD, available in the docket for this rulemaking (Docket Id. No EPA-HQ-OAR-2019-0424).
Based on our analysis, we are proposing to add numeric composition thresholds for natural gas to a new paragraph in 40 CFR 98.233(z)(2) that define the fuels for which an owner or operator may use subpart C methodologies. In particular, we are proposing that subpart C methodologies Tier 2 or higher may be used for fuel meeting the definition of "natural gas" in 40 CFR 98.238 if it has a minimum HHV of 950 Btu/scf, a maximum CO2 content of 1 percent by volume, and a minimum CH4 content of 85 percent by volume. We are not proposing to amend the existing provisions in 40 CFR 98.233(z)(1) that allow the use of any subpart C calculation methodology for natural gas of pipeline quality specification with a minimum HHV of 950 Btu/scf (with the clarifications noted earlier in this section). We are also proposing to move the existing provisions for fuels that do not meet the specifications to use subpart C methodologies from 40 CFR 98.233(z)(2) to a new paragraph 40 CFR 98.233(z)(3). This proposed amendment would allow reporters to use subpart C methodologies for a wider variety of fuel streams while still ensuring data quality. We request comment on the natural gas specifications included in proposed 40 CFR 98.233(z)(2), including the values proposed for the maximum CO2 content and minimum CH4 content, as well as whether additional specification criteria should be included (e.g., a maximum HHV).
Third, we are proposing amendments to clarify that emissions may be calculated in 40 CFR 98.233(z)(3)(ii) for groups of combustion units. The current provisions of 40 CFR 98.233(z)(2) (proposed to be moved to 40 CFR 98.233(z)(3)(ii)) could be interpreted to specify that emissions must be calculated for each individual combustion unit. However, because combustion emissions and activity data are reported as combined totals for each type of combustion device and fuel, it is not necessary to calculate emissions for each individual unit before aggregating the total emissions. For example, if the volume of fuel combusted is determined at a single location upstream of several combustion units with similar combustion efficiencies, emissions may be determined for that combined volume of fuel (i.e., for that group of combustion units). In other words, it is not necessary in this case to apportion a volume of fuel to each unit, calculate emissions separately, and then combine them again. If the combustion units downstream of this shared measurement point are a mix of combustion device types, the emissions and the volume of fuel would still need to be apportioned between those combustion device types for reporting purposes; however, reporters may elect to perform that apportioning either before or after emissions are calculated, as appropriate, as long as the group of combustion units does not include any natural gas-driven compressor drivers. If any of the combustion units downstream of this shared measurement point are natural gas-driven compressor drivers, the volumes of fuel for those units would have to be separated from the total before emissions are calculated to account for the differences in combustion efficiency, as described in section III.J.1.n of this preamble.
g. Onshore Natural Gas Processing and Natural Gas Distribution Throughput Information
Onshore Natural Gas Processing plants are required to report seven facility-level throughput-related items under subpart W, as specified in 40 CFR 98.236(aa)(3). These seven data reporting elements include: quantities of natural gas received and processed gas leaving the gas processing plant, cumulative quantities of NGLs received and leaving the gas processing plant, the average mole fractions of CH4 and CO2 in the natural gas received, and an indication of whether the facility fractionates NGLs. Natural Gas Distribution companies are also required to report seven throughput volumes under subpart W, as specified in 40 CFR 98.236(aa)(9). These seven data reporting elements include: the quantity of gas received at all custody transfer stations; the quantity of natural gas withdrawn from in-system storage; the quantity of gas added to in-system storage; the quantity of gas delivered to end users; the quantity of gas transferred to third parties; the quantity of gas consumed by the LDC for operational purposes; and the quantity of gas stolen.
The EPA has received stakeholder comments, including from the American Gas Association (AGA), related to some of these reporting elements. Stakeholders have commented that the reporting elements included in subpart W are redundant with data reported elsewhere within the GHGRP, specifically under subpart NN (Suppliers of Natural Gas and Natural Gas Liquids). Subpart NN requires NGL fractionators and LDCs to report the quantities of natural gas and natural gas liquid products supplied downstream and their associated emissions. For example, for natural gas processing plants, both subparts require reporting of the volume of natural gas received and the volume of NGL received. Subpart W also requires reporting of total NGL leaving the processing plant, while subpart NN requires reporting of the volume of each individual NGL product supplied. For LDCs, some duplicative reporting is required as well. For example, both subparts require reporting of the volume of natural gas received, volume placed into and out of storage each year, and volume transferred to other LDCs or to a pipeline as well as some other duplicative data. In addition, commenters stated that the reporting elements included in subparts W and NN for LDCs are redundant with data reported to the U.S. Energy Information Administration (EIA) on Form EIA-176, the Annual Report of Natural and Supplemental Gas Supply and Disposition. The commenters explained that subpart W and subpart NN collect nearly the same data, and discrepancies between the data sets are due to the use of inconsistent terminology. Commenters also suggested that due to the redundancy and availability of data reported to the EIA for LDCs, the EPA should remove the throughput-related reporting requirements for the Natural Gas Distribution industry segment from the GHGRP altogether. Commenters added that if the requirements are maintained, the EPA should reconcile the terminology used within the GHGRP and clarify the reporting elements.
The EIA report is submitted in the spring of each year and covers the previous calendar year. After completing internal audits of the reports, EIA publishes the data for each LDC on its website in the fall. The EIA data provides detailed information on the volume of gas received, gas stored, gas removed from storage, gas deliveries by sector, and HHV data. The EPA previously reviewed the possibility of obtaining data by accessing existing federal government reporting and "decided not to modify the final rule because collecting data directly in a central system will enable the EPA to electronically verify all data reported under this rule quickly and consistently, to use the information for non-statistical purposes, and to handle confidential business information in accordance with the Clean Air Act." In the specific case of subpart NN, in the 2009 Final Rule, the EPA also "determined that it could not rely on EIA data to collect facility-level data from fractionators and company-level data from LDCs." Additionally, the EPA sought "data that is beyond what EIA collects, such as quality assurance information, verification data, and information on odorized propane" and "data on site-specific HHV and carbon content from those sites that choose to sample and test products rather than use default emission factors."