For the reasons described in section II.B.3 of this preamble, we are proposing to revise the frequency and applicability of the technology assessment report requirements in 40 CFR 98.96(y), which applies to semiconductor manufacturing facilities with GHG emissions from subpart I processes greater than 40,000 mtCO2e per year. (Other proposed changes to 40 CFR 98.96(y) are discussed in section III.E.1 of this preamble.) The purpose of the technology assessment report is to provide regular review of technology changes in the semiconductor manufacturing industry and ensure that default gas utilization rates, by-product formation rates, and DRE values accurately reflect changes in the industry's practices, such as the introduction of manufacturing on 450-mm sized wafers. In the 2012 proposed amendments to subpart I (77 FR 63538, October 16, 2020), we noted that the semiconductor manufacturing industry had historically been "fast-evolving, achieving exponentially increasing processor speeds and improving manufacturing efficiencies through the rapid adoption of new manufacturing processes" (see 77 FR 63565). At that time the EPA had identified the potential introduction of 450 mm wafer technology, as well as other new process technologies that could affect emissions. Therefore, we considered a three-year report appropriate for collecting information on changes in the semiconductor industry that would potentially affect emissions. However, following submission and review of the first three-year reports, we have determined that industrial advancements are occurring at a slower pace. As such, we are proposing to amend 40 CFR 98.96(y) to decrease the frequency of submission of the reports from every three years to every five years. Under the current rule, semiconductor manufacturing facilities are required to submit their next technology assessment report by March 31[st], 2023 (concurrent with their RY2022 annual report). This proposed revision would affect the due date for that technology assessment, moving the due date from March 31, 2023, to March 31, 2025. Our review of the technology assessment reports submitted for RY2016 and RY2019 did not find significant technology changes within the industry over the three years the reports covered. Based on an assessment of the RY2016 and RY2019 reports (CBI memorandum, Review of 2017 Subpart I Triennial Reports Submitted by the Electronics Industry (Transcarbon International, 2017, available in the docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424) gas emissions and wafer size data that have been submitted to e-GGRT in annual reports, and information gathered from outside sources (summarized in a literature review, Memorandum: Review of trade and scientific publications to identify significant recent changes in technologies and gas usage in electronic devices manufacturing, prepared by Sébastien Raoux, Transcarbon International, and Brian Palmer, Eastern Research Group, Inc. (April 3, 2017), available in the docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424), we believe that a five-year period would provide updates to the EPA more in line with the pace of technological change within the semiconductor industry. Revising the frequency of submission to every five years would increase the likelihood that reports will include updates in technology rather than conclusions that technology has not changed. Because we have found that changes within the industry have been incorporated at a slower pace and do not anticipate significant changes in technology on a three-year frequency, the proposal to require submission of these reports on a five-year frequency would likely not significantly affect the quality of the data available annually in the GHGRP.
Second, we are proposing to revise the applicability of 40 CFR 98.96(y). Currently, any facility with emissions greater than 40,000 mtCO2e in their most recently submitted emissions report must submit a technology assessment report, including facilities manufacturing devices only using wafer sizes smaller than 200 mm (e.g., 150 mm). Because the focus of the technology assessment report is on semiconductor manufacturing using 200-mm, 300-mm, and potentially 450-mm wafers (see 40 CFR 98.96(y)(2)(i)-(iii)), we are proposing to restrict the reporting requirement in 40 CFR 98.96(y) to facilities that emitted greater than 40,000 mtCO2e and produced wafer sizes greater than 150 mm (i.e., 200 mm or larger) during the period covered by the technology assessment report. We are also proposing to explicitly state that semiconductor manufacturing facilities that manufacture only 150-mm or smaller wafers are not required to prepare and submit a technology assessment report. The applicability of 40 CFR 98.96(y) is currently based on the emissions in a facility's most recently submitted report (typically the emissions occurring in the second-to-last year covered in the technology assessment report, e.g., RY2022 emissions for the technology reports that would be submitted in 2023). However, because facilities that cease all operations related to subpart I are eligible to discontinue reporting under 40 CFR 98.2(i)(3), we are also proposing to further revise the applicability of 40 CR 98.96(y) to clarify that a technology assessment report need not be submitted by a facility that has ceased (and has not resumed) semiconductor manufacturing before the last reporting year covered by the technology assessment report (i.e., no manufacturing at the facility for the entirety of the year immediately before the year during which the technology assessment report is due). For example, if a facility manufacturing on 300-mm wafers exceeded the 40,000 mtCO2e threshold in 2023 but ceased operations in December of that year and has not since then resumed operations, that facility would not be required to submit a technology assessment report in March of 2025.
F. Subpart N  --  Glass Production
For the reasons described in section II.A.4 of this preamble, we are proposing two revisions to the recordkeeping and reporting requirements of subpart N of Part 98 (Glass Production) to enhance the quality and accuracy of the data collected under the GHGRP. Subpart N currently requires calculation of CO2 emissions using one of two methodologies, either direct measurement using CEMS, or a mass balance methodology based on mass, carbonate content, and fraction of calcination for each carbonate-based input material. For each option, reporters are required to provide the annual quantities of glass produced from each glass melting furnace, and the annual quantities of glass produced from all furnaces combined. The annual quantities of glass produced have been used historically in verification of reported emissions under the GHGRP for comparison to, and to check for temporal consistency with, carbonate content data and emissions estimates provided by facilities. Facilities also maintain records of monthly glass production rate for each glass furnace. We are proposing to revise the existing reporting and recordkeeping requirements for both CEMS and non-CEMS reporters to require that facilities report and maintain records of annual glass production by glass type. Specifically, we are proposing to revise 40 CFR 98.146(a)(2) and (b)(3) to require the annual quantity of glass produced in tons, by glass type, from each continuous glass melting furnace and from all furnaces combined, and the annual quantity of glass produced in tons, by glass type, from each continuous glass melting furnace and from all furnaces combined. The major raw materials (i.e., fluxes and stabilizers) that emit process-related CO2 emissions in glass production are limestone, dolomite, and soda ash, though there are variations in ingredients and other carbonates may be used in smaller quantities. In general, the composition profile of raw materials is relatively consistent among individual glass types (e.g., container, flat glass, fiber glass, specialty glass), however, some facilities make use of recycled glass in their production process. Differences in the use of recycled material, and other factors, lead to differences in emissions from the production of different glass types. The annual quantities of glass produced by type would provide a useful metric for understanding variations and differences in emissions estimates that may not be apparent in the existing annual production data collected, improve our understanding of industry trends, and improve verification for the GHGRP. The proposed data elements would also provide useful information to improve analysis of this sector in the U.S. GHG Inventory. As noted in the 2019 U.S. GHG Inventory report, the EPA reviews the GHGRP data in the development of inventory estimates for this sector to help understand the completeness of emission estimates and for quality control. Including glass product type would increase the transparency of the data set produced by the Inventory. In addition to the proposed reporting of these data elements, we are proposing harmonizing revisions in 40 CFR 98.147(a)(1) and (b)(1), to add that records must also be kept on the basis of glass type.
We do not anticipate that the proposed data elements would require any additional monitoring or data collection by reporters, as annual production data by glass type is likely available in existing company records. The proposed changes would therefore result in minimal additional burden to reporters. We are also proposing related confidentiality determinations for the additional data elements, as discussed in section VI of this preamble.
G. Subpart P  --  Hydrogen Production
1. Proposed Revisions to Improve the Quality of Data Collected for Subpart P
As discussed in section II.A of this preamble, we are proposing several amendments to enhance the quality of the data collected under subpart P of Part 98 (Hydrogen Production).
Subpart P estimates CO2 emissions from hydrogen production units using a carbon mass balance along with an assumption that all carbon is transformed to CO2 and is emitted from the hydrogen production process. This assumption is reasonable for the majority of hydrogen production units because these facilities produce hydrogen using either steam methane reforming or partial oxidation, followed by a water-gas-shift reaction. The first step (steam methane reforming or partial oxidation) produces a mixture of carbon monoxide (CO) and hydrogen, commonly referred to as syngas. The water gas shift reaction uses water to react with the CO in the syngas to produce CO2 and additional hydrogen. While the majority of hydrogen production units use the water-gas-shift reaction, some facilities only produce syngas as their product. Some facilities may also intentionally produce methanol as a product of these reactions. In these cases, the assumption that 100 percent of the carbon used in the process is converted to CO2 and thus are direct CO2 emissions from hydrogen production units is inaccurate.
As noted in section III.C of this preamble for subpart G (Ammonia Manufacturing), TFI has commented numerous times regarding its view of the lack of a true mass balance for subpart G. In several of their comments (specifically, TFI's Comments on the Proposed "2013 Revisions to the Greenhouse Gas Reporting Rule and Proposed Confidentiality Determinations for New or Substantially Revised Data Elements," May 2, 2013, and Comments on the Proposed "2015 Revisions and Confidentiality Determinations for Data Elements under the Greenhouse Gas Reporting Rule," March 30, 2016),[,] TFI stated that subpart P lacked a true mass balance because the emissions calculation methodology in 40 CFR 98.163 does not account for carbon that is bound in methanol or other by-products of the process and therefore is not emitted as CO2. TFI pointed out that subpart P requires reporting of methanol that is intentionally produced and "carbon other than CO2" that is transferred off site, but that the emissions calculation methodology in 40 CFR 98.163 still assumes that 100 percent of the carbon is emitted as CO2 because the mass balance equations do not subtract out the carbon that leaves the facility as methanol or another product.
Syngas is used as a feedstock for chemical production, most commonly to produce methanol. Carbon transformed into methanol or other chemicals are not emitted as CO2 unless the syngas is used directly as fuel. For fuel combustion units other than the hydrogen process units, and to which subpart C (General Stationary Fuel Combustion Sources) applies, the CO2 emissions from syngas combustion would be reported under subpart C of Part 98. In considering TFI comments, as noted in the preamble to the November 2013 amendments (78 FR 71935), we considered both the emissions from the production processes and consistency with the reporting requirements for other subparts. We note that subpart X (Petrochemical Production) uses a more direct mass balance approach in that carbon contained in produced products (e.g., ethylene) is subtracted from the carbon contained in feedstocks to calculate CO2 emissions. The EPA has tentatively concluded that requiring reporters subject to subpart P to report net CO2 process emissions after subtracting out carbon contained in other products would provide a more accurate estimate of the direct GHG emissions from these processes and would provide consistency in our approach across the GHGRP. Therefore, the EPA is proposing to amend subpart P to allow the subtraction of carbon contained in products other than CO2 (excluding methanol) and the carbon contained in methanol from the carbon mass balance used to estimate CO2 emissions. The proposed revisions would add new paragraph 40 CFR 98.163(d) to allow facilities to adjust the calculated emissions from fuel and feedstock consumption to subtract the mass of both non-CO2 carbon (excluding methanol) and carbon contained in the intentionally produced methanol in order to calculate net CO2 process emissions. We are also proposing harmonizing revisions to the introductory paragraph of 40 CFR 98.163 and 40 CFR 98.163(b).
In conjunction with adding the new paragraph to 40 CFR 98.163(d), we are proposing a clarifying revision to the reporting requirements at 40 CFR 98.166(b)(1) to specify that the annual CO2 emissions may be determined in accordance with either 40 CFR 98.163(b), the existing equations, or 40 CFR 98.163(d), the revision requiring the calculation of net CO2 emissions using Equation P-4. We are proposing to revise 40 CFR 98.166(d) to require reporting the mass of non-CO2 carbon (excluding methanol) collected and transferred off-site for each process unit rather than for all process units combined, as currently reported. Reporters are already required to account for and report under 40 CFR 98.166(d) the mass of non-CO2 carbon (excluding methanol) collected and transferred off-site for all process units combined and under 40 CFR 98.166(e) the mass of methanol produced for each process unit. This proposed revision would cause a slight increase in reporting burden, but the additional level of reporting is necessary to implement the requested change in the calculation method and facilitate report verification. The proposed revision would provide the same breadth of information that was previously reported to inform future policy decisions. Additionally, this data element may be determined using company records, which also should minimize the increased burden. We are proposing related confidentiality determinations for the additional data elements, as discussed in section VI of this preamble.
As a result of the new Equation P-4, the EPA is proposing to add two new monthly recordkeeping elements as part of the verification software records required in 40 CFR 98.167(e): (1) monthly mass of carbon other than CO2 or methanol collected and transferred off site; and (2) monthly mass of methanol intentionally produced as a desired product. This proposed change is not expected to result in a significant increase in burden because both elements are already being reported on an annual basis. For reporters that do not produce carbon other than CO2 (excluding methanol) or methanol, the requirements for recordkeeping would remain unchanged. We are also clarifying that retention of the file required in 40 CFR 98.167(e) satisfies the recordkeeping requirements for each hydrogen production unit.
2. Proposed Revisions to Streamline and Improve Implementation for Subpart P
We are proposing several revisions to subpart P to streamline the requirements of this subpart and improve flexibility for reporters. First, we are proposing several revisions to address unconventional feedstocks being used for hydrogen production. For example, in RY2017, a new facility started reporting under subpart P that produced hydrogen via brine electrolysis. Additionally, we understand facilities are considering using anhydrous ammonia as a feedstock for hydrogen production. The test methods included in 40 CFR 98.164(b)(5) are generally not applicable for these feedstocks. Moreover, the reduced, annual measurement frequency allowances in 40 CFR 98.164(b)(2) and (3) are specific to "hydrocarbon fuels and feedstocks having consistent composition" [emphasis added].
To address the recent use of unconventional non-hydrocarbon feedstocks, and for the reasons described in section II.B.2 of this preamble, we are proposing to add an allowance in a new paragraph 40 CFR 98.164(b)(5)(xix) to use alternative methods if the methods currently in 40 CFR 98.164(b)(5) are not appropriate because the relevant compounds cannot be detected, the quality control requirements are not technically feasible, or use of the method would be unsafe. Similar provisions have been provided in other GHGRP subparts, such as subpart X. This proposed revision will ensure that subpart P will not mandate the use of inappropriate or unsafe methods for these unconventional feedstocks.
Additionally, we are proposing revisions to 40 CFR 98.164(b)(2) and (3) to allow the use of product specification information annually for non-hydrocarbon gaseous fuels and feedstocks that have carbon content less than or equal to 20 parts per million by weight (i.e., 0.00002 kg carbon per kg of gaseous fuel or feedstock) rather than at least weekly sampling and analysis. Similarly, we are proposing revisions to 40 CFR 98.164(b)(3) to allow the use of product specification information annually for non-hydrocarbon liquid fuels and feedstocks that have a carbon content of less than or equal to 0.00006 kg carbon per gallon of liquid fuel or feedstock rather than monthly sampling and analysis. The value of 0.0006 kg/gallon was derived using 20 parts per million by weight and assuming the liquid that has a specific gravity of 0.8 (i.e., a density of approximately 3.0 kg/gal). The current unconventional non-hydrocarbon fuels and feedstocks utilized in hydrogen production have very limited GHG emission potential and are currently an insignificant contribution to the GHG emissions from hydrogen production. Therefore, we consider it reasonable to provide a simple alternative of allowing use of product specification information on an annual basis for determining carbon content for these unconventional, non-hydrocarbon fuels and feedstocks.
We are also proposing revisions to 40 CFR 98.164(b)(5) to clarify that the methods in 40 CFR 98.164(b)(5) must be used for determining carbon content except for the newly proposed provisions for gaseous and liquid fuels and feedstocks that have a low carbon content as provided in paragraphs 40 CFR 98.164(b)(2) and (3). Additionally, we are proposing to revise paragraphs 40 CFR 98.164(b)(2), (b)(3), and (b)(4) to specifically state that the carbon content must be determined "...using the applicable methods in paragraph (b)(5) of this section." This proposed revision does not alter the existing requirements for fuels and feedstocks, it simply clarifies the linkage between the requirements in paragraphs 40 CFR 98.164(b)(2) through (4) and (5) of the current rule.
These proposed revisions to address unconventional hydrogen production feedstocks would increase flexibility for reporters and clarify requirements to reduce the number of reporters performing monthly sampling and analysis using potentially inappropriate methods. We expect that the proposed changes would allow reporters using unconventional non-hydrocarbon fuels and feedstocks to use the proposed product specifications provisions and reduce the need for sampling and analysis. Even if the reporter cannot use the product specifications provisions, the proposed revision to allow the use of modified or alternative methods would likely reduce the analytical burden of trying to use hydrocarbon-focused methods for a non-hydrocarbon stream. While the proposed revisions would provide significant relief for those reporters using unconventional non-hydrocarbon fuels or feedstocks, the proposed change is expected to only affect a small number of reporters due to the limited number of reporters that currently use these types of feedstocks.
In providing these alternatives, we also evaluated whether amendments to the recordkeeping and reporting requirements were necessary. There are no direct reporting requirements for the analytical method used to determine carbon content. The recordkeeping requirements are included in 40 CFR 98.167(b), which requires retention of "...records of all analyses and calculations conducted as listed in 40 CFR 98.166(b), (c), and (d)." In reviewing these requirements, we noted that these recordkeeping requirements were not revised when the EPA added reporting requirements at 40 CFR 98.166(e) (79 FR 63787, Oct. 24, 2014). Therefore, we are proposing to revise the recordkeeping requirements at 40 CFR 98.167(b) to refer to paragraphs (b) through (e) of 40 CFR 98.166. We note that, for facilities using the proposed alternatives at 40 CFR 98.164(b)(2), (3) or (5)(xix), these requirements include retention of product specification sheets, records of modifications to the methods listed in 40 CFR 98.164(b)(5)(i) through (xviii) that are used, and records of the alternative methods used, as applicable.
H. Subpart Q  --  Iron and Steel Production
1. Proposed Revisions to Improve the Quality of Data Collected for Subpart Q
For the reasons described in section II.A.4 of this preamble, we are proposing revisions to the reporting requirements for subpart Q of Part 98 (Iron and Steel Production) to enhance the quality and accuracy of the data collected. Subpart Q currently requires calculation of CO2 emissions using one of three methodologies: direct measurement using CEMS, carbon mass balance methodologies, or site-specific emission factors. Subpart Q requires that the CO2 emissions be calculated and reported for the following types of units: taconite indurating furnace, basic oxygen furnace, non-recovery coke oven battery, sinter process, EAF, decarburization vessel, and direct reduction furnace. We are proposing to revise the existing reporting requirements at 40 CFR 98.176(g) for all unit types and all calculation methods to require that facilities report the type of unit, the annual production capacity, and the annual operating hours for each unit. The capacity of the unit as well as the level of operation have a significant influence on the emissions of that unit. Therefore, the annual production capacity in combination with annual operating hours would provide useful information for understanding variations in annual emissions and would provide useful information to verify reported data. We often contact facilities seeking to understand yearly variations in the emissions of a unit, and facilities explain that the variation was due to the unit not operating for a particular time period. If data on the capacity of the unit and the operating hours are included in the annual report, it could explain the variation and eliminate the need for correspondence with facilities. In addition, this data would provide useful information to understand trends across the sector and support analysis of these sources.
In general, we do not anticipate that the proposed data elements would require any additional monitoring or data collection by reporters. For facilities using the carbon mass balance method, this data is already included in the record keeping requirements described at 40 CFR 98.177(c) and 40 CFR 98.177(d). Although the record keeping requirement at 40 CFR 98.177(d) does not specify whether the data would be retained at the facility or unit level, we do not anticipate that reporting data at the unit level would present additional burden. For facilities using the CEMS method or the site-specific emission factor calculation method, we anticipate that this data would be readily available in company records. However, we seek comment on both these assumptions. We are proposing related confidentiality determinations for the additional data elements, as discussed in section VI of this preamble.
For the reasons described in section II.A.5 of this preamble, we are proposing to correct Equation Q-5 in 40 CFR 98.173(b)(1)(v). An error appears to have been introduced in Equation Q-5 in revisions to the equation in the 2016 final rule (81 FR 89188, December 9, 2016). Specifically, the final rule inadvertently published the equation such that it appeared that the total CO2 emissions from EAFs are determined as a fraction of, rather than the total of, carbon mass emissions from inputs to the furnace. The proposed revisions would correct the equation to remove the unnecessary fraction symbol and would not add additional burden for the calculation or reporting requirements for subpart Q.
2. Proposed Revisions to Streamline and Improve Implementation for Subpart Q
For the reasons described in section II.B.2 of this preamble, we are proposing two revisions to subpart Q to streamline monitoring. First, we are proposing to revise 40 CFR 98.174(b)(2) to provide a new option for facilities to determine the carbon content of process inputs and outputs. Reporters are currently allowed to determine carbon content either through direct sampling using the methods provided in 40 CFR 98.174(b)(2) or from similar analyses provided by a supplier. We are proposing to allow reporters an additional third option to use analyses provided by material recyclers that manage process outputs for sale or use by other industries. Several of the process output materials used in iron and steel production are typically sent to recycling facilities (e.g., secondary zinc recycling facilities), which process the material for supply to another entity. Such material recyclers conduct testing on their inputs and products to provide to entities using the materials downstream, and therefore perform carbon content analyses using similar test methods and procedures as suppliers. In the 2009 Final Rule, we determined that the use of carbon content analyses from a material supplier was appropriate because the carbon content does not vary widely at a given facility for the significant process inputs and outputs that contain carbon, and because the EPA continued to account for variations in emissions due to changes in production rate, which are more likely to be a significant source of variability (i.e., the quantity of carbon-containing materials that are inputs and outputs to the process more directly influence emissions). For these same reasons, we anticipate that analyses received from a material recycling entity would be a reliable source of carbon content. The proposed change would add flexibility for reporters by allowing an additional option for obtaining measurements, in lieu of direct sampling. We are proposing a minor harmonizing change to 40 CFR 98.176(e)(2) to require reporters to indicate if the carbon content was determined from information supplied by a material recycler.
We are also proposing to revise 40 CFR 98.174(b)(2) to incorporate a new test method for carbon content analysis of low-alloy steel. The EPA has become aware that an additional method is available for analysis of carbon content, specifically, ASTM method E415-17, Standard Test Method for Analysis of Carbon and Low-Alloy Steel by Spark Atomic Emission Spectrometry (2017). We have reviewed the method, which is targeted to this sector, and have tentatively concluded it is a valid method for the purposes of subpart Q monitoring and reporting. The EPA allows for the use of standard methods based on atomic emission spectrometry in other sections of the rule, including under 40 CFR 98.144(b) where it can be used to determine the composition of coal, coke, and solid residues from combustion processes by glass production facilities. Therefore, we are proposing to incorporate the method by reference in 40 CR 98.7 and cross-reference that incorporation in 40 CFR 98.174(b)(2) for use for steel, as applicable. The proposed test method would be an alternative method and would provide additional flexibility for reporters. We are also proposing a harmonizing change to the reporting requirements of 40 CFR 98.176(e)(2), to clarify that the carbon content analysis methods available to report are those methods listed in 40 CFR 98.174(b)(2).
I. Subpart S  --  Lime Manufacturing
For the reasons discussed in this section and section II.A of this preamble, we are proposing several revisions to subpart S of Part 98 (Lime Manufacturing) to improve the quality of the data collected from this subpart. First, for the reasons described in this section and in section II.A.2 of this preamble, we are proposing to amend subpart S to improve the methodology for calculation of annual CO2 process emissions from lime production. The proposed revisions would account for CO2 that is captured from lime kilns and used on-site. Under subpart S, reporters currently calculate CO2 emissions by either operating and maintaining a CEMS as specified in 40 CFR 98.193(a) or (b)(1), or by using the mass balance methodology under 40 CFR 98.193(b)(2). All lime kilns that are subject to 40 CFR 98.193(b) must calculate and report process and combustion CO2 emissions by using the procedures in either 40 CFR 98.193(b)(1), for estimation of combined process and combustion emissions from all lime kilns, or 40 CFR 98.193(b)(2), for estimation of process and combustion CO2 emissions from all lime kilns separately. For those lime kilns that use 40 CFR 98.193(b)(2), calculation of annual CO2 process emissions from all lime kilns is estimated through summing the following three values (per 40 CFR 98.193(b)(2)(iv)): (1) the product of a monthly site-specific emission factor and weight or mass for each type of lime produced, (2) the product of a monthly site-specific emission factor and each type of calcined byproduct or waste that is sold, and (3) the annual CO2 emissions from each type of calcined byproduct or waste that is not sold. There is currently no allowance for subtraction of CO2 that may be captured and used in another process on-site (e.g., for use in a purification process or the manufacture of another product such as refined beet sugars, precipitated calcium carbonate, etc.).
In response to the 2009 Proposed Rule, one subpart S reporter, Specialty Minerals Inc., submitted a comment that stated that subpart S does not include a "deduction for the carbon dioxide that is taken up as a raw material" for use in another product, resulting in "an overstatement of total carbon dioxide emissions" from lime manufacturing. In section III.C of this preamble, we describe similar comments received from TFI requesting changes that would allow sources to subtract from direct facility emissions CO2 that is being used in the manufacturing of other products on-site.
Following review of these comments, the EPA has tentatively concluded that allowing reporters subject to subpart S to report net CO2 process emissions after subtracting out CO2 captured and used in other on-site processes would provide a more accurate estimate of the direct GHG emissions from the lime manufacturing process and would provide consistency in our approach across the GHGRP. Therefore, we are proposing to modify Equation S-4 to subtract the CO2 that is captured and used in on-site processes, with corresponding proposed revisions to the recordkeeping requirements in 40 CFR 98.197(c) (to record the monthly amount of CO2 from the lime manufacturing process that is captured for use in all on-site processes). We are also proposing minor amendments to the reporting elements in 40 CFR 98.196(b)(17) to clarify that we only intend to collect data on CO2 that is captured and used on-site (i.e., reporters do not need to account for CO2 that was not captured but was used on-site), and to clarify that reporters must account for CO2 usage from all on-site processes, including for manufacture of other products, in the total annual amount of CO2 captured. The proposed changes would also correct some instances where reporters have provided values of CO2 used on-site that exceed facility emissions, where they have inadvertently included CO2 that was not captured on-site (e.g., CO2 purchased for water treatment), which incorrectly implied that the facility's emissions were net negative. The proposed amendments would not change the reporting of emissions from manufacture of lime products, calcined lime by-products, or waste; this information would continue to be collected. As such, the proposed amendments would provide the same breadth of information that was previously reported to inform future policy decisions.
Second, for the reasons described in section II.A.4 of this preamble, we are proposing to add reporting requirements for reporters using the CEMS methodology in order to improve our understanding of source category emissions and our ability to verify reported data. Subpart S reporters who use CEMS collect CO2 emissions data through direct measurement, and no data on the chemical composition of the products, byproducts, or wastes at CEMS facilities are collected through the GHGRP. As such, there is currently limited data available to the EPA to evaluate process emissions for reporters using CEMS. As we noted for cement production facilities in section III.D of this preamble, CEMS facility emissions are different from non-CEMS emissions because combustion and process emissions are typically vented through the same stack, causing process and combustion emissions to be mixed and indifferentiable. In order be able to differentiate process emissions, we are proposing to collect other data elements from CEMS reporters that are not currently reported, including annual average results of the chemical composition analysis of lime products, byproducts, or wastes. Collecting average chemical composition data for CEMS facilities will provide the EPA the ability to develop a process emission estimation methodology for CEMS reporters, which can be used to verify the accuracy of the reported CEMS emission data. The EPA is proposing to add data elements under 40 CFR 98.196(a) to collect annual averages of the chemical composition input data on a facility-basis. The proposed data elements include the annual arithmetic average calcium oxide content (metric tons CaO/metric tons lime) and magnesium oxide content (metric tons MgO/metric tons lime) for each type of lime produced, for each type of calcined lime byproduct and waste sold, and for each type of calcined lime byproduct and waste not sold. The proposed data elements would rely on an arithmetic average of the measurements rather than requiring reporters to weight by quantities produced in each month. In addition to improving verification and data quality for the GHGRP, the proposed data elements will also improve the U.S. GHG Inventory, which could use the proposed data elements to disaggregate process and combustion emissions that are reported by facilities using CEMS.
Similarly, in order to improve verification, we are proposing to collect additional data elements for reporters using the mass balance methodology (i.e., reporters that comply using the requirements at 40 CFR 98.193(b)(2)). These proposed amendments would allow the EPA to build verification checks for the actual inputs entered (e.g., MgO content). We currently rely on verification checks within the IVT to check the accuracy of inputs and reported emissions from non-CEMS reporters, however, these checks are of limited usefulness since we lack the information to develop specific anticipated ranges or references for the entered data. Reporters using the mass balance methodology are currently required to report the annual average results of chemical composition analysis of each type of lime product produced and calcined byproduct or waste sold, but do not supply data for byproducts or wastes not sold. The EPA is proposing to add data elements under 40 CFR 98.196(b) to collect the annual average results of the chemical composition analysis of all lime byproducts or wastes not sold (e.g., a single facility average calcium oxide content calculated from the calcium oxide content of all lime byproduct types at the facility), and the annual quantity of all lime byproducts or wastes not sold (e.g., a single facility total calculated as the sum of all quantities, in tons, of all lime byproducts at the facility not sold during the year). Because the proposed data elements rely on annual averages of the chemical composition measurements and an annual quantity of all lime byproducts or wastes at the facility, they are distinct from the data entered into the EPA's IVT. These proposed data elements would inform and improve the EPA's existing reference checks and allow the EPA to build additional checks for the data that are currently verified through IVT. The proposed amendments would improve the verification of entered data and confirm the veracity of reported emissions.
We do not anticipate that the proposed data elements would require any additional monitoring or data collection by reporters, as these data are likely already available in existing company records. However, we are requesting comment on whether any of the above listed data elements would not be readily available to reporters. Reporters using the mass balance methodology are expected to have very minimal changes to reporting, as the chemical composition averages and quantities we are proposing can be calculated from the inputs that are currently entered into IVT. Finally, we are proposing related confidentiality determinations for the additional data elements, as discussed in section VI of this preamble.
J. Subpart W  --  Petroleum and Natural Gas Systems
We are proposing several revisions to subpart W (Petroleum and Natural Gas Systems). Section III.J.1 of this preamble presents proposed amendments that would improve the quality of data collected, including new requirements for reporting of additional emission sources, updated emission factors, new and revised reporting requirements, and clarification of reporting requirements that reporters have indicated are unclear, as described in section II.A of this preamble. We are also proposing revisions described in section III.J.2 of this preamble that would streamline and improve implementation, including removing redundant or unnecessary reporting requirements, and providing additional flexibility in the calculation methods and monitoring requirements for some emission sources, as described in section II.B of this preamble. We are proposing the miscellaneous technical corrections and clarifications described in section III.J.3 of this preamble. Finally, section III.J.4 of this preamble describes the provisions for which we propose subpart W reporters would be able to use best available monitoring methods (BAMM) for RY2023. We are also proposing related confidentiality determinations for new or revised data elements that result from these proposed amendments, as discussed in section VI of this preamble.
In addition, on November 15, 2021 (86 FR 63110), the EPA proposed under CAA section 111(b) NSPS for new, reconstructed, and modified oil and natural gas sources, i.e., sources for which owners or operators commence construction, modification, or reconstruction after November 15, 2021 (40 CFR part 60, subpart OOOOb) (hereafter referred to as "NSPS OOOOb"), as well as emissions guidelines under CAA section 111(d) for existing oil and natural gas sources, i.e., sources for which owners or operators commence construction, modification, or reconstruction on or before  November 15, 2021 (40 CFR part 60, subpart OOOOc) (hereafter referred to as "EG OOOOc") (the sources affected by these two proposed subparts are collectively referred to in this preamble as "affected sources"). While the standards in NSPS OOOOb would directly apply to new, reconstructed, and modified sources when finalized, the final EG OOOOc would not impose binding requirements directly on sources; rather it would contain guidelines, including presumptive standards, for states to follow in developing, submitting, and implementing plans to establish standards of performance to limit GHGs (in the form of methane limitations) from existing oil and gas sources within their own states. If a state does not submit a plan to the EPA for approval in response to the final emission guidelines, or if the EPA disapproves a state's plan, then the EPA must establish a Federal plan that would apply to existing sources within that state that are not covered by a state plan. In addition, a Federal plan could apply to facilities located on tribal land that do not request approval to develop a tribal implementation plan similar to a state plan. Once the Administrator approves a state plan under CAA section 111(d), the plan is codified in 40 CFR part 62 (Approval and Promulgation of State Plans for Designated Facilities and Pollutants) within the relevant subpart for that state. 40 CFR part 62 also includes all Federal plans promulgated pursuant to CAA section 111(d). Therefore, rather than referencing the presumptive standards in EG OOOOc, which would not directly apply to sources, the proposed amendments to subpart W reference 40 CFR part 62.
Similar to the 2016 amendments to align subpart W with certain requirements in 40 CFR part 60, subpart OOOOa (hereafter referred to as "NSPS OOOOa") (81 FR 86500, November 30, 2016), we are proposing revisions to certain requirements in subpart W relative to the requirements proposed for NSPS OOOOb and the presumptive standards proposed in the EG OOOOc (which would inform the standards to be developed and codified under 40 CFR part 62). Specifically, we are proposing amendments to the subpart W calculation methodologies for natural gas pneumatic devices and equipment leak surveys related to the proposed NSPS OOOOb and presumptive standards in EG OOOOc, and we are proposing new reporting requirements for "other large release events" as defined in subpart W that would reference the NSPS OOOOb and approved state plans or applicable Federal plan in 40 CFR part 62. These proposed amendments are described in sections III.J.1.a, k, and m, respectively. These proposed amendments, if finalized, would not apply to individual reporters unless and until their emission sources are required to comply with either the final NSPS OOOOb or an approved state plan or applicable Federal plan in 40 CFR part 62. In the meantime, reporters would comply with the applicable provisions of subpart W for sources not subject to NSPS OOOOb or 40 CFR part 62.
1. Proposed Revisions to Improve the Quality of Data Collected for Subpart W
As further described in section II.A of this preamble, the EPA is proposing amendments that would ensure that accurate data are being collected under the rule, improve the accuracy of emissions reported under Part 98, and enhance the overall quality of the data collected under the GHGRP. Consistent with section II.A.1 of this preamble, we are proposing to incorporate recent data to update selected subpart W emission factors. Where emission factors are currently provided in subpart W for certain emission source types, those emission factors were based on the best available public data at the time that subpart W was promulgated. In the years since promulgation of subpart W, additional data have been collected for some source types as part of emissions studies, and the EPA has reviewed and evaluated the data in these studies. Based on those evaluations, the EPA is proposing to update selected subpart W population emission factors for natural gas pneumatic device vents across a variety of industry segments and equipment leaks from the Onshore Petroleum and Natural Gas Production, Onshore Petroleum and Natural Gas Gathering and Boosting, and Natural Gas Distribution industry segments. The EPA is also proposing revisions to the leaker emission factors for all industry segments conducting equipment leak surveys to account for differences in the leak detection methodologies. Consistent with section II.A.2 of this preamble, the EPA is proposing amendments to improve calculation methodologies for emissions from natural gas pneumatic pumps, centrifugal compressors, reciprocating compressors, equipment leak surveys, combustion units, and sources that use the acoustic leak detection method for leak detection. Consistent with section II.A.3 of this preamble, we are proposing to add calculation and reporting requirements for "other large release events," which are emission events that are not sufficiently accounted for using the current subpart W methodologies, and emissions from uncombusted methane from compressor engines. We are also proposing to require facilities in the Onshore Natural Gas Processing industry segment to begin calculating and reporting emissions from natural gas pneumatic devices and proposing to require facilities in the LNG Import/Export industry segment to begin calculating and reporting emissions from acid gas removal vents. Consistent with section II.A.4 of this preamble, we are proposing to add or revise reporting requirements to better understand and characterize the emissions from acid gas removal units, glycol dehydrator vents, liquids unloadings, atmospheric storage tanks, associated gas flaring, flare stacks, and equipment leaks, as well as to better characterize facilities in the Onshore Petroleum and Natural Gas Gathering and Boosting industry segment. Finally, consistent with section II.A.5 of this preamble, we are proposing to clarify calculation and reporting requirements for natural gas pneumatic devices, natural gas driven pneumatic pumps, blowdown vent stacks, atmospheric storage tanks (including requirements for open thief hatches), associated gas venting and flaring, centrifugal and reciprocating compressors, combustion devices, and facilities in the Onshore Natural Gas Transmission Pipeline industry segment, in part to address questions asked by reporters to the GHGRP Help Desk and in verification correspondence via e-GGRT.
a. Natural Gas Pneumatic Device Vents
Revisions to Emission Factors. Subpart W requires calculation of GHG emissions from natural gas pneumatic device venting using default population emission factors multiplied by the number of devices and the average time those devices are "in-service" (i.e., supplied with natural gas). Subpart W provides two sets of pneumatic device emission factors, one for devices in the Onshore Petroleum and Natural Gas Production and Onshore Petroleum and Natural Gas Gathering and Boosting industry segments and one for the Onshore Natural Gas Transmission Compression and Underground Natural Gas Storage industry segments. Each set of emission factors consists of emission factors for three different types of natural gas pneumatic devices: continuous low bleed devices, continuous high bleed devices, and intermittent bleed devices.
The EPA has become aware of several studies on emissions from natural gas pneumatic device vents since subpart W was first promulgated. For example, in April 2015, the EPA reviewed three recently published studies on emissions from pneumatic devices (also referred to as "pneumatic controllers" within the studies as well as in NSPS OOOOa, NSPS OOOOb, and EG OOOOc) at onshore production facilities and evaluated those studies for use in the U.S. GHG Inventory. As part of this proposed rulemaking, we have reviewed these and other available studies to evaluate the potential for revisions to the natural gas pneumatic device emission factors in subpart W. For more information regarding this review, see the document Greenhouse Gas Reporting Rule: Technical Support for Revisions and Confidentiality Determinations for Data Elements Under the Greenhouse Gas Reporting Rule; Proposed Rule  -  Petroleum and Natural Gas Systems, (hereafter referred to as "subpart W TSD"), available in the docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424.
As part of our review, we found there are significantly more data available now by which to characterize pneumatic device emissions. Therefore, consistent with section II.A.1 of this preamble, we are proposing to amend the emission factors for the Onshore Petroleum and Natural Gas Production, Onshore Petroleum and Natural Gas Gathering and Boosting, Onshore Natural Gas Transmission Compression, and Underground Natural Gas Storage industry segments. We are also proposing to add pneumatic device venting as an emission source for the Onshore Natural Gas Processing industry segment using the same emission factors we are proposing for the Onshore Natural Gas Transmission Compression and Underground Natural Gas Storage industry segments, consistent with section II.A.3 of this preamble.
Intermittent Bleed Pneumatic Devices Subject to Surveys. As part of our review to characterize pneumatic device emissions, we found a significant difference in the emissions from intermittent bleed pneumatic devices that appeared to be functioning as intended (short, small releases during device actuation) and those that appeared to be malfunctioning (continuously emitting or exhibiting large or prolonged releases upon actuation). For natural gas intermittent bleed pneumatic devices, it is possible to identify malfunctioning devices through routine monitoring using optical gas imaging (OGI) or other technologies. 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 sources. Under the proposed standards in NSPS OOOOb and the proposed presumptive standards in EG OOOOc (which would inform the state plans or, if necessary, the Federal plan in 40 CFR part 62), nearly all covered pneumatic devices (continuous bleed and intermittent vent) would be required to have a methane and volatile organic compound (VOC) emission rate of zero. The only exception would be for pneumatic devices in Alaska at locations where on-site power is not available, in which case owners and operators would be required to use low bleed pneumatic devices in place of high bleed pneumatic devices (unless a high bleed device is needed for a functional need such as safety), and to verify that any intermittent bleed pneumatic devices operate such that they do not vent when idle by monitoring these devices during the fugitive emissions survey.
We envision relatively few intermittent bleed pneumatic devices under the proposed zero-emission standard and presumptive standard for these pneumatic devices, compliance with which would require the use of non-emitting devices. As noted in the previous paragraph, we proposed in NSPS OOOOb and EG OOOOc to require periodic monitoring of those few intermittent bleed pneumatic devices. In addition, as noted in section III.J of this preamble, the proposed amendments that would apply to sources subject to the NSPS OOOOb and approved state plans or applicable Federal plan in 40 CFR part 62 would not become effective for individual reporters unless and until their emission sources become subject to and are required to comply with either the final NSPS OOOOb or an approved state plan or applicable Federal plan in 40 CFR part 62. Prior to that time, a reporter may elect to conduct inspections or surveys of their intermittent bleed pneumatic devices. Therefore, similar to the 2016 amendments to subpart W (81 FR 4987, January 29, 2016), the EPA is proposing amendments to subpart W to provide an alternative methodology to calculate emissions from intermittent bleed pneumatic devices based on the results of inspections or surveys, consistent with section II.A.2 of this preamble. Specifically, for facilities that would be required to inspect their intermittent bleed pneumatic devices requirements under NSPS OOOOb or an approved state plan or the applicable Federal plan in 40 CFR part 62 (to the extent there are any) or facilities that elect to conduct routine monitoring surveys of their existing natural gas intermittent bleed pneumatic devices consistent with the methods in NSPS OOOOb prior to becoming subject to 40 CFR part 62, we are proposing to provide an alternative calculation methodology analogous to a "leaker factor" approach used for equipment leaks. Reporters using this calculation methodology would report the total number of natural gas intermittent bleed pneumatic devices at the facility, the frequency of monitoring, the number of devices found to be malfunctioning, and the average time the malfunctioning devices were malfunctioning. For more information regarding this proposed alternative calculation methodology for natural gas intermittent bleed pneumatic devices, see the subpart W TSD, available in the docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424.
Hours of Operation of Natural Gas Pneumatic Devices and Natural Gas Driven Pneumatic Pumps. In correspondence with the EPA via e-GGRT, reporters have indicated that there is confusion over the use of the term "operational" in the definition of variable "Tt" in Equation W-1 in 40 CFR 98.233(a) and the term "in operation" in the reporting requirements in 40 CFR 98.236(b)(2). Both the current emission factors and the proposed updated emission factors described earlier in this section for natural gas pneumatic devices were developed by taking both periods of actuation and periods without actuation into account; in other words, the emission factors are population emission factors. To calculate emissions accurately using a population emission factor, the average number of hours used in Equation W-1 should be the number of hours that the devices of a particular type are in service (i.e., the devices are receiving a measurement signal and connected to a natural gas supply that is capable of actuating a valve or other device as needed). Therefore, consistent with section II.A.5 of this preamble, we are proposing to revise the definition of variable "Tt" in Equation W-1 and the corresponding reporting requirement in 40 CFR 98.236(b)(2) to use the term "in service (i.e., supplied with natural gas)" rather than "operational" or "in operation."
Similarly, the population emission factor for natural gas driven pneumatic pumps was developed using measurements taken during actuations together with manufacturer data and observed operational data at facilities (e.g., pump actuation rate). In other words, the emission factor represents the average emissions over the period when the pump is operating, not just the emissions during periods when the pump was actuating. Therefore, we are also proposing to revise the definition of variable "T" in Equation W-2 in 40 CFR 98.233(c)(1) for natural gas driven pneumatic pumps to use the term "in service (i.e., supplied with natural gas)," and we are proposing to use that same term in the corresponding reporting requirement in proposed 40 CFR 98.236(c)(4).
b. Natural Gas Driven Pneumatic Pump Venting
The current procedures in subpart W for calculating and reporting emissions from natural gas driven pneumatic pump venting are specified in 40 CFR 98.233(c) and 40 CFR 98.236(c). The inputs to Equation W-2 in 40 CFR 98.233(c) are the total number of natural gas driven pneumatic pumps and average estimated number of hours in the operating year the pumps were operational. Reporters then report these inputs along with the emissions under 40 CFR 98.236(c). As the calculated emissions are vented emissions from natural gas driven pneumatic pumps, the intent is that the total number of natural gas driven pneumatic pumps should include only those pumps that are vented directly to the atmosphere (i.e., uncontrolled). However, based on contact with reporters, we understand that emissions from some natural gas driven pneumatic pumps are routed to controls, particularly flares or combustion units. Flared emissions from natural gas driven pneumatic pumps are not required to be calculated and reported separately from other flared emissions. Instead, emission streams from natural gas driven pneumatic pumps that are routed to flares are required to be included in the calculation of total emissions from the flare according to the procedures in 40 CFR 98.233(n) and reported as part of the total flare stack emissions according to the procedures in 40 CFR 98.236(n), in the same manner as emission streams from other source types that are routed to the flare. Similarly, emissions from natural gas driven pneumatic pumps that are routed to a combustion unit are required to be combined with other streams of the same fuel type and used to calculate total emissions from the combustion unit as specified in 40 CFR 98.233(z) and reported as part of the total emissions from the combustion unit as specified in 40 CFR 98.236(z).
In correspondence with the EPA via e-GGRT, some reporters have expressed confusion regarding the requirements for natural gas driven pneumatic pumps that are routed to flares or combustion devices, particularly between 40 CFR 98.236(c) (for vented emissions) and 40 CFR 98.236(n) or (z) (for flared or combusted emissions, respectively). Additionally, the counts of controlled natural gas driven pneumatic pumps currently are not reported separately from counts of vented natural gas driven pneumatic pumps under 40 CFR 98.236(c), and the emissions currently reported from flares and combustion units are not attributed specifically to natural gas driven pneumatic pumps. This lack of reported information leads to uncertainty in verification of reported data when there are significant changes in reported data at a facility from one year to the next, which can result in additional communication with the reporter to clarify whether or not the changes are an error. The lack of reported information also means changes in the trends related to implementation of such controls relative to trends in overall use of natural gas driven pneumatic pumps in the petroleum and natural gas systems source category would be difficult to track. In addition, there are other rules that require the control of pneumatic pumps (e.g., NSPS OOOOa), so we expect that there will be an increase in the number of natural gas driven pneumatic pumps that are routed to controls as more facilities become subject to those rules.
Thus, consistent with section II.A.2 of this preamble, we are proposing to revise 40 CFR 98.233(c) to clarify requirements for calculating emissions from both natural gas driven pneumatic pumps that are vented to the atmosphere and controlled natural gas driven pneumatic pumps that are consistent with the intent of the current rule. Specifically, we are proposing to revise 40 CFR 98.233(c) introductory text and the definitions of the terms "Count" and "T" in Equation W-2 to further clarify that the provisions of 40 CFR 98.233(c)(1) and (2) should only be used to calculate emissions from natural gas driven pneumatic pumps venting directly to the atmosphere. We are proposing to add 40 CFR 98.233(c)(3) to specify that if the emissions are flared, then flared emissions would be calculated using the method for flare stack emissions in 40 CFR 98.233(n) and reported as flare stack emissions under 40 CFR 98.236(n). If emissions are routed to a combustion device, then emissions would be calculated using the methods for combustion devices as specified in 40 CFR 98.233(z) and reported as specified in 40 CFR 98.236(z). Finally, if the emissions are routed to vapor recovery and are not subsequently routed to a combustion device, then we are proposing that reporters would not calculate or report emissions. If a natural gas driven pneumatic pump is vented directly to the atmosphere for part of the year and routed to a flare, combustion, or vapor recovery system during another part of the year, the reporter would calculate emissions using all applicable procedures and adjust the number of hours used in Equation W-2 as needed. We request comment on whether pneumatic pumps are routed to vapor recovery systems and whether there are other controls that should be addressed with these new provisions. In addition, we request comment on whether flared emissions associated with natural gas driven pneumatic pumps should continue to be reported as flare stack emissions under 40 CFR 98.236(n) or should be reported in the natural gas driven pneumatic pumps emission source under 40 CFR 98.236(c).
We are also proposing to add new reporting elements in 40 CFR 98.236(c) to align with the proposed clarifications to the emission calculation procedures. Specifically, we are proposing to expand the current requirement to report the total count of natural gas driven pneumatic pumps to three separate counts: the number of natural gas driven pneumatic pumps that are vented directly to atmosphere (i.e., uncontrolled); the number of natural gas driven pneumatic pumps that are routed to a flare, combustion, or vapor recovery (i.e., controlled); and the total number of natural gas driven pneumatic pumps at the facility. The total count of pneumatic pumps is a proposed reporting element along with the counts of uncontrolled and controlled pneumatic pumps because the total count would not always be equal to the sum of the other two counts. For example, a reporter that switches from one scenario to another during a year for a particular pneumatic pump (e.g., from vented to flared) would include that pneumatic pump in the count of pumps that vent directly to atmosphere and in the count of pumps that are routed to flares, but that pneumatic pump would only be counted once towards the total number of pneumatic pumps. The number of pneumatic pumps vented directly to the atmosphere would be equal to the "Count" in Equation W-2 and would be used in the verification of annual reports to the GHGRP. The total count of pneumatic pumps at the facility and the number of pneumatic pumps that are routed to a flare, combustion, or vapor recovery would provide the EPA with information to better characterize emissions from this source, including how many pneumatic pumps are controlled across the industry, how often pneumatic pumps are both controlled and vented directly to the atmosphere in the same year, and how the use of controls for pneumatic pumps changes across multiple years.
c. Acid Gas Removal Vents
Acid Gas Removal Units at LNG Import/Export Facilities. Emissions from acid gas removal units are currently reported for three industry segments: Onshore Petroleum and Natural Gas Production, Onshore Natural Gas Processing, and Onshore Petroleum and Natural Gas Gathering and Boosting. However, prior to becoming LNG, natural gas is treated to specifications more stringent than pipeline quality natural gas to remove nearly all of the heavy hydrocarbons, mercury, CO2, sulfur compounds, and other impurities to prevent problems with the liquefaction process (e.g., CO2 and hydrogen sulfide can cause freezing and plugging in downstream units once the gas is liquefied). Therefore, liquefaction plants at LNG export facilities may include acid gas removal units, and those emissions are not currently reported to the GHGRP if the acid gas removal unit vents are vented directly to the atmosphere. Emissions from acid gas removal unit vents that are routed to flares or thermal oxidizers that meet the subpart W definition of flare in 40 CFR 98.238 are reported under the flare stacks emission source, but they are not characterized as acid gas removal emissions. LNG export facilities may receive natural gas that has already been treated in a natural gas processing plant as well as raw material from dedicated gas fields, so the emissions from acid gas removal units at these facilities can comprise a significant portion of the facility's emissions if the gas received at an LNG export facility has a relatively high CO2 content.
Therefore, consistent with section II.A.3 of this preamble, the EPA is proposing to revise 40 CFR 98.232(h) and 40 CFR 98.236(a)(7) to add acid gas removal vents to the list of emission sources for which facilities in the LNG Import/Export industry segment must calculate and report emissions. Facilities in this industry segment with an acid gas removal unit would use one of the four calculation methods currently provided in 40 CFR 98.233(d) and report emissions as currently provided in 40 CFR 98.236(d). Facilities in this industry segment without an acid gas removal unit would only be required to indicate that in their report. We request comment on whether all four calculation methods currently provided in 40 CFR 98.233(d) are appropriate for facilities in the LNG Import/Export industry segment and if not, how specific calculation methods could be adjusted to be more applicable to this industry segment. In addition, we request comment on whether there are other emission sources at LNG Import/Export facilities with significant emissions that should be added to subpart W (e.g., glycol dehydrators), as well as whether there are other industry segments with acid gas removal units that are not reported and make up a significant portion of facility emissions.
Calculation Method 4 Reporting. Reporters with acid gas removal units that elect to calculate emissions using Calculation Method 4 are required to report several data elements that are inputs to the simulation software package that is used to calculate emissions. One of the required inputs to report is the solvent weight, in pounds per gallon (40 CFR 98.236(d)(2)(iii)(L)). A variety of different solvents may be used in an acid gas removal unit (e.g., chemical solvents such as monoethanolamine (MEA) and methyl diethanolamine (MDEA), physical solvents such as SelexolTM and Rectisol(R)), and the solubility of CO2 varies across the different types of solvent. Requiring reporters to provide solvent characteristics provides information about the type of solvent used so the emissions calculated by the modeling run could be verified. However, the "solvent weight" is the only data element related to the identification of the solvent that is currently collected, and the values reported across all reporters have been inconsistent over the last few years, indicating that this data element is likely not clear to reporters (e.g., some reporters appear to be providing the density of the solvent and others appear to be providing the amine concentration in weight percent). In addition, the densities of common amine-based solvents are fairly close in value, so even among reporters that are providing values within the expected range of solvent densities, we have found it difficult to use this data element to identify the solvent type. Finally, the current requirement to report solvent weight does not specify how this value should be determined, but given the precise values being reported, it appears that reporters are either measuring the solvent or reporting a specific value provided by the vendor.
Therefore, we are proposing to replace the requirement to report solvent weight with a requirement to report the solvent type and, for amine-based solvents, the general composition. Reporters would choose the type/general composition option from a pre-defined list that most closely matches the solvent type and composition used in their acid gas removal unit. The standardized response options would include the following: "Selexol(TM)," "Rectisol(R)," "Purisol(TM)," "Fluor Solvent(SM)," "Benfield(TM)," "20 wt% MEA," "30 wt% MEA," "40 wt% MDEA," "50 wt% MDEA," and "Other." We are proposing to use commercially available trade names in this list rather than chemical compositions, as the trade names are more commonly used among acid gas removal unit operators and therefore more readily available. This proposed amendment to collect standardized information about the solvent is expected to result in more useful data that would improve verification of reported data and better characterize acid gas removal vent emissions, consistent with section II.A.4 of this preamble. It would also improve the quality of the data reported compared to the apparently inconsistent application of the current requirements. In addition, the solvent type and composition rarely change from one year to the next, so once the data element is reported the first time, most reporters would be able to copy the response from the previous year's reporting form each year. Therefore, the proposal to require reporters to select a solvent type and composition from these standardized responses is also expected to streamline and improve implementation compared to the current requirement of reporting an exact value for solvent weight, consistent with section II.B.3 of this preamble.
d. Dehydrator Vents
Dehydrators are used to remove water from produced natural gas prior to transferring the natural gas into a pipeline or to a gas processing facility. Subpart W requires reporting of GHG emissions from dehydrator vents at onshore petroleum and natural gas production, onshore petroleum and natural gas gathering and boosting, and natural gas processing facilities. Emissions are determined using one of the calculation methodologies for glycol dehydrators provided in 40 CFR 98.233(e) based on the unit's annual average daily natural gas throughput. For units 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). For units with an annual average daily natural gas throughput greater than or equal to 0.4 MMscf per day, reporters must follow the provisions under 40 CFR 98.233(e)(1), which require modeling GHG emissions using a software program (e.g., AspenTech HYSYS(R) or GRI-GLYCalc(TM)).
The EPA has reviewed the subpart W glycol dehydrator data and reporting requirements in 40 CFR 98.236(e) and has made a preliminary determination that additional information would help to more accurately characterize emissions from glycol dehydrators with an annual average daily natural gas throughput greater than or equal to 0.4 MMscf per day. Specifically, the EPA's review found no strong correlations between glycol dehydrator emissions and the operating parameters currently reported under 40 CFR 98.236(e)(1). This assessment is consistent with the results of an analysis provided to the EPA by GPA Midstream, which indicated that the correlations between vent gas flow rate, glycol circulation rate, and glycol pump type provided the most accurate approximation of dehydrator emissions. While subpart W does currently collect information on glycol pump type and circulation rate for each modeled glycol dehydrator with an annual average daily natural gas throughput greater than or equal to 0.4 MMscf per day, reporters are not asked to report any characteristics of their units' flash tank and still vents, including vent gas flow rate. As such, the EPA is not able to review historical subpart W dehydrator data to verify GPA Midstream's suggested correlation between vent gas flow rate, glycol circulation rate, and glycol pump type. Therefore, the EPA is proposing to add new reporting requirements to 40 CFR 98.236(e)(1), consistent with section II.A.4 of this preamble. The following new data elements are proposed to be added to subpart W for glycol dehydrators with an annual average daily natural gas throughput greater than or equal to 0.4 MMscf per day:
Flash tank control technique
Regenerator still vent control technique
Flash tank vent gas flow rate (standard cubic feet per hour (scfh))
Regenerator still vent gas flow rate (scfh)
Concentrations of CH4 and CO2 in flash tank vent gas (mole fraction)
Concentrations of CH4 and CO2 in regenerator still vent gas (mole fraction)
Type of stripping gas used
Flow rate of stripping gas (standard cubic feet per minute (scfm))
These proposed additional data elements are intended to allow the EPA to derive a correlation between vent flow rate and absorbent circulation rate and better characterize emissions from glycol dehydrators with an annual average daily natural gas throughput greater than or equal to 0.4 MMscf per day. Further, the EPA is proposing to require separate reporting of emissions for a modeled glycol dehydrator's still vent and flash tank vent. These vents often use different control techniques, so requiring the emissions from these vents to be reported separately would ensure that future analyses accurately characterize the emissions. The proposed data elements are included in the output files from the modeling software used for glycol dehydrators and are, therefore, not expected to be difficult for reporters to implement.
Additionally, in correspondence with the EPA via e-GGRT, some reporters have expressed confusion regarding the requirements for glycol dehydrators emissions that are routed to vapor recovery and subsequently routed to a flare or regenerator firebox/fire tubes. As such, the EPA is proposing edits to the vapor recovery calculation methodology of 40 CFR 98.233(e)(5) (proposed to be moved to 40 CFR 98.233(e)(4)) to clarify that unrecovered emissions that are not routed to flares or regenerator fireboxes/fire tubes should be reported as emissions vented directly to atmosphere, while emissions that are routed to flares or regenerator fireboxes/fire tubes should be reported as flared emissions from dehydrators. Along with the proposed amendments to 40 CFR 98.233(e)(6) (proposed to be moved to 40 CFR 98.233(e)(5)) for calculating emissions from flares or regenerator fireboxes/fire tubes (discussed in section III.J.1.i of this preamble), the EPA seeks to enhance the overall quality of the data collected under the GHGRP, consistent with section II.A.5 of this preamble.
e. Liquids Unloading
Subpart W currently requires reporting of emissions from well venting for liquids unloading. Facilities calculate emissions using measured flow rates under Calculation Method 1 (40 CFR 98.233(f)(1)) or engineering equations under Calculation Method 2 for unloadings without plunger lifts (40 CFR 98.233(f)(2)) and Calculation Method 3 for unloadings with plunger lifts (40 CFR 98.233(f)(3)). Under the reporting requirements of 40 CFR 98.236(f), facilities must report whether plunger lifts were used when using Calculation Method 1 and must report the data elements used in Equations W-7A and W-7B. For Calculation Methods 2 and 3, however, reporters only report a subset of the data elements used to calculate emissions in Equations W-8 and W-9. Specifically, for Calculation Methods 2 and 3, reporters must provide a plunger lift indicator (i.e., whether plunger lifts were used), total number of wells with well venting for liquids unloading, the total number of unloading events, and the casing diameter (Calculation Method 2) or the tubing diameter (Calculation Method 3).
In a 2019 study, Zaimes et al. evaluated various liquid unloading scenarios, and the results indicated that differentiating emissions only on the basis of type of unloading (plunger or non-plunger lift) may not accurately assess emissions from this source. In particular, Zaimes et al. noted that type of unloading should be further differentiated for plunger lift unloadings between automated and manual unloadings, suggesting further granularity is necessary to properly characterize emissions. In particular, there could be significant differences in the number and duration of unloadings and, hence, differences in emissions between manual and automated plunger lift unloadings and liquids unloading emissions.
The Zaimes et al. study did not evaluate manual and automated non-plunger lift unloadings separately, but further differentiating non-plunger lift unloadings between manual and automated unloadings in subpart W could also improve data quality. Correspondence with reporters via e-GGRT since subpart W reporting for the onshore production segment began in 2011 indicates potentially significant differences in the number of unloadings and emissions for manual versus automated non-plunger lift unloadings. When the EPA finalized the calculation methods and reporting requirements for well venting for liquids unloading, the reporting requirements did not differentiate between manual and automated non-plunger lift unloadings. However, reporters have clearly affirmed the use of automated non-plunger lift unloadings in response to multiple inquiries the EPA has made as part of the annual report verification process.
In addition, there are several data elements used to calculate emissions from liquids unloading in Equations W-8 and W-9 for Calculation Methods 2 and 3 that are not currently required to be provided. Specifically, reporters do not report well depth (Calculation Method 2) or tubing depth (Calculation Method 3), the average flow-line rate of gas, the hours that wells are left open to the atmosphere during unloading events, and the shut-in, surface or casing pressure (Calculation Method 2) or the flow-line pressure (Calculation Method 3). Requiring reporting of these data elements would improve verification of annual reports to the GHGRP and would allow the EPA and the public to replicate calculations and more confidently confirm reported calculated emissions than is currently possible.
The EPA is, therefore, proposing to revise the reporting requirements in 40 CFR 98.236(f)(1) and (2) to require reporters to include the following data elements, consistent with section II.A.4 of this preamble. In 40 CFR 98.236(f)(1), for Calculation Method 1, the EPA is proposing that reporters would identify the type of unloading as an automated or manual unloading in addition to identifying whether the unloading is a plunger lift or non-plunger lift unloading. We are also proposing that reporters would report emissions from automated unloadings separately from manual unloadings. In addition, for each individual Calculation Method 1 well that was tested during the year, we are proposing that reporters would specify the type of unloading as an automated or manual unloading under 40 CFR 98.236(f)(1)(xi)(F) or 40 CFR 98.236(f)(1)(xii)(F), as applicable.
For non-plunger lift unloadings that use Calculation Method 2 in 40 CFR 98.233(f)(2), the EPA is proposing that reporters would identify the type of non-plunger lift unloading as an automated or manual non-plunger lift unloading and that reporters would report emissions and activity data separately for each unloading type. In addition, for all non-plunger lift unloadings, the EPA is proposing to add requirements in 40 CFR 98.236(f)(2)(ix) (proposed to be moved to 40 CFR 98.236(f)(2)(xi)) to report the average well depth for all wells in the sub-basin (WDp) and the average shut-in pressure or surface pressure for wells with tubing production, or average casing pressure for wells with no packers for all wells in the sub-basin (SPp).
For plunger lift unloadings that use Calculation Method 3 in 40 CFR 98.233(f)(3), the EPA is proposing that reporters would identify the type of plunger lift unloading as an automated or manual plunger lift unloading and that reporters would report emissions and activity data separately for each unloading type. In addition, for all plunger lift unloadings, the EPA is proposing to add requirements in 40 CFR 98.236(f)(2)(x) (proposed to be moved to 40 CFR 98.236(f)(2)(xii)) to report the average tubing depth to plunger bumper for all wells in the sub-basin (WDp) and the average flow-line pressure for all wells in the sub-basin (SPp). Finally, for all unloadings that use Calculation Method 2 or 3, the EPA is proposing to add requirements in 40 CFR 98.236(f)(2)(ix) and (x) to report the average flow-line rate of gas for all wells in the sub-basin (SFRp) and cumulative number hours that all wells in the sub-basin are left open to the atmosphere during unloading events (HRp,q), respectively.
f. Blowdown Vent Stacks
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)). Stakeholders have indicated that there is some confusion regarding the reference to "distribution" pipelines in the descriptions of the "facility piping" and "pipeline venting" categories because compressor stations are not associated with distribution pipelines. Therefore, the EPA is proposing to revise the descriptions of the facility piping and pipeline venting categories to reduce confusion regarding which equipment or event type category is appropriate for each blowdown, consistent with section II.A.5 of this preamble. Our intent is that the "facility piping" equipment category is limited to unique physical volumes of piping (i.e., piping between isolation valves) that are located entirely within the facility boundary. Conversely, the intent for the "pipeline venting" equipment category is that a portion of the unique physical volume of pipeline is located outside the facility boundary and the remainder, including the blowdown vent stack, is located within the facility boundary. The proposed revisions to the equipment type descriptions would clarify these distinctions. Additionally, we are proposing to remove the reference to "distribution" pipelines because we did not intend to limit the pipeline venting category to unique physical volumes that include such pipelines. We agree with the industry stakeholders that facilities subject to the blowdown vent stack reporting requirements typically are connected to other pipelines such as gathering pipelines or transmission pipelines, and on-site blowdowns from sections of these pipelines should be reported. Finally, we note that for the "facility piping" equipment category and the "pipeline venting" equipment category, the phrase "located within a facility boundary" generally refers to being part of the facility as defined by the existing provisions of subpart A or subpart W, as applicable. In other words, blowdowns from unique physical volumes of gathering pipeline that are entirely considered to be part of the "facility with respect to onshore petroleum and natural gas gathering and boosting" as defined in 40 CFR 98.238 would be assigned to the "facility piping" equipment category. The "pipeline venting" equipment category would only apply if the unique physical volume includes some sections of gathering pipelines that are not part of the "facility with respect to onshore petroleum and natural gas gathering and boosting" as defined in 40 CFR 98.238.
g. Atmospheric Storage Tanks
Open Thief Hatches. Facilities in the Onshore Petroleum and Natural Gas Production and Onshore Petroleum and Natural Gas Gathering and Boosting industry segments are required to report CO2 and CH4 emissions (and N2O emissions when flared) from atmospheric pressure fixed roof storage tanks receiving hydrocarbon liquids (hereafter referred to as "atmospheric storage tanks"). The purpose of a thief hatch on an atmospheric storage tank is generally to allow access to the contents of the tank for sampling, gauging, and determining liquid levels. The thief hatch also works along with the vent valve to maintain pressure on the tank while preventing excessive vacuum from collapsing the tank. The EPA previously evaluated emissions from atmospheric storage tanks as part of the 2016 amendments to subpart W (81 FR 86500, November 30, 2016) and determined that the subpart W calculation methodology in 40 CFR 98.233(j) already includes emissions from thief hatches or other openings on atmospheric storage tanks in the Onshore Petroleum and Natural Gas Production and Onshore Petroleum and Natural Gas Gathering and Boosting industry segments. The subpart W calculation methodologies for controlled atmospheric storage tanks include procedures for determining emissions from storage tanks with a vapor recovery system (40 CFR 98.233(j)(4)) and storage tanks with a flare (40 CFR 98.233(j)(5)). The procedure for determining emissions from a tank with a vapor recovery system instructs reporters to adjust the storage tank emissions downward by the magnitude of emissions recovered using a vapor recovery system as determined by engineering estimate based on best available data (40 CFR 98.233(j)(4)(i)). The procedure for determining emissions from an atmospheric storage tank with a flare references 40 CFR 98.233(n), which instructs reporters to use engineering calculations based on process knowledge, company records, and best available data to determine the flow to the flare if the flare does not have a continuous flow measurement device. If a reporter sees emissions from a thief hatch or other opening on a controlled atmospheric storage tank during an equipment leak survey conducted using OGI, the reporter should consider that information as part of the "best available data" used to calculate emissions from that storage tank.
However, it appears that emissions from open thief hatches on atmospheric storage tanks may not be accurately portrayed in subpart W, as many reporters claim 100 percent capture efficiency from vapor recovery systems and flares. In order to alleviate any reporting confusion, the EPA is proposing several clarifying edits to 40 CFR 98.233(j)(4) and (5), consistent with section II.A.5 of this preamble. We are proposing to specifically state in each paragraph that emissions during times of reduced capture efficiency are required to be evaluated to determine if adjustments are needed to the calculated recovered mass from vapor recovery units or flare feed gas volumes. Reduced capture efficiency may occur during periods when the control device is not operating or is bypassed and at times when the control device is operating, such as open thief hatches. The emissions that are not captured by a vapor recovery system or sent to a flare must be considered when calculating emissions from atmospheric storage tanks vented directly to the atmosphere.
The EPA is also proposing revisions to the atmospheric storage tank reporting requirements in 40 CFR 98.236(j) with regard to open thief hatches. Specifically, the EPA is proposing to require reporting of the number of controlled tanks with open or unseated thief hatches within the reporting year, as well as the total volume of gas vented through the open or unseated thief hatches. With these new reporting elements, the EPA seeks to quantify the impact of open thief hatches on atmospheric storage tanks and enhance the overall quality of the data collected under the GHGRP, consistent with section II.A.4 of this preamble.
Malfunctioning Dump Valves and Atmospheric Storage Tanks with Flares. For Onshore Petroleum and Natural Gas Production and Onshore Petroleum and Natural Gas Gathering and Boosting facilities with atmospheric storage tank emissions calculated using Calculation Method 1 (40 CFR 98.233(j)(1)) or Calculation Method 2 (40 CFR 98.233(j)(2)), reporters must also follow the procedures in 40 CFR 98.233(j)(6) and use Equation W-16 to calculate emissions from occurrences of gas-liquid separator dump valves not closing properly. Equation W-16 estimates the annual volumetric GHG emissions at standard conditions from each storage tank resulting from the malfunctioning dump valve on the gas-liquid separator using a correction factor, the total time the dump valve did not close properly in the calendar year, and the hourly storage tank emissions. Per the definition of the variable "En" in Equation W-16, the input hourly storage tank emissions should be those calculated using Calculation Methods 1 or 2 and should be adjusted downward by the magnitude of emissions recovered using a vapor recovery system, if applicable. However, the definition of the variable "En" in Equation W-16 does not include the procedure to be used for emissions from malfunctioning dump valves and atmospheric storage tanks that are flared. In order to address any confusion for reporters, the EPA is proposing to amend the definition of the variable "En" in Equation W-16 to include flared storage tank emissions as determined in paragraph 40 CFR 98.233(j)(5), consistent with section II.A.5 of this preamble. The EPA is also proposing to revise the equation variables (particularly the subscripts) in Equation W-16 to clarify the intent of this equation. We are proposing to revise the variable "En" to "Es,i" to further clarify that these are the volumetric atmospheric storage tank emissions determined using the procedures in 40 CFR 98.233(j)(1) through (5). We are also proposing to replace the "n" and "p" subscripts in the other variables with a "dv" subscript to indicate that these are the emissions from periods when the gas-liquid separator dump valves were not closed properly and that the emissions from these periods should be added to the emissions determined using the procedures in 40 CFR 98.233(j)(1) through (5).
Composition of Hydrocarbon Liquids. Under 40 CFR 98.236(j)(1)(vii) and (viii), reporters with atmospheric storage tank emissions calculated using Calculation Method 1 or Calculation Method 2 are required to provide the minimum and maximum concentrations (mole fractions) of CO2 and CH4 in the tank flash gas. Reporting of emissions and activity data for atmospheric storage tanks is aggregated at the sub-basin or county level, and the minimum and maximum flash gas concentrations were expected to provide the EPA with a broad characterization of the often-significant number of tanks reported for each sub-basin or county. However, through correspondence with reporters via e-GGRT, the EPA has found that the minimum and maximum flash gas concentrations do not accurately represent the majority of atmospheric storage tanks within the reported sub-basins and counties. Thus, the EPA is proposing to revise these two reporting requirements to request the flow-weighted average concentration (mole fraction) of CO2 and CH4 in the flash gas, rather than the minimum and maximum values. Consistent with section II.A.4 of this preamble, the EPA expects that these revisions would improve both the representative nature of the data collected and the process of verifying annual reported atmospheric storage tanks emissions data under the GHGRP.
h. Associated Gas Venting and Flaring
Associated Gas Venting. Associated gas venting or flaring is the venting or flaring of natural gas that originates at wellheads that also produce hydrocarbon liquids and occurs either in a discrete gaseous phase at the wellhead or is released from the liquid hydrocarbon phase by separation. Venting associated gas involves directly releasing associated gas into the atmosphere at the well pad or tank battery. Flaring associated gas is a common, and usually preferred, alternative to venting for safety and environmental reasons. Subpart W requires reporters to calculate annual emissions from associated gas venting and flaring using Equation W-18, which uses the gas-to-oil ratio (GOR), volume of oil produced, and volume of associated gas sent to sales to calculate the volume of gas vented. Associated gas venting emissions are then calculated using the results of Equation W-18 and the gas composition determined using 40 CFR 98.233(u), and associated gas flaring emissions are calculated by applying the calculation method of flare stacks in 40 CFR 98.233(n) to the associated natural gas volume and gas composition determined for the associated gas stream routed to the flare.
As discussed further in section III.J.1.i of this preamble, the EPA is proposing several amendments to the calculation and reporting requirements for flare stacks that would impact associated gas flaring emissions. One of the proposed amendments would provide for the use of continuous flow measurement devices for the purposes of calculating flared emissions. Similarly, for associated gas venting emissions, we are proposing provisions to specify that if a continuous flow measurement device is present, it must be used to determine the volume of gas vented rather than Equation W-18. We are proposing corresponding reporting requirements for associated gas venting emissions, including requiring an indication of whether a continuous flow monitor or continuous composition analyzer was used and the flow-weighted mole fractions. Finally, we are proposing to specify that if all of the volumetric emissions from associated gas venting and flaring in the sub-basin were determined using a continuous flow measurement device rather than Equation W-18 (i.e., Equation W-18 was not used for any wells in the sub-basin), then reporting of the GOR, the volume of oil produced, and the volume of gas sent to sales for wells with associated gas venting or flaring is not required for that sub-basin.
Oil and Gas Volumes. As noted previously in this section, subpart W requires reporters to calculate annual emissions from associated gas venting and flaring using Equation W-18. Two of the inputs in the equation are the volume of oil produced and volume of associated gas sent to sales for each well in the sub-basin during time periods in which associated gas was vented or flared. However, based on the values reported, there seems to be confusion among some reporters regarding the inputs to these equations. For example, for some reporters, when the reported volume of gas sent to sales during time periods in which associated gas was vented or flared under 40 CFR 98.236(m)(6) is summed across all sub-basins at the facility, the total is the same as the total volume of gas sent to sales for the facility reported under 40 CFR 98.236(aa)(1)(i)(B). If these reporters are accurately reporting the volume of gas sent to sales and using that volume in Equation W-18, then the associated gas venting and flaring emissions are likely overstated, as it is unlikely that all wells are venting or flaring associated gas 100 percent of the time. If the reporters are using accurate volumes of gas sent to sales during time periods in which associated gas was vented or flared for their emissions calculations but reporting total gas sent to sales, then the activity data reported do not match the emissions, leading to an inconsistent data set. Therefore, the EPA is proposing to add the word "only" to the definitions of the terms Vp,q and SGp,q in Equation W-18 (40 CFR 98.233(m)(3)) and to the reporting requirements for those data elements in 40 CFR 98.236(m)(5) and (6). Consistent with section II.A.5 of this preamble, these proposed amendments would reduce reporter confusion regarding the volumes that should be used in the emissions calculations and the volumes that should be reported.
i. Flare Stack Emissions
Flare stacks are an emission source type subject to emissions reporting by facilities in seven of the ten industry segments in the Petroleum and Natural Gas Systems source category. Total CO2, CH4, and N2O emissions from each flare are required to be calculated using the methodology specified in 40 CFR 98.233(n). In addition to calculating total emissions from a flare, reporters must also separately calculate the flared emissions from several types of emission sources. The methodology for calculating source-specific flared emissions is specified in the applicable paragraph of 40 CFR 98.233 for each source type. The procedures in the source-specific paragraphs of the rule cross-reference the calculation procedures in 40 CFR 98.233(n), but they also specify that the volume and composition of the gas routed to the flare are required to be determined according to the procedures for estimating vented emissions from the specific source type. For example, 40 CFR 98.233(e)(6) specifies that the volume and gas composition to use in calculating flared emissions from dehydrators must be determined according to the procedures for calculating vented emissions from dehydrators as specified in 40 CFR 98.233(e)(1) through (5). Since source-specific flared emissions often are a portion of the total emissions from a flare, 40 CFR 98.233(n)(9) specifies that the total CO2, CH4, and N2O for a particular flare must be adjusted downward by the amount of the source-specific emissions that are calculated for the same flare; this ensures that emissions from a flare are not double counted (i.e., reported for both the flare stacks source type and another emission source type). The resulting CO2, CH4, and N2O emissions to report for that flare according to 40 CFR 98.236(n)(9) through (11) should be only what is left after subtracting all of the source-specific flared emissions from the total emissions.
This calculation and reporting paradigm often means zero mass emissions are reported for the flare because all of the mass emissions are reported as flared emissions from other source types. However, even when the only streams routed to a flare are from source types that are subject to flared emissions reporting, the flare name or ID and all activity data related to the streams that are routed to the flare and the flare operating characteristics still must be reported under 40 CFR 98.236(n). These activity data include the volume of gas routed to the flare, average CO2 and CH4 mole fractions in the flared gas, flare combustion efficiency, fraction of flared gas routed to the flare when it was unlit, and indicators of whether a continuous flow measurement device and a continuous gas analyzer were used on the gas stream routed to the flare. These flare ID and activity data reporting requirements are specified in 40 CFR 98.236(n)(1) through (8). In the rare cases that a CEMS is used on the outlet of a flare, then according to 40 CFR 98.236(n)(12), only the flare ID and the measured CO2 emissions must be reported.
Reporting Requirements for Flared Emissions. Many reporters have provided information through the GHGRP Help Desk and in correspondence with the EPA via e-GGRT indicating that reporters are not interpreting the reporting requirements as written and as the EPA intended for flares that receive gas from sources that are subject to source-specific flared emissions reporting (e.g., atmospheric tanks). A key misconception is that the adjustment requirement in 40 CFR 98.233(n)(9) applies to all flare data, not just the mass emissions (as intended). Thus, some reporters provide information for a flare only if some of the mass emissions from the flare are due to combustion of gas from source types that are not subject to source-specific flared emissions reporting (i.e., miscellaneous flared sources). Although these reporters generally correctly report the mass emissions from the flare that are due to the miscellaneous flared sources, they incorrectly limit their activity data reporting to those same streams. The EPA has procedures in its verification process to identify such errors; if errors are identified, the EPA notifies the reporter, who can resolve the issue by correcting the data and resubmitting their annual GHG report. Some reporters have also indicated that it is confusing to report activity data for a flare in one table in the reporting form (i.e., Table N.1), but to report the emissions in different tables; they suggest that it would be clearer to report all flare activity data and emissions related to a particular emission source type together in one location. One industry stakeholder, GPA Midstream, also suggested that flare activity data should be reported in the same manner that flared emissions are reported. In other words, instead of providing a single comprehensive record of the activity data per flare as is currently required by 40 CFR 98.236(n), the activity data for flared streams for a particular emission source (e.g., associated gas or atmospheric storage tanks) should be reported with the flared emissions for the same emission source type. According to GPA Midstream, this reporting approach would be simpler and easier for reporters to follow than the current requirements. We reviewed the flare reporting requirements based on this feedback, and we are proposing several revisions to the reporting requirements to improve the quality of the reported data, consistent with section II.A.4 of this preamble.
First, we are proposing to modify the reporting requirements so that the existing requirements in 40 CFR 98.236(n) would apply only to flares that receive gas from miscellaneous flared sources. The activity data to report would be limited to the streams from the miscellaneous flared sources, and the CO2, CH4, and N2O emissions to report would be the emissions that are calculated from combustion of the same streams. In addition, we would add comparable activity data reporting requirements to the reporting required for all of the source types for which flared emissions reporting is currently required (e.g., 40 CFR 98.236(e) for dehydrators, 40 CFR 98.236(g) for completions and workovers with hydraulic fracturing). The activity data reporting would be on the same basis as the emissions reporting. For example, activity data for glycol dehydrators with an annual average daily natural gas throughput greater than or equal to 0.4 MMscf per day would be related to the flared streams from each dehydrator because flared emissions are reported per dehydrator. Activity data to be reported for associated gas streams, on the other hand, would be aggregated over all associated gas streams routed to flares in a sub-basin because flared associated gas emissions are reported per sub-basin. In addition, for completions and workovers with hydraulic fracturing, flaring during the initial flowback period may not be possible; therefore, some of the wells that report as part of a "flared" well type combination because most of the gas is flared may also include emissions from gas that is vented before flaring begins. To improve our understanding of the characteristics of the "flared" emissions from completions and workovers with hydraulic fracturing, we are proposing that reporters would indicate in 40 CFR 98.236(g)(10)(i) whether the total emissions reported under 40 CFR 98.236(g)(8) and (9) include emissions from venting during the initial flowback period. These proposed amendments would better align the flared emissions and activity data for source types for which flared emissions reporting is currently required.
Second, in the current rule, 40 CFR 98.236(n)(7) and (8) require reporting of the CH4 and CO2 mole fractions in feed gas that are used in Equations W-19 and W-20 to calculate total emissions from a flare. The intent was for reporters to provide the average values used to calculate total emissions from the flare. However, the rule language is not clear on this point, and it appears some reporters have interpreted these data elements in different ways. It appears that one common interpretation is to report the mole fraction for the emissions source type with the most flared emissions. Because that interpretation does not align with the EPA's intent, clarification of this reporting requirement is needed to improve the verification process. Thus, we are proposing to modify these reporting elements, both in 40 CFR 98.236(n) (proposed to be moved to 40 CFR 98.236(n)(1)(ix) and (x)) and for all the proposed activity data reporting elements for individual source types that are subject to source-specific flared emissions reporting as described above. Specifically, we are proposing to require the flow-weighted annual average mole fraction of CH4 over all streams from a particular emission source type that are used in Equation W-19 to calculate the reported flared CH4 emissions from that emission source type (and used in Equation W-20 to calculate CO2 emissions). For example, if a flare receives gas from an acid gas removal vent and a blowdown vent stack, both of which are miscellaneous flared sources, then the CH4 mole fraction to report should be the flow-weighted annual average value from the acid gas removal vent and each blowdown through the blowdown vent stack. The CO2 mole fractions to report would also be a flow-weighted annual average determined in the same manner.
Third, reporters are required to use Equation W-40 to calculate N2O emissions from flares. Variables in the equation are the volume of gas routed to the flare and the HHV of the gas. The volume of gas routed to the flare must be reported, but the HHV is not reported. As a result, when reported N2O emissions differ significantly from the amount that would be expected if using the default HHV, it can be difficult for the EPA to determine whether the reported emissions are an error or if the difference is due to the use of a site-specific HHV. To improve the verification process and potentially reduce the amount of communication with reporters via e-GGRT, we are proposing to add a reporting element that would require reporters to indicate whether each reported N2O value is based on the default HHV, a site-specific HHV(s), or both the default and site-specific HHVs. The proposed reporting element would be added in 40 CFR 236(n)(4)(iv) for miscellaneous flared sources, and it would be included as one of the proposed activity data reporting elements for each of the other source types that are subject to source-specific flared emissions reporting. Providing an option to indicate that both types of HHVs are used is needed because some reported flared N2O emissions are aggregated values over all flares in a sub-basin or county (e.g., for atmospheric tanks), and a reporter may choose to use different methods for the flares in each sub-basin or county. In addition to improving the verification process, knowledge of site-specific HHVs would allow the EPA to assess how well the default HHV characterizes flared gas streams in different industry segments and basins.
Fourth, an additional finding from the currently reported data is that a number of facilities in the Onshore Petroleum and Natural Gas Production industry segment, the Onshore Petroleum and Natural Gas Gathering and Boosting industry segment, and the Onshore Natural Gas Processing industry segment report significant amounts of emissions from miscellaneous flared sources. It is not clear what sources are generating the large amount of gas that is routed to these flares. To help clarify the source types that are generating large amounts of flared gas, we are proposing in 40 CFR 98.236(n)(1)(v) to require reporting by facilities in these three industry segments of an estimate of the fraction of the gas burned in the flare that is obtained from other facilities specifically for flaring as opposed to being generated in on-site operations. As an example, if an owner or operator has an onshore petroleum and natural gas production and an onshore petroleum and natural gas gathering and boosting facility in the same basin and routes associated gas from wells in the onshore petroleum and natural gas production facility to a flare that is defined as part of the onshore petroleum and natural gas gathering and boosting facility, then the flared emissions would be reported by the onshore petroleum and natural gas gathering and boosting facility as emissions from "other flare stacks" sources under the current rule (or from miscellaneous flared sources under the proposed amendments). If the other gas streams routed to the flare are from sources at the onshore petroleum and natural gas gathering and boosting facility, then for this proposed reporting requirement, the onshore petroleum and natural gas gathering and boosting facility report would include an estimate of the fraction of the total gas burned in the flare that is associated gas from the onshore petroleum and natural gas production facility. We request comment on the types of sources that may be generating these large emissions and whether other reporting elements could be specified that would better achieve the EPA's objective of clearly characterizing the sources of flared emissions from facilities in the three industry segments identified above. For example, one potential additional reporting element could be a requirement to describe the primary source of miscellaneous flared emissions for any flare that reports CO2 emissions greater than an amount that would be determined if such a reporting requirement were finalized.
Finally, one objective of the current flare reporting requirements is to obtain information on the total number of flares and their operating characteristics. If the proposed changes to flare activity data requirements as described previously in this section were finalized, then additional amendments to reporting requirements would be needed to continue collecting flare-specific information. Thus, we are proposing to require reporting of a list of all flare IDs per facility and add reporting for a series of flare-specific data elements. One of the proposed flare reporting elements is the total volume of gas routed to the flare. This information is consistent with current reporting requirements and would be helpful in conducting verification of other reported flare data because the sum of the total volume from all flares should be equal to the sum of the disaggregated volumes reported for all flared emissions source types. The total volumes per flare also would provide information on the range of flare sizes in different industry segments and would be useful in analyses for potential future policy decisions related to flares. Another of the proposed flare reporting elements is a list of the subpart W emission source types that routed emissions to the flare stack. This proposed data element would improve verification of other reported flare data as well as provide information regarding the types of sources that are combined and routed to the same flare. We are also proposing a few new flare-specific reporting elements to help us better understand the state of flaring in the industry, such as an indication of the type of the flare (e.g., open ground-level flare, enclosed ground-level flare, open elevated flare, or enclosed elevated flare) and the type of flare assist (e.g., unassisted, air-assisted (with indication of single-, dual-, or variable-speed fan), steam-assisted, or pressure-assisted). Further, researchers conducting remote sensing tests of emissions from flares have reported detecting much larger quantities of emissions from un-lit flares than is evident from the GHGRP data. To help us better understand the prevalence of emissions from un-lit flares, we are proposing to add requirements to report an indication of whether the flare has a continuous pilot or autoigniter, whether the presence of flame is continuously monitored if the flare has a continuous pilot, and an indication of how the reporter identifies periods when the flare is not lit if the flare does not have a continuous pilot. These proposed data elements would be added in 40 CFR 98.236(n). This paragraph of subpart W would be rearranged into two subparagraphs. The first subparagraph, 40 CFR 98.236(n)(1), would include the current activity data and emissions data reporting elements but would be revised to be specific to miscellaneous flared sources (as discussed previously), and the proposed flare-specific reporting elements would be added in the second subparagraph, 40 CFR 98.236(n)(2).
Definition of Flare Stack Emissions. In response to a verification message in e-GGRT, one reporter noted that the definition of the term "flare stack emissions" in 40 CFR 98.238 does not include CO2 that is in streams routed to the flare. The term is currently defined to mean "CO2 and N2O from partial combustion of hydrocarbon gas sent to a flare plus CH4 emissions resulting from the incomplete combustion of hydrocarbon gas in flares." Based on this definition, the reporter concluded that CO2 in streams routed to the flare are not to be reported as flare stack emissions. However, the current definition, which was added to the 2010 final rule after consideration of comments on the 2010 re-proposal, does not clearly convey the EPA's intent that the CO2 that enters a flare should be reported as flare stack emissions. This intent is evident from the fact that Equation W-20 includes a term for the inlet gas volume times the CO2 mole fraction in the inlet gas. Additionally, in a response to a comment on the 2010 proposed rule, the EPA clearly stated that the total quantity of CO2, including both combusted CO2 (i.e., CO2 created in the flare) and uncombusted CO2 (i.e., CO2 that entered and simply passed through the flare), is to be calculated. Another issue with the current definition is that it implies N2O emissions only result from partial combustion of hydrocarbons in the gas routed to the flare. This is likely the primary mechanism for generating N2O emissions when combusting fuels that include nitrogen-containing compounds. However, natural gas and field gas have negligible amounts of fuel-bound nitrogen. For combustion of these fuels, it appears the N2O is generated primarily from converting thermal NOx under certain operating conditions in the flare. To eliminate the unintended inconsistency between the definition and the intent that CO2 in gas routed to the flare is to be reported as emissions from the flare, to clarify the requirement to calculate and report total CO2 that leaves the flare, and to clarify the source of flared N2O emissions, we are proposing to revise the definition of the term "flare stack emissions" to mean CO2 in gas routed to a flare, CO2 from partial combustion of hydrocarbons in gas routed to a flare, CH4 resulting from the incomplete combustion of hydrocarbons in gas routed to a flare, and N2O resulting from operation of a flare.
Calculation Methodology for Flared Emissions. In addition to proposing changes to the flare reporting requirements as discussed above, we are also proposing to clarify language in the emission calculation procedures of 40 CFR 98.233(n) that we believe may be ambiguous for flares that do not have CEMS, consistent with section II.A.5 of this preamble. The procedures for determining the volume and composition of gas routed to flares for use in the emission calculation equations for a particular emission source type are currently specified in two places for each source type. Each source type-specific paragraph in 40 CFR 98.233 specifies calculation methodologies for that emissions source type, as do 40 CFR 98.233(n)(1) and (2). The procedures in the source type-specific requirements specify only that the volume and composition of the flared gas are to be determined using the procedures for estimating vented emissions from that source type, but they also cross-reference the calculation method in 40 CFR 98.233(n) for determining the emissions from the flaring of that gas stream. However, 40 CFR 98.233(n)(1) and (2) specify that if continuous flow or composition measurement devices are used on the gas to the flare, then data from those devices must be used to calculate emissions; otherwise, estimates may be used. The intent is that the procedures in 40 CFR 98.233(n) should take precedence, but this may not be clear to all reporters. Additionally, the procedures for continuous measurement devices in 40 CFR 98.233(n)(1) and (2) refer to devices "on the flare" or "on gas to the flare." The intent is that the procedures should apply to devices regardless of whether they are on a stream routed from a single emission source or on a stream routed to a flare that includes streams combined from multiple emission source types, but this is not explicitly described. A third potential ambiguity is that procedures in 40 CFR 98.233(n)(1) and (2) do not specify how to disaggregate data collected with a continuous measurement device when the device measures a combined stream from more than one emission source type.
To clarify these requirements, we are proposing to specify all of the potential options for determining volume and composition of gas to the flare(s) in the applicable sections of 40 CFR 98.233 for each of the emission source types that have flared emissions reporting requirements. In general, the volume of gas would be determined by a continuous flow measurement device, if available, or using the methods for determining vented emissions for the applicable emission source type. If the measured volume includes flow from multiple source types routed to the same flare, reporters would use process knowledge and best available data to determine the portion of the total flow from each emission source type. Similarly, the composition of the gas from the emission source type would be determined by a continuous composition analyzer, if available, or using the methods for determining the composition of the vented emissions for the applicable emission source type. Alternatively, if multiple source types are routed to one flare and the gas routed to the flare from each of those source types is expected to have similar compositions, the reporter could measure the composition of the total gas to the flare using a continuous composition analyzer just upstream of the flare and apply the results to each of the applicable source types. The source-specific sections of 40 CFR 98.233 would then cross-reference only 40 CFR 98.233(n)(3) through (8) for the applicable calculation equations and procedures for determining combustion efficiency, converting volumetric emissions to mass emissions, and the separate procedures that apply if a CEMS is used on gases from the flare. As part of this proposed amendment, we would also remove 40 CFR 98.233(n)(9); with these proposed calculation methodology clarifications and the reporting clarifications described earlier in this section, a general direction to correct flare emissions to avoid double counting would no longer be necessary (however, a provision specifically to avoid double counting of CO2 emissions from acid gas removal units that route emissions to a flare would still be needed, as discussed later in this section). We recognize that the proposed changes introduce some repetition to the regulatory text overall because the requirements for each emission source type are similar. However, clearly describing the applicable procedures for each source type separately rather than trying to generally describe a single set of consolidated procedures would make the rule easier for reporters to understand, and we request comment on whether the proposed changes achieve this goal.
Calculation Methodologies for Flared Emissions from Acid Gas Removal Vents. We are also proposing source type-specific provisions for calculating and reporting emissions from acid gas removal vents routed to flares that are related to the proposed calculation methodology clarifications described earlier in this section, consistent with section II.A.5 of this preamble. Reporters are currently required to report the CO2 removed from the natural gas as CO2 emissions from acid gas removal vents, and that quantity is not affected (i.e., the CO2 is not converted to another compound) when the acid gas vent stream is routed to a flare, engine, or sulfur recovery plant. Therefore, the current rule does not require reporters to separate emissions vented directly to the atmosphere from emissions routed through a flare, engine, or sulfur recovery plant. Instead, as noted earlier in this section, 40 CFR 98.233(n)(9) specifies that the total CO2 for a flare that receives gas from acid gas removal vents must be adjusted downward by the amount of the CO2 emissions that are calculated for those acid gas removal vents. In other words, the CO2 emissions that are calculated for the acid gas removal vents are reported under 40 CFR 98.236(d) and not under 40 CFR 98.236(n).
Because the reporting of emissions from acid gas removal vents routed to a flare is addressed differently in the current rule from the reporting of flared emissions for all other source types, we are proposing amendments for acid gas removal vents routed to flares that are slightly different than the proposed amendments for other sources. First, as noted previously in this section, we are proposing to remove 40 CFR 98.233(n)(9) because it would be unnecessary for other source types in light of the other amendments previously described. However, for acid gas removal vents routed to flares, an adjustment would still be necessary for CO2 emissions. Therefore, we are proposing to add provisions in 40 CFR 98.233(d)(12) for calculating emissions from acid gas removal vents routed to flares (as described in more detail in the next paragraph) and proposing to add a clarification to the requirement to report CO2 emissions from flare stacks (40 CFR 98.236(n)(9), proposed to be moved to 40 CFR 98.236(n)(1)(xi)) indicating that the reported CO2 emissions should not include emissions from acid gas removal vents reported under 40 CFR 98.236(d)(1)(v) to prevent double counting of emissions.
Second, we reviewed the calculation methods for acid gas removal vents and flares, and we are proposing amendments to more closely align the methods for acid gas removal vents routed to flares. For acid gas removal vents, Calculation Method 1 (40 CFR 98.233(d)(1)) is required to be used if a vent has a CEMS installed, and Calculation Method 2 (40 CFR 98.233(d)(2)) is required to be used if a vent has a continuous flow monitor. If there is no CEMS or flow monitor installed, then reporters currently must use Calculation Methods 3 or 4 (40 CFR 98.233(d)(3) or (4), which are estimation methods based on the volume of natural gas treated and the acid gas contents of the inlet and outlet natural gas. However, because these are estimation methods rather than methods based on measurements, the EPA has found through the verification process and correspondence with reporters via e-GGRT that these methods can sometimes result in estimated volumetric CO2 emissions from acid gas removal vents routed to a flare that are greater than the reported total volume of gas routed to that flare. Therefore, we are proposing new provisions in 40 CFR 98.233(d)(12) for reporters routing acid gas removal vents to flares. The first set of amendments would apply to acid gas removal vents that are routed to any dedicated flare as well as acid gas removal vents comingled with emissions from other source types and routed to flares with no continuous monitors for either the flow or composition of the comingled gas stream. In either of these cases, reporters would continue to calculate CO2 emissions using one of the Calculation Methods 1 through 4, as applicable for the type of monitoring available, and would continue to report those emissions under 40 CFR 98.236(d) rather than 40 CFR 98.236(n). Reporters would also incorporate the flow rate and composition of the acid gas removal vent stream into the calculation of total flare emissions from miscellaneous flared sources. For acid gas removal vent streams comingled with emissions from other source types and routed to flares with continuous monitoring of the flow and/or composition of the comingled gas stream, we are proposing that reporters would first determine the total emissions from the flare stacks and then use site-specific engineering estimates based on best available data to estimate the portion of the total flared CO2 emissions that is from the acid gas removal vents. In this case, we are proposing that reporters would select "Routed to a flare [§ 98.233(d)(12)(ii)]" as the calculation method. We are also proposing new reporting requirements for acid gas removal vents routed to flares; in addition to the current requirements to report the CO2 emissions under 40 CFR 98.236(d)(1)(v), we are proposing to add the identification of the flare to which the acid gas removal vent is routed.
j. Compressors
Compressors are used across the petroleum and natural gas industry to raise the pressure of and convey natural gas or CO2. The two main types of compressors used in the industry are centrifugal compressors and reciprocating compressors. Subpart W requires Onshore Petroleum and Natural Gas Production and Onshore Petroleum and Natural Gas Gathering and Boosting facilities to calculate compressor emissions using population emission factors. Population emission factors are multiplied by the count of equipment, in this case compressors of a certain type, to calculate emissions. For the Onshore Natural Gas Processing, Onshore Natural Gas Transmission Compression, Underground Natural Gas Storage, LNG Storage, and LNG Import and Export Equipment industry segments, subpart W requires facilities to annually measure the emissions from the compressor sources applicable to the mode the compressor is in at the time of the measurement; facilities also have the option to continuously measure emissions from a compressor source. The annual measurements are called "as found" measurements because the compressors are to be measured in the mode in which they are found when the measurements are made. The "as found" measurements are required for each centrifugal and reciprocating compressor at least annually, but only for those compressor emission sources that have measurement requirements for the mode in which they are found (i.e., the defined "compressor mode-source combinations"), as described in the following paragraph.