June 2017 Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990-2016: Updates Under Consideration for C02 Emissions This memo discusses C02 emission calculation revisions being considered for multiple segments of natural gas and petroleum systems in the 2018 Inventory of U.S. Greenhouse Gas Emissions and Sinks (GHGI). The EPA is considering C02 methodological revisions for sources and segments that already rely on a subpart W-based CH4 emission calculation methodology or where the CH4 calculation methodology was otherwise recently revised. The subpart W methodology revisions are documented in the following memos: the 2014 HF Completion and Workover memo,1 2015 HF Completion and Workover memo,2 2016 Transmission memo,3 2016 Production memo,4 2017 Production memo,5 and 2017 Processing memo.6 These revisions will create consistency between CH4 and C02 calculation methodologies. In addition, the EPA is considering updating the GHGI to include both the C02 emissions and the relatively minor CH4 emissions from flare stacks reported under subpart W in the production and transmission and storage segments. The sources discussed in this memo include: production segment storage tanks, associated gas venting and flaring, hydraulically fractured (HF) gas well completions and workovers, production segment pneumatic controllers, production segment pneumatic pumps, liquids unloading, production segment miscellaneous flaring, most sources in the gas processing segment, transmission station flares, underground natural gas storage flares, LNG storage flares, LNG import flares, and transmission and storage pneumatic controllers. The EPA is not considering revisions to the distribution segment C02 emissions calculation methodology, as discussed in Section 1.2. 1. Background and Current GHGI Methodology for COz Emissions This section discusses the current GHGI methodology for calculating C02 emissions. Section 1.1 describes a C02-to-CH4 gas content ratio methodology, which is the default approach used in all GHGI segments. Section 1.2 describes the current GHGI methodology to calculate C02 emissions for certain 1 "Overview of Update to Methodology for Hydraulically Fractured Gas Well Completions and Workovers in the Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012 (2014 Inventory)/' available at https://www.epa.gov/ghgemissions/natural-gas-and-petroleum-systems-ghg-inventory-updates-1990-2012- inventory-published. 2 "Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990-2013: Revision to Hydraulically Fractured Gas Well Completions and Workovers Estimate," available at https://www.epa.gov/ghgemissions/natural-gas-and- petroleum-systems-ghg-inventory-updates-1990-2013-inventory-published. 3 "Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990-2014: Revisions to Natural Gas Transmission and Storage Emissions," available at https://www.epa.gov/ghgemissions/natural-gas-and-petroleum-systems-ghg- inventory-additional-information-1990-2014-ghg. 4 "Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990-2014: Revisions to Natural Gas and Petroleum Production Emissions," available at https://www.epa.gov/ghgemissions/natural-gas-and-petroleum-systems-ghg- inventory-additional-information-1990-2014-ghg. 5 "Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990-2015: Revisions to Natural Gas and Petroleum Systems Production Emissions," available at https://www.epa.gov/ghgemissions/natural-gas-and-petroleum- systems-ghg-inventory-additional-information-1990-2015-ghg. 6 "Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990-2015: Revisions to Natural Gas Systems Processing Segment Emissions," available at https://www.epa.gov/ghgemissions/natural-gas-and-petroleum-systems-ghg- inventory-additional-information-1990-2015-ghg. Page 1 of 16 ------- June 2017 sources that rely on emission source-specific methods. The current GHGI C02 EFs are documented in Appendix A. COz-to-CH# Gas Content Ratio Methodology The current GHGI methodology to calculate C02 emission factors (EFs) for the majority of emission sources relies on CH4 emission factors and an assumed ratio of C02-to-CH4 gas content. The C02 EF calculation is shown in equation 1: __ ^ /CO, content \ C02 EF = CH4 EF * I I Equation 1 z 4 VCH4 content/ ^ The default CH4 and C02 content values for sources in natural gas systems are from the 1996 GRI/EPA study/ EIA,8 and GTI's Gas Resource Database9 and summarized in Table 1 below. Table 1. Default Gas Content Values for Natural Gas Systems in the GHGI Segment CH4 Content (vol%) CO; Content (vol%) Production - North East region 78.8 3.04 Production - Mid Central region 0.79 Production - Gulf Coast region 2.17 Production - South West region 3.81 Production - Rocky Mountain region 7.58 Production - West Coast region 0.16 Processing - Before C02 removal 87.0 3.45 Processing - After CO2 removal 1.0 Transmission and Underground NG Storage 93.4 1.0 LNG Storage and LNG Import/Export 93.4 1.16 Distribution 93.4 1.0 For most of the petroleum production sources evaluated in this memo, the GHGI uses a ratio of C02 to CH4 content is set at 0.017 based on the average flash gas C02 and CH4 content from API TankCalc runs. The ratio of C02-to-CH4 gas content methodology is used to calculate venting and fugitive C02 EFs, because the CH4 EFs that are referenced for this methodology represent venting and fugitive emissions, which are predominantly CH4 with minimal C02 emissions. EPA does not use this methodology in the GHGI to calculate C02 EFs for combustion sources such as flares, for which the inverse is true (C02 is predominant, with minimal CH4 emissions). 7 Methane Emissions from the Natural Gas Industry, Volume 6: Vented and Combustion Source Summary, Appendix A. 8 U.S. Energy Information Administration. Emissions of Greenhouse Gases in the United States: 1987-1992, Appendix A. 1994. 9 GRI-01/0136 GTI's Gas Resource Database: Unconventional Natural Gas and Gas Composition Databases. Second Edition. August, 2001. Page 2 of 16 ------- June 2017 1.2 Emission Source-Specific CO2 Calculation Methodologies The current GHGI uses emission source-specific methodologies to calculate C02 emissions from oil and condensate tanks at production sites, AGR units at natural gas processing plants, and production and processing flaring. Qil..and...Cond^nMteJ^nks^LPm^^cMonSites The current GHGI methodology to calculate C02 emissions for oil and condensate tanks uses C02 specific EFs. The EFs were developed using API TankCalc software with varying API gravities. The oil tank EF is the average from API TankCalc runs for oils with API gravity less than 45, and the condensate tank EF considered data with API gravity greater than 45. Condensate tank EFs were determined for both controlled and uncontrolled tanks; the controlled tank EF assumed a control efficiency of 80%. The current GHGI calculates oil tank C02 emissions by applying the oil tank emission factor (EF) to 20% of stripper well production and 100% of non-stripper oil well production. For gas production, the current GHGI methodology estimates tank emissions by applying the condensate tank EF to condensate production in each NEMS region. The current GHGI C02 EF for AGR units at natural gas processing plants relies on gas C02 content only. The difference in the default C02 content before and after C02 removal (3.45% -1.0% = 2.45% of processing plant gas throughput) is assumed to be emitted. Flaring Flaring emissions from the production and processing segments are currently calculated under a single line item in the production segment of natural gas systems. Therefore, flaring emissions are not specifically attributed to the processing segment of natural gas systems or the production segment of petroleum systems. The EF is based on data from ElA's 1996 greenhouse gas emissions inventory, which estimated the amount of C02 released per BTU of natural gas combusted (0.055 g/BTU). The activity data are annual EIA "Vented and Flared" gas volumes (MMcf), which are reported under Natural Gas Gross Withdrawals and Production,10 combined with the estimated national average gas heating value (averaging approximately 1,100 BTU/cf over the time series11). The EIA Vented and Flared data represents a balancing factor amount that EIA calculates to reconcile reported upstream and downstream gas volumes, and assumes is potentially emitted to the atmosphere during production or processing operations; the current GHGI assumes it is all flared. Details on how much of the Vented and Flared gas is potentially emitted during natural gas production, petroleum production, and processing are not available, so the current GHGI assigns it all to natural gas production. Also, the EIA data do not account for gas that is flared prior to metering. Flaring emissions from the transmission and storage segment and distribution segment are not currently calculated in the GHGI. Data are unavailable on flaring emissions in the distribution segment, but they are likely to be insignificant. EPA is not considering revisions to the distribution segment C02 emissions calculation methodology for the 2018 GHGI. 10 EIA Natural Gas Gross Withdrawals and Production, including the Vented and Flared category, is available at https://www.eia.gov/dnav/ng/ng_prod_sum_a_EPGO_VGV_mmcf_m.htm 11 EIA Monthly Energy Review. Table A4 - Approximate Heat Content of Natural Gas (Btu per Cubic Feet). Page 3 of 16 ------- June 2017 2, Available Subpart W Data Subpart W of the EPA's Greenhouse Gas Reporting Program (GHGRP) collects annual operating and emissions data on numerous sources from onshore natural gas and petroleum systems and natural gas processing facilities that meet a reporting threshold of 25,000 metric tons of C02 equivalent (MT C02e) emissions. Onshore production facilities in subpart W are defined as a unique combination of operator and basin of operation, a natural gas processing facility in subpart W is each unique processing plant, a natural gas transmission compression facility in subpart W is each unique transmission compressor station, an underground natural gas storage facility in subpart W is the collection of subsurface storage and processes and above ground wellheads, an LNG storage facility in subpart W is the collection of storage vessels and related equipment, and an LNG import and export facility in subpart W is the collection of equipment that handles LNG received from or transported via ocean transportation. Facilities in the above-mentioned industry segments that meet the subpart W reporting threshold have been reporting since 2011; currently, five years of subpart W reporting data are publicly available, covering reporting year (RY) 2011 through RY2015.12 Subpart W activity and emissions data are used in the current GHGI to calculate CH4 emissions for several production, processing, and transmission and storage sources. C02 emissions data from subpart W have not yet been incorporated into the GHGI. However, facilities use an identical reporting structure for C02 and CH4. Therefore, where subpart W CH4 data have been used, the C02 data may be incorporated in an identical manner. The 2014 HF Completion and Workover memo, 2016 Transmission memo, 2016 Production memo, 2017 Production memo, and 2017 Processing memo discuss in greater detail the subpart W data available for those sources. EPA is also considering GHGI revisions to use subpart W data for C02 emission estimates from miscellaneous production flaring, acid gas removal (AGR) vents, and transmission and storage station flares—sources for which the emissions are not currently calculated with subpart W data in the GHGI. Production segment flare emissions are only reported under the "flare stacks" emission source in subpart W if the flare emissions originate from sources not otherwise covered by subpart W—this emission source is referred to as "miscellaneous flaring" for purposes of this memo. Therefore, the subpart W production flares data do not duplicate flaring emissions reported, for example, under production tank flaring or associated gas flaring. It also ensures all production flaring emissions are reported for facilities that meet the reporting threshold. Flare emissions are calculated using a continuous flow measurement device or engineering calculations, the gas composition, and the flare combustion efficiency. A default flare combustion efficiency of 98% may be applied, if manufacturer data are not available. Under subpart W, gas processing facilities calculate AGR unit C02 emissions using one of four methods: (1) C02 CEMS; (2) a vent stream flow meter with C02 composition data; (3) calculation using an equation with the inlet or outlet natural gas flow rate and measured inlet and outlet C02 composition data; or (4) simulation software (e.g., AspenTech HYSYS or API 4679 AMINECalc). CH4 emissions for AGR units are not reported in subpart W. Transmission, underground natural gas storage, LNG storage, and LNG import stations report emissions from all flaring under the "flare stacks" emission source as of RY2015. Prior to that, flare emissions 12 The GHGRP subpart W data used in the analyses discussed in this memo are those reported to the EPA as of August 13, 2016. Page 4 of 16 ------- June 2017 reported under subpart W were included in the reported emissions for the specific source (e.g., reciprocating or centrifugal compressor). Flare emissions are calculated in subpart W using a continuous flow measurement device or engineering calculations, the gas composition, and the flare combustion efficiency. A default flare combustion efficiency of 98% may be applied, if manufacturer data are not available. 3, Revisions Under Consideration The EPA is considering revising C02 EFs for certain production, natural gas processing, and transmission and storage segment sources to use subpart W data in the exact same manner as CH4 EFs are currently calculated in the GHGI. For purposes of this memo, EPA calculated preliminary C02 EFs using data from the same subpart W reporting years (RY) as were used when developing CH4 EFs for the 2017 GHGI. For the 2018 GHGI, EPA will separately seek stakeholder feedback on potentially using data from other subpart W years to recalculate both CH4 and C02 EFs. In addition, EPA is considering updating the GHGI to incorporate subpart W data for C02 from AGR units, and both the C02 emissions and the relatively minor CH4 emissions from flare stacks. duction C(h Emission Factors The EPA developed preliminary C02 EFs for associated gas venting and flaring, oil and condensate tanks, gas well hydraulically fractured completions and workovers, pneumatic controllers, pneumatic pumps, and liquids unloading in the natural gas and petroleum production segments. The CH4 EFs for these sources were recently revised using subpart W data, and EPA applied the same methodology to calculate C02 EFs. A brief summary of the existing methodology and the resulting C02 EFs are provided below for each source. The EPA is also considering a C02 emissions calculation methodology for miscellaneous production flaring, which is described below. Associated Gas Venting and Flaring Based on the CH4 EF methodology documented in the 2017 Production memo, the EPA calculated oil well associated gas venting and flaring C02 EFs using subpart W data for RY2011 through RY2015. EPA divided the reported associated gas or venting emissions by the number of reported wells with associated gas venting or flaring for each year to calculate EFs. Subpart W C02 data are presented in Table 2, and the calculated C02 EFs are presented in Table 3. Table 2. GHGRP Subpart W C02 Data for Associated Gas Venting and Flaring Year Associated Gas Venting Associated Gas Flaring #Venting Wells Venting CO; Emissions (MMT) #Flaring Wells Flaring CO; Emissions (MMT) 2011 8,863 0.012 5,628 3.72 2012 8,554 0.016 7,259 6.88 2013 6,980 0.005 8,880 9.61 2014 7,264 0.013 12,189 11.05 2015 4,286 0.011 21,606 10.31 Page 5 of 16 ------- June 2017 Table 3. GHGRP Subpart W-based Associated Gas Venting and Flaring C02 EFs (kg/well/yr) Year Venting EF Flaring EF 2011 1,336 661,723 2012 1,902 948,057 2013 773 1,081,842 2014 1,754 906,608 2015 2,675 477,254 Based on the CH4 EF methodology documented in the 2017 Production memo, the EPA calculated oil and condensate tank C02 EFs for several tank categories, using RY2015 subpart W data: large tanks with flaring; large tanks with a vapor recovery unit (VRU); large tanks without controls; small tanks with flaring; small tanks without flaring; and malfunctioning separator dump valves. EPA applied several steps described in the 2017 Production memo to apportion the reported subpart W data to each of the categories. EPA then summed the emissions and divided by the throughput for each tank category. Table 4 presents the resulting C02 EFs. Table 4. GHGRP Subpart W-based Oil and Condensate Tank C02 EFs (kg/bbl/yr) Tank Category Oil Tanks EF Condensate Tanks EF Large Tanks with Flaring 7.16 8.44 Large Tanks with VRU 0.040 0.12 Large Tanks without Controls 0.016 0.020 Small Tanks with Flaring 0.26 1.95 Small Tanks without Flares 0.078 0.28 Malfunctioning Dump Valves 0.013 8.28E-05 HF Gas Well Completions arid Workovers Based on the CH4 EF methodology documented in the 2014 HF Completion and Workover memo and 2015 HF Completion and Workover memo, the EPA calculated C02 EFs for four categories of HF gas well completions and workovers, using RY2011-RY2013 subpart W data: HF gas well completions and workovers that vent; flared HF gas well completions and workovers; HF gas well completions and workovers with reduced emissions completions (RECs); and HF gas well completions and workovers with RECs that flare. Average emissions per completion and workover were calculated for each category by summing the emissions in each category and dividing by the number of completions and workovers in each category using facility-level records that could be assigned to a single unambiguous category. Table 5 presents the subpart W activity and emissions data for those HF gas well completions and workovers that could be assigned to a specific category, along with the calculated C02 EFs. Table 5. GHGRP Subpart W Activity and Emissions Data and Calculated EFs for HF Gas Well Completions and Workovers Category # of Events CO; Emissions mt) CO; EF (kg/event) 2011 2012 2013 2011 2012 2013 HF Completions and Workovers that Vent 3,901 2,370 1,308 11,700 2,681 7,214 2,849 Flared HF Completions and Workovers 1,171 538 422 1,203,235 363,631 192,235 825,481 HF Completions and Workovers with RECs 2,224 1,283 1,566 3,745 151 995 964 HF Completions and Workovers with RECs that flare 818 968 1,129 485,313 387,280 460,691 457,387 Page 6 of 16 ------- June 2017 Pneumatic Controllers Based on the CH4 EF methodology documented in the 2016 Production memo, the EPA calculated pneumatic controller EFs for low, intermittent, and high bleed controllers using Subpart W RY2014 data. EPA divided the reported emissions by the number of reported controllers for each controller type to calculate EFs. All pneumatic controllers data were considered together, and thus pneumatic controller EFs for natural gas and petroleum systems are identical. Table 6 presents the subpart W activity and emissions data, along with the calculated C02 EFs. Table 6. GHGRP Subpart W RY2014 Activity and Emissions Data and Calculated EFs for Pneumatic Controllers Controller Type # Controllers Total CO; Emissions (mt) CO; EF (kg/controller/yr) Low Bleed 200,337 2,391 12 Intermittent Bleed 572,407 98,393 172 High Bleed 29,567 10,013 339 Pneumatic Pumps Based on the CH4 EF methodology documented in the 2016 Production memo, the EPA calculated a pneumatic pump EF using Subpart W RY2014 data. EPA divided the reported emissions by the number of reported pneumatic pumps to calculate the EF. All pneumatic pumps data were considered together, and thus the EF for natural gas and petroleum systems is identical. Table 7 presents the subpart W activity and emissions data, along with the calculated C02 EF. Table 7. GHGRP Subpart W RY2014 Activity and Emissions Data and Calculated EF for Pneumatic Pumps # Pumps Total CO; Emissions (mt) CO; EF (kg/pump/yr) 79,885 11,650 146 Liquids Unloading Based on the CH4 EF methodology documented in the 2017 Production memo, the EPA calculated liquids unloading EFs using Subpart W RY2011-RY2015 data. Separate EFs were calculated for liquids unloading activities that vent with and without plunger lifts. The EPA calculated an average EF by summing the emissions reported in each category for RY2011-RY2015 and dividing by the total number of wells in each category over those years. Table 8 presents the subpart W activity and emissions data, along with the calculated C02 EFs. Table 8. GHGRP Subpart W RY2011-RY2015 Activity and Emissions Data and Calculated EFs for Liquids Unloading With Plunger Lifts Without Plunger Lifts Year CO; Emissions # Wells CO; Emissions # Wells (mt) Vented (mt) Vented 2011 17,671 42,826 20,294 26,679 2012 18,869 34,136 26,300 25,262 2013 4,233 30,922 5,617 27,723 2014 2,430 26,859 5,113 23,068 2015 1,782 30,757 3,348 20,886 Total 44,985 165,500 60,673 123,618 EF (kg C02/well/yr) 272 491 Page 7 of 16 ------- June 2017 Miscellaneous Production Flaring The EPA is considering the use of subpart W RY 2015 miscellaneous production flaring (reported under "flare stacks") emissions data to revise the GHGI and more fully account for flare emissions in the production segment. Subpart W data for this source were not previously considered. The EPA calculated the C02 and CH4 EFs using the following approach. Miscellaneous production flaring emissions are not reported separately for gas and oil production. Therefore, to use reported emissions data for separate natural gas and petroleum systems GHGI estimates, the EPA calculated the fraction of wells that were gas and oil wells for each facility, using the well counts reported in the Equipment Leaks section of subpart W for RY2015.13 The EPA then apportioned each facility's reported miscellaneous flaring C02 and CH4 emissions by production type. The EPA summed the facility-level C02 and CH4 emissions for each production type to estimate total reported miscellaneous flaring C02 and CH4 emissions from natural gas and oil production. The EPA then divided the reported C02 and CH4 emissions for natural gas and oil production by total reported gas wells and oil wells, respectively. These emissions data, well counts, and calculated EFs are provided in Table 9 and Table 10 below. To calculate national emissions, the EFs would be multiplied by the national gas and oil well counts already estimated in the GHGI. Table 9. GHGRP Subpart W RY2015 C02 Emissions and Activity Data and Calculated EFs for Miscellaneous Production Flaring Total CO; Emissions (mt) Natu CO: Emissions (mt) ral Gas Prodi Total Gas Wells jction CO; EF (kg/well/yr) 0 CO; Emissions (mt) il Productio Total Oil Wells n CO; EF (kg/well/yr) 3,779,110 1,299,672 307,737 4,223 2,479,438 219,433 11,299 Table 10. GHGRP Subpart W RY2015 CH4 Emissions and Activity Data and Calculated EFs for Miscellaneous Production Flaring Total CH4 Emissions (mt) Natur CH4 Emissions (mt) al Gas Produc Total Gas Wells tion CH4 EF (kg/well/yr) ( CH4 Emissions (mt) )il Production Total Oil Wells CH4 EF (kg/well/yr) 14,058 5,443 307,737 17.7 8,614 219,433 39.3 3,2 Processing COz Emiss tclors The EPA developed preliminary gas processing C02 EFs for the plant grouped emission sources (reciprocating compressors, centrifugal compressors with wet seals, centrifugal compressors with dry seals, dehydrators, flares, and plant fugitives), blowdowns and venting, and AGR vents. The CH4 EFs for the grouped sources and blowdowns and venting were recently revised using subpart W data, and the EPA applied the same methodology to calculate C02 EFs. While AGR vent emissions are not currently calculated from subpart W data (as CH4 emissions are not reported for this source), the EPA has calculated a subpart W-based EF and determined the corresponding activity data for this source. Based on the CH4 EF methodology documented in the 2017 Processing memo, the EPA calculated the plant grouped source C02 EFs using subpart W RY2015 data (the purpose of the plant grouped EF is 13RY2015 is the first year in which total oil and gas well counts are reported. However, six facilities did not report these data. Therefore, for these six facilities, the EPA determined the fraction of sub-basins applicable to gas production (i.e., sub-basins with high permeability gas, shale gas, coal seam, or other tight reservoir rock formation types) and oil production (i.e., sub-basins with the oil formation type). Page 8 of 16 ------- June 2017 discussed in Section 3.4). Subpart W data and calculated C02 EFs for the plant grouped sources are presented in Table 11. Table 11. GHGRP Subpart W RY2015 Emissions and Activity Data and Calculated EFs for Gas Processing Plant Grouped Sources Emission Source CO; Emissions (mt) Activity Count (plants or compressors) CO; EF (kg/compressor/yr or kg/plant/yr) Reciprocating compressors 7,818 2,662 compressors 2,937 Centrifugal compressors with wet seals 1,259 264 compressors 4,768 Centrifugal compressors with dry seals 20 214 compressors 400 Dehydrators 7,433 467 plants 15,916 Flares 4,503,224 467 plants 9,642,878 Plant fugitives 2,291 467 plants 4,906 Plant Grouped Sources 4,522,046 467 plants 9,683,181 Based on the CH4 EF methodology documented in the 2017 Processing memo, the EPA also calculated the blowdown and venting C02 EF using subpart W RY2015 data. Subpart W data and the calculated C02 EF for blowdowns and venting are presented in Table 12. Table 12. GHGRP Subpart W RY2015 Emissions and Activity Data and Calculated EF for Gas Processing Blowdown and Venting C02 Emissions (mt) Activity Count (plants) CO; EF (kg/plant/yr) 11,084 467 23,733 For AGR vent emissions, the existing CH4 EF methodology does not rely on subpart W, but the EPA is considering applying a similar methodology as the other processing sources to develop C02 EFs and activity data from subpart W data. The EPA summed the reported AGR vent emissions for gas processing plants and divided by the total reported count of plants for each RY from 2011 to 2015 to calculate C02 EFs. Note, the current GHGI methodologies for gas processing segment sources that use subpart W- based CH4 EFs rely on RY2015 only. To calculate national C02 emissions, the C02 EF would be multiplied by the number of gas plants each year. Subpart W data and the calculated C02 EFs for AGR vents are presented in Table 13. Table 13. GHGRP Subpart W RY2015 Emissions and Activity Data and Calculated EF for Gas Processing AGR Vents Year CO; Emissions (mt) Activity Count (plants) CO; EF (kg/plant/yr) 2011 16,093,040 374 43,029,519 2012 15,692,240 403 38,938,561 2013 13,201,139 438 30,139,587 2014 12,559,555 479 26,220,366 2015 10,048,285 467 21,516,669 Page 9 of 16 ------- June 2017 3,3 Transmission and Storage CO2 Emission Factors Based on the CH4 EF methodology documented in the 2016 Transmission memo, the EPA calculated transmission station and storage station pneumatic controller C02 EFs for low, intermittent, and high bleed controllers using Subpart W RY2011 - RY2015 data. The EPA divided the reported emissions by the number of reported controllers for each controller type to calculate EFs. Table 14 and Table 15 present the subpart W activity and emissions data, along with the calculated C02 EFs. Table 14. GHGRP Subpart W Activity and Emissions Data and Calculated EFs for Transmission Station Pneumatic Controllers Controller Type Data Element 2011 2012 2013 2014 2015 High Bleed Total Count 2,203 1,114 1,158 1,173 1,483 CO2 Emissions (mt) 203 106 106 107 120 CO2 EF (kg/controller/yr) 92 95 91 91 81 Intermittent Bleed Total Count 8,343 9,114 9,903 11,141 10,857 CO2 Emissions (mt) 673 736 747 134 103 CO2 EF (kg/controller/yr) 81 81 75 12 10 Low Bleed Total Count 644 880 857 1,078 1,032 CO2 Emissions (mt) 4.6 6.2 6.2 6.7 4.3 CO2 EF (kg/controller/yr) 7.1 7.0 7.3 6.2 4.2 Table 15. GHGRP Subpart W Activity and Emissions Data and Calculated EFs for Underground Natural Gas Storage Station Pneumatic Controllers Controller Type Data Element 2011 2012 2013 2014 2015 High Bleed Total Count 1,253 1,100 1,089 1,271 1,024 CO2 Emissions (mt) 116 118 116 117 64 CO2 EF (kg/controller/yr) 92 107 106 92 63 Intermittent Bleed Total Count 1,391 1,539 1,601 2,045 2,098 CO2 Emissions (mt) 16 21 21 24 22 CO2 EF (kg/controller/yr) 12 13 13 12 10 Low Bleed Total Count 250 319 366 319 320 CO2 Emissions (mt) 1.9 2.4 2.8 2.2 1.4 CO2 EF (kg/controller/yr) 7.5 7.4 7.6 7.0 4.4 Hares The EPA is considering developing updated GHGI flare C02 EFs for transmission station, underground natural gas storage, LNG storage, and LNG import stations using subpart W data. As discussed in Section 1.3, the GHGI C02 emissions calculation methodology does not calculate C02 emissions from flares. Therefore, the EPA is considering supplementing the current methodology to calculate C02 emissions with new line items for station flares. The EPA divided the reported flare C02 and CH4 emissions by the number of reported stations for RY2015 to calculate the EFs. Subpart W transmission station, underground natural gas storage, LNG storage, and LNG import station flare data are presented in Table 16 through Table 19. The applicable activity data to calculate national emissions are the national number of stations, which are already calculated in the GHGI. Page 10 of 16 ------- June 2017 Table 16. GHGRP Subpart W RY2015 Emissions and Activity Data and Calculated EFs for Transmission Station Flares Total # Stations # Stations With Flares # Flares Total CO; Emissions (mt) CO; EF (kg/station/yr) Total CH4 Emissions (mt) CH4 EF (kg/station/yr) 521 16 24 28,511 54,723 124 238 Table 17. GHGRP Subpart W RY2015 Emissions and Activity Data and Calculated EFs for Underground Natural Gas Storage Flares Total # Stations # Stations With Flares # Flares Total CO; Emissions (mt) CO; EF (kg/station/yr) Total CH4 Emissions (mt) CH4 EF (kg/station/yr) 53 8 21 3,576 67,479 34 650 Table 18. GHGRP Subpart W RY2015 Emissions and Activity Data and Calculated EFs for LNG Storage Flares Total # Stations # Stations With Flares # Flares Total CO; Emissions (mt) CO; EF (kg/station/yr) Total CH4 Emissions (mt) CH4 EF (kg/station/yr) 7 2 2 259 37,042 1.9 266 Table 19. GHGRP Subpart W RY2015 Emissions and Activity Data and Calculated EFs for LNG Import Flares Total # Stations # Stations With Flares # Flares Total CO; Emissions (mt) CO; EF (kg/station/yr) Total CH4 Emissions (mt) CH4 EF (kg/station/yr) 7 2 3 77,420 11,059,970 268 38,238 3,4 Time Series Considerations For the production segment sources discussed in Section 3.1, the EPA would apply the same methodology to calculate C02 over the time series as used for calculating CH4 emissions over the time series.14 For oil and condensate tanks, the EPA applies category-specific EFs for every year of the time series; for associated gas venting and flaring, the EPA applies the subpart W 2011 EFs for years prior to 2011 and year-specific subpart W EFs are applied for 2011 and forward; for liquids unloading, the average 2011-2015 EFs developed from subpart W data are applied to each year of the time series; for pneumatic controllers and pumps, category-specific EFs are applied for each year of the time series; and for HF gas well completions and workovers, category-specific EFs are applied for each year of the time series. EPA will separately seek stakeholder feedback on considerations for time series calculations for both CH4 and C02 emissions in the 2018 GHGI. For the production miscellaneous flaring time series, the current GHGI flare emission estimate (representing both production and processing), fluctuates based on activity data (ElA's estimated annual vented and flared volumes). Assessment of subpart W C02 data over the time series for this source indicates that miscellaneous flaring emissions per well do not show a clear trend. See Requests for Stakeholder Feedback section for more information. In a revised approach to use subpart W-based C02 EFs (kg/well), the EF could be held constant for each year and flare emission estimates would fluctuate with active gas or oil well count over the time series. 14 Additional details on current time series calculations for production segment sources are provided in the 2014 HF Completion and Workover memo, 2015 HF Completion and Workover memo, 2016 Production memo, and 2017 Production memo. Page 11 of 16 ------- June 2017 For certain processing sources discussed in Section 3.1, the EPA would apply the same methodology to calculate C02 over the time series as used for calculating CH4 emissions over the time series.15 For plant grouped emission sources and blowdowns and venting, GRI/EPA 1996 EFs are used for 1990 through 1992; EFs calculated from subpart W are used for 2011 forward; and EFs for 1993 through 2010 are developed through linear interpolation. For AGR vents, the EPA is considering adopting a similar methodology as the other processing sources (maintain the current GRI/EPA 1996 EFs for 1990 through 1992, apply the subpart W-based EFs for 2011 forward, and develop EFs for 1993 through 2010 using linear interpolation). For transmission and storage flares, the EPA is evaluating the prevalence of flares over the 1990-2016 time series. The EPA is considering applying a subpart W-based EF (kg/station) for all years of the time series. However, few transmission and storage stations reported flares for RY2015 (see Table 16 through Table 19). Therefore, the EPA might alternatively assume that flares did not operate in 1990 (i.e., an EF of 0), apply the subpart W-based EF for 2011 forward, and apply linear interpolation from 1991 through 2010. 4, National Emissions Estimates The EPA calculated national C02 emissions using each of the subpart W-based approaches discussed in Section 3 in conjunction with activity data for year 2015 from the 2017 GHGI. These emissions are compared against 2015 emissions from the 2017 GHGI in Table 20 and Table 21. Table 20. Natural Gas Systems Estimated Year 2015 National C02 Emissions (mt) Using Subpart W-based EFs Compared to 2017 GHGI Production 18,585,048 4,855,904 Tanks 30,426 1,108,346 Large Tanks w/Flares 1,059,701 Large Tanks w/VRU 2,840 Large Tanks w/o Control 632 Small Tanks w/Flares 35,173 Small Tanks w/o Flares 9,984 Malfunctioning Separator Dump Valves 15 Miscellaneous Flaring (a) 17,628,522 1,860,355 Gas HF Completions/Workovers 91,965 1,129,883 Non-REC with Venting 397 Non-REC with Flaring 281,489 REC with Venting 3,203 REC with Flaring 844,794 Liquids Unloading 39,485 9,282 w/Plunger Lifts 13,780 4,169 w/o Plunger Lifts 25,705 5,112 Pneumatic Controllers 119,970 79,608 Low-Bleed 1,842 Intermittent Bleed 71,177 15 Additional details on current time series calculations are provided in the 2017 Processing memo. Page 12 of 16 ------- June 2017 High-Bleed 6,589 Pneumatic Pumps 14,021 7,770 Other Production Sources (b) 660,659 660,659 Processing 23,712,956 20,826,478 AGR Vents 23,643,456 14,351,618 Plant Grouped Sources 63,662 6,458,775 Blowdowns/Venting 5,586 15,830 Pneumatics 250 255 Transmission & Storage 38,694 250,095 Transmission Flares 0 100,357 Underground Storage Flares 0 23,542 LNG Storage Flares 0 2,603 LNG Import Flares 0 85,162 Pneumatic Controllers 1,649 1,386 Other Transmission & Storage Sources (b) 37,045 37,045 Distribution (b) 13,988 13,988 a. Also represents flaring from petroleum production and gas processing. b. Set 2018 GHGI value equal to 2017 GHGI value. Table 21. Petroleum Systems Estimated Year 2015 National C02 Emissions (mt) Using Subpart W-based EFs Compared to Current GHGI Production 640,443 44,233,703 Tanks 519,934 8,643,876 Large Tanks w/Flares 8,576,672 Large Tanks w/VRU 17,229 Large Tanks w/o Control 5,928 Small Tanks w/Flares 10,581 Small Tanks w/o Flares 8,271 Malfunctioning Separator Dump Valves 25,194 Miscellaneous Flaring incl. w/NG 6,864,989 Associated Gas (a) 826 28,582,015 Flaring 28,550,273 Venting 31,742 Pneumatic Controllers 87,576 109,857 Low-Bleed 2,697 2,252 Intermittent Bleed 74,341 100,265 High-Bleed 10,538 7,339 Pneumatic Pumps 10,779 11,639 Other Production Sources (b) 21,327 21,327 Refining (b) 2,926,666 2,926,666 a. 2017 GHGI is estimate for stripper well venting. b. Set 2018 GHGI value equal to 2017 GHGI value. The C02 revisions under consideration will result in an overall shift of C02 emissions from Natural Gas systems to Petroleum systems. This is due to the availability of industry segment-specific and emission source-specific data in subpart W, whereas previous data sources were not as granular. The current Page 13 of 16 ------- June 2017 GHGI accounts for all onshore production and gas processing flaring emissions under a single line item in the production segment of natural gas systems. Using the revised approach, these flaring emissions would be specifically calculated for natural gas production, petroleum production, and gas processing (within the plant grouped emission sources). The shift in C02 emissions from Natural Gas systems to Petroleum systems is also due to the inclusion of associated gas flaring as a specific line item under Petroleum systems; this is the largest source of C02 emissions for the revisions under consideration. 5. Requests for Stakeholder Feedback 1. EPA seeks stakeholder feedback on the general approach of using subpart W reported C02 emissions data to revise the current C02 emissions calculation methodology (described in Section 1) in the GHGI. 2. EPA seeks feedback on using consistent calculation methodologies for both CH4 and C02, when GHGI relies on subpart W data. Are there sources where the CH4 and C02 methodologies based on subpart W should differ? 3. Section 3.1 discusses considerations for developing EFs and associated activity data for miscellaneous production flaring that facilitate scaling reported subpart W data to a national level. The EPA has presented a preliminary approach that develops an EF in units of emissions per well. National active well counts would be paired with such EF to calculate emissions in the GHGI. The EPA seeks feedback on this approach, or suggestions of other approaches that would facilitate scaling to a national level and time series population. 4. For sources discussed in this memo that do not currently estimate CH4 emissions using subpart W, EPA is considering which year(s) of subpart W data to use in developing the C02 emissions methodologies. For miscellaneous production flaring, the EPA reviewed reported emissions and activity data for RY2011 - RY2014. However, wellhead counts for RY2011 - RY2014 are only reported by those facilities that calculated equipment leak emissions using Methodology 1, and as such, are not comprehensive. At the time of the 2016 Production memo, 83% of reporting facilities for RY2011, 85% of RY2012 reporting facilities, 93% of RY2013 facilities, and 98% of RY2014 reporting facilities reported wellhead counts under Methodology 1. In addition, facilities only reported total wellheads and did not report gas and oil wellhead counts separately for RY2011 - RY2014. The EPA calculated the C02 EFs under consideration using RY2015 only, because well counts from all reporting facilities are reported. However, the EPA requests feedback on whether it is appropriate to consider data from prior reporting years, which have more uncertainty due to incomplete coverage, in order to show a trend over the time series. Table 22 provides the reported subpart W emissions and activity data for RY2011-RY2015. Table 22. GHGRP Subpart W Emissions and Activity Data for Miscellaneous Production Flaring Year CO: Emissions (mt) # Flares # Wells (a) CO; EF (kg/well) 2011 2,252,297 13,509 371,604 6,061 2012 3,616,326 16,356 398,137 9,083 2013 4,596,329 21,098 415,355 11,066 2014 4,841,116 22,155 502,391 9,636 2015 3,779,110 20,293 527,170 7,169 Page 14 of 16 ------- June 2017 a. Total gas and oil wellheads. Wellhead counts for RY2011 through RY2014 are available from those onshore production facilities that calculated equipment leak emissions using Methodology 1. For transmission and storage segment flares, the EPA relies on RY2015 data for the revisions under consideration, because all flaring emissions are reported under the flare stacks source. Whereas, for RY2011 - RY2014, flare emissions are reported under flare stacks and each individual emission source. 5. Section 3.4 discusses time series considerations for transmission and storage flares. The EPA is considering applying a subpart W-based EF (kg/station) for all years of the time series. However, few transmission and storage stations reported flares for RY2015 (see Table 16 through Table 19). Therefore, EPA might alternatively assume that flares did not operate in 1990 (i.e., an EF of 0), apply the subpart W-based EF for 2011 forward, and apply linear interpolation from 1991 through 2010. The EPA seeks feedback on these approaches, or suggestions of other approaches to time series population. Page 15 of 16 ------- June 2017 Appendix A - Current GHGI COz Emlssic :tors All EFs are presented in the same units as the EFs under consideration; kg/[unit]. Natural Gas & Petroleum Production Stripper Wells (for Associated Gas Venting) 2.47 kg/well Condensate Tank Vents - Without Control Devices 0.18 kg/bbl Condensate Tank Vents - With Control Devices 0.037 kg/bbl Oil Tanks 0.18 kg/bbl HF Gas Well Completions and Workovers 18,367a kg/event Pneumatic Controllers, all bleed types (Natural Gas) 144a kg/controller Low Bleed Pneumatic Controllers (Petroleum) 8.8 kg/controller Intermittent Bleed Pneumatic Controllers (Petroleum) 83.9 kg/controller High Bleed Pneumatic Controllers (Petroleum) 238.9 kg/controller Pneumatic Pumps (Natural Gas) 168.4a kg/pump Pneumatic Pumps (Petroleum) 82.8 kg/pump Liquids Unloading with Plunger Lifts 613a kg/well Liquids Unloading without Plunger Lifts 678a kg/well Onshore Production & Processing - Flaring Emissions 40,624 kg/well Natural Gas Processing Reciprocating compressors - before C02 removal 4,764 kg/compressor Reciprocating compressors - after C02 removal 1,058 kg/compressor Centrifugal compressors with wet seals - before C02 removal 21,859 kg/compressor Centrifugal compressors with wet seals - after C02 removal 4,854 kg/compressor Centrifugal compressors with dry seals - before C02 removal 10,719 kg/compressor Centrifugal compressors with dry seals - after C02 removal 2,380 kg/compressor Plant fugitives - before C02 removal 3,364 kg/plant Plant fugitives - after C02 removal 747 kg/plant Kimray pumps 859 kg/plant Dehydrator vents 5,291 kg/plant Plant Grouped Sources 95,303 kg/plant AGR vents 35,394,396 kg/plant Blowdowns and venting 8,363 kg/plant Transmission High Bleed Pneumatic Controllers 84.43 kg/controller Intermittent Bleed Pneumatic Controllers 10.95 kg/controller Low Bleed Pneumatic Controllers 6.22 kg/controller Underground NG Storage High Bleed Pneumatic Controllers 82.21 kg/controller Intermittent Bleed Pneumatic Controllers 10.74 kg/controller Low Bleed Pneumatic Controllers 6.34 kg/controller a. Average EF based on data from all NEMS regions. Page 16 of 16 ------- |